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1/2-1
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<p><b>General</b></p>
<p>Well 1/2-1 is located in the Central Graben, about 200 m from the UK border in the North Sea. The main objective was Paleocene sands of the Rogaland Group. The secondary target was the chalk formations, although these were possibly not enough fractured to represent a reservoir. </p> <p><b>Operations and results</b></p> <p>Wildcat well 1/2-1 was spudded with the semi-submersible installation Ross Isle on 20 March 1989 and drilled to TD at 3574 m in the Late Cretaceous Tor Formation. While cutting of core no 7, the elevators accidentally opened and dropped the string. Two attempts were made to recover the string with no success. The hole was sidetracked from 3078.5 m and core no 8 was cut. The well was drilled with seawater down to 645 m, with native mud (water mixed with clays from the borehole itself) from 645 m to1525 m, and with seawater from 1525 m to TD. No shallow gas was detected in the hole.</p> <p>The Forties Formation came in at 3121 m. The formation was hydrocarbon bearing down to 3142.5 m as confirmed by both electric logs and the RFT pressure gradient. The reservoir sandstones of the Forties Formation showed good to excellent reservoir properties. Average core porosity was 18.5% and test permeability was measured to 49 mD. </p> <p>Shows on cores were recorded down to core # 8 where they gradually decreased to zero at 3166 m. From the RFT data two water gradients were identified below the oil zone. A shift of 8 psi between them suggested the existence of an impermeable barrier around 3160.2 and 3162 m. Core saturations and fluorescence indicated the potential existence of a thin (4 m) oil zone below this barrier. This zone was not identified from the logs and was not evaluated for a test due to lack of data at that point. </p> <p>The Ekofisk formation was encountered at 3407 m, and the Tor formation at 3514 m. Both formations were water bearing.</p> <p>A total of 8 cores were cut in the Forties Formation, seven in the first hole and the eighth in the sidetrack. No wire line fluid samples were taken. </p> <p>The well was permanently abandoned on 4 June 1989 as an oil/gas discovery.</p> <p><b>Testing</b></p> <p>Two intervals were perforated and tested with the intention to first test the oil zone and then open up a deeper zone to produce and sample formation water. The perforated intervals were 3122 - 3137 m in the oil zone and 3145.5 - 3157.7 m in the water zone. The oil test produced up to 859 Sm3 oil and 57200 Sm3 gas/day on a 64/64" choke. The GOR was 67 Sm3/Sm3 and the oil gravity was 42.5 deg API. The maximum temperature recorded during the test was 133.8 deg C. Analysis of the final co-mingled oil + water test confirmed that the lower perforation interval produced only water. This confirmed the contact at 3142.5 m to be an OWC.</p> |
1382
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7/6/2016 12:00:00 AM
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04.11.2024
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1/2-2
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<p>The 1/2-2 well was drilled to evaluate the prospect named Hummer, located in the Central Graben in the North Sea ca 4.5 km east of the UK border. The prospect was a relatively simple four-way dip closure structure, with the primary target being the Palaeocene Forties Sandstone Member of the Sele Formation. There was a secondary target in the underlying Mey Sandstone Member of the Lista Formation. The Hummer prospect was located between several proven hydrocarbon accumulations in the Forties Sandstone, including the Blane oil discovery in PL 143BS, approximately 11 km to the south, the 7/11-3 gas condensate discovery on the flank of the Cod Field, 5 km to the North, and the Olselvar gas condensate discovery 12 km to the east in Block 1/3.</p> <p><b>Operations and results</b></p> <p>Well 1/2-2 was spudded with the jack-up installation Mærsk Giant on 14 December 2005 and drilled to TD at 3434 m in the Paleocene Ekofisk Formation. There were no serious technical problems in the operations, but due mainly to hole problems and WOW the well was completed ca 15 days after schedule. The well was drilled with seawater and pre-hydrated bentonite sweeps down to703 m, with Performadrill KCl mud from 703 m to 1507 m, and with Enviromul oil based mud from 1507 m to TD.</p> <p>A Forties reservoir was penetrated at 3135 m, +3m low from the prognosis. No hydrocarbons were encountered, but oil shows were recorded in the upper part of the Forties Formation and in a sandstone stringer further down in the Lista Formation.</p> <p>A 46 m core (4") was cut in the Forties sandstone Member, from 3141.5 m to 3187.5 m. The core recovery was 98% (44.9 m). Wire line logging was according to dry hole case with no wire line fluid samples taken.</p> <p>The well was permanently abandoned on 2 February 2006 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
5192
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4/11/2017 12:00:00 AM
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04.11.2024
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1/3-1
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-1 was drilled on the crest of a salt-induced anticline on the Hidra High in the North Sea. The purpose of the well was to investigate Tertiary and Mesozoic sequences down to top salt.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well is Type Well for the Våle, Hidra, Hod, and Tor Formations, and Reference Well for the Vidar, Ekofisk and Blodøks Formations.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-1 was spudded with the four leg jack-up installation Orion on 6 July 1968 and drilled to TD at 4877 m in the Permian Zechstein Group. From the deviation survey it is seen that the well starts to deviate significantly at 4037 m (8 deg deviation), and at TD the deviation is 18 deg. This will correspond to a TVD RKB that is ca 25 m less than MD RKB.</span><span lang=EN-GB>Several drilling problems occurred during the drilling operations of well 1/3-1. While drilling the 17 1/2" hole for the 20" casing, circulation losses started at 220 m (720') and became total at 238 m (781'). While drilling on with sea water, without returns, the pipe stuck. The lost circulation zone eventually had to be sealed off with a cement plug. In the Tertiary plastic clays the problems included tight hole conditions, bit balling, and difficulties in lowering the logging tools. The mud weight had to be raised from 10.8 ppg to 13.6 ppg to stabilize the hole. At 4131 m (13554') the bit twisted off, but was retrieved on the second fishing run. A hydrocarbon bearing zone was encountered at 4567 m (14984'). The mud became gas cut. At 4592 m (15064') the degasser was overloaded and the circulation lost, probably higher in the hole. A cement plug was needed to combat the lost circulation problems. It was then decided to set a 7" casing. Circulation was lost while running the casing, which had to be cemented in two stages. Drilling continued with a 5 7/8" bit. Around 4677 m (15346'), when drilling into salt, the penetration rate increased from 10 to 50 ft/hr. Further deepening to TD went without problems. The well was drilled water based.</span></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-1 found no sand of any significance in the Tertiary section. An unexpectedly thick Danian/Late Cretaceous chalk section (Shetland Group) was penetrated from 3258 m to 4441 m. The underlying Cromer Knoll Group was found resting directly on Permian salt at 4671 m. Minor gas was confirmed by testing in the Tor Formation. No source rock section was identified in the well. Shows were reported in the interval from 2999 m to 3423 m as follows: direct and cut "faint" fluorescence were reported on sidewall cores from the interval 2999 to 3002 m; weak cut fluorescence was recorded on cuttings from 3039 m; strong cuttings fluorescence and moderate cut was recorded at 3357 m; "fair" - "soaked w/oil, giving yellowish-grn flu, but no cut" on the conventional core at 3405 to 3423 m</span></p> <p class=MsoBodyText><span lang=EN-GB>One core was cut from 11165 to 11232 ft (3403.1 to 3423.5 m). No wire line fluid samples were taken. A sea bed core (0 - 46 m from seabed) was taken for geotechnical purposes at the 1/3-1 location. Samples from this core are available at the NPD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 11 November 1968 as a minor gas discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Three Drill Stem Tests were conducted. They produced some fluids at very low rates:</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 4583.6 - 4601.0 m in the Cromer Knoll Group and recovered a total of 0.74 bbl gas cut mud in 45 minutes, corresponding to a standard rate of 40 bbl (1133 Sm3) gas/day. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 4563.5 - 4581.8 m in the Cromer knoll Group and recovered a total of 18 bbl of gas cut mud with traces of condensate and slugs of gas in 140 minutes. This corresponds to a standard rate of 234 bbl (6626 Sm3) gas/day. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 3 tested the interval 3355.2 - 3359.8 m in the Tor Formation and recovered a total of 30 bbl of gas cut mud and slugs of gas in 45 minutes. This corresponds to a standard rate of 1000 bbl (28317 Sm3) gas/day. </span></p> |
154
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5/19/2016 12:00:00 AM
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04.11.2024
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1/3-10
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 1/3-10 is located on the Hidra High, ca 20 km south-south west of the Ula Field in the North Sea. It was drilled to appraise the oil and gas bearing Late Paleocene Forties Sandstone in the Oselvar structure, first discovered by the 1/3-6 well drilled by Elf Aquitaine Norway A/S in 1991. The main goal of the well was to acquire sufficient reservoir data to make a decision on future development of the Oselvar discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 1/3-10 was spudded with the jack-up installation Mærsk Guardian on 25 October 2007 and drilled to TD at 3288 m in the Paleocene Lista Formation. The well was drilled and tested without significant technical problems. It was drilled with seawater / PHB down to 816 m, with KCl/Polymer mud from 816 to 1300 m, and with Carbo SEA OBM from 1300 to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The top of the Hordaland Group came in deep (19 m) compared to prognosis, as did the Balder and Sele Formations of the Rogaland Group (12 m and 5 m deep respectively). More significantly, a thicker than prognosed Sele Formation resulted in the target reservoir Forties sandstone coming in at 3153 m, 24 m deep compared to prognosis. The thickness of the Forties Sandstone however, was 52 m, which is only one meter thinner than prognosed. Of this thickness 32 m was designated as net reservoir using a porosity cut-off value of 10%. The average porosity was 17.7 % and the water saturation was 44.9%. The Forties Formation contained light oil with a free water level for the area estimated at 3245 m. Shows were only recorded in the target Forties Formation sandstones.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Forties Formation Sandstone was cored from 3159 to 3232 m with 99.8% recovery. An RCI log was run for pressure and fluid sampling.</span><span lang=EN-GB>Four light oil gradients with increasing density downwards could be identified from these data. Light oil fluid samples were taken in Run 2A at two depths, 3162.2 m and 3186.3 m. Run 2D samples were taken at 3203.3 m (approximately 70% water and 30% oil), and at 3196.5 m (about 80% light oil and 20% water). </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged back for sidetracking on 7 January 2008 as an oil and gas appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The Forties Formation was tested by an open hole ("barefoot") DST in the 8 1/2" section from 3158 to TD. The test produced 457 Sm3 oil and 212453 m3 gas /day through a 48/64" choke in the main flow period. The GOR was 465 m3/m3, the oil density was 0.791 g/cm3, and the gas gravity was 0.855 (air = 1), with 5 ppm H2S and 2.5 % CO2.</span></p> |
5614
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4/11/2017 12:00:00 AM
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04.11.2024
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1/3-10 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-10 A is located on the Hidra High, ca 20 km south-south west of the Ula Field in the North Sea. It was drilled to further appraise the Forties Formation Sandstone in the Oselvar structure, after the primary well 1/3-10 had confirmed oil and gas in the structure. The main goal of the sidetrack well was to penetrate the water leg for water sampling and establish the free water level in the structure. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The Oselvar 1/3-10 A appraisal sidetrack kicked off in the claystones of the Hordaland Group at 2276 m on 7 January 2008. It was drilled with the jack-up installation Mærsk Guardian to final TD at 3632 m in the lower part of the Sele Formation below the target Forties Sandstone. The well was drilled without significant technical problems. It was drilled with Carbo SEA OBM from kick-off to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well track penetrated the remaining Hordaland claystone, and the claystones, tuffaceous claystones and sandstones of the Rogaland Group (Paleocene-Eocene), which included the Balder Formation, the Sele Formation, and the target Forties Sandstone Member. The top of the Balder Formation came in only 1 m TVD shallow compared to prognosis, the Sele Formation came in deep (10 m TVD) compared to prognosis. The Forties Sandstone came in at 3516 m (3257 m TVD RKB), 11 m TVD compared to prognosis. The log data confirmed that the well had penetrated the water leg of the reservoir as expected, and indicated 64 m MD (43 m TVD) gross reservoir and a net reservoir of 37 m MD (25 m TVD), giving a Net/Gross of 0.58. The net reservoir, all of which is considered to be non-pay, has an average porosity of 18 % and mobilities in the range 1-13 mD/cP. Pressure measurements indicated a free water level at 3245 m TVD RKB.</span></p> <p class=MsoBodyText><span lang=EN-GB>From petrophysical evaluation the water bearing reservoir was found to contain residual hydrocarbons. The only oil show in the well was a weak oil stain at 3525 m (3263 m TVD RKB) in the Forties Formation.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut in 1/3-10 A. An RCI log was run for pressure and fluid sampling.</span><span lang=EN-US>Water</span><span lang=EN-GB> samples were taken at 3556 m, 3572 m, and 3536.75 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13 January 2008 as an oil and gas appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No DST was carried out</span></p> |
5779
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4/11/2017 12:00:00 AM
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04.11.2024
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1/3-11
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The 1/3-11 Ipswich well was drilled in the Central Graben of the North Sea about 9 km south of the 1/3-10 Oselvar well, which confirmed oil in a similar geological setting to that of the Ipswich prospect. The primary objective of the 1/3-11 well was to determine the presence and nature of recoverable hydrocarbons in the Forties Formation Sandstone reservoir expected to exist along the western flank of the Ipswich salt dome.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/3-11 was spudded with the jack-up installation Mærsk Galant on 28 May 2008 and drilled to 3289 m in the Paleocene Våle Formation. The well path was drilled with a slight S shape after the originally planned surface location was moved to avoid potential shallow gas. Due to unexpected lithology the original hole penetrated most of an hydrocarbon-bearing reservoir sand in the well without cores being taken. Therefore it was decided to make a technical coring side-track, in which also fluid samples would be obtained. The sidetrack was denoted technical (1/3-11 T2) as coring was the main objective. It was kicked off at 1330 m and drilled to final TD at 3595 m in the Paleocene Ekofisk Formation. The well was drilled with seawater and pre-hydrated bentonite down to 825 m, with KCl/polymer mud from 825 m to 1306 m, and with Carbo SEA oil based mud from 1306 m to TD, including the technical sidetrack.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated the clays and claystones (with sand interbeds) of the Nordland Group, the claystones of the Hordaland Group, and the claystones, tuffaceous claystones and sandstones of the Rogaland Group. The latter contained the Balder Formation, the Sele Formation (which was expected to contain the target Forties Formation sandstone), the Lista Formation and the Våle Formation. The well did not penetrate sands at the stratigraphic equivalent of the target Forties Formation sandstone. Instead, a de-sanded Forties equivalent was penetrated consisting of claystone interbedded with siltstone and dolomitic limestone. However, hydrocarbon bearing sands were encountered at 3176 m within the underlying Lista formation, and these were interpreted as possible lateral equivalents of the "Mey Sandstone Member" (Andrew Formation). </span></p> <p class=MsoBodyText><span lang=EN-GB>Based on initial analysis of the LWD logs and wire line formation pressure measurements, it was decided to drill the coring sidetrack down dip in order to investigate also the thickness of the hydrocarbon column, lateral variation in reservoir quality and thickness, the presence of the Forties Formation sandstone down dip in addition to the Andrew Formation penetrated in the main well, in addition to the coring and sampling objectives. The Ipswich 1/3-11 T2 sidetrack kicked off in the claystones of the Nordland Group and penetrated the claystone of the Hordaland Group and claystones, tuffaceous claystones and sandstones of the Rogaland Group. The sandstones of the Rogaland Group included 37 m of Forties Formation which, unlike in the main well, was present in the sidetrack as a sandstone, in addition to 116 m of the Andrew Formation. In 1/3-11 T2 the Forties Sandstone was found hydrocarbon bearing, while the Andrew Formation was poorer and water filled. </span></p> <p class=MsoBodyText><span lang=EN-GB>No definite hydrocarbon contact levels were seen in the wells.</span></p> <p class=MsoBodyText><span lang=EN-GB>In the primary well oil shows were recorded throughout the Andrew Formation, else no shows above background OBM was observed. In the sidetrack a show (very weak, if any) was recorded in the Vade Formation sandstone at 2594 to 2600 m, in a thin sandstone at 3215 m within the Sele Formation, and in the Forties Formation. In the sidetrack no shows above background OBM level was observed in the Andrew Formation.</span></p> <p class=MsoBodyText><span lang=EN-GB>At total of 93.63 m core was recovered in three cores from the interval 3288 m to 3355.7 m in the Forties and Sele Formations and 2 cores from the interval 3398.9 m to 3429.1 m in the Andrew Formation. All cores were cut in the sidetrack. No fluid samples were taken in the primary well. In the sidetrack fluid sampling resulted in the recovery of three water samples at 3415.1 m in the Andrew Formation and five oil samples at 3294.5 m in the Forties Formation Sandstone. All oil samples were heavily contaminated by oil based mud filtrate.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 30 August as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> < |
5806
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4/11/2017 12:00:00 AM
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04.11.2024
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1/3-12 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-12 S was drilled in the Breiflabb Basin of the southern North Sea, about half-way between the Albuskjell Field and the 1/3-11 discovery. The principal objective of the well was to penetrate the Mandarin East pod and evaluate a prognosed un-faulted section of Triassic (Skagerrak Formation) within which there was a strong amplitude event that was interpreted pre</span><span lang=EN-GB style='font-family:"Cambria Math","serif"'>‐</span><span lang=EN-GB>drilling as being the Top Julius mudstone, with a Joanne Sandstone section above and the Judy Sandstone beneath. Both of these were prognosed to contain hydrocarbons. The secondary objective was to evaluate the hydrocarbon potential of the Late Jurassic Sandstones, if any were present.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-12 S was spudded with the jack-up installation Rowan Gorilla VI on 1 December 2009 and drilled to TD at 5931 m (5868 m TVD) in the Late Triassic Skagerrak Formation. At final TD the pipe became stuck and after some time working to free the pipe it parted just below the rotary table. A complex 12 day fishing operation then commenced, eventually recovering the fish from 5590 m upwards, but leaving the BHA across the Judy Sandstones. This made wire line logging operations impossible. Following recovery of the fish a further 32 days were spent plugging and abandoning the well before the rig moved off location. The well was drilled with seawater and pre-hydrated bentonite down to 1150 m, with Carbosea oil based mud from 1150 m to 5412 m, and with Magma-Teq oil based mud from 5412 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The stratigraphic sequence was different to that expected, with a thicker Late Jurassic, and the unexpected presence of Middle Jurassic claystones and sandstones eroding down into the Triassic sequence. The Joanne sandstones was not encountered and the well went directly into what was believed to be the Judy Sandstones at 5817.5 m. When the well had gone deep enough to ensure that Julius Mudstone was not present, a core was taken for evaluation of reservoir quality. The LWD GR and resistivity logs clearly showed the Middle Jurassic and Skagerrak Sandstones to be water bearing. There were no oil shows above OBM seen on cuttings from the Jurassic and Triassic sandstones. No shows were seen on the core.</span></p> <p class=MsoBodyText><span lang=EN-GB>One core was cut from 5876 m to 5903 m in the Skagerrak Formation, Judy Member. Only 8.43 m (32.6%) was recovered. It was not possible to obtain wire line log data, pressures, and fluid samples over the Middle Jurassic and Skagerrak Sandstones due to the BHA becoming stuck at TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 22 July 2010 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
6260
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4/11/2017 12:00:00 AM
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04.11.2024
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1/3-13
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 1/3-13 was drilled to test the Ommadawn prospect on the border between the Hidra High and the Breiflabb Basin in the North Sea. The well was drilled near the 1/3-11 (Ipswich) oil discovery from 2008, which found oil in the Forties and Andrew formations. The primary objective of 1/3-13 was to test the hydrocarbon potential of the Tor Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/3-13 was spudded with the jack-up installation Maersk Integrator on 16 June 2021 and drilled to TD at 3341 m the Late Cretaceous Tor Formation. Drilling started with a pilot hole down to 920 m to check for shallow gas. Boulders were encountered at 270 m and 10 hrs were lost due to stuck pipe at this point. No shallow gas was encountered. The main well was initiated on 18 June. Losses occurred at TD, possibly related to a fault. Due to this and a dry Tor Formation the well was TD'd. The well was drilled with seawater and hi-vis pills down to 796 m and with Rheguard oil-based mud from 796 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The target Tor Formation was encountered water-wet at 3238 m. However, unexpectedly the well encountered hydrocarbon bearing sands in the overlying Forties and Andrew formations from 3025 to 3037 m and 3073 to 3093 m, respectively. No pressure points or fluid samples were acquired in these sands, so pressure communication with the Forties and Andrea sands in the 13/1-11 Ipswich discovery could not be confirmed. The fluid type was interpreted as oil based on LWD logs and gas readings.</span></p> <p class=MsoBodyText><span lang=EN-GB>In the cuttings no shows could be distinguished above the OBM background fluorescence.</span></p> <p class=MsoBodyText><span lang=EN-GB>Due to dry target, no cores were cut, and no fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7 July 2021.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
9334
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9/6/2023 12:00:00 AM
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04.11.2024
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1/3-2
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-2 was drilled on the crest of a salt-induced anticline on the Hidra High in the North Sea.</span><span lang=EN-GB>The main objective was possible L. Tertiary sands, well developed and productive in Phillips 7/11-1. Secondary objective was the Late Cretaceous chalky limestone, which had given shows in 1/3-1.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/3-2 was spudded with the semi-submersible installation Sedneth I on 14 May 1969 and drilled to TD at 4297 m in the Early Cretaceous Sola Formation. When drilling out of the 20" casing shoe, circulation was lost immediately, and the lost circulation zone had to be cemented off. The plastic clays caused continuous troubles, such as bit balling and plugged shaker screens, and the hole had to be reamed and washed several times. Below 3378 m diamond bits were used, and the drilling was interrupted frequently because of leaking bumper subs. The well was drilled water based with a 1 - 4 % addition of diesel through most of the well bore.</span></p> <p class=MsoBodyText><span lang=EN-GB>Tertiary sands were not developed, and whilst thick Late Cretaceous chalky limestone was found as predicted, there were no hydrocarbon bearing intervals in it, and reservoir qualities were poor. No source rock intervals were encountered, and only very minor traces of higher hydrocarbons were detected in the Late Paleocene-Early Eocene section, and in the interval 3761 to 3901 m in the Hod Formation.</span></p> <p class=MsoBodyText><span lang=EN-GB>A small core recovered by junk basket was taken at 3589.02 - 3589.5 m. No wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 27 July 1969 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
165
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5/19/2016 12:00:00 AM
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04.11.2024
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1/3-3
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-3 is located on the Cod Terrace in the North Sea. It was drilled to evaluate the hydrocarbon potential of both the Late Jurassic and the Triassic sandstone formations. Main target was the Late Jurassic Ula Formation found oil bearing in the Ula field, 17 km to the NW, and in the well 2/1-3. Secondary target was the Triassic sandstone found oil bearing in the well 7/12-6 in the Ula field. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/3-3 was spudded with the semi-submersible installation Borgsten Dolphin on 22 August 1982 and drilled to TD at 4876 m logger's depth (4867 m driller's depth). The well was drilled using water based mud. Two drilling breaks occurred, one at 4127 m and one at 4180 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Thin layers of sandstone were found in the Palaeocene. The Chalk Group was 686 m thick. Less than 10 m of sandstones scattered in several thin layers were encountered and partially cored in the Farsund Formation, they were found tight. The Late Jurassic Ula Sandstones, which were the main objective, were found at 4178 m and they were oil bearing down to an OWC at 4221 m, but with only ca 5 m pay zone. The upper half with the best reservoir qualities was cored (cores 2 to 6). The coaly Bryne Formation is assigned at 4527 m, top Triassic Smith Bank Formation at 4620 m, and the Zechstein evaporitic rocks, anhydrite (26 m) and halite was penetrated from 4820 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Residual hydrocarbon saturation based on electric logs were seen in the Paleocene at 3068 to 3093 m and in top Triassic at 4622 to 4637 m. Shows were reported as follows: Direct yellow fluorescence on cuttings at 2955 m; Weak direct fluorescence and poor streaming yellow cut fluorescence on cuttings at 3075 - 3145 m; Yellowish green direct fluorescence and dull bright yellow cut fluorescence on cores at 4186 - 4219 m; Weak direct fluorescence and pale cut fluorescence on cuttings at 4527 - 4542 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>One core was cut from 4129 m to 4147 m in the Farsund Formation and five more from 4181 m to 4284 m in the upper half of the Ula Formation (core depths = log depths + 7 m for core 1 and + 6.4 m for cores 2 to 6). RFT wire line fluid samples were taken at 4212 m (2 l gas and 3.5 l light brown water with yellow green oil film), 4244 m (3.5 l water), 4214 m (3.5 l water with strong petroleum odour), and 4436 m (4.2 l fluid).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 24 March 1983 as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Three DST's were performed in this well.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1 tested the intervals 4528.5 - 4533.8 m + 4535.3 - 4538.3 m + 4546 -4552 m. It produced mud filtrate and formation water at a rate of 2.63 m3/day. The maximum temperature recorded in the test was 160.9 deg C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 4233 - 4240 m. It produced formation water at a rate of 170 m3/day. The maximum temperature recorded in the test was 160.0 deg C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 3A tested the interval 4202 - 4208 m. It produced mud filtrate and formation water at a rate of 0.6 m3/day. The maximum temperature recorded in the test was 158.3 deg C. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 3B tested the intervals 4202 - 4208 + 4211 - 4214 m. It produced 143 Sm3 oil and 28000 Sm3 gas/day. The GOR was 196 Sm3/Sm3, the oil density was 0.829 g/cm3, and the gas gravity was 0.820 (air = 1). The maximum temperature recorded in the test was 165.6 deg C. </span></p> |
87
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5/19/2016 12:00:00 AM
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04.11.2024
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1/3-4
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/3-4 was drilled on the northern part of the Hidra High in the North Sea. The objective was to test the hydrocarbon potential of the Danian and late Cretaceous Chalk, on a domal structure induced by halokinesis.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-4 was spudded with the semi-submersible installation Dyvi Alpha on 15 February 1983 and drilled to TD at 3198 m in the Late Permian Zechstein Group. While drilling through Middle Miocene claystones, the average background gas increased rapidly from 5% to 80% between 1580 m and 1595 m and, at this depth, the mud weight had to be increased gradually from 1.37 to 1.50 - 1.53 to lower the gas content. Furthermore, to stop the gas leakage and to isolate the weak zone, it was decided to set the 13 3/8" casing. Logs were run (ISF/BHC and LDT/CNL) and the casing was set with shoe at 1557 m. While circulating after the logging a gain of 1 m3 with gas and more than 100 litres of oil occurred. To stabilize the well, 2 cement plugs and 4 barite plugs were set, in order to stop the gas leaking from the formation. In total, twenty days were spent on circulating, logging (ISF/BHC and LDT/CNL), setting the 13 3/8" casing, and plugging before drilling of the 12 1/4" section commenced. While drilling the 12 1/4" hole, the background gas varied between 32 and 84% down to 1695 m where the mud-weight was raised to 1.60. The background gas then decreased between 10 and 25% and drilling continued normally. Logs performed at the end of the 12 1/4" phase and covering the zone of interest are strongly affected by large cavings and by barite squeezed into the formation. Side wall core recovery was very poor from the caved zone. The well was drilled water based.</span></p> <p class=MsoBodyText><span lang=EN-GB>The first evidence of hydrocarbons in the well was the gas and oil kick at 1595 m in the base of the Middle Miocene, The oil in the mud was a 34 deg API gravity oil and geochemical analysis suggested that the organic matter rich Mandal Formation of Late Jurassic age was the source rock. However, according to the lithology and log information, there was no evidence of a reservoir at this level. The oil was probably trapped in a fault that acted as a drain. The Ekofisk Formation (Danian limestone) was encountered at 2754 m, and the Tor Formation (Maastrichtian) at 2797 m. Most of RFT measurements and core analysis showed that both formations were virtually tight and water bearing, but some residual hydrocarbons (60 - 80% water saturation) was seen on Cyberlook computation 2754 to 2780 in the upper Ekofisk Formation. Shows on cuttings and cores were as follows: Bright yellow direct fluorescence at1580 - 1600 m; direct bright yellow fluorescence with pale yellow cut on sand grains at 2244 m; direct yellow fluorescence in limestones with whitish to pale yellow cut at 2678 - 2687 m; pale yellow direct fluorescence on a few particles at 2753 - 2765 m; a gain of 8m3 of salt water (85 g/1) with trace of hydrocarbons was observed at 2884 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut in the Chalk. </span><span lang=EN-US>Core 1 was cut at 2780 - 2789 m</span><span lang=EN-GB> with 95% recovery, and core 2 at 2817 - 2830 m with 8% recovery. Due to tight formation no fluid samples were taken on the RFT, but oil samples were taken from the oil in the mud at 1595 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 8 May 1983 as a dry well with strong oil shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
2
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5/19/2016 12:00:00 AM
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04.11.2024
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1/3-5
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<p><b>General</b></p>
<p>Well 1/3-5 was drilled on a NW-SE oriented fault block tilted towards the NW. The structure is located in the northern Permian basin, on the east side of Central Graben, extending into blocks 116, 211, and 2/4. The purpose of the well was to evaluate the hydrocarbon potential of the Rotliegendes Group sandstones.</p> <p><b>Operations and results</b></p> <p>Wildcat well 1/3-5 was spudded with the 3-leg jack up installation Neddrill Trigon on 1 October 1984 and drilled to TD at 4850 m in the Permian Rotliegendes Group. After setting the 30" conductor a 14 3/4" pilot hole was drilled to 1195 m, before opening the hole to 26". Drilling to 2470 m the mud weight was raised from 1.33 g/cm3 to 1.70 g/cm3 due to high formation pressure. This resulted in tight hole during wiper trips, and high weight strain on the drill string, and also caused the 13 3/8" casing to be set somewhat higher than prognosed. Through the chalk sequence the hole seemed to be tight, and while tripping at 3523 m, the drill string got stuck with the bit at 3515 m. It was assumed that the tight interval was caused by one of the stabilizers between 3247 and 3267 m. The string was freed by pumping acid. A high pressure sand sequence in the interval 4363-4395 m, with pore pressure close to the last leak-off Test, resulted in the 7" liner being set 520 m higher than prognosed. The well was drilled with spud mud down to 1195 m, with KCl/polymer mud from 1195 m to 3000 m, from 3000 m the mud was lightly treated with lignosulphonate. Fifty bbl of pipelax with a mud/diesel ratio of 1:1 was added to the mud to free the stuck pipe at 3515 m. From 4122 m to TD the well was drilled with a polymer/sulphonated resin mud.</p> <p>Traces of yellow direct fluorescence, mainly on fractures, with a moderate milky-white cut fluorescence were observed at the top of the Tor Formation and at several levels deeper down in the formation. Also near the base of the Hod Formation, a very weak and slow pale yellowish cut fluorescence was occasionally observed. Direct fluorescence was not detected. Petrophysical analysis supported that some zones in the lower Hod Formation (4369 m to 4448 m) could be marginally hydrocarbon bearing. The objective Rotliegendes sand came in at 4769 m. Results from permeability measurements indicated that the sand was water bearing and tight, although porosity readings from the core from this sand were surprisingly high. A water-bearing formation was supported also by low background gas readings and lack of shows while drilling through the interval. </p> <p>One core was cut in the Rotliegendes Group sandstones from 4805 m - 4814 m. An FMT sample taken at 4387 m (Lower Hod Formation) recovered mud filtrate only. An FMT sample taken at 4770 m near the top of the Rotliegendes Group recovered mud filtrate, with no indications of hydrocarbons.</p> <p>The well was permanently abandoned on 11 February 1985 as a dry well with shows.</p> <p><b>Testing</b></p> <p>No drill stem test was performed in the well.</p> |
223
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7/6/2016 12:00:00 AM
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04.11.2024
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1/3-6
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<p><b>General</b></p>
<p>Well 1/3-6 is located between the Gyda, Ula, and Blane fields in the Central Graben of the Norwegian North Sea.</p> <p>The primary objective was Late Jurassic Ula sands deposited as a rim syncline linked to salt diapirism. The Ula sands had been found hydrocarbon bearing in several wells in the surrounding blocks. Secondary objective was Late Paleocene "Cod sands" (Forties Formation), which could be present in the 1/3-6 area and could pinch out towards the diapir. The prognosed TD was 5030 m below MSL. The "Cod sands" were considered a low-probability target.</p> <p><b>Operations and results</b></p> <p>Wildcat well 1/3-6 was spudded with the semi-submersible installation Dyvi Stena on 11 March 1991. Drilling performance went on without significant problems but the primary target of the well was not reached. The discovery of a significant hydrocarbon-bearing reservoir in the Paleocene activated the contingency measures of the programme (to set an extra 11 3/4" liner). For safety and technical reasons, and to allow for a proper test of the Paleocene, the well was stopped at 3586 m in the Late Cretaceous Hod Formation. No shallow gas was encountered while drilling. The well was drilled with a KCl polymer mud.</p> <p>The well encountered 85 m of hydrocarbon bearing Forties sands at 2913.5 m. The pay zone was 44 m thick with a hydrocarbon saturation of 56 %. No hydrocarbon-water contact was found. Apart from the hydrocarbons in the Forties sands oil shows were also recorded from 3519 to 3530 m in the Tor Formation.</p> <p>One conventional core was cut at 2921 m to 2928.5 m in the Forties sands. Segregated fluid samples were taken at three depths: 2923 m (filtrate and gas), 2937 m (filtrate and gas), and two samples at 2973.5 m (filtrate and gas in one and filtrate only in the other).</p> <p>The well was permanently abandoned on 22 June 1991 as a gas-condensate discovery.</p> <p><b>Testing</b></p> <p>Three DST tests were performed. DST 1A and DST 1B both tested the interval 2960.5 - 2977 m. Due to packer failure</p> <p>during DST 1A this test was abnormally terminated and the re-test DST 1B was performed. DST 1B produced 78 Sm3 oil and 93300 Sm3 gas /day through a 44/64" choke in the final flow period. The GOR was 1196 Sm3/Sm3. The bottom hole temperature in this flow was 107.2 deg C.</p> <p>DST 2 tested the intervals 2913 - 2924 m + 2929 - 2953 m. The final flow in DST 2 was 153 Sm3 oil and 172500 Sm3 gas /day through a 48/64" choke. The GOR was 1131 Sm3/Sm3 and the condensate gravity was measured to 50.47 deg API. The pressure drawdown in this flow was 290 bar and the bottom hole temperature was 112.2 deg C. The maximum temperature in DST 2 was 123.1 deg C and was recorded in the flow with the lowest rates and lowest drawdown. It was believed to be closer to the true formation temperature than the one recorded in DST 1B. </p> |
1521
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7/6/2016 12:00:00 AM
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04.11.2024
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1/3-7
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-7 is located on the Hidra High in the North Sea. It was drilled to appraise the 1/3-6 Oselvar condensate discovery made in Paleocene Forties Formation sandstones. The well was placed down-flanks on the structure relative to the discovery well in order to penetrate the hydrocarbon-water contact and further appraise reservoir properties and production rates. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 1/3-7 was spudded with the 3 leg jack-up installation West Epsilon on 13 February 1995 and drilled to TD at 3345 m in the Paleocene Våle Formation. A gas kick was taken at 1740 m in the top of the Hordaland Group, later it was found that the gas probably originated from a limestone less than one meter thick. The hole packed off, the string had to be cut off at 1564 m, and the hole was plugged back. A technical sidetrack (1/3-7 T2) was made from 1204 m. This sidetrack failed as the bit fell back into the original hole during a wiper trip. A new and successful technical sidetrack (1/3-7 T3) was made from 1202 m. A second gas kick occurred in the T3 sidetrack when reaching 1741 m. This kick was controlled by the driller's method without significant problems or extra rig time. The extra activity caused by the first kick prolonged the rig time with 23 days. Due to poor hole conditions no open hole logging was performed in the 12 1/4" section. As the West Epsilon was available only up to 28 May open hole logging at final TD was also abandoned in order to secure time for the well test. The reservoir was logged through casing. The well was drilled with sea water down to 207 m and with gelled mud from 207 m to 1204 m. From 3103 m to TD it was drilled with a salt polymer.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top Forties Formation was encountered at 3175 m. The Forties reservoir sandstones was encountered at 3183.5 m and proved to be oil bearing down to an oil-water contact at 3225 m. The logs indicated hydrocarbons down to 3229.4 m (3182.3 m MSL) and oil shows (direct and cut fluorescence) were reported down to 3232 m. This lower zone was considered to be only a residual oil zone, which was indicated also by the change in geochemical composition. No oil shows were reported above the Forties reservoir or below 3232 m, only background gas. The up-flanks 1/3-6 reservoir contains condensate. Hence, the 1/3-7 well suggests a ca 490 m hydrocarbon column with a gas/oil contact somewhere between the two wells. However, the depth of a GOC could not be determined, nor could it be deduced with any certainty that there is pressure communication between the reservoir sections penetrated in the two wells.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 74.5 m core was cut and retrieved in 4 cores in the interval from 3164 to 3251 m. No wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 25 May 1995 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Two tests were performed on the reservoir.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1A tested the interval 3183.5 to 3215.5 m. It produced 49 Sm3 oil and 16783 Sm3 gas /day through a 1/2" choke. The GOR was 333 with a well head flowing pressure (WHFP) of 15.4 bara. The density of the oil was 0.797 g/cm3.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1B tested the intervals 3183.5 to 3215.5 m and 3220 to 3224.5 m. It produced 136.8 Sm3 oil and 37762 Sm3 gas /day through a 1/2" choke. The GOR was 280.9 Sm3/Sm3, with a well head flowing pressure of 35 bara. The formation temperature was measured in the tests to be 131.6 deg C. The formation temperature was taken as the highest flowing temperature just after opening the well for DST 1A. This is due to the temperature reducing with time because of the thermal expansion effect of gas (BHFP << Bubble point pressure).</span></p> |
2505
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7/6/2016 12:00:00 AM
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04.11.2024
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1/3-8
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-8 is located on the Hidra High in the North Sea. The primary objective was to test the Jurassic Upper Ula sand package within the Kamskjell prospect. The secondary objective was a sand package at the base of the Jurassic. Planned TD was tagging the Triassic or reaching 5085 meters TVD SS.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/3-8 was spudded with the 3 legs jack-up installation Transocean Nordic on 12 December 1996 and drilled to TD at 5199 m in the Triassic Smith Bank Formation. Two major unscheduled events occurred in the 12 1/4" section. First, the mud line hanger failed. A total of 16 days was required to repair this before drilling could be resumed. Secondly, and more serious, a 3.5 bbl kick was taken at 4529 m while drilling a limestone interval in the Early Cretaceous Cromer Knoll Group. Based on the worst case scenario interpretation of the kick, there could be a large volume of hydrocarbons (estimated at up to 300 bbls) in the annulus between the kick and thief zones. For this reason it was decided to rig up flare booms to increase the rig safety should it become necessary to by-pass the MGS whilst circulating out the influx. The well was opened up, and the influx circulated out at 3.3 bpm. Initially returns were taken through the MGS. After pumping 1464 bbls returns were switched from the MGS to the boom. This decision was taken as gas levels in the pit room were rising, and the seal leg pressure was dropping steadily (from 11.5 to 6.4 psi) indicating the onset of possible blow-down. The flare lit immediately with the clear burn characteristic of condensate. A total of 420 bbls was flared before mud was at surface and the flare extinguished. A total of 15 days were spent stabilising the well to permit running casing and continue drilling the next section. The well was drilled with seawater down to 303 m, with pre-hydrated gel mud down to 1105 m, with KCl/polymer/glycol mud from 1105 m to 3445 m, and with Ancovert oil based mud from 3445 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The only live hydrocarbons found in the well was the condensate kick at 4529 m in the Cromer Knoll Group, believed to originate from a fracture in the Sola Formation limestone. The target Upper Ula Formation was not found in the well. Poorly developed and generally tight Basal Jurassic sands were encountered at 5005 m with a pooled thickness of ca 22 m. Poor oil shows were recorded in the interval 5007 to 5024 m in these sands. Thin sands were present also in the Triassic, but no shows were recorded in these. </span></p> <p class=MsoBodyText><span lang=EN-GB>One core was cut in the interval 5024 to 5041 m with 15.07 m recovery. One FMT fluid sample was taken at 5006.3 m, recovering muddy water with 190000 ppm of chloride.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 27 May 1997 as a dry well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
2829
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7/6/2016 12:00:00 AM
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04.11.2024
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1/3-9 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-9 S is located on the Tambar Field on the Cod Terrace in the North Sea. The objective was to appraise the possibility of commercial quantities of hydrocarbons in the Ula Formation sandstones of the JU8 prospect (the Ula Formation is sometimes referred to as the "Gyda Sandstone Member" in this part of the North Sea). The well was planned deviated to avoid shallow gas anomalies and to fully appraise the target sand.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-9 S was spudded with the semi-submersible installation Mærsk Jutlander on 8 May 1998 and drilled to 3100 m where hole problems led to plug-back and a sidetrack (1/3-9 S T2) with kick-off at 1836 m. Final TD of the well was set at 4516 m in the Late Jurassic Ula Formation. The well was drilled with seawater and hi-vis pills down to 1050 m, with Barasilc WBM from 1050 m to 3185 m, and with Enviromul OBM from 3185 m to TD. Total Non-Productive time for the well was 40%, most of which was due to contamination of the mud system, the side-track of the well and the TD logging performance. The 12 1/4" Section was notably different from plan, after an unexpected water kick was taken at 2535 m. This not only reduced the mud systems ability to accept contaminants, with a required MW increase up to 1.7sg, but also severely reduced the ROP, due to high overbalance drilling, later in the section. This also resulted in setting the 9 5/8" casing high, leaving reactive shales open whilst drilling the 8 1/2" section. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Palaeocene Forties sands of the 1/3-6 and 1/3-7 wells were not encountered.</span><span lang=EN-GB>The target Ula Formation sandstone was encountered at 4266.3 m, 33.7 m high to prognosis. It was oil-bearing with an estimated OWC at ca 4375 m. Oil shows, both fluorescence in cuttings samples and drilled gas with the compositional range of C1 - C5, were observed through the interval 4273 - 4377 m, within this unit. No other shows were recorded in the well. Analysis of MDT pressure revealed a 550 psi difference compared to well 1/3-3 and Gyda well 2/1-6. This is interpreted as being a result of depletion from Gyda oil production, and suggests there is significant communication through the aquifer between the JU8 structure and the Gyda Field.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 105 m of core was cut in two cores in the Ula Formation. A total recovery of 99.7% was obtained, representing the two longest core recoveries in the area. MDT oil samples were taken at 4279.5 m, 4304.98 m, and at 4346.49 m. Following extensive logging of the well, a 7" liner was run in preparation for future development. The well was temporarily suspended on 31 July 1998, with a combined trawl guard and corrosion cap left on top. In June 2001 it was re-entered and reclassified to development well on the Tambar and Tambar Øst Fields.</span></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/3-9 S is classified as an appraisal of the 1/3-3 Tambar Discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
3362
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7/6/2016 12:00:00 AM
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04.11.2024
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1/5-1
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The Flyndre (1/5-1) well was drilled on a structural high situated in the Feda Graben of the North Sea close to the UK border. At the commencement of the well the principle objective horizons were the Paleocene and Jurassic sand sections which had produced oil in the UK 30/13-2 well and the NO 2/7-3 wells respectively. It was estimated that at Paleocene depth the structure was an irregular dome about 4 miles in diameter, with 12 square miles of closure and 290 ft (88.4 m) of vertical relief while at Jurassic depth the structure was a NW-SE trending anticline 4.5 miles by 3.5 miles with 12 square miles of closure at 190 ft (57.9 m) of vertical relief. Planned TD was 15000 ft (4572 m), Triassic sands, or the Zechstein Group, whichever came first.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/5-1 was spudded with the semi-submersible installation Ocean Viking on 12 October 1973. The well was drilled to 491 m in the Nordland Formation. When running 20" casing the casing got stuck. After an unsuccessful fishing operation the well was permanently abandoned on 19 October 1973 as a junk well. No cores were cut and no wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>Replacement well 1/5-2 was spudded 15 m away in a 320 deg true direction.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
237
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7/6/2016 12:00:00 AM
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04.11.2024
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1/5-2
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The Flyndre well (1/5-2) was drilled on a structural high situated in the Feda Graben of the North Sea close to the UK border. The principle objective horizons were the Paleocene and Jurassic sand sections which had produced oil in the UK 30/13-2 well and the NO 2/7-3 wells. It was estimated that at Paleocene depth the structure was an irregular dome about 4 miles in diameter, with 12 square miles of closure and 290 ft (88.4 m) of vertical relief while at Jurassic depth the structure was a NW-SE trending anticline 4.5 miles by 3.5 miles with 12 square miles of closure at 190 ft (57.9 m) of vertical relief. Planned TD was 15000 ft (4572 m), Triassic sands, or the Zechstein Group, whichever came first. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><a name="OLE_LINK2"></a><a name="OLE_LINK1"><span lang=EN-GB>Well 1/5-2 </span></a><span lang=EN-GB>was spudded on 19 October 1973, 15 m away from the original Flyndre well 1/5-1, which was junked at 491 m for technical reasons. Well 1/5-2 was drilled with the semi-submersible installation Ocean Viking. Total depth was set at 4287 m in Late Permian Zechstein salt. The well was drilled with seawater and hi-vis pills down to 494 m. The rest of the well was drilled with lignosulphonate mud.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well had shows throughout the Paleocene and Late Cretaceous sections and four drill-stem tests were carried out.</span></p> <p class=MsoBodyText><span lang=EN-GB>The top sand in Paleocene at 2832 m (Forties Formation sand) produced oil upon testing. Mud log shows were present in the Danian, but testing proved the section to be tight and unproductive. A thick Late Cretaceous section was encountered with oil shows at the top of the Maastrichtian (Tor Formation) and in the Campanian (Lower Tor and Hod Formation) sections. Drill-stem tests were carried out in these zones and the Maastrichtian zone produced oil from fractured limestone at 3151.6 - 3174.2 m while the lower zone from 3337.6 - 3363.2 m was tight with only minor amounts of oil being recovered. The Early Cretaceous section, 281 m thick, consisted of sediments of Albian/Aptian and Barremian age. There were no shows in this section. The Jurassic, section was encountered at 4203 m but contained only 24 m of Kimmeridgian shale. The Kimmeridgian rested directly upon the Zechstein Group at 4228 m. </span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 15 April October 1974 as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Four intervals were perforated and tested.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST I tested the interval 3337.6 - 3363.2 m in the lower Hod and upper Tor Formations produced a total of 5.6 Sm3 oil and 17.5 m3 of water. The oil gravity was 35 deg API.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST II tested the interval 3151.6 - 3174.2 m in the Tor Formation produced 501 Sm3 oil, 180661 Sm3 gas, and 49 m3 water /day through a 54/64" choke. The GOR was 361 Sm3/Sm3 and the oil gravity was 42 deg API. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST III tested the interval 3076.7 - 3102.9 m in the Ekofisk Formation produced total 30- 40 m3 water with 6 - 20% oil.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST IV tested the interval <a name="OLE_LINK4"></a><a name="OLE_LINK3">2831.6 - 2841.3 m </a>in the Forties Formation. It produced 37 sm3 oil, 16707 Sm3 gas, and 24 m3 water /day. The GOR was 456 Sm3/Sm3 and the oil gravity was 42.6 deg API.</span></p> |
238
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7/6/2016 12:00:00 AM
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04.11.2024
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1/5-3 S
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<p><b>General</b></p>
<p>Block 1/5 is situated in the Norwegian Central Trough at the transition of the Feda Graben and the Breiflabb Basin. Well 1/5-3 S was planned as an exploration well with TD at 2910 m in the Tor Chalk Formation. The well was positioned in a seismically defined "gas chimney" on the crest of a salt induced diapir and was the first well drilled on this diapir. Similar cases have been drilled successfully by STATOIL on the Tommeliten Discovery 1/9-2 and 1/9-3 wells. The primary objective of well 1/5-3 S was to test the presence of moveable hydrocarbons in fractured, reservoir quality chalk of the Ekofisk and Tor formations along the southwestern flank of the diapir. A secondary potential objective was in the Paleocene Rogaland Group. A total depth of 1566 m was reached in the 12 1/4" hole section on June 29, 1998 before deciding to permanently abandon the well due to increasing pore pressure, without fulfilling any of the well objectives.</p> <p><b>Operations and results</b></p> <p>Exploration 1/5-3 S well was spudded with the semi-submersible "Byford Dolphin" on 10 June 1998 and drilled to TD at 1566 m in rocks of Late Miocene age (undifferentiated Nordland Group). The well was drilled with seawater and hi-vis pills down to 792 m and with Baroid "BARASILC" silicate / KCl glycol enhanced ("GEM GP") mud from 792 m to TD. Due to possible shallow gas hazard at 466 m, a 9 7/8" pilot hole was drilled below the 30" conductor to 780 m. The 9 7/8" hole was opened up to 26" at 792 m prior to setting 20" casing at 785 m. No shallow gas was observed from the MWD resistivity in this hole section.</p> <p>Record setting overpressures were experienced in the 17 1/2" hole section in well 1/5-3 S. Abnormal pressures were indicated first at 700 - 800 m. Pore pressures built quickly to 1.4 g/cc due to gas just below 1000 m in. Having passed that depth, the hole drilled without problems until below 1200 m where it again became gassy. Mud weight was increased to 1.52 g/cc, thus reducing 30% gas to 5-10%. This weight was sufficient until below 1400 m when gas again increased. By 1450 m, the DXC was beginning to show signs of increasing pore pressure, as was the MWD resistivity. Below 1500 m, gas went off scale and an oil kick to 1.70 BMW was taken at 1544 m. Pressures of this magnitude were not forecast at all. Lost circulation was experienced during well control operations, which eventually lead to cementing of the BHA, and plugging back to sidetrack around the fish. The 17 l/2" hole was re-drilled as 1/5-3 S T2 from 1246 m to a revised 13 3/8" casing point at 1412 m. Although re-drilled with 1.60 g/cc mud weight versus the original 1.52 g/cc mud, the hole drilled nearly as gassy as the original hole. Following the 13 3/8" casing, an excellent leak-off was tested to nearly overburden gradient at 1.98 BMW. </p> <p>The 12 1/4" drilling was done with Statoil's Tommeliten method which emphasized ignoring gas in favour of other pressure parameters while minimizing mud weight builds but this proved to be unsuccessful for 1/5-3S. After drilling out with 1.76 g/cc mud weight, the hole became so gassy (up to 50%) from limestone stringers oozing oil that it had to be circulated clean at 1494 m, and 1.80 g/cc mud was circulated around. This should have balanced the 1.7 BMW kick zone coming up at 1544 m, as well as leading to increased confidence, as gas and cuttings size would diminish. Although the cuttings remained small until growing to 7 cm splinters near TD, gas was again off scale. By 1566 m, only 22 m beyond the second kick zone, the well was shut-in. 1.86 g/cc mud weight was required to balance the formation, and 1.90 g/cc mud weight was eventually circulated around on a dead well. Well 1/5-3 S T2 had transitioned from a pore pressure of 1.7 EMW at 1544 m to 1.86 EMW at 1566 m in only 22m of new hole. At this point the decision was taken to plug and abandon the well.</p> <p>Three kicks taken were regional records for both overpressure magnitude and shallowness of depth. Statoil's Tommeliten Field in block 1/9 did not see anywhere near the overpressure magnitude and shallow onset; mud weight was able to control mud gas far more successfully on Tommeliten and multiple hydrocarbon kicks were not experienced. Conoco's 1/6-5 crestal diapir well also exhibited a lesser overpressure profile. In hindsight the most important methods to monitor the pressure during drilling were the MWD resistivity and the cuttings shape and size. Gas in the mud was carefully monitored and plotted in units of percent methane in air. Gas was commonly 5% in the claystones, some of which showed bleeding gas at the surface, and ran 30-50% and higher in the carbonate stringers, which bled oil at the surface. The gas chimney section drilled with high gas background all the way from the top of overpressure to the terminal kicks below 1500 m. While the mud gas gave a general indication of overpressure, the high background levels actually obscured both of the final two kicks. </p> <p>Good trace of crude oil in the mud was observed from 1498m. At 1544 m, a kick was taken which resulted in crude oil being circulated up to the rig. Circulating gas varied between 40-100%, with peaks way above 100% caused by large amount of hydrocarbons. The crude oil collected at surface was dark yellowish brown and had a density of 0.84 g/cc (37 API) measured with a pressurised mud balance. Later laboratory analysis onshore gave a density of 0.80 g/cc (35.1 API).</p> <p>No conventional or sidewall cores were taken in this well. The well was permanently abandoned as a junked well with minor oil on 6 August 1998.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
3257
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7/6/2016 12:00:00 AM
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04.11.2024
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1/5-4 S
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<p><b>General</b></p> <p>The primary objective of the 1/5-4 S well was to test the hydrocarbon bearing potential of a Chalk prospect close to the crestal position on the NE side of a salt diapir. The well path was also planned to penetrate the edge of a mapped Palaeocene fan system. Hydrocarbon bearing Forties sandstone were targeted and treated as a secondary objective. Thicker and better quality sandstones were expected to be present down flank of the structure. </p> <p>The overburden was known to contain charged feature, as experienced by the Conoco well 1/5-3 S. In order to avoid these fractures and the associated well bore instability problems, a delineated well path using Oil Based Mud was planned from the 12.25" hole section to TD.</p> <p><b>Operations</b></p> <p>Exploration well 1/5-4 S was spudded with the semi-submersible installation Deepsea Bergen on 17 April 2002 and drilled deviated to TD at 3090 m in rocks of Permian age. Drilling went very well and closely followed the plan. The well was drilled with seawater and gel sweeps down to 928 m and with KCl/Glycol mud from 928 m to 1646 m, and with oil based mud from 1646 m to TD. </p> <p>Top Palaeocene was encountered 55 m higher than prognosis. Two thin sandstone beds were drilled, both within the Lista formation (Andrew Formation sandstones). The lower stringer was tight but contained some shows. The upper stringer had better reservoir properties however. Forties sandstone were absent. The primary objective, the Chalk, was 118 m higher than forecast, and 49 m thick, which was 80 m thinner than expected. The chalk was found to be water saturated with a maximum porosity of 25 %, and in pressure communication with the thin Palaeocene Andrews sand stringer. Minor shows were reported in the chalk. No sidewall or conventional cores were cut. An FMT sample was taken at 2945 m. It recovered only water. The well was permanently abandoned as a dry well with shows on 24 may 2002</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
4521
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7/6/2016 12:00:00 AM
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04.11.2024
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1/5-5
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 1/5-5 was drilled to test the Solaris prospect in the Central Graben, about 40 km North-West of the Ekofisk field, close to the border between UK and Norway. The primary target was to prove reservoir and hydrocarbon presence in Late Jurassic reservoir sands of the Ula Formation. Secondary target was the Triassic Skagerrak Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/5-5 was spudded with the jack-up installation Mærsk Gallant on 24 February 2016 and drilled to TD at 5942 m in the Middle - Late Vestland Group. A pilot hole was drilled from 210 to 1140 m to check for shallow gas, but no gas was seen and the opening up and continuation of the well could be carried out. The well is a deep high temperature-high pressure well. Thirty-nine days were counted as NPT. The single main cause of NPT (11 days) was main rig maintenance and changing the drilling line after installing BOP at 1140 m. Otherwise operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 1140 m, with NABM oil based mud from 1140 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The primary target Ula Formation sandstone was encountered at 5831 m. The Ula Formation was 80 m thick and consisted mainly of sandstones and a few siltstones. The reservoir showed traces of gas and wireline logging was carried out for further classification. The logging proved the reservoir tight, of moderate to poor quality, and dry. There were no shows above the oil-based mud. As the primary reservoir was found dry, it was decided not to continue to the secondary, Triassic target.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 16 September 2016 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7874
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3/16/2018 12:00:00 AM
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04.11.2024
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1/6-1
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<p><b>General</b></p>
<p>Wildcat well 1/6-1 is located ca 15 km northwest of the Ekofisk Field in the southern Norwegian North Sea. It was drilled in a crestal position on a large chalk structure shared between Norske Shell's block l/6 and Phillips' block 2/4, the Ekofisk block. Phillips participated in drilling this well on a 50/50 basis. The primary objective was to investigate Danian and Maastrichtian chalk prospects. Secondary objective was to evaluate possible sand developments in the Paleocene and the Lower Cretaceous or older units. Planned total depth was 4572 m (1500 ft).</p> <p><b>Operations and results</b></p> <p>Well 1/6-1 was spudded with the jack-up installation Zapata Nordic on 10 July 1972 and drilled to TD at 4822 m in the Late Permian Zechstein Group. No major technical problems were encountered in the operations and the drilling of this deep well was within the prognosed time schedule. The drill string stuck at 228 m. After working the string and spotting pipe-free/diesel the string came loose. Some highly porous limestone intervals (1 - 8 m thick) resulted in lost circulation problems. The pipe stuck at 3456 m, but was freed after spotting with pipe-free/diesel. The well was drilled with seawater down to 448 m, with seawater/lignosulphonate and a shale inhibitor (shalock) from 448 m to 1586 m, and with seawater/lignosulphonate/ligcon (caustisized lignite) from 1586 m to TD.</p> <p>Reservoir development was encountered only in the Chalk Formations, with hydrocarbon-bearing intervals being developed in both the Danian and Late Cretaceous. Four hydrocarbon-bearing intervals were encountered and tested within the Chalk, but only one zone in the Maastrichtian (Tor Formation), yielded commercial flows of gas and condensate. Reservoir developments in the Danian (Ekofisk Formation) and earlier Maastrichtian (Hod Formation) were found to be considerably less favourable in l/6-l than in the adjacent Ekofisk and West Ekofisk field. The Early Cretaceous (Valanginian) was found resting directly on Late Permian Zechstein evaporite at 4800 m.</p> <p>Two cores were cut in the intervals 3177.5 to 3189.7 m and 4604.6 to 4610.7 m. No fluid samples were taken on wire line.</p> <p>The well was permanently abandoned on 26 November as a gas/condensate discovery.</p> <p><b>Testing</b></p> <p>Based on results from logging four zones were perforated and tested. </p> <p>Zone 1 was perforated from 3821 to 3833 m in the (DST 1, Hod Formation). The test produced only a small quantity of gas and traces of light crude/acid emulsion. </p> <p>Zone 2 was perforated in the intervals 3653.6 - 3650.6 m, 3646.0 - 3647.5 m, and 3621 - 3632.2 m (DST 2, Hod Formation). The test produced ca 65 Sm3 fluid (50% oil) /day. </p> <p>Zone 3 was perforated from 3270.5 m to 3279.6 m (DST 3,Tor Formation). The test produced at maximum 451 Sm3 oil and 480400 Sm3 gas /day. The rates decreased during the test and the GOR changed accordingly from 1070 to 1330 Sm3/Sm3. Oil gravity was 46.8 deg API. Maximum down hole temperature was 135 deg C. </p> <p>Zone 4 was perforated from 3152.9 m to 3158.9 m (DST 4, Ekofisk Formation). After acidization the test produced 24 Sm3 oil, 52000 Sm3 gas, and 29 Sm3 water / day. Oil gravity was 46.3 deg API, gas gravity was 0.745 (air = 1), and GOR was 2180 Sm3/Sm3. </p> |
239
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7/6/2016 12:00:00 AM
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04.11.2024
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1/6-2
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/6-2 was drilled between the Albuskjell and Flyndre Fields in the Feda Graben of the North Sea. The primary objective was to evaluate the Danian and Maastrichtian Chalk prospects (Ekofisk and Tor Formations) of a prominent diapiric domal structure. The well was placed on the flank of the structure.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/6-2 was spudded with the jack-up installation Zapata Nordic on 28 November 1972 and drilled to TD at 3383 m in the Late Cretaceous Hod Formation. Some downtime recorded in the top hole was due to a defect 20" casing shoe and bad weather, otherwise operations went forth without significant problems. The maximum deviation down to 3226.6 m was 3.5 deg. The well was drilled with Sea water and viscous mud down to 460 m, with Shaletrol mud from 460 m to 2445 m, and with Unical mud from 2445 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>In the Tertiary shale sequence potential reservoirs were limited to a few very thin (0.5 m or less) limestone or dolomite streaks. Top of the Chalk was encountered at 3024 m. The reservoir development in the Chalk was rather poor throughout, with the exception of a zone of ca 12 m in the Danian Ekofisk Formation having a porosity of about 26%. The Chalk formations were entirely water bearing as seen on the logs. However, weak hydrocarbon indications were observed in the Chalk (namely weak fluorescence and occasional slight oil staining), and relatively more abundant indications of oil staining and dead oil traces were recorded in the overlying Tertiary shales and interbedded carbonate layers.</span></p> <p class=MsoBodyText><span lang=EN-GB>One core was cut from 3226.6 m to 3241.5 m in the Tor Formation. The core confirmed the generally dense nature of the Chalk in this section. No wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12 January 1973 as a dry well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
240
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7/6/2016 12:00:00 AM
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04.11.2024
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1/6-3
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<p><b>General</b></p>
<p>Well 1/6-3 is located on the Albuskjell Field in the southern Norwegian North Sea. The primary objective was appraisal of reservoir development in the western part of the Albuskjell field. A Danian - Maastrichtian gas condensate field had previously been confirmed by two wells (A/S Norske Shell l/6-l and Phillips 2/4-9) drilled farther east along the WNW - ESE trending structure. Secondary objectives were to investigate Danian Chalk prospect and possible deeper prospects. </p> <p><b>Operations and results</b></p> <p>Appraisal well 1/6-3 was spudded with the jack-up installation Zapata Nordic on 12 April 1974. Three sidetracks had finally to be drilled, of which the second and deepest reached 3343 m in the Late Cretaceous Tor Formation. The first sidetrack was kicked off at 314 m after unsuccessful fishing (lost hole opener). The second sidetrack was kicked off at 3022 m when it was realised that a core point had been missed so that a Danian porous zone and 37 m of Maastrichtian had not been cored. Lost circulation and stuck pipe led to the third side track, which was kicked off at 2995 m. Further lost circulation problems and the discovery that there was a break in the casing at 3140 m finally led to abandonment of the well without investigating the deeper prospects. The well was drilled with seawater down to 417 m, with shale-trol/lignosulphonate from 417 m to 1221 m, with shale-trol/lignosulphonate and lime from 1221 m to 2500 m, and with lignosulphonate and lime from 2500 m to TD. A diesel/pipe lax pill was spotted at 314 m.</p> <p>As prognosed, gas was encountered both in the Danian and Late Maastrichtian Chalk. Hydrocarbons were present from Top Ekofisk at 3110 m down to an OWC at 3289.7 m in the Tor Formation. The net thicknesses were respectively 91 and 45 m. The great thickness of the Danian reservoir was in contrast to the findings from wells l/6-l and 2/4-9, where only a thin hydrocarbon-bearing zone was present in an otherwise tight Danian. </p> <p>Eleven conventional cores were cut over the interval 3123.3 to 3343.0 m. Of these, the first core was cut from 3123.3 to 3141.5 m in the first sidetrack, cores 2 to 9 were cut from 3162.3 to 3343 m in the second sidetrack, and cores 10 and 11 were cut from 3136.4 to 3163.8 m in the third sidetrack. No fluid samples were taken on wire line.</p> <p>The well was permanently abandoned on 11 September 1974 as a gas/condensate appraisal.</p> <p><b>Testing</b></p> <p>Two thin zones in the Maastrichtian chalk (Tor Formation) were Drill Stem Tested to obtain water samples. DST 1 tested the interval 3298 to 3299.5 m and started to produce gas, which had flown down the 7" / 8 l/2" annulus in preference to water from the formation opposite the perforations. The well was killed immediately for safety reasons. DST 2 was then attempted from the interval 3302.5 to 3304 m after a cement squeeze to shut of the annulus gas stream. The Formation proved tight and only gas cut mud was obtained. No water sample was obtained.</p> <p>The hydrocarbon bearing zones were Production Tested in two intervals: PT 1 from 3227.8 to 3265.9 m in the Maastrichtian chalk (Tor Formation) and PT 2 from 3125.7 to 3166.9 m in the Danian chalk (Ekofisk Formation). PT 1 produced after acid treatment on a 28/64" choke 541000 Sm3 gas and 409 Sm3 oil /day The GOR was 1325 Sm3/Sm3, the oil gravity was 47 deg API, and the gas gravity was 0.67 (air = 1). Maximum reservoir temperature (from build up period between 1.and 2. flow period) was 137.2 deg C. Unfortunately, no successful test was made of the Danian reservoir in Test 2, from the interval 3125.7 to 3166.9 m. This was due to plugging by formation and lost circulation material from the tested interval. In this zone, the Danian consisted of very friable, fractured chalk. The well slugged badly and gave unstable measurements. Average rates were 325000 Sm3 gas and 318Sm3 oil /day, with similar fluid characteristics as in Test 1.</p> |
241
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4/26/2022 12:00:00 AM
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04.11.2024
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1/6-4
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/6-4 was drilled in the southernmost part of the Breiflabb Basin in the North Sea. The objective was to evaluate a large low relief base Tertiary - Late Cretaceous structure with potential reservoirs both in the Danian - Late Cretaceous Chalk and in the Paleocene Sands. The primary target was the Chalk (Ekofisk and Tor formations).</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/6-4 was spudded with the semi-submersible installation Chris Chenery on 29 December 1975 and drilled to TD at 3810 m in the Late Cretaceous Tor Formation. The drilling of 1/6-4 was beset with rig mechanical problems, most notably failures in the mooring system induced by adverse North Sea weather. All in all 34 days (ca 33%) of the total rig time on the well was counted as down time. The well was drilled with bentonite/seawater spud mud down to 437 m and with lime/Drispac/seawater mud from 437 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top Rogaland Group, Balder Formation, came in at 3110 m. A Paleocene sandstone, Andrew Formation was penetrated from 3197 to 3253 m. Top Shetland Group, Ekofisk Formation, came in at 3374 m. The Balder Formation (Tuff marker) had some residual hydrocarbons up to 30%. This was substantiated by gas readings and some shows of fluorescence in ditch cuttings. The underlying Andrew Formation sandstones were found 100% water-bearing. Both the Danian and Maastrichtian were fully water bearing based on petrophysical analyses. This was in agreement with the lack of oil/gas shows while drilling in this section.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 9 April 1978 as a dry well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
242
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7/6/2016 12:00:00 AM
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04.11.2024
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1/6-5
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/6-5 is located in the Feda Graben between the Flyndre and Tommeliten Gamma discovery in the North Sea. The well was drilled on the crest of a major salt diapir. The objective of the well was to test the existence of a chalk raft and the presence of reservoired hydrocarbons.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/6-5 was spudded with the semi-submersible installation Dyvi Stena on 20 July 1990 and drilled to TD at 1854 in Late Permian salt of the Zechstein Group. An 8 1/2" pilot hole was drilled from 156m to 600m. The hole was control drilled at 30m/hr maximum ROP as a precaution for encountering shallow gas. No shallow gas was encountered. Pore pressure prediction while drilling in the 1/6-5 well was difficult as the only pore pressure detection parameters that appeared to work were gas measurements, resistivity and sonic log measurements. Other parameters such as shale cuttings density, Electric log density, D-exponent and rate of penetration were not successful in determining high pore pressure zones. However, despite the abnormally high pressures and temperatures encountered drilling went forth without major incidents. A minor salt water flow accompanied by a 37.1 % gas peak occurred during a trip at core point at 1725 m. The mud weight was increased from 15 ppg to 15.3 ppg and finally 15.5 ppg as a result of this flow. In the following coring 119 bbls of mud was lost to the formation, but this was cured by setting an LCM pill. The well was drilled with seawater and viscous pre-hydrated bentonite sweeps down to 600 m and with fresh water polymer mud/Duponol WBS 200 wellbore stabilizer from 600 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>From 864 m gas readings showed all components from C1 to C4. Gas peaks from the formation were experienced all the way down to the Ekofisk Formation, some of which originated from thin sandstone beds. Oil shows were first observed at 1434 and 1585 m, both in thin limestone beds of Oligocene age. On reaching the top Ekofisk Formation at 1721 m, limestone with oil stain and bright yellow fluorescence was observed. </span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut. Core 1 was cut from 1725 to 1742.5 m in the Tor and Hod Formations. Only 22% was recovered and most of it was rubble, indicating a highly fractured limestone. Core 2 was cut from 1742.5 to 1751.5 m in the salt. Ten RFT pressure tests were taken in the Shetland Group of which 6 were classified as valid tests. They indicated a formation pressure in the range of 4520 to 4540 psi, being equivalent to 15.6 ppg equivalent mud weight. No obvious pressure gradient could be derived from these 6 points.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 2 September 1990 as a dry well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One drill stem test was performed from perforations in the Shetland Group from 1722 to 1740.9 m. The well flowed only salt water at a rate of 231 m3/day on a 24/64" choke. There was no trace of oil and the gas content was too low to be measured. The shut-in pressure after final build-up was 4531 psia. The maximum bottom hole temperature recorded in the test was 98.3 deg C. This corresponds to a mean gradient of 56 deg C/km, assuming 6 deg C at the sea floor. This is an exceptionally high temperature gradient for the Norwegian North Sea.</span></p> |
1508
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7/6/2016 12:00:00 AM
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04.11.2024
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1/6-6
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<p><b>General</b></p> <p>Well 1/6-6 is located ca 2 km south of the Albuskjell Field in the southern Norwegian North Sea. The principal objective was to test the hydrocarbon potential of Middle and Late Jurassic sandstones on the southern flank of a faulted dip closure, partially underlying the Albuskjell Chalk Field. It was proposed to drill to a total depth of 5355 m or 200 m below the interpreted Base Late Jurassic.</p> <p><b>Operations and results</b></p> <p>Well 1/6-6 was spudded with the semi-submersible installation Dyvi Stena on 10 February 1992 and drilled to final TD at 5565 m (5562 m TVD), some 100 m into Triassic siltstone. The well achieved its objective, which entailed drilling 210 m deeper than plan, to a new Norwegian depth record of 5565 m RKB. Maximum pore pressure in the well was estimated to have been 2.24 sg, higher than the worst-case scenario defined by the well proposal. BHT was 190 deg C. Both pore pressure and BHT were the highest yet encountered in Norway. The well was production tested under these stringent conditions. </p> <p>Including additional time, the planned work scope for the well was 179.5 days. It eventually took 395 days. Of these, only 204.5 days (51.8%) was considered productive time. Five incidents accounted for 75% of lost time. These were: dropped 10-3/4" casing, failed wellhead, well control incident, failure of the HPC tieback packer and waiting on weather. The problems involved two sidetracks. The dropped 10-3/4" casing with TD at 4467 m led to the first sidetrack, which was made from kick-off at 2560 m. Then, after drilling to 3284 m and tripping out, a second sidetrack was accidentally made from 2522 m.</p> <p>The well was drilled with seawater and viscous sweeps to 1127 m and with gypsum / polymer mud from 1127 m to 4466 m in the first hole. The first sidetrack was drilled with gypsum/polymer mud from kick-off to TD. The second and final sidetrack was drilled with VISPLEX for sidetracking, then with HF PLUS (glycol) down to 4478 m, and with HITEMP polymer mud from 4478 m to TD. </p> <p>Top Paleocene was encountered at 3108 m. Weak shows were recorded in the Lista Formation. The Shetland Chalk Group was encountered at 3306 m and was 1345 m thick. The Late Jurassic Tyne Group was penetrated at 4876 m, and a "basal sand" of Early Kimmeridgian - Late Oxfordian age at 5396 m. The gross thickness of the sandstone was 61 m. There were indications of hydrocarbons in this sand, but a DST produced only water. No Middle Jurassic rocks were penetrated. Age at TD is not confirmed by biostratigraphic evidence as samples and core was barren of fossils.</p> <p>One ten-metre core was cut at TD in the well. During several FMT runs over the interval 5075 - 5450 m a total of 32 pressure settings were attempted, of which some 10 pressure points were considered useful. Two segregated samples were taken at 5432 and 5398 m. Both recovered only mud filtrate.</p> <p>The well was plugged and permanently abandoned on 8 March 1993 as a dry hole with shows.</p> <p><b>Testing</b></p> <p>The well was tested in the interval 5396 - 5407 m. The test flowed 900 Sm3 salt-saturated formation water and 4300 Sm3 gas /day through a 32/64" choke</p> |
1839
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7/6/2016 12:00:00 AM
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04.11.2024
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1/6-7
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/6-7 is located in the Feda Graben of the North Sea, approximately mid-way between the Albuskjell and Tommeliten Gamma fields. It was drilled on the flank of a salt diapir. The primary objective of the well was to test the hydrocarbon potential of Late Jurassic sandstones. Two secondary objectives were identified; to test for hydrocarbons in the Cretaceous Chalk and to test for the development and the hydrocarbon potential of Paleocene sands.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/6-7 was spudded with the semi-submersible installation West Vanguard on 16 March 1992 and drilled to TD at 4995 m (5001 m logger's depth / 4925 m TVD). A 9 7/8" pilot hole was drilled from 170 to 1007m prior to the 26" section to check for possible shallow gas at 311, 351, and 397 m. No shallow gas was seen. MWD check-shots inside the 20" casing (azimuth unreliable) proved that the well had sidetracked in the 26" hole. In the 12 1/4" hole a steerable assembly was run in hole to correct the course. This twisted off, leaving a fish at 3740 m. The well was plugged back to 3550 m and the well was sidetracked from 3650 m. After the sidetrack the azimuth stayed fairly constant in a northwest direction. The inclination, though, increased. In the 12 1/4" hole from 3515 m to 4329 m the angle built from 3.73deg to 13.52deg. The angle kept building in the 8 1/2" hole until a maximum MWD survey of 31.40deg at 4701m. At this depth the bit was pulled out of the hole for an intermediate logging run and to change the BHA to an angle dropping assembly. This assembly dropped the inclination to 24.7deg by TD. At 4878 m, in the top of Sandstone Unit II, a salt water kick was taken. The well was drilled with seawater with viscous pre-hydrated bentonite sweeps down to 1007 m, with inhibitive polymer mud system utilizing WBS-200 wellbore stabilizer to from 1007 m to 1400 m, with PHPA inhibitive polymer mud from 1400 m to 3273 m, and with high temperature polymer system mud from 3273 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Weak to fair shows in the claystone and limestone were seen in several intervals from 2680 to 2950 m (Hordaland Group), and free tarry oil in the mud was observed from 2912 - 2945 m (claystone with stringers of limestone and dolomite). The tarry oil was described as dark brown to black, with a resinous lustre, orange to yellow direct fluorescence, moderate to fast streaming yellowish cut and had a dark brown residue. The Chalk objective was drilled outside of structural closure and top Ekofisk Formation was penetrated at 3278 m (3275 m TVD). Moderate shows were described here in a zone from 3288 to 3293 m with weaker shows continuing down into core #1, and on cuttings further down to 3420 m. The electrical logs indicate an average porosity of 17.5% in this zone. BCU (top Mandal Formation) was penetrated at 4402.5 m (4388.6 m TVD). Two sandstone units of Oxfordian age, Sandstone Unit II (4750 - 4788 m / 4706.4 - 4739.7 m TVD) and Unit I (4879 - 4977 m / 4820 - 4907.5 m TVD) were penetrated. Average porosities of the Units were 16.1 and 21.5 % respectively.</span><span lang=EN-GB> </span><span lang=EN-GB>Shows in Sandstone Unit II (4750-4788m, Core #2 and #3) were described as very weak to no direct fluorescence, slow even bluish white crush cut, and faint creamy residue fluorescence. Shows in Sandstone Unit I (4879 - 4977 m) appeared with no fluorescence, no cut, minor traces of slow even bluish white crush cut and traces of creamy residue fluorescence. The cuttings in this unit had a good gas odour.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut with 100, 94.7, and 98.5% recovery, respectively. The first core was cut in the upper part of the Ekofisk Formation (3295 m - 3313.9, m) and the next two in the Haugesund Formation (4754 - 4773 m and 4773 - 4800.57 m respectively) in Sandstone Unit II and into the underlying shale. In order to match the gamma ray log cores #1, #2, and #3 has to be shifted + 1.2 m, +6.5 m, and +5.5 m, respectively. A total of 10 FMT pressure tests and one fluid sample were taken in Sandstone Unit I. Calculated pressure gradient in this sandstone is 0.52 psi/ft (0.12 Bar/m). The fluid sample, at 4884 m, contained water and mud filtrate only.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12 July 1992 as a dry well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
1928
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7/6/2016 12:00:00 AM
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04.11.2024
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1/9-1
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<p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/9-1 was drilled on a salt diapir structure located in the Feda Graben in the southern North Sea. The primary objective was to test hydrocarbon accumulations in the Danian and Late Cretaceous chalk. A secondary objective was to test the Jurassic and Triassic sandstones.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/9-1 was spudded with the semi-submersible installation Ross Rig on 14 October 1976 and drilled to TD at 3706 m in Cenomanian age limestone (Hidra Formation). The Jurassic was not reached. The anchor chain broke on three occasions. The third breakdown occurred during the last DST. The decision was then made to suspend the well for later re-entry. The well was drilled with seawater and gel slugs down to 433 m, and with seawater-lime-lignosulphonate from 433 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Danian chalk (Ekofisk Formation) was reached at 3043.5 m just below a marl section. It consisted of two hydrocarbon bearing zones. Zone 1 from 3043.5 m to 3071.5 m and a tighter zone 2 from 3071.5 m to 3103.5 m. Maastrichtian (Tor Formation) starts at about 3103.5 m and is also hydrocarbon bearing with water saturations below 50% down to 3141.5 m. A transition zone with gradually increasing water content is seen from 3134.0 m down to 3182.5 m. Apart from in the oil bearing reservoirs weak oil shows on minor sandstones were recorded in the interval 2947 to 2958 m; weak to good oil shows were seen on limestone in the interval 3300 m to 3500 m; and finally weak oil shows were seen occasionally from 3645 m to 3675 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The chalk section was cored in 11 cores from 3048 m to 3235.5 m (Ekofisk and Tor formations) and one core (core no 12) from 3327.2 m to 3336.7 m (Hod Formation). Total core recovery was nearly 100%. No wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was suspended on 17 February 1977 as a gas/condensate discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing </span></b></p> <p class=MsoBodyText><span lang=EN-GB>Eight drill stem tests were performed in the Late Cretaceous and Danian chalk sections. The tests indicated an oil reservoir with a retrograde gas cap. However PVT analyses indicated that the hydrocarbon system was close to its critical point and therefore difficult to interpret.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1B tested the intervals 3298 - 3302 and 3306 - 3312 m (Tor Formation). After acidizing the test produced water with less than 1% oil emulsion at a rate of 48 - 51 m3 /day on a 48/64" choke. Maximum recorded temperature was 120 deg C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2A tested the interval 3210 - 3220 m (Tor Formation). The test produced water at a rate of 53 m3 /day on a 48/64" choke. Maximum recorded temperature was 116 deg C. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 3 tested the interval 3174 - 3182 m (Tor Formation). The test produced water at a rate of 13 m3 /day on a 48/64" choke. Maximum recorded temperature was 117 deg C. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 4 tested the interval 3148 - 3157 m (Tor Formation). After acidizing the test produced 253 - 420 Sm3 oil, 152910 Sm3 gas and 108 - 180 m3 water /day on a 24/64" choke. The GOR was 365 - 606 Sm3/Sm3, oil density was 0.849 g/cm3 and gas gravity was 0.699 (air = 1). Maximum recorded temperature was 120 deg C. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 5 tested the interval 3120 - 3133 m (Tor Formation). After acidizing the test produced 405 - 461 Sm3 oil, 242000 -251000 Sm3 gas /day on a 24/64" choke. The GOR was 534 - 618 Sm3/Sm3, oil density was 0.818 g/cm3 and gas gravity was 0.680 (air = 1). Maximum recorded temperature was 120 deg C. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 5A tested the interval 3129 - 3133 m (Tor Formation). The test produced 71 - 98 Sm3 oil with 1% water, 34000 - 45000 Sm3 gas /day on a 12/64" choke. The GOR was 409 - 640 Sm3/Sm3, oil density was 0.836 g/cm3 and gas gravity was 0.710 (air = 1). Maximum recorded temperature was 121 deg C. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 6 tested the interval 3105 -3108.5 m (Tor Formation). The test produced 111 - 127 Sm3 oil with 1% water, 125000 - 130000 Sm3 gas /day on a 22/64" choke. The GOR was 989 - 1201 Sm3/Sm3, oil density was 0.796 g/cm3 and gas gravity was 0.708 (air = 1). Maximum recorded temperature was 118 deg C. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 7 tested the interval 3082 - 3088 m (Ekofisk Formation). The test gave no flow.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 8 tested the interval 3055 - 3068 m (Ekofisk Formation). The test produced 79 - 90 Sm3 oil with 0.5% water, 198000 - 218000 Sm3 gas /day on a 12/64" choke. The GOR was 2330 - 2740 Sm3/Sm3, oil density was 0.760 g/cm3 and gas gravity was 0.691 (air = 1). Maximum recorded temperature was 116 deg C. Attempts to test this interval with acid (DST 8A and 8B) failed as a consequence of the problems with the anchor chains.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
243
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7/6/2016 12:00:00 AM
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04.11.2024
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1/9-1 R
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/9-1 R is a re-entry of well 1/9-1 on a salt diapir structure located in the Feda Graben in the southern North Sea. The purpose of the re-entry was permanent abandonment.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The suspended well 1/9-1 was re-entered (1/9-1 R) with the semi-submersible installation Ross Isle on 8 May 1987. </span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged and permanently abandoned on 17 May 1987.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
1444
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7/6/2016 12:00:00 AM
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04.11.2024
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1/9-2
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/9-2 was drilled on a salt diapir structure located in the Feda Graben in the southern North Sea. It was drilled to confirm and further evaluate the proven hydrocarbons found on this seismic structure by the 1/9-1 well.<b> </b></span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 1/9-2 was spudded with the semi-submersible installation Ross Rig on 1 June 1977 and drilled to TD at 3459 m in the Late Cretaceous Hod Formation. No significant problems were encountered in the operations. The well was drilled with spud mud down to 439 m and water based with lime/Drispac/lignosulphonate mud systems from 438 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Good oil show was observed in a thin sandstone stringer at 1632 m in the Hordaland Group. Oil in cuttings was recorded also at 1710 m and 2858 m in claystones. The Ekofisk Formation was encountered at 3120 m with shows and tested small amounts of oil. The Tor Formation came in at 3195 m with shows and tested small amounts of oil. Below 3213.5 m only rare and weak fluorescence was observed on limestone.</span></p> <p class=MsoBodyText><span lang=EN-GB>The interval 3135-3215 in the Ekofisk and Tor formations was cored with nearly 100% recovery. RFT pressure readings were attempted in the Tor and Ekofisk formations, but all were unsuccessful due to tight formation. No fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12 August 1977. The poor results from DST are classified as shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two drill stem tests were carried out. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1 tested the Maastrichtian Tor Formation (3197 - 3209 m) and flowed approximately 6 - 10 m3/day of acidwater after stimulation, slugging badly. 2-10% of oil was measured in samples. The oil gravity was 34.0 deg API.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2 & 2A tested the Danian Ekofisk Formation (3130 - 3154 m). The flow stabilized at approximately 13 - 15 m3/day of acidwater after the retest effort. Clean samples of formation fluids were not obtained, but this interval produced long enough to approach clean-up. 2-17% of oil was measured on samples taken during flow and reversing sequences with the smaller value probably being more representative. Oil gravity was 35.2 - 35.7 deg API.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
244
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7/6/2016 12:00:00 AM
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04.11.2024
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1/9-3
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<p><b>General</b></p> <p>Well 1/9-3 is located in the Feda Graben, close to the UK border southwest in the Norwegian North Sea. The primary objective of the well was to evaluate the Jurassic sandstones. The secondary objective was to appraise and test the hydrocarbon bearing zones of Danian and Maastrichtian age (Shetland Group) encountered in 1/9-1. The well was drilled in two phases, of which Phase I is well bore 1/9-3 and Phase II is well bore 1/9-3 R. This procedure was a requirement from the Norwegian Petroleum Directorate since Dyvi Gamma came directly from the yard and had therefore not accumulated the experience needed to drill the high pressure Jurassic well to a planned TD of 5000 m. Phase II was to be drilled with the rig Dyvi Beta.</p> <p><b>Operations and results</b></p> <p>Wildcat well was spudded with the semi-submersible installation Dyvi Gamma on 13 August 1977 and drilled to TD at 27871 m in the Hordaland Group. The progress of the drilling was very much delayed due to technical problems on Dyvi Gamma. As a result, also hole problems were increased due to very long exposure in open hole condition. Due to these problems the well bore was terminated after setting the 13 3/8" casing instead of the plan, which was to drill down to the 9 5/8" casing point. The well was drilled with seawater and gel all through. </p> <p>Several thin sand beds were penetrated in the Hordaland Group between 1610 m and 1737 m. Oil shows were recorded in the uppermost of these, from 1610 m to 1625 m.</p> <p>No cores were cut and no wire line fluid samples taken in the well bore.</p> <p>The well was suspended as dry on 27 November 1977. </p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
245
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7/6/2016 12:00:00 AM
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04.11.2024
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1/9-3 R
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<p><b>General</b></p> <p>Well 1/9-3 is located in the Feda Graben, close to the UK border southwest in the Norwegian North Sea. The primary objective of the well was to evaluate the Jurassic sandstones. The secondary objective was to appraise and test the hydrocarbon bearing zones of Danian and Maastrichtian age (Shetland Group) encountered in 1/9-1. The well was drilled in two phases, of which Phase I is named 1/9-3 and Phase II is named 1/9-3 R. This procedure was a requirement from the Norwegian Petroleum Directorate since Dyvi Gamma came directly from the yard and had therefore not accumulated the experience needed to drill the high pressure Jurassic well to a planned TD of 5000 m. The re-entry 1/9-3 R was to be drilled with the rig Dyvi Beta.</p> <p><b>Operations and results</b></p> <p>Well 1/9-3 was re-entered (1/9-3 R) with the semi-submersible installation Dyvi Beta on 27 May 1978 and drilled to TD at 4570 m in the Late Jurassic Haugesund Formation. When running the 9 5/8" casing problems occurred with stuck pipe. This resulted in severe delays, but the casing was landed at planned depth. In the 8 1/2" hole the progress was delayed due to hole problems with high pressure and mud weight combined with lost returns. Tight hole and stuck pipe occurred on several occasions. Max mud weight was 2.04 g/cm. The well was drilled water based, but with several additions of diesel from 9 5/8" casing depth and downwards, resulting in 1 - 12 % diesel in the mud at all times below 3835 m.</p> <p>Several problems arose during the logging operations, which in the end resulted in a poor suit of logs over the reservoir.</p> <p>In summary the problems were due to uncontrolled stretch in the logging cable, generally poor log quality, especially for FDC/CNL logs, and difficult hole conditions with high pressure/temperature and excessive sticking. Logs that normally are run in combination had to be run separately. This made petrophysical evaluation difficult, and several logs had to be disregarded due to the poor quality.</p> <p>The well penetrated a typical stratigraphy for the area with a 2754 m thick Tertiary sequence down to top Rogaland Group (the 1/9-3 well bore), a 215 m thick Rogaland Group, a 709 m thick Shetland Group, and a 475 m thick Early Cretaceous Cromer Knoll Group. The well was terminated 305 m into the Late Jurassic Tyne Group. The Tyne Group contained a sand/shale sequence (Eldfisk Formation), but the sand beds were water bearing without shows. </p> <p>Live hydrocarbons were encountered and proved by testing in the Ekofisk and Tor Formations, but only the Ekofisk Formation had good reservoir properties. Petrophysical evaluation showed 36 m net pay in the upper part of the Ekofisk Formation and only 1.75 m net pay in the Tor Formation.</p> <p>A total of 100 m core was recovered in eight conventional cores in the interval from 3053 m in the Early Paleocene Maureen Formation to 3234 m in the Late Cretaceous Tor Formation. No fluid samples were taken on wire line.</p> <p>The well was permanently abandoned on 30 September 1978 as a gas/condensate appraisal.</p> <p><b>Testing</b></p> <p>Four drill stem tests were conducted in the Shetland Group chalks. DST 1 from 3205 m to 3214 m in the Tor Formation produced only water. Maximum temperature recorded at the end of the 12 hours main flow was 124.8 deg C. DST 2 from 3157 m to 3180 m in the Tor Formation produced 7175 m3 water together with 7.9 Sm3 oil and 4800 Sm3 gas per day through a 9.5 mm choke. Maximum temperature recorded at the end of the 10 hours main flow was 122.6 deg C. DST 3 from 3126 m to 3135 m in the Ekofisk Formation produced only 3 m3/day water with traces of oil and gas. DST 4 from 3094 m to 3112 m in the Ekofisk Formation was a good producer with a maximum flow of 397 Sm3 oil and 648400 Sm3 gas per day on a 19 mm choke. The gravity of the oil was 50 deg API. The maximum temperature recorded in this test was 120.1 deg C.</p> |
246
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7/6/2016 12:00:00 AM
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04.11.2024
|
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1/9-4
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<p><b>General</b></p> <p>Well 1/9-4 was drilled on a salt diapir structure in the Central Graben in the neighbourhood of the Norwegian - UK median line. The primary purpose was to test the Ekofisk and Tor formations of Danian and Maastrichtian age. Lower possible porous zones in chalk and Jurassic sands, if present, were secondary objectives.</p> <p><b>Operations and results</b></p> <p>Wildcat well 1/9-4 was spudded with the semi-submersible installation Ross Rig on 13 August 1977 and drilled to TD at 3710 m in Late Permian Zechstein salt. There were no serious drilling problems down to a depth of 3100 m. At 3100 m the bit-junksub assembly was lost in the hole. The hole was cemented back and sidetracked after the fishing attempts proved unsuccessful. After one unsuccessful sidetrack attempt the hole was sidetracked again from 3041 m and drilled on to core point at 3122 m. When cutting core no 10 the bottom hole assembly got stuck and a long section of the BHA had to be left in the hole. After some unsuccessful attempts on jarring, the hole was cemented and sidetracked again, from 3059 m in the first sidetrack hole. This second sidetracked hole was drilled to a measured depth of 3353 m. At this point 7" liner was run. 6" hole was drilled to a total measured depth of 3710 m with only minor problems and top of the salt was found at 3650 m. The 6" hole was logged and plugged back. It was found necessary to perform a squeeze job around the 7" liner shoe, but when attempting to pull out after this operation, the BHA stuck just above the cementing stinger. Jarring did not free the pipe, and a cement plug was set above the fish. The well was drilled with high viscosity spud mud of pre-hydrated bentonite, lime, and caustic soda down to 437 m and with Drispac/lime mud from 437 m to 2580 m. From 2580 m the lime was phased out and the remaining well to TD was drilled with a lignite/lignosulphonate gel mud. During abandonment an anchor chain broke in severe weather. The well was plugged back while a supply boat pulled on the anchor chain. A cap was installed on the well head and the well was suspended. </p> <p>No significant reservoir rock was penetrated above Danian level. The Early Cretaceous Valhall Formation was found resting directly on the salt. No Jurassic sediments were penetrated by the well. Hydrocarbons were encountered and tested in the Ekofisk and Tor Formations from 3114 m down to top Hod Formation at 3312 m. Above the reservoir shows in the form of cut and fluorescence was recorded on occasional shale/limestone/silty cuttings was seen from 1990 to 2733 m. More continuous shows were seen on limestone/shale cuttings in the interval 2808 to 2991 m in the Lower Hordaland Group, through the Balder Formation and into the Sele Formation. </p> <p>Nine cores were cut from - 3123 m to - 3273 m with close to 100% recovery. No RFT surveys were run and no wire line fluid samples were taken.</p> <p>The well was suspended on12 January 1978 as a dry well.</p> <p><b>Testing</b></p> <p>Four drill stem tests to evaluate productivity and fluid composition were carried out. Hydrocarbons were produced during all the tests. Weather conditions and operational problems interfered with the designed test program.</p> <p>DST 1 tested the Tor Formation in from interval 3292 to 3296 m. The second flow produced 30582 Sm3 of gas and in the range of 16 Sm3 oil /day. There was no water production. The oil produced had a gravity of 46 deg API and the gas gravity (air = 1) was 0.68. GOR varied in the range 890 to 14000 Sm3/Sm3. Maximum recorded down hole temperature was 136 deg C but the temperature readings were not stable.</p> <p>DST 2 tested the Tor Formation from the interval 3235 to 3255 m. After acid stimulation the well flowed 673940 Sm3 of gas and 592 Sm3 oil /day on a 48/64" choke. The oil gravity was 48-49 deg API at separator conditions and the gas gravity (air = 1) was 0.67 with 2 - 3 % CO2. The GOR was in the range 890 to 1160 Sm3/Sm3. No representative temperature reading is available from this test.</p> <p>DST 3 tested the Ekofisk Formation from the interval 3176 to 3198 m. After acid stimulation the well flowed 32000 Sm3 of gas and 17 Sm3 oil /day with a bottom hole flowing pressure 750 psig at depth 3154 m. This test also produced some emulsion and water. The gas and oil gravities were 0.81 (air = 1) and 45 deg API at separator conditions, respectively. 3% CO2 was measured in the gas. The GOR varied in the range 1070 to 2140 Sm3/Sm3. Due probably to gas expansion and cooling in the borehole it is assumed that the maximum recorded temperature of 122.2 deg C was not representative for the formation.</p> <p>DST 4 tested the Ekofisk Formation in the intervals 3127 to 3137 and 3120 to 3123 m. After acid treatment the well flowed 498380 Sm3 of gas and 223 Sm3 oil /day on a 48/64" choke. The gas and oil gravities were 0.688 (air = 1) and 50 - 51 deg API at separator conditions, respectively. 2-3% CO2 was measured in the gas. The GOR varied in the range 960 - 2850 Sm3/Sm3. The maximum temperature recorded, and the one assumed to be the most representative for the Formation in all four tests, was 134.2 deg C. </p> |
247
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7/6/2016 12:00:00 AM
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04.11.2024
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1/9-4 R
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/9-4 R is a re-entry of well 1/9-4 in the Central Graben of the North Sea. The purpose of the re-entry was permanent abandonment. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well was entered with the semi-submersible installation Ross Rig on 21 April 1991. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well head was removed from the sea floor.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 26 April.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
1727
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7/6/2016 12:00:00 AM
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04.11.2024
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1/9-5
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/9-5 was drilled in the Feda Graben in the southern North Sea, in the saddle between the Tommeliten Gamma-structure and the intrusive salt plug forming the Tommeliten Delta structure. The purpose of the well was to appraise the Tommeliten Gamma discovery made by 1/9-4 and to test the hydrocarbon potential and reservoir quality of the Ekofisk and Tor formations.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 1/9-5 was spudded with the jack-up installation Dyvi Beta on 3 October 1978 and drilled to TD at 3450 m in the Late Cretaceous Hod Formation. The pipe got stuck at 3426 m during a clean-up trip. When trying to come loose the hook broke and the drill string dropped in the hole. This event caused material damage and rig shut-down for three days, but nobody was injured. When fishing the drill string it came loose above the jar but the rest of the BHA (approximately 260 m) was left in the hole. The well was drilled with spud mud down to 435 m, with a lime/"Morex" mud system from 435 m to 1377 m, with lime/"Morex"/Drispac mud from 1377 m to 2725 m, and with lignosulphonate/lignite mud from 2725 m to TD. A lot of hole problems occurred in the 17 1/2" and 12 1/4" sections and this was attributed to the lime/"Morex" mud system. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Ekofisk Formation came in at 3207 m and the Tor Formation at 3282 m. No significant hydrocarbon shows were encountered in any section of the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>One core was cut from 3215.5 to 3 233.5 m, proving a dry carbonate section. No wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 16 December 1978 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
248
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7/6/2016 12:00:00 AM
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04.11.2024
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1/9-6 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/9-6 S was drilled on the north-west flank of the Tommeliten Gamma structure in the Feda Graben in the southern North Sea. The main objective was to appraise the Tommeliten Field. The well was drilled deviated due to the planned use of this well as a production well. The main targets were the Ekofisk and Tor formations. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 1/9-6 was spudded with the semi-submersible installation Sedco 703 on 21 March 1982. Drilling of the 36" and 26" holes went without incident. There was some difficulty in getting logging tools in the 17 1/2" hole. Gumbo problems occurred while drilling the 12 1/4" hole and both open hole and cased hole logging runs were plagued with tool failures. Differential sticking also occurred while drilling the bottom part of the 8 1/2" hole. TD was set 3880 m, 99 m into the Late Cretaceous Hod Formation. After retrieving the RFT the well began flowing and sloughing large amounts of shale below the 9 5/8" shoe. While circulating and reaming to TD, the pipe became stuck many times due to shale sloughing above the bit. A bit and bit sub were left in the hole during these hole problems, and were never recovered. The well was drilled with "native" mud/seawater down to 1471 m and with polymer/dispersed solids/lignosulphonate/seawater from 1471 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top Ekofisk Formation was penetrated at 3411 m (3110 m TVD) and top Tor Formation at 3516 m (3199 m TVD). Both formations were gas/condensate bearing. No other permeable section in the well had indications of hydrocarbons.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 14 cores were cut in the interval 3415.7 - 3619 m in the Ekofisk and Tor formations. Problems with jamming and differential sticking occurred while coring. The overall recovery was 90%. One run with the RFT tool on wire line was conducted, taking 14 good pressure points, but no fluid sample due to tight formation and stuck tool. </span></p> <p class=MsoBodyText><span lang=EN-GB>After testing the well was suspended on 1 December as a possible future producer. It is classified as a gas/condensate appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Four DST's were performed in this well. Technical and operational problems plagued all tests. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST1 tested the interval 3771.6 - 3776.8 m (3424.0 - 3428.6 m TVD) in the water zone at base Tor Formation. A few m3 water was produced in each of several flow periods. The temperature recorded in DST 1, at measurement depth 3750.4 m varied between 130.7 deg C and 133.0 deg C for different periods and gauges, with 131.7 deg C taken as a representative temperature. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2, 2A, and 2B tested the interval 3636.3 - 3654.6 m (3301.0 - 3316.7 m TVD) in the lower Tor Formation. The first test, DST 2, was aborted due to technical problems. Maximum rate achieved from DST 2A was 536604 Sm3 /day of gas and 477 Sm3 /day of condensate on 32/64" choke. GOR was 1125 Sm3/Sm3, oil density was 0.810, and gas gravity was 0.689 (air = 1). H2S was measured to be 4-6 ppm and the CO2 content was measured to be 3%. This test was aborted when the tester valve cut the wire line, and the zone was retested as DST 2B. The maximum flow rates were then close to 700 x 10 Sm3 /day of gas and 500 - 550 Sm3 /day of condensate on a 28/64". The maximum temperature in different flows from this interval, measured at 3652 m, varied between 121.8 and 122.4 deg C</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 3 tested the intervals 3587.5 - 3578.4 m, 3569.2 - 3560.1 m and 3550.9 - 3523.5 m in the Tor Formation. It flowed 243808 Sm3 gas and 231 Sm3 condensate/day on a 16/64" choke after acidizing. GOR was 1054 Sm3/Sm3, condensate density was 0.823 g/cm3 and gas gravity was 0.680 (air = 1). Final build-up period was terminated mid-way due to technical problems. Same interval was tested in DST3A without further acidizing. This test produced 241259 Sm3 gas and 202 Sm3 condensate/day on a 20/64" choke. The GOR was 1196 Sm3/Sm3, the oil density was 0.791 g/cm3 and gas gravity was 0.684 (air = 1). The temperature measured at 3522.6 m was 131.1 deg C</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 4 was perforated in two intervals, the upper zone from 3416.8 - 3426.0 m (3114.8 - 3122.7 m TVD) and the second from 3444.2 - 3459.4 m (3138.2 - 3151.3 m TVD), both in the Ekofisk formation. It produced gas and condensate after stimulation. The maximum rates from these intervals were 834213 Sm3 gas and approximately 559 Sm3 condensate/day of condensate on a 56/64" choke. The GOR was 1491 Sm3/Sm3 on this choke. A GOR of 2800 Sm3/Sm3 was measured before acidization, with a low flowing pressure. </span></p> |
44
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5/19/2016 12:00:00 AM
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04.11.2024
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1/9-6 SR
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/9-6 SR is a re-entry of well 1/9-6 S on the north-west flank of the Tommeliten Gamma structure in the Feda Graben in the southern North Sea. Well 1/9-6 S was suspended in December 1984 as a possible producer for the Tommeliten Gamma. The objective of the re-entry was plugging.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 1/9-6 S was re-entered with the semi-submersible installation Ross Rig on 6 April 1991. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged and permanently abandoned on 20 April 1991.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
1558
|
7/6/2016 12:00:00 AM
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04.11.2024
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1/9-7
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 1/9-7 was drilled on the Tommeliten Alpha structure on the south-western side of the Feda Graben of the North Sea, ca 1.5 km from the UK border. The main objective of well 1/9-7 was to explore the hydrocarbon potential of the Tommeliten Alpha prospect in the Jurassic level. Secondary objective was to appraise the Tommeliten Alpha Chalk discovery made by well 1/9-1 in 1976.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/9-7 was spudded with the jack-up installation Mærsk Giant on 22 March 2003. The well was drilled to the TD of the 17 1/2" section at 3040 m by 21 April. Problems with losses at the 20" shoe at 1039 m were remediated by spotting cement at the shoe. The well was inadvertently sidetracked as 1/9-7 T2 while drilling out the cement on 27 April. Unable to re-enter the original borehole after drilling to 1215 m, the 1/9- 7 T2 sidetrack was cemented back to the 20" shoe. The well was then deliberately and successfully sidetracked from 1039 m as 1/9-7 T3 on 4 May 2003. The 17 1/2" hole was re-drilled to a TD of 3058 m and 14" casing set. From there the well was drilled without further significant problems to TD at 4986 m (4965 m TVD) in the Triassic Smith Bank Formation. The well was drilled with seawater/bentonite/CMC down to 1047 m, with Versavert OBM in from 1047 to 3058 m (Versavert was used also in the primary well track and the failed sidetrack), and with Versatherm HTHP mud, a mineral oil based mud, from 3058 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Chalk of the Ekofisk Formation was encountered at 3093 m and top Tor Formation was encountered at 3159 m. Reservoir quality sands were not encountered at any level below the Base Cretaceous Unconformity, although an interval containing very fine sand and silt equivalent to the Oxfordian J50 Sand Unit in the UK well 30/19a-5, 8 km to the WNW, was encountered. The only significant hydrocarbons encountered were in the Ekofisk and Tor Formations in the upper portion of the Chalk Group where oil shows were observed. MDT sampling in Ekofisk proved a gas/condensate. Logs indicated hydrocarbon saturation down to ca 3195 m but no definite hydrocarbon contact was found.</span></p> <p class=MsoBodyText><span lang=EN-GB>Petrophysical analyses indicated some hydrocarbon saturation in a thin Miocene Sand Unit at 1675 m (1/9-7 depth) and a thin Andrew Formation sand in the Paleocene from 2989 m to 2992.5 m (1/9-7 T3 depth). None of these had oil shows. Shales in the Mandal Formation at 4315 - 4350 m had definite shows (hydrocarbon odour). However, the oil-based drilling fluids made shows identification difficult below 1047 m. </span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut with 100% recovery from 3104 to 3153 m in the Ekofisk Formation. During MDT operations across the Chalk Group, 5 down hole samples were retrieved from 3112 m in the Ekofisk Formation with an MDT dual-packer tool. Upon examination at surface, it was concluded that the samples contained what appeared to be single-phase retrograde gas condensate. From PVT studies it was concluded that the samples are 12-16 wt% contaminated with base-oil drilling mud, geochemical analyses by GC show that apart from the contamination in the range C12 - C20 the 1/9-7 MDT oil is very similar to the oil sampled from 1/9-1 side of the Tommeliten Alpha discovery.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 2 August 2003. The well is classified as dry in the main Jurassic exploration target and is also a positive appraisal of the 1/9-1 Tommeliten Alpha Ekofisk/Tor Formation discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
4652
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2/21/2020 12:00:00 AM
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04.11.2024
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10/4-1
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 10/4.-1 was drilled to test the Zeppelin prospect ca 35 km southeast of the Yme Field in the North Sea. The primary objective was to evaluate the presence of hydrocarbons in sandstones of the Jurassic Sandnes and Bryne formations. Secondary target were the Zechstein Group limestones of Late Permian age.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 10/4-1 was spudded with the semi-submersible installation Borgland Dolphin on 20 June 2015 and drilled to TD at 2415 m in the Permian Zechstein Group. No significant problem was encountered in the operations. The well was drilled with seawater and hi-vis pills down to 640 m and with Innovert oil based mud from 640 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Top Sandnes Formation was encountered at 2274 m and top Bryne Formation at 2311 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Both formation had sandstones with very good reservoir quality. The Sandnes reservoir has an average porosity of 21.5 %, and the Bryne Formation 17.4 %, using a cut off value of 10%. The gross thickness for the Sandnes Formation is 21 m with a net thickness of 19.15 m. The well encountered the Bryne reservoir with a gross thickness of 53 m and net thickness of 38.75 m. The water saturation is 100 % in both encountered reservoirs. The expected Permian age limestone reservoir was not present at this well location. All reservoirs were water-wet. The well also encountered sandstone of undifferentiated Triassic age with good quality. The sandstone of 16 m gross and 15.95 m net thickness had an average porosity of 23.7 %. It is water-wet. No shows were observed in the well</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12 July 2015 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7724
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5/23/2017 12:00:00 AM
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04.11.2024
|
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10/5-1
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<p><b>General</b></p> <p>Well 10/5-1 was designed to test a tilted fault block with an overlying pinch out trap in the eastern part of the Norwegian-Danish basin. The primary objective was Rotliegendes sands. A probable 460 m gross thickness was anticipated. A secondary objective was Middle Jurassic sandstones with an estimated gross thickness of 61 metres. Other possible objectives were the Early Cretaceous sandstones and Basal Zechstein carbonates.</p> <p>The well is Illustration Well for the Børglum Unit of the BoknFjord Group.</p> <p><b>Operations and results</b></p> <p>Exploration well 10/5-1 was spudded with the semi-submersible installation Norjarl on 31 May 1976 and drilled to TD at 1843 m in crystalline granite dated by the potassium-argon method to apparently 689 ± 21 My (Late Precambrian). After drilling the 36" section to 189 m the hole had washed out under the temporary guide base. The guide base sank 26 feet below the mud line and the 30" casing could not be stabbed through the guide base. The rig was moved 38 m and the hole was respudded. The well was drilled with seawater / gel down to 501 m, with Inpac polymer mud from 501 m to 1768.2 m, and with lignosulphonate mud from 1768.2 m to TD. </p> <p>The well penetrated a gross thickness of 67 metres of Middle Jurassic (Sandnes Formation) sandstones from 1472 m to 1539 m. Porosity was good, but there were no hydrocarbon indications while drilling, and subsequent log analysis confirmed that the objective horizons were water wet. Triassic sandstones were also encountered, but these were extremely shaley, and had no clean sandstone sections. Rotliegendes sandstones were not present at the 10/5-1 location. The base of the Zechstein interval was represented by a clear, white, light brown, hard, very angular sandstone, cemented with siliceous cement and extremely tight. Organic geochemical analyses found fair to rich TOC (1 - 5%) in the Early Cretaceous and Late Jurassic and possibly in some Permian shales. The Permian TOC could be caved Late Jurassic material. Rock-Eval pyrolysis of the high-TOC samples gave low S2 yields, so the kerogen has low hydrocarbon potential and is most likely gas prone. The entire well was found to be immature. Minor amounts of migrant hydrocarbons were detected by the geochemical analyses in the late Jurassic and the Cretaceous.</p> <p>A junk basket core was recovered from 533.4 m to 534.3 m. No conventional core was cut. Thirty sidewall cores were attempted over the interval 1250 m to 1812 m. Eighteen of these were recovered. No fluid samples were taken.</p> <p>The well was permanently abandoned on 26 June 1976 as a dry hole. </p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
306
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7/6/2016 12:00:00 AM
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04.11.2024
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|
10/7-1
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<p><b>General</b></p> <p>Well 10/7-1 is located at the southeastern end of the Egersund Basin in the North Sea. The objective of the well was to test the Tott prospect, a faulted anticline over a salt wall. The Middle Jurassic Bryne formation was the primary objective. A thin Sandnes formation sandstone overlying the Bryne was interpreted to be possible at the drilled location.</p> <p><b>Operations and results</b></p> <p>Wildcat well 10/7-1 was spudded with the semi-submersible installation Sonat Arcade Frontier on 28 June 1992 and drilled to TD at 1890 m in the Late Permian Zechstein Group. The well was drilled with seawater and gel down to 793 m and with KCl/polymer mud from 793 m to TD. </p> <p>Good reservoir quality sandstones were encountered in both the Sandnes and Bryne formations of the Vestland group. The top of the Sandnes formation was penetrated at 1539 m; top of the Bryne at 1632 m. Total thickness of the Vestland group is 297 m. From drill cuttings, fair to good visible porosity was observed in fine to coarse-grained sandstones throughout the Vestland group. Reservoir quality is good, with a net sand/gross thickness ratio of 54.5% using a 12% porosity cut-off. Using the same cut-off value the average porosity of the reservoir sandstones in the Vestland group is 23.3%. Bathonian age sediments (Bryne Formation) rested directly on Late Permian Zechstein salt at 1836 m. Occasional, spotty shows were observed in cuttings from the Sandnes and Bryne Formations. These marginal shows were interpreted to be sourced from in-situ carbonaceous material and not as migrated hydrocarbons. Analysis of the wire line logs and wire line pressure data clearly indicated that the sandstones of the Vestland group were water bearing. Organic geochemical analyses showed Total Organic Carbon (TOC) from 1.0 to 3.19 % and Hydrogen Index (HI) from 79 to 224 mg HC/g TOC in the Late Jurassic shales, which was classified as a poor oil and gas source. Associated with coals in the Vestland group were gas prone sediments with TOC values ranging from 1.64 - 6.14% and HI values of 118 to 223. The well was found immature for oil and gas generation; maximum vitrinite reflectance, recorded near TD, was 0.45 %Ro. Extractable organic matter contained low to modest amounts of immature hydrocarbons associated with local shales and coals, consistent with the trace shows recorded during drilling.</p> <p>One conventional core was cut in the Sandnes formation, from 1561 to 1566.5 m, where the core jammed. The recovered core (3.95 m) consisted of sandstone with a thin claystone/shale bed at the base. Shows were not observed in the core. Core analysis indicated generally fair to good porosity and permeability. FMT pressures also indicated fair to good permeability throughout the Vestland group. No fluid sample was taken.</p> <p>The well was permanently abandoned on 30 July 1992 as a dry hole.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
1972
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7/6/2016 12:00:00 AM
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04.11.2024
|
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10/8-1
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<p><b>General</b></p> <p>The 10/8-1 well is situated close to the Lista Nose in the eastern part of the Norwegian-Danish Basin. It was drilled on a salt induced anticlinal structure related to a salt pillow. The structure is well defined from the Permian salt up to the upper cretaceous chalk. It has a vertical closure of 300 m for a closed area of 80 km2 at a seismic horizon assumed to be the Jurassic sandstone. A fault cuts the unconformably underlying horizons attributed to Triassic. The specific objective of the 10/8-1 well was to test the hydrocarbon potential of the Jurassic sandstone section, estimated to be 60 m thick, with additional reservoir being furnished by the Triassic sandstones immediately below. </p> <p>The well is Type Well for the Skagerrak Formation and Reference Well for the Smith Bank Formation</p> <p><b>Operations and results</b></p> <p>Wildcat well 10/8-1 was spudded with the semi-submersible installation Pentagone 81 and drilled to TD at 2861 m in the Late Permian Zechstein salt deposits. The well was completed in 37 days without reported problems. The well was drilled with seawater with returns on the sea floor down to 510 m, and with a LFC/sea water mud system from 510 m to TD. </p> <p>One thousand three hundred meter of continental deposits of Triassic age is present. On top of this is the Gassum Formation. The Early to Middle Jurassic was not encountered in the well. One hundred and fifty meter Late Jurassic sand and shale is directly overlying the Gassum Formation. Around 200 m of shale was deposited during the Early Cretaceous while the Late Cretaceous is represented by 425 m of lime mudstones. The lower 200 m of the Tertiary was developed in mostly sandy facies. All Formations penetrated by the well were found water wet. The only show recorded was traces of gas (C1 and C2) from 1010 m to 1050 m. Organic geochemical screening analyses show TOC in range 0.1 - 1.5 % with the highest values in the Late Jurassic and Cretaceous sequences. The Triassic sequence appears very lean with less than 1% TOC. The upper 500 m of the well were not sampled. No conventional cores were cut and no fluid samples were taken. </p> <p>The well was permanently abandoned on 17 January 1971 as a dry hole. </p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
175
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5/19/2016 12:00:00 AM
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04.11.2024
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11/10-1
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<p><b>General</b></p> <p>Wildcat well 11/10-1 was drilled in the eastern part of the Danish Norwegian Basin close to the borderline between the Norwegian and the Danish sectors. The well is situated close to the Kreps fault zone on the western flank of the Horns Graben. The main objectives of the 11/10-1 well were to test the hydrocarbon potential of the Tertiary and the Mesozoic formations. Well 11/10-1 is the first well in quadrant 11 and one of the few wells drilled in the southeastern part of the Norwegian continental shelf so long.</p> <p><b>Operations and results</b></p> <p>Wildcat well 11/10-1 was spudded with the semi-submersible rig "Ocean Viking" on 2 August 1969 and completed 19 August the same year. The well was drilled at 63 m water depth and bottomed at a total depth of 2430 m in a Triassic sand section without having encountered hydrocarbons in any of the targets.</p> <p>Three casing strings were set in the well. Sea water was used for the initial drilling down to 253 m. From this depth down to 1023 m a sea water gel mud was used and from 1023 down to TD a sea water Q-Broxin mud system was the drilling fluid. No significant drilling problems occurred during the drilling of this well.</p> <p>No samples are available from the sea floor down to 305 m. From 305 to 430 m the sampled sequence consists of medium to coarse grained, subangular to subrounded, glauconitic sand and sandstone with scattered rock fragments. The sand is generally unconsolidated and mostly clear quartz and is relatively well sorted. Carbonaceous material, plant remains and shell fragments occur throughout. Dolomitic limestone are also present, increasing towards the bottom of the unit where the dolomite forms the cement of the sand. The underlying shales are dated Late Oligocene, the age of the sandy section is questionable as the upper 300m of the well has not been sampled.</p> <p>No sandstones are developed in the Rogaland Group which is much reduced in this well. The Upper Cretaceous chalk formations penetrated below 1048 m are approximately 400 m thick. 200 m of marls and shales containing limestone stringers constitute the Cromer Knoll Group below 1493m. The Upper Jurassic section is 200 m thick and consists of mainly shale with only stringers of sandstone. The Lower and Middle Jurassic section is missing in this well. The interval from 1860 to 1900 is considered to belong to the Triassic Gassum formation. At the top of this sequence there is a bed of light grey lime mudstone. Most of the interval, however, consists of loose, clear quartz sand, coarse to very coarse and a fine grained white to light grey sandstone with calcareous cement. From 1900 to 2430 m (TD) interbedded reddish and brownish sandstones and shales of the Skagerrak Formation are present. Visual porosity is good throughout this unit. No shows were observed when drilling through almost 600 m of Triassic section.</p> <p>Neither fluid samples nor pressure point were taken in this well.</p> <p>No cores were taken in this well.</p> <p><b>Test</b><b>ing</b></p> <p>No drill stem test was performed.</p> |
170
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5/19/2016 12:00:00 AM
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04.11.2024
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11/5-1
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 11/5-1 was drilled to test the Loshavn prospect, a 3-way dip closure situated on the southern flank of the Farsund Basin. The primary objectives were to test the hydrocarbon potential in shallow marine sandstones of the Late to Middle Jurassic Sandnes and Bryne Formations. Secondary objectives were to test the source rock potential of the Late Jurassic Tau Formation; and to test the reservoir and hydrocarbon potential of the Permian Rotliegendes sandstones. The TD criterion was to drill 600 m below Top Rotliegendes.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 11/5-1 was spudded with the semi-submersible installation Polar Pioneer on 7 August 2007 and drilled to TD at 1950 m into Silurian basement. The well was spudded twice, with the second spud ca 30 m north-west of the original spud position. The well was drilled without much technical problems, but a significant deviation from vertical started below 1375 m. The deviation persisted down to TD, with maximum deviation of 17.3 deg at 1837 m, resulting in a TVD at TD that was 15 m short compared to measured TD. The well was drilled with sea water down to 415 m and with Formate polymer mud from 415 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Late Jurassic Sandnes formation was drilled from 1276 m to 1322m. No Middle Jurassic (Bryne Formation) was present at the well location and the Permian Rotliegendes Sands were drilled from 1321 m to 1920 m. From 1920 m to TD biostratigraphic analyses indicate rocks of Silurian age. The Sandnes Formation was found to be an overall heterolithic transgressive unit of 45 m at the well location. It consisted of a lower shaly part with lower porosity, and an upper more sandy and porous. The upper part was slightly thicker than the lower. The Rotliegendes Group is a more than 500 m thick unit, very heterolithic, mainly composed of interbedded claystones, sandstones, conglomerates and siltstones with traces of limestones. Porosities were very low and wire line pressure tests proved them to be tight. An additional sandstone interval was drilled at the base of Cromer Knoll Group, from 1073 m to 1088 m, the ?Sauda Sandstone Unit?. All reservoir sections were water bearing. No shows were recorded in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12 September 2007 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
5596
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4/11/2017 12:00:00 AM
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04.11.2024
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11/9-1
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<p><b>General</b></p> <p>Well 11/9-1 is located in the Horn Graben far to the east in the North Sea towards the Skagerrak Sea, ca 15 km from the Danish border. It was located near the top of a saliferous structure in order to explore the whole Triassic series in the most favourable structural position. The structure is potentially large, but since all horizons above the Jurassic level were expected to crop out on the seabed the objective horizon was Lower Middle Triassic carbonaceous shales. These shales were seen both as source rock and seal for hydrocarbons in underlying sandstones (basal Triassic Brockelschiefer). No other objectives were defined for this well. </p> <p><b>Operations and results</b></p> <p>Wildcat well 11/9-1 was spudded with the semi-submersible installation Deepsea Driller on 16 January 1976 and drilled to TD at 1972 m, 42 m into Late Permian Zechstein salt. The well was drilled water based with spud mud down to 660 m and with ferrochrom lignosulphonate mud (FCL) from 660 m to TD. </p> <p>Drilling was without returns to 145 m. From there red sandstones and variegated shales made up a very thick Triassic interval (1785 m). The Triassic contained reservoirs as usual but no obvious sealing intervals were seen. Moreover, no potential source rocks were encountered. No shows of gas or oil were recorded during drilling and the different reservoirs were water bearing from the logs. No conventional core was cut and no fluid sample taken. Forty sidewall cores were retrieved in two runs in the interval 737 m to 1962 m. </p> <p>The well was permanently abandoned on 28 February 1976 as a dry hole.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
307
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7/6/2016 12:00:00 AM
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04.11.2024
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15/12-1
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<p><b>General</b></p>
<p>Well 15/12-1 was drilled in order to evaluate the Paleocene and Jurassic formations on a closed structure 5 km northeast of the Maureen Field which is located just across the UK-Norwegian median line in UK territory. The principle objectives of the 15/12-1 test were the Paleocene and Dogger (Hugin Formation) sandstones where oil accumulations had been proven in the Maureen field 5 km to the southwest on British sector.</p> <p>The well is Reference Well for the Sleipner Formation.</p> <p><b>Operations and results</b></p> <p>Wildcat well 15/12-1 was spudded with the semi-submersible installation Ross Rig on 7 July 1975 and drilled to a total depth of 3269 m in Triassic fine-grained sandstone with green and red-brown shale of the Skagerrak Formation. The well was drilled with a lignosulphonate type of mud.</p> <p>The Paleocene sandstone at 2633 m to 2643 m in 15/12-1 was encountered 6 m lower than in the Maureen no. 2 well. The sandstone is medium to coarse grained with good porosity (26%), but water wet. The Hugin sandstone was encountered some 50 m higher than in the Maureen no. 2 well. Oil shows were encountered on the cores from the Hugin Formation, but log analysis and FIT proved the sandstone to be water bearing. The logs also indicated shows of hydrocarbon in the Late Cretaceous limestone at 2925 - 2955 m, but log porosity was calculated from 0 to 6%, too tight to obtain a sample. The Late Triassic has good sand development that could be adequate for accumulation of hydrocarbons. During the drilling of the Triassic section, the background gas in mud and cuttings was near zero.</p> <p>Eight cores were cut in the well. Paleocene sands (Lista and Maureen Formations) were cored from 2612.1 m to 2651.1 m. One core was cut in the Heather Formation from 3067 m to 3073.3 m; one core was cut from the Hugin Formation into the Sleipner Formation from 3125.7 m to 3143.7 m. The Sleipner Formation was further cored in three cores down to 3183 m. On the basis of log analysis, two points for FIT tests were picked: one point at 3142.5 m (Ï = 23%, SW = 66%) and one point at 3126.5 m (Ï = 11.2%, SW = 31%). Test l at 3142.5 m produced 0.3 litres mud and 9.9 l water with a light skim of oil. The oil skim probably came from the FIT tools hydraulics. Based on the chloride content the water in the sample probably contained a large proportion of mud filtrate. The other sample was a failure due to tight formation. The well was permanently abandoned as a dry well with shows on 6 September 1975.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
94
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5/19/2016 12:00:00 AM
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04.11.2024
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15/12-10 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The well is positioned on the western flank of the northern segment of the Varg Field, on a horst mapped at Top Sleipner level. Thick Intra Heather sandstones present in the southern and eastern segments of Varg were expected also in the northern segment. Over the horst, Draupne/Heather shales were assumed eroded so that Intra Heather sandstones were present between BCU and Top Sleipner. These two horizons could be mapped seismically, but the extent of sandstones could not be mapped. The well was drilled to determine the extent and thickness of the Intra Heather sandstone reservoir over the northern segment of Varg and, if oil was encountered, to determine fluid characteristics and depth to the OWC. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/12-10 S was drilled from the S4 slot on the Varg subsea template using the semi-submersible installation Deepsea Bergen. It was spudded on 2 October 1996 and drilled deviated to TD at 3550 m in the Triassic Skagerrak Formation. The deviation started at 250 m, building angle to 35 deg at 960 m and was then kept between 28 deg and 38 deg down to TD. No significant problems were encountered in the operations. The well was drilled with seawater down to 207 m, with seawater/PAC/CMC from 207 m to 1396 m, and with Ancovert oil based mud from 1396 m to TD. No shallow gas was predicted and no shallow gas was found in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>Down to Top Shetland, the well was within prognosis, and penetrated the expected lithology. Below this level, the Shetland limestone was thicker than expected, and Top Cromer Knoll and Base Cretaceous was penetrated considerably deeper than prognosed (55 and 58 metres, respectively). Below BCU, the well encountered Late Jurassic shales and siltstones, and only 13 metres TVD of poor quality Intra Heather Sandstone was penetrated at 3372 - 3388 m (2924 - 2937 m TVD MSL) in the lower part of the Late Jurassic section. This was considerably less than prognosed, and the poor reservoir quality seen in the well also proved a rapid facies variation between 15/12-6 S and -10 S, probably controlled by faulting. The Intra Heather Sandstone was oil bearing, but had poor reservoir characteristics. MDT fluid samples from the top of the unit were contaminated with oil from the oil-based drilling mud, but analyses showed that the oil was of the same type as the oil found in well 15/12-6 S. The Intra Heather Sandstone section was deeper than the anticipated OWC for this part of the field (2920 m TVD MSL), and the base of the interval represented an ODT, indicating that sandstones in this area contain oil down to a deeper level than previously assumed. </span></p> <p class=MsoBodyText><span lang=EN-GB>Top Sleipner and Top Triassic were penetrated close to prognosis, and a core taken in the Triassic was in parts heavily tectonized. The borehole imager (UBI) indicated faulting at the top of the Intra Heather Sandstone, and in the Sleipner formation. </span></p> <p class=MsoBodyText><span lang=EN-GB>One conventional core was cut from 3427 - 3448 m in the Triassic Skagerrak Formation. An MDT sampling run collected fluid in two sample chambers at 3372.15 m (2947.04 m TVD RKB).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was re-classed to cuttings-injector 15/12-A-4 on 4. November 1996.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed</span></p> |
2285
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7/6/2016 12:00:00 AM
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04.11.2024
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15/12-11 S
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<p><b>General</b></p> <p>Exploration well 15/12-11 S was a joint operation of Production Licence 038 and 116. It was drilled in the northwestern area of block 15/12 and north of the Varg Field. Well 15/12-1 nearby to the northwest had shows in the Middle Jurassic Hugin Formation, but this was inconclusive with respect to moveable hydrocarbons. Block 15/12 is structurally located in the junction between the Jµren High to the southeast, the Ling Depression to the east, the Sleipner Terrace towards the north and the Witch Ground Graben to the west. The prospect was defined as a multi-target structure, situated on a rotated fault block. Primary targets were Tertiary sandstones of the Heimdal Formation in a genuine closure, in addition to sandstones of the Middle Jurassic Hugin Formation. Secondary high-risk targets were sandstones of Eocene, Late Jurassic and Triassic age. </p> <p><b>Operations and results</b></p> <p>Exploration well 15/12-11 S was spudded with the semi-submersible drilling installation "Deepsea Bergen" on 10 April 1997 and drilled to TD at 3597 m (3464 m TVD RKB) in sandstones of the Triassic Skagerrak Formation. The well was drilled with seawater and hi-vis pills down to 407 m and with KCl / polymer / Glycol (ANCO 208) mud from 407 m to TD. </p> <p>Sandstone was encountered in all of the possible prospective levels except in the Late Jurassic. The two primary targets however, were more silt/shale dominated than expected. The upper part of the Heimdal Formation, penetrated at 2680 m had a lower reservoir quality than expected. These distal parts of the formation were relatively shaly/silty. More massive and porous sand of the Heimdal Formation was penetrated deeper, but too deep with respect to a Maureen Field oil spill. The lower reservoir, the Hugin Formation was penetrated at 3395 m, and was slightly thicker than prognosed. The only indications of hydrocarbons observed during drilling of 15/12-11 S were weak shows in the Hegre and Vestland Groups and a very weak cut fluorescence on the core from the Heimdal Formation. The gas values stayed constantly low during drilling through the reservoirs. Some gas peaks were measured while drilling the Hugin Formation, but these were associated closely to coal layers. Both the Heimdal and Hugin Formations were proved water bearing through wire line logging.</p> <p>A total of two cores were cut. The first coring recovered only 0.5 m from the Heimdal Formation (2724 m to 2724.5 m). The second coring recovered 18.6 m from the Hugin Formation (3399.4 m to 3418.0 m). </p> <p>Pressure tests were carried out in the Middle Jurassic Hugin and Sleipner formations and in the Triassic Skagerrak Formation. No fluid sample was taken.</p> <p>The well was permanently abandoned as a dry well with weak shows on 19 May 1997. </p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
3074
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7/6/2016 12:00:00 AM
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04.11.2024
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15/12-12
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<p><b>General</b></p> <p>The objective for well 15/12-12 was to test the hydrocarbon potential of the Rev structure in PL 038 approximately 5 km south-east of the Varg Field (Varg A Platform). The target level was Oxfordian Intra Heather Sands of the Viking Group.</p> <p><b>Operations and results</b></p> <p>Well 15/12-12 was spudded with the semi-submersible installation Scarabeo 6 on 25 December 2000 and drilled to TD at 3085 m in the Triassic Skagerrak Formation. At ca 2700 m the well starts to build angle up to a deviation of ca 25 deg at ca 2830 m. This deviation is kept down to TD where it leads to a difference between measured and vertical depth of ca 30 m. The well was drilled with seawater and hi-vis pills through to the base of the 17 1/2" section at 1384 m and with Glydrill KCL Polymer from 1384 m to TD. </p> <p>A total of 121 m (2856 - 2977 m) gross Late Jurassic, Intra Heather reservoir sequence was penetrated in well 15/12-12 on the Rev Structure. The reservoir is interpreted as shallow marine sand bodies and is dated Oxfordian of age. On top of the reservoir lie 6 m sand dated Earliest Kimmeridgian of age. This sand was not considered as part of the net reservoir. The massive Intra Heather sands had very good reservoir quality. The cored interval of the reservoir had good hydrocarbon shows. Pressure data showed a clear gas gradient with a distinct GOC at 2954 m (2912 m TVD MSL) and an oil gradient down to base of reservoir (Top Triassic) at 2977 m (2932.5 m TVD MSL). MDT samples of the oil leg indicated an oil-down-to (ODT) situation. The pressure data also showed approximately 40 bars of depletion, caused by the production on the Varg Field (Southern Segment). </p> <p>The interval between 2864 - 3000 m was cored in six cores, nearly the complete reservoir section and the upper part of Triassic. MDT fluid samples were taken throughout the reservoir at 2867.5 m, 2895 m, 2961 m, 2964.2 m, and 2972.5 m. Samples from the two deepest levels recovered variable proportions of water and oil, reflecting the lack of a clear oil-water contact (OWC) in the reservoir. This is interpreted as an effect of the pressure depletion due to the production on Varg. Apart from the sampled water, which was heavily mud contaminated, sampled fluids were considered representative for the reservoir. </p> <p>The well was permanently abandoned on 9 February 2001 as an oil and gas discovery.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
3391
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7/6/2016 12:00:00 AM
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04.11.2024
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15/12-13
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<p><b>General</b></p> <p>Well 15/12-13 is located approximately 0.8 km northwest of the 15/12-12 (Varg South) Discovery well. The primary objective was to appraise the Varg South discovery: to define the oil/water contact, measure current reservoir pressure and fluid gradients, confirm reservoir quality and geometry, and confirm geophysical model in terms of depth to top and base reservoir. Potential Kimmeridgian Sandstone immediately above the main Oxfordian reservoir was seen as a secondary objective.</p> <p><b>Operations and results</b></p> <p>Appraisal well 15/12-13 was spudded with the semi-submersible installation West Alpha on 23 April 2003 and drilled to TD at 3047 m in Middle Jurassic Hugin Formation sandstone. The well is classified as vertical, but due to high deviation the difference between measured depth and vertical depth is 17 m at TD. The well was drilled with seawater and hi-vis sweeps down to 1321 m, and with Sodium silicate (Barasil CX) mud from 1321 m to TD.</p> <p>Well 15/12-13 penetrated the target Oxfordian sandstone (Intra Heather Formation sandstone) at 3013 m (2966 m TVDSS), which was 105 m deeper than prognosed. This was below OWC, and the sand was water-wet. The overlying Draupne and Heather formations were thicker the than prognoses, and the target area proved to be down faulted. The sand encountered was, based on biostratigraphy, the same as in well 15/12-12. As the objectives were not achieved by this well, it was decided to drill a geological sidetrack.</p> <p>Well bore 15/12-3 was logged by LWD in two runs; no wire line logs were run. No pressure or fluid sampling tools were run. No cores were cut.</p> <p>The well bore was plugged back to 1279 m and permanently abandoned on 11 May 2003 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
4733
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7/6/2016 12:00:00 AM
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04.11.2024
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15/12-13 A
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<p><b>General</b></p> <p>Well 15/12-13 is located ca 0.8 km northwest of the 15/12-12 (Varg South) Discovery well. The primary objective was to appraise the Varg South discovery: to define the oil/water contact, measure current reservoir pressure and fluid gradients, confirm reservoir quality and geometry, and confirm geophysical model in terms of depth to top and base reservoir. Potential Kimmeridgian Sandstone immediately above the main Oxfordian reservoir was seen as a secondary objective. The well bore 15/12-13 encountered the Oxfordian sandstones (Intra Heather Formation sandstone) 105 m deeper than the prognosed reservoir, and below the OWC. Since the objectiv of this well was not met well 15/12-13 A was drilled as a geological sidetrack to 15/12-13. The geological target was the same as in the primary well bore, but ca 300 m southwest of the discovery well 15/12-12.</p> <p><b>Operations and results</b></p> <p>Appraisal sidetrack well 15/12-13 A was spudded with the semi-submersible installation West Alpha on 11 May 2003. Kick-off was at 1350 m. The well was drilled to 2530 m, when the BHA became stuck repeatedly due to poor hole cleaning and the fact that the formation was reacting with the mud. The well bore was drilled with Sodium silicate (Barasil CX)/KCl/glycol mud. The well bore was logged with LWD only. No wire line logs were run, no pressure or fluid samples were taken, and no cores were cut.</p> <p>The sidetrack was abandoned in favor of a lower angle sidetrack along a different azimuth. It was permanently abandoned on 17 May as a junked well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
4754
|
7/6/2016 12:00:00 AM
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04.11.2024
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15/12-13 B
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<p><b>General</b></p> <p>Well 15/12-13 is located ca 0.8 km northwest of the 15/12-12 (Varg South) Discovery well. The primary objective was to appraise this discovery: to define the oil/water contact, measure current reservoir pressure and fluid gradients, confirm reservoir quality and geometry, and confirm geophysical model in terms of depth to top and base reservoir. Potential Kimmeridgian Sandstone immediately above the main Oxfordian reservoir was seen as secondary objective. The well bore 15/12-13 encountered the Oxfordian sandstones (Intra Heather Formation sandstone) 105 m deeper than the prognosed reservoir, and below the OWC. Since the objective of this well was not met well 15/12-13 A was drilled as a geological sidetrack to 15/12-13. Well 15/12-13 was abandoned in the Rogaland Group due to hole instability problems, and it was decided to drill a second sidetrack. This sidetrack had target approximately 350 m to the northwest of 15/12-12. </p> <p><b>Operations and results</b></p> <p>Appraisal sidetrack well 15/12-13 B was spudded with the semi-submersible installation West Alpha on 17 May 2003. Kick-off was at 1345 m in 15/12-13. It was drilled to TD at 3151 m in the Triassic Sleipner Formation. The well bore was drilled with Sodium silicate (Barasil CX)/KCl/glycol mud.</p> <p>A total of 134 m MD (128 m TVD) of Kimmeridgian to Late Oxfordian reservoir (2958 m to 3092 m MD) was penetrated in well 15/12-13 B. The oil/water contact was established at 3061.3 m (2964 m TVDSS), and the gas/oil contact at 3027.5 m (2931 m TVDSS). The reservoir was found to be pressure depleted, most likely due to production from the Varg Field, and the gas/oil contact had moved downwards from 2912 m TVDSS in well 15/12-12 (drilled in 2001). </p> <p>No conventional core was cut. The MDT tool was run for pressure measurements and fluid sampling. Gas was sampled at 3010 m, 3017 m, 3021 m, and 3024 m. Oil was sampled at 3028.5 m. After completion of the logging program, the well was permanently abandoned on 11 June 2003 as an oil and gas appraisal.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> </html> |
4759
|
7/6/2016 12:00:00 AM
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04.11.2024
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15/12-14
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<p><b>General</b></p>
<p>Well 15/12-14 was drilled as an appraisal well in the Varg West segment. The well was sidetracked from the existing well 15/12-A-12. The objectives were to prove hydrocarbons in the Varg West segment, complete as an oil producer, and maximize the Varg oil production.</p> <p><b>Operations and results</b></p> <p>Appraisal well 15/12-14 was drilled as a sidetrack from 15/12-A-12 on the Varg field below the 13 3/8" casing shoe. The operations started on 8 December 2003 with re-entry of well 15/12-A-12. All operations were performed with the jack-up 3 legs installation Mærsk Giant. The well bore was kicked off on 14 December at 1348 m and was drilled to TD at 3305 m in the Middle Jurassic Hugin Formation. Maximum deviation in the well is 36.95 degrees towards the base of the reservoir, decreasing to 34.4 degrees at TD. Apart from a VSP_GR run and a CST-GR run all log data in the well originate from LWD. The well was drilled using oil-based mud (ENVIRON) from kick-off to TD. </p> <p>Well 15/12-14 penetrated oil filled Late Oxfordian sandstone, Hugin Formation, at 3104.9 m (2867.6 m TVD MSL). A total of 105 m MD (3105 ? 3210 m), 84 m TVD (2868 ? 2952 m TVD MSL), was penetrated in the well. No oil/water contact was found in the well, the oil-down-to is placed at 2956 m TVD MSL (3214.5 m MD). Shows were recorded down to 3236 m. The reservoir consisted of fine to medium grained sandstone with some coarser grained beds in between. The average estimated porosity in the reservoir section was 21 % with a N/G of 0.7. The reservoir was found to be pressure depleted compared to the initial pressure observed in the Varg Field. Varg W is interpreted to be in communication with Varg N3 (15/12-A-5 T2). The results from the well thus confirmed the presence of hydrocarbon bearing reservoir in the Varg W segment, and increased the reserves in the field. </p> <p>No conventional core was cut in the well. Formation pressure sampling was performed while drilling, utilizing the GeoTap tool from Halliburton. No fluid sample was taken.</p> <p>The well was completed with a perforated liner and set in production with an initial production rate of 2000 Sm3/d. The well was classified as appraisal and was renamed to 15/12-A-12 A after completion. </p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
4845
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4/11/2017 12:00:00 AM
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04.11.2024
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15/12-15
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<p><b>General</b></p> <p>Wildcat well 15/12-15 was drilled on the Maureen Terrace, ca 3 km west of the Varg and 15/12-12 Rev Discoveries. The main object of the well was to drill to Middle Jurassic/Triassic strata with the aim to explore the hydrocarbon bearing potential of Oxfordian age sandstones analogues to the Varg West. Secondary objective was the hydrocarbon potential of Kimmeridge age sandstone immediately above the main Oxfordian reservoir. The well should measure reservoir pressure and fluid gradients, assess the reservoir quality of the Late Jurassic target reservoir, assess reservoir geometry, and confirm geophysical model in terms of depth to top and base reservoir. </p> <p><b>Operations and results</b></p> <p>Well 15/12-15 was spudded with the semi-submersible installation Deepsea Trym on 19 November 2004 and drilled to TD at 3300 m in the Middle Jurassic Sleipner Formation. Apart from some very slow drilling in the interval from 2454 m to 2492 m no significant problems were encountered in the operations. The well was drilled with seawater and hi-vis sweeps down to 1370 m, and with a salt saturated /polymer mud system (Performadril) from 1370 m to TD.</p> <p>Well 15/12-15 penetrated the Oxfordian sandstone at 3140.5 m. The sand was encountered 92 m TVDSS deeper than expected, and was water-wet. The overlying Kimmeridgian sands within the Heather Formation were approximately 96 metres thicker than prognosed and were also water-wet. Weak possible fluorescence was reported from cuttings within the Kimmeridgian reservoir but post-well geochemical analyses revealed no evidence for hydrocarbons of any kind. MDT pressure measurements found the reservoir to be pressure depleted. </p> <p>No cores were cut and no wire line fluid samples taken in the well.</p> <p>The well was permanently abandoned on 21 December 2004 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
5017
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4/11/2017 12:00:00 AM
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04.11.2024
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15/12-16 S
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<p>Well <a name="OLE_LINK2"></a><a name="OLE_LINK1">15/12-16 S </a>was drilled to appraise the Varg Field in the Southern Viking Graben area of the North Sea. Three wells had been drilled on the field, 15/12-12 and 15/12-13 B (gas condensate) and one dry well 15/12-13. Well 15/12-13 A failed while in the Rogaland Formation. These 3 wells delineate the Western Flank of the field, while 15/12-16 S should seek to add proven reserves in the central panel. </span></p> <p>The primary objective for the well was to produce gas condensate from the Oxfordian reservoir in the central panel and to determine by DST whether surrounding faults form barriers to production. Secondary objectives were to acquire reservoir pressure data, formation depths, cuttings, log and drill data for reservoir description and reservoir performance prediction.</p> <p><b>Operations and results</b></p> <p>Well 15/12-16 S was spudded with the jack-up installation Mærsk Giant on 6 February 2006 and drilled to TD at 2961 m, 47 m into the Triassic Skagerrak Formation. No major drilling problems or incidents occurred during the drilling of the well. The 8 ½" section was drilled in one bit run. The well was drilled with seawater and KCl/polymer down to 1319 m, with Performadril WBM from 1319 m to 2835 m, and with Baradril-N WBM from 2835 m to TD.</p> <p>The well encountered the top reservoir Oxfordian sandstone at 2836 m (2787 m TVD RKB), 70 m high to prognosis and encountered a reservoir section thinner than predicted (83 m MD vs. 130 m). Preliminary interpretation indicated that the top of the reservoir section was faulted out and that RZ2 is very condensed. Reservoir quality was slightly poorer than was predicted with low porosities in the lower part but is still good. Logs and MDT pressure data showed the reservoir was gas filled but no definite gas-water contact was defined.</p> <p>Dull yellow/gold mineral fluorescence, poor slow white cuts and poor crush cuts were noted on the cuttings in top of the Tor Formation. In the gas filled Oxfordian sandstone dull blue white slow cloudy cut fluorescence was observed, no direct fluorescence. Otherwise there were no shows reported from the well.</p> <p>No cores were cut and no wire line fluid samples were taken.</p> <p>The well was suspended on 31 March 2006 as a Varg South gas producer.</p> <p><b>Testing</b></p> <p>The well was completed with a 7" liner across the reservoir and perforated at intervals 2850 m to 2884 m for testing. An extended testing program was carried out, with the main flow period flowing at a steady rate of 1190000 Sm3 gas/day through a 72/64" choke. The average condensate-gas ratio was 49.7 bbl/MMSCF corresponding to a GOR of ca 3600 Sm3/Sm3. Sampling results gave a condensate gravity of 52.3 deg API, a gas gravity of 0.692 with 2ppm H2S and 2 % CO2.</p> |
5271
|
4/11/2017 12:00:00 AM
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04.11.2024
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15/12-17 A
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<p><b>General</b></p> <p>Well <a name="OLE_LINK2"></a><a name="OLE_LINK1">15/12-17 A </a>was drilled as a geological sidetrack of the 15/12-17 S, down dip into a separate down faulted compartment. The objective was to find the GOC and OWC which were not seen in the 15/12-17 S well.</span></p> <p><b>Operations and results</b></p> <p>Well 15/12-17 A was drilled with the jack-up installation Mærsk Giant. The well was kicked of from 3030 m in 15/12-17 S on 4 February 2007 and drilled to TD at 3620 m (2655 m TVD RKB) in the Triassic Skagerrak Formation. The well was drilled with Carbo SEA oil based mud from kick-off to TD.</p> <p>The top of late Jurassic sands was picked at 3360 m (2813 m TVD RKB). The base of the reservoir (top Skagerrak Formation) was picked at 3550 m (2916m TVD RKB) and gives a reservoir thickness of 107 m TVD. The well found gas in the Late Jurassic sands and the Skagerrak formation, but did not find any GOC or OWC.</p> <p>No cores were cut and no fluid samples were collected.</p> <p>The well was suspended on 23 March 2007 for future use as a gas producer.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
5484
|
4/11/2017 12:00:00 AM
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04.11.2024
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15/12-17 S
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<p><b>General</b></p> <p>Well <a name="OLE_LINK2"></a><a name="OLE_LINK1">15/12-17 S </a>was drilled to explore an un-drilled part of the East flank of the Rev structure. Four previous wells on the structure had proved good quality Late Jurassic shallow marine reservoir sandstone containing gas-condensate and a thin oil leg around a salt structure at about 3000 metres depth. Pressure measurements have shown that the reservoir is in communication with the Varg field to the north. Seismic data indicated that the reservoir thins and possibly pinches-out up dip towards the crest of the salt wall.</span></p> <p><b>Operations and results</b></p> <p>Well 15/12-17 S was spudded with the jack-up installation Mærsk Giant on 23 December 2006 and drilled to TD at 3371 m in the Late Permian Zechstein Group. The well surface position was on the west flank of the salt structure. A vertical 9 7/8" pilot hole was drilled in one bit run down to 810 m to ensure no shallow gas in potential zones. No gas was observed. The pilot hole was then opened up to 17 1/2" down to 810 m. From there the 17 1/2" section was drilled deviated in a single bit run down to 1313 m. The well continued in an east-southeast direction with TD at a location east of the crest of the salt structure. The well was drilled with sea water and hi-vis sweeps down to 810 m, with sea water and KCl/polymer from 810 m to 1313 m and with Carbo SEA oil based mud from 1313 m to TD. The well took a 15 m3 gas kick at 3258 m (2871 m TVD RKB). It is clear from the kick that the reservoir pressures were higher than both the anticipated depleted values and the previously measured virgin pressures in the Varg/Rev area.</p> <p>The Late Jurassic reservoir sands were penetrated at 3246 m (2773 m TVD RKB) and were found to be gas/condensate filled. No gas/water or gas/oil contact was penetrated. Apart from the oil bearing Late Jurassic reservoir section, fluorescence, mostly mineral fluorescence, was recorded only in limestone of the Tor Formation.</p> <p>No cores were cut. MDT pressure samples were acquired in the Late Jurassic sandstones together with an MDT fluid gas/condensate sample at 3288 m. The pressure data obtained showed that the reservoir penetrated by the well was in a separate pressure cell that did not seem to have been affected by production from Varg. </p> <p>Following wire line logging and pressure and fluid sampling, the well was plugged back for a geological. The purpose of the sidetrack was to establish the hydrocarbon/water contacts. </p> <p>The well was plugged back to 3156 m on 4 February 2007.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
5442
|
4/11/2017 12:00:00 AM
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04.11.2024
|
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15/12-18 A
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<p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/12-18 A is located between the Sleipner Øst and Varg fields in the North Sea. It was drilled to appraise the Paleocene oil discovery made in 15/12-18 S. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/12-18 A was kicked off from below the 13 3/8" casing shoe at 1170 m in well 15/12-18 S on 8 November 2007. Inclination was built to 41 degrees, which was achieved at 1733 m. Final TD was reached at 3036 m in the Late Cretaceous Tor Formation. The well was drilled with the jack-up installation Mærsk Giant. It was impossible to run wire line logs past the kick off area and therefore only LWD logs were obtained from 15/12-18 A. Otherwise no significant problem was encountered in the operations. The well was drilled with Enviromul oil based mud from kick-off to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was drilled into Top Heimdal reservoir at 2884 m where hydrocarbons were encountered in two 2 m thick sands. The targeted Ty Formation was encountered 10 m thick at 2952 m (2613 m TVD). The sand was, however, found below the OWC established in 15/12-18 S and was water bearing. Apart from the Heimdal Formation reservoir shows were observed only on claystones in the interval 2600 - 2690 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid samples were taken in this well bore.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 11 December 2009 as a discovery well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
5608
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4/11/2017 12:00:00 AM
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04.11.2024
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15/12-18 S
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<p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/12-18 S is located between the Sleipner Øst and Varg fields in the North Sea. The well was designed to test three prospects in different stratigraphic intervals, referred to as Grid (Eocene), Storskrymten (Paleocene) and Grytkollen (Triassic Hugin/Skagerrak Formation). The Storskrymten reservoir was the primary objective of the three. If hydrocarbons were discovered bore, a sidetrack would be evaluated to prove the vertical extension of the column. All prospects were based on up doming effects along the main migration routes from the Maureen area. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/12-18 S was spudded with the jack-up installation Mærsk Giant on 5 September 2007 and drilled to TD at 3520 m (3310 m TVD) in the Late Permian Zechstein Group. It was drilled vertical down to 1700 m, building angle up to ca 35 deg at ca 2550 m. The deviation was kept within 36 to 24 deg for the remaining well path down to TD. The drilling operation was executed with several down-hole problems. Major delays were due to logging problems and lost circulation in the Cretaceous. The well was drilled with seawater down to 474 m, with KCl/polymer mud from 474 m to 1173 m, with mineral oil -based mud (Carbo-Sea) from 1173 m to 2773 m, and with Enviromul oil based mud from 2773 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Twenty-two m of Grid sandstones were found water bearing. The Paleocene Ty Formation at 2670 m (2589 m TVD) was found hydrocarbon bearing. The OWC was from pressure data set to 2687.5 m (2602.5 m TVD). From the resistivity logs, however, the OWC would be set at 2691 m (2605.8 m TVD). This gives a vertical oil column of 16.8 m. Shows were recorded down to 2722 m. After evaluation of the Ty Formation reservoir, drilling continued into Hugin Formation at 3420 m (3219 m TVD), where 9 m of sandstone was encountered, but with no hydrocarbons. Shows were recorded on limestone at 2960 to 2970 m, in marl/claystone in the interval 3053 to 3175 m, and in shales of the Draupne and Heather Formations from 3270 to 3320 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>No core was cut. Oil was sampled during the MDT runs at depths of 2671.9 m and 2683.6 m. Water was sampled at 2705 m. A mini-DST was attempted but aborted due to packer problems.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was completed on 7 November 2007 as an oil discovery. A side track (15/12-18 A) was initiated to appraise the discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
5607
|
4/11/2017 12:00:00 AM
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04.11.2024
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15/12-19
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>The Pi North well 15/12-19 was drilled on the northern lobe of the Maureen Terrace in the North Sea. The prospect is adjacent to the UK Armada complex of Fields (Fleming, Drake and Hawkins) and the Seymour Fields to the West and the Varg and Rev Fields to the North. The main objective of the well was to test the hydrocarbon potential in Sleipner/Skagerrak sandstone formations in the Pi North structure.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well was spudded with the jack-up installation Mærsk Guardian on18 February 2008 and drilled to TD at 3212 m in Triassic rocks of the Skagerrak Formation. A 9 7/8" shallow gas pilot hole was drilled from TD in the 36" section at 203.5 m to 672 m. No shallow gas was seen. No significant problem was encountered in the operations. The well was drilled with sea water and pre-hydrated bentonite down to 672 m, with Aquadrill mud from 672 m to 1364 m, and with Carbo SEA oil based mud from 1364 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top Jurassic was encountered at 2969 m and consisted of only 4 m Draupne Formation directly overlying the Triassic Skagerrak Formation. No sediments of the Jurassic Sleipner Formation were encountered. The Skagerrak Formation was hydrocarbon bearing. The sandstones had an average porosity of 17% net when using an 11.8% cut off in the oil case and 8.1% in the gas case. The reservoir system was complex with an upper reservoir with gas down to 2986.8 m (13.8 m TVD gross gas column, 9.21m net pay) and an underlying oil column of 35.7 m TVD gross (13.11m net pay). A lower reservoir with a 16.5 m TVD gross oil-leg (3.81 m net pay) was encountered at 3044.5 m. The two oil zones were separated by a 22 m thick zone of movable water (confirmed by RCI water samples). Pressure data in the different reservoir zones indicated different pressure regimes and varying pressure depletion caused by production from neighbouring fields. No oil shows were observed in the well other than in the Skagerrak reservoir sections.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores totalling 156.69 m were cut with 100% core recovery from 2975.0 to 3131.7 m in the Skagerrak Formation. </span></p> <p class=MsoBodyText><span lang=EN-GB>RCI wire line fluid samples were taken at 2973.5 m (gas), 2983 m (gas), 2994.5 (oil), 3023.5 m (water/oil mix), 3056.2 m (oil), 3030.1 m (water), 3015 m (oil), and 3117.5 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 20 May as an oil and gas discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Three drill stem test were conducted in the Skagerrak Formation. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1A tested the interval 3088 - 3102 m. It produced 318 Sm3 oil and 29450 Sm3 gas /day through a 28/64" choke in the main flow. The GOR was 93 Sm3/Sm3. The bottom hole temperature was 130.8 deg C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1B tested the intervals 3088 - 3102 m and 3036.5 - 3064 m. It produced 657 Sm3 oil and 156620 Sm3 gas /day through a 44/64" choke in the main flow. The GOR was 239 Sm3/Sm3. The bottom hole temperature was 130.0 deg C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1C tested the interval 3088 - 3102 m, 3036.5 - 3064 m, and 3023 - 3029 m. It produced 396 Sm3 oil and 831297 Sm3 gas /day through a 56/64" choke in the main flow. The GOR was 2102 Sm3/Sm3. The bottom hole temperature was 127.8 deg C.</span></p> |
5705
|
2/21/2020 12:00:00 AM
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04.11.2024
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15/12-2
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<p><b>General</b></p>
<p>Well 15/12-2 was drilled in order to evaluate Jurassic formations on a seismic structure located in the eastern part of block 15/12. The principal objective of the 15/12-2 well was to test the Dogger (Hugin Formation) sandstone, where oil shows had been encountered in the 15/12-1 well. A secondary object was a possible sand in the Paleocene. </p> <p><b>Operations and results</b></p> <p>Wildcat well 15/12-2 was spudded with the semi-submersible installation Ross Rig on 7 January 1976 and drilled to TD at 2924 m in Late Permian Zechstein anhydrite. The well was drilled with a lignosulphonate mud system. </p> <p>No sand was found in the Paleocene. The Hugin Formation sandstone was found 304 meters higher than in the 15/12-1 well. The sandstone proved to have very good reservoir qualities, but was completely water bearing. There were sandstone stringers in the lower part of the Heather Formation. The Hugin Formation sand was cored from 2823 m to 2835.4 m, with no show. No fluid sampling was attempted in the well.</p> <p>The well was permanently abandoned as a dry well on 27 February 1976.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
331
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9/16/2019 12:00:00 AM
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04.11.2024
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15/12-20 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/12-20 S was drilled from the Varg Field production Platform in the southern Viking Graben in the North Sea. The primary objective of the well was to explore a potential undrained compartment in Triassic sands. A secondary objective was potential Late Jurassic sands that could exist above the Triassic sands. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/12-20 S was drilled with the jack-up installation Mærsk Giant, as a sidetrack from development well 15/12-A-7 on the Varg Field. It was kicked off 28 May 2008 from 1306 m, just above the 13 3/8" casing in the 15/12-A-7 development well, and drilled to TD at 4192 m (3142 m TVD) in the Late Triassic Skagerrak Formation. Significant operational problems were not encountered although 21% of the rig time was counted as non-productive. The main contributor to non-productive time was failure to mill the window in the 13 3/8" casing during kick-off. The well was drilled with Carbo-Sea oil based mud from kick-off to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Oxfordian Sandstone that makes up the reservoir over Varg Field was absent as forecast. A discovery was made in Middle Jurassic Sleipner Formation sandstone. This sand, encountered at 3808 m, was not prognosed. It contained oil down to a lithological contact at ca 3842 m (2878 m TVD SS). The underlying Triassic was encountered at 3874 m and was dry. Good shows on sandstones were reported in cuttings at 3810 and all through to the end of the cores at 3875 m. Formation Gas peaks up to a maximum of 4% were seen in the Sleipner formation. Resistivity was initially high, 15 ? 30 ohm/m from 3812 m (after the coal) and dropped off at 3835m MD to 0.3 - 0.8 ohm/m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were taken (26.26 m and 54.85 m) from the Sleipner Formation and ca 25 m into the Triassic. Reservoir pressures were taken using TesTrak and an oil gradient of 0.935 SG was obtained although a water gradient was not established. No wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>Exploration well 15/12-20 S is classified as an oil discovery. On 1 July 2008 7" liner was run to 4191 m and the well was reclassified to development well 15/12-A-7-A.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
5824
|
4/11/2017 12:00:00 AM
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04.11.2024
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15/12-21
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The 15/12-21 Grevling well is located on the south-western margin of the Hidra High, approximately 18 km north of the Varg field in the southernmost part of the Viking Graben. The primary objective was to test the Middle Jurassic Hugin and Sleipner formations in a crestal position on the structure. The Triassic Skagerrak Formation was a secondary objective.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>A 12 1/4" pilot hole was drilled to 1195 m to check for shallow gas. No shallow gas was encountered. Well 15/12-21 was spudded with the jack-up installation Mærsk Guardian on 15 March 2009 and drilled to TD at 3310 m in the Late Triassic Skagerrak Formation. The well was drilled with Seawater and sweeps down to 221 m, with a water based KCl mud from 221 m to 1193 m, and with Carbosea oil based mud from 1193 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The top of the Hugin reservoir was encountered at 3031 m, 15m deeper than prognosis. The Sleipner Formation reservoir came in 21m shallow, at 3059 m, and top the Triassic 11 m shallow, at 3122 m. The Hugin, Sleipner and upper Skagerrak formations all proved to be oil bearing with a total pay of 67 m. No oil water contacts were encountered within the well. However, two vertical pressure barriers were interpreted; a top Sleipner coal at 3059 m (3017 m TVDSS), which separates the Hugin and Sleipner oil-bearing sandstones, and an intra-Triassic shale at 3164 m (3122 m TVDSS), which separates oil bearing Skagerrak sandstones above from water bearing Skagerrak sandstones below. No oil shows were recorded above reservoir level in the well. In the Triassic oil shows were seen down to 3179 m, 15 m below the oil-down to contact in the Skagerrak Formation.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores of a total of 88.26 m were cut. Core 1 was cut from 3047.50 m to 3081.70 m in the Hugin and Sleipner formations, and core 2 was cut from 3106.50 m to 3160.56 m in the Sleipner and Triassic Skagerrak formations. The Cores need to be depth shifted up 6.5 meters to match log data. RCI wire line fluid samples were taken in the Hugin Formation at 3034.5 m (oil), the Sleipner Formation at 3074.4 m (oil), and in the Skagerrak Formation at 3152 m (oil), 3186.8 m (water), and 3222 m (water). </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 21 May 2009 as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two drill stem tests were performed. </span></p> <p class=MsoBodyText><span lang=EN-GB>In DST 1 the Sleipner/Skagerrak Formations were perforated in the interval 3099.6 to 3158.17 m. DST1 produced 124 Sm3 oil and 3617 Sm3 gas /day through a 20/64" choke in the main flow. The oil density was 0.861 g/cm3 and the GOR was 29 Sm3/Sm3. The gas gravity was 1.121 (air = 1) with 11 ppm H2S and 5.5% CO2. The bottom hole temperature recorded in DST1 was 120 deg C.</span></p> <p class=MsoBodyText><span lang=EN-GB>In DST 2 the Hugin Formation was perforated in the interval 3030.24 to 3059.04 m. DST2 produced 75 Sm3 oil and 3563 Sm3 gas /day through a 20/64" choke in the main flow. The oil density was 0.861 g/cm3 and the GOR was 47 Sm3/Sm3.The gas gravity was 1.121 (air = 1) with 10 ppm H2S, and 9.0 % CO2. The bottom hole temperature recorded in DST2 was 117 deg C.</span></p> <p class=MsoBodyText><span lang=EN-GB>No water was produced in the tests.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6047
|
4/11/2017 12:00:00 AM
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04.11.2024
|
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15/12-21 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The 15/12-21 A is a sidetrack to the 15/12-21 Grevling well, which discovered oil in Hugin, Sleipner, and Skagerrak Formations sandstones. No oil-water contacts were seen in 15/12-21. The sidetrack well was drilled to appraise the discovery down flanks and to the east on the structure.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/12-21A was kicked off from 2162 m in well 15/12-21 on 21 May 2009. It was drilled with the jack-up installation Mærsk Guardian to TD at 3702 m (3348 m TVD) in the Late Triassic Skagerrak Formation. The well was drilled with Carbosea oil based mud from kick-off to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Hugin Formation was encountered at 3378 m (3118 m TVD), the Sleipner Formation at 3412 m (3141 m TVD), and the Triassic Skagerrak Formation at 3493 m (3198 m TVD). All three formations proved to be oil bearing as in the main well, with total pay of 36 m MD. No oil shows were noted above reservoir level. Patchy oil shows were recorded down to 3570m and the higher gas components had died away by 3586m. Show description was compromised due to the fact that the sandstone cuttings were often altered to an amorphous rock flour. The shows were described as poor direct pale white fluorescence, slow white crush cut fluorescence, very pale tea colour residue.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut in this well. RCI wire line fluid samples were taken at 3394.5 m in the Hugin Formation (oil), 3411.7 m in the Hugin Formation (oil), 3519.4 m in the Skagerrak Formation (oil), and at 3646 m in the Skagerrak Formation (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 20 June 2009 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6139
|
4/11/2017 12:00:00 AM
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04.11.2024
|
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15/12-22
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The15/12-22 Storkollen well was drilled south of the Sleipner East Field in the south Viking Graben of the North Sea. The objective was test the hydrocarbon and reservoir potential of the Storkollen prospect. Primary target was Oxfordian "Varg Equivalent sandstone" (Hugin Formation) of the Vestland Group, while the Early Tertiary Heimdal/Ty Formations was a secondary target.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/12-22 was spudded with the semi-submersible installation Bredford Dolphin on 17 April 2010 and drilled to TD at 3035 m in the Late Triassic Skagerrak Formation. A shallow gas influx occurred at 697-700 m while waiting on weather (low wind) after having drilled the 9 7/8" pilot hole to 744 m. The interval had an intermediate shallow gas warning. The gas influx was killed with 1.25 GS mud, and the pilot hole was plugged back for setting the contingent 20" casing with the shoe at 622 m. The well was drilled with seawater/bentonite and hi-vis sweeps down to 622 m, with KCl/polymer/GEM mud from 622 m to 1550 m, and with XP-07 oil based mud from 1550 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Tertiary sands were penetrated in the Utsira and Skade formations, while the Frigg Formation sandstones were not encountered at the Storkollen location. The secondary target, the Paleocene Heimdal/Ty Formations was not present, and Top Shetland chalks were penetrated at 2320 m, which was 16 m shallower than prognosed. The primary reservoir target, the Hugin Formation of the Vestland Group, was penetrated at 2831 m, which was 22 m shallower than prognosed. The sandstone unit was 154 m thick and had excellent quality with a N/G ratio of 96% and an average porosity of 25%. It was water bearing. GeoTap pressure measurements within the Hugin Formation detected an overpressure of only 42 bars, compared to normal hydrostatic pressure. The low overpressures may indicate compartmentalisation, thus explaining failed migration into the Storkollen 4-way closure. Apart from the shallow gas influx no oil or gas shows are reported from the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. The well was logged on MWD/LWD and no wire line logs were run. No wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 16 May 2010 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
6326
|
4/11/2017 12:00:00 AM
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04.11.2024
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15/12-23
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/12-23 was drilled to appraise the Grevling Discovery in the Southern Viking Graben in the North Sea. The objective was to seek a deeper oil reservoir, or an oil water contact, within the Sleipner Formation, while addressing reservoir distribution and quality along with oil type and to prove up additional reserves in the Grevling discovery in the Hugin, Sleipner and Skagerrak formations sandstones.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/12-23 was spudded with the semi-submersible installation Transocean Winner on 1 April 2010 and drilled to TD at 3485 m in the Late Triassic Skagerrak Formation. No significant problem was encountered in the operations. The well was drilled with Hi-Vis Bentonite Sweeps down to 176 m, with KCl/GEM mud from 176 m to 1200 m, and with ENVIROMUL oil based mud from 1200 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The prognosed top reservoir Hugin Formation was absent. Instead a silty Intra Heather Formation Sandstone was found directly on the Sleipner Formation. The Sleipner Formation came in at 3164 m and proved to be the main reservoir with coals and massive sandstones interbedded with siltstone. The top of the Sleipner was picked on the log response of coals present at the top of the Formation, and coals seen in the samples. Top reservoir sandstones came in at 3179 m only 1 m deep to prognosis. The reservoir comprises the Sleipner and Skagerrak Formations at this well location. The Skagerrak Formation came in at 3192 m 56 m shallower than the prognosis. Top Skagerrak was picked 54 m shallower from core biostratigraphy than from seismic and petrophysical logs. An OWC, possibly ODT, was picked at 3251 m in the Skagerrak Formation. Shows were observed on cuttings in the Sleipner sandstones and varied from no show to very good show in clean sands before pulling out to cut core at 3187 m. Shows from top cored interval in the Sleipner Formation at 3187 m continued into the Skagerrak Formation and down to 3230m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut, core 1 from 3187 m to 3241.5 m and core 2 from 3241.5 m to 3296 m, giving a total of 109 m of core. Cores must be depth shifted down 4.6 meter to match the logs. The MDT was run and 18 good pressure points were obtained. Fluid samples were taken at 3191 (oil), 3232 m (oil), 3264 (water), 3285 (water), and 3336 (water). </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29 May 2012 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One drill stem test was performed from the interval 3181.5 - 3233 m in the Sleipner and Skagerrak Formations. The test produced at maximum 103 Sm3 oil/day through a 16/64" choke in the main flow. The gas measuring equipment did not work properly. In the succeeding sampling flow the well produced 84 Sm3 oil and 4159 Sm3 gas/day through a 12/64" choke. The GOR was 50 Sm3/Sm3. </span></p> l> |
6327
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4/11/2017 12:00:00 AM
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04.11.2024
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15/12-23 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/12-23 A is a geological sidetrack to well 15/12-23, which proved oil in the Middle Jurassic Sleipner Formation and the Late Triassic Skagerrak Formation. It was drilled to appraise the Jurassic and Triassic potential in the western flank of the Grevling prospect in the Southern Viking Graben in the North Sea. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/12-23 A was drilled with the semi-submersible installation Transocean Winner. It was kicked off at 1191 m, below the 13 3/8" casing shoe in 15/12-23, and drilled to TD at 4772 m (3327 m) in the Middle Jurassic Sleipner Formation. The well was drilled with ENVIROMUL oil based mud from kick-off to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Hugin Formation was encountered at 4603 m (3220 m TVD). It had very good reservoir conditions and oil shows, but was water filled. The Sleipner Formation was encountered at 4632 m (3242 m TVD) and the upper section down to 4699 m consisted dominantly of coal beds and interbedded sandstones, which were difficult to interpret from logs. Some interbedded sandstones had shows and some had no shows. From 4699 m the Sleipner Formation was oil-bearing down to a probable OWC around 4725 m (3315 m TVD). Shows were recorded down to 4735 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut, core 1 from 4612 to 4664 m, core 2 from 4664 to 4701 m and core 3 from 4701.2 to 4741 m, giving a total of 129 m of core.</span></p> <p class=MsoBodyText><span lang=EN-GB>No wire line logs were run hence no down-hole fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 18 July 2010 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6404
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4/11/2017 12:00:00 AM
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04.11.2024
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15/12-24 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 15/12-24 S was drilled to test the Snømus prospect in the Ling depression adjacent to the Varg Field in the North Sea. The primary objective was to test the hydrocarbon potential in syn-rift Ula-Sandnes formations and pre-rift Hugin - Sleipner formations. Sands in the Triassic Skagerrak Formation was secondary objective. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/12-24 S was spudded with the jack-up installation Mærsk Giant on 10 April 2015 and drilled to TD at 3181 m in the Late Triassic Skagerrak Formation. A pilot hole was drilled from 178 m to 1355 m to check for shallow gas. Minor gas peaks associated with thin sand layers were recorded at 757 and 768 m, and potentially also at 488 and 505 m. No significant problem was encountered in the operations. The well was drilled with seawater and hi-vis sweeps down to 178 m, with KCl/polymer/GEM mud from 178 m to 1365 m, and with Innovert oil based mud from 1365 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Ula sand was encountered at 2903 m, 10.7 m deeper than prognosed. A total of 194 m MD of Ula and Sandnes sand with mostly good quality, were drilled. Top Skagerrak Formation was picked at 3097 m, 6 meters shallower than prognosed. A total of 84 m MD of Skagerrak Formation was drilled, however only poor quality reservoir sands encountered. All target reservoirs were water-wet. Only weak shows above the OBM were described in the Vestland Group and Skagerrak Formation, else no shows were recorded in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. Due to dry well, only VSP was run on wireline. No fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 20 May 2015 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7661
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4/18/2017 12:00:00 AM
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04.11.2024
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15/12-25
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 25/12-25 was drilled to test the Jerv prospect on the northern end of the Maureen Terrace in the North Sea, close to the UK border. The primary objective was to find hydrocarbons in the Paleocene Ty Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>A 9 7/8" pilot hole was drilled to section TD at 476 m and no shallow gas or over-pressured water was observed.</span></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 25/12-25 was spudded with the semi-submersible installation COSL Innovator on 18 February 2021 and drilled to TD at 2820 m in the Paleocene Våle Formation. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 476 m, and with Aquadril water-based mud from 476 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Ty Formation was penetrated from 2765.5 to 2808 m and contained gas-condensate all through to top Våle Formation. Approximately 30 meters of Ty was sandstone of good reservoir quality. The gas-water contact was not encountered. Oil shows were not observed outside of the Ty Formation. Pressure data collected with TesTrak showed the reservoir to be highly depleted due to production.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut in succession from 2780 to 2811.5 m in the lower sandstone in the Ty Formation and into the Våle Formation. No fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 26 March 2021 as a gas-condensate discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
9203
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3/26/2023 12:00:00 AM
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04.11.2024
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15/12-26
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 15/12-26 was drilled to test the Ilder prospect between the Grevling and Varg discoveries in the Ling depression in the North Sea. The primary objective was to find hydrocarbons in the Late Jurassic Ula formation. The secondary objective was to test the Triassic Skagerrak Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>A 9 7/8" pilot hole was drilled down to 1270 m with no shallow gas observed. </span></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/12-26 was spudded with the semi-submersible installation COSLInnovator on 12 May 2021. The 17 1/2" hole was drilled to 1270 m. Due to severe hole instability problems BOP was set at 1123 m. When starting to clean out the long rat hole from 1123 m to 1270 m, severe hole stability issues quickly became prominent. The decision was made to cement back and make a side-track. The 12 1/4" section was kicked off as a technical side-track 15/12-26 T2 at 1140 m within the Nordland Group and drilled down to a TD at 2625 m, 15 m into the Late Jurassic Draupne Formation. Prior to running in hole with 8-1/2" BHA #9, a problem was observed with the BOP. The BOP was pulled and after a week of pulling, repair and testing, the BOP was run back in hole. The 8 1/2" section was drilled to final TD at 2787 m (2786 m TVD), 3 m into Zechstein anhydrite. The primary well was drilled with seawater and hi-vis pills down to 1270 m while the side-track was drilled with Aquadril mud from 1140 m to TD. Altogether 14.6 days NPT was spent on the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Ula Formation reservoir was encountered at 2709 m (2708 m TVD) with good to very good reservoir sand. The Ula Formation was confirmed water bearing by logs and pressure points. In addition, the well encountered a ca 8 m thick Hugin Formation directly underlying the Ula Formation. There were no oil shows in the well and the gas levels were low.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12 May 2021 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
9204
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3/29/2023 12:00:00 AM
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04.11.2024
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15/12-3
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<p>Well 15/12-3 is located in the South Viking Graben in the North Sea, south of the Sleipner Øst Field. The primary objective of the well was to test possible hydrocarbons in late Jurassic sand. This sand was proven in 15/12-2. Secondary objectives were Danian and Rotliegendes sands. Minor Danian sand beds were proved in 15/12-1, and further west on the UK side oil was produced from Palaeocene sands on the Maureen Field. The well should be drilled through ca 1100 m of prognosed salt and 100 m into the Rotliegendes or to a total depth of 4900 m. </p> <p><b>Operations and results</b></p> <p>Well 15/12-3 was spudded with the semi-submersible installation Nordraug on 21 June 1980 and drilled to TD at 4450 m in Early Permian Rotliegendes sandstone. After setting the 13 3/8" casing the rig crew went on strike from 20 July to 14 August. While drilling 12 1/4" hole with salt saturated mud the bottom hole assembly got stuck at 2715 m when pulling out of the hole. Eleven days were spent working on the fish before the hole was eventually sidetracked from 2488 m. The well was drilled with seawater/bentonite/lignosulphonate mud down to 2185 m, with salt saturated polymer mud from 2185 m to 3361 m, and with oil based mud (Oilfaze) from 3361 m to TD.</p> <p>The primary objective, Jurassic sandstone, was only a few meter thick. The sand was found deeper and was thinner than expected. The well proved no sand in Palaeocene. The other secondary objective, Rotliegendes sandstone, was highly interbedded with shale. None of the sands had shows of hydrocarbons. </p> <p>One core was cut from 3256 to 3263 m in the Zechstein Group above the salt. A second core was cut near final TD in the Rotliegendes Group from 4424 to 4433 m. No wire line fluid samples were taken.</p> <p>The well was permanently abandoned on 22 December 1980 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
199
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5/19/2016 12:00:00 AM
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04.11.2024
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15/12-4
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<p>Wildcat well 15/12-4 is located on the Maureen Terrace in the South Viking Graben in the North Sea. The primary objectives were the Palaeocene Heimdal Formation and sandstones of Jurassic and Triassic age. Secondary objectives were the Frigg Formation and fractured limestone in the Cretaceous. </p> <p><b>Operations and results</b></p> <p>Well 15/12-4 was spudded with the semi-submersible installation Deepsea Bergen on 13 September 1984 and drilled to TD at 3157 m, 17 m into the Triassic Group. Operations were completed within the time schedule and with very few problems. The well was drilled with seawater and gel down to 505 m, with gypsum polymer from 505 m to 2680 m, and with lignosulphonate from 2680 m to TD.</p> <p>No Heimdal or Frigg sands were encountered in the well. From logs and cores hydrocarbons were seen in the uppermost part of the Cretaceous chalk in the interval 2490 ? 2515 m. Core analysis and log analysis indicated very poor reservoir properties in this chalk. The water saturation was high (60 - 80 %) and the permeability was extremely low (0.01 - 0.5 mD). A 1.5 meter oil column was seen in the Jurassic sandstone, from 2911.5 to 2913 m with a transition zone down to 2915.5. Apart from these two intervals there were no shows or other hydrocarbon indications in the well.</p> <p>Four cores were cut, one in the Palaeocene, two in the Late Cretaceous and one in the Late Jurassic sequence. One FMT run was made in the Cretaceous. Here, no pressure points out of 19 attempts were successful due to seal failure and very low permeability in the formation. One attempt to get sample at 2439.5 m failed due to tight formation. In the Jurassic a segregated FMT sample was taken at 2912 m (5.8 l oil with a density of 0.847 g/cm3 in the 2 3/4 gallon chamber) and a second segregated sample at 2913.5 m (0.5 l oil and 9 l water/mud filtrate in the 2 3/4 gallon chamber).</p> <p>The well was permanently abandoned on 31 October 1984 as an oil discovery.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
438
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7/6/2016 12:00:00 AM
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04.11.2024
|
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15/12-5
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 15/12-5 was drilled on the Beta Central structure ca 3.3 km north-east of the 15/12-4 Varg discovery well in the North Sea. Primary objective was the Jurassic sandstones. Secondary objective was the Frigg Formation sand and fractured limestone of Cretaceous age. Seismic anomalies indicated shallow gas. Prognosed TD was 3100 m RKB in sandstone of Triassic age.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/12-5 was spudded with the semi-submersible installation Ross Isle on 12 March 1986 and drilled to TD at 3150 m in the Late Triassic Skagerrak Formation. No shallow gas was encountered. Drilling proceeded without significant problems. The well was drilled with Spud mud down to 217 m, with gel/seawater/XC-polymer from 217 m to 619 m, with gypsum/polymer mud from 619 m to 2889 m, and with gel/lignosulphonate/lignite from 2889 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top Cretaceous came in at 2457 m, and top Jurassic at 2841 m. Top of the reservoir, an Oxfordian sandstone, was encountered at 2918 m with good shows. The OWC was found at 2942 m, 28 m below that of well 15/12-4. This is probably due to a flow barrier caused by the fault system with a maximum throw of ca 100 m that separates the Beta West and Beta Central structures. Due to FMT pressure measurements and fluid samples, Statoil decided to go for "sole risk" testing, since Esso denied participating in the testing program.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the interval 2892 m to 2967 m with 100% recovery. The core-log depth shifts were small, in the range 0.0 to -0.5 m for all three cores. FMT fluid samples were taken at 2919.3 m (oil), 2923.5 m, 2937.0 m (oil), and at 2941.5 m (water mud filtrate and a little oil).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 4 May 1986 as an oil appraisal of the Varg Field.<b> </b></span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One DST test was performed in the interval 2926 m to 2936 m. The test produced 520 Sm3 oil and 42000 Sm3 gas /day through a 40/64” choke. The GOR was 81 Sm3/Sm3, oil gravity was 0,909 g/cm3, and the gas gravity was 0.795 (air = 1). The test temperature was 127 °C.</span></p> |
113
|
2/21/2020 12:00:00 AM
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04.11.2024
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15/12-6 S
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<p>Block 15/12 is situated between the Jæren High to the south, Central Graben to the south-southwest, Andrew Ridge to the west, Ling Graben to the north and Viking Graben to the north-northwest. Well 15/12-6 S was the third well within the license area. It was drilled ca 3 km north of the 15/12-4 Varg Discovery well, which found 1.5 oil column in Jurassic sandstone. The main objective of 15/12-6 S was to test the hydrocarbon potential in Oxfordian sandstone in the north-western segment of the Beta west structure. Secondary objectives were Palaeocene sandstones (Maureen formation) and Triassic sandstones. Due to possible shallow gas problems, the well was moved 100 south to avoid this problem.</p> <p><b>Operations and results</b></p> <p>Well 15/12-6 S was spudded 19 August 1990 with the semi-submersible rig Deepsea Bergen and drilled to 3050 m in the Triassic Skagerrak Formation. While drilling the 12 1/4" hole the penetration stopped at 2560 m. The BHA was pulled out and it was found that the MWD tool had been twisted off. The hole was cemented back and sidetracked from 2495 m with increased mud weight. Ran 7" liner to 3046 m, and cemented inside the liner to 2960 m. No shallow gas was encountered. The well was drilled with bentonite spud mud and CMC/seawater down to 615 m, with gypsum/polymer mud from 615 m to 2757 m, and with gel/lignosulphonate mud from 2757 m to TD.</p> <p>Logs and shows indicated presence of hydrocarbons in the interval from 2428 to 2473 m in the late Cretaceous chalk but tests were not performed here due to tight formation. The Late Jurassic Oxfordian sandstone (Hugin Formation) came in at 2871 m, 80.5 m deeper than prognosed. It contained oil and from logs the OWC was found to be at 2943 m. There were no shows or other hydrocarbon indications below this depth.</p> <p>A total of seven cores were cut, six in the interval 2838 to 2966 m and the seventh from 2980 to 2988.5 m. An FMT run in Oxfordian sandstone gave 12 pressure readings out of 27 attempts. One sample was taken at 2935.5 m. The sample contained a mixture of mud filtrate and formation water with traces of hydrocarbons.</p> <p>The well was suspended on 4 November 1990 as an oil appraisal well, and was converted to development well (15/12-A-2).</p> <p><b>Testing</b></p> <p>Two DST tests were performed in this well:</p> <p>DST 1 from 2922 - 2930 m produced 153.8 Sm3/d oil and 11.683 Sm3/d gas through a 12.7 mm choke. The GOR was 76 Sm3/Sm3. A breakthrough, possibly through a fault, occurred at the end of the cleanup flow in this test, and this totally changed well productivity and also altered the flowing temperature. Before the breakthrough the temperature was 127 deg C and still increasing. After breakthrough the temperature sunk to 123 deg C.</p> <p>DST 2 from 2875 - 2895 m produced 866 Sm3/d oil and 52530 Sm3/d gas through a 15.9 mm choke. The GOR was 61 Sm3/Sm3, the oil density was 0.843 g/cm3 and the gas gravity was 0.740 (air = 1). The reservoir temperature was measured to 127.5 deg C.</p> |
1524
|
7/6/2016 12:00:00 AM
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04.11.2024
|
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15/12-7 S
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<p><b>General</b></p> <p>Well 15/12-7 S was designed to drill in Late Jurassic Oxfordian sandstones on the Theta North prospect in the southeastern part of the PL 116 licence area. The structure is a rotated fault block dipping southeast and bound to the west and north by faults. Based on mapping and inversion studies of the 15/12-5 well and the Beta-east structure it was likely that an Oxfordian sequence was present at the Theta structure. However, it could not be excluded that the Oxfordian reservoir had been eroded from top of the structure. The main objective of well 15/12-7 S was to test the potential for hydrocarbons in the Oxfordian sandstones. A secondary objective was to test possible Triassic sandstones. Seismic anomalies at 441 m and 792 m strongly suggested shallow gas. Because of this the spud location was set outside of the planned location.</p> <p><b>Operations and results</b></p> <p>Wildcat well 15/12-7 S was spudded with the semi-submersible installation Deepsea Bergen on 6 November 1990 and drilled to TD at 3529 m in the Triassic Smith Bank Formation. Problems were encountered in building and dropping angle in deviated well section (13 3/8" to 9 5/8"). Pipe stuck at 2703 m and 2720m but came free. Stuck again with FMT-tool at 3425m. The tool was left in the hole. The well was drilled with seawater and bentonite pills down to 173 m, with seawater and CMC EHV from 173 m to 620 m, with gypsum/PAC from 620 m to 3027 m, and with gel/polymer/lignosulphonate from 3027 m to TD. No shallow gas was encountered at 441 m, but from MWD gas was encountered at 775 m. Several misruns while logging were experienced. </p> <p>The Oxfordian reservoir sandstone (Intra Heather Sandstone) came in at 3025 m, 25.5 m shallower than prognosed. No hydrocarbons were encountered. One 27 m conventional core was cut from 3028 m to 3055 m in the reservoir unit with 94.4 % recovery. A total of 100 sidewall cores were attempted of which 93 were recovered. No sidewall cores were attempted in the 17 1/2" section (620 m to 1820 m) due to hole problems. No fluid samples were taken in the well.</p> <p>The well was permanently abandoned on 7 January 1991 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
1680
|
7/6/2016 12:00:00 AM
|
04.11.2024
|
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15/12-8
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<p><b>General</b></p>
<p>Wildcat well 15/12-8 was drilled ca 3.5 km east of the 15/12-4 well, which made the Varg oil discovery in Jurassic and Triassic sandstones. The main objective of the well was to test the potential for hydrocarbons in sandstones of Oxfordian and Triassic age. Seismic anomalies at 437, 467, 479 and 803 m indicated possibility for shallow gas. Planned TD for the well was 3260 m.</p> <p><b>Operations and results</b></p> <p>Well 15/12-8 was spudded with the semi-submersible installation Deepsea Bergen on 5 June 1991 and drilled to TD at 3054 m in the Triassic Skagerrak Formation. No significant problems occurred during operations. The well was drilled with seawater / hi-vis pills / CMC down to 615 m, with KCl/polymer mud from 615 m to 2855 m, and with Ancotemp/bentonite mud from 2855 m to TD. No shallow gas was encountered.</p> <p>Jurassic Vestland Group sandstone was encountered hydrocarbon-bearing at 2838 m. The hydrocarbon column extended 23 m into Triassic sandstone of the Skagerrak Formation. The gas/water contact was estimated to 2877 m, confirmed by FMT pressure gradients and wire line logs. The well was tested, and since no core was cut through the reservoir, the well was sidetracked at 2623 m with TD at 2940 m. The sidetrack was drilled with Ancotemp/bentonite mud. Three conventional cores were cut in the interval 2841 - 2902 m. The sidetrack was formally named 15/12-8 A.</p> <p>The FMT tool was run in well 15/12-8 and 15/12-8A. One segregated sample was taken at 2863 m in 15/12-8 (gas, condensate and mud filtrate) and another in the water zone at 2888 m in well 15/12-8 A (recovered mud only due to seal failure). </p> <p>Well 15/12-8 was permanently abandoned on 14 July 1991 as a gas/condensate discovery. The 15/12-8 A sidetrack was permanently abandoned on 29 July as a gas/condensate appraisal well.</p> <p><b>Testing</b></p> <p>One DST test was performed in 15/12-8 in the interval 2838 - 2869 m. The well produced gas-condensate with a dew point of 230 bar at the measured reservoir temperature, which was 123 deg C. The rates were 550 000 Sm3 gas and 420 Sm3 condensate /day through a 15.9 mm choke. The condensate/gas ratio was 1308 Sm3/Sm3, the condensate gravity was 61 deg API, and the gas gravity was 0.817 (air = 1).</p> |
1778
|
7/6/2016 12:00:00 AM
|
04.11.2024
|
|
15/12-8 A
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<p><b>General</b></p>
<p>Wildcat well 15/12-8 was drilled ca 3.5 km east of the 15/12-4 well, which made the Varg oil discovery in Jurassic and Triassic sandstones. The main objective of the well was to test the potential for hydrocarbons in sandstones of Oxfordian and Triassic age. Seismic anomalies at 437, 467, 479 and 803 m indicated possibility for shallow gas. Planned TD for the well was 3260 m.</p> <p><b>Operations and results</b></p> <p>Well 15/12-8 was spudded with the semi-submersible installation Deepsea Bergen on 5 June 1991 and drilled to TD at 3054 m in the Triassic Skagerrak Formation. No significant problems occurred during operations. The well was drilled with seawater / hi-vis pills / CMC down to 615 m, with KCl/polymer mud from 615 m to 2855 m, and with Ancotemp/bentonite mud from 2855 m to TD. No shallow gas was encountered.</p> <p>Jurassic Vestland Group sandstone was encountered hydrocarbon-bearing at 2838 m. The hydrocarbon column extended 23 m into Triassic sandstone of the Skagerrak Formation. The gas/water contact was estimated to 2877 m, confirmed by FMT pressure gradients and wire line logs. The well was tested, and since no core was cut through the reservoir, the well was sidetracked at 2623 m with TD at 2940 m. The sidetrack was drilled with Ancotemp/bentonite mud. Three conventional cores were cut in the interval 2841 - 2902 m. The sidetrack was formally named 15/12-8 A.</p> <p>The FMT tool was run in well 15/12-8 and 15/12-8A. One segregated sample was taken at 2863 m in 15/12-8 (gas, condensate and mud filtrate) and another in the water zone at 2888 m in well 15/12-8 A (recovered mud only due to seal failure). </p> <p>Well 15/12-8 was permanently abandoned on 14 July 1991 as a gas/condensate discovery. The 15/12-8 A sidetrack was permanently abandoned on 29 July as a gas/condensate appraisal well.</p> <p><b>Testing</b></p> <p>One DST test was performed in 15/12-8 in the interval 2838 - 2869 m. The well produced gas-condensate with a dew point of 230 bar at the measured reservoir temperature, which was 123 deg C. The rates were 550 000 Sm3 gas and 420 Sm3 condensate /day through a 15.9 mm choke. The condensate/gas ratio was 1308 Sm3/Sm3, the condensate gravity was 61 deg API, and the gas gravity was 0.817 (air = 1).</p> |
1835
|
7/6/2016 12:00:00 AM
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04.11.2024
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15/12-9 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/12-9 S was drilled on the Varg Field in the North Sea. The Varg Field reservoir is in Upper Jurassic sandstones at a depth of approximately 2700 metres. The Varg Field is segmented and includes several isolated compartments with varying reservoir properties. The well was drilled from a location near to the Varg A and Petrojarl A production installations and targeted a southern compartment in the Varg structure. The objective for the well was to prove hydrocarbons in Late Oxfordian sandstone and to reduce the uncertainty in the reserve estimate for this part of the Varg Field.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/12-9 S was spudded with the semi-submersible installation Deepsea Bergen on 17 July 1992 and drilled to TD at 3848 m (3213 m TVD) in the Triassic Skagerrak Formation. The well was drilled deviated from 623 m with a sail angle of ca 56 ° and then vertical again from ca 2400 m TVD through the target reservoir to TD. The well was drilled with seawater down to 620 m, with KCl/polymer mud from 620 mto 3226 m, and with Ancotemp/bentonite mud from 3226 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated top reservoir, the Oxfordian sandstones, at 3385 m (2750 m TVD). The reservoir was oil-bearing down to a well-defined OWC at 3501.5 m (2867.0 m TVD). Seven cores were cut with 100% recovery. Core 1 to 6 were cut in the interval 3689 m to 3555 m and core 7 was cut from 3649.5 m to 3668.0 m. The core to log depth shift was -2.45 m for core 7; for the other cores the core depth was equal to the logger’s depth. Two segregated FMT oil samples were taken at 3498 m. Oil shows continued down to 3545m </span></p> <p class=MsoBodyText><span lang=EN-GB>The well is classified an oil appraisal well. It was suspended on 8 October 1992 and was later re-classified to oil production well 15/12-A-11 on the Varg Field.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two drill stem tests were performed in the Oxfordian sandstones.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1 tested the water zone from 3545 m to 3552 m (2910 – 2917 m). The test produced water at a rate of 890 m3/day through a 48/64” choke. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2 tested the oil zone from 3385 m to 3443 m (2750 – 2809 m). The test produced on average 132200 Sm3 gas and 1520 Sm3 oil /day through a 40/64” choke. The GOR was 87 Sm3/Sm3, the oil density was 0.852 g/cm3 and the gas gravity was 0.751 (air = 1) with 1.5% CO2 and 4% H2S. Maximum flowing temperature was 124.6 °C. </span></p> |
1978
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4/25/2019 12:00:00 AM
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04.11.2024
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15/2-1
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/2-1 was drilled in the Vilje sub-basin in the Viking Graben in the North Sea, ca 1.5 km from the UK border.</span><span lang=EN-GB>The objective of the well 15/2-1 was to test the Upper Jurassic, Middle Jurassic, and Triassic sandstone reservoirs northwest of and down dip of the salt diapir encountered in the well 15/5-3. The well was planned to be drilled ca 200 m into the Triassic with a total depth of ca 4525 m.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/2-1 was spudded with the semi-submersible installation Nortrym on 26 September 1981 and drilled to TD at 4600 m in the Late Permian Zechstein Group. No significant problems were encountered in the operations. The well was drilled with seawater and hi-vis pills down to 665 m and with Shaletrol polymer mud system from 665 m to 2750 m. At 2750 m the mud was converted to a dispersed mud system by adding lignosulphonate and this was used for the remaining well bore down to TD. There was 0 - 3% oil in the mud below 1168 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated a number of sandstone Formations in the Tertiary (Skade, Grid, Intra Balder sandstone, Heimdal, and Ty Formations). All these were entirely water wet. The Hugin Formation (4356 - 4493 m) consisted of massive very fine grained sandstones with beds of coal on top. The Sleipner Formation (4493 - 4554.5 m) had a 10 m thick coal layer on top underlain by siltstones grading occasionally to very fine sandstones, interbeds of sandstones, and stringers of coal. The well did not penetrate any Early Jurassic or Triassic rocks, but encountered evaporites of Permian age at 4554.5 m, unconformably underlying the Sleipner Formation.</span></p> <p class=MsoBodyText><span lang=EN-GB>Good hydrocarbon shows were reported from both the Hugin and Sleipner Formations. However, wire line log evaluation and core analysis showed very poor reservoir parameters and no moveable hydrocarbons. Fluorescence and cut were observed also on limestone and shale cuttings in the Tor Formation at 2800 - 2835 and in the Early Cretaceous at 3815 - 3922 m</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut from 4365 to 4405 m in the Hugin Formation. The RFT tool was run in the Hugin Formation. The formation proved to be tight and no wire line fluid samples were taken. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 24 February 1982 as a dry well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
308
|
7/6/2016 12:00:00 AM
|
04.11.2024
|
|
15/3-1 S
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<htm
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/3-1 S was drilled west of the Gudrun Terrace on the east flank of the North Sea Central Graben. The primary objective was to test sands in the Middle Jurassic (Dogger sands). Secondary objectives were the Early Tertiary, Danian, Early Cretaceous sands. Triassic sandstones and Zechstein dolomites down to the "economic basement" were also possible targets. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well is reference well for the Ty, Draupne, and Heather formations.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/3-1 S was spudded with the semi-submersible installation Deepsea Driller on 27 November 1974 and drilled without significant problems to 4400 m. While circulating before logging the pipe stuck and the hole started to kick. After unsuccessful efforts to free the pipe the well was plugged back and sidetracked from 3985 m. The sidetrack was drilled without further significant problems to final TD at 5129 m in the Middle Jurassic Hugin Formation. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated water-bearing Hermod, Heimdal and Ty formation sandstones from 2215 to 2715 m. The Ty Formation from 2556 m was reported as the best of these with a main body of clean sand from 2599 to 2711 m. Top Viking Group, Draupne Formation was encountered at 3947 m. The Draupne Formation contained many oil and gas bearing Intra-Draupne Formation sandstones. Of these the best reservoirs were found in the intervals 4083 to 4317 m with OWC at 4218 m, and 4442.5 to 4610 m with OWC at 4486 m. Total net pay in these two intervals together were 32 m with 22 - 19 % porosity. Geochemical analyses indicated good source rock properties in the shale interbeds, with a maturity ranging from early to late oil window (vitrinite reflectance from 0.6 to 0.9 %Ro). Top Heather Formation was encountered at 4754 m. The Heather Formation had no sandstone interbeds. Top Hugin Formation came in at 4986 m with a 10 m net pay gas bearing sandstone reservoir at 4986 to 5001 m. Porosity here was 12.5%. Sandstones with hydrocarbons were penetrated below this level, but these had low permeability. No oil shows were reported above the Viking Group.</span></p> <p class=MsoBodyText><span lang=EN-GB>Four cores were cut in the well; the three first before and the fourth after sidetracking. Core 1 was cut from 3947 to 3951 m, core 2 was cut from 4083 to 4092, core 3 was cut from 4141 to 4150 m, and core 4 was cut from 4991 to 4993.3 m. FIT wire line fluid samples were taken at 4217 m (oil and gas), 4148.8 m (oil and gas), 4089.3 m (gas), 4168.5 m (oil and gas), 4243.5 m (water and trace filtrate), 4443.5 m (oil and gas), and at 4479.5 m (water and filtrate)</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 6 July 1975 as a gas/condensate discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
309
|
7/6/2016 12:00:00 AM
|
04.11.2024
|
|
15/3-10
|
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 15/3-10 was drilled as an appraisal well on the 15/3-4 Sigrun discovery on the Gudrun Terrace in the North Sea. The target formation was located to the west and down dip of the original discovery well 15/3-4. The main objective was to prove more resources than already proven in the Middle Jurassic Hugin Formation in the 15/3-4 discovery well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>A 9 7/8” pilot hole (15/3-U-8) was drilled to check for shallow gas. No shallow gas was observed.</span></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/3-10 was spudded with the semi-submersible installation Deepsea Bergen on 5 June 2018. The well was drilled to 990 m but due to failed cement operation of the surface casing, the well was abandoned. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well did not fulfil the objectives.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13 June 2018 as a junk well. Replacement well 15/3-11 was initiated.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
8442
|
6/13/2020 12:00:00 AM
|
04.11.2024
|
|
15/3-11
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 15/3-11 is the replacement well for 15/3-10, which was junked for technical reasons. It was drilled to appraise the 15/3-4 Sigrun discovery on the Gudrun Terrace in the North Sea. The target formation was located to the west and down dip of the original discovery well 15/3-4. The main objective was to prove more resources than already proven in the Middle Jurassic Hugin Formation in the 15/3-4 discovery well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/3-11 was spudded with the semi-submersible installation Deepsea Bergen on 14 June 2018 and drilled to TD at 4014 m in the Middle Jurassic Sleipner Formation. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 1000 m, with KCl/polymer/GEM mud from 1000 m to 2350 m, with Enviromul oil-based mud from 2350 m to 3660 m, and with BaraECD oil-based mud from 3660 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The target Hugin formation was penetrated from 3856 to 3959 m. The reservoir consisted of interbedded sandstones and claystone with a few thin coal layers. It was oil filled in the upper sands, whereas the deeper sands were water-bearing. The fluids are the same volatile oils as were encountered in 15/3-4. Like the previously drilled wells, 15/3-4 and 15/3-5, did the 15/3-11 well encounter oil-down-to (ODT) situations. <a name="OLE_LINK1">Pressure data show a complex reservoir with two different oil gradients</a> and three different water gradients. In the well site cuttings descriptions shows are described in the Draupne Formation from 3744 to 3798 m (direct and cut fluorescence but no visible oil stain). In the core description oil shows are described in the Hugin reservoir sandstones down to 3930 (typically direct and cut fluorescence with visible stain), and with weaker shows in a few samples around a coal layer at 3959 m. No other zones with shows are reported.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut in succession from3868 to 3975 m with 99.3% and 94% recovery, respectively. MDT fluid samples were taken at 3857.7 m (oil), 3888.46 m (oil) and 3927.5 m (water). The oil samples proved undersaturated volatile oil with small variations in GOR.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 9 August 2018 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
8489
|
8/9/2020 12:00:00 AM
|
04.11.2024
|
|
15/3-12 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 15/3-12 A is a geological side-track to well 15/3-12 S, which discovered oil in the Sigrun East Hugin prospect on the Gudrun Terrace in the North Sea. Side-track 15/3-12 A was drilled to the Sigrun East Draupne prospect located west of the primary well and south of the Sigrun Field. The primary objective of 15/3-12 A was to verify down-flank continuation of the Hugin Formation reservoir and find the related hydrocarbon contacts. The secondary objective was to verify presence of Intra-Draupne Formation reservoir and hydrocarbons in same.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/3-12 A was kicked off on 19 January 2020 from the main well at 2100 m in Lower Hordaland Group. It was drilled with the semi-submersible installation West Phoenix to 3593 m (3428 m TVD) in the Cromer Knoll Group. While POOH with 12 ¼” drilling BHA, the drill string got stuck at 2756 m in Ty sand. The BHA could not be freed and a technical side-track 15/3-12 A T2 was initiated with kick-off at 2215 m. Large amounts of caved cuttings was produced during kick-off. Drilling proceeded to final TD at 4038 m (3834 m TVD) in the Middle Jurassic Sleipner Formation. Both 15/3-12 A and 15/3-12 A T2 were drilled using Exploradrill oil-based mud from kick-off to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Hugin reservoir was water filled and only cemented sand stringers were penetrated in the Draupne Formation. No oil shows were described in the well. Combined pressure data from the 15/12-3 S and 15/12-3 A T2 well indicated the following hydrocarbon contacts in the Hugin Formation: Free Water Level at 3614.6 m TVD in the upper reservoir unit, OWC at 3570 m TVD in the middle unit, and Free Water Level at 3605.4 m TVD in the lower unit. The contacts are based on pressure data and oil sample densities and are not penetrated by the wellbores.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. MDT water samples were taken at 3898 m in the Hugin Formation in the 15/3-12 A T2 side-track</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 2 March 2020 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
8948
|
10/20/2022 12:00:00 AM
|
04.11.2024
|
|
15/3-12 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 15/3-12 S was drilled to test the Sigrun East Hugin prospect on the Gudrun Terrace in the North Sea. The primary and secondary exploration targets for wildcat well 15/3-12 S were to prove petroleum in Middle Jurassic Hugin Formation reservoir rocks.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/3-12 S was spudded with the semi-submersible installation West Phoenix on 3 December 2019 and drilled to TD at 3810 m (3691 m TVD) m in the Middle Jurassic Sleipner Formation. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 1010 m, with Glydril mud from 1010 m to 2374 m, and with Exploradrill oil-based mud from 2374 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well encountered three separate oil-filled reservoir zones from 3647 to 3660 m, 3680 to 3683 m, and 3703 to 3733 m in the Hugin Formation. The three zones lie on different pressure gradients. The reservoir zones mainly have moderate reservoir quality. The oil/water contacts were not penetrated in the well. Oil shows in the well were observed only in the Hugin Formation between 3652 to 3729 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut with 100% recovery in the Hugin and Sleipner formations. Core 1 was cut from 3652 to 3706 m and core 2 was cut from 3706 to 3760 m. The core-log depth shifts are 1.9 m for core 1 and 1.7 m for core 2. MDT fluid samples were taken at 3647.5 m (oil), 3681.1 m (oil), 3698 m (water), and 3704.2 m (oil).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 14 January 2020 as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
8947
|
8/9/2022 12:00:00 AM
|
04.11.2024
|
|
15/3-2
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<p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/3-2 was drilled in the Vilje sub-basin structural element of the south Viking Graben of the North Sea. The objectives of well 15/3-2 were all Jurassic sands. The well was planned in two phases. Phase 1 (15/3-2) was to be drilled with the Polyglomar Driller down to top Jurassic. Phase 2 (15/3-2 R) was to be drilled with the Pentagone 84, a rig with a 15.000 psi wellhead equipment, necessary for testing of the high-pressure Jurassic reservoirs.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/3-2 was spudded with the semi-submersible installation Polyglomar Driller on 29 October 1976 and drilled to TD at 4258 m in the Late Jurassic Draupne Formation. When pulling out of the hole to set the 9 5/8" casing the drill string parted at 138 m, but was fished out. Otherwise, no significant technical problem occurred in the operations. The well was drilled with seawater and hi-vis pills down to 186 m, with prehydrated bentonite in fresh water from 186 m to 784 m, with LFC/Dextrid mud from 784 m to 2875 m, and with LFC+LC in seawater from 2875 m to TD. Up to 3% oil was added to the mud from 3953 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Down to 4236 m (Tertiary and Cretaceous sections) no significant shows were observed except in Coniacian and Turonian limestones where some brown-yellow fluorescence was observed. Electric log analysis did not indicate any hydrocarbon-bearing reservoirs in these limestones. </span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line pressure points or fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>A 9 5/8" casing was set at 4248 m and the well was suspended on 24 January 1977 for later re-entry and drilling and testing of the Jurassic targets. The well is classified as dry.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
310
|
7/6/2016 12:00:00 AM
|
04.11.2024
|
|
15/3-2 R
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<p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/3-2 R is a re-entry of well 15/3-2 in the Vilje sub-basin structural element of the south Viking Graben of the North Sea. The primary well 15/3-2 was drilled by "Polyglomar Driller", which was equipped with 10.000 psi WP 18 3/4" BOP-stack. This well was suspended on 24 January 1977 with 9 5/8" casing set at 4248 m, in the Late Jurassic Draupne Formation. The re-entry was drilled with the Pentagone 84, equipped with a 15000 psi WPI 11" BOP stack, necessary to drill and test high-pressure Jurassic reservoirs. The objective of well 15/3-2 R was to test the Jurassic reservoirs, including the Dogger - Lias sections.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/3-2 was re-entered with the semi-submersible installation Pentagone 84 on 26 July 1977 after some initial problem with connecting to the wellhead on the sea floor. An 8 11/32" hole was drilled down to 4990 m when the drill string parted. In spite of an extensive fishing operation, the fish had to be left in hole. Top fish is at 4742 m. A sidetracking operation was performed trying to bypass the fish, but also this operation failed and 4990 became TD of the well. The well was drilled water based with LFC-LC mud from re-entry point to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Draupne Formation extended from 4236 m down to 4352 m, making up a total of 116 m. Geochemical analyses proved TOC from 3 to 7 %wt and vitrinite reflectance analyses indicated middle oil window maturity (%Ro = 0.75). Four Intra Heather Formation sandstone reservoirs were drilled in the Jurassic section, varying in gross thickness from 15 to 112 m. According to logs the two upper ones, 112 and 64 m thick, were hydrocarbon-bearing, but with bad characteristics (porosity destruction by silicification) and no tests were successful. Shows during drilling were recorded throughout the Jurassic: low levels of C1 to C4 gas in mud, and fluorescence (direct and cut) on cuttings and cores. Gas was observed bubbling and seeping from all the cores. Because of the premature stop the Brent to Statfjord (Dogger to Early Jurassic) sedimentary section was not reached. As no electric logs were run below 4742 m the lithostratigraphy is poorly defined in the bottom part of the well. However, it is likely that TD was set in Heather Formation shale, and it is possible that the Dogger section (Brent Group) is very close to the TD (J4 horizon was prognosed at 5000/5100 m).</span></p> <p class=MsoBodyText><span lang=EN-GB>Four cores were cut in the intra Heather Formation Sandstones: cores 1 and 2 from 4404 to 4409 m, core 3 from 4565 to 4574 m, and core 4 from 4656 to 4662 m. 26 RFTs were attempted in the three upper sandstone bodies. All were either dry or they failed. Only two RFTs, at 4401 and 4401.4 m, were stabilized and indicated an equivalent density of 1.73. The well was permanently abandoned on 27 November 1977 as a well with strong shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>A 7" liner was set from 4101 m to 4665 m. Three DST-runs were carried out, all misruns due to mechanical failure of the PCT-tool.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
311
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7/6/2016 12:00:00 AM
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04.11.2024
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15/3-3
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/3-3 was drilled west of the Gudrun Terrace on the east flank of the North Sea Central Graben, about 4.5 km north-east of the 15/3-1 S discovery. The main objective of the 15/3-3 well was to appraise the complete Jurassic series up-dip of well 15/3-1 S drilled on the same structure in 1975. </span></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/3-3 is type well for the Grid Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/3-3 was spudded with the semi-submersible installation Pentagone 84 on 5 January 1979 and drilled to TD at 5115 m in the Triassic Skagerrak Formation.</span></p> <p class=MsoBodyText><span lang=EN-GB>Several water bearing sands with high porosity were encountered in the Tertiary section including the Grid, Heimdal and Ty formations. The Cretaceous had no reservoir sections and was drilled without gas shows. The Late Jurassic Draupne Formation was encountered at 4017 m. The Draupne Formation was 208 m thick and consisted of shales with only a few < 1 m sandstone beds. The Heather Formation was penetrated from 4225 to 4522 m and contained a main Intra Heather Formation sandstone from 4260 to 4369 m. This sandstone was gas and condensate bearing in the upper part down to a GOC at 4272 m. The Hugin Formation came in at 4522 m and then the Sleipner Formation at 4545 m. The Hugin Formation contained gas filled sandstone from 4522 to 4527 m. Several thinner sandstones with gas followed down to a main gas filled sandstone in the Sleipner Formation from 4588 to 4632 m. A second hydrocarbon filled Sleipner Formation sandy interval was penetrated from 4679 to 4693 m. The upper part down to 4687 m consisted of good sandstone, further down it was cemented.</span></p> <p class=MsoBodyText><span lang=EN-GB>The only oil shows in the well was rare pale yellow to greenish crush cut fluorescence on cuttings around 4100 m and on white - yellowish fluorescence on all cores.</span></p> <p class=MsoBodyText><span lang=EN-GB>Six conventional cores were cut in the Jurassic section all with full recovery. The three first were cut in the Heather Formation from 4262 to 4307 m (4264 to 4309.9 m logger's depth). The three last were cut in the Sleipner Formation (cored depth = loggers depth): Core 4 from 4547 to 4562 m; core 5 from 4851 to 4860 m; and core 6 from 4995 to 5004 m. Three RFT fluid samples were taken at 4262 m (gas and condensate), 4262.5 m (mud and traces of condensate), and 4261.5 m (condensate). Four FIT samples were taken at 5059.5 m (water), 4989.5 m (mud filtrate), 4626.5 m (gas and mud), and 4262 m (oil and gas).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 9 August 1979 as a gas/condensate appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two DSTs were performed through perforations in the 7" liner.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1 tested 4967 - 4990 m with packer at 4957 m. It produced 4.3 m3 of salt water (125 g/1) with traces of gas in 11 hours.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2 tested 4615 - 4632 m with packer at 4600 m. It produced 520000 m3 gas, 60 m3 41.5 deg API paraffinic condensate and 2.2 m3 water /day in 24 hours. The GOR was ca 8600 Sm3/Sm3.</span></p> |
313
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4/11/2017 12:00:00 AM
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04.11.2024
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15/3-4
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 15/3-4 was drilled on the Gudrun Terrace, east of the 15/3-1 S Gudrun Discovery in the North Sea. The main objective of the well was to test sandstones of the Late and Middle Jurassic, which were found to contain gas and condensate in wells 15/3-1 S and 15/3-3. The secondary target was the Eocene sands where oil shows were encountered in well 15/5-3. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/3-4 was spudded with the semi-submersible installation Borgsten Dolphin on 3 October 1981and drilled to TD at 4259 m in the Triassic Skagerrak Formation. After the 13 3/8" casing had been cemented drilling was interrupted for 13 days due to a combination of bad weather and repairs on the BOP stack. When running in hole at TD the drill string stuck leaving a fish with top at 4098 m. Hence, no logs were run between 4098 m and TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Eocene sands from 1628 to 2025 m (Grid Formation sands) were found water bearing. The Brent Group was encountered with top Hugin Formation at 3786 m and top Sleipner Formation at 3856 m. Sandstones in the Brent Group contained oil and gas in four different intervals: 3786 to 3817 m, 3819.5 to 3826.5 m, 3849.9 to 3854.8 m, and 3872.2 to 3876.4 m. The four zones were in different pressure regimes. The interval from 3819.5 to 3826.5 m had a low hydrocarbon saturation based on the logs, but the cores from this section had good shows with a similar bulk hydrocarbon composition as in the uppermost interval. Triassic sands below 4050 m were found water bearing. Good oil shows were seen on all cores from the Hugin Formation, otherwise no shows were reported from the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>Five cores were cut in the well. Core 1 was cut in the Grid Formation from 1678 to 1694 m with 27% recovery. Coring of the Grid sands was difficult due to their unconsolidated nature. Cores 2 - 5 were cut in the interval 3792 to 3839 m in the Hugin Formation with recovery from 65% to 100%. RFT fluid samples were taken at 3802.5 m (water, mud and filtrate), 3823.5 m (water, mud and filtrate), and 3850.2 m (gas and water). FIT fluid samples were taken at 3822.5 m (water and dissolved gas), 3852.6 m (oil, gas and water), and 3873.5 m (oil, gas and water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 30 March 1982 as an oil and gas discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One DST was performed through perforations in the interval 3789 to 3807.5 m. The test produced 615 Sm3 oil and 245000 Sm3 Gas/day through a 40/64" choke. The GOR was 400 Sm3/Sm3, the oil density was 0.816 g/cm3, and the gas gravity was 0.803 (air = 1). The gas contained 7.4 % CO2. Bottom hole temperature during the DST, at reference depth 3800 m, was 127.8 deg C. </span></p> |
314
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12/6/2019 12:00:00 AM
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04.11.2024
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15/3-5
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/3-5 was drilled on the Gudrun Terrace, east of the 15/3-1 S Gudrun Discovery in the North Sea. Well 15/3-5 was drilled in a downdip position of a structure explored by the well 15/3-4, where oil bearing reservoirs of Middle Jurassic age were tested. The main objectives of 15/3-5 were to find the extension of these reservoirs and to define a hydrocarbon/water contact. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/3-5 was spudded with the semi-submersible installation Byford Dolphin on 28 December 1983 and drilled to TD at 4130 m in the Middle Jurassic Sleipner Formation. Drilling was suspended at 195 m due to bad weather. The well was re-spudded on 6 January 25 m west of the original location. Some technical problems with the BOP occurred after setting of the 20" and 13 3/8" casings. A seat protector got stuck in the riser during drilling of the 17 1/2" hole. Drilling breaks occurred at 3943 m, 3954 m, 4018 m, 4032 m and at 4041 4043 m in the 8 1/2" hole section. The well was drilled using water based mud.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top Draupne Formation was encountered at 3808 m, followed by the Heather Formation at 3881 m, and the target Middle Jurassic Sleipner Formation at 3935 m. Several thin reservoir zones were penetrated in the Sleipner Formation. The sands were interpreted as minor fluvial channels (2 to 5m in thickness) deposited in two main sequences. Four of the channels were oil-bearing with an oil gradient of 0.61 bar/10 m based on pressure measurements. An OWC could be established at 4022.6 m. Pressure measurements showed that the upper fluvial channel sequence is over-pressured, and not in contact with the sands encountered in well 15/3-4. The lower fluvial sequence could be connected between the two wells. Petrophysical evaluation of the whole system gave a net pay of 6.7 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>In the Quaternary, Tertiary and Cretaceous series no fluorescence due to hydrocarbons were observed. In the Upper Jurassic sequence, a weak yellow colour in direct fluorescence light was observed on sandstone pieces. A pale to clear yellow and orange colour in direct fluorescence light was reported from the Middle Jurassic sequence down to about 4060m. Below 4060 m to TD nil to very weak direct fluorescence was observed. </span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the Sleipner Formation. Cores 1 and 2 were cut from 3971 to 4003 m (3973.6 to 4005.6 m logger's depth) with 98 % and 84% recovery, respectively. Core 3 was cut from 4020 to 4029 m (4023.9 to 4032.9 m logger's depth) with 94% recovery. RFT wire line fluid samples were taken at 3969.9 m (gas + mud filtrate), 3984 m (gas + mud filtrate), 4022.2 m (minor gas + mud filtrate), and 4028.5 m (trace gas + mud filtrate),</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13 May 1984 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
52
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5/19/2016 12:00:00 AM
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04.11.2024
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15/3-6
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<p><b>General</b></p> <p>Well 15/3-6 was drilled to test the Paleocene Balder and Hermod sandstones of the Pinnsvin prospect, and had a licence requirement to penetrate Cretaceous age formations. The well was drilled within licence PL 187 (Amoco Norway, Statoil, Norsk Hydro). License PL 025 farmed into the well (Statoil, Elf, Total, Hydro) for 20% of well costs.</p> <p><b>Operations and results</b></p> <p>Wildcat well 15/3-6 was spudded 15. December 1998 with the semi-submersible installation Mærsk Jutlander, and drilled to TD at 2793 m in the Late Cretaceous Shetland Group. The well was drilled with seawater and hi-vis pills down to 1018 m and oil based mud (Versavert) from 944 m to TD.</p> <p>The Intra Balder and Hermod sandstones were encountered as prognosed but the well was found to be completely water wet all through. A wire line fluid sample was taken at 2160 m in the Intra Balder Formation Sandstone. Two cores were cut in the interval 2140 m to 2176 m in the Balder Formation and Intra Balder Formation sandstones, and one was cut from 2278 m to 2297.7 m in the Hermod Formation Sandstone.</p> <p>The well was plugged and abandoned as a dry hole on 5 January 1999.</p> <p><b>Testing </b></p> <p>No drill stem test was performed</p> |
3250
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7/6/2016 12:00:00 AM
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04.11.2024
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15/3-7
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 15/3-7 was drilled to appraise the Gudrun Discovery in the North Sea, on the east flank of the South Viking Graben and west of the Utsira High. The main objective was to improve the data quality related to formation pressure, fluid properties and other reservoir parameters in the Hugin Formation in the Middle Jurassic. The secondary objectives were to explore possible reservoir sands in the Late Jurassic and the hydrocarbon phase of any proven hydrocarbons.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/3-7 was spudded with the semi-submersible installation West Alpha on 26 April 2001and drilled to TD at 4818 m, 211 meters into the Middle Jurassic Hugin Formation. The 8 1/2" hole was drilled in 21 bit runs, including 4 core runs. The main reason for all the bit runs was junk in hole causing 18 days NPT. The well was drilled with seawater and bentonite down to 945 m, with KCl/polymer/glycol from 945 m to 2740 m, and with oil based mud from 2740 m to TD. No shallow gas was observed.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated several Tertiary sandstone sequences including a 373 m thick Heimdal-Ty sequence. The Draupne Formation was found to be 350 m thick and contained several intra-Draupne sandstone sequences interbedded with claystone and limestone. The claystones became darker and more organic rich with depth. A MDT sample from 4224 m in the upper part of the Draupne Formation proved light oil. The upper part of the Hugin Formation was found water bearing as confirmed by a water sample from the Hugin 1 sandstone at 4610 m. No pressure gradients could be obtained from the Hugin Formation. In the lower part of the Hugin Formation, no sample or pressure data could be obtained. However, sandstones were gas filled based on logs, with a likely GWC at 4787 m. Pressure gradients from the Draupne Formation indicate no communication between the oil- and water-bearing zones. </span></p> <p class=MsoBodyText><span lang=EN-GB>Four conventional cores were cut in the interval 4609 m to 4670 m in the Hugin Formation, with a total of 46.4 m core recovered.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
4055
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2/21/2020 12:00:00 AM
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04.11.2024
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15/3-8
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>The Gudrun structure is situated on the east flank of the South Viking Graben and west of the Utsira High in the North Sea. Well 15/3-8 was drilled on the western flank of the structure, approximately 9 km east of the UK border. New seismic data and results from well 15/3-7 had revealed uncertainties regarding the Late Jurassic reservoir section in the Gudrun structure. The main purpose of well 15/3-8 was to gather the necessary information required to ascertain whether the Intra-Draupne Formation reservoir rocks of the Gudrun Discovery could be developed commercially. This included reservoir pressure data, petrophysical data including taking cores, fluid sampling for fluid characteristics, and production properties by drill stem testing.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/3-8 was spudded with the semi-submersible installation Transocean Leader on 11 April 2006 and drilled to TD at 4592 m in Late Jurassic Intra-Draupne Formation sandstone. No significant technical problems were encountered in the operations and the well was completed within planned time frame. The well was drilled with seawater/bentonite/hi-vis pills down to 1010 m, with Glydril mud from 1010 m to 2765 m, and with Paratherm oil based mud (paraffin base) from 2765 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top Viking Group was encountered at 3932.5 m and consisted of the interbedded lithologies of sandstone, claystone and limestone, with varying thicknesses from laminas to stringers and massive layers. The first 140 m was Draupne Formation claystone. The target reservoir section, Intra Draupne Formation sands, was encountered at 4072.5 m, 38.9 m deeper than expected. Three intra Draupne Formation sandstone units were identified, SST1 from 4072.5 m to 4212.5 m, SST2 from 4212.5 m to 4346 m, and SST3 from 4474.5 m to TD. The sand quality was significantly better than observed in the neighbouring wells. When correlated with neighbouring wells well 15/3-8 showed significant lateral reservoir variations over small distances within the structure. SST1 contained a high-shrinkage volatile oil down to a contact at 4208 m, the SST2 pressure gradient proved a water bearing sandstone, although oil was sampled at 4332.9 m, while SST3 contained a near-critical gas-condensate down to a contact at 4485.4 m. </span></p> <p class=MsoBodyText><span lang=EN-GB>Good shows were seen in the cores from the reservoir section as they were recovered on deck. It was no possible to give a reliable evaluation of the shows on cuttings during drilling due to background fluorescence from the oil based mud. In addition, some of the most marginal shows described from the cored section were hampered by the existence of formation derived kerogens in the mud. Some of the cores were also bleeding HC from very tight zones at surface and seepages from these zones might have contaminated better sandstone sections below. From the general fluorescence picture there seem to be a presence of heavier HC in the tight zones than in the more porous zones. </span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 158 m core was recovered in 7 cores from the interval 4167 to 4505 m in various Intra-Draupne Formation sandstone sections in the Late Jurassic. MDT fluid samples were taken at 4514.5 m (water), 4479.1 m (hydrocarbons), 4332.9 m (hydrocarbons), 4213.5 m (water), 4182.1 m (hydrocarbons), and at 4074 m (hydrocarbons). </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 11 April 2006 as an oil and gas appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two drill stem test was performed in Intra-Draupne Formation sandstones. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 4141 - 4183 m. The well was opened to flow for a total of 28 hours. The main flow duration was 14 hours with an approximate oil rate of 739 m3/day a gas rate of 346600 Sm3 gas/day and a GOR of 469 m3/m3 through a 32/64" choke. This was followed by a 96 hours build up period. Maximum bottom hole temperature recorded in the test was 133 deg C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 4073 - 4087 m. The well was open to flow for a total of 26 hours. The main flow duration was 10 hours with an approximate oil rate of 650m3/day, a gas rate of 342400 Sm3 gas/day and a GOR of 500 m3/m3 through a 28/64" choke. This was followed by a 96 hours build up period. Maximum bottom hole temperature recorded in the test was 130 deg C.</span></p> |
5175
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2/21/2020 12:00:00 AM
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04.11.2024
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15/3-9
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/3-9 was drilled on the Brynhild prospect situated on the east flank of the south Viking Graben, west of the Utsira High. The Brynhild Prospect was interpreted as the eastwards continuation of the Gudrun Field. The main objective of the 15/3-9 well was to prove economical hydrocarbon columns in the Late Jurassic SST1 and the Late Jurassic SST2 of the Draupne Formation. The Hugin Formation was a secondary objective.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/3-9 (Brynhild) was drilled with the semi-submersible installation Transocean Leader. A pilot hole 15/3-U6 was drilled to 918 m. No shallow gas was observed by the ROV at the wellhead or by the MWD while drilling the pilot hole. The main well was spudded 15 m off the pilot-hole location on 19 May 2010 and drilled to the Ty Formation where the pipe got stuc stuck. It was not possible to get it loose. A technical sidetrack, 15/3-9 S T2 was decided. The sidetrack was kicked off from 2350 m and the well was drilled to TD at 4654 m in the Middle Jurassic Sleipner Formation without further significant problems. The well was drilled with Seawater and SW/PAC sweeps down to 1001 m, with Performadril WBM from 1001 m to 2724 m (primary well and sidetrack), and with XP-07 OBM from 2724 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Late Jurassic Draupne Formation was encountered at 3975 m with top Intra Draupne Formation SST1 sandstone at 4112 m. The SST1 was oil bearing down to an oil water contact was at 4132 m TVD. The prognosed SST2 sandstone was encountered at 4226 m and was entirely water filled. The Hugin Formation was encountered at 4475 m and contained both gas and oil, each fluid type with its own down-to contact. The Draupne SST1 had a net to gross ratio of 0.75, while the net to gross ratio in the Hugin Formation was 0.16. Except for the petroleum bearing SST1 and Hugin reservoirs no oil shows were reported from the well. </span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut in sidetrack 15/3-9 T2, Core 1 in the Draupne SST1 (23 m), and Core 2 in the upper part of the Hugin Formation (32.15 m). The cored section in the Draupne SST1 extends from 4124 to 4147 m MD, while the cored section in the Hugin Formation extends from 4482 to 4514.17 m MD. Core 1 and Core 2 are shifted against the log curves with +2.13 m and +2.89 m, respectively. MDT fluid sampling was performed. Oil samples were taken at 4115 m and 4128 m in the Intra Draupne Formation SST1 sandstone. In the Hugin Formation a gas/condensate sample was taken at 4580.7 and an oil samples was taken at 4510 m. MDT water samples were taken at 4182.5 m and at 4528.7 m in the Hugin Formation.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13 August 2010 as an oil and gas discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6354
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4/11/2017 12:00:00 AM
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04.11.2024
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15/5-1
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/5-1 was drilled on the Ve Sub-basin north of the Sleipner Vest Field in the North Sea. The main objective of the well was to test sandstone reservoirs of Middle Jurassic age. In the nearby Sleipner field (in block 15/6 and 15/9) gas had been found previously in reservoirs of the same age. The well was located down flank on the structure at the Kimmerian level. This position was chosen to penetrate reservoirs believed to be wedging both above and below a strong seismic marker ("Red Marker").</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/5-1 was spudded with the semi-submersible installation Treasure Seeker on 26 November 1977 and drilled to TD at 3775 m in Late Triassic sediments belonging to the Hegre Group. This was the first well drilled by Treasure Seeker, which was outfitted in Stavanger. About 25% of total rig time was counted as lost time, mainly due to wait-on-weather or equipment problems caused by rough weather in wintertime. The well was drilled with seawater and gel down to 1225 m, with seawater/gel/CMC/Spersene from 1225 m to 1910 m, and with a freshwater-based Spersene/gel/chrome-lignosulphonate/Drispac mud from 1910 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The 15/5-1 well encountered gas condensate-bearing sandstones of Late and Middle Jurassic age (Callovian and Bathonian) from top at 3558 m down to 3614 m where a Bathonian/Bajocian deltaic series with up to five m thick coal beds appeared. From wireline log evaluation the sandstone section with a gross thickness of 56 m, has been subdivided into four separate pay zones, each zone being separated by thin impermeable layers, resulting in a net sand pay of 42.1 m. Average porosity was calculated to 14% and the average water-saturation to 14%. Sands were water wet below the coal beds at 3650 m. The actual oil-water contact was not seen. The strong seismic “Red Marker was correlated to the top of the deltaic coaly sequence of Middle Jurassic age. Oil shows were recorded on limestone in intervals from 2804 m to 2904 m (Tor Formation), from 3180 m to 3190 m (Hod Formation), and from 3365 m to 3375 m (top of Rødby Formation). Below the hydrocarbon-bearing reservoir, oil shows were recorded on sandstones in the intervals 3650 m to 3657 m and 3725 m to 3740 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut from 3561 m to 3601 m and two cores were cut from 3609 m to 3625.5 m. RFT samples were taken at 3560 m and 3611.8 m. They were found not to be representative of the formation fluid. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7 April 1977 as a condensate discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two zones were production tested </span></p> <p class=MsoBodyText><span lang=EN-GB>DST1 tested the interval 3610 m to 3614 m. The flow did not stabilise. On average, a production of 35720 Sm3 gas and 18.1 Sm3 oil /day through a 12/64” choke is reported. The GOR was ca 1970 Sm3/Sm3, the oil gravity was 43.0 °API and the gas gravity was 0.804 (air = 1). The bottom hole temperature was 125.6 °C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST2 tested the interval 3561 m to 3584 m. The test produced 660270 Sm3 gas and 474 Sm3 oil /day through a 48/64” choke. The GOR was 1390 Sm3/Sm3, the oil gravity was 43.4 °API, and the gas gravity was 0.778 (air = 1). The bottom hole temperature was 126.7 °C.</span></p> |
315
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7/6/2016 12:00:00 AM
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04.11.2024
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15/5-2
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/5-2 was drilled in the Ve Sub-basin in the North Sea, north of the Sleipner Vest Field and 15/5-1 Gina Krog Discovery. The main objective of the well was to test possible hydrocarbon accumulations in Middle to Late Jurassic Bathonian/Callovian transgressive sandstones and Middle Jurassic Bajocian deltaic sandstones. The well was located in a purposely off-crestal position on an approximately 16 km2 large structure some 7 km north-west of the 15/5-1 discovery.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was planned to penetrate into the Triassic with a projected total depth of 4500 m. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/5-2 was spudded with the semi-submersible installation Treasure Seeker on 16 August 1978 and drilled to TD at 4322 m in the Triassic Hegre Group. At 1267 m, the string unscrewed in a tight section, but it was fished without problems. After drilling to 2293 m, the string stuck when pulling out of hole. This time the fish was not recovered and a sidetrack was performed with kick-of at 1775 m. Heavy weather caused further delays, otherwise the drilling went forth without significant problems to TD. The well was drilled with seawater mud mixed with gel and Spersene down to 454 m, and with a Spersene/XP-20 (lignosulphonate) mud from 454 m to TD. At 2232 m 1% Diesel was added to the mud. </span></p> <p class=MsoBodyText><span lang=EN-GB>Two hydrocarbon bearing sandstone intervals were penetrated by the well. In the Jurassic, only a thin Early to Middle Bathonian sandstone development was penetrated between 4035 m and 4055 m. Interbeds of siltstones and shales reduced the 20 m gross pay to a net pay of 7.3 m from wireline log interpretation. Average porosity and average water saturation over the pay interval was calculated to 14.3 and 41.7% respectively. The top of the Triassic sandstones was encountered at 4141.3 m and continued with interbeds of varicoloured shales and siltstones to TD. From wireline log evaluation hydrocarbon bearing sandstones were seen down to 4158.1 m. Below this a tight cemented sandstone appears, masking the exact hydrocarbon - water contact. Proven gross pay interval is thus 16.8 m while the net pay is 12.8 m. Average porosity over this interval has been calculated to 14.6 % and the average water saturation to 43 %.</span></p> <p class=MsoBodyText><span lang=EN-GB>Above top Jurassic weak oil shows were observed on limestones at 2792 and 2828 m in the Tor Formation, between 3488 m and 3517 m in the Lower Hod and Blodøks formations, and between 3707 m and 3723 m in the Rødby Formation. In the Jurassic oil shows were recorded on sandstones from 4008 m to 4055 m. In the Triassic, no oil shows were seen despite the hydrocarbon saturation (gas) in the sandstones shown by the logs.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut in the Middle Jurassic sequence. Core 1 was taken from 4013.6 m to 4020.6 m and recovered 5.1 m (72.8 %). The core was decided to be cut based on sandstone occurrence in the ditch cuttings, but only shale and coal beds were found in the core. Core 2 was cut from 4032.5 m to 4043.0 m and recovered 9.8 m (93.3 %). The core to log depth shift is ca +4.5 m for both cores. RFT fluid samples were attempted at 4148.5 m, 4145 m, 4053 m, and 4157.5 m. Only mud filtrate was retrieved at all depths.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was suspended on 16 December 1978 for future re-entry and testing. It is classified as a gas discovery. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> > |
316
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7/6/2016 12:00:00 AM
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04.11.2024
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15/5-2 R
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/5-2 R is a re-entry of well 15/5-2 in the Ve Sub-basin in the North Sea, north of the Sleipner Vest Field and 15/5-1 Gina Krog Discovery. Well 15/5-2 found gas in Jurassic and Triassic sandstones and was suspended without testing. The objective of the re-entry was to conduct a production test from the Triassic reservoir. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/5-2 was re-entered with the semi-submersible installation Treasure Seeker on 2 November 1979. </span></p> <p class=MsoBodyText><span lang=EN-GB>After testing, the well was plugged and permanently abandoned on 7 December 1979. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two FIT runs at 4150 m were attempted in order to obtain fluid samples. Both runs failed. </span></p> <p class=MsoBodyText><span lang=EN-GB>A production test was run in the Triassic Hegre Group over the perforated intervals 4142 - 4146 and 4148 -4152 m. The test produced 304120 Sm3 gas and 17.6 Sm3 liquid hydrocarbons /day through a 48/64” choke. The gas/condensate ratio was 17260 Sm3/Sm3, the condensate gravity was 49 °API, and the gas gravity was 0.622 (air = 1). The reservoir temperature estimated from the test is 130.6 °C (267 °F).</span></p> |
1250
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7/6/2016 12:00:00 AM
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04.11.2024
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15/5-3
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/5-3 was drilled in the Vilje Sub-basin between the Enoch and the Gudrun fields in the North Sea. The primary objective was to test possible sandstone reservoirs of Triassic age. A secondary objective was to test the Middle Jurassic Sleipner Formation. The well was planned to penetrate approximately 400 m into the Triassic and had a projected total depth of 4200 m.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>After two unsuccessful spuds, wildcat well 15/5-3 was spudded with the semi-submersible installation Nortrym on 21 August 1980 and drilled to TD at 5042 m in shale and sandstones of Late Permian age. Hole reaming was necessary in intervals below 2250 m, otherwise the well was drilled without significant problems or incidents. The hole was good and vertical down to ca 3000 m. Below 3200 m the hole deviation increased to between 3° and 8°. The well was drilled with seawater and hi-vis sweeps down to 615 m, with a seawater/Dextrid mud from 615 m to 2029 m, with seawater/polymer/Q.Broxin mud from 2029 m to 3834 m, and with a salt-saturated Dextrid mud from 3834 to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>None of the objective sandstone reservoirs were found in the well. The Draupne Formation was encountered at 3665 m. After penetrating 135 m of Draupne shales, the well encountered 1050 m of Zechstein evaporites. At this point, it was decided to deepen the well further in order to explore the pre-salt rocks. Below these, undefined shales and thin sandstones of Late Permian age were found. </span></p> <p class=MsoBodyText><span lang=EN-GB>Traces of oil in the mud was observed during P&A - see below. Poor oil shows were recorded in thin limestone stringers at 2850 m, 2920, and in the interval 3355 to 3365 m. No shows were recorded in the pre-Zechstein shales and sand sequence.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut. Core 1 was cut from 3815 to 3834.4 m with 59.9% recovery. Core 2 was cut from 5038 to 5042 at TD with 94% recovery. No fluid samples were taken on wire line. However, while cutting the 9 5/8" casing during P&A, small amounts of oil were found floating on the drilling mud. The oil is assumed to originate from two 2-meter thick sandstone stringers at 1474 m and 1479 m in the top of the Grid Formation. From wire line log interpretation, these show high porosities and high hydrocarbon saturations.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7 December 2015 as a well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
207
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5/19/2016 12:00:00 AM
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04.11.2024
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15/5-4
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/5 4 was drilled on a structure that straddles the border between the U.K. and the Norwegian sector of the North Sea. Hydrocarbons were proven in the structure by three earlier wells drilled in the UK sector (U.K. 16/13a-3, 16/13a-4, and 16/13a-5). Well 16/13a-4 penetrated a gas cap at the top of the structure and an oil column down to base reservoir. The other two wells penetrated an oil zone and a water leg. The objective of well 15/5-4 was to assess the extension of hydrocarbon bearing Sele Formation sand towards the east into PL048. The well position was chosen for possible use as a producer in the event of a positive appraisal. Prognosed total depth was 2300 m. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/5-4 was spudded by the semi submersible installation Vildkat Explorer on 6 June 1991 and drilled to TD at 2300 m in rocks of the Paleocene Heimdal Formation. No shallow gas was observed on the predicted sand/gas levels. Drilling proceeded without any significant problems. The well was drilled with spud mud down to 1027 m and with KCl/polymer mud from 1027 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Thin sands of the Sele Formation were encountered at 2120 m and had good oil shows. The reservoir thickness was calculated to 7.5 m. The sandstones of the Heimdal Formation were penetrated below the oil/water contact and were totally water wet. Weak oil shows was described on sidewall cores from claystone at 1909 m in the Frigg Formation and sandstone at 2182 m in the Lista Formation.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of six cores were cut from 2106 m to 2147 m over the reservoir section. RFT fluid samples were attempted at 2125.1 m, 2125.3 m, 2125.8 m, and 2129.5 m. Sampling suffered from sand plugging and only the samples from run 1C (2129.5 m) contained traces of oil.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 3 July 1991 as a well with oil shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One DST test was performed over the interval 2123.4 to 2135.9 m in the Sele Formation. Water was produced, but not to surface. </span></p> |
1762
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7/6/2016 12:00:00 AM
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04.11.2024
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15/5-5
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<p><b>General</b></p>
<p>Well 15/5-5 is located in the Northern North Sea, ca 15 km north of the Sleipner Field. The primary objective of the well was to prove commercial volumes of oil in a prospect in the Late Paleocene Heimdal Formation. The well location was chosen so as to test the prospect in a position with as little up dip reserves as possible.</p> <p><b>Operations and results</b></p> <p>Wildcat well 15/5-5 was spudded with the semi-submersible installation Treasure Saga on 31 August 1995 and drilled to TD at 2645 m in the Early Paleocene Ekofisk Formation. Boulders were experienced in the interval 155 -170 m MD and some time was spent to correct the inclination. Otherwise operations went without problems and the well was completed well within schedule. The well was drilled with spud mud down to 1000 m and with KCl/polymer mud from 1000 m to TD.</p> <p>The well penetrated water bearing Grid Formation sands from 1479 m to 1807 m. The Heimdal Formation was encountered at 2154 m with 27.4 m of net pay hydrocarbon-bearing reservoir sand down to the OWC at 2187m. The average porosity was calculated to 30.6 % and the average horizontal core permeability was 1.9 Darcy. The OWC was based on formation pressure measurements (MDT) and logs. The average oil saturation over the interval was estimated to 67.4 %. The MDT data indicated a Free Water Level at 2189.2 m. Oil shows and low saturation of migrated hydrocarbons were observed in selected intervals below the OWC down to 2191 m. The Heimdal Formation from top to 2191 was the only interval in the well that had reported oil shows. An 82 m thick water bearing sandstones of the Ty Formation was encountered at 2501 m.</p> <p>The interval 2157 - 2200 m was cored in 3 cores using equipment especially developed for soft sediment coring. The original core depths are 4 m shallow relative to wire line log curves. The cores covered most of the oil zone and extended into the water leg. MDT fluid samples were taken at 2157.5 m (mud filtrate and oil), 2177 m (oil), 2186.5 m (oil), and at 2193.5 m (water).</p> <p>The well was permanently abandoned on 5 October 1995 as an oil discovery.</p> <p><b>Testing</b></p> <p>One production test was conducted in the Heimdal Formation over the perforated interval 2154 - 2183.5 m. The test produced 575 Sm3 oil and 36000 Sm3 gas /day through a 60/64" choke. The GOR was 63 Sm3/Sm3, the oil density was 0.864 g/cm3, and the gas gravity was 0.868 (air = 1). The gas contained maximum 0.3% CO2 and no H2S. Maximum bottom hole temperature in the test was 79.7 deg C.</p> </html> |
2635
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7/6/2016 12:00:00 AM
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04.11.2024
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15/5-6
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<p><b>General</b></p> <p>Well 15/5-6 was drilled on the Glitne field in the North Sea. The main objective was to appraise the 15/5-5 Glitne oil discovery in the Heimdal Formation. The secondary objective was to investigate the oil potential of a separate "Intra Lista Sandstone" which had been mapped as a sequence lapping onto the main Heimdal Formation. </p> <p><b>Operations and results</b></p> <p>Appraisal well 15/5-6 was spudded with the semi-submersible installation Byford Dolphin on 20 June 1997 and drilled to TD at 2725 m in the Paleocene Ekofisk Formation. The drilling went according to plan. However, problems due to poor hole conditions were encountered during wire line logging at TD. The well was drilled with seawater and hi-vis pills down to 1002 m and with KCl/polymer/glycol mud from 1002 m to TD.</p> <p>The top of the main Heimdal reservoir was penetrated 39 m TVD deeper than prognosed. The top corresponded seismically to the reflector that pre-drill was interpreted as the top "Intra Lista Sandstone", so the general consensus is now that the reflector is actually the top Heimdal Formation and that the "Intra Lista Sandstone" sequence is not present.</p> <p>The uppermost part of the Heimdal reservoir was oil bearing, exhibiting good reservoir properties. The OWC was found at 2185 m (2160 m TVD MSL), equivalent to the contact in well 15/5-5. No other parts of well 15/5-6 contained hydrocarbons or shows of hydrocarbons.</p> <p>One core was cut in the upper part of the Heimdal Formation. No fluid sample was taken in the well.</p> <p>The well was permanently abandoned on 16 July 1997 as an oil appraisal.</p> <p><b>Testing</b></p> <p>The well was not production tested due to the limited oil column and no "Intra Lista Sandstone" being present.</p> |
3113
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7/6/2016 12:00:00 AM
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04.11.2024
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15/5-7
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/5-7 was drilled on the Dagny Discovery in the southern Viking Graben area of the North Sea. The primary objective of the well was to prove an oil leg beneath the proven gas in the Dagny structure and establish hydrocarbon contacts. Further objectives were the hydrocarbon characteristics in the Hugin and Sleipner Formations and to test the permeability and productivity of the reservoir. The second objective was to collect a water sample in the Hugin Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/5-7 was spudded with the semi-submersible installation Transocean Winner on 5 July 2008 and drilled to TD at 4037m in the Triassic Skagerrak Formation. No shallow gas was observed by the ROV at the wellhead or by the MWD while drilling the 36" hole or the 17 1/2" hole. Operational problems included repairs of leakage in the BOP in the 17 1/2" section (close to 5 days NPT), directional deviation in the 8 1/2" section and loss of MDT tool in hole at final logging. The lost MDT was pushed to bottom before plugging back. The well was drilled with spud mud down to 1048 m and with KCl/polymer/Glycol (Glydril) mud from 1048 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated rocks of Quaternary, Tertiary, Cretaceous and Jurassic age. The well penetrated the Hugin Formation reservoir at 3821 m (3815.3 m TVD), 59.7 m TVD shallower than prognosed. The well proved oil down to base of the Hugin Formation and it was decided to sidetrack the well for data acquisition in the water zone, including formation water sampling. Based on pressure gradients recorded in 15/5-7 and in the later sidetrack 15/5-7 A, the OWC was estimated at 3923 m TVD RKB. The sandstones of the Hugin Formations had good oil shows, otherwise no oil shows were recorded in the well. </span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut. The first core was cut in Hugin Formation, the second core covered the transition zones between the Hugin and Sleipner Formations and the third core was cut in the Sleipner Formation. MDT pressures were recorded in the oil bearing Hugin Formation and into the Sleipner Formation. MDT oil samples were taken at 3828.8 m, 3830.5 m (sampled during mini DST from 3830 - 3831 m), and at 3883 m (sampled during mini DST from 3882.2 - 3883.2 m). </span></p> <p class=MsoBodyText><span lang=EN-GB>The open hole was plugged back to 3036 m and prepared for sidetracking (15/5-7 A). The bore hole was abandoned on 7 September 2008 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
5842
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4/11/2017 12:00:00 AM
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04.11.2024
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15/5-7 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/5-7 A is a sidetrack from well 15/5-7 on the Dagny Discovery in the southern Viking Graben area of the North Sea. Well 15/5-7 proved an oil-filled Hugin Formation, a 98 m oil column. The primary objective of the sidetrack 15/5-7 A was to obtain data from the water zone, down-flanks on the structure.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/5-7 A was drilled with the semi-submersible installation Transocean Winner. The sidetrack commenced on 8 September at 3145 m and drilled to 4130 m in the Sleipner Formation. The wire line logging tools stuck in the first run at 3515 m and only very incomplete logs were obtained from this bore hole. Fishing failed, the fish was pushed down to 3715 m, and the borehole was plugged back for a second sidetrack. The second, named technically as sidetrack 15/5-7 AT2, was kicked off from 3337 m in well 15/5-7 on 24 September 2008 and drilled to TD at 4199 m in the Middle Jurassic Sleipner Formation. TD logging was obtained. The sidetrack well was drilled with an oil based mud.</span></p> <p class=MsoBodyText><span lang=EN-GB>Based on pressure gradients recorded in 15/5-7 and the sidetrack, the OWC was estimated at 3923 m TVD RKB. No oil shows were recorded in the well. </span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut in the well. MDT pressures were recorded in the water bearing Hugin Formation. MDT water samples were taken at 3998.2 m in the technical sidetrack.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13 October 2008 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
5946
|
4/11/2017 12:00:00 AM
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04.11.2024
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15/6-1
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<p><b>General</b></p>
<p>Well 15/6-1 is located ca 5 km north of the Sleipner Field. The primary objective of the well was Eocene sands.</p> <p><b>Operations and results</b></p> <p>Well 15/6-1 was spudded with the drill vessel Glomar Grand Isle on 7 August 1971and drilled to TD at 1679 m in Eocene sediments of the Hordaland Group. Initial drilling from the sea floor to 384 m was with sea water and gel. Below 384 m to a depth of 1247 m the mud system consisted of sea water and Spersene XP-20 Salinex with drilling detergent. From 1247 m to TD a fresh water Spersene XP-20 system was used. Due to problems with the casing seal assembly the well was abandoned without reaching its target. The vessel vas moved approximately 335 m east and a replacement hole (15/6-2) was drilled.</p> <p>The only reservoir penetrated was a thick Miocene sand section (the Utsira Formation) between 768 and 996 m. No hydrocarbon shows were encountered.</p> <p>No cores were cut and no wire line fluid samples were taken.</p> <p>The well was permanently abandoned on 8 September 1971 as a junk well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
197
|
5/19/2016 12:00:00 AM
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04.11.2024
|
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15/6-10
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/6-10 was drilled on the Gudrun Terrace in the South Viking Graben of the North Sea. The main objectives of the well were to test the hydrocarbon and reservoir potential in the Hugin and Sleipner sandstones of the Freke prospect. The main target was the Hugin Formation, prognosed at 3495 m TVD RKB, and the secondary target was the Sleipner Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-10 was spudded with the semi-submersible installation Bredford Dolphin on 7 February 2009 and drilled to TD at 3700 m in the Late Triassic Skagerrak Formation. The well experienced some deviation difficulties in the 17 1/2" and 12 1/4" sections. The 17 1/2" section started out well but with fairly high torque and stick-slip levels. When entering the Skade Fm the assembly started to build angle. Despite attempts to reduce the building tendency, the angle kept building 0.5- 0.7 degrees per stand drilled. When drilling at 1838 m, the 17 1/2" assembly twisted off in an extension sub just below the bottom stabilizer, approximately 18 m above the bit. The fish was retrieved at first attempt. The 17 1/2" were finished on a motor run to correct the well path. In 12 1/4" section, steering commenced in order to correct the well path back towards the target centre. Initially steering proved to be relatively easy but turned impossible once entering chalk due to very poor toolface control. The well was drilled with spud mud down to 696 m, with KCl/GEM water based mud from 696 m to 2109 m, and with Performadril water based mud from 2109 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated several Tertiary sands (Utsira, Skade, and Heimdal Formations), all water-filled. The primary target Hugin Formation was not encountered although an equivalent age Heather Formation shale prone lithology was encountered at 3497 m. Top Sleipner Formation was encountered at 3510 m and contained gas/condensate down to ca 3567 m (3536 m TVD SS), however the actual hydrocarbon/water contact could not be established from any well data. The Sleipner Formation reservoir sands were silty, with interbedded coals, claystone and thin limestones. Net/gross ratio of the total reservoir was limited to ca 0.3. Oil shows were observed in the Shetland Group (3260-3270 m and 3340-3370 m), in the Vestland Group (3497 - 3584 m) and in the Hegre Group (3620 - 3659 m).</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were taken because massive sands with shows were not identified. No sidewall cores were obtained due to tool failure. MDT hydrocarbon samples were taken at 3545.5 and 3563.8 m and an MDT water sample was taken at 3628 m. Compositional analysis of the hydrocarbon samples showed a condensate with ca 23 % C2+ hydrocarbons.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 6 April 2009 as a gas/condensate discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6030
|
4/11/2017 12:00:00 AM
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04.11.2024
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15/6-11 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/6-11 A was drilled to appraise the 15/5-1 Dagny Discovery in the South-eastern end of the Viking Graben. The north-eastern extension of this structure, the Ermintrude Segment, was tested in 2007 by well 15/6-9 S and side tracks 15/6-9 A&B, which proved oil and gas in a down-to situation in the Hugin Formation, and in communication with the Dagny Discovery. Well 15/6-11-A was drilled on the western part of the Ermintrude structure, on the saddle point between the main Dagny segment and the Ermintrude Segment. The main objective was thus to delimit and test the extension of the hydrocarbon-bearings sands in Hugin Formation of the Dagny Discovery. If hydrocarbons were confirmed a drill stem test would be conducted.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/6-11 A was sidetracked from the primary well 15/6-11 S on 26 December 2010. Kick-off point was 1981 m. The well was drilled with the semi-submersible installation Ocean Vanguard to TD at 4305 m (3853 m TVD) in the Early Jurassic Statfjord Formation. No significant problems were encountered in the operations. The sidetrack well was drilled with XP-07 14A oil based mud from kick-off to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The target reservoir sandstones of the Hugin Formation were encountered at 4121 m (3708.5 m TVD), 12.5 m deeper than prognosis. The Hugin Formation was found to be heterolithic siltstone/sandstone at the top but grading to better sand quality with depth. Good sandstones with high gas values and hydrocarbon shows were encountered 4138 m. Both the core and the logs showed presence of hydrocarbons in the Hugin Formation with OWC at 4167 m (3745 m TVD). There were shows indications also in sands in the Sleipner Formation and in the Statfjord Formation towards TD of the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>A core was cut from 4148 m to 4179 m. The core shift relative to the logs was found to be close to + 2.3 m for the whole core. MDT wire line fluid samples were taken at 4148 m (oil and gas), and at 2597.7 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13 March 2011 as a gas/condensate appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>A drill stem test was conducted from perforations at 4137.8 m to 4158.5 m in the gas/condensate bearing zone of the Hugin Formation. The test produced 120 Sm3 oil and 220000 Sm3 gas /day through a 32/64" choke. The GOR was 1830 Sm3/Sm3. The bottom hole temperature at reference depth was 118 deg C. </span></p> |
6526
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4/11/2017 12:00:00 AM
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04.11.2024
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15/6-11 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/6-11 S was drilled on the Dougal North prospect in the South-eastern end of the Viking Graben. The Dougal North prospect is situated in a down-faulted block south of the Ermintrude West Segment of the Dagny Discovery. It was believed to be a continuation of the Dagny reservoir. The main objective was thus to delimit and test the extension of the Hugin Formation of the Dagny Discovery. If hydrocarbons were confirmed a drill stem test would be conducted.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/6-11 S was spudded with the semi-submersible installation Ocean Vanguard on 27 October 2010 and drilled to TD at 4042 m in the Early Jurassic Statfjord Formation. The BHA was lost at 1758 m but was retrieved. It was decided to run wire line logs at this point, and drilling proceeded without further significant problem after that. The well was drilled with sea water and bentonite sweeps down to 696 m, with Performadrill WBM from 696 m to 2190 m, and with XP-07 14A OBM from 2190 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Hugin Formation reservoir sands were penetrated at 3868.5 m MD (3800 m TVD), which was 16 m deeper than prognosis. The Hugin reservoir was found to be water wet. Only weak oil shows that could be due to the OBM was observed in the Hugin Formation, otherwise no hydrocarbon indications were reported from the well. </span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. MDT water samples were taken at 3916.5 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged back for sidetracking to a second prospect, Ermintrude West. It was abandoned on 19 December 2010 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6488
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4/11/2017 12:00:00 AM
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04.11.2024
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15/6-12
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/6-12 was drilled on the McHenry prospect on the south-western tip of the Gudrun Terrace in the south Viking Graben. The main objective was to test the Hugin Formation. The secondary objectives were to test the Sleipner and</span></p> <p class=MsoBodyText><span lang=EN-GB>Skagerrak formations. The Hugin Formation was also the main reservoir in the Dagny/Ermintrude discovery wells. The deep oil-water-contact observed in the 15/5-7 well on Dagny (3897 m TVD SS) indicated a possible spill from the Dagny/Ermintrude structure towards McHenry.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-12 was spudded with the semi-submersible installation on Transocean Leader on 22 December 2010 and drilled to TD at 3930 m in the Triassic Skagerrak Formation. Shallow gas was interpreted close to the well location and a 9 7/8" pilot hole was drilled from the 30" conductor shoe to 1060 m. No shallow gas was observed. Eighteen meter of drill string was lost in the hole prior to the logging job so loggers TD is 3914 m. Otherwise no significant problem occurred in the operations. The well was drilled with sea water and hi-vis pills down to 1104 m, with Performadrill WBM from 1104 m to 2768 m, and with Low-ECD XP-07 oil based mud from 2768 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Hugin Formation was penetrated at 3798 m. It was only 12 m thick and held a 4 m thick oil filled sandstone. The Hugin sand was prognosed to be between 10 and 100 m thick. The pressure measured in the Hugin Formation indicated no communication with the Dagny/Ermintrude discoveries to the south of 15/6-12. Otherwise there were no hydrocarbon indications apart from a 2.5 m thick limestone stringer with top at 2975 m. This limestone showed a significant resistivity increase and a decrease in density and gave a gas peak of 4.2 %, but no fluorescence was described. The secondary targets, Sleipner Formation and Skagerrak Formation were water bearing. </span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. An oil sample was collected with a MDT tool at 3806.0 m. The sample was estimated to be ca 11% contaminated with OBM.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 9 February 2011 as an oil discovery. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6518
|
4/11/2017 12:00:00 AM
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04.11.2024
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15/6-13
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 15/6-13 was drilled to test the Gina Krog East-3 prospect on the south end of the Gudrun Terrace in the North Sea. The primary objective was to prove commercial hydrocarbons in the Hugin Formation</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-13 was spudded with the semi-submersible installation Songa Trym on 11 April 2015 and drilled to TD at 3577 m in the Late Triassic Skagerrak Formation. No significant problem was encountered in the operations. The well was drilled with Seawater down to 1033.5 m, with Glydril mud from 1033.5 m to 2247 m, and with EMS3300 oil based mud from 2247 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Two separate oil columns, 13 and 3 metres were encountered in sandstone with moderate to good reservoir properties in the Hugin Formation and upper part of the Sleipner Formation. No oil/water contact was encountered. No oil shows were recorded other than in the hydrocarbon-bearing Hugin and Sleipner formations.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two consecutive cores were cut from 3466 to 3495.3 m in the Hugin / Sleipner formations. The recovery was 100%. MDT fluid samples were taken at 3466.7 m (oil), 3471.8 m (oil), 3486.3 m (oil), 3486.3 m (mud), and 3494.0 m (water)</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 15 May 2015 as an oil discovery well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7667
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4/18/2017 12:00:00 AM
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04.11.2024
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15/6-13 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 15/6-13 A is a geological sidetrack to well 15/6-13 on the south end of the Gudrun Terrace in the North Sea. It was drilled to delineate the Gina Krog East-3 oil discovery made by the main well. The objective was to test the down-flank potential of the Gina Krog east-3 structure.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/6-13 A was kicked off at 2141 m in the main wellbore on 16 May 2015. It was drilled with the semi-submersible installation Songa Trym to TD at 3925 m (3741 m TVD) in the Late Triassic Skagerrak Formation. No significant problem was encountered in the operations. The well was drilled with EMS4400 oil based mud from kick-off to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/6-13 A encountered seven and nine metres of sandstone with moderate reservoir quality in the Hugin and Sleipner formations. Both were water bearing. They were not in pressure communication with each other, but the Hugin Formation sandstone is presumed to be in pressure communication with the oil zone in 15/6-13. Petrophysical interpretation indicated hydrocarbons in the Skagerrak Formation, but no pressure data were acquired to confirm this. No oil shows were recorded in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. MDT water samples were taken at 3812 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 30 May 2015 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7668
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4/26/2017 12:00:00 AM
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04.11.2024
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15/6-13 B
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 15/6-13 B is a geological sidetrack to well 15/6-13 on the south end of the Gudrun Terrace in the North Sea. It was drilled to delineate the Gina Krog East-3 oil discovery made by the main well. The objective was to test the presence of a gas cap up-flank on the Gina Krog east-3 structure.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/6-13 B was kicked off at 2031 m in the main wellbore on 3 June 2015. It was drilled with the semi-submersible installation Songa Trym to TD at 3773 m (3472 m TVD) m in the Late Triassic Skagerrak Formation. No significant problem was encountered in the operations. The well was drilled with EMS4400 oil based mud from kick-off to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The main target (Hugin Formation) was not present. The Sleipner and Skagerrak formations proved to be hydrocarbon bearing (gas) with a GOC at 3710 m (3416 m TVD). No oil water contact was seen. No oil shows are were recorded in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut in the well. MDT fluid samples were taken at 3665 m (gas), 3695.3 m (gas), and 3724.6 m (oil).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29 June 2015 as a gas and oil discovery well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7718
|
4/26/2017 12:00:00 AM
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04.11.2024
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15/6-14 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 15/6-14 S was drilled on the Gina Krog in the Ve Sub-basin in the North Sea. The objective was to prove commercial hydrocarbon volumes in the Hugin Formation in the unproven Gina Krog Central 3 Segment, contributing to the Gina Krog Field production.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-14 S was kicked off from main bore 15/6-B-2 below the 13 5/8" casing shoe at 3334 m on 20 December 2017. It was drilled with the jack-up installation Maersk Integrator. It was drilled to TD at 4684 m (3916.3 m TVD) in the Middle Jurassic Sleipner Formation. Operations proceeded without significant problems. The well was drilled with Innovert oil-based mud from kick-off to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Twenty-nine meters of Hugin Formation sandstone was penetrated from 4628 m (3861 m TVD) to 4657 m (3890 m TVD). The formation did not contain mobile hydrocarbons based on log interpretation. There were no oil shows above the OBM in the well, and gas levels in the Hugin Formation were low. </span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. No logs were run on wire line and no fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 26 December 2017 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
8293
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1/28/2020 12:00:00 AM
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04.11.2024
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15/6-15
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<p class=MsoBodyText><span lang=EN-GB>Well 15/6-15 was drilled to test the Freke-Garm prospect on the Gudrun Terrace in the North Sea. The primary objective was to test the hydrocarbon potential in the Middle Jurassic Hugin and Sleipner formations. The secondary objective was to test the Triassic Skagerrak Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>An 8 ½” pilot hole 15-6/U-5 was drilled 1390 m MD. The pilot was drilled in parallel with the main bore. No shallow gas was observed. </span></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-15 was spudded with the semi-submersible installation Deepsea Stavanger on 18 May 2019 and drilled to TD at 3795 m in the Triassic Skagerrak Formation. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 1377 m, with KCl-polymer mud from 1377 m to 3033 m and with Innovert oil-based mud from 3033 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/6-15 encountered the Sleipner Formation with a thickness of about 124 meters, of which 45 meters were reservoir sands of good to moderate reservoir quality. The Skagerrak Formation was encountered with a thickness of about 150 meters, of which 16 meters were reservoir sands with poor reservoir quality. The well is dry without shows</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 2 June 2019 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
8746
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5/1/2021 12:00:00 AM
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04.11.2024
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15/6-16 S
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<p class=MsoBodyText><span lang=EN-GB>Well 15/6-16 S was drilled to test the Hornet prospect in the Ve sub-basin about 10 kilometres north of the Gina Krog field in the central part of the North Sea. The primary objective was to prove petroleum in reservoir rocks from the Middle Jurassic Hugin and Sleipner formations. The secondary objective was to prove petroleum in reservoir rocks from the Late Triassic Skagerrak Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>An 8 ½” pilot hole 15/6-U-4 was drilled down to 1130 m to acquire good quality LWD log data in the shallowest section</span></p> <p class=MsoBodyText><span lang=EN-GB>and to verify no shallow gas present at the drilling location. The pilot hole was drilled in parallel with the 36’’ hole of the main bore. No shallow gas was seen.</span></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-16 S was spudded with the semi-submersible installation Deepsea Stavanger on 14 May 2019 and drilled to TD at 4203 m (4192 m TVD) m in the Late Triassic Skagerrak Formation. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 1128 m, with water-based mud from 1128 to 3705 m, and with oil-based mud from 3705 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Hugin Formation was absent in the well. The Sleipner Formation was penetrated at 4020 m, and the Skagerrak Formation at 4130 m. The Sleipner Formation consists of interlayered sandstones, siltstones and coals of which a total of 23 metres was sandstone of moderate to poor reservoir quality. The Skagerrak formation came in with a thickness of 73 metres, with sandstone layers totalling 17 metres with poor to moderate reservoir quality. There were no shows above OBM in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. RDT fluid samples were taken at 4131.3 m (water and filtrate) and 4054.3 m (water and filtrate)</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 28 June 2019 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
8747
|
5/1/2021 12:00:00 AM
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04.11.2024
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15/6-2
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/6-2 was drilled in the Ve Sub-basin in the North Sea, ca 5 km north of the Sleipner Field. It is the replacement well for 15/6-1, which was junked for technical reasons. The objective was to evaluate a deep-seated structure in the Scottish-Norwegian Graben. The target was Eocene to Paleocene sandstones.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-2 was spudded with the drill vessel on 9 September 1971 and drilled to TD at 3131 m in the Shetland Group. No drilling problems were encountered, however, due to deviation problems around 1311 m a planned FIT was aborted, as the tool would not go beyond this depth. Initial drilling from the sea floor to 1330 m was with seawater and gel. Below 1330 m, a fresh water Spersene XP-20 mud system was used. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Paleocene section contained abundant potential sandstone reservoirs (Heimdal Formation) with thin beds of clay becoming marly below 2390. Significant shows were encountered in the interval 2223 to 2236 m in the upper Heimdal Formation. The cuttings, sidewall and conventional cores corroborated the shows. Weak shows were recorded also on numerous sidewall cores between 2303 and 2604 m. However, other evidence did not substantiate these shows and the reservoir was assumed water wet below 2236 m. The Danian (2676 to 2735 m, Våle Formation) consisted of a sequence of thinly interbedded sandstones, clays, shales and chalky limestones. No shows were reported in this section. The Late Cretaceous section, from 2735 m to 3106 m, was predominantly limestone with thin interbeds of shale. Thin interbeds of sandstone were also noted. There were no shows in the Late Cretaceous.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut. Core 1 was cut from 2236 to 2242 m with 100% recovery, core 2 was cut from 2336.6 to 2343.9 m with 42% recovery, and core 3 was cut from 2695.3 to 2699.3 m with 46% recovery. No fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was suspended on 26 October 1971 as a well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
317
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7/6/2016 12:00:00 AM
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04.11.2024
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15/6-2 R
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/6-2 R is a re-entry of well 15/6-2 in the Ve Sub-basin in the North Sea, ca 5 km north of the Sleipner Field. The initial well 16/6-2 was drilled to 3131 m in the Shetland Group with the drill vessel Glomar Grand Isle. The well found good shows in Paleocene sandstones and was suspended in October 1971. The primary objective of the re-entry was to deepen the well and test the Dogger (Middle Jurassic) deltaic sands. A secondary objective was to test the Lias section (Early Jurassic).</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-2 re-entered on 9 May 1974. It was drilled with the semi-submersible installation Drillmaster to TD at 4779 m in the Late Permian Zechstein Group. The pipe stuck temporarily three times in intervals below 4602 m. Due to hole problems and tight spots no logs were run below 4611 m The well was drilled with a seawater /lignosulphonate mud from re-entry point to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The only hydrocarbon reservoir penetrated was the Dogger gas-condensate sands from 3582 to 3641 m. The lower part of Dogger section and all of the Lias section were cut out of this test by an erosional unconformity and/or faulting. The missing interval has good potential for additional reservoir quality sands. In addition, the Late Triassic has good sand development that could be adequate for reservoiring hydrocarbons. During the drilling of the Triassic and Permian section (3688 to TD), the background gas in mud and cuttings was near zero, which probably is related to lack of source material for hydrocarbons.</span></p> <p class=MsoBodyText><span lang=EN-GB>No shows were recorded except in Dogger.</span></p> <p class=MsoBodyText><span lang=EN-GB>Five cores were cut with 100% recovery in the interval 3582.3 to 3641.1 m. A total of eight FIT fluid samples were taken: P8 (3600.6 m, mud filtrate and poor gas), P7 (3606.4 m, gas and 2 litres condensate), P6 (3610.4 m, gas), P1 (3615.5 m, mud and gas), P3 (3616.5 m, gas and water), P5 (3623.5 m, gas and mud filtrate), P4 (3634.4 m, gas and 2 litres condensate), and P2 (3675.3 m, water, mud and filtrate).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1 August 1974. It is classified as an appraisal well for the 15/5-1 Gina Krog Discovery</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
517
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7/2/2020 12:00:00 AM
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04.11.2024
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15/6-3
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/6-3 was drilled in the Ve Sub-basin in the south Viking Graben in the North Sea. The primary objective was to test the Dogger Sands (Middle Jurassic), which were gas bearing in 15/6-2 R, at a structurally higher position on a large north south trending anticline.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-3 was spudded with the semi-submersible installation Drillmaster on 5 September 1974 and drilled to TD at 3795 m in Late Triassic sediments of the Skagerrak Formation. A lignosulphonate seawater mud was used to drill the well. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Dogger sand from top at 3488 m to 3579 m was hydrocarbon bearing. The resistivity log indicate gas down to a massive coal layer at ca 3562 m. The true gas/water contact was not established. There was 63 m of net gas bearing sand with average porosity 21% and average water saturation 21.%. The Triassic was not a viable reservoir. The only major shows in the well were in the Dogger reservoir sands.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 125.8 m core was recovered (90.7 % overall recovery) in ten cores in the interval 3512.2 to 3650.9 m. FIT fluid samples were taken at 3505 m (gas, water, mud and trace oil), 3553 m (gas, water, mud and trace oil), 3557 m (gas, mud filtrate and mud), and 3575 m (mud filtrate and mud).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 19 December 1974 m as a gas/condensate discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two production tests were run.</span></p> <p class=MsoBodyText><span lang=EN-GB>The first was between 3601.2 and 3604.3 m, this failed to flow. </span></p> <p class=MsoBodyText><span lang=EN-GB>The second was between 3514.3 and 3520.4 m. This test flowed 974300 Sm3 gas with 165 Sm3 condensate /day through a 1.5" choke. The GOR was 5910 Sm3/Sm3 and the condensate gravity was 41.5° API. </span></p> |
318
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7/6/2016 12:00:00 AM
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04.11.2024
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15/6-4
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/6-4 was drilled on the southern end of the Gudrun Terrace in the North Sea. The objective was to test the hydrocarbon potential of Middle Jurassic (Dogger) sandstones.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-4 was spudded with the semi-submersible installation Norjarl on 28 June 1976 and drilled to TD at 3505 m in the Triassic Smith Bank Formation. The well was drilled water based with lignosulphonate/CMC/lignite below 3097 m</span></p> <p class=MsoBodyText><span lang=EN-GB>Top Draupne Formation was encountered at 3157 m. The target sandstone unit was encountered at 3222 m and was found to be water bearing.</span></p> <p class=MsoBodyText><span lang=EN-GB>Four cores were cut. Cores 1 and 2 were cut from 3226.3 m to 3247.6 m and cores 3 and 4 were cut from 3271.5 m to 3308 m. FIT fluid samples were taken on wire line at 3312 m (small amounts of gas and 10.2 l water) and at 3222.5 m (small amounts of gas and 10.2 l water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 16 August as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
319
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7/6/2016 12:00:00 AM
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04.11.2024
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15/6-5
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/6-5 was drilled in the north-eastern part of the Sleipner Field (Sleipner West). The objective was to confirm structural and stratigraphic interpretations as well as define the hydrocarbon content and contacts and the reservoir properties in this part of the Field.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well is reference well for the Hugin Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/6-5 was spudded with the semi-submersible installation Drillmaster on 10 October 1977 and drilled to TD at 3824 m in Triassic sediments. No significant problems were encountered during the drilling of the well. Initial drilling from the sea floor to 166.5 m was with fresh water and lignosulphonate. Below this depth and down to 1197.5 m a seawater gel with carboxymethyl-cellulose (CMC) mud system was used. Below 1197.5 m the above mud with lignosulphonate was used.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Hugin Formation (Upper Dogger Sandstone) was encountered at 3627 meters. This was six meters below the lowest gas seen in the main Sleipner reservoir to that date, 3597 m MSL in 15/9-1. The Hugin Formation is 53 meters thick in the well and essentially 100% sandstone. Electric log analysis and RFT pressure data show the section to be water bearing, although the presence of residual hydrocarbons down to 3655 m was indicated by bleeding gas and excellent liquid hydrocarbon shows in the cores. No hydrocarbon indications were present below 3655 m. The Sleipner Formation (Lower Dogger) came in at 3580 m with several massive coals beds. The well established that the potential lower limit of hydrocarbons in the main Sleipner reservoir was 3627 m (3603 m MSL). </span></p> <p class=MsoBodyText><span lang=EN-GB>Four conventional cores were cut from 3629 m to 3683 m in the Middle Jurassic sandstones (Dogger). Five FIT wire line fluid samples were taken between 3632.6 m and 3655.5 m. They all contained mud filtrate.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29 November 1977 as a dry well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
320
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7/6/2016 12:00:00 AM
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04.11.2024
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15/6-6
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<p><b>General</b></p>
<p>Well 15/6-6 was drilled to appraise the north eastern flank of Alpha structure on the 15/6-3 Sleipner Vest Discovery in the North Sea. The primary target was a gas bearing Jurassic sandstone known as the Hugin Formation. It was drilled to provide needed structural control and to establish a gas/water contact. </p> <p><b>Operations and results</b></p> <p>Appraisal well 15/6-6 was spudded with the semi-submersible installation Glomar Biscay II on 1 April 1982 and drilled to TD at 3760 m in Late Triassic sediments of the Skagerrak Formation. The 36" hole had to be reamed several times due to ledging. This also occurred in the top of the 26" section. Forty-six bbl's (7.3 m3) of fluid were lost to the formation during cementing of the 13 3/8" casing. The mud weight in this section was 1.68 which is lower than the previous Sleipner wells. This and the fluid loss can possibly be related to an unconsolidated sand (Skade Formation) interval from 1185 to 1199 m. Minor hole problems were encountered in the 12 1/4" section. The drill string was temporarily stuck at 1627 m after making a connection. The well was drilled with seawater and gel.</p> <p>The well proved sands in the Utsira, Grid, Heimdal, and Sleipner Formations; all water bearing. The gas bearing Hugin Formation was encountered at 3563 m and had a gross thickness of 58 m. The gas/water contact was found at 3607 m, which gives a gross gas interval of 44 m. No oil shows were reported from the target reservoir or other sections in the well.</p> <p>Three cores were taken in the Middle Jurassic interval in the 8 1/2" section. Core 1 recovered 18.5 m sandstone from 3591 m to 3609.5 m. Core 2 recovered 16.0 m sandstone from 3609.5 m to 3622 m. Core 3 recovered 18.9 m Sandstone, shale and coal from 3625.5 m to 3644.5 m. No wire line fluid sample was taken. </p> <p>The well was permanently abandoned on 9 June 1982 as a gas appraisal well.</p> <p><b>Testing</b></p> <p>The well was tested in the interval 3568 - 3578 m in the Hugin Formation where reservoir data indicated significant accumulations of gas and condensate. The test produced 835000 Sm3 gas and 278 Sm3 condensate /day through a 56/64" choke. The GOR (gas/condensate ratio) was 3003 Sm3/Sm3 and the condensate gravity was 47 dg API. The gas gravity was 0.762 (air = 1), the CO2 content was 5 % and the H2S content was 7.5 ppm.</p> |
38
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5/19/2016 12:00:00 AM
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04.11.2024
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15/6-7
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<p><b>General</b></p>
<p>Well 15/6-7 was the first well in licence 166. The primary objective of the well was to test the hydrocarbon potential of the Middle Jurassic, Hugin Formation of Callovian age within a seismically defined structural trap. There were no secondary objectives for the well, however, other potential reservoir horizons, albeit outside closure, were anticipated within the early Tertiary succession. The well programme was designed to maximize the evaluation of these sections as</p> <p>required. </p> <p><b>Operations and results</b></p> <p>Exploration well 15/6-7 was spudded on 24 April 1993 with the semi-submersible installation "Vildkat Explorer" and drilled to TD at 3540 m in the Triassic Smith Bank Formation. The well was drilled with gel and seawater down to 505 m, with PHPA/KCl mud from 505 m to 1173 m, with PHPA/KCl/Glycol mud from 1173 m to 2788 m, and with PHPA/KCl mud from 2788 m to TD. </p> <p>The Quaternary and Tertiary sequence represented by the Nordland, Hordaland and Rogaland Group is dominated by mudstone lithologies with occasional thick sandstone developments in the Utsira, Grid, and Heimdal Formations. Background gas values ranged from less than 0.1% to 0.5% with rare isolated gas peaks. The Late Cretaceous succession in the well, 493 m thick, is dominated by carbonate lithologies of the Shetland Group; below 3150 m these become increasingly and atypically sandy. A number of gas peaks were recorded over the interval 3025 m to 3157 m with a maximum gas peak of 5.42% recorded at 3154 m. The Early Cretaceous, 14.5 m thick, represented by the Cromer Knoll Group is substantially thinner than anticipated and consists of arenaceous limestones interbedded with thin calcareous sandstones. The Upper Jurassic Draupne Formation was penetrated at 3233 m, 36 m low to prognosis. Intra Draupne Formation Sandstone was encountered at 3292 m. A formation fluid influx of 3.9 m3 equivalent to a calculated pore pressure of 1.5 sg (RFT) occurred at 3327 m (3331 m loggers depth), a gas peak of 0.74% was associated with this influx. The mud weight was increased from 1.30 sg to 1.52 sg during well control operations. The top Heather Formation was penetrated at 3352.5 m, 75.5 m deeper than anticipated. Background gas values within the Draupne and Heather Formations gradually decreased with depth from 4% to 0.18% at the base of the Heather Formation. The primary objective, the Hugin Formation, was penetrated at 3390.5 m, 4.5 m shallower than anticipated. The Hugin Formation consists of interbedded mudstones and sandstones with the sandstone beds increasing in thickness with depth. The well failed to penetrate any hydrocarbon bearing horizons. The primary objective Hugin Formation was water bearing. This was confirmed by RFT and petrophysical evaluation of the logs. </p> <p>One conventional core was cut over the interval 3414 m to 3432 m (15.7 m recovered) in the Triassic Skagerrak Formation. Three RFT runs, 3/1,3/2 and 3/3, were performed in the 8.5" hole section in the Draupne, Hugin and Skagerrak Formations, over the interval 3433-3331 m. A segregated sample was taken on run 3/3. The sample recovered 5 l of muddy water in the 6-gallon chamber. The 1-gallon chamber was plugged. </p> <p>The well was permanently plugged and abandoned as a dry hole on 8 June 1993.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
2084
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7/6/2016 12:00:00 AM
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04.11.2024
|
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15/6-8 A
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<p><b>General</b></p> <p>Block 15/6 is situated on the eastern flank of the southern part of the South Viking Graben, lying in a transition zone on a system of faulted terraces between the main Viking Graben to the west and the Utsira High to the east. The primary objective of the 15/6-8 S well was to test the hydrocarbon potential of the Middle Jurassic Hugin Formation within a seismically defined structural trap. A secondary objective was the Heimdal Formation sandstone ("C-Prospect") which was prognosed to be penetrated in a down dip flank location, but within structural spill. </p> <p>The sidetrack 15/6-8 A was designed to test the "C-prospect" in a more optimal crestal location, some 1000 m to the west of the well position. </p> <p>Other potential reservoir horizons existed in the Early Tertiary Skade and Grid Formations. These were not within mapped structural closure in any of the well trajectories. The well programmes were designed to maximise the evaluation of these sections.</p> <p><b>Operations and results</b></p> <p>Exploration well 15/6-8S was spudded with the semi-submersible installation "Byford Dolphin" on 18 February 1997 and drilled as a vertical hole to a depth of 1538 m, before kicking off in a NNW direction towards the Middle Jurassic primary objective. The final TD was reached at 3225 m MD (3122.5 m TVD SS) in the Triassic Skagerrak Formation. The well was drilled with Seawater and bentonite down to 512 m, with KCl / polymer mud from 512 to 1650 m, and with KCl / polymer / glycol from 1650 m to TD.</p> <p>The Quaternary and Tertiary sequence of 2550 m thickness (2493 m True Vertical Thickness, TVT) was represented by the Nordland, Hordaland and Rogaland Groups. Mudstone lithologies dominated, but significant thick sandstone development was present in the Utsira, Skade, Grid, and Heimdal Formations. </p> <p>The Shetland Group comprised the Early Palaeocene Ekofisk and the Late Cretaceous, Tor, Hod, Blod°ks and Svarte Formations. This 408 m sequence (389 m TVT) was dominated by carbonate lithologies. There were no intervals of reservoir potential. The Early Cretaceous was primarily recognised from well site micropalaeontological analysis of ditch cuttings as a very thin but condensed lithological sequence (4.5 m). It is interpreted as the Åsgard Formation. The Draupne Formation was penetrated at 3089.5 m (2988.6 m TVD SS), and the Heather Formation at 3117.5 m (3016.2 m TVD SS). The primary objective Hugin Formation was penetrated at 3164.5 m, (3062.6 m TVD SS). It consisted of 9 m of sandstone with some minor claystone intercalations, passing into the Triassic Skagerrak Formation at 3173.5 m (3071.4 m TVD SS). Sandstone lithology continued to 3191 m, below which claystone with thin sandstone interbeds became the dominant lithology. </p> <p>No hydrocarbon shows were recorded or noted within any of the potential reservoir sections in the well. FMT and petrophysical evaluation confirmed all zones to be water bearing with a complete absence of hydrocarbons. </p> <p>A total of four log runs, were successfully completed at well TD, the first 2 on wire line, the second 2 were pipe conveyed. A 5th run (walk away VSP) was abandoned after 2 1/2 x 6 km lines due to loss of air pressure at the offset source. On rigging up the wire line logging tools the logging contractor Western Atlas was unable to detect marks on the cable and unable to determine the fault. The cable was changed out, but the second cable was again found to be faulty. As a result of the problems, depth matching between log runs had an error factor of at least +/-2m. The first log in the hole, DLL/MLL/DAC/GR/CHT run 1/1, was therefore used as the reference log giving a consistent error for all further runs. Depth mismatching was further exacerbated by the need to run wire line pipe conveyed, and open hole sticking with accelerometer correction required in certain instances. No fluid sample was taken in the well. One core was cut in the Hugin and Skagerrak Formations in the interval 3172 m to 3181.5 m (8.85m recovered). </p> <p>Well 15/6-8 S was permanently plugged back to the 9 5/8" casing shoe and abandoned as a dry well on 5 April 1997. Well 15/6-8 A was kicked off from below the 9 5/8" casing at 1525 m and drilled to TD at 2480 m (2397 m TVD SS) in the Heimdal Formation, below the mapped structural spill point. The sidetrack was drilled with KCl / Polymer / Glycol mud from kick-off to TD.</p> <p>The Quaternary and Tertiary sequence of at least 2353 m thickness (2295 m TVT) was represented by the Nordland, Hordaland and Rogaland Groups. Mudstone lithologies dominated, but significant thick sandstone development was present in the Utsira, Skade, Grid and Heimdal Formations. No hydrocarbon shows were recorded within any of the potential reservoir horizons. The logging operations suffered similar problems as in the primary well bore leading to similar uncertainty in depth correlation of the logs. No fluid samples were taken. One conventional core was cut over the interval 2438 m to 2449 m (10.2m recovered) in the Heimdal Formation. </p> <p>Well 15/6-8 A was permanently abandoned as a dry well on 18 April 1997.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
3077
|
7/6/2016 12:00:00 AM
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04.11.2024
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15/6-8 S
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<p><b>General</b></p> <p>Block 15/6 is situated on the eastern flank of the southern part of the South Viking Graben, lying in a transition zone on a system of faulted terraces between the main Viking Graben to the west and the Utsira High to the east. The primary objective of the 15/6-8 S well was to test the hydrocarbon potential of the Middle Jurassic Hugin Formation within a seismically defined structural trap. A secondary objective was the Heimdal Formation sandstone ("C-Prospect") which was prognosed to be penetrated in a down dip flank location, but within structural spill. </p> <p>The sidetrack 15/6-8 A was designed to test the "C-prospect" in a more optimal crestal location, some 1000 m to the west of the well position. </p> <p>Other potential reservoir horizons existed in the Early Tertiary Skade and Grid Formations. These were not within mapped structural closure in any of the well trajectories. The well programmes were designed to maximise the evaluation of these sections.</p> <p><b>Operations and results</b></p> <p>Exploration well 15/6-8S was spudded with the semi-submersible installation "Byford Dolphin" on 18 February 1997 and drilled as a vertical hole to a depth of 1538 m, before kicking off in a NNW direction towards the Middle Jurassic primary objective. The final TD was reached at 3225 m MD (3122.5 m TVD SS) in the Triassic Skagerrak Formation. The well was drilled with Seawater and bentonite down to 512 m, with KCl / polymer mud from 512 to 1650 m, and with KCl / polymer / glycol from 1650 m to TD.</p> <p>The Quaternary and Tertiary sequence of 2550 m thickness (2493 m True Vertical Thickness, TVT) was represented by the Nordland, Hordaland and Rogaland Groups. Mudstone lithologies dominated, but significant thick sandstone development was present in the Utsira, Skade, Grid, and Heimdal Formations. </p> <p>The Shetland Group comprised the Early Palaeocene Ekofisk and the Late Cretaceous, Tor, Hod, Blod°ks and Svarte Formations. This 408 m sequence (389 m TVT) was dominated by carbonate lithologies. There were no intervals of reservoir potential. The Early Cretaceous was primarily recognised from well site micropalaeontological analysis of ditch cuttings as a very thin but condensed lithological sequence (4.5 m). It is interpreted as the Åsgard Formation. The Draupne Formation was penetrated at 3089.5 m (2988.6 m TVD SS), and the Heather Formation at 3117.5 m (3016.2 m TVD SS). The primary objective Hugin Formation was penetrated at 3164.5 m, (3062.6 m TVD SS). It consisted of 9 m of sandstone with some minor claystone intercalations, passing into the Triassic Skagerrak Formation at 3173.5 m (3071.4 m TVD SS). Sandstone lithology continued to 3191 m, below which claystone with thin sandstone interbeds became the dominant lithology. </p> <p>No hydrocarbon shows were recorded or noted within any of the potential reservoir sections in the well. FMT and petrophysical evaluation confirmed all zones to be water bearing with a complete absence of hydrocarbons. </p> <p>A total of four log runs, were successfully completed at well TD, the first 2 on wire line, the second 2 were pipe conveyed. A 5th run (walk away VSP) was abandoned after 2 1/2 x 6 km lines due to loss of air pressure at the offset source. On rigging up the wire line logging tools the logging contractor Western Atlas was unable to detect marks on the cable and unable to determine the fault. The cable was changed out, but the second cable was again found to be faulty. As a result of the problems, depth matching between log runs had an error factor of at least +/-2m. The first log in the hole, DLL/MLL/DAC/GR/CHT run 1/1, was therefore used as the reference log giving a consistent error for all further runs. Depth mismatching was further exacerbated by the need to run wire line pipe conveyed, and open hole sticking with accelerometer correction required in certain instances. No fluid sample was taken in the well. One core was cut in the Hugin and Skagerrak Formations in the interval 3172 m to 3181.5 m (8.85m recovered). </p> <p>Well 15/6-8 S was permanently plugged back to the 9 5/8" casing shoe and abandoned as a dry well on 5 April 1997. Well 15/6-8 A was kicked off from below the 9 5/8" casing at 1525 m and drilled to TD at 2480 m (2397 m TVD SS) in the Heimdal Formation, below the mapped structural spill point. The sidetrack was drilled with KCl / Polymer / Glycol mud from kick-off to TD.</p> <p>The Quaternary and Tertiary sequence of at least 2353 m thickness (2295 m TVT) was represented by the Nordland, Hordaland and Rogaland Groups. Mudstone lithologies dominated, but significant thick sandstone development was present in the Utsira, Skade, Grid and Heimdal Formations. No hydrocarbon shows were recorded within any of the potential reservoir horizons. The logging operations suffered similar problems as in the primary well bore leading to similar uncertainty in depth correlation of the logs. No fluid samples were taken. One conventional core was cut over the interval 2438 m to 2449 m (10.2m recovered) in the Heimdal Formation. </p> <p>Well 15/6-8 A was permanently abandoned as a dry well on 18 April 1997.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
3014
|
7/6/2016 12:00:00 AM
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04.11.2024
|
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15/6-9 A
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<p><b>General</b></p> <p>Well 15/6-9 A is a sidetrack to well 15/6-9 S on the Ermintrude prospect west of the Dagny discovery in the southern Viking Graben. The main objective of the side track was to prove communication between the Dagny discovery and the Ermintrude structure, and to prove gas up dip of the oil leg discovered in the Hugin Formation in 15/6-9 S. </p> <p><b>Operations and results</b></p> <p>Well 15/6-9 A was drilled with the jack-up installation West Epsilon. It was sidetracked from the 15/6-9 S well at 2911 m. The well was drilled deviated to a total depth of 3690 m, 26 m into the Triassic Skagerrak Formation. It was drilled with a KCl/Polymer/Glycol mud system. </p> <p>The MDT results concluded with gas condensate in a gas-down-to situation. A plot of the MDT pressure data for 15/6-9 A and 15/6-9 S give oil and gas gradients that intersect to give a gas-oil contact at approximately 3641 m TVD MSL.</p> <p>No conventional cores were cut and no sidewall cores were retrieved from the 15/6-9 A well. High quality condensate samples were acquired at 3587.5 m in the Hugin Formation. </p> <p>Well 15/6-9 A was plugged back to 2786 m on 26 May 2007. It is classified as a gas condensate appraisal well. The geologic sidetrack 15/6-9 B was kicked off on the same day in order to find the oil-water contact.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
5566
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4/11/2017 12:00:00 AM
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04.11.2024
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15/6-9 B
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<p><b>General</b></p> <p>Well 15/6-9 B is a sidetrack to well 15/6-9 S on the Ermintrude prospect west of the Dagny discovery in the southern Viking Graben. It was drilled down dip on the structure compared to 15/6-9 S. The primary objective was to prove a possible oil water contact below 3714 m TVD MSL, and test the spill point depth of the Ermintrude and Dagny structures.</p> <p><b>Operations and results</b></p> <p>Well 15/6-9 B was drilled with the jack-up installation West Epsilon. It was sidetracked from the 15/6-9 S well at 2824 m on 13 June 2007 and drilled deviated to a total depth of 4010 m driller?s depth, 63 m into the Sleipner Formation. It was drilled with a low-sulphate KCl/Polymer/Glycol mud system. </p> <p>The MDT results and wire line logs proved light oil in an oil-down-to at ca 3948 m (3805 m TVD MSL). The MDT results and wire line logs from all three wells 15/6-9 S, 15/6-9 A and 15/6-9 B give gas/condensate up to 3485 m TVD MSL, a GOC at approximately 3641 m, and a minimum of 164 m TVD oil column below the gas.</p> <p>No conventional cores were cut and only two sidewall cores were recovered from the 15/6-9 B well. High quality oil samples were acquired at 3935 m in the Hugin Formation.</p> <p>Well 15/6-9 B was permanently abandoned on 23 July 2007 as an oil appraisal well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed. </p> |
5571
|
4/11/2017 12:00:00 AM
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04.11.2024
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15/6-9 S
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<p><b>General</b></p> <p>Well 15/6-9 S was drilled on the Ermintrude prospect east of the Dagny discovery and north of the Sleipner Vest field. The prospect is located in the South Viking Graben on the northernmost extension of the Sleipner Terrace, with the Utsira High immediately to the east. The primary objective was to prove hydrocarbons in the Hugin Formation and to acquire data to understand the reservoir characteristics and fluid distribution, and how the Ermintrude structure is connected to the Dagny discovery. Potential targets in the Sleipner and Skagerrak Formation were also investigated by this drilling. </p> <p><b>Operations and results</b></p> <p>Well 15/6-9 S was spudded with the jack-up installation West Epsilon on 29 March 2007 and drilled to TD at 3940 m in the Late Triassic Skagerrak Formation. The well was drilled vertical down to 1050 m and continued in a slightly deviated S-shaped trajectory towards TD. The well was drilled with seawater and hi-vis sweeps down to 277 m, with seawater and CMC EHV sweeps from 277 to 762 m, with a KCl/glycol/polymer mud from 762 to 2797 m, and with low-sulphate KCl/glycol/polymer mud from 2797 m to TD. No shallow gas was observed while drilling the 36" hole, 12 1/4" pilot hole or in the 24" hole opening run. However, 6.3% gas (98% Methane) was observed at top Utsira Formation, 39 m below the 20" casing shoe. MDT pressures and sampling confirmed a normally pressured gas accumulation.</p> <p>The well penetrated rocks of Quaternary, Tertiary, Cretaceous, Jurassic, and Triassic age. The well penetrated the Hugin reservoir at 3741 m, slightly shallower than prognosed. Pressure points and fluid samples were taken with the MDT and a hydrocarbon discovery was proven in the Hugin Formation. The MDT results and wire line logs proved this to be light oil in an oil-down-to situation at ca 3790 m (3714 m TVD MSL). There were no shows or other hydrocarbon indications below 3790 m.</p> <p>One conventional core was cut at 3761.3 - 3811 m in the Hugin Formation. Shows on the core verified the oil-down-to contact at 3793 m. A total of 26 sidewall cores were drilled with the MSCT in Draupne, Heather, Hugin, Sleipner and Skagerrak Formation. High quality oil samples were acquired in the Hugin Formation at 3763 m and 3791 m. A water sample was taken at 3804 m in the Sleipner Formation. The quality of the water sample was low with 40% mud contamination measured at the rig site. In the Utsira Formation, gas samples were taken by dual packer MDT at 793 m.</p> <p>Well 15/6-9 S was plugged back to 2838 m in the 8 1/2" section on 26 May 2007. The well is classified as a gas and oil appraisal well. The geologic sidetrack 15/6-9 A was kicked off on the same day to prove communication with the Dagny discovery and to appraise gas above the oil-leg in the Hugin Formation.</p> <p> <b>Testing</b></p> <p>No drill stem test was performed. </p> |
5494
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4/11/2017 12:00:00 AM
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04.11.2024
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15/8-1
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<p><b>General</b></p> <p>Wildcat well 15/8-1 was drilled west of the Sleipner field, ca 2 km from the UK border. The well was designed to test possible hydrocarbon accumulation in the sandstones of middle Jurassic age.</p> <p><b>Operations and results</b></p> <p>Wildcat well 15/8-1 was spudded with the semi-submersible installation Glomar Biscay II on 18 July 1981 and drilled to TD at 4300 m in the Middle Jurassic Fladen Group. Drilling operations were performed without significant problems in the 36", 26" and 17 1/2" holes. Pipe stuck in the 12 1/4" hole at 2254 m and several times in the 8 1/2" hole. Miscellaneous technical problems occurred while drilling the 6" hole and a gas kick was at 4265 m while tripping. The well was drilled with seawater and gel down to 500 m and with gypsum mud from 500 m to 2890 m. Lignosulphonate was added from 1570 m, and from 2890 m to TD the gypsum mud was gradually depleted and replaced with a gel/lignosulphonate mud.</p> <p>The well 15/8-1 proved gas and condensate in sandstone of Middle Jurassic age. The gas/water contact was indicated at 3698 m from the Formation Multi Tester. Oil shows were recorded from 3065 m to 3075 m in the Hod Formation. Five conventional cores were cut in the interval 3658 m to 3705.5 m in the Hugin Formation. Three samples were attempted taken during FMT runs. Due to technical malfunctions only 1 sample (from 3668 m) was obtained.</p> <p>The well was permanently abandoned on 7 January 1982 as a gas/condensate discovery.</p> <p><b>Testing</b></p> <p>One drill stem test was performed in the Sleipner formation and three in the Hugin Formation. The procedure of the tests was similar; after initial flow and build up the well was flowed for approximately 660 min. producing gas/condensate. Test no. 4 was only flowed for 480 minutes. CO2 was produced in all tests, in concentrations ranging from 4% to 15%, and up to 8 ppm H2S was recorded in DST2. Two sets of PVT samples were taken at the separator during all 4 tests. </p> <p>DST1 from 4079 m to 4094 m in the Sleipner Formation produced 427000 Sm3 gas and 316 Sm3 condensate/day on a 19.1 mm choke. The gas/condensate ratio (CGR) was 1351 m3/m3. DST2 from 3911 m to 3926 m produced 486000 Sm3 gas and 399 Sm3 condensate/day on a 16.7 mm choke, the CGR was 1218 m3/m3. DST3 from 3688 m to 3697 m produced 657000 Sm3 gas and 408 Sm3 condensate/day on a 22.2 mm choke. The CGR was 1610 m3/m3. DST4 from 3643 m to 3653 m produced 550000 Sm3 gas and 290 Sm3 condensate/day on a 22.2 mm choke. The CGR was 1897 m3/m3. </p> |
321
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7/6/2016 12:00:00 AM
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04.11.2024
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15/8-2
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>The 15/8-2 well was drilled in the Ve sub-basin, west of the Sleipner Field and ca 3 km from the UK border in the North Sea. The primary objective was to prove a commercial hydrocarbon accumulation within Upper and Lower Hugin Formation. The secondary objectives were to test possible hydrocarbon presence within the Sleipner Formation and leads in the Hod Formation (Goldfinger lead) and Late Jurassic.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/8-2 was spudded with the semi-submersible installation COSLPioneer on 20 August 2011 and drilled to TD at 4386 m in the Middle Jurassic Sleipner Formation. Before spud, a shallow gas class 1 warning was given. A 9 7/8" pilot hole was drilled from 208.5 to 1100 m. However, no shallow gas was observed by the ROV at the wellhead or by the MWD during drilling. No significant problem was encountered in the operations. The well was drilled with Seawater and bentonite hi-vis sweeps down to 1133 m, with Glydril mud from 1133 m to 2419 m, and with Versatec OBM from 2419 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated rocks of Quaternary, Tertiary, Cretaceous, and Jurassic age. No hydrocarbon indications were observed in the Hod Formation (Goldfinger) and only thin sandstone stringers were observed in the Late Jurassic. The main target Upper Hugin Formation was encountered at 3881.5 m, 31 m higher than prognosed, and the Lower Hugin Formation came in at 4065 m, 1 m shallower than prognosed. The secondary target Sleipner Formation was encountered at 4238 m, i.e. 61 m deeper than prognosed. No movable hydrocarbons were proven in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>Shows: Bright yellowish direct fluorescence, and a slow streaming cloudy bluish white cut fluorescence was recorded in siltstones in the Draupne Formation in the interval from 3812 m to 3818 m and Heather Formation from 3845 m to 3857 m. In the Hugin Formation sandstones questionable shows (oil-based mud?) were recorded in the intervals from 3881 m to 3911 m and 4013m to 4120m. </span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. The MDT tool was run for pressure and fluid sampling. Four water samples were taken at 4011 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 21 October 2011 as a dry well.<b> </b></span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
6681
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2/21/2020 12:00:00 AM
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04.11.2024
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15/9-1
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<p><b>General</b></p> <p>Well 15/9-1 is located in the Sleipner Field. It was drilled on a seismic structure in order to evaluate the Dogger sandstone (Hugin and Sleipner Formations) of Middle Jurassic age.</p> <p><b>Operations and results</b></p> <p>Wildcat well 15/9-1 was spudded with the semi-submersible installation Ross Rig on 24 February 1977 and drilled to TD at 3734 m in the Late Triassic Skagerrak Formation. Severe weather occurred on 31 March, at 3539 m, when the drill string was hung off in the wellhead and the lower marine package disconnected. Drilling commenced on 2 April. When washing/reaming back to TD at 3675 m with a bit to open up the rat hole the pipe stuck at 3647m. Jarring/fishing action was unsuccessful and the string was backed off at 3507 m. The hole was then plugged back, sidetracked and drilled to TD. The well was drilled with seawater and hi-vis pills to 415.5 m and with a seawater/conditioned bentonite/spersene mud system from 415.5 m to TD.</p> <p>Top of the Dogger sandstone (Hugin Formation) was encountered at 3530 m. Log evaluation gave a net productive pay of 56 m, of which 38 m was gas bearing and 18 m was oil bearing. Lowest producible hydrocarbon depth was top of coal bed at 3672 m. Good shows were recorded on cuttings in the interval 3633 m to 3687 m, and in porous sandstones on cores from 3545 m to 3667 m. The Jurassic sandstone was cored in nine cores between 3521 m and 3675.5 m. RFT fluid samples were taken at 9 depths in the interval 3525.5 m to 3701 m. Most of them recovered traces of condensate or oil together with mud filtrate and gas. Only three samples recovered measurable quantities of fluid hydrocarbons: 3528.8 m (5 - 15 ml condensate), 3596.5 m (500 ml condensate), and 3621 m (5 - 15 ml oil). </p> <p>The well was permanently abandoned on 30 May 1977 as an oil and gas appraisal.</p> <p><b>Testing</b></p> <p>Two DST's were performed. </p> <p>DST 1 perforated the interval 3660 m to 3655 m and flowed 1330 STBOPD (211.5 Sm3 oil /day) and 1420000 SCF/D (40210 Sm3 gas/day). This gives a GOR of 1070 SCF/STB (191 Sm3/Sm3). The gas gravity was 0.738 (air = 1), and oil gravity was 26 °API. Foam problems made it difficult to get reliable separator data: oil rates are probably maximum rates and GOR could thus be substantially higher. </p> <p>DST 2 perforated 3602 m to 3607 m and flowed 812 STBOPD (129.1 Sm3 oil/day) and 26000000 SCF/D (7362400 Sm3 gas/day). This gives a GOR of 32000 SCF/STB (5700 Sm3/Sm3). The gas gravity was 0.704 (air = 1) and oil gravity was 45.5 °API.</p> |
322
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7/6/2016 12:00:00 AM
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04.11.2024
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15/9-10
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<p><b>General</b></p> <p>Wildcat well is located between the Sleipner Vest and Sleipner Øst Fields. The well was designed to test possible hydrocarbon accumulations in the Upper Middle Jurassic sands and secondary test Heimdal Formation Sand of Paleocene age.</p> <p><b>Operations and results</b></p> <p>Wildcat well 15/9-10 was spudded with the semi-submersible installation Neptuno Nordraug on 15 September 1981 and drilled to TD at 3289 m in the Triassic Smith Bank Formation. Drilling the 26" hole section complete loss of returns occurred at 186 m and a cement plug was set. Drilling out of the cement returns were again lost, at 178 m, requiring a further cement plug. Total losses due to this loss zone were well in excess of 10 000 bbls. After this operations went without significant problems. The well was drilled with seawater and hi-vis pills down to 172 m. The next section, the 26" section, was drilled down to 472 m with seawater/bentonite and quantities of Mica Fine, Nutplug, Kwikseal, and other additives. From 472 m to TD m the well was drilled with polymer/Drispac.</p> <p>The well encountered Tertiary sands in the Utsira Formation at 884 - 1102 m, Grid Formation at 2049 - 2079 m, Heimdal and Ty Formations at 2547 m to 2667 m. An RFT run in the Heimdal sand indicated a water gradient, 1.02 g/cm3. The primary target Jurassic sandstones was encountered at 3070 m in the Hugin and Sleipner Formations. Some shows were recorded in the Hugin Formation, but from the logs the formations were all water-wet. Possible source rocks were encountered in a comparatively thick and marly Blodøks Formation from 2871 m to 2924 m, and in the Late Jurassic Draupne and Heather Formations from 3004 m to 3070 m. Four conventional cores were cut. Core 1 was cut from 3061 m to 3062.4 m in the Heather Formation, core 2 was cut from 3082 m to 3100 m in the Hugin Formation, and cores 3 and 4 were cut from 3137 m to 3171 m in the Sleipner Formation. No fluid sample was taken.</p> <p>The well was permanently abandoned as dry with minor shows on 7 November 1981.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
69
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5/19/2016 12:00:00 AM
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04.11.2024
|
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15/9-11
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<p><b>General</b></p> <p>Well 15/11-9 was drilled to appraise the 15/9-9 Sleipner Øst discovery in the south Viking Graben area of the North Sea.</p> <p>The primary objective was to delineate the hydrocarbon accumulation found in the Heimdal Formation of the 15/9-Gamma structure. The secondary objective was to test for possible hydrocarbons in Triassic sandstones.</p> <p>The well is Reference well for the Lista Formation, the Meile Member, and the Heimdal Formation</p> <p><b>Operations and results</b></p> <p>Appraisal well 15/9-11 was spudded with the semi-submersible installation Ross Rig on 18 September 1981 and drilled to TD at 2950 m in the Triassic Hegre Group. A total of 99 days including a strike was spent on this well. Apart from the strike, which amounted to 22 days of lost operation, there were no severe problems during drilling and testing operations. The well was drilled with sea water and bentonite down to 585 m and with gel/lignosulphonate/seawater mud from 585 m to TD.</p> <p>The well proved gas and condensate in Heimdal formation and verified thereby the results from the 15/9-9 well. The gas- water contact was found at 2442 m. Hydrocarbons were found also in the Jurassic Hugin Formation sandstones with a gas-water contact at 2825 m. The TD for the well was then extended from 2650 to 2950 m. No hydrocarbons were found in Triassic sandstones </p> <p>Eleven cores were cut in the well. Cores 1 and 2 were cut from 2364 to 2379 m in the Lista Formation. Cores 3 to 11 were cut from 2395 to 2514 m in the Heimdal Formation. The RFT tool was run on wire line and the pressure data supported communication with the 15/9-9 discovery well within the Heimdal Formation, while the Hugin Formation was in a separate pressure regime. Segregated fluid samples were taken at 2387.5 m, in the Heimdal Formation, and at 2812 and 2825.8to 2826.5 m in the Hugin Formation.</p> <p>The well was permanently abandoned on 23 December 1981 as a gas/condensate appraisal well.</p> <p><b>Testing</b></p> <p>Three DST was performed. DST 1 tested the Hugin Formation sandstone from 2789.5 - 2830 m. It produced 566000 Sm3 gas and 243 Sm3 condensate / day through a 15.9 mm choke. The condensate density was 0.75 g/cm3 and the gas gravity was 0.74 (air = 1) with 0.5 - 1% CO2. The maximum down hole temperature measured in the test was 103.9 deg C.</p> <p>DST 2 tested the Heimdal Formation sandstone in the interval 2432 - 2440 m. It produced 233785 Sm3 gas, 104 Sm3 condensate and 1085 m3 water/ day through a 12.7 mm choke. The oil density was 0.75 g/cm3 and the gas gravity was 0.72 (air = 1) with 0.1 - 0.5% CO2. The maximum down hole temperature measured in the test was 93.3 deg C.</p> <p>DST 3 tested the Heimdal Formation sandstone in the interval 2395 - 2415 m. It produced 570867 Sm3 gas and 266 Sm3 condensate / day through a 19.1 mm choke. The oil density was 0.75 g/cm3 and the gas gravity was 0.734 (air = 1) with 0.1 - 0.5% CO2. The maximum down hole temperature measured in the test was 92.2 deg C.</p> |
329
|
7/6/2016 12:00:00 AM
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04.11.2024
|
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15/9-12
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-12 was drilled as an appraisal well on the saddle area between the Alpha and Beta structures on the Sleipner Vest field in the North Sea. The main objective was to test the Middle Jurassic sandstones.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>After setting anchors on 8 November 1981 the spud was delayed two weeks due to strike by the maritime and drilling crews. </span></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-12 was spudded with the semi-submersible installation Nordraug on 22 November 1981 and drilled to TD at 3740 m in the Middle Jurassic Sleipner Formation. The 36" hole was drilled to 195 m but due to bad weather the hole was lost and the well was re-spudded on 26 November. Drilling of the 26" and 17 1/2" holes went forth without significant problems other than tight spots in the lower part of the 17 1/2" hole. When setting the 9 the 5/8" casing shoe at 2755 m 64 m3 mud was lost to the formation. The well was drilled with seawater and gel slugs down to 501 m, with gel-lignosulphonate mud from 501 m to 1135 m, with lignosulphonate/gypsum/CMC mud from 1135 m to 2771 m, and with gel-lignosulphonate mud from 2771 to 3740 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>A 251 m thick Heimdal Formation was penetrated from 2374 m to 2625 m. The Heimdal Formation was water bearing without shows. The primary target reservoir Hugin Formation was penetrated at 3510 m and proved to contain gas-condensate with a gas-water contact at 3654 according to RFT pressure gradients. Weak shows continued on the cores down to 3665 m. The underlying Sleipner Formation was dry without shows. </span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 168.8 m core was cut from top to base of the Hugin Formation. The depth for cores 1 - 9 should be shifted down ca 7 m to fit with the loggers' depth. Cores 10 - 11 should be shifted 8 and 9 m down, respectively. Seven RFT runs were conducted for pressure points and sampling. Segregated fluid samples were taken at 3653 m, 3592.5 m, 3512 m, and 3647 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was suspended on 27 February 1982 as a gas-condensate appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Testing was planned, but failed due to problems with the test string. For this reason Nordraug was taken to the shipyard and testing would be done in a re-entry.</span></p> |
330
|
7/6/2016 12:00:00 AM
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04.11.2024
|
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15/9-12 R
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-12 R is a re-entry of well 15/9-12, which was drilled as an appraisal well on the saddle area between the Alpha and Beta structures on the Sleipner Vest field in the North Sea. Due to technical problems with the rig the final testing was not done in the primary well. The purpose of the re-entry was testing and plugging. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-12 was re-entered on 29 March 1982 with the semi-submersible installation Deepsea Saga. </span></p> <p class=MsoBodyText><span lang=EN-GB> After testing the well was permanently abandoned on 27 April 1982 as a gas-condensate appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Three Drill Stem Tests were conducted. DST 1A tested the interval 3585 m 3595 m. This test was aborted due to bad weather after flowing the well for 150 minutes. The interval was retested a few days later in DST 1B. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1B flowed 252 Sm3 condensate and 771600 Sm3 gas /day through a 64/64" choke. The condensate/gas ratio (CGR) was 3056 Sm3/Sm3, the condensate density was 0.793 g/cm3, and the gas gravity was 0.772 (air = 1) with ca 8% CO2. The DST temperature was 121 deg C at gauge depth 3561.8 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 3512 m to 3522 m. It flowed 231 Sm3 condensate and 808500 Sm3 gas /day through a 64/64" choke. The CGR was 3495 Sm3/Sm3, the condensate density was 0.793 g/cm3, and the gas gravity was 0.765 (air = 1) with ca 7% CO2. The DST temperature was 119 deg C at gauge depth 3499 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Eight gas samples and six condensate samples were taken at the separator during DST 1. Eight gas and eight condensate samples were taken at the separator during DST 2. Neither test experienced sand production nor was H2S detected. </span></p> |
516
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7/6/2016 12:00:00 AM
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04.11.2024
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15/9-13
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-13 was drilled on the Sleipner East Field in the Viking Graben in the North Sea. The objective was to delineate the hydrocarbon accumulation found in the Heimdal Formation of the 15/9 Gamma structure. Secondary objectives were to test possible hydrocarbons in sandstones of Jurassic - Triassic age. The well is reference well for the Utsira and Skade formations. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-13 was spudded with the semi-submersible installation Ross Rig on 21 March 1982 and drilled to TD at 3280 m in the Permian Zechstein Group. <span style='color:black'>No significant problem was encountered in the operations.</span> The well was drilled with seawater and hi-vis slugs down to 518 m, with gel/lignosulphonate mud from 518 m to 1165 m, gypsum/lignosulphonate mud from 1165 m to 2642 m, and gel/lignosulphonate mud from 2642 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB style='color:black'>The well proved gas and condensate in the Heimdal Formation. Shows on cores indicate that all sandstones in the Heimdal Formation are gas filled to a probable down-to contact in top Shetland Group at 2440 m. Gas and condensate were also encountered in a Jurassic sandstone from 2763 to a probable down-to contact at 2791 m. No hydrocarbons were found in Triassic sandstones. No shows were recorded outside of the hydrocarbon-bearing sections in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>Seven cores were cut. Cores 1 - 3 were cut from 2404 m in the Heimdal Formation to 2453.5 m in the Tor Formation with 84 to 100% recovery. Cores 4 - 7 were cut from 2763 m to 2801.6 m in the Hugin Formation with 90 to 100% recovery. Segregated RFT fluid samples were taken at 2400 m, 2437 m, 2765.8 m, and 2766.5 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 27 May 1984 as a gas/condensate appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two DST's were performed on this well. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1 tested gas and condensate from 2765 to 2769 m in the Jurassic sand through the 7" liner. During the main flow on a 64/64” choke, the test produced on average 804500 Sm3 gas and 388 Sm3 condensate /day. The GOR was 2073 Sm3/Sm3, the condensate density was 0.783 g/cm3 and the gas gravity was 0.742 (air = 1). The gas contained 0.8 ppm H2S and 1.0 % CO2. The gauge temperature at final build-up was 98.3 °C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2 tested gas and condensate from 2422 to 2427 m in the Heimdal sand through the 9 5/8" casing. During the clean-up period on a 64/64” choke, the test produced on average 758600 Sm3 gas and 401 Sm3 condensate /day. The GOR was 1891 Sm3/Sm3, the condensate density was 0.76 g/cm3 and the gas gravity was 0.702 (air=1). The gas contained 0.4 ppm H2S and 0.3 % CO2. The gauge temperature at final build-up was 90.3 °C.</span></p> |
45
|
5/19/2016 12:00:00 AM
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04.11.2024
|
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15/9-14
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-14 is located ca 7 km south of the Sleipner Vest Field in the south Viking Graben of the North Sea. The main objectives of the well were sandstones of Late to middle Jurassic age. The secondary objective was the Triassic. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-14 was spudded with the semi-submersible installation Deepsea Saga on 1 May 1982 and drilled to TD at 3563 m in Triassic Smith Bank Formation. Operations were conducted without incident except some problems with tight hole and stuck pipe in the 12 1/4" section. The well was drilled with spud mud down to 561 m, with seawater/gel/ lignosulphonate from 561 m to 1371 m, with seawater/gypsum/ lignosulphonate from 1371 m to 3016 m, and with lignite/lignosulphonate from 3016 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>All objectives proved water bearing according to logs and RFT measurements. The RFT data also showed that the predicted pore pressures had been on the low side. The well was shut in two times due to flow, but there was no pressure build-up. Grains of siltstone and sandstone in cuttings the interval 1220 to 1260 had weak shows (fluorescence, no cut). Fluorescence and cut were observed on sandstones from 3220 to 3290 m in the Vestland Group. </span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut in the Vestland Group. Core no 1 was cut from 3228 to 3243 m (recovered interval 3228.4 - 3636.6 m corrected to loggers depth) and core no 2 was cut from 3267 to 3285.9 (recovered interval 3267 m to 3285.9 m) corrected to loggers depth). One RFT run was performed in the Middle Jurassic - Triassic Formations. Eleven pre-test samples were obtained out of 19 sampling points. No wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 27 June 1982 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
71
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5/19/2016 12:00:00 AM
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04.11.2024
|
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15/9-15
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-15 was drilled south of the Sleipner Øst Field in the Viking Graben of the North Sea. The objectives were to test possible hydrocarbon accumulations in Paleocene and Mesozoic sandstones in the 15/9 My structure. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-15 was spudded with the semi-submersible installation Ross Rig on 28 May 1982 and drilled to TD at 3200 m in the Triassic Skagerrak Formation. During drilling the 12 1/4" section, a significant volume of mud was lost at 2200 m. The thief zone was most probably in the Frigg sand. 3 days were spent locating the zone and pumping LCM pills. Otherwise no significant problem was encountered in the operations, which proceeded with little downtime. The well was drilled with spud mud down to 515 m and with gypsum/lignosulphonate mud from 515 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Paleocene sandstones were missing in this well. The Mesozoic sandstones were encountered at 2806. The upper part consisted of tight Melke Formation sandstones without shows. From 2821 m (top Skagerrak Formation) they were gas bearing down to a true gas/water contact at 2923 m. No oil shows were recorded outside of the hydrocarbon-bearing reservoir in this well.</span></p> <p class=MsoBodyText><span lang=EN-GB>Four cores were cut across the reservoir from 2805 m in the Heather Formation to 2878.2 m in the Skagerrak Formation. The core-to-log depth shift was 2.8 m for all four cores. RFT fluid samples were taken at 282.5 m (gas, condensate and mud filtrate), 2838.5 m (gas, condensate and mud filtrate), and at 2907 m (gas, condensate and mud filtrate) fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1 August 1982 as a gas and condensate discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two Drill Stem Tests were performed.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 2880 m to 2890 m. It produced 298000 Sm3 gas and 155 Sm3 condensate through a 32/64” choke. The GOR was 1922 Sm3/Sm3, the condensate density was 0.760 g/cm3, and the gas gravity was 0.718 with 0.2% CO2. The maximum temperature was 106.8 °C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 2830 m to 2850 m. It produced 293900 Sm3 gas and 124 Sm3 condensate through a 28/64” choke. The GOR was 2478 Sm3/Sm3, the condensate density was 0.757 g/cm3, and the gas gravity was 0.710 with 0.5% CO2. The maximum temperature was 105.7 °C. </span></p> <p class=MsoBodyText><span lang=EN-GB>Both Drill Stem Tests included a flow period with a three-step multirate drawdown test. Check the well completion report and well test report for further details, such as flow parameters for other choke sizes. </span></p> |
74
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4/25/2019 12:00:00 AM
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04.11.2024
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15/9-16
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-16 was drilled on the Sleipner Øst discovery in the southern Viking Graben of the North Sea. The primary objective was to delineate the hydrocarbon accumulations in the Heimdal Formation on the gamma structure. Sandstones of Jurassic/Triassic age were secondary objectives. It was the fourth well drilled on this structure.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-16 was spudded with the semi-submersible installation Deepsea Saga on 28 June 1982 and drilled to TD at 3120 m, 52 m into the Permian Rotliegendes Group. The 9 5/8" casing had a leak at 522 m. It was squeezed twice with cement before it held a reduced pressure. Otherwise, no significant problem was encountered in the operations. The well was drilled with gel/seawater spud mud down to 515 m, with gypsum/lignosulphonate mud from 515 m to 2652 m, and with a seawater/lignite/lignosulphonate mud from 2652 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top Heimdal was encountered at 2378 m. It contained gas and condensate, but was thinner than expected. Pressure data indicated a gas/water contact at 2434 m. The logs showed a sharp increase in water saturation at 2428 m. Weak oil shows were recorded on cores between 2418 m and 2427.5 m. The prognosed sandstones of Jurassic/Triassic age were not present at this location. Fair shows were recorded on cuttings in evaporites at 3014 m, at top Zechstein Group level. No shows were recorded on sidewall cores from the same level.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 113.5 m of core (98% recovery) was cut in seven cores in the interval 2382 to 2498 m. cores were cut and no wire line logs were run in the well. An RFT fluid sample was taken at 2380 m (good recovery), while attempts to sample at 2411m, 2413 m, and 2426 m gave poor recovery.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 24 August 1982 on as a gas/condensate appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
79
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5/19/2016 12:00:00 AM
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04.11.2024
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15/9-17
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-17 was drilled on the Sleipner Terrace in the Viking Graben of the North Sea. The primary objectives were to test possible hydrocarbon accumulations in the Paleocene Heimdal Formation and in Jurassic/Triassic sandstones. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-17 was spudded with the semi-submersible installation West Vanguard and drilled to 3120 m in the Triassic Smith Bank Formation. A 12 1/4" pilot hole was drilled down to 519 m, but no indications of shallow gas was found. Bad weather caused some delay. Bad weather and repeated BOP problems caused some down time. The well was drilled with spud mud down to 500 m, with gypsum/polymer mud from 519 m to 2616 m, with Lignosulphonate/Drispac mud from 2616 m to 2950 m, and with Drispac from 2950 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Both the Heimdal Formation and the Mesozoic sandstones contained gas and were tested. </span></p> <p class=MsoBodyText><span lang=EN-GB>The log evaluation indicated top of the hydrocarbon column in the Heimdal Formation at 2377.5 m. The logs indicated the gas/water contact at 2418.5 m, while pressure data gave a gas/water contact a bit shallower, at 2413 m. Weak and spotted shows were recorded on cored sandstones in the Heimdal Formation below the contact down to 2425 m, and from 2442 to 2450 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The top of the hydrocarbon column in the Mesozoic sandstones was at 2715 m (top Vestland Group). The column extended down into the Triassic. No definite gas/water contact was found but could be as deep as 2848 m. Shows were recorded on cored sandstones throughout this reservoir, getting weaker with depth. </span></p> <p class=MsoBodyText><span lang=EN-GB>No shows were seen outside of the hydrocarbon bearing sections in the well</span></p> <p class=MsoBodyText><span lang=EN-GB>Ten cores were cut. Cores 1 to 5 were cut from 2382 to 2460 m. The recovery was 100% except for core 4, which had only 46% recovery. No core-log depth shift was required for these cores. Cores 6 to 9 were cut from 2714 to 2775.4 m with 100% recovery. The core-log shift was from 1.1 m to 0.45 m. Core 10 was cut from 2810 to 2828.9 m with 100% recovery. The core-log shift was 1.0 m. wire line logs were run in the well. RFT fluid samples were taken at 2308.3 m (mud filtrate), 2729.3 m (gas, condensate and mud filtrate), 2802.7 m (gas, condensate and mud filtrate), and 2844.8 m (gas, condensate and mud filtrate).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was suspended on 30 March 1983 as a gas and condensate discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Three Drill Stem Tests were conducted.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 2802 to 2814.5 m. It produced 590000 Sm3 gas and 210 Sm3 condensate /day through a 19.05” choke. The GOR was 2800 Sm3/Sm3. Traces of sand and water were produced. Dräger measurements indicated 0.5 - 1.0% of CO2 and no H2S. The downhole temperature was 100 °C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 2726.5 to 2741.5 m. It produced 570000 Sm3 gas and 205 Sm3 condensate /day through a 19.05” choke. The GOR was 2780 Sm3/Sm3. An average BSW of 0.5% was produced throughout the test. Dräger measurements indicated 0.5% of CO2 and no H2S.The downhole temperature was 97.8 °C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 3 tested the interval 2381.5 to 2414 m. It produced 525000 Sm3 gas and 280 Sm3 condensate /day through a 19.05” choke. The GOR was 1875 Sm3/Sm3. Between 0.4 - 0.9% BSW was measured during the final flow. No. CO2 and H2S was measured. The downhole temperature was 90 °C.</span></p> |
60
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5/19/2016 12:00:00 AM
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04.11.2024
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15/9-17 R
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-17 R is a re-entry of well 15/9-17 on the Sleipner Terrace in the Viking Graben of the North Sea. The purpose of the re-entry was plugging and permanent abandonment.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-17 was re-entered with the semi-submersible installation Ross Rig on 28 April 1991.</span></p> <p class=MsoBodyText><span lang=EN-GB>No significant problem was encountered in the operations. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged and permanently abandoned on 4 May 1991.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
1768
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7/6/2016 12:00:00 AM
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04.11.2024
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15/9-18
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-18 is located between the Sleipner Øst and Sleipner Vest Fields in the South Viking Graben in the North Sea.</span></p> <p class=MsoBodyText><span lang=EN-GB>It was designed primarily to test hydrocarbon accumulations in the Middle Jurassic Hugin Formation. Secondary objectives were Paleocene sandstones in the Heimdal and Sleipner Formations, and sandstones of Triassic age. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-18 was spudded with the semi-submersible installation Deepsea Bergen on 16 December 1983 and drilled to TD at 3622 m in the Triassic Smith Bank Fm. No major problems occurred while drilling this well, but some tight hole problems were experienced in the 12 1/4" hole section. The well was drilled with seawater gel down to 520 m and with gypsum/lignosulphonate mud from 520 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Tertiary sands were penetrated at 866 m (Utsira Formation), 1254 m, and at 2071 m ("Frigg Fm Equivalent"). The Draupne Formation was encountered 105 m thick at 3108 m. The Hugin Formation was encountered at 3237 m. It was found hydrocarbon bearing in a 7.5 m interval from 3237.5 m and down to a coal layer at 3245.0 m but the hydrocarbons were immovable. The well did not encounter other hydrocarbon bearing intervals. Shows were however recorded further down in the Hugin Formation in the interval 3275 m to 3325 m. </span></p> <p class=MsoBodyText><span lang=EN-GB>Four cores were cut, two in the Paleocene and two in the Middle Jurassic sequence. Segregated FMT fluid samples were taken in the hydrocarbon bearing interval in the Hugin Formation at 3238.3 m, 3239 m, and 3240 m. All samples were reported to recover mud filtrate only, but the samples from 3240 m were analysed to contain 0.2 g petroleum hydrocarbons.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 2 March 1984 as a dry well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
36
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5/19/2016 12:00:00 AM
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04.11.2024
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15/9-19 A
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<p><b>General</b></p> <p>The well 15/9-19 SR on the Theta Vest structure North of the Sleipner East Field proved oil in the Hugin Formation in 1993. The objective for the well 15/9-19 A, a side-track from this well, was to confirm a minimum economic hydrocarbon volume in the Hugin Formation and map the extension of the oil-bearing formation. </p> <p><b>General</b></p> <p>The well 15/9-19 SR on the Theta Vest structure North of the Sleipner East Field proved oil in the Hugin Formation in 1993. The objective for the well 15/9-19 A, a side-track from this well, was to confirm a minimum economic hydrocarbon volume in the Hugin Formation and map the extension of the oil-bearing formation. </p> <p><b>Operations and results</b></p> <p>Well 15/9-19 A was kicked off from 2178 m in well bore 15/9-19 SR on 25 July 1997, using the semi-submersible installation Byford Dolphin. The well was drilled through the Skagerrak Formation and terminated approximately 30 m TVD into the Triassic Smith Bank Formation at 4131 m (3318.5 m TVD RKB). The final acquisition programme immediately after reaching the total depth of the well was strongly affected by a labour conflict, which delayed the well operations for 32.5 days. The originally planned open hole electric logging program had to be terminated and the 7" casing run to TD in order to secure the well. The later cased hole logging failed due to tool problems. The well was drilled oil based with the Ultidril mud system (oil base consists of synthetic olefins) from kick-off to TD.</p> <p>Top of the Hugin Formation was penetrated at 3796.5 m (3015.5 m TVD RKB) approximately 60 m TVD deeper than prognosed. It was 153 m thick (TVD) and oil-bearing. The total oil column in the well was 80 m, but no clear oil-water contact was observed. The base of the reservoir was at 3919 m (-3126.5 m TVD RKB). Seven cores were cut in the interval 3838 m to 4017 m in the Hugin and Skagerrak Formations, with a total recovery of 177.6 m. One attempt was made to run FMT on PCL for pressure points and fluid sampling. The run failed for technical reasons and no further attempts were made due to the labour conflct.</p> <p>The well was permanently abandoned on 9 November 1997 as an oil appraisal.</p> <p><b>Testing</b></p> <p>Three tests were performed in order to evaluate the well, one in the water zone and two in the oil zone.</p> <p>Test 1 at 3952 - 3958 m (3159.8 - 3165.5 m TVD RKB), was in the water zone to obtain water samples due to MDT failure during wire line logging. Four good samples were obtained, indicating similar formation water as in other wells in the Sleipner area. Maximum recorded temperature in this test was 112.7 deg C. </p> <p>Test 2A at 3885.5 - 3888.5 m (3100 - 3102.5 m TVD RKB) flowed 300 Sm3 oil and 27000 Sm3 gas /day through a 38/64" choke during the cleanup flow. The corresponding GOR was 90 Sm3/Sm3, the oil density was 0.892 g/cm3, and the gas gravity was 0.738 (air = 1) with 2.5 ppm H2S and 3% CO2. The temperature recorded in this flow period was 112.3 deg C.</p> <p>Test 2B at 3885.5 - 3888.5 m + 3826 -3865 m (3100 - 3102.5 m + 3046.2 - 3081.3 m TVD RKB flowed 528 Sm3 oil and 38107 Sm3 gas /day through a 34/64" choke during the main flow. The corresponding GOR was 72 Sm3/Sm3, the average oil density was 0.902 g/cm3, and the average gas gravity was 0.730 (air = 1) with 2.8 ppm H2S and 3.5% CO2. The temperature recorded in this flow period was 110.8 deg C.</p> |
3145
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7/6/2016 12:00:00 AM
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04.11.2024
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15/9-19 B
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<p><b>General</b></p> <p>Well 15/9-19 B was drilled back-to-back with 15/9-19 A. The -19 A well proved an 80 m oil column in the Hugin Formation, and no OWC was found. Also, top Hugin Formation was found 62.5 m deeper than prognosed in the former well. The overall well objective of 15/9-19 B was to obtain a better definition of the resource estimate of the Theta Vest structure by identifying the oil-water contact, establish the pore pressure east of the -19 A well, and to improve the seismic tie. </p> <p><b>Operations and results</b></p> <p>Sidetrack well 15/9-19 B was kicked off from 2200 m in well bore 15/9-19 A on 9 November 1997, using the semi-submersible installation Byford Dolphin. Well 15/9-19 A in turn, was drilled as a sidetrack of well 15/9-19 SR drilled in 1993. The well 15/9-19 B was drilled as an 8 1/2" hole from the kick-off point to 3272 m. Due to stuck pipe the string was severed and the well plugged back. A technical sidetrack (15/9-19 BT2), was then made from 2911 m and drilled as 8 1/2" hole to 3220 m. A 7" liner was set at 3198 m, and 6" hole drilled to well TD at 4250 m / 3360.5 m TVD RKB, approximately 30 m TVD into the Triassic Smith Bank Formation. The originally planned open hole electric logging program was performed in the 6" hole section due to setting of 7" liner. All planned logs were run, and data obtained had generally good quality. Due to casing-ringing data from the MAC log in 7" liner is of poorer quality. The well was drilled with the oil based Ultidril mud system from kick-off to TD.</p> <p>The top of the Vestland Group, Hugin Formation was penetrated at 4036 m (3174 m TVD RKB) approximately 100 m TVD deeper than prognosed and 47.5 m deeper than the oil down-to contact in the -19 A well. The mismatch with the prognosis was due to wrong pick on the seismic. Both the Hugin and the Sleipner Formations were present with a total thickness of 156 m, of which the Hugin Formation was 126 m (TVD). The well is classified as dry. However, in the Hugin Formation weak to fair shows from 4036 m and over the cored intervals were reported.</p> <p>Four conventional cores were cut in the interval 4037 m to 4109 m in the Hugin Formation. The FMT measurements confirmed a water gradient (0.1069 bar/m) in the Hugin sandstones, with a pressure of approximately 1.09 g/cc equivalent mud weight. No formation fluid samples were collected in the well.</p> <p>The well was permanently abandoned on 2 February 1998 as a dry well with shows.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
3251
|
7/6/2016 12:00:00 AM
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04.11.2024
|
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15/9-19 S
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<p><b>General</b></p> <p>Wildcat well 15/9-19 S was the first well to be drilled into the Theta Vest Structure north of the Sleipner East Field. It was designed to test gas from the Heimdal reservoir, and to provide geological and reservoir data enabling optimal reservoir management. The secondary target was the Hugin/Skagerrak Sands, which were to be fully evaluated if hydrocarbon bearing.</p> <p><b>Operations and results</b></p> <p>Well 15/9- 19 S was spudded with the semi-submersible installation Treasure Prospect on 18 November 1992, from Slot 3 of the Loke Discovery template. The well was deviated, penetrating the top of the Theta Vest structure approximately 2290 m west northwest of the Loke Template, and reached the target Top Heimdal Formation at 3622.5 m (2427.0 m TVD RKB). The 12 1/4" section from 1482 m to 3580 m was drilled with significant problems. Trips out of the hole at 2018 m, 3016 m and 3353 m were performed to change the bits, due to low penetration rate. The hole packed of several times when tripping out. Problems with lost returns and stuck BHA finally led to plugging back and sidetracking from 1493 m. Attempts to orientate the well became progressively more difficult, especially after penetrating 3308.5 m in the Balder Formation. The Lista Formation was encountered at 3483 m, and final TD was set at 3580 m, at the edge of the Heimdal Formation target. The well was drilled with bentonite mud down to 531 m, and with KCL/POLYMER (Phpa/pac) mud from 531 m to TD in the first hole. After sidetracking oil based mud (Petrofree) was used.</p> <p>The well penetrated 150 m TVD of Tertiary sands between 1313 m and top Balder Formation at 3302 m. </p> <p>It was temporarily suspended on 31 January 1993 after setting 9 5/8" casing at 3569.0 m (2394.0 m TVD RKB), immediately above the Heimdal sands. No cores were cut and no fluid samples taken in this well bore. It is classified as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
2043
|
7/6/2016 12:00:00 AM
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04.11.2024
|
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15/9-19 SR
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The re-entry 15/9-19 SR is a continuation of wildcat well 15/9-19 S, which was temporarily suspended at 3569.0 m (2394.0 m TVD RKB), immediately above the Heimdal sands. The target of the well was the Theta Vest Structure north of the Sleipner East Field. The primary objective was to test gas from the Heimdal reservoir, and to provide geological and reservoir data enabling optimal reservoir management. The secondary target was the Hugin/Skagerrak Sands, which were to be fully evaluated if hydrocarbon bearing. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9- 19 S was re-entered (15/9-19 SR) with the semi-submersible installation Treasure Prospect on 17 February 1993, from Slot 3 of the Loke Discovery template. The well was drilled to TD at 4641 m (3132.3 m TVD RKB) in the Triassic Skagerrak Formation. No significant technical problems were encountered in this well bore. The well bore was drilled with oil-based mud (Petrofree).</span></p> <p class=MsoBodyText><span lang=EN-GB>The Heimdal sandstone was penetrated at 3623 m (2427 m TVD RKB), 50 m low to prognosis. This Formation was the main target in the well. No hydrocarbons were encountered. The Hugin Formation was penetrated at 4317 m (2886 m TVD RKB), 2 m low to prognosis. The entire Hugin Formation was oil filled (18 m TVD). The core from this formation was filled with H2S (650 ppm). Sandstones of the Skagerrak Formation were water wet. No shows were recorded due to invasion of petrofree mud. </span></p> <p class=MsoBodyText><span lang=EN-GB>One core was cut from 3643 m to 3648 m in the Heimdal Formation, and two cores were cut from 4328 m to 4383 m in the Hugin and Skagerrak Formations.No fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was suspended on 29 March 1993 as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>One Drill Stem Test from the interval 4316 to 4338 m in the Hugin Formation was performed. The test produced 680 Sm3 oil /day through a 12.7 mm choke. The GOR was 98 Sm3/Sm3, the oil density was 0.870 g/cm3, and the gas gravity was 0.740 (air =1)</span></p> |
2105
|
7/6/2016 12:00:00 AM
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04.11.2024
|
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15/9-19 SR2
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<p><b>General</b></p> <p>The re-entry 15/9-19 SR2 is a Re-entry of well 15/9-19 SR, which was suspended in 1993 without testing, after having discovered oil in the Middle Jurassic Hugin Formation. The objective of the re-entry was plug back before sidetracking (15/9-19 A) for evaluation of the Hugin discovery.</p> <p><b>Operations and results</b></p> <p>Well 15/9-19 SR was re-entered (15/9-19 SR2) on 18 July 1997 with the semi-submersible installation Byford Dolphin through slot 3 on the Loke template. </p> <p>The well bore was plugged back and permanently abandoned on 25 July 1997.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
3180
|
7/6/2016 12:00:00 AM
|
04.11.2024
|
|
15/9-2
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<html>
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-2 was drilled on the Sleipner Vest Field in the North Sea. The primary objective was to test the "beta closure" on the 15/6-3 Sleipner Vest discovery. The target was Middle Jurassic sandstones.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-2 was spudded with the semi-submersible installation Ross Rig on 12 April 1978 and drilled to TD at 3764 m in Late Triassic sediments in the Skagerrak Formation. The main problem in operations was the discovery of a washout in the well head 18 3/4" ax seal area after setting 9 5/8" casing. This was repaired so that drilling could proceed, but it was decided not to do the planned DST due to possible leak. Otherwise, operations proceeded without significant problem. The well was drilled with seawater and gel down to 644 m and with gel and lignosulphonate from 644 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Vestland Group, Hugin Formation was encountered at 3483 m. The Hugin Formation contained gas/condensate down to the OWC between 3652 and 3654 m based on logs and pressure gradients. Weak shows continued down to 3659 m, 2 meters into top Sleipner Formation. Two spots of dead oil and fluorescence on limestone/siltstone cuttings at 2788 and 2812 m in the upper Shetland Group were the only other shows described in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 186.3 m core was recovered in 11 cores from the interval 3498 m to 3692 m. RFT fluid samples were taken at 3490 m ((gas, condensate, water), 3535,7 m (gas and condensate), 3601.6 m (gas, condensate, water), 3640.4 m (gas, condensate, water), 3641 m (gas, condensate, water), 3641.5 m (gas, condensate, water), 3644 m (gas, condensate, water), 3652 m (gas, condensate, water), and 3654 m (water). The condensate gravity in the samples varied from 50.3 °API in the shallowest sample to 45.5 °API in the sample just above the OWC.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 17 June 1978 as a gas/condensate well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
323
|
7/6/2016 12:00:00 AM
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04.11.2024
|
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15/9-20 S
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<p><b>General</b></p> <p>Wildcat well 15/9-20 S was drilled from the Sleipner A platform on the Sleipner øst Field. It started off as development well 15/9-A-22, which was designed to provide gas production from the Heimdal reservoir in the central part of the Sleipner Øst Field, and to contribute with geological and reservoir technical data for optimal reservoir management in this area. Due to unexpected geology in the deeper part of the well the Cretaceous and below was reclassified to exploration well 15/9-20 S.</p> <p><b>Operations and results</b></p> <p>Well 15/9-20 S was spudded from the fixed installation Sleipner A on 16 February 1994 and drilled deviated to TD at 3624 m in the Triassic Smith Bank Formation. No significant problems were reported from the operations. The well was drilled with seawater/PAC mud from below 26" conductor to 506 m, with KCl/PHPA/PAC mud from 506 m to 1735 m, with KCl/PHPA/PAC/Glycol mud from 1735 m to 2928 m, and with ester mud from 2928 m to TD. No shallow gas was encountered.</p> <p>The well penetrated the Heimdal Formation target at 2931 m (2279.6 m TVD MSL), 11.6 m TVD deeper than prognosis. The Heimdal Formation was 104 m thick (71.2 m TVD) and proved to be gas filled as expected. Under the Heimdal Formation the well drilled 204 m Late Cretaceous limestone overlying 8 m Blodøks Formation. At 3247 m (2490.2 m TVD MSL) the well drilled unexpected into Jurassic/Triassic sandy sediments, which proved to have a 30 - 50 m TVD hydrocarbon leg.</p> <p>Five conventional cores were cut from 2940 - 3043 m in the Heimdal and into the top of the Tor Formation. A sixth core was cut from 3216 - 3244 m, from base Hod Formation and into the Blodøks Formation. One RFT segregated sample was taken at 3272.6 m in the Skagerrak Formation.</p> <p>Well bore 15/9-20 S was plugged back and permanently abandoned on 1 June 1994 as a gas discovery.</p> <p><b>Testing</b></p> <p>The well was perforated on wire line over the interval 3229 - 3238 m in the base of the Hod Formation and stimulated with acid, but the result was negative and the interval was plugged. Two drill stem tests were performed in the Heimdal Formation sandstone. DST 1 tested the interval 2942 - 2956 m and DST 2 tested the interval 2933 - 2942 m.</p> |
2319
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7/6/2016 12:00:00 AM
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04.11.2024
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15/9-21 S
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<p><b>General</b></p> <p>Well 15/9-21 S was drilled from the Sleipner Vest wellhead facility. The well was designed deviated to appraise the oil potential of the Hugin Formation east of the main Sleipner Vest Field. Another objective was to further appraise the Hugin Formation oil in the Sleipner Vest area, which had been discovered in well 15/9-B-4 T2.</p> <p><b>Operations and results</b></p> <p>The 24" section of well 15/9-21 S was spudded from the batch-set 32" conductor on 23 March 1998. Using the jack up installation West Epsilon the well was drilled to TD at 5126 m in the Middle Jurassic Sleipner Formation. No significant problems were reported from the operations. The well was drilled with PAC/seawater down to 506 m, with Aquadril KCl/glycol mud from 506 m to 3457 m, and with oil based mud from 3457 m to TD.</p> <p>The target was penetrated approximately 2670 m east of the platform centre, at a depth of 4736.5 m (3592.0 m SS), 19.6 m deep to prognosis. The first 30 m of the target sandstone drilled was Intra Heather Sandstone. The Hugin Formation was penetrated at 4767 m. Only minor hydrocarbons were found. Oil shows, partly masked by the oil based mud, was observed on the cores from the Hugin Formation. The strongest shows were seen in the interval 4784 to 4798 m where oil slowly seeped from the core. </p> <p>Four cores were cut from 4747 m in the Intra Heather Formation Sandstone to 4843 m in the Hugin Formation. No wire line fluid samples were taken.</p> <p>The well was permanently abandoned on 23 May 1998 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
3334
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7/6/2016 12:00:00 AM
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04.11.2024
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15/9-22
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<p>Well 15/9-22 is located just south of the Sleipner Vest field in the South Viking Graben of the North Sea. The primary objective of the well was to test the hydrocarbon potential of the Wishbone NE prospect, which was a stratigraphic pinch out trap. The key risks for the prospect were reservoir adequacy (Hugin Formation) and lateral seal. The primary reservoir target was the Upper Hugin Formation (Middle Jurassic Vestland Group), with Middle Jurassic Lower Hugin Formation, Sleipner Formation and Triassic as secondary targets. The anticipated hydrocarbon type was gas with condensate.</p> <p><b>Operations and results</b></p> <p>Well 15/9-22 was spudded with the semi-submersible installation Ocean Vanguard on 1 January 2006 and drilled to TD at 3915 m (3923 m logger?s depth), 167 m into the Triassic Skagerrak Formation. A 36" hole was drilled and 30" conductor was successfully run and cemented at 201 m. Due to the probability of shallow gas, a 26" hole was drilled to 508 m and a 20"x18 5/8" casing string set at 204 m. The BOP and riser were run and tested after considerable delays for repairs and waiting on weather. The 17 1/2" hole was drilled to 1531 m, and no shallow gas was seen. The 13 5/8" surface casing was run and became stuck at a depth of 953 m. The casing was cut and fished out of hole from 601 m and a kick-off plug set from 592 m to inside of the 18 5/8" casing at 410 m. The hole was sidetracked (15/9-22 T2) at 522 m on Jan 31 2006, and the new hole was drilled to TD without further significant problems. The well was drilled with seawater down to 508 m and with Glydril KCl mud from 508 m to TD. </p> <p>The lithostratigraphic tops below 410 m, as given on this fact page, are from the sidetrack. The Hugin Formation was encountered at 3572 m. It was 141 m thick, of which 40 m had average porosity of 18.1%. From wire line interpretation possible residual hydrocarbon saturation was reported in the uppermost porosity intervals in the Hugin Formation, but otherwise the only hydrocarbon indication in the well was a strong hydrocarbon odour from a cuttings sample from 3408 m in the Draupne Formation. MDT pressures were taken. A dry hole case logging program was performed. No conventional cores or sidewall cores were taken.</p> <p>The well was permanently abandoned on 13 March 2006 as a dry well.</p> |
5174
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4/11/2017 12:00:00 AM
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04.11.2024
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15/9-23
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-23 was drilled in the southern Viking Graben, south of the Sleipner East Field in the North Sea. The primary objective was to test the Middle Jurassic Hugin and Sleipner formations and the Triassic Skagerrak formation within the Skardkollen prospect. The Early Paleocene Ty Formation was secondary objective.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-23 was spudded with the semi-submersible installation Bredford Dolphin on 18 November 2009 and drilled to TD at 3225 m in late Triassic sediments of the Skagerrak Formation. A 9 7/8" pilot hole was drilled from the 36" section to 714 m and a shallow gas zone was encountered at 674 to 678 m. The hole was opened to 26" down to 556 m, and 20" casing was set at 550 m. The well was drilled with seawater and hi-vis sweeps down to 556 m, with KCl/Glycol mud from 556 to 1520 m, and with XP-07oil based mud from 1520 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The top of the first Frigg Formation sand was penetrated at 2092 m. The secondary target, the Ty Formation of the lowermost Rogaland Group was penetrated at 2524 m. The Ty Formation constituted excellent reservoir sandstones with a gross thickness of 24 m. GeoTap pressure measurements detected a pore pressure depletion of 105 bar compared to a normal hydrostatic gradient, most likely related to production at the nearby Sleipner East Field within the same stratigraphical unit. The primary reservoir target, the Middle-Jurassic Vestland Group, was penetrated at 3087.5 m, 45.5m deeper than anticipated. The Hugin Formation was absent, and the top of the Vestland Group consisted of the coal-bearing Sleipner Formation. Firm identification of red-brown Triassic mudstones of the Skagerrak Formation was penetrated at 3169 m, 5.5m shallower than prognosed. GeoTap pressure measurements through the Sleipner- and Skagerrak Formations also detected higher overpressures (65-73-89 bar) than measured in the nearby, analogue wells. The high and vertically varying overpressures, in combination with the low N/G and inferred poor/non-effective sand-to-sand connectivity, may explain the failure of hydrocarbons migrating into the Skardkollen structure. </span></p> <p class=MsoBodyText><span lang=EN-GB>All reservoirs were water-wet. The only show recorded in the well was a very weak show on cuttings in the Sleipner Formation. Lack of supportive from logs and gas levels suggested that the show could be caused by the drilling fluid.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. No logs were run on wire line, all logs are from LWD. No fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 3 January 2010 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
6186
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4/11/2017 12:00:00 AM
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04.11.2024
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15/9-24
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-24 was drilled just south of the Sleipner Terrace in the southern Viking Graben of the North Sea. The main objective was to test the hydrocarbon potential of the Storkinn prospect. The main reservoir target was the Paleocene Heimdal-/Ty formations, south-east and up dip to the Sleipner Øst Field. The prognosed top of the Heimdal / Ty formations was at 2310 m.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-2 was spudded with the semi-submersible installation Bredford Dolphin on 18 May 2010 and drilled to TD at 2400 in the Late Cretaceous Tor Formation. The 26" section was drilled first as a 9 7/8" pilot hole in case of shallow gas. Due to low wind speeds at the moment 10 hours were spent WOW before the pilot could commence. No shallow gas was observed, and the drilling operations went forth without significant problems. The well was drilled with Seawater and Hi-Vis Sweeps down to 627 m, with KCL/GEM Glycol Mud from 627 to 1496 m, and with XP-07 Oil Based Mud from 1496 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Heimdal-/Ty Formation sandstones were not observed in the well. No hydrocarbon shows were observed in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. The well was logged with MWD/LWD; no wire line logs were run. No fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 10 June 2010 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
6381
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4/11/2017 12:00:00 AM
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04.11.2024
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15/9-3
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well was drilled on the northwestern part of the Sleipner Vest structure in the Viking Graben of the North Sea. The objective was to test hydrocarbons in the “Alpha structure” of the Sleipner field. The target was Middle Jurassic sandstones.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-3 was spudded with the semi-submersible installation Ross Rig on 17 December 1978 and drilled to TD at 3796 m in the Triassic Skagerrak Formation. Many problems were encountered in the operations. When drilling the 26" interval, the circulation was lost several times. Pumping lost circulation material pills and cement into the formation solved this. The main problem arose when drilling the 8 1/2” interval. At 3375 m on top of Upper Jurassic, an abnormally pressured impermeable zone was penetrated. Due to a series of technical problems that followed this incident, the well was finally plugged back and sidetracked from 1213 m. Furthermore, the well was drilled in the wintertime and the cold was quite severe. Because of this, the hydraulic control system for the BOP stack froze on one occasion. Functional problems with the BOP pods were experienced, consequently, the time and cost estimates, were seriously exceeded. The well was drilled with spud mud down to 402 m, with gel/lignosulphonate from 402 m to 2680 m and with gel/lignosulphonate/lignite mud from 2680 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Middle Jurassic Vestland Group, top Hugin Formation, was encountered at 3498 m. Well 15/9-3 proved very poor reservoir qualities in these strata and the well was hence not production tested. A cluster of RFT pressure data points suggested a light hydrocarbon gradient of 0.11 - 0.25 psi/ft. between 3600 m and 3612 m. Between 3650 m and 3682 m a good "heavier" hydrocarbon gradient of 0.35 psi/ft. was established. This indicates a hydrocarbon/water contact approximately at 3682 m. Very weak spotted shows were described over this section and down to 3709 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Four cores were cut from the interval 3511 to 3580 m in the Hugin Formation. RFT fluid-sampling chambers recovered six samples, all containing mud filtrate with minor amounts of gas. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 3 April 1981 and was classified as dry with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
324
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7/6/2016 12:00:00 AM
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04.11.2024
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15/9-4
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-4 was drilled on in the southeastern part of the Sleipner Vest area in the Viking Graben of the North Sea. Previously four wells had been drilled on the Sleipner Alpha structure in the north. Two of these showed significant gas-condensate accumulations (15/6-3 and 15/9-1) in the middle Jurassic while in the western part of the Alpha structure the sand had shaled out (15/9-3). In the northeast, the sand was penetrated below the hydrocarbon/water contact (15/6-5). The first well drilled on the Beta prospect (15/9-2) showed a significant gas-condensate column in the middle Jurassic sand. The primary objective for well 15/9-4 was to test possible hydrocarbons in Middle Jurassic sandstones in the southeast extending Delta structure. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-4 was spudded with the semi-submersible installation Ross Rig on 4 April 1979 and drilled to TD at 3716 m in the Triassic Skagerrak Formation. Very few problems were encountered during drilling of this well, with the exception of lost circulation in the 26" interval. This problem was solved by pumping cement into the formation. The main problem arose only after drilling the 8 1/2” interval. The 7" liner was run and cemented sucessfully. When pressure was applied in order to test the liner lap, the 9 5/8" casing burst. The well was drilled with spud mud down to 415 m and with gel/lignosulphonate mud from 402 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top of the Middle Jurassic Vestland Group, Hugin Formation was penetrated at 3441 m. The section contained sandstones with good reservoir properties interbedded with some thin shale beds. The sandstones were hydrocarbon bearing with a gas-water contact at ca 3570 m, 7 m into the Sleipner Formation. Weak oil shows were described throughout the hydrocarbon-bearing reservoir down to 3582 m. Shows were not described in any other section of the well. The Triassic Skagerrak Formation was encountered at 3629 m with some small water bearing sand intervals.</span></p> <p class=MsoBodyText><span lang=EN-GB>Nine cores were cut in the interval 3457 to 3594.8 m in the Hugin and Sleipner formations. The core-log depth shift is reported as -2.5 m for all cores. Overall recovery was 132.1 m core (98.2%). An RFT fluid sample was taken at 3481 m. It contained gas, condensate, mud and water.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 14 June 1979 as a gas/condensate appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was not production tested, due to technical problems.</span></p> |
325
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7/6/2016 12:00:00 AM
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04.11.2024
|
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15/9-5
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-5 was drilled in the Sleipner Vest area in the Central Graben of the North Sea. The objective was to test hydrocarbons in Middle Jurassic sandstones in the Beta structure of Sleipner Vest. The well is Reference Well for the Heimdal and Våle formations.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-5 was spudded with the semi-submersible installation Norskald on 19 November 1979 and drilled to TD at 3946 m in the Triassic Skagerrak Formation. Operations met with many problems, but the well objectives were fulfilled in the end. Excessive drag when pulling core barrel out of reservoir was a severe problem, and consequently frequent reaming and circulating trips was needed. Having finished logging in the 8 1/2” section, and just started testing the BOP stack, one of the riser tension sheaves broke and fell down. Also several problems with the hydraulic BOP control system and the ball joint made nearly 12 days rig repair necessary. After this delay the hole required extensive reaming before the 7” liner could be ran and the final 6” section could be drilled. Testing operations were hampered and delayed by bad weather and test equipment breakdown. The well was drilled with spud mud down to 426 m and with seawater/lignosulphonate mud from 426 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well proved gas in sandstones of Middle Jurassic age from top Hugin Formation at 3526 m down to a true gas/water contact at 3662 m, based on logs and RFT samples. The Sleipner Formation was encountered at 3693 m. Logs and RFT pressure gradient proved Sleipner water filled, and ca 3 bar overpressured compared to the Hugin Formation. Shows were described on cores all through the hydrocarbon bearing reservoir. Abundant spots of fluorescence described on cuttings below ca 2000 m are described as “no shows”. According to other comments in the cuttings descriptions the fluorescence may be related to diesel addition to the mud.</span></p> <p class=MsoBodyText><span lang=EN-GB>Nine cores were cut in the interval 3525 to 3663.6 m. A total of 133 m core (96.8%) was recovered. A FIT fluid sample at 3536 m recovered gas, condensate and mud. An RFT fluid sample was taken at 3540 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 11 April 1980 as a gas/condensate appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Three Drill Stem Tests were conducted.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST1 tested the interval 3642 m to 3646.6 m. The final flow was controlled by using two variable chokes mounted in parallel. On the smallest choke size, 2x25/64”, the well produced 583000 Sm3 gas and 181 Sm3 condensate /day. The GOR was ca 3200 Sm3/Sm3, the oil density was 45.3 °API, and the gas gravity was 0.774 (air = 1).</span></p> <p class=MsoBodyText><span lang=EN-GB>DST2 tested the interval 3605 to 3610 m plus 3613 to 3618 m. The final flow was controlled by using two variable chokes mounted in parallel. On the smallest choke size, 2x28.75/64”, the well produced 699400 Sm3 gas and 189 Sm3 condensate /day. The GOR was ca 3700 Sm3/Sm3, the oil density was 45.4°API, and the gas gravity was 0.773 (air = 1). The CO2 content was 9.2%. Maximum temperature during this test was 122.8 °C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST3 tested the interval 3536 to 3546 m. The final flow was controlled by using two variable chokes mounted in parallel. The choke size was kept at 2x45.5/64” throughout the whole flow. The well produced 815500 Sm3 gas and 212 Sm3 condensate /day. The GOR was ca 3850 Sm3/Sm3, the oil density was 40 °API, and the gas gravity was 0.771 (air = 1). The CO2 content was 7.7 %. Maximum temperature during this test was 117.8 °C. </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
326
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7/6/2016 12:00:00 AM
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04.11.2024
|
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15/9-6
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-6 was drilled in the Sleipner Vest area in the Viking Graben of the North Sea. The objective of the well was to test possible hydrocarbons in Middle Jurassic sandstones on the northern flank of the 15/9-Beta structure, and to get more information about the sand distribution in this area.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-6 was spudded with the semi-submersible installation Nordskald on 7 May 1980 and drilled to TD at 3946 m in the Triassic Skagerrak Formation. No significant problem was encountered in the operations. The well was drilled with seawater and pre-hydrated gel down to 465 m, with sweater/gel and SSP lubricant (a vegetable oil) from 465 m to 1140 m, and with gel lignosulphonate/SSP lubricant from 140 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top of the target reservoir sandstones (Callovian age Hugin Formation) was found at 3762 m. This was deeper than expected and below the field gas-water contact. The sandstones were also thinner than expected. Isolated spots of shows on sandstones were described on cuttings and cores from the Hugin and Sleipner formations and the Upper part of the Skagerrak Formation. One cuttings sample from 3346 m in the Blodøks Formation was described with good show on sandstone.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut. Core 1 was cut from 3768.5 m to 3781.4 m in the Hugin Formation (75% recovery) and core 2 was cut from 3810 m to 3814.5 m in the Sleipner Formation (37% recovery). An RFT fluid sample was taken at 3774 m in the Hugin Formation. Laboratory analysis indicated the content to be a mixture of formation water, mud, and fresh water from the water cushion in the sampler. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7 September 1980 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
231
|
7/6/2016 12:00:00 AM
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04.11.2024
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15/9-7
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-7 was drilled as an appraisal well on the south part of the Sleipner Vest Field in the North Sea. The primary objective was to test for hydrocarbons in Callovian age sandstones in the Epsilon structure.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-7 was spudded with the semi-submersible installation Nordraug on 26 December 1980 and drilled to TD at 3776 m in the Middle Jurassic Sleipner Formation. A total of 20 days was spent on waiting on weather. The phase of running BOP after cemented 20" casing took 15 days due to several broken guide wires combined with bad weather. The well was drilled with spud mud down to 465 m, with gypsum/polymer mud from 465 m to 2823 m, and with gel/lignosulphonate/Drispac mud from 2823 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The primary target Hugin Formation was penetrated at 3519 m and proved to hold gas and condensate down to a true gas/water contact at 3673 m based on RFT gas gradients. The gross reservoir thickness was 185 m (3519 to 3704 m) with a net pay of 83 m with 18% porosity and 12 % water saturation. There were no oil shows above top Hugin reservoir level. Oil shows were described on the cores from the reservoir and on cuttings down to 3677 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 156 m core was recovered in 12 cores from the interval 3516 to 3671 m. The core-log depth shift was significant for all cores: from +6.0 to +9.1 meter, the largest shifts are for the deepest cores. Segregated RFT fluid samples were taken at 3560 m (gas, mud filtrate and condensate), 3603 m (gas, mud filtrate and condensate), 3658.5 m (gas, mud filtrate and condensate +dark oil emulsion), 3687 m (mud filtrate, formation water and minor gas), and 3672.2 m (mud filtrate and water). </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29 April 1981 as a gas/condensate appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Three drill stem tests were performed in the Hugin Formation.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST1 tested the interval 3671 to 3674.5 m. It produced 194100 Sm3 gas and 38 Sm3 condensate /day through a 24/64" choke. The GOR was 5107 Sm3/Sm3, the condensate density was 0.797 g/cm3 and the gas gravity was 0.78 (air = 1). The gas contained 7-8% CO2. The maximum temperature in the test was 127.8 °C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST2 tested the interval 3637 to 3638.5 m. It produced 322500 Sm3 gas and 93.2 Sm3 condensate /day through a 24/64" choke. The GOR was 3461 Sm3/Sm3, the condensate density was 0.790 g/cm3 and the gas gravity was 0.775 (air = 1). The gas contained 7-8% CO2. The maximum temperature in the test was 121.1 °C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST3 tested the interval 3555 to 3565 m. It produced 912900 Sm3 gas and 242.8 Sm3 condensate /day through a 64/64" choke. The GOR was 3760 Sm3/Sm3, the condensate density was 0.792 g/cm3 and the gas gravity was 0.775 (air = 1). The gas contained 8-9% CO2. The maximum temperature in the test was 118.3 °C.</span></p> |
218
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7/6/2016 12:00:00 AM
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04.11.2024
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15/9-8
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-8 was drilled on the Delta structure in the southeastern part of the Sleipner West Field in the North Sea. The primary objective was to delineate the hydrocarbon accumulation encountered in the 15/9-4 well on the same structure, and to get further information about the sand distribution in the area. The primary target was Callovian sandstones. Paleocene sandstone was the secondary target.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-8 was spudded with the semi-submersible installation Nortrym on 5 March 1981 and drilled to TD at 3730 m in the Triassic Smith Bank Formation. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 495 m, with gypsum/polymer mud from 495 m to 2845 m, and with a gel/lignosulphonate mud from m 2845 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The sandstones in Paleocene were water bearing. Top of the Callovian sandstone, Hugin Formation, was encountered at 3446 m, while top Sleipner Formation was encountered at 3493 m. Bothe formations proved to be gas/condensate bearing with a gas-water contact at 3564 m based on pressure gradients and well logs. No shows were recorded outside of the hydrocarbon bearing Hugin and Sleipner Formation.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 46.5 m core was recovered in four cores from the interval 3448 to 3499 m. Segregated RFT fluid samples were taken at 3460 m (gas, condensate and mud filtrate), 3561.5 m (gas, condensate and mud filtrate), and 3566.5 m (mud filtrate and a smaller quantity of gas).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 25 May 1981 as a gas/condensate appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One Drill Stem Test was performed from the interval 3450 to 3460.2 m in the Hugin Formation. The test produced 255 Sm3 condensate and 820000 Sm3 gas /day through a 91/64" choke. The gas/condensate ratio was 3200 Sm3/Sm3, the condensate gravity was 0.78 g/cm3, and the gas gravity was 0.74 (air = 1). The CO2 content was 6-7%. The DST temperature was 121 °C. </span></p> |
327
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7/6/2016 12:00:00 AM
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04.11.2024
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15/9-9
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 15/9-9, was drilled on the Sleipner Terrace in the North Sea. The primary objective was to test possible hydrocarbons in Jurassic sandstones on the 15/9-Gamma structure and to get more information about the sand distribution in the area.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-9 was spudded with the semi-submersible installation Nordraug on 4 May 1981 and drilled to TD at 3044 m in the Early-Middle Permian Rotliegendes Group. No significant problems were experienced in operation, logging or testing of the well. The well was drilled with seawater and pre-hydrated gel down to 501 m, with gel/lignosulphonate from 501 to 1155 m, with gypsum/polymer mud from 1155 m to 2540 m, and with gel/lignosulphonate from 2540 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The primary objective, the Jurassic, was thinner than expected and consisted of Late Jurassic Viking Group shales only. The well, however, proved gas and condensate in the Heimdal Formation. The Heimdal Formation was reached at 2322 m. It consisted of sand of fairly good reservoir properties interbedded with some thin shale beds. The whole sand interval was hydrocarbon bearing and no water contact was located. In addition, the well proved residual hydrocarbons over the interval 2648 to 2738 m on cores from the Triassic Skagerrak Formation. </span></p> <p class=MsoBodyText><span lang=EN-GB>Seven cores were cut. The interval 2648 to 2756 m was cored in six cores with 98 - 100% recovery. A seventh core was cut from 3032 to 3043.5 m with 96% recovery at TD. RFT segregated samples were taken at 2323 m (condensate and mud filtrate) and 2648 m (water and mud filtrate, no gas or condensate). Repeated attempts to sample in the interval 2401 to 2414 all failed due to plugging of probe by unconsolidated sand.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 14 July as a gas/condensate discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Three drill stem tests were performed. </span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 2414 to 2421 m. This test gave no flow to surface and it was aborted due to malfunctioning downhole valves. The maximum downhole temperature measured by the gauges was 85.6 °C</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 2386 to 2392 m. This test produced 286 Sm3 condensate and 586200 Sm3 gas /day through a 1.0" choke (max flow). No H2S and only traces of CO2 was measured. The GOR was 2050 Sm3/Sm3, the condensate gravity was 57.7 °API and the gas gravity was 0.734. The bottom hole temperature measured by the Flopetrol gauge was 87.8 °C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 3 tested the interval 2323 to 2333 m. This test produced 272 Sm3 condensate and 587000 Sm3 gas /day through a 1.0" choke (max flow). No H2S and only traces of CO2 was measured. The GOR was 2160 Sm3/Sm3, the condensate gravity was 60.7 °API and the gas gravity was 0.740. The maximum down hole temperature measured by the gauges was 93.9 °C.</span></p> |
328
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7/6/2016 12:00:00 AM
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04.11.2024
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16/10-1
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<p><b>General</b></p> <p>Well 16/10-1 was the first well drilled in block 16/10 operated by Norsk Agip. Among the various structures defined within block 16/10, the one called "Alpha", located in the southwestern area, was selected as the first one to be drill. Main reason for this choice was the presence of a deep basin (Witch Ground Graben) to the south west of the block, where the Viking Group shales was believed to have generated hydrocarbons since Cretaceous time. The tectonic evolution of the structure is probably of pre-Cretaceous age, well before hydrocarbon generation started.</p> <p>The purpose of the well was to explore all main reservoirs down to Triassic. The primary targets were the Jurassic and Triassic sandstone units, expected at 2850 m and 2980 m, respectively. Prognosed TD was at 3175 m.</p> <p><b>Operations and results</b></p> <p>Wildcat well 16/10-1 was spudded 25 May 1986 by Dyvi Offshore A/S semi-submersible rig Dyvi Stena and drilled to TD at 3151 m in the Late Permian Zechstein Group. The well was drilled with Seawater and hi-vis pills down to 514 m, with KCl/Polymer mud from 524 m to 2565 m, and with lignosulphonate mud from 2565 m t TD. Drilling proceeded without any significant problems. Electrical logs were run already in the 26" section from 195 m. No shallow gas was encountered. </p> <p>The Quaternary/Tertiary sequence, 2280.5 m thick, is represented by Nordland, Hordaland and Rogaland groups and is predominantly constituted by marine claystones. A 513.5 m Cretaceous section represented by the limestones of the Chalk Group and by the reddish marl and calcareous shales of the Cromer Knoll Group was penetrated. It was nearly a complete sequence except for two possible hiatus: the first in the Late Santonian and the second between the Cenomanian and the Aptian-Albian. The base Cretaceous Unconformity overlies the Late Jurassic shales of the Viking Group (top at 2794 m), which proved to have a thickness of 211 m. The top of the Jurassic sandstones of the Vestland Group was encountered at 3005 m. The "Oxfordian Sandstone Unit" (Hugin Formation) was 33m thick with very good reservoir properties. Below this was a 15 m thick "coal unit" of the Sleipner Formation, containing a major coal sequence with interbedded carbonaceous claystone/shale. Below the Mid Kimmerian Unconformity, a 58 m thick sequence of arenaceous sediments of the Triassic Skagerrak Formation was drilled. The interval was a monotonous sequence of clastics, with the typical continental red iron colour. At 3116 m the top of the Permian evaporites of the Zechstein Group was touched and penetrated until the depth of 3151 m (TD). Two cores were cut in the Heather Formation, the first from 2855 m to 2873 m, and the second from 2925 m to 2934 m. No fluid samples were taken. The well was permanently abandoned on 14 July 1986 as a dry hole.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
901
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7/6/2016 12:00:00 AM
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04.11.2024
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16/10-2
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<p><b>General</b></p> <p>Block 16/10 is located in a structurally complex area between the Viking Graben, the Central Graben, the Witch Ground Graben and the Ling Graben. Well 16/10-2 is the second well drilled in block 16/10 PL 101 operated by Norsk Agip; the first one 16/10-1 was drilled May-July 1986. The purpose of the well was to test the hydrocarbon potential of the "Delta" structure located in the west part of 16/10 block. This structure is a tilted fault block elongated north-south bounded to the west by a north-south trending normal fault, and dip-closing to the north, east and south. It was interpreted as the largest structure in block 16/10 in terms of possible oil reserves. The structure is not salt-induced and being one of the oldest in this area it was also considered prospective for possible early migration. The Upper Jurassic and the Lower Cretaceous shales constituted the seal rocks for the geological model. The main and the secondary targets were respectively the "Oxfordian Sandstones" (Upper Jurassic) and the Triassic sandstones of the Skagerrak Formation that had been found hydrocarbon bearing in the nearby blocks in wells 6/3-1, 15/12-5, 15/12-4, 15/12-8, 15/12-6 and 16/7-4.</p> <p><b>Operations and results</b></p> <p>Exploration well 16/10-2 was spudded with the semi-submersible installation Byford Dolphin on 20 June 1991 and drilled to a total depth of 3150 m in the Triassic sandstones of the Skagerrak Formation. The well was drilled with seawater and gel down to 417 m, with Seawater and gypsum polymer from 417 m to 2798 m and with Bentonite/Anco Temp mud from 2798 m to TD.</p> <p>The Quaternary/Tertiary sequence constituted predominantly marine claystones of the Nordland, Hordaland and Rogaland Groups. The Cretaceous sequence was mainly represented by limestones of the Chalk Group and by the reddish claystones and calcareous marls of the Cromer Knoll Group that overlay the Base Cretaceous Unconformity found at 2818 m. The Upper Jurassic sequence consisted of 35 m darkish/brown shales belonging to the Draupne Formation overlying 70 m of the "Oxfordian Sandstones" (Hugin Formation). This reservoir showed a larger sand development than in 16/10-1 well where only 33 m sand was encountered. The top of the "Oxfordian Sandstones" was encountered at 2853 m. Below the sand, from 2923 m to TD, Triassic continental sandstones of the Skagerrak Formation were encountered. The geological results of 16/10-2 well were in good agreement with the structural and stratigraphic models expected. The targets (i.e. Oxfordian Sandstone and Skagerrak Fm.) were found water bearing and no hydrocarbon bearing level or relevant shows were encountered in the well. Conventional cores were not taken. A RFT segregated sample at 2876 m recovered only water and mud filtrate.</p> <p>The well was permanently abandoned as a dry well on 1 August 1991.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
1767
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7/6/2016 12:00:00 AM
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04.11.2024
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16/10-3
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<b>
General </b> <p> Well 16/10-3 was drilled as an exploration well on the "Tyr Central prospect" located near the block boundary in the northeast part of the Block in Production License 101. The licence was awarded in 1985, after the 9th concession round. </p> <p> The purpose of drilling well 16/10-3 was to test the hydrocarbon potential of the Middle Jurassic/Triassic reservoir (Hugin and Skagerrak Formations) in the Tyr structure. The tested structure consisted in several culminations with a common dip closure. The well location was set on the largest of these, called "Tyr Central". The well was drilled by Norsk Agip as operator and was a joint well with the licence holders of PL 072. </p> <b> Operations and results </b> <p> Exploration well 16/10-3 was spudded with the jack-up installation "Transocean Nordic" on 22 October 1996 and drilled to a total depth of 2850 m in the Triassic Smith Bank Formation shales. The well was drilled/cased/logged and abandoned in 40 days but due to WOW (wait on weather) the rig was not released from its contract and moved off location until the 6 December 1996 after a total of almost 51 days. The well was drilled with spud mud down to 196 m, with Seawater and PAC hi-vis sweeps from 196 m to 431, and with KCl / PAC glycol mud from 431 m to TD. </p> <p> All the expected formations were encountered. The Jurassic/Triassic sands were found with fair reservoir quality. The expected reservoir was encountered at 2521 m, 31 m deeper than prognosis. The Hugin-Skagerrak sands were found water bearing and no hydrocarbon shows were detected. No relevant gas amounts were recorded in the well and no hydrocarbon shows were identified on cuttings in the reservoir section. Two FMT fluid samples were collected at two different depths: the recovery was mud filtrate in the first sample at 2522 m and mud in the second one at 2544.3 m. No conventional cores were cut in this well. The well was permanently abandoned as a dry well on 1 December 1996. </p> <b> Testing </b> <p> No drill stem test was performed. </p> |
2703
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7/6/2016 12:00:00 AM
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04.11.2024
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16/10-4
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<b>
General </b> <p> Well 16/10-4 was drilled on the Trond prospect located in the northeast part of PL 101, which is southeast of the existing Sleipner field. The prospect was a north-south elongated salt-induced structure with dip closure in all directions. The main purpose was to test the hydrocarbon potential within the upper Jurassic (Hugin) formation in the prospect and to obtain representative cores of that sand package. </p> <b> Operations and results </b> <p> The jack up installation "Transocean Nordic" arrived on location on June 25 1998. Spud was significantly delayed due to insufficient leg penetration. Gravel boats had to be employed to dump gravel around the spud cans. This operation took 141 hours. With the gravel dumping completed, the weather became rough and the spud cans could not be lifted according to the plan. It took 162 hours before the weather was sufficiently calm to proceed with the pre-loading. Exploration well 16/10-4 was finally spudded on July 11 1998 and drilled to a total depth of 2580 m in Permian Zechstein anhydrites. The well was drilled with seawater and bentonite sweeps down to 380 m, with KCl / PAC mud from 380 m to 1230 m, and with KCl /PAC / glycol mud from 1230 m to TD. </p> <p> All the formations encountered from top Balder were found above prognosis due to anomalous velocities in the gas chimney drilled by this well. The reservoir target (Hugin Formation) was encountered at 2474 m. (80 m below prognosis). The petrophysical properties of the reservoir were found to be good. The only interval with some gas shows was the Rogaland Group (1792-1888 m) where the total gas was between 2.6 and 4.4 % Ci-nC4, but no reservoir was encountered at this level. No direct shows were observed in the Hugin Formation and the total gas was below 0.1%. From FMT measurements, log analysis and all the information collected during the drilling phase, the reservoir was found to be water bearing. However, onshore geochemical analysis by Eni central laboratories in Milan reported significant traces of migrated hydrocarbons in core samples from 2478 to 2496 m and high levels of phenols with possible traces of altered oil in the FMT water sample. </p> <p> One core was cut from 2477 to 2504 m in the soft, unconsolidated Hugin Formation (Previous wells in the area suffered no core recovery). The median porosity of the core was 25% and the median permeability was 260 m. Eight FMT pre tests and one segregated sample were taken from the Hugin reservoir. All pressure tests were good and gave a clear water gradient of 0,102 bar/m in the reservoir. The sample recovered was a mixture of mud filtrate and formation water. </p> <p> The 16/10-4 well was permanently abandoned on 10 August as a dry well. </p> <b> Testing </b> <p> No drill stem test was performed. </p> |
3531
|
7/6/2016 12:00:00 AM
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04.11.2024
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16/10-5
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/10-5 was drilled on the Isbjørn prospect in the northern end of the Jæren High in the North Sea. The Isbjørn Prospect was mapped as a four-way dip-closure structure. The primary objective of the well was to test the hydrocarbon potential in the Late Jurassic Ula Formation sandstones.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/10-5 was spudded with the jack-up installation Mærsk Giant on 6 October 2012 and drilled to TD at 3034 m in the Middle Jurassic Bryne Formation. A 12 1/2” pilot hole was drilled from below the 30” conductor to 1057 m to check for shallow gas. No shallow gas was seen. Drilling of the 8-1/2” section was troubled with junk in the hole ending up with two additional clean-out runs; else, operations proceeded without significant problem. The well was drilled with seawater and sweeps down to 180 m, with KCl/GEM/Polymer mud from 180 m to 1057 m, and with Enviromul oil based mud from 1057 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated 98 m of radioactive Mandal Formation shales directly overlying the Ula Formation. The Ula formation came in at 2929 m, which was 65 m shallower than the prognosis. One hundred and six m of good quality sand was penetrated but it was water filled without shows and gas values were low. RCI pressure data points indicate a common formation water gradient, with no likely internal pressure barriers, for both Ula and Bryne Formations.</span></p> <p class=MsoBodyText><span lang=EN-GB>No conventional or sidewall cores were taken. The RCI tool was run for pressure points, but no fluid samples were taken. Maximum static temperatures was measured in the reservoir on wireline RCI run was 124 ºC at 3039 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 27 November 2012 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7021
|
4/11/2017 12:00:00 AM
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04.11.2024
|
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16/1-1
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<p><b>General</b></p> <p>Well 16/1-1 is located roughly midway between the Gudrun Discovery and the Balder Field in the North Sea. This early wildcat well had the general objective to: " -test the hydrocarbon potential and investigate the lithology in this portion of the North Sea basin".</p> <p>The well is Type Well for the Utsira Formation.</p> <p><b>Operations and results</b></p> <p>Wildcat well 16/1-1 was spudded with the semi-submersible installation Ocean Traveler on 26 September 1967 and drilled to TD at 3203 m in the Late Cretaceous Hod Formation. No significant problems were reported from the operations. Initial drilling from the sea floor to 392 m was with seawater and gel without casing. Returns were to the sea floor. Below 392 m to total depth, a seawater slurry with Bentonite, Zeogel, Spersene, XP-20, Caustic Soda, and 0-12% diesel oil was used.</p> <p>Porous sandstone was observed in the Miocene, Oligocene, and Eocene. There were also Paleocene sands in the well. Traces of possible residual oil stain were encountered in cuttings and cores from the Oligocene and Eocene. In addition, questionable shows (non-fluorescent dead oil) were reported on cores from the Paleocene. However, neither the hot wire gas indicator nor chromatograph suggested the presence of hydrocarbons. </p> <p>A total of 18 cores were cut from the different formations within the Hordaland, Rogaland, and Shetland Groups, recovering a total of 171 m core. The depth for core 2 is probably incorrect, possibly be five meter shallow due to malfunction of the bumper subs. FIT wire line fluid samples were taken in potential hydrocarbon-yielding beds at 1878.5 m, 2532.9 m, and at 2592.3 m. Only water and mud were recovered. </p> <p>The well was permanently abandoned on 10 December 1967 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
147
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5/19/2016 12:00:00 AM
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04.11.2024
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16/1-10
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-10 was drilled on the eastern margin of the South Viking Graben on the south-western part of the Utsira High in the North Sea. It was drilled to confirm the northern extent of the Luno oil discovery in Early Jurassic conglomerates made by well 16/1-8. The oil-water contact at 1965 m TVD RKB should be confirmed and a production test of the clean sand facies and conglomeratic facies should be conducted.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-10 was spudded with the semi-submersible installation 16/1-10 on 13 November 2008 and drilled to TD at 2151 m in conglomeratic sandstones of Early Jurassic age. As the site survey revealed a number of possible shallow gas zones the well started with a 9 7/8" pilot hole to check for shallow gas down to 400 m, TD of planned 26" section. No gas was seen in this interval. Due to a leak in the 20" casing the casing programme was significantly revised, with 13 3/8" casing set at 589 m, above a potential shallow gas zone at 634 m, and the 12 1/4" hole was drilled down into top Shetland Group. This slimmer-than-planned hole turned out to give easier drilling than in the previous well on the prospect (16/8-1). The amount of down time was however comparatively large, due mainly to wait-on-weather. Additional coring also added to a longer than planned time for this well. The well was drilled with seawater and hi-vis bentonite sweeps down to 411 m, with KCl/glycol enhanced mud from 411 m to 1860 m, and with Performadril water based mud with 5% glycol from 1860 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Utsira, Skade and Grid sandstone formations were penetrated by the well, all water bearing. The top of the Jurassic reservoir sequence was encountered at 1898 m (1872.9 m TVD MSL), 11.4 m TVD deeper than prognosed. The reservoir sequence was composed of oil bearing sandstones and conglomerates with an OWC at 1965 m. No gas cap was observed on the logs or could be inferred from the production testing. The first hydrocarbon shows in well 16/1-10 were observed in the core chips collected in the Shetland Group limestones that overlie the reservoir. Generally good hydrocarbon shows were observed in the reservoir from 1898 m down to 1911 m. From 1911 to 1928 m the hydrocarbon shows became more patchy due to widespread argillaceous infilling of the pore spaces within the sandstone matrix. More consistent shows were present in the interval from 1929 to 1940 m but below this depth only intermittent shows were observed.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 7 cores were cut from 1868 to 1987.5 m. The first two cores were cut entirely within the Shetland Group. The third core penetrated top reservoir at 1898 m. The entire hydrocarbon bearing part of the reservoir interval was cored with the last core penetrating the oil-water contact. Four wire line logging runs were made including one MDT run for samples and pressures. Oil samples were taken at 1899.6 m and 1933.1 m and a water sample was taken at 2024.9 m. Fluid gradients were established for both water and oil zones, indicating an oil-water contact at 1965 m TVD, confirming the contact extrapolated in well 16/1-8. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 5 February as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two Jurassic intervals were production tested. DST 1A was performed in the interval 1919.92 to 1958.11 m in the conglomeratic sandstone facies.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1B was performed in the interval 1897.00 to 1909.79 m in addition to 1919.92 to 1958.11 .The test rate was 338 Sm3 oil per day and 35500 Sm3 gas per day through a 12,7 mm choke.</span></p> <p class=MsoBodyText><span lang=EN-GB>Maximum temperature recorded in the tests was 82.1 deg C.</span></p> |
5879
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/1-11
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-11 was drilled to appraise the 16/1-9 discovery on the Gudrun Terrace just west of the Utsira High in the North Sea. The discovery well 16/1-9 was completed in April 2008 and revealed oil shows in the Middle Jurassic Vestland Group, but neither coring or logging was completed according to programme due to hole problems. The extent and reservoir quality of the Sleipner Formation in the Vestland Group was a primary objective in the data acquisition programme for 16/1-11 and an extensive wire line logging suite was planned in order to get as much information as possible regarding the oil-water contact, depth conversion, reservoir thickness, facies, fluids, well productivity and possible barriers in the reservoir. The Sleipner Formation reservoir was prognosed to be 75 m thick and coring of the hydrocarbon bearing part of the reservoir was decided prior drilling. Planned TD was TD at 2579 m, approximately 100 metres below prognosed base of the Sleipner Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-11 was spudded with the semi-submersible installation Songa Delta on 23 February 2010. The 8 1/2" section in was drilled to TD at 2625 m in the Skagerrak Formation. After logging problems with setting and cementing the 7" liner made it necessary to make a sidetrack, 16/1-11T2, in order to do a drill stem test. The 8 1/2" sidetrack was kicked off from 2193 m and drilled to 2532 m (2523 m TVD). The sidetrack was drilled deviated with up to 20 deg deviation at its TD. The well was drilled with seawater down to 603.5 m, with Aqua-drill mud with 6% glycol from 603.5 to 1770 m, and with Carbo-Sea oil based mud from 1770 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Hydrocarbons were proven in the Sleipner and Skagerrak formations. Top Sleipner Formation came in at 2380.5 m. It consisted of 20 m coarse fining upward sandstones and contained gas. Analysis of core and log data showed good reservoir quality with calculated average effective porosity of about 19% and an average gas saturation of 31%. The Net Pay/Gross was nearly 1.0. The Skagerrak Formation came in at 2400.5 m. The core and log analysis proved a much lower reservoir quality than in the Sleipner Formation, mainly due to carbonate cementation. No contacts could be interpreted from the logs but pressure data gave a gas/oil contact at 2377.8 m TVD MSL. The log and pressure evaluation showed oil down to 2438 m (2409 m TVD MSL) and water up to 2445 m (2416 TVD MSL) in the Skagerrak formation. There were no pressure barriers between the Sleipner and Skagerrak formations. The deepest oil staining and fluorescence was recorded at 2502.8 m. </span></p> <p class=MsoBodyText><span lang=EN-GB>Five 90 ft cores were cut in the interval 2385.5 m to 2522 m with practically 100 % recovery. Fluid samples were taken with the RCI tool. Gas samples were taken at 2396 m and 2406 m while oil samples were taken at 2408.8 m and 2437.8. A water sample was taken at 2454.1 m. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged back for a geological sidetrack on 26 April as an oil and gas appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One DST was performed in the sidetrack. It was perforated from 2415 - 2425 m, underbalanced with TCP. It flowed 177 Sm3 oil /day through a 28/64" choke. The oil density was 0.835 g/cm3 and GOR was 127 Sm3/Sm. Initial formation pressure was 244.75 bar at reference depth 2377.8 m TVD MSL. Initial formation temperature at this depth (DST temperature) was 98 deg C.</span></p> |
6157
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4/11/2017 12:00:00 AM
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04.11.2024
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16/1-11 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-11 and the subsequent 16/1-11 A sidetrack was drilled to appraise the 16/1-9 discovery on the Gudrun Terrace just west of the Utsira High in the North Sea. The discovery well 16/1-9 was completed in April 2008 and revealed oil shows in the Middle Jurassic Vestland Group, but neither coring or logging was completed according to programme due to hole problems. In well 16/1-11, the Sleipner Formation proved to be hydrocarbon bearing with a gas cap of approximately 25 m thickness and a gas-oil contact interpreted at approximately 2407 m in the Skagerrak Formation. However, acquisition of pressure data and sampling in the water zone in the Skagerrak Formation proved to be difficult due to very low porosity and permeability. Thus, no reliable water gradient could be established from the RCI sampling programme. </span></p> <p class=MsoBodyText><span lang=EN-GB>The 16/1-11 A geological sidetrack was drilled down flank on the structure. The main objectives were to obtain pressure samples in order to delineate the oil/water contact and to obtain water samples from the Skagerrak Formation in order to establish reservoir properties. A sidetrack would also give useful facies and thickness variation input. Another objective was to acquire sidewall cores to pin down the expected hiatus on top of the Sleipner Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-11 A was drilled with the semi-submersible installation Songa Delta. It was kicked off on 26 April 2010, with kick-off point at 1744 m in the parent well. It was drilled to TD at 2595 m (2528 m TVD), 94 m MD into the Late Triassic Skagerrak Formation. The well was drilled with Carbotech oil based mud from kick-off to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The reservoir of the Sleipner Formation was penetrated at 2476 m (2393.2 TVD MSL) approximately 300 m down flank westward relative to the parent well, with an inclination of 27.6 degrees. Pressure data proved an oil gradient throughout. Top Skagerrak formation was penetrated at 2500.5 m (2414.9 m TVD MSL). Gas and oil shows were present through the reservoir interval and a possible OWC at 2526.1 m (2433.6 m TVD MSL) in the Skagerrak Formation was defined by pressure points and fluid samples. Oil shows above the OBM was recorded down to 2533 m. </span></p> <p class=MsoBodyText><span lang=EN-GB>The planned wire line logging program including pressure points, fluid samples, mini-DST and sidewall cores was performed. No conventional cores were cut. RCI oil samples were collected at 2478.02 m and 2510.52 m. Contamination from oil base in these samples was estimated to be between 2.5% and 8.5% by weight. Draw-down was 1.6 to 4.0 bar. RCI samples with both oil and water was collected at 2521.13 m. In these samples the mud contamination was estimated to be ca 76% by weight and the draw-down was 66 - 70 bar. Water samples were collected at 2522.1 m during a mini-DST with the MRCH-JAR-TTRm-GR-Straddle packer-Observation probe.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 9 May 2010 as an oil and gas appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6364
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4/11/2017 12:00:00 AM
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04.11.2024
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16/11-1 S
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<p>Well 16/11-1 S is located in the Danish Norwegian Basin. The objective of the well was to test the hydrocarbon potential of the Tertiary, Mesozoic and Permian sediments. Specifically, Tertiary sandstones, Cretaceous sandstones and limestones, Jurassic and Triassic sandstones, Permian carbonates and Permian Rotligendes sandstone were considered to be prospective.</p> <p><b>Operations and results</b></p> <p>Wildcat well 16/11-1 S was spudded with the semi-submersible installation Ocean Viking on 17 July 1967 and drilled to TD at 3050 m (ca 3020 m TVD RKB) in the Late Permian Zechstein Group. The well is classified as deviated, but was not meant to be. During reaming operation at about 1463 m the hole was accidentally sidetracked. This was not discovered until 13 3/8" casing was set and the cement plug drilled through. Hole deviation was then determined to be 16 deg at the casing shoe. In order to prevent a dogleg the deviation was gradually decreased to 12.5 deg at about 2322 m and stabilized at an average of 12 deg to TD. The dip meter log indicates that the hole drifted in a N 45 deg E direction. While drilling at 2952 m the drill string stuck and a fish was left in the hole. A cement plug was set and the fish was bypassed by sidetracking with jet action from the bit. Upon reaching 2952 m, the pipe stuck a second time, which resulted in leaving a new fish. A second cement plug was set and the hole sidetracked using a Neyrpic turbine drill. The pipe stuck a third time at 2954 m and another fish was left. The hole was again sidetracked and mud weight increased to about 16 ppg. Drilling then continued to TD, before 9 5/8" casing was set. Circulation was lost immediately after drilling through the 9 5/8" casing shoe at 2957 m. Five Diaseal "M" squeezes and five DOC squeezes were performed in an attempt to regain circulation with a 16.0 ppg mud, but all attempts were unsuccessful. A Drispac/Flosal/Desco mud system was used to a depth of 2326 m. At this depth the system was converted to a Sodium Chloride -saturated Drispac/Flosal/Sodium Sulphate system. The salt-saturated mud system was used to total depth.</p> <p>The Tertiary section consisted mainly of clays and shales. Fairly high methane percentages were recorded by the chromatograph in the shaley lower part of this section as the section was drilled. Two zones within the Mesozoic were encountered which could be prospective reservoirs in other areas. These zones were the middle part of the Late Cretaceous chalk and the sandstones of the Early Jurassic. No shows were observed in either zone, but permeability was indicated in the Late Cretaceous chalk by a small salt-water inflow. Electric log calculations of the Early Jurassic sandstones indicated an average porosity of 23 percent and 100 percent water saturation. No sidewall or conventional cores were taken and no fluid samples collected.</p> <p>The well was permanently abandoned on 31 October 1967 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
112
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5/19/2016 12:00:00 AM
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04.11.2024
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16/1-12
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-12 was drilled south of the Luno Discovery on the south-western part of the Utsira High. The Luno Discovery sits in an inlier basin where well 16/1-8 Luno Discovery well proved a 275 m thick Late Triassic to Jurassic sequence, overlain by a 25 m thick Late Cretaceous chalk sequence. The purpose of the well is to prove oil-filled sediments of Late - Middle Jurassic fluvial/marine and pre-Jurassic sediments south of the established Luno sediment basin. The potential reservoir was expected from the top of the Jurassic conglomeratic sandstones to the base of the Triassic sandstones and conglomerates (TD). </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well was spudded with the semi-submersible installation Songa Dee on 29 July 2009 and drilled to TD at 2055 m in pre-Devonian Basement rock. The well was drilled with seawater and sweeps down to 603 m and with Glydril mud from 603 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-12 proved oil in weathered and faulted/fractured granitic basement beneath a thin, 20 - 30 cm, Early Cretaceous conglomerate. An oil/water contact was established at approximately 1954 m. An extensive data acquisition program was undertaken and the oil column was confirmed by oil sampling, pressure measurements and observations in both cores and sidewall cores. The weathered and fractured basement showed moderate reservoir characteristics with an average porosity of 9% and an average permeability of 1 mD. As fractured basement plays are rare on the Norwegian continental shelf, a large uncertainty applied to both reservoir properties and the lateral outline of the discovery. The latter being due to seismic image quality and to difficulties mapping the fracture/fault density. </span></p> <p class=MsoBodyText><span lang=EN-GB>The first oil shows in well 16/1-12 were observed in Core 4 at 1912 m after penetrating the thin, Cretaceous age, conglomerate layer below the Cromer Knoll marls. Moderate oil shows continued throughout the remainder of the cored interval, which consisted of fractured basement rocks. In cuttings from the subsequent drilling below the cored interval oil shows were more difficult to detect, however, poor shows were reported down to 1956 m. Oil was present in both the fractures and in secondary pore spaces.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 8 conventional cores were taken in well 16/1-12. As planned, coring operations commenced at 1864 m in the Shetland Group limestones in order to core the transition into the reservoir. Mini DSTs were performed at 1922.5 m, 1946.8 m, and 1956.6 m. Test interpretation indicated permeability ranges of 2-30 mD, 5-100 mD, and approximately 700 mD respectively, for the three tests. Oil samples were obtained from the first two DSTs and water from the last.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 8 September 2009 as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
6166
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4/11/2017 12:00:00 AM
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04.11.2024
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16/11-2
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<p><b>General</b></p>
<p>The Anchovy (16/11-2) well was drilled on a semi-domal structure, about 5 miles long and 4 miles wide situated in the Danish-Norwegian Basin. It was estimated that at Paleocene depth there would be 12 square miles of closure with 150 m vertical relief and at Jurassic depth, 9 square miles of closure with 370 m vertical relief. The principal objective horizons were the Jurassic and Paleocene sands.</p> <p><b>Operations and results</b></p> <p>Wildcat well 16/11-2 was spudded with the semi-submersible installation Ocean Viking and drilled to TD at 2378 m in Late Permian Zechstein salt. </p> <p>No Paleocene sands were encountered. As expected the Danian Chalk section was missing in the well. The Upper Cretaceous Limestone was tight with no shows. The Jurassic sand top was encountered at 2202 m with the main sand development beginning at 2207 m. The net sand thickness was 35 m, but on testing was found to be tight and unproductive. The total Jurassic section was about 244 m thinner than anticipated. The Triassic was missing. An 11.5 m Dolomite section was developed from 2250 m to 2261.5 m at the top of the Permian succession. This was also tested, but found to be tight and unproductive. Thus the well was terminated in the Zechstein higher than planned. Except for the reduced Jurassic sequence and absence of Triassic sediments causing the higher position of the Zechstein, the structure and stratigraphy were as predicted in the prognosis. Geochemical analyses of shales from the Late Jurassic Tau Formation proved excellent source potential, but the kerogen is immature to marginally mature in the well location. No cores were cut. The well was permanently abandoned as a dry well on 23 July 1973.</p> <p><b>Testing</b></p> <p>Two intervals in the Sandnes Formation were perforated and tested, 2261 m to 2251 m and 2242 m to 2231 m. Both intervals were found tight and unproductive and no hydrocarbons were produced during the tests.</p> |
336
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7/6/2016 12:00:00 AM
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04.11.2024
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16/1-13
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-13 was drilled to appraise the Luno Discovery on the southern part of the Utsira High in the North Sea. The Luno discovery was made after drilling the 16/1-8 well in 2007 and confirmed by the appraisal well, 16/1-10. The objectives of well 16/1-13 were to confirm the resource estimates for the Luno Discovery, prove the presence of Jurassic sediments with good reservoir properties, and to improve understanding of the reservoir facies distribution.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-13 was spudded with the semi-submersible installation Transocean Winner on 30 November 2009 and drilled to TD at 2303 m in the Late Triassic Hegre Group. A precautionary 9 7/8" pilot hole was drilled from seabed to a depth of 606 m MD RKB. MWD logs in the pilot hole confirmed that all permeable formations were water bearing and shallow gas was not present. Minor gas sands were observed in the main bore at 631 and 726 m, but no gas flow occurred. The well was drilled with Seawater and hi-vis pills down to 606 m and with Glydril mud with 4 - 6 % glycol from 606 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-13 proved a 50 m oil column in Jurassic / Triassic sandstones with excellent reservoir characteristics. The pressure at the top of the reservoir was measured at 193.2 bar (equivalent to a gradient of 1.028 g/cc). Pressure measurements and samples established an oil gradient of 0.069 bar/m with an oil-water contact at 1966.5 m (1939 m TVD MSL). A water gradient of 0.101 bar/m was established below the OWC. The water zone lithology consisted of sandstones and conglomerates, the latter of relatively poor reservoir quality. The first oil shows in well 16/1-13 were observed in the shale at the top of core number 2 at 1918 m. From 1967.4 m (1965.4 m TVD) in core number 4 the sandstones became thickly interbedded with tightly cemented conglomerates. The latter did not contain any visible hydrocarbon shows; however shows were present within the sandstone layers down to 1972.7 m (1970.7 m TVD). Below this depth and above reservoir level no oil shows were seen.</span></p> <p class=MsoBodyText><span lang=EN-GB>An extensive data acquisition program was undertaken. In total five cores were cut from 1917.0 to 2001.1 m with 97 % total recovery. Four cores covered the complete oil column and one core was taken in the water zone. MDT fluid samples were taken at 1924.5 m (oil), 1965 m (oil), 1967.2 m (water and trace oil), and 1973 m (water and trace oil).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 21 January 2010 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
6232
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/1-14
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-14 was drilled to explore the Jurassic Apollo Prospect situated south of the Draupne Discovery and down flank of the Luno Discovery. The well is located on the eastern margin of the South Viking Graben in the North Sea. The structure is situated between eastern part of the Gudrun Terrace and the western flank of the Utsira High.</span><span lang=EN-GB> </span><span lang=EN-GB>The primary objective was to test the Vestland Group, Hugin Formation sands and to verify communication with the 16/1-9 Draupne Discovery. A thickening and improving reservoir quality in the Hugin Formation, when compared to well 16/1-9 was expected towards the Apollo. Prospect.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-14 was drilled with the semi-submersible installation Transocean Winner. First a 9 7/8" pilot hole was drilled to 606 m. This hole was abandoned due to shallow gas and it was named 16/1-U-6. Wildcat well 16/1-14 was spudded ca 15 m west of 16/1-U-6 on 26 September 2010 and drilled to TD at 2550 m in Late Triassic sediments of the Skagerrak Formation. As the Cretaceous to Eocene hydrocarbon bearing reservoirs were insufficiently logged and cored a sidetrack was decided. The 16/1-14 T2 sidetrack was made through a window in the 9 5/8" casing at 1800 m. The sidetrack was drilled to TD at 2295 m (2293.4 m TVD) in the Late Jurassic Draupne Formation. The well was drilled with seawater and hi-vis sweeps down to 378 m and with Glydril mud from 378 m to TD in both well tracks. </span></p> <p class=MsoBodyText><span lang=EN-GB>The primary objective of the well was not realised because the Hugin Formation was found to be dry. However, well 16/1-14 encountered oil in three levels, the Balder Formation, the Heimdal Formation and one in the Lower Cretaceous (Berriasian to Valangian) Åsgard Formation. Free water levels were estimated to be at 2004 m (1978 m TVD MSL) in the Paleocene (Balder-Heimdal) discovery and at 2181 m (2155 m TVD MSL) in the Lower Cretaceous Åsgard discovery. In well 16/1-14 several thin sands were encountered in the Lista Formation. The sands were oil-filled and displayed moderate properties from log analysis. However, no fluid gradients could be acquired from pressure-points. In the sidetrack, 16/1-14 T2, the corresponding sand intervals were found to be missing or to be thinner. In the Heimdal Formation 6.5 to 7 m net sand of good quality was interpreted from the logs. Oil was confirmed by sampling. In the Åsgard Formation, a 9 m interval of very good sand was oil filled. Mobilities derived from the MDT results showed up to 3500 mD/cp. A water filled Intra Draupne Formation sandstone was found 16 m thick in the primary well bore, but was only 4 m thick in the sidetrack, indicating a pinch-out of this sand towards the south-west. The primary target Hugin Formation came in at 2472 m; deeper than prognosed and water bearing. However, oil shows were recorded from 2472 m to 2495 m. Weak oil shows were also recorded in intervals in siltstones and claystones of the Draupne and Heather formations. </span></p> <p class=MsoBodyText><span lang=EN-GB>Three conventional cores were cut in the main wellbore from 2373 m to 2454.6 m, and four additional cores were cut in the sidetrack from 2052 m to 2101 m and from 2167 m to 2221.46 m. In 16/1-14 fluid scanning (LFA) confirmed oil at 2063.3 m, and at 2098.1 m, where 3 oil samples were acquired. A further MDT water sample was acquired at 2491.5 m. In the sidetrack MDT oil samples were acquired at 1998 m (Balder Formation), 2002.8 m (Balder Formation), 2102.2 m (Heimdal Member) and 2174 and 2178.8 m (Åsgard Formation). MDT water samples were acquired in the sidetrack at 2106 m (Heimdal Member) and 2188 m (Åsgard Formation).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 30 November 2010 as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6399
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/1-15
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-15 was drilled on the western side of the Utsira High in the North Sea. The objective was to test Jurassic/Triassic sandstones prognosed at 1925 in the Tellus prospect north of the Luno Discovery. The Luno Discovery has later been officially named the Edvard Grieg Field. The Tellus prospect was separated from Luno by a fault zone trending NW SE.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-15 was spudded with the semi-submersible installation Bredford Dolphin on 22 January 2011 and drilled to TD at 2150 m, 230 m into pre-Devonian basement rock. Due to possible shallow gas sands a precautionary 9 7/8" pilot hole was drilled down to 585 m. Only water filled sands were seen. Several incidents interrupted the progress where the most serious was a failed 20" casing cement job. The other incidents were related to the BOP and a stuck wire line string. The well was drilled with seawater and sweeps down to 585 m, and with Performadril mud from 585 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well proved an oil column of 48 metres in a thin, Intra Åsgard Formation Sandstone directly overlying weathered and porous / fractured basement. Top of fractured basement was at 1920 m. No Triassic or Jurassic sediments were identified in the well. The Intra Åsgard Formation Sandstone is a chalk arenite, 2.7m thick, with excellent reservoir properties. An oil/water contact was established at approximately 1965 m (1940 m TVD MSL). The acquired pressure, geochemistry and PVT data supports communication between the Luno and Tellus Discoveries, making the Tellus area a northern extension of the Luno Discovery.</span></p> <p class=MsoBodyText><span lang=EN-GB>Intermittent oil shows were described on core 1 immediately above the reservoir in a thin Hod Formation limestone. Below OWC shows were described on cores down to 1976 m. Further weak shows were described on cuttings down to 1997 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 61 meter core was recovered in four cores from 1915 to 1976 m (all core depths 2.15 m deeper than logger's depth) in the Hod Formation, Intra Åsgard Formation Sandstones and Basement. The overall recovery rate was 85.2%. Fluid sampling, water and oil, was performed using an extra-large diameter MDT-probe and dual packer. Samples were taken in the oil bearing zone at 1918.99 m, 1921.47 m, 1923.81 m, 1932.96 m,1937.23 m, 1952.43 m, 1959.62 m, and 1967.04 m. A water sample was taken at 2030.52 m. The oil samples show an under saturated light oil similar to the oil found in the Luno Field. The typical GOR from the MDT samples was 125 Sm3/Sm3, the oil density was 0.72 g/cm3 and the gas gravity was 0.95 (air=1).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged back to the 20" casing shoe on 5 April 2011 and a sidetrack 16/1-15 A was prepared. Well 16/1-15 is classified as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two drill stem tests were performed.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 1926 to 1960 m in the basement. After a slow initial production, the perforations were cleaned up and the well produced with a continuous flow to surface with an oil-rate of 105 sm3/d on a 40/64" choke and a bottom-hole pressure of 56.6 bar. No water was produced. This was the first successful full-scale production test of a reservoir consisting of cracked and porous bedrock on the Norwegian Continental Shelf.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 1917 to 1920 m in the Intra Åsgard Formation Sandstone. The main flow produced 470 sm3/d on a 36/64" choke with a bottom-hole pressure of 179.7 bar. No water was produced. The average GOR was 90 Sm3/Sm3. The maximum temperature at reference depth 1916.9 m was 84.5 deg C.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6517
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/1-15 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-15A is a sidetrack to Well 16/1-15, drilled on the western side of the Utsira High in the North Sea. The primary well proved Tellus to be a continuation of the Luno Discovery, now officially named the Edvard Grieg Field. The objectives of the geological sidetrack, 16/1-15 AT2, were to prove thicker, high productivity sandstone sequences to add to the Luno reserves, and to provide seismic calibration of complex stratigraphy.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-15 A was kicked off at 599 m in well 16/1-15 on 6 April 2011. It was drilled with the semi-submersible installation Bredford Dolphin. The 12 1/4" hole was drilled to TD at 2041 m. When running 9 5/8" casing it got differentially stuck forcing a new sidetrack. It is believed that the casing stuck in Grid Formation sandstone. The 16/1-15 A well bore was thus plugged back to the 20" casing and the technical sidetrack 16/1-15 AT2 was kicked off from 584 m and drilled to final TD at 2175 m (2011 m TVD) in Basement rocks. The sidetrack was drilled with Performadril mud from kick-off to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-15 AT2 proved 1 meter thick Intra Åsgard Formation Sandstone at 2067 m, overlying fractured basement. The sandstone was oil bearing and the basement had shows, but in this well bore the basement was found to be cemented and was considered unproductive. Oil shows were first recorded on the cores in the Intra Åsgard Formation Sandstone. They continued on the cores into the underlying basement where they were generally restricted to fractures. Below the cored interval sporadic shows were seen on cuttings down to a depth of 2124 m (1967.6 m TVD).</span></p> <p class=MsoBodyText><span lang=EN-GB>Four short cores were cut from 2066 to 2076.26 m, across the Intra Åsgard Formation Sandstone and into the Basement. The recovery was 100% and the core-log depth shifts were less than 0.5 m. MDT fluid samples were taken at 2067.83 m (oil), 2070.61 m (oil), and 2051.05 m (water). </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13 May 2011 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6593
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/1-16
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-16 was drilled on the east side of the Gudrun Terrace towards the Utsira High in the North Sea. The main objectives were to test the hydrocarbon potential in Late Jurassic/Early Cretaceous sands (the Noor prospect), and to appraise the extension of the Ivar Aasen Field of Middle Jurassic/Triassic age into PL457 area (Asha prospect). A possible secondary target at Paleocene level is the Heimdal sand pinchout. The well was planned to drill into Zechstein carbonates that may act as reservoir in this area.<b> </b></span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-16 was spudded with the semi-submersible installation Bredford Dolphin on 23 October 2012 and drilled to TD at 2722 m in the Permian Rotliegend Group. A 9 7/8” pilot hole was first drilled to 600 m to check for shallow gas. No shallow gas was observed. Operations proceeded without significant problems. The well was drilled with </span></p> <p class=MsoBodyText><span lang=EN-GB>No significant problem was encountered in the operations. The well was drilled with seawater and hi-vis sweeps down to 592 m and with water based Performadril mud from 592 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The interpreted Heimdal Formation sand reservoir was absent. The Lista Formation consists predominantly of Claystone with Limestone stringers. </span></p> <p class=MsoBodyText><span lang=EN-GB>In the first main exploration target (Noor prospect), the well penetrated approximately 90 m gross sandstones altogether, but there were no hydrocarbon shows or anomalous gas values seen. The Early Cretaceous Åsgard Formation is a Limestone/Chalk - sandstone sequence, with a predominantly limestone/chalk in the top 50 m and sandstone from 2120 m and towards the base. The Draupne Formation was found as a primarily siltstone sequence with abundant thin sandstones and limestone streaks throughout. </span></p> <p class=MsoBodyText><span lang=EN-GB>In the other main target (Asha prospect), the 16/1-16 well encountered a gross oil column of around 70 m in excellent reservoirs within the Middle Jurassic Hugin Formation, and into the Triassic Skagerrak Formation. Two hydrocarbon zones were found in separate pressure regime (0.6 bars difference). The first oil zone has an ODT at ca. 2435 m in the Hugin Formation. The deeper oil zone has an ODT at ca. 2454.2 m in the Skagerrak Formation. No oil/water contact was encountered. The oil found in 16/1-16 is of different type (heavier) than the oil previously proven in the Ivar Aasen field to the West. Moreover, unlike in Ivar Aasen, no gas cap is present in the Asha Discovery. </span></p> <p class=MsoBodyText><span lang=EN-GB>The 29 m thick Zechstein Group was found water wet. It is composed of dolomites and limestone and has relatively poor reservoir properties</span></p> <p class=MsoBodyText><span lang=EN-GB>Three consecutive cores were cut from 2385 m in the Hugin Formation to 2441 m in the Skagerrak Formation. MDT fluid samples were taken at 2163.28 m (water), 2385.2 m (oil), 2399.9 m (oil), 2424 m (oil), 2452.7 m (oil), 2458 m (water), and 2498.2 m (water). </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged back and completed for sidetracking on 7 December 2012. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
6823
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/1-16 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-16 A is a geological sidetrack to well 16/1-16 on the east side of the Gudrun Terrace towards the Utsira High in the North Sea. The primary well bore 16/1-16 found oil in two slightly differently pressured compartments in the Middle Jurassic Hugin Formation and the Triassic Skagerrak Formation (Asha prospect). Both pressure compartments were penetrated in oil-down-to settings. The objective of the 16/1-16 A sidetrack was to find the true Asha OWC by drilling down flank on the structure to the south.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-16 A was kicked off at 2047 m in main bore 16/1-16 on 7 December 2012. It was drilled with the semi-submersible installation Bredford Dolphin to TD at 2897 m (2663 m TVD) in the Triassic Skagerrak Formation. No significant problem was encountered in the operations. The well was drilled with water based Performadril mud from kick-off to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well encountered more than 30 m gross oil in a Hugin Formation of very good quality and which is much thicker than in 16/1-16. Top Hugin was at 2527 m. The oil/water contact was encountered at 2592.8 m (2465 m TVD), 6 metres TVD deeper than the OWC found in the western part of the Ivar Aasen Field. The Lower oil zone in a Skagerrak sand with a separate pressure regime was not present or very little developed in 16/1-16 A compared to16/1-16.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut in the well. MDT fluid samples were taken at 2573 m (oil) and at 2610.5 m (water)</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1 January 2013 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7095
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/1-17
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-17 was drilled on the Jorvik Prospect on the Utsira High, about 5 km east of 16/1-8, the discovery well on the Edvard Grieg field. The objective of the well was to prove petroleum in Pre-Jurassic sandstone and conglomerate rocks.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-17 was spudded with the semi-submersible installation Transocean Winner on 9 January 2013 and drilled to TD at 2070 m in granitic Basement rock. Due to shallow gas warnings, a 9 7/8" pilot hole was drilled to 610 m. No shallow gas was observed. Operations proceeded without significant problems. The well was drilled with seawater and high viscosity pills down to 615 m and with Glydril water based mud from 615 m to TD. Geochemical analyses of cuttings and cores show traces of diesel-like hydrocarbons in the mud.</span></p> <p class=MsoBodyText><span lang=EN-GB>A conglomeratic/sandy section was penetrated from 1869 m to top basement at 1987 m. Poor dating suggest the section to belong to either the Triassic Hegre Group, or the Permian Rotliegend Group. The cores show oil in the conglomeratic part of this section between 1882 m and 1952 m. The shows correspond to increased gas readings on the logs. Moveable oil was sampled here, at high drawdown in tight formation, but no fluid gradients were established. The uppermost part of the basement, 1987.45 to 1993.5 m core was covered by core #5. This is an extremely weathered felsic basement. No granitic wash or regolith was observed in core at the top of the interval. Pressure measurements in the water filled fractured basement indicate a pressure regime analogous to the Edvard Grieg field and the 16/1-12 discovery. </span></p> <p class=MsoBodyText><span lang=EN-GB>Five cores were cut covering the interval from 1856 m in the Early Cretaceous, throughout the conglomeratic/sandy unit, to 1993 m; six meter into the basement. The total recovery was 100%. MDT fluid samples were taken in the conglomeratic section at 1915.8 m (oil and water), and 1944.6 m (oil and water), and at 1944.61 m (oil and water), and in the basement at 2017.71 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 19 March 2013 as a dry well with shows</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7113
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/1-18
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-18 was drilled to appraise the Edvard Grieg Field on the Utsira High in the North Sea. The objective of the well was to delineate the southeastern part of the Edvard Grieg Field in order to optimise the drainage strategy and to determine the best possible location of production wells in this area. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>A 9 7/8" pilot hole was drilled from seabed to 620 m to check for shallow gas. No shallow gas was seen. Appraisal well 16/1-18 was spudded with the semi-submersible installation Island Innovator on 24 February 2014 and drilled to TD at 2391 m in granitic basement rock. No significant problem was encountered in the operations. The well was drilled with spud mud down to 613 m and Aqua-Drill mud from 613 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>No Jurassic sediments were penetrated in the well. BCU / Top Triassic, Hegre Group was encountered at 1894 m. A 62-metre gross oil column was found in conglomerate sandstone of the Hegre Group, where the top 43 metres have very good reservoir properties and the lower 19 metres have good reservoir quality. The oil/water contact was not encountered. Pressure points proved an oil gradient with the same density oil as in the rest of the Edvard Grieg Field, with an ODT at 1956 m. Oil shows were described on cores down to 1986 m. There were no shows above top reservoir level.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 95.6 m core was recovered in eight cores from the interval 1886 to 1986 m. MDT fluid samples were taken at 1894.9 m (oil), 1921.4 m (oil), 1954.5 m (oil), and 967.4 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 14 May 2014 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One DST was conducted in a 13-metre interval from 1938.9 to 1959.6 m in the lower part of the oil column in reservoir of good quality. The main flow in the test produced 135 Sm3 oil and 12000 Sm3 gas /day through a 28/64" choke and showed good flow properties from the entire oil zone. The GOR was 88 Sm3/Sm3, the oil gravity was 0.83 g/cm3, and the gas gravity was 0.66 (air = 1). The temperature profile for the test extrapolated to an initial top reservoir temperature of 80.1 °C at 1938.9 m.</span></p> |
7314
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/1-19 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-19 S was drilled on the Amol prospect about two and a half kilometres east of appraisal wells 16/1-16 and 16/1-16 A at the Ivar Aasen field, and about three kilometres north of the Edvard Grieg field in the central part of the North Sea. The primary objective was to prove petroleum in Early Cretaceous reservoir rocks (the Åsgard formation) in the western part of the Utsira High. The secondary target was to prove petroleum in fractured and/or weathered basement rocks.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-19 S was spudded with the semi-submersible installation Borgland Dolphin on 13 August 2013 and drilled to TD at 1995 in the Basement rock. A 9 7/8" pilot hole was drilled to 604 m without any indication of shallow gas. Operations were suspended twice to accommodate sidetrack operations on the Asha East prospect. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 604 m, with Carbo-Sea oil based mud from 604 m to 1862 m, and with Aquadril mud from 1862 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Åsgard Formation was encountered at 1878 m and proved to contain only half a metre of tight sandstone/clay stone. The fractured basement was encountered at 1891 m with oil in the fractures. Live oil was sampled from the fractures, but the reservoir quality was poorer than expected. </span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the interval 1865 to 1910 m with 100% recovery. RCI oil samples were taken at 1929.5 m. The samples proved a GOR in the range 106 to 135 Sm3/Sm3, an oil density of ca 0.857 g/cm3, and a gas gravity of ca 0.97 (air = 1).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 25 October 2013 as a well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7255
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/1-2
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-2 is located on the eastern side of the Gudrun Terrace, towards the Utsira High in the North Sea. The well was designed to test all potential reservoirs through the Permian on a closure on a large, rotated fault-block. Primary objectives were Jurassic sandstones and secondary objectives were Paleocene sandstones.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-2 was spudded with the semi-submersible installation Ross Rig on 4 July 1976 and drilled to TD at 2919 m in granite basement. Loss of circulation in high-porosity Zechstein carbonates was the only significant problem encountered during the drilling of 16/1-2. Initial drilling from the sea floor to 1286 meters was with sea water and gel. Below this depth a fresh water and lignosulphonate mud system was used.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated several sands in the Tertiary including the Utsira, Skade, and Grid formations. The Heimdal Formation was encountered at 2098 m with a 10 m zone of strong oil shows. The zone was however judged by log analysis to be water-productive and the shows not of sufficient quality to warrant testing. Triassic sandstones were originally interpreted to be water-filled. Later reinterpretation have confirmed the presence of oil in the Triassic interval. There were no shows from either the Zechstein or the Rotliegendes sandstone.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7 August 1976 as a dry well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
332
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7/6/2016 12:00:00 AM
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04.11.2024
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16/1-20 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-20 A was drilled on the Asha East prospect about two and a half kilometres east of appraisal wells 16/1-16 and 16/1-16 A on the Ivar Aasen field, and about three kilometres north of the Edvard Grieg field in the central part of the North Sea. The well is an appraisal well to the 16/1-16 Asha Discovery and the primary objective was to investigate if the hydrocarbon accumulation in the Hugin found in the Asha well spilled eastwards into the fault bound dip closure against the Utsira High Fault. Secondary target were younger sands of Late Jurassic and Early Cretaceous age.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-20 A was drilled with the semi-submersible installation Borgland Dolphin. It was drilled in tandem with the 16/1-19 S Amol well. After drilling the 16/1-19 S Amol well to 604 m and set 13 3/8" casing at 597 m, the Amol well was suspended in order to drill 16/1-20 A Asha East 12 1/4" section. Drilling operations on Asha East were severely hampered by hole stability problems in the 12 1/4" hole section. Two attempts to drill the Asha East well were conducted from 20 August to 4 September 2013 without success. The Asha East well was then suspended and plugged back in order to continue with Amol well. The remaining 12 1/4" and 8 1/2" sections of the Amol well was drilled from 4 to 25 September 2014, then plugged back to kick off the 16/1-20 A T3 Asha East well. </span></p> <p class=MsoBodyText><span lang=EN-GB>In the Cromer Knoll Group a sandy section with a log response unlike the Åsgard Formation was penetrated from 2427 m to 2753.5 m. Below this section the well penetrated Intra-Draupne Formation sandstone down to the target Hugin Formation sandstones at 2977 m. All sandstones were devoid of any hydrocarbons. Post well depth conversion showed the spill point to the east from the Asha/Ivar Aasen structure to be below the OWC. In addition, the Heather Formation shale acting as top seal in the Asha well was not present in the Asha East.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 55 meter of 4" core was cut and 55 meter recovered over a single core run at 2967 to 3022 m. RCX fluid samples were taken at 2995.5 m. The maximum temperature from the RCX run was 99.9 °C at 3040.6 m, giving a temperature gradient of 4.2 °C/100 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Operations on Asha East ended with permanent abandonment on 22 October 2013. The well is classified as a dry appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7256
|
4/11/2017 12:00:00 AM
|
04.11.2024
|
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16/1-21 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-21 A is a geological sidetrack to well 16/1-21 S. It was drilled to appraise the 16/1-9 Ivar Aasen discovery on the Gungne Terrace in the North Sea. The objective was to obtain key depth and reservoir information for field development in the eastern part of the Ivar Aasen Discovery. The targets were reservoirs in the Hugin/Sleipner and Skagerrak Formations.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-21 A was kicked off on 3 March 2015, from the main well 16/1-21 S with an open hole kick off below the 13 3/8" casing shoe at 1317 m. The well was drilled with the jack-up installation Mærsk Innovator to TD at 3313 m (2517 m TVD) in the Triassic Hegre Group. Due to severe losses when drilling the 12 1/4" section at 2951 m a cement plug was set and the 9 5/8" liner was run with shoe depth at 2796 m. The well was drilled with Versatec oil based mud from kick-off to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated a 6.3 m net sand in the Sleipner Formation above the Skagerrak formation. The reservoir quality in the sand is very good with an average porosity in the net sand of 24 percent. The sand contains gas-condensate and oil. A gas oil contact is interpreted to be at 3192.0 m (2408.0 m TVD).</span></p> <p class=MsoBodyText><span lang=EN-GB>The underlying Skagerrak reservoir is oil filled and the net sand interval above the Alluvial Fan is 20.3 meters. The average porosity in the net intervals is 23 percent in Skagerrak 2 and 21 percent in Skagerrak 1. The formation pressures in 16/1-21 A indicated a contact at 3273.9 m (2481.6 m TVD) in Skagerrak Alluvial Fan. However, the pressures in this very calcite cemented part of Skagerrak Formation is about 0.6 bar higher than in the oil-filled Skagerrak above, and the actual contact is not resolved. The deepest oil sample is from 3221.1 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Oil shows were recorded on cores from 3183 m, in the Sleipner Formation. Shows were visible throughout the cored sections with a weakening trend towards the lowermost part of core 3 in the Skagerrak Formation. No shows are described below base of core 3 at 3234 m. </span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut from 3174 m in the Heather Formation, through the Sleipner Formation and down to 3235.8 m in the Triassic Skagerrak Formation. The core recovery varied from 92.7% to 99.0 %. The core to log shift is reported to vary between +2.0 m to +3.0 m in different sections of the cores. MDT fluid samples were taken at 3191.03 m (gas-condensate), 3193.44 m (oil), 3195.53 m (oil), 3208.93 m (oil), and 3221.1 m (oil).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 20 April 2015 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7530
|
4/18/2017 12:00:00 AM
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04.11.2024
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16/1-21 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-21 S was drilled to appraise the 16/1-9 Ivar Aasen discovery on the Gungne Terrace in the North Sea. The objective was to obtain key depth and reservoir information for field development in the north-eastern part of the Ivar Aasen Discovery. The targets were reservoirs in the Heimdal, Hugin/Sleipner and Skagerrak Formations.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-21 S was spudded with the jack-up installation Mærsk Interceptor on 21 January 2015 and drilled to TD at 2630 m (2584 m TVD) m in the Triassic Hegre Group. A 9 7/8" pilot hole was drilled from the 30" conductor shoe to 376 m. No shallow gas was encountered. The well was drilled with seawater and hi-vis pills down to 373 m, with Glydril mud from 373 m to 1304 m, and with Versatec oil based mud from 1304 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Heimdal Formation was encountered water filled at 2176 m (2138.7 m TVD). Reservoir properties were excellent with 26.5 m net sand with 30% average porosity. The distribution of the Jurassic versus the Triassic sequence was different from the expected. Triassic reservoir was thicker than predicted, while the Jurassic had no reservoir at all. However, the total actual reservoir quality and hydrocarbon pore volume height was in agreement with the predicted, since the Triassic proved better than expected combined with a deeper hydrocarbon contact. The Triassic reservoir (Skagerrak Formation) was penetrated at 2491 m (2446.6 m TVD) and it was hydrocarbon bearing with 20.3 m net pay with 20% average porosity. The hydrocarbon type was undersaturated oil, as in well 16/1-16. No gas cap was present and an oil down-to situation was established at ca 2535 m (2490 m TVD). Hydrocarbon shows were first evident in the lowermost part of core #1, from 2489 m in the Skagerrak Formation. Good hydrocarbon shows continued in the sandy sections in the cores. No shows were recorded below 2554 m, in the lowermost part of the Skagerrak Formation. </span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut in succession from 2499 m in the Heather Formation to 2586.2 m in the Skagerrak Formation. Core recovery was 100%. The core to log shift is +1.85 m for all three cores. Fluid samples were taken at 2178.25 m (water), 2497.71 m (oil), 2514.7 m (oil), 2525.25 m (oil), 2533.61 m (oil), and 2538.92 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged back and abandoned on 3 March 2015 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7529
|
4/11/2017 12:00:00 AM
|
04.11.2024
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16/1-22 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-22 A is a geological sidetrack to well 16/1-22 S on the Ivar Aasen Field on the Gudrun Terrace in the North Sea. The primary objective was to test the hydrocarbon potential in the Sleipner and Skagerrak Formations in the southwestern part of the Ivar Aasen Field, ca 950 m northeast of the main wellbore. 16/1-22 A also aimed to investigate a seismic anomaly at reservoir level.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-22 A was kicked off at 1465 m in the main wellbore on 27 May 2015. It was drilled with the jack-up installation Mærsk Interceptor to TD at 2896 m (2522 m TVD) m in the Triassic Skagerrak Formation. Static and dynamic mud losses occurred from 2794 m. The losses were cured by using coarse lost circulation material. The well was drilled with oil-based mud from kick-off to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Top of the reservoir in the 16/1-22 A well was penetrated at 2769 m (2432.4 m TVD), 17 m shallower than expected, and with a reservoir thickness approximately half of what was predicted. No Jurassic reservoir was present, only Triassic. A total oil column of about 55 metres was encountered in the Skagerrak formation, 30 metres of which was in sandstone of varying reservoir quality, from moderate to very good. The oil/water contact was not encountered. The seismic anomaly is linked to the top of a total oil column of about 25 metres in an alluvial sandstone unit within the Skagerrak Formation, 15 metres of which had moderate reservoir properties. Hydrocarbon shows were recorded from top at 2769 m and throughout the Skagerrak Formation, with a weakening downward trend towards TD. A gas peak of up to 20% total gas indicated a gas cap in the uppermost part down to ca 2785 m. Shows were visible throughout the reservoir to TD, </span></p> <p class=MsoBodyText><span lang=EN-GB>No coring or wireline operations were performed in this sidetrack. No pressure points or fluid samples were acquired du to mud losses.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 4 June as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7716
|
4/26/2017 12:00:00 AM
|
04.11.2024
|
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16/1-22 B
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-22 B is a geological sidetrack to well 16/1-22 S on the Ivar Aasen Field on the Gudrun Terrace in the North Sea. The primary objective was to test the hydrocarbon potential in the Sleipner and Skagerrak Formations in the southwestern part of the Ivar Aasen Field, ca 1290 m northeast of the main wellbore. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-22 B was kicked off at 1470 m in the main wellbore on 4 June 2015. It was drilled with the jack-up installation Mærsk Interceptor to TD at 3215 m (2556 m TVD) m in the Triassic Skagerrak Formation. No significant problem was encountered in the operations. The well was drilled with oil-based mud from kick-off to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Top reservoir, Skagerrak Formation was penetrated at 3065 m, 19 m deeper than prognosed, and with a total reservoir thickness of 35 m, 12 m thinner than expected. Like the -S and -A wells, a thick Viking Group was penetrated but no Jurassic reservoir. The total reservoir quality was proven better than predicted. Well 16/1-22 B encountered a total oil column of about 45 metres in the Skagerrak formation, 25 metres of which was in sandstone of good to very good reservoir quality. The oil/water contact was not encountered. Hydrocarbon shows were evident from top Skagerrak Formation at 3065.6 m. A 10% total gas reading indicated clearly a gas cap in the uppermost part of the reservoir. As for the two previous well tracks, shows varied according to changing lithologies in the reservoir. No shows were recorded below 3160 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. Attempts to record pressure points with a stethoscope tool on the 8 1/2" drilling assembly failed. No fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 14 June 2015 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7720
|
4/26/2017 12:00:00 AM
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04.11.2024
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16/1-22 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-22 S was drilled to appraise the Ivar Aasen Field on the Gudrun Terrace in the North Sea. The primary objective was to test the hydrocarbon potential in the Sleipner and Skagerrak Formations in the southwestern part of the Ivar Aasen Field and to establish hydrocarbon fluid contacts. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-22 S was spudded with the jack-up installation Mærsk Interceptor on 24 April 2015 and drilled to TD at 2640 m in the Late Triassic Skagerrak Formation. No significant problem was encountered in the operations. The well was drilled with seawater and bentonite sweeps down to 600 m, with Versatec oil based mud from 600 m to TD. Good hydrocarbon shows were recorded in the sandy sections in the cores from 2503 to 2550 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Jurassic - Triassic sequence was different from the expected as the Jurassic consisted of the Viking Group only, with no Jurassic reservoir present. This was however partly compensated by a thicker Triassic reservoir sequence with good quality sandstone in the uppermost part. Top Skagerrak Formation was encountered at 2506 m, which was 28 m deeper than the prognosis. The total reservoir thickness was 9 m thinner than expected. The Skagerrak Formation had moveable oil in the top three meters down to an ODT at 2508.3 m (2486 m TVD).</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut in this well. Core 1 was cut from 2502.8 to 2517.66 m with 93.14% recovery, and core 2 was cut from 2517.66 to 2550 m with 100% recovery. A small depth shift relative to the logs (-0.1 to -0.4 m) is estimated for core 1. For Core 2 there was no core-log depth shift. MDT fluid samples were taken at 2506.15 (oil) and 2524.03 m (water) fluid.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged back for sidetracking on 27 May 2015. It is classified as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7531
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4/18/2017 12:00:00 AM
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04.11.2024
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16/1-23 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-23 S was drilled appraise the Edvard Grieg Field on the Utsira High in the North Sea. The primary objective was to investigate the hydrocarbon potential in the South Eastern part of the Field. It was also designed to allow installation of a CaTS pressure gauge for long term monitoring of reservoir pressure.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-23 S was spudded with the jack-up installation Rowan Viking on 24 June 2015 and drilled to TD at 2130 m in basement rock. The well was drilled S-shaped with up to 24 ° deviation in the interval from 630 m to 1480 m. This was to avoid a fault at the reservoir level. Target location was approximately 43 m west of the spud location. No significant problem was encountered in the operations. The well was drilled with seawater and hi-vis sweeps down to 315 m, with KCl/polymer mud from 634 m to 1888 m, and with Aquadril mud from 188 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-23 S proved a 66 metres gross oil column in conglomerates and sandstones with medium to good reservoir quality. The top of the reservoir, from 1953 to 1953.5 m, is a marine sandstone unit with a basal conglomeratic transgression lag belonging to the Åsgard Formation, the remaining reservoir is conglomerates and thin sandstone units belonging to the Triassic Skagerrak Formation. A Free Water Level was established from pressure gradients at ca 2020.4 m (1985.5 m TVD). The pressure points further proved an oil gradient with the same density as in the rest of the Edvard Grieg field. Fair to poor oil shows were recorded on cores below the FWL down to 2054 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Eight cores were cut. Core 1 was cut from 1681 to 1690 m in Hordaland Group claystone for hole instability studies. Core recovery was 104.1%. Cores 2 to 8 were cut from 1945.5 m in the Åsgard Formation to 2064.4 m in the Skagerrak Formation. Recovery varied from 92.5 to 100%. MDT fluid samples were taken at 1958.2 m (oil), 1990.0 m (oil), 1990.6 m (oil), 2015.21 m (oil), 2024.7 m (water), 2061.4 m (water), 2061.72 m (water), and 2030.85 m (water). Single stage separation of the oil samples gave oil densities in the range 0.857 to 0.886 g/cm3 and GORs in the range 149 to 111 Sm3/Sm3.</span></p> <p class=MsoBodyText><span lang=EN-GB>The CaTS reservoir pressure monitoring system was installed before the well was permanently abandoned on 25 August 2015 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7532
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5/23/2017 12:00:00 AM
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04.11.2024
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16/1-24
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-24 was drilled to test the Gemini prospect on the Gudrun Terrace west-south-west of the Edvard Grieg Field in the North Sea. The primary objective was to test the hydrocarbon potential in the Paleocene Ty Formation</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-24 was spudded with the semi-submersible installation Island Innovator on 14 February 2015 and drilled to TD at 2299 m in the Late Jurassic Hugin Formation. No significant problem was encountered in the operations. The well was drilled with seawater and hi-vis pills down to 600 m and with Aquadril mud from 600 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The target Ty Formation came in at 2116 m. The Ty Formation consisted of a 30-metre thick sandstone with an average porosity of 26.7% and a net/gross of 0.984. </span><span lang=EN-US>The well also encountered a ca 30-metre thick Intra Draupne Formation sandstone of very good reservoir quality and a ca 120-metre thick sandstone-dominated interval in the Heather formation with good to poor reservoir quality. Pressure points in Paleocene and Late Jurassic were below hydrostatic, indicating pressure depletion in the area. All reservoirs are water bearing. </span><span lang=EN-GB>No oil shows were observed in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut and no fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 16 March 2015 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7616
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4/18/2017 12:00:00 AM
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04.11.2024
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16/1-25 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-25 S was drilled on the Utsira High in the North Sea, 2.7 km south of well 16/1-12 (Rolvsnes discovery well). The primary objective was to prove the presence of transgressive Cretaceous and/or Jurassic sandstones overlying the basement and to test the extension of the 16/1-12 discovery in porous basement towards south.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-25 S was spudded with the semi-submersible installation Bredford Dolphin on 15 October 2015 and drilled to TD at 2210 m (2121 m TVD) m in the basement rock. The section from 2010 to 602 m was drilled first as a 97/8” pilot hole to check for shallow gas and then opened up with a 26” bit. No shallow gas was observed. The well was drilled as a deviated well (15° through basement) in order to cross more faults and test a wider area and in that way to get better control on variability, quality and thickness of the weathered zones. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis sweeps down to 602 m and with Aquadril mud from 602 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>A 10 m transgressive sandstone was prognosed at the base of the Early Cretaceous Åsgard Formation but only 10 cm was observed directly above basement. The top basement was found at 2004.25 m (1922.7 m TVD). The well encountered an oil column of about 30 m in porous and fractured basement rock. The OWC is set 2034.5 m MD RKB (1952 m TVD). The pressure data shows communication with the 16/1-12 oil discovery, with approximately the same oil/water contact. The fluid type is oil with similar properties to the Edvard Grieg oil. Below OVC there was oil shows (direct, cut and residual fluorescence) down to 2067 m, and weaker shows down to 2124 m. There were no shows below this depth or above top Basement.</span></p> <p class=MsoBodyText><span lang=EN-GB>Six Cores were cut in succession in the basement from 2002 to 2025.23 m with a total recovery of 97%. The core-log shift varies between 0.07 and 0.342 m. MDT fluid samples were taken at 2012.25 m (oil), 2032.5 m (oil), and 2059.6 m (water). PVT single flash analyses of the samples from 2012.25 m gave GOR in the range 175 to 197 Sm3/Sm3 and oil density in the range 0.847 to 0.849 g/cm3. The samples from 2032.5 m had GOR in the range 168 to 177 Sm3/Sm3 and oil density in the range 0.851 to 0.852 g/cm3.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 26 December 2015 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One production test (DST) was performed in the oil zone from 2006.83 to 2029.26 m. The test produced 47 Sm3 oil and 13300 Sm3 gas per day through a 32/64“ choke. The GOR was 280 Sm3/Sm3. The DST temperature measured at 2019.9 m (1937.8 m TVD) was 77.4°C.</span></p> |
7775
|
5/20/2022 12:00:00 AM
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04.11.2024
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16/1-26 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-26 A is a geological sidetrack to well 16/1-26 S, both wells being drilled from the 16/1-D-9 West Cable oil producer well on the Ivar Aasen Platform in the North Sea. The objective for 16/1-26 A was to prove additional reserves in the southern part of the West Cable structure, west of the Ivar Aasen Field. West Cable is a Sleipner Formation oil discovery made by well 16/1-7 in 2004.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-26 A was kicked off from 16/1-26 S at 2925 m (1893.1 m TVD) on the 17 April 2016. It was drilled with the jack-up installation Mærsk Interceptor to TD at 4888 m (3102 m TVD) m in the Middle Jurassic Sleipner Formation. The well is highly deviated with drilled inclination dropping from ca 60° at kick-off to ca 31° at TD. No significant problem was encountered in the operations. The well was drilled with Versatec oil based mud all through. </span></p> <p class=MsoBodyText><span lang=EN-GB>Top Sleipner Formation was encountered at 4710 m (2959.2 m TVD, 2901.2 m MSL), above the OWC at 2940 m MSL in 16/1-7 Cable West. The Sleipner Formation contained approximately 75 metres TVD of sandstone with moderate to good reservoir properties, but the reservoir was proven to be entirely water bearing. No oil shows were recorded in this well.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 24 April as a dry appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7940
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4/25/2019 12:00:00 AM
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04.11.2024
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16/1-26 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-26 S was drilled deviated from the 16/1-D-9 West Cable oil producer well on the Ivar Aasen Platform in the North Sea. The objective was to prove additional reserves in the southern part of the West Cable structure, west of the Ivar Aasen Field. West Cable is a Sleipner Formation oil discovery made by well 16/1-7 in 2004.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Exploration well 16/1-26 S was drilled from below the 13 3/8 casing shoe at 2792.5 m in producer well 16/1-D-9. Spud date for the exploration well was 3 April 2016. The well was drilled with the jack-up installation Mærsk Interceptor to TD at 5330 m (2979 m TVD) in the Late Triassic Skagerrak Formation. The well is highly deviated with a deviation of ca 63 ° all through. No significant problem was encountered in the operations. The well was drilled with Versatec oil based mud all through. </span></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-26 S encountered gas and oil in two Intra-Draupne Formation Sandstone units. Top of the upper sandstone is at 4726.2 m (2713.4 m TVD).The two sands are indicated not to be in pressure communication. The upper sand is gas-filled, while the lower, with top at 4754 m (2725 m TVD) contain oil down to a lithological contact at 4773 m (2731 m TVD) and with a possible 1-metre gas cap on top. The underlying sandstones of the Statfjord Group and Skagerrak Formation are water wet. No Middle Jurassic sediments are present in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 14 April 2018 as an oil and gas discovery</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7915
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3/16/2018 12:00:00 AM
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04.11.2024
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16/1-27
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<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>General</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/1-27 was drilled on the Edvard Greg Field on the Utsira High in the North Sea. It was drilled as an appraisal well to verify top reservoir and sand content in the western part of the field.<o:p></o:p></span></p> <p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Operations and results</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Appraisal well 16/1-27 was spudded with the semi-submersible installation Island Innovator on 1 March 2017 and drilled to TD at 2258 m in Basement rock. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 611 m and with <span class=SpellE>Aquadril</span> mud with 4% glycol from 611 m to TD.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Top reservoir, <span class=SpellE>Åsgard</span> Formation sandstone, was encountered at 1962 m, directly overlying Triassic Skagerrak Formation sandstone at 1968.35 m. The reservoir contained oil from top down to the OWC at 1978 m (1948 m TVD MSL), 9 meters deeper than the established FWL at 1939 m TVD MSL in the central Edvard Grieg area. Pressure data showed one oil gradient through the Cretaceous to Triassic sandstones, and two water gradients below the oil: one in communication with the oil gradient and one with 6 bar higher pressure in the lower conglomerates of the Skagerrak Formation, below a <span class=SpellE>shaly</span> layer around 2150 m.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Apart from shows in the reservoir section significant oil shows were recorded above reservoir level. First oil show in the well was described in thin Oligocene sandstones at 1309 to 1322.5 m as fair patchy straw yellow direct fluorescence, fast blooming to streaming bluish white cut fluorescence, medium straw to bluish white fluorescent residue, no visible residue. <o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>At 1506 to 1543 m, in thin Eocene Hordaland Group sandstones, there were oil shows described as no to weak hydrocarbon odour, no to medium brown oil stain, patchy to even weak to dull straw yellow to orange direct fluorescence, slow blooming to streaming bluish white cut fluorescence, weak bluish white fluorescent residue, no visible residue.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>At 1811 to 1858 m, in Early Eocene Balder Formation and base Hordaland group Tuff and limestone, there were oil shows described as medium brown to dark brown oil stain, weak spotty to patchy bluish white to light yellowish brown direct fluorescence, slowly bleeding to blooming light yellowish brown cut fluorescence, no fluorescent or visible residue. Below the OWC only poor shows were recorded down to 2023 m.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Three cores were cut. Core 1 was cut from 1967 to 1993.1 m with 95.8% recovery. The core-log shift is +0.7 m. Core 2 was cut from 1993.1 to 2002.2 m with 78.8% recovery. The core-log shift is +0.5 m, Core 3 was cut from 2002.2 to 2023 m with 98.7% recovery. The core-log shift is -0.25 m. <span style='mso-spacerun:yes'> </span>MDT fluid samples were taken at 1972.3 m (oil), 1976 m (oil), and 2025 m (water). The two oil sampling stations gave similar oils according to PVT analysis, with GOR ranging from 120.3 to 123.2 Sm3/Sm3 and stock tank oil density ranging from 0.8545 to 0.8565 g/cm3.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The well was permanently abandoned on 11 April 2017 as an oil appraisal<o:p></o:p></span></p> <p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Testing</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'> <b><o:p></o:p></b></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No drill stem test was performed. <o:p></o:p></span></p> |
8124
|
11/11/2019 12:00:00 AM
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04.11.2024
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16/1-28 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-28 S was drilled to appraise the 16/1-12 Rolvsnes Discovery on the Utsira High in the North Sea. The objective was to verify pressure communication within the reservoir and determine possible depletion resulting from production from the Edvard Grieg Field. Further objectives were to prove the drillability of a 2.5 km long horizontal well within granitic basement, and to perform a production test to better understand the reservoir performance.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-28 S was spudded with the semi-submersible installation COSL Innovator on 3 April and a 36 “x 42” was drilled to 200 m. A 9 7/8” pilot was drilled from 200 to 780 m due to shallow gas warnings. No shallow gas was observed. Hole instability problems were encountered in the 12 ¼” section, from 1742 to 2186 m, and this section was unintentionally side-tracked at 1978 m while reaming. The side-track, 16/1-28 ST2, was drilled to final TD at 4880 m (1919 m TVD) in granite basement rock. The well was drilled vertical down to 957 m, building angle from there to ca 2410 m, from where the well was drilled horizontally. A union strike delayed the DST operations with approximately 11 days. The well was drilled with seawater and hi-vis pills down to 957 m, with Aquadril mud from 957 m to 1734 m, with Delta TEQ oil-based mud from 1734 m to 2180 m, and with Performadril mud from 2180 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Basement was encountered at 2335.5 m (1908.8 m TVD) and well TD was reached at 4880 m (1919.0 m TVD). A total horizontal section of 2500 m in basement was drilled with an average penetration rate of 9.9 m/h. 65 pressure measurements were attempted, the successful tests showed a depletion of about 10 bars, which can be the result of production from the Edvard Grieg Field. Good oil shows were recorded throughout the fractured granitic reservoir from 2336.5 to 4880 m, otherwise no shows were described in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>Due mainly to wellbore instability issues, no cores or sidewall cores were taken in wellbore 16/1-28 ST2. This restricted the amount of petrographic data acquired to evaluate the degree and type of alteration of the basement rock. Fluid samples were taken during the DST</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 23 August 2018 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was formation-tested (DST) for ten days. The well was tested from intervals separated by swell packers over the whole reservoir section below 2417 m and production logging was carried out. The maximum production rate was 1100 Sm3 oil per flow day through a 52/64” nozzle opening. The main flow period of 5 days was held with a rate of 650 Sm3 oil per day through a 52/64” nozzle opening. The oil is undersaturated with a gas/oil ratio of 130 Sm3/Sm3. The DST temperature at Gauge depth 1852.4 m TVD was 77.6°C. </span></p> |
8357
|
8/23/2020 12:00:00 AM
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04.11.2024
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16/1-29 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-29 S was drilled to test the Lille Prinsen prospect on the north-western part of the Utsira High in the North Sea. The exploration objective was to test the Lille Prinsen prospect, believed to mainly consist of Triassic sediments, with the possibility of (thin) transgressive Jurassic sands similar to Johan Sverdrup on top. In addition, the well was expected to penetrate Grid and Heimdal sands, which were found to contain oil and gas in the 16/1-6 S Verdandi well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-29 S was spudded with the semi-submersible installation Deepsea Bergen on 22 April 2018. During the operation, the well (16/1-29 S) experienced unexpected heavy mud losses when drilling into the reservoir section, eventually leading to well collapse and stuck drill string. Consequently, a technical side-track (16/1-29 ST2) was kicked off at 1225 m and this was successfully drilled through the reservoir section. Continuous mud losses were also experienced in the reservoir section of the technical side-track, but these were controlled by lowering the mud weight. The well was finally drilled to planned TD at 2024 m (2010 m TVD) in Basement rock. The well was drilled with seawater and hi-vis pills down to 550 m, with KCl mud from 550 m to 1210 m, with Enviromul oil-based mud from 1210 m to 1863 m (mainwell and side-track) and with KCl/polymer/GEM mud from 1863 m to final TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Eocene Grid Formation and the Paleocene Heimdal Formation were encountered at 1419 m (1416 m TVD), and 1794 m (1785 m TVD), respectively. They both contained gas over oil. In the Grid formation a gas-oil contact was found at 1462.6 m (1459.9 m TVD) with a free water level at 1498.9 m (1495.8 m TVD). In the Heimdal Formation a gas-oil contact was found at 1808.1 m (1798.4 m TVD) with a thin oil leg down-to 1809.2 m (1799.5 m TVD). The oil-leg was confirmed by PVT analyses, which found the fluid samples taken at 1808.5 m (1798.8 m TVD) to contain both gas-condensate and black oil. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well did not encounter any of the expected Jurassic/Triassic sands, but instead encountered 26.6 m of oil filled Permian Zechstein Group Dolostone carbonates with top at 1885 m (1874 m TVD), immediately below the Cretaceous Shetland Group. The Permian Carbonates show varying, but good reservoir quality, with an average net/gross of 0.91 and porosity of 23%. The core and thin sections show variations within the carbonate reservoir, with the better zones in the upper parts, which can be associated with vuggy porosity, low content of calcite cement and karst development.</span></p> <p class=MsoBodyText><span lang=EN-GB>Poor shows were described from drilled cuttings in Grid sand at 1475 m and in Heimdal sand at 1800 m. Shows from drilled cuttings in Zechstein were described as patchy even brown oil stain, even yellow direct fluorescence, weak blooming cut and weak patchy yellow residual. Oil shows (direct and cut fluorescence and spots of oil stain) continued in basement down to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut in the technical side-track from 1888.2 to 1907.5 m in the Permian Zechstein Group. MDT fluid samples were taken at 1474.5 m (oil with 3% mud contamination), 1808.5 m (gas-condensate and oil with <1% mud contamination), 1892.5 m (oil, no mud contamination), and 1985.7 m (formation water and filtrate).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 3 June 2018 as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
8383
|
6/3/2020 12:00:00 AM
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04.11.2024
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16/1-3
|
<p><b>General</b></p> <p>Well 16/1-3 is located on the Gudrun Terrace west of the Utsira High. The main objective of the well was to evaluate the hydrocarbon potential of Jurassic sand reservoirs. Eocene and Paleocene sands were secondary objectives. 16/1-3 was drilled on the flank of a seismically defined structure. The prime crestal location could not be tested due to the presence of a telephone cable on the sea floor. </p> <p><b>Operations and results</b></p> <p>Well 16/1-3 was spudded with the semi-submersible installation Glomar Biscay II on 29 July 1982 and drilled to TD at 3498 m in granite basement. After losing returns while drilling at 210 m, the 30" casing was re-cemented. Shallow gas was encountered between 400 and 444 meters. Tight hole, swabbing on trips and reaming were recurrent problems in the 12 1/4" hole due mainly to swelling of claystone and siltstone. Mud was lost when drilling through a flint layer at 2638 m. The well was drilled with seawater and bentonite down to 702 m, with a lignosulphonate/CMC mud from 702 m to 2282 m, and with lignosulphonate/lignite mud from 2282 m to TD.</p> <p>Mechanical log analysis over the Jurassic interval indicated the presence of about 60 meters of gross sand. Two thin zones of approximately 4 meters each in thickness were interpreted to be hydrocarbon bearing. The remaining sands were judged to be water bearing or non-reservoir. No reservoir was believed to be present in the Triassic sand, siltstones and shales. Minor shows, consisting of stain, fluorescence and/or mud gas manifestations were recorded in the Pliocene-Eocene, Miocene and Paleocene sections. In addition, oily mud was recovered in one of the MFT samples from the Jurassic Sleipner Formation. The Zechstein formation contained generally tight anhydritic dolomites at the top. A porous but interpreted water bearing limestone section was found in the middle portion of the Zechstein Group. Below the limestone a 36 m thick sandstone sequence was encountered. At the base of the Zechstein Group 3 m of Kupferschiefer Formation was encountered. The Kupferschiefer Formation is present in several wells in the area. The Permian Rotliegendes formation contained poor reservoir quality felspathic sandstones, siltstones and shales. Also the Permian reservoirs appeared to be water bearing on wire line logs. </p> <p>One core was cut from 2282 m to 2290.5 m in the Lista Formation. Two Multi Formation Test (MFT) samples were taken at 2742 m and 2742.5 m in a thin sand in the Jurassic Sleipner Formation. The first sample contained mud filtrate only. The second sample contained mud filtrate and 75 cc of light gravity oil. The well was permanently abandoned as a dry well with shows on 27 September 1982.</p> <p><b>Testing</b></p> <p>No drill stem test was performed </p> |
84
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5/19/2016 12:00:00 AM
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04.11.2024
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16/1-30 A
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<p class=MsoBodyText><span lang=EN-GB>Well 16/1-30 A Lille Prinsen Outer Wedge was
drilled to appraise the 16/1-29 Lille Prinsen Discovery in</span><span class=a1455><span lang=EN-US> the north-western part of the Utsira High in the North Sea. The structure was first tested by wells 16/1-6S and 16/1-6 A, which made the Verdandi Discovery in the Eocene Grid and the Paleocene Heimdal formations. The Lille Prinsen prospect is mapped in several geographically separate segments at Basement to Base Cretaceous level. These segments are: The Permian Main Carbonate Discovery penetrated by 16/1-29 S, the western Outer Wedge segment, and segments 2,3 and 5 (Carbonate upsides).</span></span><span lang=EN-US> </span><span lang=EN-GB>The primary well 16/1-30 S found oil in Intra-Draupne Formation sandstone in the Outer Wedge segment. The objective of 16/1-30 A was to verify lateral reservoir distribution and quality of the Outer Wedge reservoir units.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-30 A is a geological side-track to 16/1-30 S. It was kicked off at 1307.2 m on 2. July 2019 with the semi-submersible installation West Phoenix and drilled to TD at 2075 m (1989 m TVD) m in Basement rock. Operations proceeded without significant problems. The well was drilled with Versatec oil-based mud from kick-off to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-30 A encountered Viking Group sandstone and Basement Group granite reservoirs. Some shows were observed on the core chips from the Intra-Heather reservoir. MDT pressure points showed an oil gradient in Intra-Heather Formation sandstone down to 2031 m (1951.2 m TVD). Good shows with fluorescence odour and stain were recorded from top Intra-Heather Formation sandstone down to ca 2030 m. The log responses in Basement indicate the granite is oil filled at the top and water-bearing below ca 2045 m. However, MDT pressure logging gave no valid pressure points here (tight) and no shows were observed.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut. Core 1 was cut from 1993 to 2029 m with 92.3% recovery, capturing Shetland Group claystone and limestone and Intra-Heather Formation reservoir sandstone. The core-log depth shift is 2.3 m. Core 2 was cut from 2030 to 2039.46 m with 72.8% recovery, capturing basal Heather Formation claystone and granitic basement. The core-log depth shift is 4.5 m. MDT fluid samples were taken at 2026.5 m (oil with 6% OBM contamination) in Intra-Heather Formation sandstone.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 19 July 2019 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
8749
|
11/11/2021 12:00:00 AM
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04.11.2024
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16/1-30 S
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<p class=MsoBodyText><span lang=EN-GB>Well 16/1-30 S Lille Prinsen Outer Wedge was drilled to appraise the 16/1-29 Lille Prinsen Discovery o</span><span class=a1455><span lang=EN-US>n the north-western part of the Utsira High in the North Sea. The structure was first tested by wells 16/1-6S and 16/1-6 A, which made the Verdandi Discovery in the Eocene Grid and Paleocene Heimdal formations. The Lille Prinsen prospect is mapped in several geographically separate segments at Basement to Base Cretaceous level. These segments are: The Permian Main Carbonate Discovery penetrated by 16/1-29 S, the western Outer Wedge segment, and segments 2,3 and 5 (Carbonate upsides).</span></span><span lang=EN-US> </span><span lang=EN-GB>The primary objective of 16/1-30 S was to appraise the Outer Wedge segment believed to consist of Permian carbonates in the 16/1-29 S with an overlying package of Triassic to Early Cretaceous siliciclastics. The secondary objective in 16/1-30 S was to appraise the oil and gas in the Grid and Heimdal formations found in the 16/1-6 S Verdandi discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-30 S was spudded with the semi-submersible installation West Phoenix on 27 May 2019 and drilled to TD at 2140 m (1990 m TVD) m in basement rock. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 572 m, with Glydril mud from 572 to 1361 m, and with Versatec oil-based mud from 1361 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-30 S encountered poor quality oil-filled sandstone in the Grid Formation. Shows were observed on core and cuttings in the interval 1499 to 1421 m, including fluorescence and oil stain, and the log responses indicated the sandstone being oil filled. MDT pressure points was not conclusive due to poor reservoir quality, but oil was sampled at 1507.1 m and water at 1548 m. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Heimdal Formation was not present.</span></p> <p class=MsoBodyText><span lang=EN-GB>Good quality Viking Group sandstone and Basement Group granite reservoirs were encountered in the primary target. Shows were observed on core chips and sidewall cores in the interval 2016 to 2047 m, including odour, oil stains, fluorescence, and oil seeping from SWC’s. MDT pressure points confirmed an oil and a water gradient in the Viking Group. Oil was sampled at 2023.8 m and water at 2042.7 m, and the oil and water gradients intersect at ca 2029 m. </span></p> <p class=MsoBodyText><span lang=EN-GB>Four cores were cut. Core 1 was cut in the Grid Formation from 1510.9 to 1537.9 m. Cores 2 to 4 were cut in the interval 2023.2 to 2104.3 m in Intra-Draupne and Intra-Heather sandstones and upper part of Basement. The core-log depth shifts are 0.9 m, 6.2 m, 0.6 m, and 2.05 m respectively for core 1, 2, 3, and 4. MDT fluid samples were taken at 1507.1 m (oil with 8 to 14% OBM contamination) and 1548 m (water) in the Grid Formation, and at 2023.76 m (oil with 8 to 15% OBM contamination) and 2042.7 m (water) in the Viking Group.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1 July 2019 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
8748
|
11/11/2021 12:00:00 AM
|
04.11.2024
|
|
16/1-31 A
|
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-31 A was drilled in the northern margin of the Edvard Grieg Field on the Utsira High in the North Sea. The primary objective was to appraise the reservoir quality, fluid properties, hydrocarbon potential and productivity of potential reservoir rocks on the eastward continuation of the Edvard Grieg basement high.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-31 A was spudded with the semi-submersible installation Leiv Eiriksson on 11 May 2019 and drilled to TD at 2650 m (2002.6 m TVD) m in granitic basement rocks. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 1404 m, with Innovert oil-based mud from 1404 m to 2267 m, and with Baradril N water-based mud from 2267 m to TD. </span></p> <p class=MsoNormal><span lang=EN-GB style='font-family:"Times New Roman",serif; font-weight:normal'>The Tellus East appraisal well encountered a gross oil column of 60 metres in porous, weathered basement reservoir. Top reservoir was encountered at 2350.1 m (1874.8 m TVD). The oil/water contact is estimated to be between 2492 and 2497 m (1935 and 1937 m TVD). No oil shows were observed above top reservoir. Partly continuous shows with petroleum odour, stain, cut, and direct fluorescence were seen in basement down to 2390 m. Below this depth sporadic shows were observed with direct and cut fluorescence, but without odour or stain down to 2460 m.</span></p> <p class=MsoBodyText><span lang=EN-US>Three cores were cut in succession from 2357 to 2369.05 m with 85% total recovery. MDT pressure data indicated ca 4 bars depletion relative to the 16/1-13 Edvard Grieg well. MDT fluid samples were taken at 2351.51 m (oil), 2362.01 m (water), 2389.5 m (oil), 2410.4 m (oil), 2452.71 m (oil), 2492.70 m (oil and water), 2497.68 m (water), 2513.91 m (water), and 2538.0 m (water). The oil composition indicated same oil as in the Edvard Grieg oil population.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 22 June 2019 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
8758
|
12/21/2021 12:00:00 AM
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04.11.2024
|
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16/1-31 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-31 S was drilled to test the Jorvik prospect on the Utsira High, about 4 kilometres northeast of the Edvard Grieg platform in the North Sea. The primary objective was to prove oil in conglomerates from the Triassic Age in an extension of the Edvard Grieg basin toward the east. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-31 S was spudded with the semi-submersible installation Leiv Eiriksson on 10 March 2019 and drilled to TD at 2220 m in conglomerates of indeterminate Triassic to Permian age. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 602 m and with Polymer water-based mud from 602 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated the Early Cretaceous Åsgard Formation directly overlying top of the target reservoir at 1938 m (1866.4 m TVD). The reservoir contained an oil column of about 30 metres in conglomerates and conglomeratic sandstones, presumably of Triassic Age and with generally poor reservoir quality. There was around one metre of sandstone of good quality in the upper part of the reservoir section. The oil/water contact was not proven. Pressure measurements showed that the area is in communication with the Edvard Grieg field. The reservoir pressure was depleted 9-10 bar compared to the Edvard Grieg before start of production.</span></p> <p class=MsoBodyText><span lang=EN-GB>Below 1968 m and down to 2028 m shows are described on cores as: faint to moderate odour, 40% patchy weak, dark yellow direct fluorescence, slow blooming good bluish white cut fluorescence, 30% moderately, cream fluorescent residue. Patchy shows (cut and fluorescence) was described on sidewall cores down to 2176.5 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the interval 1940 to 2034.5 m. Recoveries were 100%, 97.7%, and 99.3% in cores 1, 2 and 3 respectively. MDT fluid samples were taken at 1938.61 m (oil) and 1964.57 m (oil).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged back for side-tracking (16/1-31 A) on 10 May 2019. The well was initially classified as a wildcat but has been reclassified as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>A drill stem test was conducted from perforations in the interval 1945.15 to 2001.9 m. The test produced oil and gas at relatively low rates, between 21 to 24 Sm3 oil and 4900 to 8000 Sm3 gas /day through a 26/64” choke. The GOR was between 233 and 333 Sm3/Sm3, but this was likely not representative due to slugging. The temperature at gauge depth 1920.9 m was 80.2°C.</span></p> |
8655
|
12/22/2021 12:00:00 AM
|
04.11.2024
|
|
16/1-33 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-33 S was drilled to test the Sørvesten prospect on the Gudrun Terrace west of the Utsira High in the North Sea. The primary objective was to test the hydrocarbon potential in the Middle Jurassic Sleipner Formation and the Triassic Skagerrak Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-33 S was spudded with the semi-submersible installation Leiv Eiriksson on 10 July 2020 by tagging seabed with the 9 7/8" pilot hole BHA. The shallow gas pilot hole was drilled to 555 m, 5 m deeper than the planned setting depth for the 20" surface casing. No shallow gas was encountered. Drilling proceeded to final TD at 3158 m (3066.8 m TVD) m in the Late Triassic Skagerrak Formation. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 553 m and with Rheguard oil-based mud from 553 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>No hydrocarbons were encountered in any formation. Seven pressure points were taken with Stethoscope LWD tool on the way out of hole, proving a hydrostatic pressure slightly depleted compared to the regional pressure regime. Apart from some fluorescence in traces of sand in the Draupne and Heather formations there were no shows in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut, no wireline runs were made, and no fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 6 August 2020 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
9062
|
12/21/2021 12:00:00 AM
|
04.11.2024
|
|
16/1-34 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-34 A is located on the Utsira High, north of the Edvard Grieg Field in the North Sea. The primary objective was to appraise the lateral extension and producibility of the Permian Zechstein carbonates found in well 16/1-29 S. The secondary objective was to appraise the Grid Formation injectites and Heimdal Formation sandstones.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-34 A was kicked of at 555 m in the main well on 1 August 2021. It was drilled with the semi-submersible installation Deepsea Stavanger to TD at 2195 m (2024 m TVD) in the Permian Zechstein Group. The well was drilled vertical down to 543 m, then drilled towards WSW with up to ca 30 deviation at most, then dropping to 20 deviation in the bottom section. Severe mud losses (60 90 m3/hr) were encountered after coring the first core to 2067 in the Zechstein section. The well was drilled with Rheguard Prime oil-based mud from kick-off to 2047 m and with Glydril Plus mud from 2047 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Shetland, Viking and Statfjord groups that are present in 16/1-34 S are missing in 16/1-34 A. In 16/1-34 A this interval, between 2047 m (lower V le) to 2064 (upper Zechstein), contain reworked Shetland Group chalks, possible Cromer Knoll basal conglomerates and reworked Zechstein. The Basement can be divided into a weathered section from 2104 to 2149 m and a non-weathered section below.</span></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-34 A encountered an oil column of about 66 metres, of which 46 metres was in Zechstein dolomite, with good reservoir quality. About 20 metres of the oil column was encountered in basement rock with poor reservoir quality. Pressure measurements acquired using XPT and ORA tools confirmed oil and water fluid gradients were present with a free-water level estimated at 2130 m (1962.8 m TVD RKB). As in the offset 16/1-29 S well, the formations (Zechstein and Basement) were found to be slightly depleted.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Grid Formation was penetrated below the hydrocarbon-water contact previously observed in the 16/1-34 S wellbore. The sandstones in 16/1-34 A had very good reservoir properties but contained only water. Sandstones of the Heimdal Member were of poorer quality than expected and were water filled. Pressure points were slightly scattered, and the formation was found to be pressure depleted. </span></p> <p class=MsoBodyText><span lang=EN-GB>Oil shows above OBM were observed in the uppermost Heimdal Formation down to ca 1970 m, in the Zechstein section on conventional cores and sidewall cores down to 2108.5 m, and on cuttings throughout the Basement section. In the unweathered Basement the shows are weak.</span></p> <p class=MsoBodyText><span lang=EN-GB>Four cores were cut in the well. Core 1 was cut from 2059.5 to 2067.3 m. Cores 2 to 4 were cut in succession from 2074.8 to 2079.8. total recovery for all four cores was 10.18 m (79.5%). MDT water samples were taken in the Heimdal Formation at 1975.01 m and 1985.01 m. In the Zechstein section ORA samples were taken at 2087.86 m (oil/water), 2098.86 m (oil), and 2162.13 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 15 September 2021 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>A drill-stem test was conducted in the Zechstein section from the intervals 2057.6 to 2073.4 m and 2079.8 to 2108.5 m. The main flow produced 468 Sm3 oil, 107 Sm3 water and 48150 Sm3 gas /day through a 42/64" choke. The GOR was 103 Sm3/Sm3, the oil density at 15 C was 0.854 g/cm3 and the gas gravity was 0.84 (air=1). The gas had 0.5 ppm H2S and 0.2% CO2. The temperature at 1880.4 m was 83.6 C.</span></p> |
9354
|
9/19/2023 12:00:00 AM
|
04.11.2024
|
|
16/1-34 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-34 S is located on the Utsira High, north of the Edvard Grieg Field in the North Sea. It was drilled to appraise the oil-leg in the 16/1-6 S Heimdal Formation Verdandi discovery. Grid Formation injectite sandstones and expected clastic formations of Jurassic age (Garun lead) were secondary targets.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-34 S was spudded with the semi-submersible installation Deepsea Stavanger on 7 July 2021 and drilled to TD at 2383 m (2125.7 m TVD) m in the Late Triassic Raude Formation. The well was drilled S-shaped with a vertical section down to 543 m, up to ca 40 deviation at most, then dropping to 21 deviation in the bottom section. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 543 m, with Rheguard Prime oil-based mud from 543 m to 2016 m and with Glydril Plus mud from 2016 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>In the Heimdal Formation, wellbore 16/1-34 S encountered an oil column of approximately 7 m in good quality reservoir sandstone with a total thickness of 50 m. The oil-water contact was found at 2090.2 m (1850.5 m TVD). Fluid sampling showed good quality oil. However, pressure data in the following 16/1-34 A sidetrack encountered Heimdal in a different pressure segment to the Verdandi gas discovery and consequently the 16/1-34 S oil discovery is considered to represent a separate accumulation which is not in direct contact with the Verdandi gas accumulation. This is referred to as the Lillefix discovery. The Grid Member consists of two sandstone intervals. The upper sandstone is about 8 m thick and is filled with hydrocarbons. The fluid gradient in this sandstone could not be established. The lower sandstone is about 70 m thick and is water filled. No permeable sandstone layers were encountered in the Jurassic Garun lead. There were oil shows in the Grid and Heimdal formations, else no oil shows are described in the well. </span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut in succession in the Heimdal Formation from 2085.5 to 2135.0 m with recoveries between 91.6 and 98.9 %. ORA fluid samples were taken at 2083.86 m (oil/water), 2089.35 m (oil/water), and 2090.88 m (water)</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 31 July 2021 as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
9326
|
9/13/2023 12:00:00 AM
|
04.11.2024
|
|
16/1-4
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<p><b>General</b></p>
<p>The objectives of exploration well 16/1-4 were to test Paleocene sandstones (Heimdal Formation) in prospect C and Eocene sandstones (Grid Formation) in prospect D. Prospect C was the main target. Oil was the prognosed hydrocarbon type. It was expected to penetrate a pre-Cretaceous sedimentary sequence, although the well location was not optimal for a test of the pre-Cretaceous. </p> <p><b>Operations and results</b></p> <p>Wildcat well 16/1-4 was spudded with the semi-submersible installation "Deepsea Bergen" on 17 March 1993 and drilled to TD at 2010 m, 146 m into basement rocks. The well was drilled with spud mud / hi-vis pills down to 324 m and with "ANCO 2000" mud from 324 m to TD. Well 16/1-4 penetrated sedimentary rocks of Quaternary, Tertiary, and Cretaceous ages, in addition to basement rocks of unknown age. No pre-Cretaceous sediments were present in the well. In the Tertiary, reservoir quality sandstones were present in the Miocene and the Oligocene (Utsira and Skade Formations) and in the Eocene Grid Formation. The Grid sandstones were thinner than expected. No sandstones were developed in the Paleocene (Rogaland Group) at the well location. The carbonates in the Shetland Group were dated to be of Early Paleocene, Danian age. The lower Cretaceous sediments in well 16/1-4 are 4 m thick (1860 m -1864 m) and consist of clay stone/marls and immature sandstones with grains of igneous rocks similar to the basement rocks below. These sediments are dated to be of Early Aptian age and have been identified as the Sola Formation of the Cromer Knoll Group. The basement rocks consist mainly of brecciated igneous rocks. No hydrocarbon shows were observed in the Grid Formation sandstones. Gas-condensate was encountered in the upper part of the drilled basement section. Cores were cut in the Eocene Grid Formation and in the Hordaland Group shales between upper and lower Grid Formation (cores 1-3), in the Paleocene Balder- and Sele Formations (cores 4-6), and in basement rocks (core 7).</p> <p>The cores show well-developed clean sandstones in the Grid Formation. The boundary between the Balder- and the Sele Formations is present in core 4. The basement core generally consists of a mafic plutonic rock (gabbro/diorite) with intrusions of a felsic rock (syenite). The rocks are strongly brecciated. Petrologic analysis indicates that the plutonic igneous rocks are hydrothermally altered. FMT samples from1867.5 m and 1867.4 m in the Basement contained wet gas / condensate. Onshore geochemical analyses indicated low maturity for both the gas and the condensate components. The well was permanently abandoned as a minor gas/condensate discovery on 13 April 1993.</p> <p> </p> <p><b>Testing</b></p> <p>No drill stem test was performed. </p> |
2072
|
9/10/2016 12:00:00 AM
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04.11.2024
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16/1-5
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<b>
General </b> <p> The objectives of well 16/1-5 were to prove hydrocarbon reserves in the Upper Jurassic (Oxfordian - Ryazanian) shallow marine sandstone as well as in the Middle Jurassic shallow to marginal marine sandstone. The well was also planned to provide a good stratigraphic tie to the Paleocene interval and test the possibility for Paleocene sands. A high amplitude at around 2070 ms TWT was also meant to be clarified with this well. The objective of the 16/1-5A sidetrack was to prove hydrocarbon reserves in an Upper Jurassic shallow marine sandstone, up-dip from the hydrocarbon shows that were recorded in well 16/1-5. </p> <b> Operations and results </b> <p> The main well, 16/1-5, was spudded and drilled with a water based mud to a total depth of 2460 m RKB. Both the Upper Jurassic sandstone, the Heather Formation "Sandstone Unit", and the Middle Jurassic Hugin Formation were encountered. Both sandstone sequences were water bearing, but oil shows were recorded in the upper 3 meters of the Heather Formation. A good stratigraphic tie to the Paleocene interval was established by the well, but no Paleocene sands were encountered. The high amplitude, observed on the seismic data at approximately 2070 ms TWT, most probably stems from the acoustic impedance contrast between the Heather sandstone - siltstone boundary and/or the Heather - Hugin boundary. No Permian sediments were encountered, with a stratigraphic succession going directly from Jurassic sediments into the Basement. Well 16/1-5 was terminated 194.5 m TVD into the Basement. Three cores were cut in the interval 2023 to 2066 m RKB in the Heather Formation. An FMT sample from 2024.5 m contained formation water and filtrate. The well was classified as dry. <br> The sidetrack, 16/1-5 A, was kicked off at 1440 m RKB and a 8 1/2" hole section was drilled to a total depth of 2150 m with no casing strings run. Oil based mud was used from kick off to TD. The well encountered the Heather Formation "Sandstone Unit" close to prognosis. Moderate hydrocarbon shows were recorded in the thin, Cretaceous limestone sequence above the Heather Formation as well as in the upper 8 meters of the Heather Formation sandstone. The sidetrack was terminated 24 m TVD into the Heather Formation where a core was cut from 2123 m RKB to TD. No wire line logs were run and the well was permanently plugged and abandoned. </p> <b> Testing </b> <p> No drill stem test was performed. </p> |
3279
|
7/6/2016 12:00:00 AM
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04.11.2024
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16/1-5 A
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<b>
General </b> <p> The objectives of well 16/1-5 were to prove hydrocarbon reserves in the Upper Jurassic (Oxfordian - Ryazanian) shallow marine sandstone as well as in the Middle Jurassic shallow to marginal marine sandstone. The well was also planned to provide a good stratigraphic tie to the Paleocene interval and test the possibility for Paleocene sands. A high amplitude at around 2070 ms TWT was also meant to be clarified with this well. The objective of the 16/1-5A sidetrack was to prove hydrocarbon reserves in an Upper Jurassic shallow marine sandstone, up-dip from the hydrocarbon shows that were recorded in well 16/1-5. </p> <b> Operations and results </b> <p> The main well, 16/1-5, was spudded and drilled with a water based mud to a total depth of 2460 m RKB. Both the Upper Jurassic sandstone, the Heather Formation "Sandstone Unit", and the Middle Jurassic Hugin Formation were encountered. Both sandstone sequences were water bearing, but oil shows were recorded in the upper 3 meters of the Heather Formation. A good stratigraphic tie to the Paleocene interval was established by the well, but no Paleocene sands were encountered. The high amplitude, observed on the seismic data at approximately 2070 ms TWT, most probably stems from the acoustic impedance contrast between the Heather sandstone - siltstone boundary and/or the Heather - Hugin boundary. No Permian sediments were encountered, with a stratigraphic succession going directly from Jurassic sediments into the Basement. Well 16/1-5 was terminated 194.5 m TVD into the Basement. Three cores were cut in the interval 2023 to 2066 m RKB in the Heather Formation. An FMT sample from 2024.5 m contained formation water and filtrate. The well was classified as dry. <br> The sidetrack, 1671-5 A, was kicked off at 1440 m RKB and a 8 1/2" hole section was drilled to a total depth of 2150 m with no casing strings run. Oil based mud was used from kick off to TD. The well encountered the Heather Formation "Sandstone Unit" close to prognosis. Moderate hydrocarbon shows were recorded in the thin, Cretaceous limestone sequence above the Heather Formation as well as in the upper 8 meters of the Heather Formation sandstone. The sidetrack was terminated 24 m TVD into the Heather Formation where a core was cut from 2123 m RKB to TD. No wire line logs were run and the well was permanently plugged and abandoned. </p> <b> Testing </b> <p> No drill stem test was performed. </p> |
3626
|
7/6/2016 12:00:00 AM
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04.11.2024
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16/1-6 A
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<p><b>General</b></p> <p>Well 16/1-6 A is a sidetrack to the 16/1-6 S discovery on the Utsira High in the North Sea. The objective of well 16/1-6A was to penetrate the Heimdal Formation down flank, where a flat event had been mapped, in order to appraise the extent of the gas discovery and possibly penetrate a hydrocarbon - water contact.</p> <p><b>Operations and results</b></p> <p>Appraisal well 16/1-6 A was spudded with the semi-submersible installation Borgland Dolphin on 8 June 2003. The well was kicked off at 1215 m in 16/1-6 S and drilled to TD at 2194 m in the Late Cretaceous Tor Formation. It was drilled with oil-based mud (Novatec) from kick-off to TD. </p> <p>Grid sands were penetrated from 1529.5 m (1480.5 m TVD MSL) to 1757 m (m TVD MSL). The Heimdal Formation came in at 2006.5 m (1850.5 m TVD MSL), which was considerably deeper than expected. The Heimdal Formation was also thinner than expected. Wire line and MWD logs showed relatively high resistivity readings combined with high porosity within the uppermost 2 ? 3 m of the Grid sandstone, but no conclusions regarding the presence of hydrocarbons could be drawn from these weak indications. Weak shows in the Heimdal Formation were considered to be residual only. From logs both the Grid and the Heimdal sandstones were concluded to be water wet. One core was attempted in the Grid Formation, but junk in the hole prevented the core from entering the core barrel, hence no recovery. MWD log data were collected from the whole well track, while the majority of the wire line logging, including MDT and VSP, had to be abandoned due to tight, partly collapsed hole. </p> <p>The well was permanently abandoned on 21 June 2003 as a dry hole.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
4767
|
7/6/2016 12:00:00 AM
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04.11.2024
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16/1-6 S
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<p><b>General</b></p> <p>Wildcat well16/1-6 S is located on the Utsira High in the North Sea. The objective was to test the hydrocarbon potential of the Verdandi prospect on Paleocene level in a favourable position with respect to an observed DHI, interpreted tentatively as a gas-oil contact in a reservoir sand.</p> <p><b>Operations and results</b></p> <p>Wildcat well 16/1-6 S was spudded with the semi-submersible installation Borgland Dolphin on 22 May 2003 and drilled to TD at 1997 m in the Late Cretaceous Ekofisk Formation. Sidewall coring and VSP logging could not be performed below 1762 m due to hole problems. Apart from this no significant problems were encountered in the operations. The well was drilled with seawater and viscous bentonite/polymer pills down to 551 m, with KCl/polymer/glycol (Glydril) mud from 551 m to 1200 m, and with oil based mud (Novatec pseudo oil based) from 1200 m to TD. </p> <p>MWD logs and drill gas indicated shallow gas in a sandstone stringer at 603 m. This gas correlate well with nearby wells, particularly well 16/1-4. </p> <p>Grid sandstones were encountered between 1489.5 m (1451 m TVD MSL) to 1685 m (1617.5 m TVD MSL). Top Heimdal Formation came in at 1861.5 m (1765 m TVD MSL). It proved to be slightly deeper and significantly thinner than expected. Hydrocarbons were proven in the Grid sands as well as in the Heimdal sand. A distinct gas peak of 2.55 %, C1 to C4, was recorded from 1498 m in the upper Grid Formation. Log responses indicated thin, hydrocarbon filled stringers of sand positioned above the massive Grid sandstone. Cuttings exhibited calcareous sand with traces of hydrocarbon stain and with spotty to even, bright, bluish white, direct fluorescence with instant, white cut fluorescence. MDT hydrocarbon samples confirmed the presence of oil, with a density of 0.857 g/cm³. No shows were seen in the underlying, massive Grid sandstone with logs confirming a water-wet sandstone. Furthermore gas was found in the Heimdal Formation with a ?gas down to? situation. One conventional core was cut from 1872 m to 1899 m in the Heimdal Formation. Sidewall cores were recovered from the Grid Formation sandstones. MDT hydrocarbon samples were collected from 1499 m in the Grid Formation and 1870.5 m in the Heimdal Formation. Oil based mud contamination was as high as 59 % in the Heimdal sample which gave limited value for PVT analysis. The oil sample collected in the Grid sandstone was of good quality with contamination calculated to 16 %. </p> <p>The well was permanently abandoned on 7 June as an oil and gas discovery.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
4711
|
7/6/2016 12:00:00 AM
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04.11.2024
|
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16/1-7
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<p><b>General</b></p> <p>The primary objective of well 16/1-7 was to test the hydrocarbon potential of the West Cable prospect. The prospect was located on the eastern margin of the South Viking Graben southwest of the Utsira High in the North Sea, approximately 35 km southwest of the Balder Field. The main objective of the well was to test the hydrocarbon potential of the Sleipner Formation coastal plain sandstone reservoir of Callovian and Bathonian age. The hydrocarbon potential of the Late Jurassic Heather and Draupne Formations, and the Tertiary Lista and Våle Formations were considered as secondary objectives. The anticipated hydrocarbon type was light oil. Planned TD was 50 m into Triassic sediments.</p> <p><b>Operations and results</b></p> <p>Well 16/1-7 was spudded with the semi-submersible installation Deepsea Delta on 29 April 2004 and drilled to TD at 3186 m 103 m into in the Late Triassic Skagerrak Formation. No significant problems were reported from the operations. The well was drilled with seawater + high viscosity polymer sweeps down to 1286 m and with Versavert oil based mud from 1286 m to TD. No shallow gas was observed.</p> <p>A 73 m thick Heimdal Formation (Meile Member) was encountered at 2327 m. The Formation was water wet with no shows. No sands were developed in the Late Jurassic. The well discovered a 14.0 m (11.0 m net) oil bearing sand between 2955.5 and 2969.4 m (logging depth) in the Sleipner Formation. The RCI tool was used to take pressures and samples. The reservoir was normally pressured. Four 840 cc and two 4 litre samples were taken in the oil zone at 2965 m, 2964.1 m and two 840 cc samples were taken in the water zone at 2977.5 m, 2976.5 m. The interpreted Free Water Level was at 2969.9 m. No conventional coring was performed in the well.</p> <p>The well was permanently abandoned on 28 May 2004 as an oil Discovery.</p> <p><b>Testing</b></p> <p>The discovery was tested using RCI straddle packer assembly (also called mini drill stem tests) at 2975 m, 2964.5 m and 2959.5 m (logging depth). </p> |
4928
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/1-8
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<p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-8 was drilled on the Luno Prospect on the eastern margin of the South Viking Graben on the south-western part of the Utsira High in the North Sea. The Luno prospect is situated between well 16/1-5 with oil shows in Late Jurassic and 16/1-4 with gas/condensate discovery in fractured basement rocks and up dip from the 16/1-7 Jurassic discovery. The primary objective of well 16/1-8 was to test the hydrocarbon potential in Late Jurassic sandstones of the Viking Group. Secondary objectives were to assess the quality of the Eocene Grid Formation and Permo-Triassic sandstones. Total depth was planned in basement at 2173 +/- 50 m.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-8 was spudded with the semi-submersible installation Bredford Dolphin on 8 September 2007 and drilled to TD at 2200 m in undefined Triassic formations consisting of conglomerates, sandstones and claystone. A shallow gas zone was warned and encountered in a thin sand from 634 - 638 m. Downtime (NPT) for the operations was as much as 33% of total rig time. Forty-four per cent of the total NPT was due to WOW before anchor handling. Another 14 % of NPT was caused by problems with cementing the 13 3/8" casing. In addition formation characteristics in the reservoir made operations challenging, and combined with increased formation evaluation scope; time spent on coring, logging and drilling to TD drastically increased compared to plan. The well was drilled with seawater and hi-vis pills down to 400 m, with KCl/glycol enhanced mud (GEM) from 400 to 1196 m, and with Performadril mud from 1196 m to TD. Performadril may contain up to 5% polyakylene glycols.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Eocene sandstones of the Grid Formation at 1556 m were found water bearing with normal pressure gradient. Top Jurassic was encountered at 1925 m and contained sandstones and conglomerates with hydrocarbon shows. A 2 m thick and questionable Late Jurassic sequence was seen on top. Palynoflora at 1930.7 m suggested a Middle to Early Jurassic age. Hydrocarbons were encountered from 1925 m down to an OWC based on MDT pressure data at ca 1965 m, which gives an oil column of ca 40 m. Shows on cores continued down to 1966.3 m. No shows were recorded below this depth or above 1925 m. The reservoir was not easily characterized by log data as these were affected by feldspar rich conglomerates and other electrically conductive materials.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three conventional cores were cut. The first two were taken in the hydrocarbon bearing interval and the third in the water bearing interval. MDT pressure and fluid sampling was carried out and the fluid gradients were determined (oil and water). The fluid samples were taken at 1933.6 m, 1939.4 m, 1952.8 m, and 1956.4 m (oil), and at 1982 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The plan was to permanently abandon the well, but due to the characteristics of the discovery, a decision was made to temporary abandon the well with the purpose of re-entering to perform a DST at a later stage. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was suspended on 13 November 2007 as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
5612
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/1-8 R
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/1-8 R is a re-entry of well 16/1-8, which made the Luno discover in Jurassic sandstone and conglomerate. The purpose of the re-entry was testing and plugging of the bore hole.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-8 R was re-entered with the semi-submersible installation Transocean Winner on 2 October 2009. </span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>After testing the well was permanently abandoned on 10 October.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was perforated and tested in two intervals with flow rate up to approximately 3547 barrels of oil per day (564 Sm3/day) through a one inch (40/64") choke.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6226
|
4/2/2020 12:00:00 AM
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04.11.2024
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16/1-9
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The 16/1-9 Draupne prospect is located on the eastern margin of the South Viking Graben in the North Sea. The structure is situated in the eastern part of the Gudrun Terrace and the western flank of the Utsira High. The primary target was a faulted anticline trap within Hugin/Sleipner reservoir sandstones of Middle Jurassic Bajocian - Callovian age. A secondary target was mapped on a four way dip closure within the Paleocene top Heimdal level, the Gugne prospect. Well 16/1-9 was planned as a vertical well with TD ca 50 m into the Hugin/Sleipner Formation if water bearing, or ca 50 m into the Triassic Skagerrak Formation in case of a discovery. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-9 was spudded with the semi-submersible installation Bredford Dolphin on 19 February 2008 and drilled to TD at 2544 m in the Late Triassic Skagerrak Formation. A pilot hole was drilled prior to the 36" section. No signs of shallow gas were observed or seen on MWD logs. Significant downtime resulted from a shallow water flow beside the well (5.2 days), wait on weather (4.3 days), BOP acoustic failure (3.5 days), poor hole conditions (2.9 days) and stuck wire line (2.2 days). The well was drilled with Seawater and sweeps down to 600 m, with KCl/GEM mud from 600 m to 1281 m, and with Performadril mud from 1281 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The secondary target Heimdal Formation was entered at 2126.0 m (2123.2 m TVD), approximately 100 meters deeper than the prognosed depth, and it was dry. The Sleipner Formation sandstone was encountered at 2399.0 m (2393.2 m TVD), 167 TVD meters deeper than prognosed. The Skagerrak Formation was encountered at 2411 m (2405 m TVD), 23 TVD meters shallower than prognosed. The wire line logs proved a thin gas cap from 2399 m (2368 m TVD MSL) to about 2407.5 m (2376.5 m TVD MSL), oil down to 2442.5 m (2411 m TVD MSL) and oil shows on cuttings down to 2448 m. There was no indication of an oil-water contact from the logs. The reservoir quality is variable with good reservoir sands disrupted by shale layers and cemented zones (carbonate nodules/clasts).</span></p> <p class=MsoBodyText><span lang=EN-GB>Apart from shows in the Sleipner and Skagerrak formations reservoir zone oil shows were observed also in thin Hordaland Group sandstones from 1510 to 1540 meters.</span></p> <p class=MsoBodyText><span lang=EN-GB>One core was cut at 2417.5 to 2426.9 m in the Skagerrak Formation with 100% recovery. The MDT tool was run on wire line. One gas and one oil sample were taken at 2405.0 and 2419.5 m respectively. During the MDT run the wire line cable got stuck and further wire line operations were terminated.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 22 April 2008 as an oil discovery</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
5773
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4/11/2017 12:00:00 AM
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04.11.2024
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16/2-1
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<p><b>General</b></p>
<p>Well 16/2-1 is located on the very western part of the Utsira High in the central part of the Vestland Arch. The Utsira High is a large, flat, fault bounded basement feature. The objective of this early well in the North Sea was: "To test the hydrocarbon potential of the sedimentary section; investigate the lithology and sequence in this portion of the North Sea basin; and to partially fulfil Esso's drilling obligation to the Norwegian Government incurred on behalf of the Licences." </p> <p><b>Operations and results</b></p> <p>Wildcat well 16/2-1 was spudded with the semi-submersible installation Ocean Traveler on 11 July 1967 and drilled to TD at 1906 m, 33 m into basement rock. There were no noteworthy drilling problems encountered while drilling. Initial drilling from the sea floor to 381 m was with seawater and gel without casing. Returns were to the sea floor. Below 381 m to total depth of 1906 m, a seawater slurry with gel, CMC, Spersene, XP-20, Caustic Soda, Barite, and 0-10% diesel oil was used.</p> <p>Oil shows were seen on cores in tight Cretaceous carbonate rocks in the Tor Formation. The shows were strong and continuous from top Tor Formation down to 1776 m, and then became patchy. These rocks were too impermeable to justify further tests in this well. Weak shows were seen also in a thin Oligocene sand from 1256 m to 1263 m and in Eocene mudstones from 1631 m to 1637 m, Balder Formation. Dead oil/tar was observed in fractures in the basement rock. </p> <p>Five cores were cut from 1739.5 m to 1821.8 m in the Tor Formation chalk and two more cores were cut from 1879.1 m to 1883.7 m in the basement. Four Formation Interval Tests (FIT) were performed at 1748.9 m, 1733.4 m, 1642.6 m, and at 1738.2 m. The tests, one in Early Tertiary shales and three in Late Cretaceous carbonates, did not show any hydrocarbons.</p> <p>The well was permanently abandoned on 9 August 1967 as a well with shows.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
144
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5/19/2016 12:00:00 AM
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04.11.2024
|
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16/2-10
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-10 was drilled on the Utsira High in the North Sea to appraise the northern part of the Aldous Major Discovery in a segment called Espevær. The main objective was to investigate the hydrocarbon potential and the</span></p> <p class=MsoBodyText><span lang=EN-GB>reservoir quality and lateral sand distribution in Late Jurassic sandstones in the Draupne Formation of the Viking Group, and the Hugin and Sleipner Formations of the Vestland Group. The secondary well objective was to explore the reservoir properties in the Triassic age Skagerrak Formation. The third objective was to investigate the hydrocarbon potential in the Cretaceous chalk of the Shetland Group.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>A 9 7/8" pilot hole 16/2-U-6 was drilled to check for shallow gas down to setting depth for the 20" casing. No sign of shallow gas or shallow water flow was seen on the logs nor observed by the ROV. </span></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-10 was spudded with the semi-submersible installation Transocean Leader on 27 September 2011 and drilled to TD at 2090 m in the Late Triassic Skagerrak Formation. No significant problem was encountered in the operations. The well was drilled with sea water down to 463 m and with water based Performadril mud with 3-4% glycol from 463 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-10 penetrated sediments of Cenozoic, Cretaceous, Jurassic and Triassic age. Top of the Intra Draupne Formation sandstones, came in at 1892 m. An oil column of 66 meters was found in these sandstones and the underlying sandstones of the Middle Jurassic Hugin Formation. The free water level was established at 1957.7 m (1934.2 m TVD MSL) as confirmed by logs, cores, pressure data and fluid samples. This is deeper than in the 16/2-8 discovery well, where the free water level was found at 1920.7 m. The Triassic Skagerrak Formation was water wet. There were no sign of hydrocarbons in the Shetland Group. Oil shows were recorded from 1890 m to 1953 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Four cores were cut from 1889.5 m in the Åsgard Formation to base Hugin Formation at 1962 m. Reservoir fluid samples were obtained in 3 MDT runs at 7 depths: 1893.5 m (oil), 1927.0 m (oil), 1935.5 m (oil), 1935.7 m (oil), 1955 m (oil and some water), 1961 m (water), and 1966 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 28 October 2011 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
6715
|
4/11/2017 12:00:00 AM
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04.11.2024
|
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16/2-11
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-11 was drilled to appraise the western part of the Johan Sverdrup (formerly Avaldsnes) discovery on the Utsira High in the North Sea. The primary objective was to prove a 50 to 60 m oil column in Middle - Late Jurassic sandstones. The well would also serve as calibration for seismic interpretation and depth conversion and it would give information about any lateral variation in facies and thickness of the Johan Sverdrup reservoir.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-11 was spudded with the semisubmersible installation Bredford Dolphin to 2126 m in the Triassic Skagerrak Formation. A 9 7/8" pilot hole was drilled to 756 m to check for shallow gas. No indication of shallow gas was observed. No significant problem was encountered in the operations. The well was drilled with sea water and hi-vis pills down to 756 m and with Performadril Water Based Mud from 756 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top reservoir, Intra-Draupne Formation sandstone, was encountered at 1890 m and Middle Jurassic sandstones, Vestland Group, was encountered at 1910 m. The reservoir was encountered at the prognosed depth and 54 m oil column in an oil-down-to situation was proven. The well also confirmed good reservoir properties, in line with the earlier Johan Sverdrup wells where the Late Jurassic reservoir was also of excellent quality with a high net to gross ratio. A peak of high gamma ray between 1889.3 m and 1890 m, indicated a 0.7 m thick Draupne shale on top of the reservoir, but this could not be confirmed by cuttings samples and adjacent sidewall cores. Oil shows were restricted to the Middle-Late Jurassic reservoir section.</span></p> <p class=MsoBodyText><span lang=EN-GB>Five cores were cut from 1891.6 m, just below the possible Draupne shale, to 1957.78 m, ca 12 m into the Skagerrak Formation. Overall good recovery was obtained. MDT fluid samples were taken at 1895.61 m (oil), 1918.41 m (oil), 1937.02 m (oil), 1941.75 m (oil), 1951.38 m (water), and at 2059.09 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29 March 2012 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>A production test (DST) was run over the interval 1934.5 m to 1943.3 m in the previously untested Middle Jurassic reservoir section to investigate its flow properties. The main flow gave 476 Sm3 oil and 14500 Sm3 gas per day through a restricted 40/64 choke, with good reservoir properties indicating a laterally continuous reservoir. The GOR was 30 Sm3/Sm3, the oil density was 0.89 g/cm3, and the gas gravity was 0.768 (air = 1). The flowing temperature, recorded at depth 1908.2 m, was 79.7 deg C. </span></p> |
6742
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4/11/2017 12:00:00 AM
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04.11.2024
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16/2-11 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-11 A is a sidetrack to well 16/2-11. It was drilled to appraise the western part of the Johan Sverdrup (formerly Avaldsnes) discovery on the Utsira High in the North Sea. The primary objectives of 16/2-11 A was to verify the system pressure and oil-water contact in the 16/2-11 area and to get a representative water sample from the central part of the Johan Sverdrup field. The well would also give information about variations in lateral thickness and facies in the Johan Sverdrup Field for better understanding of geology and field drainage strategy.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-11 A was kicked off from 770 m in the main well bore on 29 March 2012. It was drilled with the semi-submersible installation Bredford Dolphin to TD at 2365 m (2073 m TVD) in the Triassic Skagerrak Formation. The sidetrack deviation was up to 45 degrees and it penetrated BCU ca 950 m to the north-east of the main well location. No significant problem was encountered in the operations. The well was drilled with Performadril Water Based Mud from kick-off to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated a 4 m thick Draupne Formation from 2180 m to 2184 m. The Draupne Formation consisted of decimetre scale Spiculites and fine grained sandstones interbedded with centimetre scale laminated mudstones typical of the Draupne shales. It was dated Late Volgian to Late Ryazanian. Top Intra-Draupne Formation Sandstone was penetrated at 2184 m (1915 m TVD). The Vestland Group was encountered at 2206 m (1934 m TVD) with a section of claystone and silstone on top down to 2215 m (1942 m TVD) and heterolithic sandstone from there down to top Skagerrak Formation at 2239 m (1963 m TVD). The oil water contact was established at 2221 m (1947 m TVD). This is in line with other wells in the License. The well also confirmed the good reservoir properties encountered in the well 16/2-11. Minor oil shows were reported in one sample of tuff from the Balder Formation at 1600 m, otherwise oil shows were restricted to the Middle to Late Jurassic reservoir section.</span></p> <p class=MsoBodyText><span lang=EN-GB>Five cores were cut from 2169 m to 2243 m with 98-100% recovery in all cores. The cores covered the entire section from base Åsgard Formation, across the BCU, through the Late to Middle Jurassic reservoir, and into the upper Skagerrak Formation. MDT fluid samples were taken at 2186.1 m (oil), 2202 m (oil), 2223.5 m (oil), 2225.1 m (water), and 2233.4 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 4 May 2012 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6849
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/2-12
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-12 was drilled on the Geitungen Prospect on the Utsira High in the North Sea. The prospect is situated on a basement terrace north-west of the Johan Sverdrup Field. The main objectives were to investigate the hydrocarbon potential, reservoir quality, and lateral distribution of Intra-Draupne Formation sandstones, and the underlying sandstones of the Hugin and Sleipner Formations. The secondary objectives were to explore the hydrocarbon potential and reservoir properties in the fractured granitic Basement.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-12 was spudded with the semi-submersible installation Ocean Vanguard on 25 July 2012 and drilled to TD at 2067 m in granite Basement. There was a pre-drill shallow gas warning at 707 m, ca 100 m below 20” casing shoe, but no gas was observed when drilling. The well was drilled with seawater down to 211 m and with PerformaDril water based mud from 211 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated rocks of Quaternary, Neogene, Paleogene, Cretaceous and Jurassic age. No indication of hydrocarbons were recorded above top Intra Draupne Formation sandstone, which was picked at 1894 m, 12 m deeper than prognosed. The reservoir had excellent reservoir properties and contained oil. The top of the Basement was picked at 1938 m, 5 m deeper than prognosed. The fractures in the uppermost part of Basement were oil-filled. The oil/water contact was not encountered, but pressure measurements indicate a connection between this segment and the rest of the Johan Sverdrup discovery. Extensive data acquisition and sampling was carried out. The gas/oil ratio is 51.8 Sm3/Sm3 and the oil density is estimated at 0.81 g/cm3 in the Intra-Draupne reservoir. </span></p> <p class=MsoBodyText><span lang=EN-GB>Four cores were cut in the interval 1893 m to 1951.7 m, covering the whole Jurassic interval and 13.7 m of the Basement. The difference between the cores depth and wireline logs depth is less than 50 cm. Core 1 was dripping with oil and had excellent shows. The same type of shows continued on core 2 down to 1930 m. From 1930 – 1940 m, the shows disappeared. From 1940 m, oil was observed in fractures in the granitic Basement. Due to less fractures in core 4 shows disappeared. The deepest indication of weak shows were seen at 1950 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Reservoir fluid samples were obtained at four depths, with three MDT runs in the well. Large diameter probe was used on MDT wireline runs 5 and 7, and dual straddle packer was used on MDT wireline Run 8. In Run 5, samples were taken in Intra-Draupne Formation sandstone at 1901.3 m (oil) and in the Basement at 1940.0 m (oil with water and filtrate). In Run 7 samples were taken in Intra-Draupne Formation sandstone at 1928.3 m (oil), In Run 8 samples were taken in the Basement at 1940.1 m (oil with water and filtrate) and at 1945 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 6 September 2010. It was planned and drilled as a wildcat well. However, after performing data acquisition, and acquiring formation pressure testing data in the reservoir section, the well was reclassified as an appraisal of the Johan Sverdrup field. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Formation tests (mini-DST) were conducted in the bedrock, revealing stable flow rates of both oil and water in different levels in the fractured and weathered bedrocks. </span></p> |
6952
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4/11/2017 12:00:00 AM
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04.11.2024
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16/2-13 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-13 A is a geological side track to well 16/2-13 S on the Johan Sverdrup discovery on the Utsira High in the North Sea, 6.7 km northeast of well 16/2-8 and 2.4 km north-east of well 16/2-6. The objective of the side track was to calibrate the depth model in a position far enough away from 16/2-13 S to provide significant information for depth conversion; to investigate if FWL in 16/2-10 is present in area across the fault close to 16/2-13 S and; to map lateral thickness and quality variations in the Jurassic sequence.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-13 A was kicked off at 735 m in 16/2-13 S on 30 August 2012. The semi-submersible installation Transocean drilled the well to TD at 2776 m (2101.7 m TVD) in indeterminate pre-Rotliegend Group rock. The sidetrack was drilled with Enviromul OBM.</span></p> <p class=MsoBodyText><span lang=EN-GB>The reservoir was encountered at 2596.06 (1926 m TVD) about 1250 metres north of well 16/2-13 S and slightly shallower than prognosis. It consisted of a 26.5 m thick Intra-Draupne, Intra-Heather and Hugin sandstone package, similar as in 16/2-13 S. The oil column in the sidetrack was 12 m and the oil water contact was established at 1949 m TVD (1925 m TVD MSL). </span></p> <p class=MsoBodyText><span lang=EN-GB>Four cores were cut from 2587.3 m in Draupne Formation shales to 2669.0 m in Pre-Rotliegendes rock. The core to log shift for all four cores is -1.5 m. The core recovery was 100%. RCX wire line fluid samples were taken at 2596.7 m (oil), 2607.5 m (oil), 2608.5 m (oil and water), 2610.7 m (water), and 2615.0 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29 September 2012 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7028
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/2-13 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-13 S was drilled on the Johan Sverdrup discovery on the Utsira High in the North Sea, 6.7 km northeast of well 16/2-8 and 2.4 km north-east of well 16/2-6. The main objectives were to confirm an oil saturated Upper Jurassic Draupne sand thickness of approximately 30 meter in the northeastern part of Johan Sverdrup; to establish the Johan Sverdrup pressure system and oil-water-contact in this area; and to improve the understanding of Draupne sand facies changes and lateral Draupne shale thickness variations.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The 16/2</span><span lang=EN-GB style='font-family:"Cambria Math",serif'>‐</span><span lang=EN-GB>13 (later renamed as 16/2</span><span lang=EN-GB style='font-family:"Cambria Math",serif'>‐</span><span lang=EN-GB>U</span><span lang=EN-GB style='font-family:"Cambria Math",serif'>‐</span><span lang=EN-GB>13) well was drilled according to the well design with the semi-submersible installation Transocean Arctic. A 9 7/8” pilot hole was drilled from the seabed and encountered shallow gas at 382 m. The hole was then plugged back with gas tight cement and the rig was moved 45 m SW. The appraisal well 16/2</span><span lang=EN-GB style='font-family:"Cambria Math",serif'>‐</span><span lang=EN-GB>13 S was then re</span><span lang=EN-GB style='font-family:"Cambria Math",serif'>‐</span><span lang=EN-GB>spudded on 24 July 2012 and a new 9 7/8” pilot hole was drilled to 725 m without seeing shallow gas. Drilling continued with 36”, 26”, 12 ¼” and 8 ½” hole sections and reached TD at 2090 m (2085.7 m TVD) in Pre-Permian fractured granite and quartzite rock. Seawater and high viscosity pill was used as drilling fluid on the riserless sections down to 725 m, while Performadril water based mud was used from 725 m To TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Draupne Formation shale was encountered at 1914.5 m (1910.2 m TVD) and was 10 m thick. Intra Draupne Formation sandstone was drilled from 1924.4 m to 1939.9 m (1920.1 m to 1935.6 m TVD). A 25 m oil column was confirmed in these sandstones and down through sandstones in the underlying Heather Formation (1 m thick) and Hugin Formation (8 m thick) to top Skagerrak Formation at 1949.3 m (1945 m TVD). The reservoir was oil filled to the base with an oil-down-to contact at top Skagerrak Formation. The upper Intra Draupne Formation sandstone had very good reservoir properties. No shows were recorded above top Jurassic or below the oil-bearing reservoir. </span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut across the reservoir from 1918 m in Draupne Formation shale to 1971.8 m in the Rotliegend Group. The core to log depth shift is -1.6 m for both cores. The core recovery was 100%. RCX oil samples were collected at, 1925.0 m, 1940.7 m and 1948.7 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 30 August as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
6888
|
4/11/2017 12:00:00 AM
|
04.11.2024
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16/2-14
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-14 was drilled on the Espeværhøgda prospect on the Johan Sverdrup Field on the Utsira High. The main objective was to investigate the reservoir thickness, quality and facies near the crest of the whole Johan Sverdrup structure. The secondary objective was to acquire data in the overburden for field development decisions and planning of future production and injection wells at Johan Sverdrup Field. A third objective was to investigate reservoir presence in the Triassic section (Hegre Group). The fourth objective was to investigate the reservoir quality of the Shetland Group chalk (Ekofisk/Tor Formation).</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>A pilot hole 16/2-U-14 was drilled 30 m south of the main wellbore location to aid in picking core points in the overburden. Appraisal well 16/2-14 was spudded with the semi-submersible installation Ocean Vanguard on 14 September 2012 and drilled to 1210 m where a fish was lost in hole. The hole was cemented back and it was decided to set the 13 3/8 casing shoe. Well 16/2-14 T2 was sidetracked from 16/2-14 below the 13 3/8" casing shoe at 1171 m and drilled to TD at 1982 m in the Triassic Skagerrak Formation. The well was drilled with Seawater down to 608 m and with oil based XP-07 mud from 608 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Good oil shows were recorded at top Ekofisk level from 1565 to 1570 m. Weak shows (from OBM?) were recorded in the Ekofisk chalk from 1570 to 1733 m. The well encountered the target Late Jurassic reservoir sand 18 m deep to prognosis, at 1856 m. The reservoir showed good reservoir properties and contained oil. Top Triassic, the tertiary objective, came in at 1886 m, 11 m deeper than prognosed. There were no shows on the core from the Triassic section (core 7).</span></p> <p class=MsoBodyText><span lang=EN-GB>Seven cores were cut. Core 1 was cut from 811 to 820 m in Utsira Formation sandstone, core 2 was cut from 987 to 996 m in Skade Formation sandstone, and core 3 was cut from 1067 to 1076 m in undifferentiated Hordaland Group sandstone and core 4 was cut from 1539 to 1548 m in the Lista Formation mudstone. Cores 5 to 7 were cut in succession from 1836 to 1904.5 m, covering the interval from lowermost Cretaceous, through the whole reservoir section, and 16 m into the Triassic. MDT water samples were taken at 820.05 m, 820.53 m and 820.98 m in the Utsira Formation and at 1116.53 m in undifferentiated sandstone in the Hordaland Group. Oil samples were taken at 1858 m in the Late Jurassic reservoir sandstone. Fifteen percent contamination of the sampled fluid was estimated.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 17 November 2012 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Injection tests were performed in the plug and abandon phase.</span></p> |
6898
|
4/11/2017 12:00:00 AM
|
04.11.2024
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16/2-15
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The 16/2-15 Kvitsøy Basin well was drilled as an appraisal well for the Aldous Major South discovery in PL265 that together with Avaldsnes discovery in PL501 was to be called the Johan Sverdrup Field. The objective of 16/2-15 was to investigate the reservoir thickness, quality and facies in the southwestern part of the Johan Sverdrup Field. A specific objective was to obtain good water samples from the reservoir.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-15 was spudded with the semi-submersible installation Ocean Vanguard on 21 November 2012 and drilled to TD at 2006 in the Triassic Skagerrak Formation. A 9 7/8” pilot hole was drilled to 511 m to check for shallow gas. No shallow gas was observed. No significant problem was encountered in the operations. The well was drilled with seawater down to 736 m, with Performadril water based mud from 736 m to 1159 m, and with XP07 oil based mud from 1159 m to TD. The oil-based mud was chosen to avoid drill water contamination in the water samples from the reservoir.</span></p> <p class=MsoBodyText><span lang=EN-GB>The target reservoir, Intra Draupne Formation sandstones, was encountered at 1913 m. The reservoir was oil filled down to top Statfjord Group at 1945 m. Pressure data and logs indicate a true OWC at this depth. Oil shows on cores continued down to 1958 m. Oil shows were not observed above top reservoir or below 1958 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Five cores were cut from 1895 m in the Åsgard Formation and down through the entire reservoir section to 1990.7 m in the Skagerrak Formation. MDT fluid samples were taken at 1913.8 m (oil), 1916.6 m (oil), 1926.9 m (oil), 1946.5 m (water), and at 1957.1 m (water). Water samples of good quality was obtained.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13 January 2013 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
6979
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/2-16
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-16 was drilled on the northeastern part of the Johan Sverdrup Field on the Utsira High. The main objective was to acquire information about the Jurassic reservoir properties and hydrocarbon column in this part of the field. Secondary objectives were to investigate the reservoir properties of the Zechstein Group, and to determine whether oil-bearing Paleocene sandstones (Heimdal and Hermod formations) were present.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-16 was spudded with the semi-submersible installation Transocean Winner on 11 November 2012 and drilled to TD at 2214 m in the Permian Rotliegend Group. A 9 7/8” pilot hole was drilled to a total depth of 706 m to check for shallow gas before opening up the pilot hole to 36" and 26" sections. No shallow gas was observed. No significant problem was encountered in the operations. The well was drilled with seawater and bentonite mud down to 695 m and with Glydril mud from 695 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>No Paleocene sands were present in the well. In total 15 m of net sandstone was found within a 60 m Jurassic sequence. The top of the reservoir was penetrated at 1950 m as prognosed. The oil/water contact was identified at 1952 m just above the good reservoir sand. This is the same level as observed in well 16/2-13 A and 3 m deeper than found in previously drilled wells in PL 501. The 6 m thick Intra Draupne Formation sandstone below the contact sand had good shows. A 3 m thick sandstone in the Vestland Group had similar, but weaker shows; otherwise, no shows were reported from the well. The Zechstein Group consisted of water-wet sandstones, limestones and siltstones with a water gradient in line with the above Jurassic sandstones.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two successive cores were cut from 1947 m in the lower Draupne Formation and down to 1986.8 m in the Statfjord Group. Oil and water samples were collected using MDT. Water was sampled at 1952.1 and 1966.0 m. At 1951.6 m, formation water, mud filtrate and oil were sampled with 68 bars drawdown.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged back and completed for sidetracking on 12 December 2012. It is classified as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7047
|
4/11/2017 12:00:00 AM
|
04.11.2024
|
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16/2-16 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-16 A is a sidetrack to well 16/2-16 on the northeastern part of the Johan Sverdrup Field on the Utsira High. The primary well bore found the oil/water contact at 1952 m, in line with the other wells in PL501. The main objective was to investigate lateral thickness and facies variations within the Viking Group and the Vestland Group in the area 1000 m to the west of the main wellbore. Further, to provide input to the Johan Sverdrup water injection strategy, and to investigate lateral pressure and free water level variations.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-16 A was kicked off from 693 m in main well bore 16/2-16 on 13 December 2012. It was drilled with the semi-submersible installation Transocean Winner to 2274 where the string stuck. Attempts to free the string failed and in the end, a 434 m fish was left in the hole. The hole was cemented back and a technical sidetrack, 16/2-16 A T2, was kicked off from 1600 m. Drilling continued to final TD at 2503 m (2085 m TVD) in the Triassic Skagerrak Formation. The well was drilled with Versatec oil based mud from kick-off to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well encountered a gross oil column of approximately 30 m within a Jurassic sequence with largely excellent reservoir quality. No firm FWL could be established. A range for the FWL from a clean oil sample at 2361.9 m (1960.7 m TVD) to approximately 2368 m (1966 m TVD) from water gradient/oil gradient intersection was suggested. This is the deepest contact so far observed in the Johan Sverdrup area. Very weak shows (trace blue-white fluorescent cut) were recorded below the FWL, and a good spot of oil show (stain, odour, yellow-brown fluorescence) was described at 2382.5 m in the Eirikson Formation. No shows were recorded in the Skagerrak Formation.</span></p> <p class=MsoBodyText><span lang=EN-GB>Five cores were cut in succession in the 16/2-16 A T2 sidetrack from 2324 m in the Draupne Formation to 2420 m in the Skagerrak Formation. MDT fluid samples were taken at 2327.3 m (oil), 2355.0 m (oil), 2361.9 m (oil), and at 2379.9 m (water)</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12 December 2012 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7107
|
3/28/2023 12:00:00 AM
|
04.11.2024
|
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16/2-17 B
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-17 B is a geological sidetrack to well 16/2-17 S. The sidetrack targeted the Cliffhanger South prospect on the western side of the main western bounding fault on the Johan Sverdrup Discovery. The primary objective of 16/2-17 B was to investigate whether the Intra-Draupne Formation sandstone is present west of the main bounding fault. A secondary objective was to investigate the hydrocarbon potential of the Basement, which is expected to be directly beneath the Jurassic reservoir. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal sidetrack well 16/2-17 B was drilled with the semi-submersible installation Ocean Vanguard. It was kicked off from 600 m in the primary well bore on 20 May 2013 and drilled to TD at 2200 m (1937 m TVD) in pre-Devonian granitic basement. No significant problem was encountered in the operations. The well was drilled with XP-07 oil based mud.</span></p> <p class=MsoBodyText><span lang=EN-GB>This well did not encounter any Jurassic strata, nor any sands with potential reservoir properties. The top of the Basement was encountered at 2133 m, which was 23 m TVD deeper than prognosed. The granitic Basement contained hydrocabons; however, the fractured top was disappointing concerning reservoir properties. Apart from the shows in top of the granitic basement, no oil shows above the oil-based mud were recorded in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut through the target prospect, from 2087 in the Rødby Formation to 2144.5 m in the Basement. The basement core recovered 70.5% (including ca 7.6 m of the basement); the two others had 100% recovery. MDT pressure evaluation was attempted at four depths in the top of the basement without success due to tight rock. No fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 16 May 2013 as a dry well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7175
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/2-17 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-17 S was drilled on the western flank of the Johan Sverdrup Discovery. The main objectives were to investigate the reservoir thickness, quality and facies along the western bounding fault of the Johan Sverdrup Field. The main bounding fault separates the basin to the east where Intra-Draupne Formation sandstone is present in all the wells, and the main Utsira High to west where Intra-Draupne Formation sandstone has not been encountered in the wells nearby.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>A pilot hole 16/2-U-17 was drilled 25m South-East of the main wellbore to investigate for shallow gas. No gas or shallow water flow were encountered. </span></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-17 S was spudded with the semi-submersible installation Ocean Vanguard on 24 March 2013 and drilled to TD at 2052 m (2039 m TVD) in the Triassic Skagerrak Formation. No significant problem was encountered in the operations. The well was drilled with seawater down to 905 m and with Performadril water based mud from 905 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The top of the main reservoir, Draupne Formation, was picked at 1873 m (1859.7 m TVD), 18.3m deeper than prognosed. The reservoir showed excellent reservoir properties and held an 82 m thick oil column down to the oil-water contact in the Statfjord Group at 1957 m (1922 m TVD MSL). A formation gas peak with C2+ hydrocarbons was recorded in the top of the Shetalnad Group, and at 1873 m good oil shows were recorded. Gas generally dropped off down in the Shetland Group. Below the OWC oil shows were described down to 1965 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 164 m core were recovered from seven coring runs covering the Jurassic interval and 21 m TVD into the Triassic Skagerrak Formation. Core recoveries varied between 98.8 and 105.3%. The high recoveries are due to core expansion. MDT fluid samples were taken at 1884.8 m (oil), 1934.5 m (oil), and 1959.7 m (water). </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 20 May 2013 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two Drill Stem Tests were performed.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 1929 to 1937 m in the Statfjord Formation reservoir section. It produced 422 Sm3 oil and 14200 Sm3 gas /day through a 40/64" choke. The DST temperature was 77.7 °C.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 1875.5 to 1914.5 m, nearly the whole Intra Draupne Formation sandstone section of the reservoir. It produced 910 Sm3 oil and 24300 Sm3 gas /day through a 48/64" choke. The DST temperature was 75.5 °C.</span></p> |
7085
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/2-18 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-18 S was drilled on the Cliffhanger North prospect west of the Johan Sverdrup Field on the Utsira High in the North Sea. The main objective was to prove hydrocarbons in the Late Jurassic intra-Draupne Formation sandstones and to verify the reservoir quality, fluid property, lateral extension and possible communication with the Johan Sverdrup discovery. The secondary objective of the well was to explore the hydrocarbon potential and reservoir properties in fractured and weathered granitic Basement.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-18 S was spudded with the semi-submersible installation Ocean Vanguard on 5 July 2013 and drilled to TD at 1970 m in fractured granitic basement rock. The well was drilled with a slightly deviated well path with the purpose of avoiding a prognosed shallow gas anomaly. A 9 7/8" pilot hole was drilled from 201 m to 455 m to check for shallow gas. No shallow gas was seen. No significant problem was encountered in the operations. The well was drilled with seawater and hi-vis sweeps down to 855 m and with KCl/Polymer/Glycol mud from 855 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Intra-Draupne Formation sandstone reservoir was not present at the well location; hence the primary objective of the well was not met. The secondary objective, however, was met by proving oil in weathered and fractured granitic Basement, which was encountered at 1864 m. An oil column of ca 15 m was estimated but no oil/water contact was established. Pressure data showed the discovery to be 2.6 bar higher and with a different oil gradient than in the Johan Sverdrup Field, and thus not in communication. However pressure and sampling data from the 16/2-4 Ragnarrok basement discovery has shown that the 16/2-18 S basement discovery is in communication, making 16/2-18 S well an appraisal of the Ragnarrok discovery. From the combined pressure data for these two wells the gas oil contact for the Ragnarrok discovery is found to be at ca 1862 m (1840 m MSL).</span></p> <p class=MsoBodyText><span lang=EN-GB>Shows were observed in the upper part of the Shetland Group and in the Basement. The uppermost Shetland Group (Ekofisk Formation) also had high gas readings.</span></p> <p class=MsoBodyText><span lang=EN-GB>An extensive sample and data acquisition programme was conducted in the upper part of the Basement. Four cores were drilled, but the first core was lost in the hole. Cores 2 - 4 recovered 19.9 m between 1855.5 m in the Åsgard Formation and 1876 m in the Basement. Three dual packer mini-DST’s were performed showing limited production properties. Fluid samples were taken at 1866.2 m (gas, oil, and mud) and 1875.1 m (oil).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 8 August 2013 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7220
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/2-19
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>The 16/2-19 Geitungen well was drilled on the northern part of the Johan Sverdrup Field on the Utsira High in the North Sea. The primary objectives were to investigate the reservoir distribution, facies and quality in a more distal and down flank position and different seismic response than the Geitungen discovery well 16/2-12. The well was targeting possible Intra Draupne Formation sandstones to find the oil-water contact and to take water samples to aid the design of Johan Sverdrup production facilities.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-19 was spudded with the semi-submersible installation Ocean Vanguard on 1 March 2014 and drilled to TD at 2023 m in the granitic basement rock. The well was drilled and cored without any major problems. The well was drilled with spud mud down to 902 m and with XP-07 oil based mud from 902 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Intra Draupne sandstone was not encountered in the well. Top Statfjord Group sandstone came in at 1945 m and the upper 5 m was oil filled. Shows were observed from the well site description in the Draupne Formation above the Statfjord reservoir and in the Skagerrak Formation below the OWC, but no shows are observed in the Basement. Gas readings were generally low through the entire well. </span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut with a total of 68.38 m recovery, starting from lower part of Cromer Knoll Group, through Viking Group, Statfjord Group, Hegre Group and down into the Basement. MDT samples were taken at 1945.13 m (oil with ca 4% OBM contamination), 1949.03 m (oil with ca 18% OBM contamination), and 1951.21 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>Since no Intra Draupne Formation sandstone was encountered in the well, it was decided to drill a sidetrack, 16/2-19 A.</span></p> <p class=MsoBodyText><span lang=EN-GB>Well bore 16/2-19 was plugged back and prepared for sidetracking on 3 March 2016. It is classified as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7403
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/2-19 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/2-19 A is a geological sidetrack to the 16/2-19 Geitungen well. The well is drilled on the northern part of the Johan Sverdrup Field on the Utsira High in the North Sea. The sidetrack 16/2-19 A targeted Intra Draupne Formation Sandstones in an assumed depocentre in a more distal position than the 16/2-12 but in a more proximal position than 16/2-19. The objectives were to investigate the reservoir distribution, facies and quality of the Draupne sandstone, and to find the oil-water contact.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-19 A was kicked off through 13 3/8" casing at 625.5 m in the primary well on 3 April 2014. It was drilled with the semi-submersible installation Ocean Vanguard to TD at 2347 m (1979 m TVD) in granitic basement rock. No significant problem was encountered in the operations. The well was drilled with XP-07 oil based mud from kick-off to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Draupne Formation claystone was penetrated at 2265 m, while Intra Draupne Formation Sandstone came in at 2271 m. A 13 m gross oil column was encountered in Intra Draupne Formation sandstone and Triassic Skagerrak Formation sandstone, the upper 3 m of which were in sandstone with very good reservoir quality. An oil-down-to situation was encountered. Oil shows described in in the reservoir section from 2270 m to 2289 m; otherwise, no shows are reported from the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut across the reservoir section. Core 1 was cut from 2256.5 m in the Åsgard Formation, through Draupne formation claystone and Intra Draupne Formation Sandstone to 2283.2 m in the uppermost Hegre Group with 100% recovery. Core 2 was cut from 2283.2 m to 2305.1 m in the Skagerrak Formation with 99% recovery. MDT fluid samples were taken at 2281.04 m (oil with trace OBM contamination) and 2291.74 m (oil with ca 30% OBM contamination).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 3 May 2014 as an oil appraisal well. A CATS system was installed for long term monitoring of pressure and temperature.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7456
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/2-2
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<p><b>General</b></p>
<p>Well 16/2-2 is located on the Skuld prospect located just to the south of the proven Balder/Grane oil province. There are four main prospective sandstones in the area: the Ty, the Lower Heimdal, the Middle/Upper Heimdal, and the Hermod Formations. All four sandstones were believed to be present in the prospect. The objectives of the well were to prove commercial volumes of hydrocarbons and to test the stratigraphic trap and the structural closure.</p> <p><b>Operations and results</b></p> <p>Exploration well 16/2-2 was spudded with the semi-submersible installation "Byford Dolphin" and drilled to TD at 1880 m in the Early Cretaceous Rødby Formation. The well was drilled with seawater and bentonite hi-vis pills down to 1312 m and with oil based "NOVATEC" mud from 1312 m to TD.</p> <p>No shallow gas was encountered. Only minor amounts of gas were recorded in the well with maximum 0.17% formation gas recorded at 1697 m in Tertiary, predominantly claystone lithology. Otherwise there were no indications of hydrocarbons throughout the well. No reservoir rock was developed in the Paleocene section. The Paleocene sequence is composed of claystones with only occasional traces of coarser clastics (siltstone and rarely sandstone). No cores were cut in the well and no fluid samples were taken.</p> <p>The well was permanently plugged and abandoned as a dry well on 4 October 2000.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
4408
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7/6/2016 12:00:00 AM
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04.11.2024
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16/2-20 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-20 A is a geologic sidetrack to well 16/2-20 S. Both well tracks were drilled to test the Torvastad prospect north of the Johan Sverdrup Field on the Utsira High in the North Sea. The primary objective was to investigate the Jurassic - Early Cretaceous sequence with respect to reservoir facies, hydrocarbons, free water level, pressure communication with the Johan Sverdrup Field, and seismic interpretations and depth conversion. Well 16/2-20 A was drilled 800 meters towards west to investigate the presence of oil filled Jurassic reservoir at shallower depth than the S well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-20 A was drilled with the semi-submersible installation Island Innovator. Operations started on 21 November 2013 but due to problems with the lower marine riser package (LMRP) and bad weather, actual kick-off was not performed until 12 December 2013. The kick-off point was at 732 m in the primary S well. Equipment failure, mainly related to the LMRP, caused 551 hours no production time for this well, while bad weather caused 725 hours WOW. Only 41% of total rig time was counted as productive. The well was drilled to TD at 2215 m in Granitic basement rock using Aquadril mud from kick-off to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-20 A found a late Jurassic Draupne </span><span lang=EN-US>spiculitic sandstone/siltstone</span><span lang=EN-US> </span><span lang=EN-GB>sequence of similar extent and facies as found in well 16/2-20 S, despite indications of a thinning of this sequence interpreted from seismic data. The Statfjord Group sequence is not present and the spiculite rests unconformable on a 57 m Triassic Hegre and Skagerrak Group sequence. Good shows were observed in the sandstones of the Draupne and Skagerrak formations.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the interval 2090 to 2139 m, recovering a total of 45.7 m (93.3% total recovery). The core to log depth shifts are +0.31 m, -2.28 m, and -2.67 m for cores 1, 2, and 3, respectively. RCX fluid samples were taken at 2125.19 m and 2129.52 m. Water with a fraction of oil was obtained from both depths.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 17 February as a dry well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7316
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/2-20 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-20 S was drilled on the Torvastad prospect north of the Johan Sverdrup Field on the Utsira High in the North Sea. The primary objective was to investigate the Jurassic - Early Cretaceous sequence with respect to reservoir facies, hydrocarbons, free water level, pressure communication with the Johan Sverdrup Field, and seismic interpretations and depth conversion.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-20 S was spudded with the semi-submersible installation Island Innovator on 30 September 2013 and drilled to TD at 2150 m (2098 m TVD) m, 36 m into granitic basement. A 9 7/8" pilot hole was drilled from </span></p> <p class=MsoBodyText><span lang=EN-GB>seabed to 720 m RKB to check for shallow gas. No shallow gas was observed. The well was drilled deviated due to a ridge on the seafloor that could cause instability for the wellhead and BOP. The well path is vertical down to ca 730 m, deviated with a sail angel of ca 23 ° from 730 to 1900 m, and vertical from 1900 m to TD. The well was drilled with seawater and hi-vis sweeps down to 720 m and with Aquadril mud from 720 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>An unusual, 21 m thick age-equivalent to the Draupne Formation (Volgian to Ryazanian age) was encountered at 2006.3 m (1954.6 m TVD). It consists of a condensed section at base, a thin shale section, and a 16.6 m thick spiculitic sandstone/siltstone on top. The porosity of these sediments is relatively high, but permeability is very low. Underlying this sequence, at 2027 m (1975.5 m TVD) the well penetrated a 10 m sequence of sandstones belonging to the Statfjord Group, a 77 m sequence of sandstones, limestone and mudstones belonging to the Skagerrak Formation and a 20 m thick Smith Bank Formation resting on the granitic basement. Good oil shows were described in the Statfjord Group. </span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 52.5 m core was recovered in four cores from the interval 2001 to 2055 m. The core to log depth shifts are -2.34 m, -2.12 m, -1.3 m, and -1.3 m for cores 1 to 4, respectively. RCX fluid samples were taken at 2012.5 m (water), 2026.7 m (one sample with water and one with water and a fraction of oil), and at 2031.3 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 21 November 2013 as a dry well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7181
|
4/11/2017 12:00:00 AM
|
04.11.2024
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16/2-21
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-21 was drilled to appraise the central part of the Johan Sverdrup discovery on the Utsira high in the North Seas. The hydrocarbon column height was predicted to be 14 m in the well location. The main objectives of the well were to investigate the reservoir sequence, facies and thickness in the central part of the discovery and to find the free water level (FWL).</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-21 was spudded with the semi-submersible installation Bredford Dolphin on 5 May 2013 and drilled to TD at 2070 m in the Late Triassic Skagerrak Formation. A 9 7/8" pilot hole was drilled from the seabed to 706 m due to slight shallow gas warnings. No shallow gas was seen. Drilling was efficient with little NPT. The NPT was caused mostly by mud losses in the Skagerrak Formation reservoir section. The well was drilled with seawater and hi-vis pills down to 706 m and with Performadril water based mud from 76 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The top of the reservoir came in as prognosed at 1935 m, overlain by a 4 m thick Draupne Formation shale. An oil column of 12 meter entirely within the late Jurassic Intra-Draupne sandstones was proven. The well proved excellent development of these sandstones in the central part of the Johan Sverdrup discovery. The total thickness of the Intra-Draupne Formation sandstone was 12 m. No sediments of middle Jurassic age were found, but 17 m of water filled early Jurassic Eriksson Formation was encountered below the Draupne Formation. The well results show an oil water contact at 1947 m, but with residual oil saturations of 20-30% down to ca 1955 m. </span></p> <p class=MsoBodyText><span lang=EN-GB>Above the reservoir, increasing amounts and wetness of mud gas down through the lowermost part of the Cromer Knoll Group suggested the possibility of leakage from the reservoir. However, no oil shows were observed in the Cromer Knoll Group; the only oil shows in the well were recorded on the cores from 1935 to 1945 m, and 1953 to 1955 m, within the Intra-Draupne and Eriksson Formation sandstones.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the interval 1907 m in the Cromer Knoll Group to 1976.6 m in the Skagerrak Formation with close to 100% total recovery. MDT fluid samples were taken at 1937.02 m (oil), 1946.62 m (oil), 1947.11 m (oil), 1947.71 m (water), 1953.79 m (water), and 1975.55 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7 June 2013 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7169
|
4/11/2017 12:00:00 AM
|
04.11.2024
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16/2-22 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/2-22 S was drilled to appraise the Northern outline of the Johan Sverdrup Field on the Utsira High in the North Sea. The Johan Sverdrup reservoir range from Late Triassic to Early Cretaceous in age, with Intra Draupne Formation sandstone as the main unit. The primary objective was to test The Intra-Draupne Formation sandstone and investigate pressure communication.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-22 S was spudded with the semi-submersible installation Deepsea Atlantic on 16 January 2017 and drilled to TD at 1993 m (1982 m TVD) m in granitic basement. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 1214 m and with Carbosea oil-based mud from 1214 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Intra Draupne Formation reservoir was penetrated from 1934.5 to 1950 m. The Formation consists of muddy spiculites and is directly overlying basement. It is oil bearing from top to base. No shows were observed in the well outside of the oil-bearing reservoir. Pressure data over the reservoir proved an oil gradient that match the one in surrounding wells. The reservoir pressure is about 0.4 bar lower pressure compared to previously drilled well 16/2-12. This difference is in line with the rate of pressure depletion in the area.</span></p> <p class=MsoBodyText><span lang=EN-GB>One core was cut from 1937 to 1953 m in the Intra Draupne Formation sandstone and Basement with 100% recovery. Two RCX fluid samples were taken. Oil was sampled at 1943.4 m (1933.4 m TVD) and water at 1950 m (1939.9 m TVD).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 28 January 2017 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
8083
|
11/12/2019 12:00:00 AM
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04.11.2024
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16/2-3
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<p><b>General</b></p> <p>Well 16/2-3 was drilled on the Ragnarrock prospect in the North Sea.The Ragnarrock prospect is situated on the top of the Utsira High, southeast of the Verdandi discovery in PL 167 and east of the Gudrun field in PL 025. The main objective was to prove presence of hydrocarbons in the Tor Formation of Maastrichtian age and to test its permeability and its productivity. The secondary target was to check the presence of hydrocarbon in the Basement and to test its permeability and its productivity.</p> <p><b>Operations and results</b></p> <p>Well 16/2-3 was spudded with the jack-up installation West Epsilon on 1 August 2007 and drilled to TD at 1905 m, 9 m into basement rock. No significant problem was encountered during drilling, but an incident with a falling object during P&A caused several days stand still for investigation before the well could be abandoned. No shallow gas was observed by the ROV at the well head or by the MWD while drilling the 36" hole and the 12 1/4" pilot hole. The well was drilled with spud mud down to 640 m and with KCl/polymer/glycol mud from 640 m to TD.</p> <p>The well encountered the Tor reservoir section at 1716 m, 6 m shallower than prognosed. A HC discovery was proven in the Tor Formation but the results from the MDT suggested the formation to be tight and tightening with depth. The basement was penetrated at 1894 m, 22 m deeper than prognosed. Only occasional dead oil stain was found in the upper 7 m of the basement so no further formation evaluation was performed here. No oil shows were recorded above top Tor Formation.</p> <p>Three cores were cut from 1715.7 to 1852.5 m. The first core covered the transition zone between the Lista and Tor Formations. Cores 2 and 3 were cut in the Tor and Hod Formations. Two mini-DST runs were performed for pressure points and fluid sampling in the Tor Formation.Sampling was performed at depths 1716.8 m (gas), 1720.5 m (oil) and 1742.6 m (oil), 1769.9 m, and 1781.1. Only the samples at 1720.5 m were found to be representative of reservoir fluid.PVT analyses of these samples gave a single stage GOR around 140 Sm3/Sm3 and an oil density of 0.861 /cm3. Sample bottles from depth 1716.8 m, 1742.6 m, 1769.9 m and 1781.1 contained mainly water</p> <p>The well was permanently abandoned on 28 September 2007 as an oil discovery.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
5551
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/2-4
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<p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well <a name="OLE_LINK2"></a><a name="OLE_LINK1">16/2-4 </a>is located on the Utsira High in the North Sea. The objective of drilling 16/2-4 was to delineate the Tor Formation oil discovery made in 16/2-3 and to test the permeability and productivity of the chalk. The secondary objective was to check the presence of hydrocarbon in the basement and to test the permeability and productivity of the basement rock.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-4 was spudded with the jack-up installation West Epsilon on 8 October 2007 and drilled to TD at 2000 m, 121 m into basement rock. No major problem was encountered in the operations. The well was drilled with spud mud down to 640 m and with KCl/polymer/glycol mud from 640 m to TD. No shallow gas was observed by the ROV at the wellhead or by the MWD while drilling the 36" hole or the 17 1/2" hole. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Tor Formation reservoir section was encountered with hydrocarbons at 1709.5 m, 12.5 m shallower than prognosed. A clear hydrocarbon contact was not seen. The best indication of an OWC was seen on cores as a disappearance of shows below 1775. The well showed that the size of the 16/2-3 discovery is likely to be in the range 5 - 10 million Sm3 recoverable oil. A series of small-scale formation tests were carried out, showing promising flow properties. Smaller amounts of oil and gas were found also in basement, but small-scale tests in the basement showed limited flow properties. Apart from the oil and gas bearing reservoirs, no significant shows were seen in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>Five cores were cut. The first core was cut in the Lista Formation, the second core covered the transition zones between the Lista, Våle and Ekofisk Formation, the third core was in the Tor Formation, the fourth core was in the Tor and Hod Formation, and the fifth core was in Basement. Four mini-DST runs were performed in the Tor Formation and in the Basement for pressure points and fluid sampling. Oil and water were sampled from the Tor Formation. Gas, oil and water were sampled from the Basement. The following depths were sampled (hydrocarbon type is verified only from chromatographic analyses of the oil phase): 1939 m (water), 1930 m, 1904 m (oil), 1898,1 m (oil), 1896.1 m, 1886.1 m (gas/condensate), 1727.5 m (oil), and 1710 m (water). Due to high draw-down during pumping with the wire line tools, most of the hydrocarbon samples are flashed and not representative for PVT analysis. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 15 December as a gas/minor oil discovery and an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
5625
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/2-5
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-5 was drilled on the Ragnarock III prospect on the Utsira High in the North Sea. The primary objective of the well was to prove the presence of hydrocarbons in the pre-BCU interval and establish the composition and age of the sediments. The secondary target was the chalk in the Ekofisk and Tor Formations of Late Cretaceous age. The presence of hydrocarbons in these formations at the well location was possible, but not expected.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-5 was spudded with the jack-up installation West Epsilon on 22 February 2009 and drilled to TD at 2373 m in pre-Devonian Basement. After drilling the 36" hole to 288 m a 9 7/8" pilot hole was drilled to 513 m to check for shallow gas. No shallow gas or shallow water flow was observed. The well was drilled with spud mud down to 519 m, with KCl/polymer/glycol mud from 519 m to 1747 m, and with KCl/polymer/glycol low-sulphate mud from 1747 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated rocks of Quaternary, Tertiary and Cretaceous age, it then penetrated Graben Fill before TD in Basement. Base Cretaceous/top Graben Fill was encountered at 1884 m. A total thickness of 458 m of Graben Fill consisting of coarse, clastic sediments was penetrated and 3 cores were cut from 1894 to 1994 m. Due to lack of fossils no reliable dating was obtained for the Graben Fill. The Graben Fill was gas/condensate filled from top of the reservoir and down to 1902 m. High quality gas condensate samples were acquired by use of wire line sampling tools. A water sample was acquired at 1935 m and oil was scanned at 1916 m MD. An interval with oil was confirmed also by sampling at 1921.5 m, but due to poor pressure measurements in this interval the OWC was only tentatively set at 1917 m based on logs and geochemistry. No oil shows were observed above reservoir level. In the reservoir oil shows were seen down to 1981 m and no shows were seen below this level.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13 May 2009 as a gas discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>A full scale DST was performed in the interval 1885 - 1902 m. The perforated interval was placed in the gas zone with the lowermost interval close to the interpreted GOC. The gas rate for the main flow was 110 000 Sm3/d with a 40/64" choke size. A maximum gas rate of 120 000 Sm3/day was achieved on a 60/64" choke size. The total test production of associated condensate with the gas was about 6 Sm3 mixed with some oil, no water was produced during testing. At top reservoir the formation pressure was 191.8 bar at 1885 m. The bottom hole temperature recorded in the test was 71 deg C.</span></p> |
6042
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/2-6
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-6 was drilled on the Avaldsnes prospect on the Utsira High in the North Sea. The primary objective was to prove oil in Jurassic and pre-Jurassic sandstone in the Karmsund Graben. The secondary objective was to prove oil in the Paleocene Ty Formation Sandstone. Planned TD was 50 m into solid basement rock.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-6 was spudded with the semi-submersible installation Transocean Winner on 20 July 2010 and drilled to TD at 2131 m. The well encountered severe loss problems in the Zechstein Group and a technical sidetrack was drilled (well 16/2-6 T2) through the reservoir. The sidetrack was kicked off from 1830 m and drilled to 2131 m where severe losses again were experienced and the well was completed without reaching its planned TD. All wire line logging and a DST were performed in the sidetrack. The well was drilled with seawater and hi-vis pills down to 748 m and with Glydril WBM (3- 5% glycol) from 748 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>No Ty Formation sand was seen in the well. Top Viking Group, Draupne Formation was encountered at 1925.5 m (1927.5 m in sidetrack) and top of the Draupne reservoir sand came in at 1931 m (1931 m in sidetrack). The top of the reservoir consists of an 8 m thick, coarse to very coarse, sand. Underlying this is finer grained sand laminated with shale. A reworked calcareous formation lies on top of the Triassic. Pressure points, MDT sampling and DST results confirmed the presence of oil in the reservoir with an oil-water contact at 1948.6 m. Residual oil was found down to 1966 m. In addition to the main reservoir section, oil was sampled in calcareous slumps with vuggy porosity between the Jurassic sandstone and the Triassic. Apart from this there were no shows of hydrocarbons reported elsewhere in the well bores.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three conventional cores were cut from 5 m into the Draupne sandstone, through the Middle Jurassic Vestland Group down to 1961.5 m in the Late Triassic Skagerrak Formation. MDT fluid samples were taken at 1933.2 m (oil), 1936.0 m (oil), 1945.2 m (oil), 1948 m (oil and water), 1953 m (water), and at 1962.5 m (water and oil).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 20 September 2010 on as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>A drill stem test was performed from the interval 1931.8 m to 1938.1 m. The test flowed 786 Sm3 oil and 18700 Sm3 through a 52/64" choke. At single stage separation The GOR was 39.6 Sm3/Sm3, the oil density was 0.891 g/cm3, and the gas gravity was 1.012 (air = 1). The maximum DST temperature was 82.7 deg C. The interpretation of the DST indicated a continuous reservoir without barriers in a radius of 2-3 km with extremely good flow characteristics.</span></p> |
6374
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4/11/2017 12:00:00 AM
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04.11.2024
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16/2-7
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-7 was drilled about 5.5 kilometres southeast of the discovery well for the oil discovery 16/2-6 (Avaldsnes) on the Utsira High in the North Sea. The 16/2-6 Avaldsnes discovery was proven in September 2010 in Middle-Late Jurassic reservoir rocks. The primary exploration target for 16/2-7 was to delineate the presence of hydrocarbons in Middle-Late Jurassic sandstones above the 1922 m MSL oil-water contact established in well 16/2-6. The well?s secondary objective was to determine the reservoir properties of the Rotliegendes Formation.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-7 was spudded with the semi-submersible installation Bredford Dolphin on 19 July 2011and drilled to TD at 2500 m in Early Permian Rotliegendes Group rock. A 9 7/8" pilot hole was drilled from the seabed to 710 m to check for shallow gas. Some sand was found at the pre-warned level, but without shallow gas. No significant technical problem was encountered in the operations. The well was drilled with seawater and hi-vis pills down to 710 m and with Performadril WBM from 710 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>BCU/top Draupne Formation was encountered at 1936 m</span><span lang=EN-GB> </span><span lang=EN-GB>approximately 15 m deeper than prognosis. This was due to a small fault that was originally not accounted for in the seismic interpretation. The well proved oil in Intra Draupne Formation sandstone from top at 1939 m and down to the OWC at 1947.5 m (1922.5 m TVD MSL), confirming the OWC found in 16/2-6. Reservoir quality was good to very good and the reservoir continued through base of the Intra Draupne Formation sandstone at 1964 m and into the underlying Sleipner with base at 1984 m. Total net reservoir was 35 m. The Permian Zechstein and Rotliegendes Groups were encountered within the depth prognosis uncertainty. Reservoir properties were not found in these sequences. The first oil show was observed in the Draupne Formation at 1937 m. Good oil shows were recorded down through the reservoir to 1948 m. Below 1948 m the oil shows became progressively weaker with no further shows observed below 1957 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Five conventional cores were cut in the well. The three first were cut from 1924 m to 1973.5 m across BCU, Draupne Formation shales and sandstone and into the underlying Sleipner Formation. Core no 4 was cut from 2198 m to 2217 m in the Zechstein Group, and core no 5 was cut from 2283 m to 2310 m in the Rotliegendes Group. MDT wire line fluid samples were taken in the Intra Draupne Formation sandstone at 1941.62 m (oil), 1945.54 m (oil), 1963.51 m (water, and 1963.52 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1 September 2011 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6561
|
4/11/2017 12:00:00 AM
|
04.11.2024
|
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16/2-7 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-7 A is a geologic sidetrack to well 16/2-7 drilled about 5.5 kilometres southeast of the discovery well for the oil discovery 16/2-6 (Avaldsnes) on the Utsira High in the North Sea. Well 16/2-7 confirmed the Avaldsnes Discovery OWC at 1922 m TVD MSL</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-7 A was drilled with the semi-submersible installation on Bredford Dolphin. It was kicked off from below the 20" shoe at 708 m in primary wellbore 16/2-7 on 2 September 2011 and drilled to a total depth of 2100 m (2010 m TVD) in the Triassic Skagerrak Formation. The sidetrack well was drilled conventionally with 12 1/4" and 8 1/2" sections using Performadril water based mud all through. No significant problem was encountered in the operations.</span></p> <p class=MsoBodyText><span lang=EN-GB>The geological sidetrack penetrated the BCU and top Intra Draupne Formation sandstone reservoir according to prognosis at 2014 m (1931 m TVD). The Draupne sandstone rested unconformable on a 14 m TVD thick Sleipner Formation sandstone with top at 2024 m (1940 m TVD). The Draupne sandstone thickness variation going from 25 m TVD in 16/2-7 to 9 m TVD in 16/2-7 A is attributed to Late Jurassic faulting. As in 16/2-7 Pressure points and MDT sampling results confirmed the presence of oil in the reservoir with a free water level at approximately 2032 m (1947.5 m TVD). </span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut from 2012 to 2054 m across the Draupne and Hugin formations. MDT wire line fluid samples were taken at 2015.8 m (oil), 2031.29 m (oil), 2035.19 m (water), and 2036.95 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29 September 2011 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
6711
|
4/11/2017 12:00:00 AM
|
04.11.2024
|
|
16/2-8
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Statoil well 16/2-8 (Aldous Major South) was drilled about 4.2 kilometres west of the Lundin oil discovery well 16/2-6 (Avaldsnes) on the Utsira High in the North Sea. The 16/2-6 Avaldsnes discovery was proven in September 2010 in Middle-Late Jurassic reservoir rocks. The main objective of well 16/2-8 was to investigate the hydrocarbon potential in Late Jurassic sandstones in the Draupne Formation and the Middle Jurassic Hugin/Sleipner Formations. The secondary and third objectives were to explore the hydrocarbon potential in the Triassic Skagerrak Formation and in Chalks of the Late Cretaceous Shetland Group, respectively.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-8 was spudded with the semi-submersible installation Transocean Leader on 17 July 2011 and drilled to TD at 2140 m in the Triassic Skagerrak Formation. Neither shallow gas nor shallow water flow was observed and the well was drilled without significant problems. The well was drilled with seawater and bentonite sweeps down to 213 m, with seawater and bentonite/PAC RE sweeps from 213 m to 945 m, with Performadril WBM spec 6a from 945 m to 1573 m, and with Performadril Low sulphate WBM from 1573 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The top of the main reservoir, in the Draupne Formation, was picked at 1877 m. The reservoir (Draupne and Hugin Formations) showed excellent reservoir properties and contained oil. An oil column of 67.5 m was present down to 1944.5 m (1921 m TVD MSL), close to the contact level seen in the 16/2-6 Avaldsnes well. Pressure data showed that the 16/2-8 Aldous Major South and the 16/2-6 Avaldsnes discoveries are in the same pressure regime and thus in communication. The secondary objective, Skagerrak Formation was water wet. The third objective, the Shetland Group chalk had moderate to poor oil shows in the very top, from 1573 to 1622 m, with a pronounced wet gas peak from 1573 to 1601 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Six cores were cut in the well. Cores 1 to 4 were cut from 1880.5 m to 1953.21 m in the Rødby Formation, across Draupne and Hugin formations and into the Sleipner Formation. Cores no 5 and 6 were cut from 1995 m to 2048.8 m in the Statfjord and Skagerrak formations. MDT wire line fluid samples were taken at 1882.1 m (oil), 1931.2 m (oil), 1945.0 m (water), 1945.4 m (water), and at 1947.2 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-8 proved communication between the Aldous Major South discovery in PL265 and the Avaldsnes discovery in PL501 made by Well 16/2-6 in august 2010. The two discoveries will be developed together under the name Johan Sverdrup Field. Well 16/2-8 was permanently abandoned on 19 August 2011 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6562
|
4/11/2017 12:00:00 AM
|
04.11.2024
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16/2-9 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/2-9 S was drilled on the Aldous Major North prospect on the Utsira High in the North Sea. The prospect is separated from the Aldous Major South/Avaldsnes discovery by a North-East trending fault, but was considered as a possible extension of the Aldous Major South. The main objective of the well was to investigate the hydrocarbon potential, reservoir quality and lateral sand distribution in the Late Jurassic Viking Group. The secondary objective of well 16/2-9 S was to explore the hydrocarbon potential in the fractured granitic basement. The third objective of well 16/2-9 S was to investigate the hydrocarbon potential in the Cretaceous age Shetland Chalk Vindballen lead. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-9 S was spudded with the semi-submersible installation Transocean Leader on 21 August 2011and drilled to TD at 2082 m (2070.6 m TVD) into Basement rocks. Neither shallow gas nor shallow water flow was observed, and operations went forth without significant problems. The well was drilled with sea water and hi-vis bentonite pills down to 343 m, with KCl/Polymer/GEM Spec 3 mud from 343 m to 1066 m, with Performadril WBM spec 6a mud from 1066 m to 1725 m, and with Low sulphate Performadril WBM mud from 1725 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top expected main reservoir, the Draupne Formation, was picked at 1933.5 m. The intra-Draupne reservoir was unusual and consisted of spiculites. It contained oil. The reservoir proved to be considerably thinner and with much poorer reservoir quality than expected and the oil water contact could not be established exactly. However, based on the saturation profile and results from fluid sampling, the OWC was set at 1941.5 m (1930.1 m TVD / 1906.6 m TVD MSL) with the Free Water Level a few meters further down. The secondary and third objectives, the fractured granitic basement and the Shetland chalk respectively, were dry. There were no oil shows observed in the well apart from in the hydrocarbon bearing reservoir section.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were taken in the Skagerrak Formation and into the basement at core depths 1952 - 1975.5 m, 1975.5 - 1987 m and 1987.1 - 1991.5 m. The core shifts relative to the logs were 1, 2, and 3 m respectively, for the three cored intervals. MDT wire line fluid samples were taken at 1935.17 m (oil), 1938.2 m (oil), 1941.0 m (water/oil), and at 1941.7 m (oil/water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 24 September 2011. It is classified as an oil appraisal to the Aldous Major South discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6615
|
4/11/2017 12:00:00 AM
|
04.11.2024
|
|
16/2-U-18
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<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>General</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/2-U-18 was drilled on the Johan Sverdrup Field on the Utsira High in the North Sea. The well objective was to reduce the geological uncertainty in the <span class=SpellE>Espevær</span> North structure in order to place the planned injectors from the E-template in a robust location with regards to sand thickness and FWL.<o:p></o:p></span></p> <p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Operations and results</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>well 16/2-U-18 was spudded with the semi-submersible installation Deepsea Atlantic on 5 November 2016 and drilled to TD at 2143 m (2139 m TVD) m in the Triassic Skagerrak Formation. Operations proceeded without significant problems. The well was drilled with Seawater and hi-vis pills down to 951 m, with Aquadrill mud from 951 to 1748 m, and with Carbosea oil-based mud from 1748 m to TD. <o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The Draupne Formation was encountered at 1947 m (1943 m TVD) and constitutes <span class=GramE>of <span style='mso-spacerun:yes'> </span>muddy</span> spiculites. Intra-Draupne Formation sandstone was penetrated from 1954 m (1950 m TVD) to 1978 m (1974 m TVD). A thin Hugin Formation sandstone is between the Viking Group and the Statfjord Group and is in communication with the Viking Group. Shales in the top of the Eiriksson Formation constitutes a pressure barrier. Hence, the pressure gradient in the water in the Intra-Draupne and Hugin sandstones is 0.4 bar higher than in the homogeneous thick sand of the Eiriksson Formation below the shale. These sands have better reservoir properties than the Intra-Draupne Formation sandstone. The Eiriksson Formation sandstone is 1 bar depleted compared to well 16/2-10 reservoir sandstone. This is as expected based on the regional pressure depletion in the area. <o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Fluid contacts are not conclusive in the well. The deepest possible water up to depth is 1956.5 m where a clean formation water sample was taken. A free water level is weakly indicated by the logs in the homogeneous sand at 1954.6 m, but this cannot be confirmed by pressure data. A paleo-OWC can be interpreted down to 1967 m, but again this is uncertain due to partially missing core at this level. <o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Shows were present in sandstones in the interval 1988 to 2028 m in the Statfjord Group. They were typically described as poor to moderate to strong hydrocarbon odour, no to even stain, poor streaming cloudy cut fluorescence white stain, yellowish gold occasionally bluish gold even bright direct fluorescence, moderately streaming becoming strongly cloudy cut fluorescence, spotted residual fluorescent ring, brown patchy residual ring.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The interval from 1937 to 2077 m was cored in seven cores with variable recovery from 29.71% in core 3 to 100% in cores 5 and 7. Water samples were taken with the RCX tool at 1956.5 m, 2020.5 m and 2046.5 m.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The well was permanently abandoned on 28 November 2016.<o:p></o:p></span></p> <p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Testing</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'> <b><o:p></o:p></b></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No drill stem test was performed. <o:p></o:p></span></p> |
8052
|
11/14/2019 12:00:00 AM
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04.11.2024
|
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16/2-U-19
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<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>General</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/2-U-19 was drilled on the Johan Sverdrup Field on the Utsira High in the North Sea. The primary objective was to reduce the depth, thickness and quality uncertainty of the Draupne reservoir for future producers. The secondary objective of the well was to gather geological information regarding the Draupne sand distribution in the Geitungen area of the Johan Sverdrup Field.<o:p></o:p></span></p> <p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Operations and results</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/2-U-19 was spudded with the semi-submersible installation Deepsea Atlantic on 29 November 2016 and drilled to TD at 2017 m (2009.6 m TVD) in Basement rock. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 1180 m and with Carbosea oil-based mud from 1180 m to TD. <o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Intra-Draupne Formation sandstone was encountered at 1907 m (1900 m TVD) and was directly overlying basement rock at 1943 m (1936 m TVD). The Intra Draupne Formation sandstone had excellent reservoir properties and was oil filled all through. The pressure level in the reservoir is about 1 bar under the pressure observed in August 2012 in 16/2-12, in line with the general rate of pressure depletion in the area. There were no shows in the well outside of the oil-bearing reservoir.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Two cores were cut from1896 in the Åsgard Formation to 1945 in the granitic basement. Recovery was 99.6% in core 1 and 96.6% in core 2. The depth shift from logger’s depth is 1.1 m for core 1 and 1.15 m for core 2. <span style='mso-spacerun:yes'> </span>No fluid sample was taken.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The well was permanently abandoned on 12 December 2016.<o:p></o:p></span></p> <p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Testing</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'> <b><o:p></o:p></b></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No drill stem test was performed. <o:p></o:p></span></p> |
8063
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11/14/2019 12:00:00 AM
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04.11.2024
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16/3-1
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<p><b>General</b></p> <p>Well 16/3-1 was drilled on the Utsira High in the North Sea. The objectives were to investigate Paleocene sand pinch out, the weathered top of the Cretaceous chalk and Jurassic sandstone.</p> <p><b>Operations and results</b></p> <p>Wildcat well 16/3-1 was spudded with the semi-submersible installation Polyglomar Driller on 31 January 1976 and drilled to TD at 453 m in Pliocene sediments. The well was drilled with seawater and gel. </p> <p>Due to progressive tilting of the BOP stack the well was junked and abandoned 10 days later, on 10 February 1976.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
451
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7/6/2016 12:00:00 AM
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04.11.2024
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16/3-2
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<p><b>General</b></p> <p>Well 16/3-2 was drilled 40 m east of 16/3-1 on the Utsira High in the North Sea. The objectives were to investigate Paleocene sand pinch out, the weathered top of the Cretaceous chalk and Jurassic sandstone. The 16/3-2 well is a replacement for well 16/3-1, which was junked for technical reasons. </p> <p><b>Operations and results</b></p> <p>Wildcat well 16/3-1 was spudded with the semi-submersible installation Polyglomar Driller on 11 February 1976 and drilled to TD at 2019 m in granite basement. No significant problems were reported from the operations. The well was drilled with spud mud (gel and lime) and pre-hydrated bentonite down to 440 m, and with lignosulphonate mud from 440 m to TD. Around the well there was a 3 m deep and 15 m wide crater. Gas was observed leaking from 2 main openings and 1 minor. The gas flow from one of the major openings was about 400 l/hour. The gas was practically pure methane (99.98%), probably coming from layers near the surface.</p> <p>There were no sands in Paleocene and the Cretaceous chalk was tight. A 20 m thick immature Draupne shale was encountered at 1955 m. The well then encountered a 31 m thick late Jurassic sandstone from 1975 m to 2006 m. Below this sandstone was a 9 m thick layer of weathered basement overlying the solid granite. The well proved to be water wet all through, and no shows were recorded.</p> <p>Three cores were cut. Core 1 gave no recovery, while core recovered 3.5 m core from the interval 1998 m to 2000.6 m in the Late Jurassic sand. Core no 3 was cut from 2017.5 m to 2019 m in basement rock. No fluid sample was taken in the well.</p> <p>The well was permanently abandoned on 8 March 1976 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
334
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7/6/2016 12:00:00 AM
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04.11.2024
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16/3-3
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<p><b>General</b></p> <p>Well 16/3-3 is located on the eastern margin of the Utsira High in the North Sea. The primary objective of the well was to test the reservoir and hydrocarbon potential of the Paleocene Heimdal sands in the Havørn Prospect. The prospect sands pinches out to the east and south combined with a structural dip to the northwest. The source kitchen was expected to be the Late Jurassic Draupne Formation in the Southern Viking Graben. Top seal for the sands were prognosed to be the Late Paleocene- and the Eocene marine shales.</p> <p><b>Operations and results</b></p> <p>Wildcat well 16/3-3 was spudded with the semi-submersible installation Vildkat Explorer on 24 July 1989 and drilled to TD at 1566 m in the Late Cretaceous Tor Formation. No significant problems occurred during the operations. The well was drilled with seawater down to 445 m and with lignosulphonate/seawater and gel from 445 m to TD.</p> <p>Late Cretaceous rocks were encountered at 1488 m, underlying 1341 meters of Cenozoic claystones. The Late Cretaceous sediments (+ 78 m) consisted of white-creamy chalk. The Heimdal Formation sands were absent. No reservoir intervals were penetrated. No shows were recorded. </p> <p>No cores were cut and no fluid samples taken in this well.</p> <p>The well was permanently abandoned on 6 August 1989 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
1415
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7/6/2016 12:00:00 AM
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04.11.2024
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16/3-4
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/3-4 was drilled to prove the extension of the Avaldsnes Discovery to the north-east of the structural crest of the Avaldsnes structure. In this area, a continuation of the Upper Jurassic, Intra-Draupne Formation sandstone found in the discovery well 16/2-6 was expected to rest on granitic basement.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/3-4 was spudded with the semi-submersible installation Bredford Dolphin on 16 May 2011 and drilled to TD at 2020 m in granitic basement. A 9 7/8" pilot hole was drilled down to planned setting depth for 20" casing at 760. No shallow gas or boulders were seen. No significant problem was encountered during drilling of the pilot or the main well. The well was drilled with seawater and hi-vis sweeps down to 760 m and with Performadril mud from 760 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>BCU, top Draupne Formation was encountered at 1914 m, and a 13.8 m thick Intra-Draupne Formation sandstone, Tithonian age, was penetrated at 1926 m. The Intra-Draupne sandstone was oil-filled down to weathered basement at 1940 m. No oil-water contact was established, however, pressure communication between 16/3-4 and the 16/2-6 T2 Avaldsnes discovery well was proved. There were no shows above or below the Intra Draupne Formation sandstone reservoir.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut from 1913 to 1961 m, covering the Draupne Formation and 21 m of the underlying Basement. Good recovery was obtained in the first and last core (100 and 94% recovery respectively), while the recovery in core number 2 was 43%. Extensive wire line logging was performed including pressures (XPT/MDT) and fluid sampling. MDT fluid samples were taken at 1929.0 m (oil), 1939.6 m (oil), and 1943 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>After completing the data acquisition program and testing, the well was plugged back to the 20" casing shoe and sidetracked as well 16/3-4 A. The 16/3-4 well bore was permanently abandoned on 28 June as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>The Draupne Formation sandstone was production tested (DST) from the interval 1923.5 to 1936.8 m. The test produced in the main flow 18200 Sm3 gas and 885 Sm3 oil /day through a 52/64" choke. The GOR was 20 Sm3/Sm3 at separator conditions of 46 deg C and 13.6 bar. The oil density and gas gravity at ambient conditions on-rig were 0.889 g/cm3 and 0.806 (air = 1), respectively. The maximum temperature measured at 1894.8 m was 83.5 m.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6553
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/3-4 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/3-4 A is a sidetrack to well 16/3-4, which was drilled to prove the extension of the Avaldsnes Discovery to the north-east of the structural crest of the Avaldsnes structure. Well 16/3-4 proved oil in a 14 m thick Intra-Draupne Formation sandstone overlying weathered basement rock. The oil was proven to be in pressure communication with the 16/2-6 Avaldsnes discovery well. The 16/3-4 A sidetrack was drilled up-flanks (south-south-west) of the main well bore. The objective was to further appraise the Avaldsnes oil discovery and to determine the extent, thickness, and quality of the reservoir in this part of the structure. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/3-4 A was kicked off from 790 m in the primary well on 28 June 201. I was drilled with the semi-submersible installation Bredford Dolphin to TD at 2128 m (1959 m TVD) in granitic basement. No significant problem was encountered in the operations. The well was drilled with Performadril mud from kick-off to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The geological sidetrack 16/3-4 A encountered top Draupne Formation shales at 2065.5 m (1906.3 m TVD). At 2076.5 m (1915.6 m TVD) a 5 m vertical thickness of Intra-Draupne Formation sandstone was penetrated. The Draupne sandstone was oil bearing down to fractured basement at 2081.6 m (1919.8 m). Slightly different fluid gradients were recorded compared to the main wellbore, however, PVT analysis of the samples showed identical oil to be present in both wellbores. No oil water contact was established. The first oil shows in the sidetrack were observed in the marls of the Åsgard Formation in a sidewall core at 2052.8 m. More extensive oil shows were seen in the underlying Draupne sandstones. The oil shows became weaker in the fractured basement that was recovered in the core. Oil shows were seen in cuttings and sidewall cores below the core down to 2115.5 m; the last observed oil shows. </span></p> <p class=MsoBodyText><span lang=EN-GB>One core was cut from 2067 m to 2082.5 m in the Draupne Formation shales and reservoir sandstone, and into the basement. MDT oil samples were taken at 2079.2 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 18 July 2011 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6629
|
4/11/2017 12:00:00 AM
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04.11.2024
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|
16/3-5
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<html>
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/3-5 is an appraisal well on the southeaster part of the Sverdrup Field on the Utsira High in the North Sea. The objectives were to determine presence and thickness of the Late Jurassic Intra-Draupne Formation sandstone in a representative part of the Avaldsnes High (informal basement structure), and to investigate the reservoir properties of the Permian Rotliegend Group and Zechstein Group.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/3-5 was spudded with the semi-submersible installation Bredford Dolphin on 4 January 2013 and drilled to TD at 2050 m in the Permian Rotliegend Group. No significant problem was encountered in the operations. The well was drilled with seawater down to 700 m and with Performadril water based mud from 700 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well encountered top Draupne Formation shales at 1909 m and the Intra-Draupne Formation sandstone at 1918 m. The Draupne shales are immature but has very good source rock potential with TOC around 7-8 % and Hydrogen Index around 540 mg HC/g TOC. The Intra-Draupne sandstone is 14 m thick and rested on Permian Zechstein Group carbonates. An oil column of approximately 30 meters was found in the Intra Draupne Sandstone and Permian carbonate. The well proves an excellent development of the Late Jurassic sandstone in the southern part of the Avaldsnes High and the reservoir level was encountered a bit shallower than predicted. The Permian carbonates, mainly limestone, had varying reservoir quality with the best quality principally located in open and partially cemented vugs, plus in the fractures. The well results show an oil down-to situation and consequently no oil/water contact was encountered. The oil bearing Zechstein limestones are in pressure communication with the overlying Draupne sandstone.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut from 1912 to 1950.5 m with ca 97% recovery in both. The cored interval includes the lower part of the Draupne Formation shales, the whole Intra-Draupne sandstone unit, one m of Triassic sediments, and 18.5 m of Permian limestones. MDT oil samples were taken at 1920.1 m, 1929.5 m, and 1943.6 m. MDT water samples were taken at 1959.4 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7 March 2013 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One commingled production test from both Draupne sandstones and Zechstein carbonates was performed in the well. DST 1A tested only the lower zone in the Zechstein Group carbonates from 1937 to 1945 m. This zone did not produce oil to surface, but a rate of 2-3 Sm3/day was estimated based on volumes of base oil to tank.</span></p> <p class=MsoBodyText><span lang=EN-GB>DST1 B tested both zones: 1937 to 1945 m in Zechstein plus 1918 to 1931.3 m in the Intra-Draupne Formation Sandstone. The Intra-Draupne sandstone showed extremely good reservoir properties as well as no indications of pressure barriers. This zone produced 740 Sm3 oil and 17000 Sm3 gas /day through a 40/64" choke. The GOR was 17.5 Sm3/Sm3, the oil density was 0.89 g/cm3 and the gas gravity was 0.79 (air = 1). The H2S and CO2 contents in the gas were ca 0.5 ppm and ca 0.4%, respectively. The maximum DST temperature at the end of the Main flow was 79.9 °C.</span></p> |
7046
|
4/11/2017 12:00:00 AM
|
04.11.2024
|
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16/3-6
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/3-6 was drilled on the eastern part of the Johan Sverdrup Field on the Utsira High in the North Sea. The primary objective was to appraise the eastern part of the Johan Sverdrup Field between wells 16/2-13 S and 16/3-4. These two wells are located 5 km apart and found different Jurassic sequences and no oil water contact. Well 16/3-6 was drilled to determine which Jurassic sequences were present at this position as well as oil water contact, thickness of the sequences and depth to top reservoir.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>A 9 7/8" pilot hole was drilled from seabed 706 m to check for shallow gas. No shallow gas was seen. Appraisal well 16/3-6 was spudded with the semi-submersible installation Bredford Dolphin on 10 June 2013 and drilled to TD at 2050 m in fractured granitic basement. No significant problem was encountered in the operations. The well was drilled with spud mud down to 698 m and with Performadril water based mud from 698 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top Draupne Formation/BCU was encountered close to prognosis at 1924 m. A well-defined 15-meter thick Draupne Formation shale was penetrated above 24 meters of excellent quality Late Jurassic Intra-Draupne Formation sandstone. The Draupne Formation shales are of late Volgian to early Valanginian age. The Intra-Draupne Formation sandstones were encountered at 1939 m. They are of early Kimmeridgian to ?late Kimmeridgian/early Volgian age and rest directly on solid granitic basement rocks at 1964.5 m. No middle Jurassic sequence was present as in the neighbouring well 16/2-13 S. The oil water contact was established at 1951 m, 4 meters deeper than predicted. Oil shows were described in the interval from 1925 m in the Draupne shales to 1956 m, 5 m below the oil water contact; no other shows were described in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut from 1926 m in the Draupne Formation shale, through the Intra-Draupne Formation sandstone reservoir and down into the basement at 1968 m. The core recovery was close to 100% and the core-log shift was 1.2 m. Oil and water samples were acquired using SLB MDT tools. Oil samples were acquired at 1940.11 m, 1946.51 m and 1950.3 m. Water samples were acquired at 1952.9 m and 1962.5 m. The oil samples proved a GOR of ca 33 Sm3/Sm3, oil density of ca 0.892 g/cm3, and gas gravity of ca 1.06 (air = 1).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged and abandoned on 16 July 2013 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>The hole was perforated between 1952.2 m and 1956.2 m, and two Expro Cats wireless downhole gauges were installed at 1900.7 m and 1885.2 m to monitor reservoir pressure and temperature. The gauges have battery capacity to sample data for up to 5 years. No DST was performed. </span></p> |
7182
|
4/11/2017 12:00:00 AM
|
04.11.2024
|
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16/3-7
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/3-7 was drilled to appraise the southeast flank of the Joan Sverdrup Field on the Utsira High in the North Sea. It is located approximately 2.8 km southeast of the appraisal well 16/3-5 and approximately 4.2 km south-west of the exploration well 16/3-2. The objectives were to determine the presence and thickness of the Upper Jurassic Draupne shale and Draupne sandstone, to calibrate the seismic interpretation and depth conversion, and find the free-water level. The well should also investigate the reservoir properties in the Permian.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/3-7 was spudded with the semi-submersible installation Bredford Dolphin on 30 September 2013 and drilled to TD at 2100 m, 12 m into granitic basement rock. A 9 7/8" Pilot Hole section was drilled from Seabed to 711 m. No shallow gas was observed while drilling the pilot hole or while opening it up to 36". No significant problem was encountered in the operations. The well was drilled with seawater and hi-vis sweeps down to 711 m and with Aquadril glycol mud from 711 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Draupne Formation shale section was encountered at 1937 m and was 13 m thick. The Intra Draupne Formation Sandstone was encountered at 1949 m, which was 12 m deep to prognosis. It was 14 m thick and of excellent quality. Live oil was proved in the uppermost part, but the reservoir was encountered almost completely in the water zone. Sampling indicated that the oil-water contact is at or near 1950 m. Permian carbonates, belonging to the Zechstein Group, were encountered at 1963 m, directly under the Jurassic section. The 36 m thick dolomitic carbonate reservoir has moderate to good reservoir properties. The pressure measurements confirmed the reservoir to be in the same pressure regime as the Johan Sverdrup discovery and the well showed a common water gradient in both the sandstone and Permian carbonates, demonstrating good communication between the two reservoirs. The carbonate reservoir is resting on a two meter thick Kupferschiefer, which in turn rests on 89 m of sandstone and conglomerate belonging to the Rotliegendes Group. Oil shows continued below the thin live oil, throughout the Intra Draupne Formation sandstones, the Zechstein carbonates and a few meters into the Rotliegendes Group.</span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 35.7 m core was recovered in two cores from the interval 1935.5 to 1977.5 m (85% overall recovery).The cores captured most of the Draupne Formation shale, parts of the Intra Draupne Formation sandstone reservoir, and 15 m of the Zechstein Group carbonate. The core to log depth shift was +0.3 m for core 1 and -0.32 m for core 2. RCX fluid samples were taken at 1949.9 m (water and oil), 1950 m (water and trace oil), 1952 m (water), 1952.1 m (water), and 1967 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 8 November 2013 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7276
|
4/11/2017 12:00:00 AM
|
04.11.2024
|
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16/3-8 A
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/3-8 A is a geological sidetrack to well 16/3-8 S. The well was drilled on the eastern part of the Johan Sverdrup Field on the Utsira High in the North Sea. The primary objective was to further investigate the reservoir sections penetrated in the primary well bore 16/3-8 S.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/3-8 A was kicked off at 1716 m in the primary well bore on 18 March 2014. It was drilled with the semi-submersible installation Bredford Dolphin to TD at 2132 m in the Permian Rotliegend Group. No significant problem was encountered in the operations. The well was drilled with Aquadrill mud from kick-off to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated 12 m of Intra Draupne Formation sandstone at 1960 m, above a thin Triassic sequence and Permian Zechstein carbonates. The Intra Draupne sandstone possessed excellent reservoir properties. Petrophysical analysis show average porosity of 25 %, N/G 0.99 and water saturation of 19 %. The resistivity data over the section is affected by massive filtrate or whole mud invasion. Oil shows were described over the Intra Draupne Formation sandstone reservoir and in the dolomitic limestone in the lower part of the Zechstein Group, down to top Kupferschiefer Formation. The oil-water contact was the same as in the main well bore, at 1950 m TVD.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut in this well bore. An RCX fluid sample was taken at 1990 m (water and filtrate).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1 April 2014 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
7459
|
4/11/2017 12:00:00 AM
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04.11.2024
|
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16/3-8 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/3-8 S was drilled on the Avaldsnes High, in the Eastern part of the Johan Sverdrup Field in the North Sea. The well has a crestal position on this part of the Johan Sverdrup structure. The primary objective was to investigate the reservoir properties of the Zechstein Carbonates, including a designed DST for this purpose. A secondary objective was to determine the presence, thickness and quality of the Late Jurassic Intra Draupne Formation sandstones at this location.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/3-8 S was spudded with the semi-submersible installation Bredford Dolphin on 1 January 2014 and drilled to TD at 2109 m in the Permian Rotliegend Group. No significant problem was encountered in the operations. The well was drilled with spud mud down to 607 m and Aquadrill mud from 607 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>A six-meter thick interval of tight Draupne shale was encountered before entering the Volgian Intra Draupne Formation sandstone reservoir at 1964 m (1897 m TVD). The reservoir section consists of 13 meters of Draupne sandstone with excellent reservoir quality and 66 meters of Zechstein carbonates with variable reservoir quality. The carbonate sequence consists of limestone with limited reservoir quality in the upper part and dolomites with moderate to good reservoir quality in the lower part. The reservoir contained a 53 m TVD oil column. The oil/water contact is interpreted at 2021 m (1950 m TVD) based on the interception of the water gradient and the oil gradient from pressure measurements. Oil shows are described throughout the oil-bearing reservoir and down to a depth of 2035.6 m in the dolomitic limestones.</span></p> <p class=MsoBodyText><span lang=EN-GB>Four cores were cut in succession from 1965 m in the Draupne Formation, through the Intra Draupne Formation Sandstone and the Smith Bank Formation and down to 2035.6 m in the Zechstein Group carbonates. Recovery was good, between 97.2 and 100%. RCX fluid samples were taken at 1965.6 m (oil), 1977.7 m (oil), 2019.5 m (water and oil), and 2037.8 m (water). Single stage separation to ambient conditions gave a GOR of ca 41 Sm3/Sm3 and an oil density of ca 0.894 g/cm3 for both of the two oil samples.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged back and prepared for sidetracking on 16 March 2014. It is classified as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One production test was performed. The interval 1964.1 - 1979.2 m was perforated and tested. In the main flow, the test produced 803 Sm3 oil and 18900 Sm3 gas through a 52/64" choke. The GOR was 23.5 Sm3/Sm3, the oil gravity was 0.89 g/cm3, and the gas gravity was 0.79 (air = 1). The maximum DST temperature was 82.5 °C.</span></p> |
7302
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/3-U-1
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<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>General</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/3-U-1 was drilled on the south-eastern end of the Johan Sverdrup Field on the Utsira High in the North Sea. The reservoir in this part of the field is below seismic resolution. The primary objective was to investigate sand presence, thickness and quality. Side-tracks were planned to further investigate horizontal well drilling and high angle hole time-stability in Draupne shales.<o:p></o:p></span></p> <p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Operations and results</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/3-U-1 was spudded with the semi-submersible installation Deepsea Atlantic on 13 December 2016 and drilled to TD at 2005 m (1999 m TVD) m in Basement rocks. The well was designed with open hole below the 13 3/8” casing shoe at 1119 m in the Hordaland Group. This allowed for reservoir logging at TD to be extended to the overburden. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to <span style='mso-spacerun:yes'> </span>down to 1130 m and with Carbosea oil-based mud from 1130 m to TD. <o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The Draupne Formation was encountered at 1938 m (1932 m TVD), the Intra-Draupne Formation sandstone at 1950 m (1944 m TVD), <span style='mso-spacerun:yes'> </span>and top Basement at 1959 m (1953 m TVD). The Intra-Draupne Formation sandstone had excellent reservoir properties and was oil-filled all through. No oil shows were described outside of the oil-bearing reservoir. Pressure data show ca 0.9 bar depletion in the reservoir compared to the pressure in well 16/3-5 in January 2013. Pressure data and logs in the overburden show no indication of flow potential.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>One core was cut from 1943 to 1962 m in Draupne shale, sandstone and into basement. An RCX oil sample was taken at 1958.2 m.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The well was plugged back for side-tracking on 24 December 2016.<o:p></o:p></span></p> <p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Testing</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'> <b><o:p></o:p></b></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No drill stem test was performed. <o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p> </o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p> </o:p></span></p> |
8071
|
11/14/2019 12:00:00 AM
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04.11.2024
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16/3-U-1 A
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<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>General</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/3-U-1 A is a geological and geo-mechanical side-track to 16/3-U-1 on the south-eastern end of the Johan Sverdrup Field on the Utsira High in the North Sea. The reservoir in this part of the field is below seismic resolution. <a name="_Hlk23318253">The primary objective of the primary well and side-track was to investigate sand presence, thickness and quality. Secondary, to investigate horizontal well drilling and high angle hole time-stability in the Draupne shales.<o:p></o:p></a></span></p> <span style='mso-bookmark:_Hlk23318253'></span> <p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Operations and results</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Wildcat well 16/3-U-1 A <a name="_Hlk23319048">was kicked off below the 13 3/8” casing at 1135 m in the primary well on 24 December 2016. It was drilled with the semi-submersible installation Deepsea Atlantic, down-dip towards the south-east to TD at 2882 m (1965 m TVD) in Basement rock. Operations proceeded without significant problems. The well was drilled with Carbosea oil-based mud from kick-</a><span class=GramE><span style='mso-bookmark:_Hlk23319048'>off <span style='mso-spacerun:yes'> </span>to</span></span><span style='mso-bookmark: _Hlk23319048'> TD. <o:p></o:p></span></span></p> <span style='mso-bookmark:_Hlk23319048'></span> <p class=MsoBodyText><a name="_Hlk23319432"><span lang=EN-GB style='mso-ansi-language: EN-GB'>Top Draupne Formation was penetrated at 2578 m (1939 m TVD), while the Intra Draupne Formation sandstone was encountered at 2763 m (1955 m TVD), and Basement at 2861 m (1963 m TVD). </span></a><span lang=EN-GB style='mso-ansi-language: EN-GB'>The Draupne sandstone had abundant cementations and was water-filled. The hole was re-entered as planned after 48 hours from encountered TD, with liner running parameters, in order to simulate a liner running job combined with time exposure of the Draupne shale. The BHA was not able to pass restrictions at the top of the Draupne shale. It was decided to re-enter with a less stiff BHA. However, a fire broke out in a hose and led to about a week delay in operations, the well had to be abandoned, and a side-track, 16/3-U-1 B, was prepared.<o:p></o:p></span></p> <p class=MsoBodyText><a name="_Hlk23320912"><span lang=EN-GB style='mso-ansi-language: EN-GB'>There are no oil show recordings from this well bore.<o:p></o:p></span></a></p> <span style='mso-bookmark:_Hlk23320912'></span> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No cores were cut. No fluid sample was taken.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The well was plugged back for side-tracking on 10 January 2017.</span><span lang=EN-GB> </span><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p> <p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Testing</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'> <b><o:p></o:p></b></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No drill stem test was performed. <o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p> </o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p> </o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p> </o:p></span></p> </div> </body> </html> |
8077
|
11/15/2019 12:00:00 AM
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04.11.2024
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16/3-U-1 B
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<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>General</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/3-U-1 B is a geological and geo-mechanical side-track to 16/3-U-1 on the south-eastern end of the Johan Sverdrup Field on the Utsira High in the North Sea. The reservoir in this part of the field is below seismic resolution. The primary objective of the primary well and side-tracks was to investigate sand presence, thickness and quality. Secondary, to investigate horizontal well drilling and high angle hole time-stability in the Draupne shales. As part of the secondary objective the first side-tracked bore hole 16/3-U-1 A should be left open for 48 hours and then re-entered. After an unsuccessful re-entry well bore 16/3-U-1 A was abandoned and side-track 16/3-U-1 B was initiated. Final TD in this side-track was set to a location between the primary wellbore and the first side-track in order to penetrate the field OWC.<o:p></o:p></span></p> <p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Operations and results</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/3-U-1 B was kicked off from 16/3-U-1 A below the 13 3/8" shoe at 2115 m on 10 January 2017. It was drilled with the semi-submersible installation Deepsea Atlantic, down-dip towards the south-east of the primary well bore to TD at 2665 m (1963 m TVD) in Basement rock. Operations proceeded without significant problems. The well was drilled with Carbosea oil-based mud from kick-off <span style='mso-spacerun:yes'> </span>to TD. <o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Top Draupne Formation was penetrated at 2515 m (1937 m TVD), while the Intra Draupne Formation sandstone was encountered at 2598 m (1952 m TVD), and Basement at 2646 m (1960 m TVD). The Intra-Draupne sandstone was oil-filled down to the OWC at<span style='mso-spacerun:yes'> </span>2605.5 (1953 TVD).<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>In order to check for mechanical issues, a check trip through Draupne shale was successfully made 8-9 hours after drilling. Then a second check trip was made after 18 hours. The BHA was unable to get down with liner running parameters, and therefore drilling parameters were used and proved to be successful.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>There are no oil show recordings from this well bore.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No cores were cut. No fluid sample was taken.<o:p></o:p></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The well was permanently abandoned on 15 January 2017.<o:p></o:p></span></p> <p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Testing</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'> <b><o:p></o:p></b></span></p> <p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No drill stem test was performed. <o:p></o:p></span></p> |
8104
|
11/15/2019 12:00:00 AM
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04.11.2024
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16/4-1
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<p><b>General</b></p>
<p>Well 16/4-1 is located on the Utsira High. The primary objective of the well was to test the Paleocene Heimdal Formation. Secondary objectives were Jurassic and Triassic sandstones, Zechstein carbonates and Rotliegendes conglomerates. The well was planned to reach TD at 2850 m + 100 m after having identified a seismic reflector at this depth, interpreted to represent Top Metamorphic Basement.</p> <p><b>Operations and results</b></p> <p>Wildcat well 16/4-1 was spudded with the semi-submersible installation Treasure Seeker on 8 September 1984 and drilled to TD at 2909 m in crystalline/metamorphic basement of Early Paleozoic age. Under the 30" casing shoe a 17 1/2" pilot hole was drilled. At 494 m in Pleistocene sand and shale, the well started to flow up the annulus from a small gas pocket. The well died out by itself but there were problems with lost circulation, so a cement plug was set from 494 - 415 m. The cement was drilled out to 480 m and the hole was underreamed to 26" before landing of the 20" casing. No other major problems occurred during drilling of this well. The well was drilled with seawater and bentonite down to 494 m, with KCl/polymer mud from 494 m to 2052 m, and with NaCl/polymer mud from 2052 m to TD. </p> <p>The well 16/4-1 encountered water-bearing sandstones in the Paleocene Heimdal Formation as well as in the Triassic. The latter is a 36 m thick sand in between the Smith Bank Formation and the Zechstein Group. The Heimdal Formation Sandstones occur as interbedded sand/claystone in the upper part (2100 m to 2142 m) and as a massive sandstone, which is homogenous and very clean in the lower part (2142 m 2277 m). The Triassic sandstones (2394 m to 2430 m) were very fine-to-fine grained with a considerable amount of silt and mica. Log evaluations over these sands gave the following results: The interval 2100 m to 2142 m gave a net/gross ratio of 0.095, with an average porosity of 23,06% and a shale volume of 43,58% after cut-off. The interval 2142 m to 2277 m had a N/G of 0,89 with 26,36% average porosity and 11,19% shale volume. The Triassic interval (2394 m to 2430 m) had a net/gross of 0,37 with 22,88% average porosity and 18,54% shale volume. All these values are calculated after a cut-off of 20% (1 mD). Twenty-five pressure tests (RFT) were performed from 2083 m to 2422.4 m. These gave a water gradient of 0,445 psi/ft (1.024 g/cc) in the Heimdal Fm sandstones. No pressure data were obtained from the Triassic. </p> <p>Three cores were cut in this well, the first and second in sandstones of the Heimdal and Smith Bank formations respectively. The third core was taken in metamorphic/crystalline basement. Core 1 was cut from 2161 m to 2174 m in the Heimdal formation. The recovered core of 11 m (85%) consisted of very fine to medium grained, poorly sorted sandstone with claystone in the interval 2170-71 m. Core 2 was cut from 2404 m to 2422 m and 17.5 m (97%) was recovered. The core was cut in the Triassic sand under the Smith Bank Formation. It consisted of micaceous sandstones and siltstones with subordinate clay clasts. Core 3 was cut from 2907 m to 2909 m in the Basement and 100% was recovered. The core consisted of schist and granite. No fluid samples were collected. The well was permanently abandoned on 18 November 1984 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
229
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7/6/2016 12:00:00 AM
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04.11.2024
|
|
16/4-10
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/4-10 was drilled to test the Fosen prospect on the southwest part of the Utsira High in the North Sea. The primary objective was to test the hydrocarbon potential in Late and Middle Jurassic reservoirs. A secondary objective was to core the BCU top reservoir boundary for facies evaluation and dating.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/4-10 was spudded with the semi-submersible installation Island Innovator on 24 January 2016 and drilled to TD at 2668 m in Early Triassic sediments in the Smith Bank Formation. A 9 7/8" pilot hole was drilled to 520 m after installing the 30"x36" conductor casing to check for shallow gas. No shallow gas or water flow was observed. No significant problem was encountered in the operations. The well was drilled with seawater and hi-vis pills down to 529 m and with Aquadril mud from 529 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-US>The well encountered about 160 m of water bearing sandstones in the Late Jurassic to Middle Triassic, of which about 90 m, mainly in the Middle Jurassic Sleipner Formation, are of good reservoir quality. The well also encountered 75 m of reservoir rocks with very good reservoir quality in the Paleocene Ty Formation. Trace fluorescence was recorded in the Sleipner Formation, but could not be confirmed as migrated petroleum in post-well organic geochemical analyses. </span></p> <p class=MsoBodyText><span lang=EN-GB>A total of 11.7 m core was cut in four cores from 2424.1 to 2440 m in the Åsgard Formation, thus missing the BCU boundary. Core depths are equal to log depths for all cores. After drilling through BCU there were no shows and no gas response and it was decided to drill ahead without taking any more cores. MDT pressure points were acquired in the reservoir section and water samples were taken at 2313.6 m and 2467.1 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7 March 2016 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7731
|
5/23/2017 12:00:00 AM
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04.11.2024
|
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16/4-11
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/4-11 was drilled on the Luno Discovery on the Utsira High in the North Sea. The primary objective of the well was to delineate the southwest flank of the 16/4-6 S (Luno II) discovery, to investigate the reservoir properties, and to investigate the type of oil and total oil column in this part of the discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/4-11 was spudded with the semi-submersible installation COSL Innovator on 7 February 2018. A 9 7/8” pilot hole was drilled from below the 30x36” casing shoe at 195 m to 475 m. Shallow gas was observed in the interval 469 m to 471 m. The 20” casing was therefore set shallow at 409.5 m, above the shallow gas zone. From there the well was drilled to TD at 2475 m in the Permian Rotliegendes Group. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 409.5 m, with KCl/polymer mud from 409.5 m to 1922 m, and with Aquadrill mud from 1922 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Top of the target reservoir, Hegre Group, was encountered at 1950 m. It was oil-bearing down to a clear oil-water contact at 1971.5 m. Good shows were described in the oil-bearing reservoir section. Below the OWC shows continued down to the base of the cored interval at 2004 m. These shows are described as having no odour, 100% even weak yellowish direct fluorescence, slightly blooming weak bluish white cut fluorescence, and 10% moderate bluish white fluorescent residue. The conventional core and sidewall cores from the Permian sandstone had shows that weakened with depth in the interval 2090 to 2329 m. These are typically described as having no odour, yellowish brown direct fluorescence, no to diffuse blue-white fluorescent cut, and no to 80% blue white cream fluorescent residue.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the well. Cores 1 and 2 were cut in the top of the Hegre Group reservoir from 1952 to 2004.1 m with 100% recovery. Core 3 was cut in the Permian sandstones from 2090 to 2099 m with 94.2% recovery. MDT fluid samples were taken at 1952.1 m (oil), 1963 m (oil), 1970.1 m (oil), 1971.61 m (water), 1978.3 m (water), 2001.72 m (water), and 2075 m (water). Single flash of the uppermost oil sample gave a GOR of 233.4 Sm3/Sm3 and an oil density of 0.8482 g/cm3.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1 April 2018 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
8353
|
4/1/2020 12:00:00 AM
|
04.11.2024
|
|
16/4-12
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/4-12 was drilled to test the Merckx prospect west of the 16/4-6 S Solveig discovery on the Utsira High in the North Sea. The primary objective was to test the reservoir properties and hydrocarbon potential of the Ty Formation. The secondary objective was to test the reservoir properties and hydrocarbon potential of the Zechstein Group.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>A 9 7/8" pilot well 16/4-U-8 was drilled to 778 m to check for shallow gas. No shallow gas was seen.</span></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/4-12 was spudded with the semi-submersible installation Deepsea Stavanger on 19 September 2021 and drilled to TD at 2171 m in the Permian Zechstein Group. Severe mud losses were experienced in the Zechstein Group with a total loss of 1353 m WBM, 68 m SW, 65 m brine and 96 m thixotropic cement. A total of 3.3 days was used to cure losses. The well was drilled with seawater and hi-vis pills down to 990 m, with Rheguard Prime oil-based mud from 990 m to 2043 m, and with Glydril Plus mud from 2043 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/4-12 was dry at both target levels. Forty-eight metres of sandstone with good to very good reservoir quality was penetrated in the Ty Formation. In the secondary target, the well encountered 12 metres of dolomitic rocks of the Zechstein Group with poor to moderate reservoir quality. The well also encountered an interval of sandstone of possibly Jurassic/Triassic age between the Ty Formation and Top Zechstein Group. The interval was 15 metres thick with good to very good reservoir quality. The only hydrocarbon indication in the well was weak shows in a thin sandstone at 2020 m in the Lista Formation ("No odour, rare back carbonaceous material, spotty pale yellow direct fluorescence, weak, slow streaming, bluish white cut fluorescence, dull bluish white, fluorescent residue ring and patchy dark orange residue"). C1 C5 gas peaks above background level were observed around the same depth.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut, and no fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 8 October 2021 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
9162
|
9/6/2023 12:00:00 AM
|
04.11.2024
|
|
16/4-13 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/4-13 S was drilled to test the D-segment prospect in a sub-basin northwest of the Solveig Field and south of the Edvard Grieg Field in the North Sea. The primary objective was to prove petroleum in reservoir rocks of Triassic to Paleozoic Age.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/4-13 S was spudded with the semi-submersible installation West Bollsta on 12 February 2021. The well was drilled to 1985 m where pack-off occurred and losses were experienced. The losses could not be cured. The decision was made to plug back and make a side-track. Technical side-track 16/4-13 ST2 was kicked off at 1365 m and drilled to TD at 2422 m (2324.3 m TVD) in Paleozoic basement conglomerates. The well was drilled with seawater and hi-vis pills down to 426 m, with Hydraglyde Optima water-based mud from 426 m to 1365 m, with Glydril Plus water-based mud form 1365 m to 2010 m and with Hydraglyde Optima water-based mud from 2010 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Paleozoic basement sandstone and conglomerates were encountered with top at 2020 m (1973.4 m TVD), directly underlying Late Cretaceous Tor Formation chalk. No Jurassic or Triassic sediments were present. The Basement was oil bearing down to an oil-water contact at ca 2031 m (1983 m TVD). About seven metres of the reservoir had poor to moderate reservoir quality. Shows on cuttings (no stain, no odour, direct and cut fluorescence) continued down to 2098 m and weaker shows (weak direct fluorescence only) down to 2175 m). No shows were described above top reservoir.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut in succession from 2022.8 to 2048.3 m in the basement conglomerates. ORA fluid samples were taken at 2022.2 m (oil), 2027.04 m (oil), and 2034.5 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 10 April 2021 as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
9209
|
4/10/2023 12:00:00 AM
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04.11.2024
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16/4-2
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<p><b>General</b></p> <p>Well 16/4-2 was the second well on the block and last commitment well for license 087. The well is located in a central position on the structure, close to the western border of the block. The main target was sands of Middle Eocene age supposed to be present within a mounded seismic sequence that constitutes the eastern part of the Alpha prospect in the Sleipner Field. The primary objective of the well was to prove oil in the Eocene sandstones. Secondary objectives were to confirm the seismic interpretation and the geological model for the Eocene sand; to test a possible small closure at top Heimdal Formation level; to obtain additional information on migration paths in the area; to confirm the seismic interpretation of the basal Cretaceous/ Late Jurassic sequence; and to test the hydrocarbon potential of possible Late Jurassic sand accumulations. Shallow gas could be expected at 537 m. This corresponds to the level of the blowout in well 16/4-1. A possible shallow gas content could occur in a thin sand layer at 685 m, which was correlated from well 16/4-1.</p> <p><b>Operations and results</b></p> <p>Wildcat well 16/4-2 was spudded with the semi-submersible installation Vildkat Explorer 29 June 1990 and drilled to 3117 m in Intra Draupne Formation sandstones. No shallow gas was encountered in the well; the gas zones were drilled with riser and mud weight 1.22 rd to control the gas. The well was drilled with seawater and hi-vis pills down to 1710 m and with KCl Polymer mud from 1710 m to TD. Drilling went without any significant problems apart from the 13 3/8" casing getting stuck at 1450 m. To resolve this problem diesel EZ pills were used in the well bore. This affected gas readings throughout the well below 1710 m and gave some spuriously high readings. The 13 3/8" casing shoe was finally set at 1683 m, and the casing cemented. The Eocene Grid formation sandstone came in at 1913 m, approximately 88 m deeper than prognosed. No hydrocarbons were recorded. The Heimdal formation sandstone came in at 2415 m, approximately 110 m deeper than prognosed. No hydrocarbons were recorded. Late Jurassic sands (Intra Draupne Formation) were also developed, but no hydrocarbons were recorded. The only hydrocarbons observed were some weak shows in claystones of the Draupne Formation. One core was cut in the interval from 1920 to 1927 m in the Grid Formation with 88.6 % recovery. A total of 60 sidewall cores were attempted in one run from 1750 to 3113 m, whereof 50 were recovered. No fluid samples were taken. The well was permanently plugged and abandoned 29 July 1990 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
1560
|
7/6/2016 12:00:00 AM
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04.11.2024
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16/4-3
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<p><b>General</b></p>
<p>Block 16/4 was initially awarded to Norsk Hydro as PL087 in 1984. Two exploration wells were drilled; 16/4-1 in 1984 and 16/4-2 in 1990. Both wells were targeted at Eocene prospects, however neither well was successful due to the inability of hydrocarbons to successfully migrate through thick Palaeocene mudstones into the targeted Eocene prospects. Subsequently, PL087 was relinquished on 1 January 1995. BP, in partnership with Norsk Hydro, was awarded Block 16/4 as the PL243 license as part of the North Sea Awards in 1999. The 16/4-3 well is the first well drilled in the license since the award and was targeted to penetrate Palaeocene turbidite sands in the Fluoritt Prospect located at the western edge of the Utsira High in the South Viking Graben of the North Sea. It was designed to determine the hydrocarbon type and properties in the Fluoritt Prospect.</p> <p><b>Operations and results</b></p> <p>Exploration well 16/4-3 well was spudded with the semi-submersible installation "West Delta" on 5 December 2000 and drilled to TD at 2425 m in the Early Paleocene Ekofisk Formation. The well was drilled with seawater and bentonite hi-vis pills down to 400 m, with KCl polymer mud from 400 m to 1700 m, and with KCl glycol enhanced mud ("GEM") from 1700 m to TD. Top Hermod was encountered 27 m low to prognosis at 2196.3 m. Hydrocarbon fluorescence was observed in cuttings from thin Hermod sands the in the interval 2195 m - 2220 m and also from a Middle Heimdal Formation sand in the interval 2277 m to 2282 m, however, the Hermod sandstones were poorly developed at the well location and are considered uneconomic. No conventional or sidewall cores were cut in the well. No fluid samples were taken, neither on wire line nor from DST. Well 16/4-3 was permanently abandoned as a well with oil shows on 24 December 2000.</p> <p> </p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
4194
|
7/6/2016 12:00:00 AM
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04.11.2024
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16/4-4
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<p><b>General</b></p> <p>Well 16/4-4 was drilled on the south-west part of the Utsira High in the Norwegian North Sea. The objective of the well was to prove hydrocarbons in the Ty/Heimdal Paleocene turbidite sandstones in the Biotitt prospect. It was important to acquire sufficient data to understand the reservoir characteristics and fluid distribution.</p> <p><b>Operations and results</b></p> <p>Wildcat well 16/4-4 was spudded with the jack-up installation West Epsilon on 28 December 2006 and drilled to TD at 2409 m at the top of the Late Cretaceous Tor Formation. The well was drilled with seawater/bentonite/polymer mud from down to 1213 m, and with KCl/PAC/GEM GP mud from 1226 m to TD. No shallow gas was observed. </p> <p>The well penetrated rocks of Quaternary, Tertiary and Cretaceous age. The Ty reservoir section was encountered at 2271 m, 12 m deeper than prognosed. It was 79 m thick and consisted of fine to medium sandstone with claystone and limestone. The Heimdal Formation was not present in the well. The pressure tests indicated an approximately 7 m thick gas/condensate column in the upper part of the Ty Formation. There were no hydrocarbon indications elsewhere in the well.</p> <p>One core was cut from 2275 m to 2302 m in the Ty Formation. Twenty excellent MDT pressure tests were acquired together with MDT water samples at 2284.9 m and MDT condensate samples at 2272.5 m. </p> <p>The well was permanently abandoned on 23 March 2003 as a gas/condensate discovery.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
5441
|
4/11/2017 12:00:00 AM
|
04.11.2024
|
|
16/4-5
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/4-5 was drilled on the Luno High prospect located south of the Luno field on the southern Utsira High in the North Sea. The general objectives were to refine the resource potential of the Greater Luno Area and to increase the regional understanding of the sedimentary sequences and fractured basement facies across the Utsira High. The specific objective was to prove the presence of oil bearing sandstones in the Late Jurassic to Early Cretaceous sequence or in conglomerates in the Triassic to Middle Jurassic sequence. The well would test the Luno regional oil-water contact at 1940 m MSL or the alternative oil-water contact established in well 16/1-12, 1928 m MSL. In case of a discovery test production rates in the variable reservoir facies by means of one or more DSTs would be conducted. Planned depth was 2300 m RKB</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/4-5 was spudded with the semi-submersible installation Transocean Winner on 2 February 2010 and drilled to TD at 2020 m in pre-Devonian basement rock. This was 280 m shallower than planned because the prognosed reservoir conglomerates or fractured basement were not encountered. At TD in the 12 1/4" section at 1790 m large quantities of mechanical and stress-release cavings, thought to originate from the Lista and Sele Formations, were circulated out of the hole. Otherwise the were no mud losses or other hole problems in the well. A very slow ROP of approximately 2.5 m/hr was obtained in the 8 1/2" hole below the core point with an insert bit. This was due to the hard, granitic formation. The well was drilled with seawater and hi-vis pills down to 600 m and with Glydril KCl mud from 600 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>No Cretaceous or Late Jurassic age sandstones or Middle Jurassic to Triassic age conglomerates were encountered in the well. Well 16/4-5 proved oil shows in faulted/fractured granitic basement underlying red coloured marls of Hauterivian to Valanginian age. The granitic basement was highly fractured, as seen from the FMI log; however, analysis of the core showed that a large majority of these fractures were tightly cemented. Several fractures were open and contained traces of migrated hydrocarbons, mainly characterised by black tarry material, dry and flaky in some cases. </span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut in the interval 1896 m to 1925.7 m across BCU and into basement. A number of attempts to measure formation pressures and take fluid samples were made using a Schlumberger MDT tool, however, the formation proved too tight. No pressure results were obtained. One MDT fluid sample recovered from 2002.5 m was found to contain drilling fluid only; otherwise no fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7 March as a well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>The fractured granitic basement did not have reservoir characteristics, therefore the well was not production tested.</span></p> |
6216
|
4/11/2017 12:00:00 AM
|
04.11.2024
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16/4-6 S
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<html>
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/4-6 S was drilled on the Luno II prospect about 15 km south of the Edvard Grieg field on the Utsira High in the North Sea. The primary objective of the well was to prove petroleum in Middle to Late Jurassic reservoir rocks. Secondary objective was to test the hydrocarbon potential in underlying older rocks.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/4-6 S was spudded with the semi-submersible installation Bredford Dolphin on 11 March 2013 and drilled to TD at 2233 m (2213 m TVD) in the Late Triassic Skagerrak Formation. No significant problem was encountered in the operations. The well was drilled with spud mud down to 610 m and with water based Performadril mud from 610 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Top of the target reservoir was reached at 1950 m (1931 m TVD). The target reservoir is capped by a 10 cm thick Cromer Knoll Group at 1950 m (1931 m TVD). The reservoir section consisted of a 248 m thick sandstone sequence assigned mainly to the Skagerrak Formation with the exception of the top four meters that could belong to the Vestland Group, based on the occurrences of a few questionable terrestrial palynomorphs of Middle Jurassic age. The reservoir contained a gross oil column of ca 45 metres down to an OWC at 1995 m (1975 m TVD). About 30 metres of the oil-bearing zone had good reservoir properties. The oil is saturated and is in contact with a thin gas zone at the top of the reservoir, above the tested zone. Below the OWC, there is a zone of biodegraded oil shows in contrast to the non-biodegraded oil above. This suggest that there has been more than one generation of hydrocarbons present. Diminishing oil shows are described intermittently down to the base of the cored section at 2024 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the interval from 1943.5 in the Tor Formation to 2024 m in the Skagerrak Formation. The core recovery was 99.7 to 100%. The core depth is ca 1 m deeper than logger's depth for all three cores. MDT fluid samples were taken at 1951.34 m (wet gas), 1952.54 m (wet gas), 1966.39 m (oil), 1978.73 m (oil), 1991.29 (water with trace oil), 1995.9 m (water), and 2028.18 m (water). </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 3 May 2013 as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One Drill Stem Test was performed from the interval 1960.6 to 1980.6 m. In the main flow the test produced 271 Sm3 oil and 53900 Sm3 gas /day through a 40/64" choke. The GOR was 209 Sm3/Sm3, the oil density was 0.85 g/cm3, and the gas gravity was 0.82 - 0.85 (air = 1). H2S and CO2 contents were low, ca 0.1 ppm and 0.1 %, respectively. The DST temperature was 76.6 °C.</span></p> |
7098
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/4-7
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/4-7 was drilled on the Biotitt prospect, a structural trap located some 30 km south of the Edvard Grieg field on the Utsira High in the North Sea. The well was drilled about 0.5 kilometres west of well 16/4-4, which penetrated down to the Late Cretaceous Tor Formation and found gas and condensate in the Early Paleocene Ty Formation. The primary objectives of well 16/4-7 was to prove petroleum deeper down on the structure, in Jurassic Intra-Heather or Hugin Formation sandstones. The well was planned to drill into Triassic strata.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/4-7 was spudded with the semi-submersible installation Bredford Dolphin on 23 July 2013 and drilled to TD at 2600 m in the Triassic Skagerrak Formation. No shallow gas was seen while drilling the top hole sections including the 9 7/8" pilot hole. The 12 1/4" section suffered from overall low efficiency due to power generation issues on the rig and a main engine cam shaft breakdown. The well was drilled with seawater and hi-vis sweeps down to 758 m and with Performadril water based mud with glycols from 758 to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Ty Formation sandstones were encountered as prognosed at 2266 m with a gross thickness of 47.5 m. It was dry without shows. The target Jurassic sandstone reservoir was encountered at 2489 m. These sandstones are of Kimmeridgian age and belong to the Ula Formation rather than the Hugin Formation. The reservoir was of excellent quality, but was water-filled with only very weak visible oil shows seen in two sidewall cores. The thickness of the Ula Formation was 40 m. Skagerrak Formation sandstones with good reservoir quality were found unconformably underlying the Ula Formation with very weak oil shows seen in a sidewall core taken at the top of the formation. Post well geochemical analyses of the three weak shows proved only trace amounts of hydrocarbons that might be related to contamination.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid samples were taken</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 21 August as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7208
|
4/11/2017 12:00:00 AM
|
04.11.2024
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16/4-8 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/4-8 S was drilled to appraise the Luno II discovery made by well 16/4-6 S in 2013 on the west flank of the Utsira High in the North Sea.</span><span lang=EN-GB> </span><span lang=EN-GB>Well 16/4-8 S targeted the Central South segment, located 4 km south of the Luno II discovery well. The objectives were to prove presence of good quality Jurassic/Triassic reservoir sandstone; to verify the petroleum potential in the Central South segment including the Luno II OWC at 1950 m MSL; and to calibrate the seismic interpretations for the Luno II sub-basin.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/4-8 S was spudded with the semi-submersible Bredford Dolphin on 19 June 2014 and drilled to 2700 m (2670 m TVD) in the Triassic Skagerrak Formation. The well was drilled deviated from 2100 m to avoid a prognosed fault. Mud losses occurred when drilling the interval 2391 m to TD. LCM pills were pumped to amend this. Otherwise, no significant problem was encountered in the operations. The well was drilled with spud mud down to 610 m and with Aquadril mud from 610 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-US>Top reservoir Hegre Group, was encountered at 1934 m (1934 m TVD). No Jurassic sediments were present. The Skagerrak Formation held a total oil column of about 30 m, of which about 15 m had very good reservoir properties. The oil is saturated with a thin gas column on top. Between ca 1970 m and ca 1980 m the reservoir was mainly water bearing, and then a separate zone with biodegraded oil and water was sampled from 1980 to 1987. No clear OWC could be established from the well data. The reservoir rocks, including the water zone, consist of 500-metre thick sandstones over a 200-metre thickness of conglomerate rock. Pressure data shows there is no pressure communication between 16/4-8 S and the 16/4-6 S discovery well. </span></p> <p class=MsoBodyText><span lang=EN-US>The first oil show appeared in sidewall cores in Shetland Group limestone from 1928 m, six meter above top reservoir. Variable but generally good oil shows were described throughout the oil-bearing reservoir and down to 2030 m. Local weak oil shows were described in the Hegre Group below 2030 m down to 2382 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Seventy-three meter core was recovered in seven consecutive cores in the interval 1935 to 2009 m (98.7% total recovery). MDT fluid samples were taken at 1934.5 m (condensate), 1942.3 m (oil), 1942.5 m (oil), 1945.5 m (oil), 1955.7 m (oil), 1962 m (oil), 1962.8 m (oil), 1967 m (oil), 1975 m (water), 1980 m (slightly biodegraded oil/water/gas), 1987 m (water and traces of mildly biodegraded oil), 2024 m (water), and 2508.2 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 26 August 2014 as an oil and gas appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One production test was performed in the well 16/4-8 S. The interval 1940 to 1958 m was perforated and produced with a final flow rate of 63 Sm3 oil and 12030 Sm3 gas /day through a 28/64" fixed choke with a wellhead pressure of 17 bar. A GOR of 192 Sm3/Sm3 was measured at separator conditions of 44.2 °C and 8.7 bar. The on-site measured oil density at 15 °C was 0.89 g/cc and the gas gravity was 0.91(air = 1). The H2S and CO2 contents were less than 0.1 ppm and 0.2 % respectively. The maximum temperature recorded at gauge depth 1919.37 was 81°C, but due to significant Joule-Thompson effects the recorded temperatures varied widely, and the true formation temperature could not reliably be established.</span></p> |
7415
|
4/11/2017 12:00:00 AM
|
04.11.2024
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16/4-9 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/4-9 S was drilled to appraise the 16/4-6 S Luno II discovery on the Utsira High southwest of the Johan Sverdrup Field in the North Sea. The well should prove extension of Triassic/Jurassic reservoir sandstone and verify pressure communication towards the Luno II C segment northwest of the 16/4-6 S discovery well. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/4-9 S was spudded with the semi-submersible installation Bredford Dolphin on 14 June 2015 and drilled to TD at 2358 m (2330 m TVD) in the Triassic Skagerrak Formation. The well was drilled S-shaped, building angle from 602 m to a sail angle of ca 12.9° in the interval 1000 m to 1750 m and back to vertical again from ca 1970 m. No significant problem was encountered in the operations. The well was drilled with seawater and high viscosity pills down to 6011 m and with Aquadril mud from 6011 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Top reservoir Skagerrak Formation sandstones was penetrated at 1983 m. The reservoir consisted of relatively homogenous sandstone overlain by a more conglomeratic sequence. It held an oil column of ca 25 m down to a clean OWC at 2008.8 m (1981 m TVD). The oil is a mix of biodegraded residual oil and a fresh light oil. The reservoir is 4 bar depleted compared to well 16/4-6 S. No shows were observed above the reservoir. Below the reservoir, good oil shows were recorded on cores down to 2042 m, and weaker shows were seen down to 2053 m. No shows were seen below 2053 m.</span></p> <p class=MsoBodyText><span lang=EN-GB>Three cores were cut from 1985 m to 2066.2 m with close to 100% recovery. The core depth was 0.775 m deeper than log depth for all three cores. MDT fluid samples were taken at 1984.5 m (oil), 2000.1 m (oil), 2006.66 m (oil and water), and 2030.1 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 16 August 2015 as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>One production test (DST) was performed from the interval 1981 to 2001.9 m. The DST produced on average 136 Sm3 oil and 23400 Sm3 gas/day through a 28/64" choke (main flow). The GOR was 172 Sm3/Sm3. The maximum downhole temperature in the DST was 78.5 °C.</span></p> |
7631
|
5/23/2017 12:00:00 AM
|
04.11.2024
|
|
16/5-1
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<p><b>General</b></p>
<p>Well 16/5-1 is located on the Utsira High in the North Sea. The main target of the 16/5-1 well ("Vali") was a pinch-out of Paleocene sands on a seismic monoclinal. The interest in this trap was emphasized by oil-shows in Paleocene sands in surrounding wells.</p> <p><b>Operations and results</b></p> <p>Wildcat well 16/5-1 was spudded with the semi-submersible installation Pentagone 81 on 17 January 1971 and drilled to TD at 1943 m in granitic basement rocks. The well was drilled using seawater-based mud.</p> <p>The Paleocene sands, which were the main objective of the Vali well, were not present. A thin Cretaceous series was found directly overlaying Caledonian basement rocks. From 1923 m to TD the well penetrated migmatitic granite, highly fractured and slightly weathered down to 1940 m. No shows were recorded, only background gas of C1 from1% to 3 % while drilling the tertiary series. The only reservoirs encountered in Vali well were 164 m net sand in the sand-shale sequence in the Utsira Formation from 754 m to 1012 m. These sands, very fine to medium and shelly, have very high porosity, more than 32 %. However, they are not sufficiently buried to form a trap and they were water wet. Two cores were cut: the first from 1573 to 1584 m in the Sele and Lista Formations, 15 m below the cinerites, and the second from 1929 to 1943 m in the basement rocks. No fluid samples were attempted. The well was permanently abandoned as a dry well on 8 February 1971.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
189
|
5/19/2016 12:00:00 AM
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04.11.2024
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16/5-2 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/5-2 S was drilled to appraise the southern flank of the Avaldsnes (subsequently Johan Sverdrup) discovery on the Utsira High in the North Sea. The objectives were to prove the presence and quality of Late and Middle Jurassic</span></p> <p class=MsoBodyText><span lang=EN-GB>sequences on the south flank of the Johan Sverdrup structure; to prove an oil column of 20 to 45 m; and to calibrate the seismic interpretation and the depth conversion. The well was planned to reach total depth in sediments of Triassic age at a depth of approximately 2180 m TVD RKB.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/5-2 S was spudded with the semi-submersible installation Bredford Dolphin on 28 November 2011 and drilled to TD at 2042 m (2037 m TVD) in the Late Triassic Skagerrak Formation. The well was drilled with Sea water and hi-vis pills down to 755 m and with Performadril Water Based Mud from 755 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>At 1958 m the well encountered a 9 m thick sequence of Late Jurassic Draupne Formation sandstone of excellent quality. No Middle Jurassic sediments were found. The seismic interpretation of Base Jurassic was encountered shallower than expected while the BCU was deeper than expected. This meant that the Late Jurassic Intra-Draupne Formation sandstone was penetrated below the regional free water level seen in neighbouring wells in the Johan Sverdrup Discovery. A water gradient of 1.022 g/cc was confirmed in the reservoir interval. Residual hydrocarbon shows were observed in some intervals in the conventional cores from 1959 m to 1967 m, otherwise no shows were reported from the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>Five cores were cut from 1919 m to 1974 m with good recovery. A fluid sample was acquired using the MDT tool at 1958.95 m. This contained only water without hydrocarbon traces.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 28 January 2012 as a dry well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> html> |
6720
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/5-3
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<html> <p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/5-3 was drilled on a possible southern extension of the Johan Sverdrup discovery in the North Sea. The main objective was to prove hydrocarbons in Late Jurassic Intra-Draupne Formation sandstone. In case of discovery, it was important to verify the reservoir quality, fluid property, lateral extension and communication with the Johan Sverdrup discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The location for well 16/5-3 was given a shallow gas class 1 warning in an interval between 295 and 422. A pilot hole was drilled (off location), well 16/5-U-1. No shallow gas was observed. </span></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/5-3 was spudded with the semi-submersible installation Ocean Vanguard on 20 February 2013 and drilled to TD at 1993 m in the Permian Zechstien Group. A sidetrack 16/5-3 T2 was kicked off from 1774 m in 16/5-3 and drilled as a bypass track in order to perform coring in zone of interest identified in the main wellbore. No significant problem was encountered in the operations. The well was drilled with seawater down to 916 m and with Performadril mud from 916 m to TD. The sidetrack was drilled with Performadril mud with tritium tracer.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Intra-Draupne Formation sandstone reservoir was entered at 1898 m, which was 38 m shallower than prognosed. The reservoir contained oil down to 1911 m and had a thickness of 13 m, which was 2 m thicker than prognosed. Oil shows continued down to 1914 m in the underlying Skagerrak Formation. Below 1914 m, no shows were observed. There were no hydrocarbon indications in the well above top Intra-Draupne Formation sandstones. One core was cut in the sidetrack well bore from 1895.3 to 1922.5 m (lower Åsgard Formation, Intra-Draupne Formation Sandstone and upper Skagerrak Formation). The core recovery was 100%. MDT fluid samples were taken at 1901.9 m. Oil without contamination was recovered.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 20 March 2013 as an oil appraisal.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
7123
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4/11/2017 12:00:00 AM
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04.11.2024
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16/5-4
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/5-4 was drilled on the south-western flank of the Johan Sverdrup Field on the Utsira High in the North Sea. The well was placed about 4.3 kilometres southwest of appraisal well 16/5-2 S and about 3.1 kilometres southeast of well 16/5-3. The objective of the well was to delineate the Johan Sverdrup discovery by examining the thickness, properties and depth of the reservoir, as well as determine the height of the oil column and clarify the oil-water contact in the south-western part. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/5-4 was spudded with the semi-submersible installation Bredford Dolphin on 23 August 2013 and drilled to TD at 2100 m in the Triassic Skagerrak Formation. No shallow gas was seen in the top holed including the 9 7/8" pilot hole. No significant problem was encountered in the operations. The well was drilled with seawater and hi-vis sweeps down to 701 m and with Performadril water based mud with glycols from 701 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well went directly from Cretaceous marls into Jurassic reservoir sandstones and no Draupne Formation shale was present in this location, as expected. The well encountered a 6 meters thick Intra-Draupne Formation sandstone section with top at 1930.4 m. This is thinner than predicted. The section consists of unconsolidated sandstones with excellent properties. The pressure measurements confirmed the reservoir to be in the same pressure regime as the Johan Sverdrup discovery. The well showed an oil-down-to situation and consequently no free water level was encountered. The Jurassic section is resting on Triassic sediments consisting of very fine to fine grained sandstones with minor stringers of claystones and siltstones. The only oil shows in the well were seen in the Intra Draupne Formation sandstone. These shows did not extend into the underlying Triassic rocks.</span></p> <p class=MsoBodyText><span lang=EN-GB>Two cores were cut in the interval 1920 to 1964.5 m with close 100% recovery. The core to log depth shift is -0.5 m for both cores. MDT fluid samples were taken at 1933.01 m (oil), 1943 m (water), and 1948.01 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was plugged abandoned on 28 November as an oil appraisal well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>Two EXPRO’s CaTS wireless gauge technology for long term post-abandonment monitoring of the Johan Sverdrup Field were installed at 1947.24 and 1931.7 m. The CATS gauges will measure pressure and temperature over a ca 5 years period. This is part of the planning process for an optimal recovery strategy for the discovery. No drill stem test was performed.</span></p> |
7258
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4/11/2017 12:00:00 AM
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04.11.2024
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16/5-5
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/5-5 was drilled to test the southeast extension of the 16/4-6 S Luno discovery on the Utsira High in the North Sea. The primary objective was to prove the presence of reservoir in this area, to improve the understanding of the sedimentary sequence, and to confirm the OWC at 1950 m TVD MSL found in 16/4-6 S.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/5-5 was spudded with the semi-submersible installation Bredford Dolphin on 11 November 2013 and drilled to TD at 2085 m in the Triassic Hegre Group. No significant problem was encountered in the operations. The well was drilled with seawater and hi-vis pills down to 601 m and with Aquadril mud from 601 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated a thick sequence consisting of alluvial deposits of predominantly Middle-Early Triassic age with top at 1936 m. The alluvial deposits show in general poor reservoir quality although a 25 m interval with improved quality is seen close to TD. The cored section is strongly fractured and appears to have penetrated several fault zones. The sandstones are partly filled with heavy biodegraded oil; however, in the upper part the section was too tight to establish a pressure gradient. The reservoir pressure in the water zone is close to hydrostatic pressure, 4 bar above the Luno II discovery well 16/4-6 S, indicating a barrier between these two wells.</span></p> <p class=MsoBodyText><span lang=EN-GB>Six cores were cut in succession from 1937 to 1983.8 m, covering the Triassic to Early Cretaceous (Sola Fm) unconformity in the well and the upper 45 m of the Hegre Group. All six cores should be shifted -3.09 m to match with the logs in the well. RCX fluid sample were taken at 1938.8 m (water and trace heavy oil), 1939.9 m (water and trace heavy oil), 1940 m (water and trace heavy oil), 1977 m (water and trace heavy oil), and at 2034 m (water). </span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29 December 2013 as a well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7285
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4/11/2017 12:00:00 AM
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04.11.2024
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16/5-6
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/5-6 was drilled to test the Rome Central prospect on the southeast part of the Utsira High in the North Sea. The primary objective was to test the presence of and hydrocarbon potential in the Late Jurassic Intra Draupne sandstone. The secondary target was to test the hydrocarbon potential in the underlying preserved wedge of Triassic or Paleozoic sediments.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/5-6 was spudded with the semi-submersible installation Borgland Dolphin on 22 June 2016 and drilled to TD at 2350 m in the Triassic Skagerrak Formation. No significant problem was encountered in the operations. The well was drilled with Seawater and sweeps down to 702 m, with Innovert NS oil based mud from 702 m to 2134 m, and with KCl/GEM water based mud from 2134 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/5-6 failed to prove the presence Late Jurassic Intra Draupne Formation sandstone sequence prognosed to overlie a Triassic section. Instead, the well drilled directly from a thin (6 m) Late Jurassic Draupne shale and 109 m into a tight sandstone sequence of Triassic or possibly Paleozoic age. No shows or indications of moveable hydrocarbons were observed in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. No wire line logs were run. No fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 10 July 2016 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7962
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4/25/2019 12:00:00 AM
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04.11.2024
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16/5-7
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/5-7 was drilled on the Klaff prospect on the basement high just west of the southern edge of the Johan Sverdrup field in the North Sea. The objective was to prove petroleum in graben fill of pre-Cretaceous age, with potential reservoir of Late Jurassic, Triassic or Permian age, or fractured and weathered basement.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/5-7 was spudded with the semi-submersible installation Transocean Spitsbergen on 12 June 2019 and drilled to TD at 2028 m, 112 m into basement rock. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 1128 m and with KCl/polymer/GEM mud from 1128 to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>The Jurassic section was absent. Base of the Early Cretaceous Åsgard Formation rests unconformably on fractured and weathered basement rock at 1916 m. No shows were observed on drilled cuttings from well 16/5-7. Good oil shows (with fluorescence, cut, oil odour and stains) were observed from 1918 to 1940 m in the core chips from the first three cores. The log readings in Basement are hard to interpret as the granite is rather tight. Pressure points indicate an oil gradient, but fluid samples showed that the formation was water bearing. The measured gas was very low throughout the well, with less than 1% recorded.</span></p> <p class=MsoBodyText><span lang=EN-GB>Four cores were cut in the interval 1911 to 1949 m with 86.2% overall recovery. RCX fluid samples were taken at 1926 m (water), and 1934 m (water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12 July 2019 as a well with shows.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
8762
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12/21/2021 12:00:00 AM
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04.11.2024
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16/5-8 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/5-8 S was drilled to test the Goddo prospect on the Utsira High in the North Sea. The primary objective was to prove hydrocarbons in porous/fractured basement below base Cretaceous and to verify pressure communication with the nearby Rolvsnes discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/5-8 S was spudded with the semi-submersible installation Leiv Eiriksson on 8 July 2019 and drilled to TD at 2468 m (2093 m TVD) 268 m into granitic Basement rock. No shallow gas was identified in the site survey or while drilling the well. Operations proceeded without significant problems. The well was drilled with seawater and hi-vis pills down to 196 m, with KCl/polymer mud from 196 m to 620 m, and with BaraHib ECO water-based mud from 620 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Top Basement was penetrated at 2201.7 m (1889.4 m TVD), underlying Valanginian age Åsgard Fm marls. The basement is porous and fractured with a ca 20-25 m oil column. Pressure data shows that the Goddo discovery is not in pressure communication with the Rolvsnes oil discovery. There were no oil shows outside of the hydrocarbon bearing fractured basement zone in the well.</span></p> <p class=MsoBodyText><span lang=EN-GB>Five continuous cores were cut in the interval 2192 to 2229.8 m. Recovery was 99 to 100% for all cores except core no 2 from 2201 to 2206 m, which had a recovery of 79.2%. The average core to log shift is estimated to +2.03 m with +1.76 m at the BCU /top Basement level in core no 1. Wire line FTNG fluid samples were taken at 2202.64 m (oil), 2205.38 m (oil), 2205.71 m (oil), 2246.16 m (water), and 2251.46 m (water). PVT analysis of the oil samples gave GOR around 150 Sm3/Sm3 and an oil density of ca 0.872 g/cm3.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 22 August 2019 as an oil discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
8704
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12/21/2021 12:00:00 AM
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04.11.2024
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16/6-1
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<p><b>General</b></p> <p>The 16/6-1 ("ODIN 1") is located on the Utsira High in the North Sea. The well was positioned crestally on the southern tip of a big, seismically defined, horst feature. This horst, trending N-S and sharply limited by faults on west, east and south sides, has induced a vast anticline in his Mesozoic and Tertiary overburden. The well was programmed to investigate the sedimentary section down to pre-Permian formations.</p> <p><b>Operations and results</b></p> <p>Wildcat well 16/6-1 was spudded with semi-submersible installation Ocean Viking on 7 November 1967 and drilled to TD at 2061 m in basement rock. The well was drilled with seawater down to 360 m, and with a seawater / Q'Broxin / CMC type mud from 360 m to TD.</p> <p>Gas shows (C1) were observed with a GAL 21 type chromatograph while drilling the Tertiary series, mainly in the upper part with a maximum of 12 % at 630 m, decreasing to 2-3 % below 790 m. In the Cretaceous, no gas was seen and only a very small show (0.02 %å was recorded at the top of Jurassic shale. In the Utsira Formation 28 m net sand was encountered. The sands had high porosities, but were water wet. From 2019 m to2050.5 m a very rich Draupne source rock shale with 6 % to 7 % TOC was penetrated. The sequence is immature in the well position. At 2050.5 m 4.5 m of lithic sand was found directly overlying basement. The sand is probably a basement "wash" which reflects the transition from an erosive stage to a depositional one. The lower 4 m of this sand had very good porosities (>32%) but were also water saturated. Permian and Triassic objectives were not present in the well. One core was cut in basement from 2057 to 2060.5 m (TD) with 100 % recovery. Two series of log-operations were run at 1362 m and 2060.5 m. Trouble occurred with gumbo type clay bridging the hole during the first operations and three cleaning trips were necessary. No fluid samples were attempted. The well was permanently abandoned as a dry well on 19 January 1968.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
148
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5/19/2016 12:00:00 AM
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04.11.2024
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16/7-1
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<p><b>General</b></p> <p>Wildcat well 16/7-1 is located in the Ling Depression between the Utsira High and the Danish Norwegian Basin. The main objectives were to test the hydrocarbon potential of the sedimentary section and to investigate the lithology and sequence in this portion of the North Sea basin.</p> <p><b>Operations and results</b></p> <p>Well 16/7-1 was spudded with the semi-submersible installation Ocean Traveller on 11 August 1967 and drilled to TD at 2781 m in salt of the Late Permian Zechstein Group. Initial drilling from the sea floor to 381 m was with seawater and gel without casing. Returns were to the sea floor. Below 381 m to a depth of 2150 m, a Spersene XP-20 Lignosulphonate mud with 3% to 8% diesel oil was used. From 2150 m to TD, the mud system contained salt saturated Spersene XP-20 Lignosulphonate mud with 5% to 9% diesel oil.</p> <p>After cementing the 30-inch casing at 131 m, the well was drilled to 213 m. On pulling out of the hole, it was found that the guide structure had sunk 5 m into the seabed or 2.5 m below the mud line. The ocean floor structures were retrieved and the platform was moved 30 m southwest and the well was re-spudded. The 30-inch casing was again cemented at 131 m. No abnormal drilling problems were encountered until a depth of 2150 m was reached. At this depth, high chloride and high viscosity mud indicated that salt had been encountered. The Continuous Dipmeter indicated that there was excessive natural deviation probably due to contorted bedding in the salt section. Deviation below 2225 m was calculated to increase at the rate of 1° per 15 m to a depth of 2637 m where the deviation was 27°. Extrapolating this deviation resulted in a deviation of 36° at TD. The direction of deviation at TD was 583° E. While drilling salt at 2780 m pipe stuck, and when attempting to pull free collars parted. Plug was set, and tagged at 2644 m. The hole was then logged. To avoid bad dog leg another plug was set and tagged at 2210 m. While attempting to sidetrack pipe again stuck and parted. It was then decided to abandon the hole. The pre-Zechstein section was thus not penetrated. </p> <p>The well penetrated Top Cretaceous at 1856 m and top of the Late Permian Zechstein Group at 2085 m. The Jurassic and Triassic were not present. No shows were encountered in any part of well 16/7-1. One conventional core was cut from 1793 m to 1809 m in the Lista Formation. Sidewall cores were not taken. No fluid samples were taken. The well was permanently abandoned as a dry hole on 24 September 1967.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
146
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5/19/2016 12:00:00 AM
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04.11.2024
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16/7-10
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<p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/7-10 was drilled on the Theta Prospect in the South Viking Graben in the North Sea, close to the Sleipner field. The prospect was seen as a possible extension of the 16/7-2 discovery in the Ty Formation. The main target was Ty Formation turbidite sands.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The semi-submersible installation Ocean Vanguard drilled this well. A 8 1/2" pilot hole 16/7-U-1 was drilled to 610.5 m prior to the main well due to shallow gas warning. At this depth a substantial amount of shallow gas was detected with the ROV sonar. The pilot hole was plugged back. Wildcat well 16/7-10 was spudded on 9 July 2011, 16 m away from the pilot hole. After intermediate wire line logging in the 12 1/4" section, it was not possible to get the 9 5/8" liner to section TD. A technical side-track (16/7-10 T2) was performed from the 16/7-10 well, with a kick-off point at 1916 m, and drilled to final TD at 2514 m in the Late Cretaceous Tor Formation. The well was drilled with sea water and sweeps down to 503 m, with Performadril mud from 503 m to 1151 m, and with XP-07 #14 oil based mud from 1151 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>Rocks of Quaternary, Tertiary and Cretaceous age were penetrated. The Ty Formation was encountered with Good reservoir sand at 2348.5 m (2347.5 m TVD), 35.5 m deeper than prognosed. Results of the Theta NE well showed a considerably reduced hydrocarbon column relative to prognosis (2 m gross HC bearing interval vs. 36 m expected). The GWC was found to be at 2349 m (2328 m TVD MSL), the same as encountered at 16/7-2, supporting pressure communication between the two wells. Reservoir parameters were also similar, with Ty Formation 115 m gross reservoir interval, 88 % Net to Gross and 27 % porosity. Hydrocarbon saturation was estimated to 51 %. No oil shows were reported from the well. The use of oil based mud obscured visible shows analysis below 1151 m</span></p> <p class=MsoBodyText><span lang=EN-GB>No conventional cores were cut in the well. MDT wire line fluid samples were taken in the Ty Formation at 2348.6 m (2347.6 m TVD; gas/condensate with ca 3% hydrocarbon contamination from mud) and 2383.0 m (2382 m TVD; water).</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13 September 2011 as a minor gas discovery.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6607
|
4/11/2017 12:00:00 AM
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04.11.2024
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16/7-11
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>
<p class=MsoBodyText><span lang=EN-GB>Well 16/7-11 was drilled to test the Knappen prospect on the Sleipner Terrace in the North Sea. The primary objective was to test the hydrocarbon potential in the Skagerrak Formation. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/7-11 was spudded with the semi-submersible installation Songa Trym on 12 August 2015 and drilled to TD at 2650 m in the Early Triassic Skagerrak Formation. No significant problem was encountered in the operations but shallow gas was observed at 613 and 630 m. The well was drilled with Spud mud down to 575 m, with Glydril mud from 575 to 1560 m and with EMS-4400 oil based mud from 1560 m to TD. </span></p> <p class=MsoBodyText><span lang=EN-GB>Top Skagerrak Formation was encountered at 2546 m. The Skagerrak Formation reservoir was found to be dry based on logs, gas response, and lack of hydrocarbon shows in cuttings.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut. No logs were run on wire line. No fluid sample was taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>During the plug and abandon, gas bubbles were observed migrating from the wellhead after pulling out the BOP. </span></p> <p class=MsoBodyText><span lang=EN-GB>This gas was suspected to come from the shallow gas zone at 630m MD. Total time spent for P&A operations including sealing off the gas leak was 8.4 days.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 4 September 2015 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7750
|
5/23/2017 12:00:00 AM
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04.11.2024
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16/7-2
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<p><b>General</b></p> <p>The 16/7-2 well was drilled on the western flank of the Utsira High in the North Sea. The primary objective was to test the presence of a stratigraphic trap in Paleocene sandstones. Secondary objectives were to test the Mesozoic structure for possible Triassic sands, and also to test the Zechstein carbonate and Rotliegendes sandstone plays. The well was the first to be drilled in connection with the 6th. License Round awards. </p> <p><b>Operations and results</b></p> <p>Well 16/7-2 was spudded with the semi-submersible installation Glomar Biscay II on 11 January 1982 and drilled to TD at 3146 m in Early Permian, Rotliegendes Group sediments. Drilling of the 36" and 26" holes went forth without any specific problems. While cementing the 20" casing, the cement slurry was overdisplaced. A remedial squeeze job was necessary. Problems also occurred when logging the 12 1/4" section due to tight hole. In the 8 1/2" inch section problems with the BOP choke valve/controls led to close to 9 days lost time, a major reason for the 38% non-productive time in this well. The well was drilled with seawater gel down to 171 m, and with lignite/lignosulphonate mud from 171 m to TD.</p> <p>Top Lista Formation was encountered at 2268 m and contained 9.5 m net of gas from 2292 m in thin sandstone intervals, interbedded with shales. The average porosity is 22% and average water saturation is 47% in the net sand. The Heimdal Formation sandstones were massive, of very good reservoir quality, and contained 13.5 m of net gas sand in a gross gas sand interval of 13.5 m down to the gas/water contact at 2352 m. The average porosity is 26% and average water saturation is 34%. The well was drilled on the crest of a structurally limited trap and the gas accumulation is not connected to the 15/9 Paleocene Gamma discovery. In the Jurassic, 19 m of water wet Hugin Formation sand was encountered. The Zechstein dolomites and Rotliegendes sandstones were also water wet and of poor reservoir quality. The well also penetrated a 5 m thick sequence of the Permian Kupferschiefer at 3112 m.</p> <p>Three cores were taken in the Lista and Heimdal Formations from 2300 m to 2376 m. A fourth core core was taken from 2675 m to 2693 m in the Middle Jurassic Hugin Formation. MFT fluid samples were taken at 2680.5 m (content: mud filtrate), 2313 m (mud filtrate), and 2341 m (gas condensate; single flash to stock tank conditions gave GOR = 3042 Sm3/Sm3 and liquid gravity = 48.3 deg API).</p> <p>The well was permanently abandoned on 30 March 1982 as a gas discovery.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
40
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5/19/2016 12:00:00 AM
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04.11.2024
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16/7-3
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<p><b>General</b></p>
<p>Exploration well 16/7-3 is located on the Utsira High, about ten km east of the Sleipner East field. The objective of the well was to test potential Jurassic sands on the large structure in the centre of the block.</p> <p>The well would also test the Zechstein carbonate and Rotliegendes sandstone plays in a small fault block structure.</p> <p><b>Operations and results</b></p> <p>The well was spudded with the semi-submersible installation Glomar Biscay II and drilled without incident to TD at 3141 m in the Rotliegendes Group. The well was drilled with seawater gel, adding lignite from 2150 m.</p> <p>The Cretaceous sequence consisted of the Late Cretaceous Tor and Hod chalk formations resting unconformably on a very thin Late Jurassic Draupne shale. Thirty-seven net m of good quality sand was encountered in the Jurassic Hugin Formation. The Triassic consisted of red beds with no major sand development. The Zechstein contained tight anhydritic dolomite, some vuggy dolomite, and shales, while the Rotliegendes Group had poor reservoir quality dolomite cemented sandstones, siltstones and shales. A shows on a core was recorded in the interval 2345 m to 2350.7 m in the upper part of the Jurassic Hugin Formation. Otherwise no hydrocarbons were encountered in the well. Two cores were taken in the 8 1/2" section, in the interval 2342 m to 2365.5 m in the Jurassic Hugin Formation. Forty sidewall cores were taken in the interval 2296 m to 3130 m. No fluid samples were taken. The well was permanently abandoned as dry on 28 August 1982.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
75
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5/19/2016 12:00:00 AM
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04.11.2024
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16/7-4
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<p><b>General</b></p>
<p>Well 16/7-4 is located ca 10 km southeast of the Sleipner Øst Field and 6 km east of the 15/9-15 gas discovery in the North Sea. The objective of the well was to test the presence of a structural trap in Jurassic/Triassic sandstones on the A-North Prospect in the southwest corner of Block 16/7. </p> <p><b>Operations and results</b></p> <p>Well 16/7-4 was spudded with the semi-submersible installation Glomar Biscay II on 15 October 1982 and drilled to TD at 2781 m in the Triassic Group. The well was drilled with seawater and gel all through.</p> <p>Only 1.5 m Jurassic sediments (Draupne Formation) were present in well position. The Triassic Group sandstone was encountered at 2521.5 m and held a 117.8 m gas/condensate column from top and down to 2639.3 m (-2314.3 m subsea). The gas-bearing sandstones were found interbedded with a few thin shales. The reservoir quality was best near the top of the sand, becoming gradually poorer downwards. The net gas sand was 85.4 m with 23% porosity and 36% average water saturation. No shows were reported from above or below the hydrocarbon-bearing interval in the well.</p> <p>Six conventional cores were cut from 2568 to 2681.5 m to in the Jurassic - Triassic interval. One Multi Formation Tester (MFT) fluid sample was taken at 2638.5 m. It recovered 1.2 litres of 57 deg API condensate, 1.3 Sm3 gas and 2 litres of water.</p> <p>The well was permanently abandoned on 6 December 1982 as a gas/condensate discovery.</p> <p><b>Testing</b></p> <p>Two drill stem tests were performed in the Triassic Group. </p> <p>DST 1 at 2590.5 - 2597 m flowed 199 Sm3 condensate and 385110 Sm3 gas /day through a 42/64" choke. The gas/condensate ratio was 1938 Sm3/Sm3, the oil gravity was 58 deg API, and the gas gravity was 0.791 (air = 1).</p> <p>DST 2 at 2525 - 2535 m flowed 253 Sm3 condensate and 472890 Sm3 gas /day through a 42/64" choke. The gas/condensate ratio was 1871 Sm3/Sm3, the oil gravity was 59 deg API, and the gas gravity was 0.797 (air = 1).</p> <p>Water, other than condensation of water vapour, was not produced in the two tests. The CO2 content was between 0.3 and 0.4 %. H2S was not detected.</p> |
91
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10/24/2016 12:00:00 AM
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04.11.2024
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16/7-5
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<p>Well 16/7-5 is located ca 10 km east of the Sleipner Øst field in the North Sea. The primary objective was to test potential gas bearing Jurassic/Triassic sandstones. </p> <p><b>Operations and results</b></p> <p>Wildcat well 16/7-5 was spudded with the semi-submersible installation Zapata Ugland on 2 July 1984 and drilled to TD at 2900 m in the Triassic Smith Bank Formation. Due to turning of the permanent guide base the 30" casing had to be re-landed. No other major problems occurred during drilling. The well was drilled with gel/sea water down to 170 m, and with seawater/lignosulphonate gel from 470 m to TD. </p> <p>The ?Jurassic/Triassic (Skagerrak Formation) was encountered at 2594, underlying an interpreted one-meter layer of Draupne shale. A 306 m gross / 120.5 m net (22% average porosity) sequence of sands was penetrated. No significant hydrocarbon shows were encountered while drilling the well. Electric log analysis also confirmed that the Jurassic/Triassic Sandstone (primary objective) was water bearing. RFT pressure measurements and samples suggested the possible presence of minor amount of gas in the upper part (2594 m to 2642.6 m) where the pressure gradient was lower than the water gradient (below 2662.5 m). However, the pressure readings were scattered in this interval and very much subject to interpretation.</p> <p>One core was cut from 2590 to 2603 m (2596 - 2612.5 m logger's depth) in the top of the target sands in the Skagerrak Formation. Three successful RFT fluid samples were taken. The first sample, at 2691 m, recovered "2800 cc. of light brown fluid, mainly mud filtrate and mud, no gas, no fluorescence". The second, at 2806.5 m, recovered "8600 cc. of clear medium brown fluid, mainly mud filtrate with a few cc's of gas. The fluid had no odour or taste but it had a very pale bluish white fluorescence". The third, at 2603 m, recovered "8700 cc. of none clear (turbid) fluid + few cc's of gas. The fluid had no odour or taste, but a pale bluish white fluorescence".</p> <p>The well was permanently abandoned on 3 August as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
134
|
5/19/2016 12:00:00 AM
|
04.11.2024
|
|
16/7-6
|
<p><b>General</b></p> <p>Wildcat well 16/7-6 is located ca 2 km south of the Sigyn Field. It was drilled to test the A-South prospect at Triassic level.</p> <p><b>Operations and results</b></p> <p>Well 16/7-6 was spudded with the semi-submersible installation Stena Dee on 27 June 1997 and drilled to TD at 2725 m in the Triassic Skagerrak Formation. A 36" hole was drilled from 103 - 178 m. The 30" casing was set at 176.5 m. A 9 7/8" pilot hole was drilled to 1160 m. No shallow gas was observed. The hole was opened up to 17 1/2" down to 1160 m and the 13 3/8" casing was set at 1153 m. The well was drilled with seawater down to 176.5 m and with Ancotec oil based mud from 1176.5 m to TD.</p> <p>The well encountered the Skagerrak Formation sands at 2564 m. A total of 140.5 m of these sands were drilled before the well was terminated at 2725 m. Of this, petrophysical evaluation gave 134.4 m net sand with 20.3 % average porosity. The entire reservoir was water bearing. No shows were reported from any section of the well.</p> <p>Two cores were cut from 2562 to 2626 m in the Skagerrak Formation. Seven MDT water samples were taken at 2621.6 m.</p> <p>The well was permanently abandoned on 24 July 1997 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
3067
|
7/6/2016 12:00:00 AM
|
04.11.2024
|
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16/7-7 S
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<p><b>General</b></p> <p>Wildcat well 16/7-7 S is located in the southern end of the Sleipner Terrace in the Norwegian North Sea. The primary objective of the well was to evaluate the resource potential of the eastern segment of the A-North prospect in the Triassic Skagerrak Formation. The western segment had been drilled in 1982 by well 16/7-4, which proved gas and condensate in sandstones of Jurassic/Triassic age.</p> <p><b>Operations and results</b></p> <p>Well 16/7-7 S was spudded with the semi-submersible installation Stena Dee on 20 October 1997. The well was drilled to 2745 m (2473.3 TVD SS) in the Cretaceous section. The bottom hole assembly was lost and the well was sidetracked. Well was sidetracked from 1777 m and was drilled to TD = 2994 m (2704.8 m TVD SS) in the Skagerrak Formation. The final well with sidetrack was drilled with seawater down to 1146 m and with Ancotec oil based mud from 1146 m to TD.</p> <p>The well found high-volatile oil in Intra Draupne Formation Sandstone and Skagerrak Formation sandstone, from 2763 m (2517.2 m TVD SS) down to a Free Water Level at 2860.3 m (2596.9 m TVD SS). Logs, wire line pressure measurements, drill stem tests, and shows confirmed the hydrocarbon column. There were no shows or other hydrocarbon indications reported from above or below the reservoir section</p> <p>Five cores were cut in the interval 2735.5 - 2887.5 m in the Åsgard Formation, the Intra Draupne Formation Sandstone, and the Skagerrak Formation. All cores were cut in the final sidetrack hole. No wire line fluid samples were taken.</p> <p>The well was permanently abandoned on 29 December 1997 as an oil discovery.</p> <p><b>Testing</b></p> <p>Two drill stem tests were performed. DST 1 tested the interval 2785 - 2852 m (2535.5 - 2590.2 m TVD SS) in the Skagerrak Formation. The well flowed at maximum 514 Sm3 oil/day on a 44/64" choke. The GOR was ca 517 Sm3/Sm3, the oil gravity was ca 59 deg API, and the specific gas gravity was 0.94 (air = 1). DST 2 tested the interval 2762 - 2852 m (2516.7 - 2590.2 m TVD SS), which includes the Intra Draupne Formation Sandstone in addition to the upper Skagerrak Formation. DST 2 flowed at maximum 563 Sm3 oil/day on a 44/64" choke, and the Production Logging Tool (PLT) indicated that most of the flow in this test came from the Intra Draupne Formation Sandstone. The GOR was ca 450 Sm3/Sm3, the oil gravity was ca 59 deg API, and the specific gas gravity was 0.94 (air = 1). The reservoir temperature was reported as 100 deg C in both tests.</p> |
3244
|
7/6/2016 12:00:00 AM
|
04.11.2024
|
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16/7-8 S
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<p><b>General</b></p>
<p>Wildcat well 16/7-8 S was drilled in a water depth of 79.5 m in PL072B to test the hydrocarbon potential of the Beta West prospect 3km north of the Sigyn field, 3km east of the Sleipner East Field. </p> <p>The Beta West prospect is located in the Ling Graben, south of the Utsira High, on the eastern margin of the South Viking Graben. The primary reservoir and the main target of the well were continental, fluvial sandstones (red beds) of the Skagerrak Formation with thin Upper Jurassic shallow marine sandstone, overlaying the Skagerrak Formation. The Beta West structure is defined by a 4-way dip closure.</p> <p><b>Operations and results</b></p> <p>The well was spudded with the semi-submersible installation "Deepsea Bergen" on 17 December 2002 and drilled deviated to a total depth of 2900 m MD (2645.5 mTVD) in the Triassic Skagerrak Formation. The well was drilled as a deviated well due to shallow gas concerns on the vertical well location. The well was drilled using sea water/high viscosity sweeps down to 445 m, with Glydril (KCl/Glycol WBM) from 445 m to 1319 m and Versavert OBM from 1319 m to TD. Shallow gas was expected at 234 m TVD and at 634 m TVD. Sandstones were observed in both intervals but proved to be water wet. The top of the reservoir was penetrated at 2585 m TVD, 25 m deeper than prognosed. The reservoir consists of approx. 21 m (vertical thickness) with Jurassic sandstone above the Skagerrak Formation. The base of the Skagerrak Formation was not penetrated in this well. The reservoirs proved to be water bearing without any indications of hydrocarbons.</p> <p>No wireline logs were run in this well. MWD logs were run as follows: gamma ray and resistivity in all sections from the 30" casing shoe to TD. Pressure while drilling was recorded in the 9 7/8" pilot hole and in the 8 1/2" section. Neutron and density were logged in the 8 1/2" hole. One oriented core was cut in the interval 2827 - 2874.5 m MD, but only 2.9 m out of 47.5 m were recovered. The recovered interval (2827 - 2829.9 m MD) represents the Hugin Formation. The low core recovery (6.1%) was due to jamming of the bit when the drillstring was rotated without circulation with the bit at bottom. This is not according to procedures and should be avoided. Acquisition of the orientation data proved to be trouble-free. No fluid sample was collected. No formation pressure data was measured in this well. The pore pressure evaluation is based on MWD log data and drilling parameters. A normal pore pressure gradient is estimated down to approximately 1400 m TVD RKB where an increase starts and continues through the Hordaland Group. The highest pore pressure is assumed at 2000 m TVD RKB, in the Balder Formation, with a gradient of 1.20 g/cm<sup>3</sup>. A decrease of the gradient is calculated through the Sele and Lista formations. A low gradient is assumed through the Ekofisk Formation, and a slight increase is assumed in the Cromer Knoll shale sequence. At the top of the Upper Jurassic/Skagerrak sandstone a pore pressure gradient of 1.16 g/cm<sup>3</sup> is estimated in the water filled reservoir. At TD a pore pressure of 1.14 g/cm<sup>3</sup> is assumed. No pressure points were conducted so the pore pressure in the reservoir is based on prognosis. </p> <p>The well was permanently plugged and abandoned on 19 January 2003 as a dry well. </p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
4612
|
7/6/2016 12:00:00 AM
|
04.11.2024
|
|
16/7-9
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 16/7-9 was drilled on the Norall prospect in the Ling Depression in the North Sea. The primary objective was to test the hydrocarbon potential of the Jurassic / Triassic (Skagerrak Formation).</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/9-7 was spudded with the semi-submersible installation Transocean Winner on 5 December 2010 and drilled to TD at 2665 m in the Late Triassic Smith Bank Formation. Due to shallow gas warnings a 9 7/8" pilot hole was drilled from seabed to 706 m. No shallow gas was found. No significant problem was encountered in the operations. The well was drilled with seawater and hi-vis pills in the riserless sections down to 706 m and with Glydril mud from 706 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was found to be dry. The Draupne Formation was encountered at 2466.5 m. Under Draupne, at 2500 m, the well penetrated a 15 m thick Intra Draupne Formation sandstone. This sand rested on 38 m of Triassic, Skagerrak Formation sandstone. The formations were water bearing. Minor oil shows were described in the organic rich Draupne shales from 2492 to 2500 m while traces of residual fluorescence were observed in the underlying Intra Draupne sandstone.</span></p> <p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 3 January 2011 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB> </span></p> |
6382
|
4/11/2017 12:00:00 AM
|
04.11.2024
|
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16/8-1
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<p><b>General</b></p>
<p>The well was located to test a thrust-faulted structure in a NE-SW trending sub-basin to the southeast of the Utsira High. The primary objective was the basal Late Jurassic sand. This sand was estimated to have an approximate gross thickness of 71 metres.</p> <p><b>Operations and results</b></p> <p>Wildcat well 16/8-1 was spudded with the semi-submersible installation Nordskald on 25 September 1976 and drilled to TD at 2301 m in the Triassic Smith Bank Formation. The well was drilled with seawater and gel down to 172 m and with Drispac and seawater from 172 m to TD. </p> <p>No reservoir sands were encountered in either the Paleocene or the Triassic. From 1769 m to 1820 m in the Late Cretaceous Tor and Hod Formations chalks with calculated porosities from 17% to 34% were encountered. At 2073 the well penetrated a gross thickness of 43 m of Late Jurassic Intra Draupne sand. This sand was of high porosity but water bearing. No evidence of hydrocarbons was encountered while drilling, and log analysis confirmed all intervals with significant porosity to be water bearing. Canned samples for source rock/maturity analysis by Robertson Research were collected every 100 m from 1000 m and every 30 m from 2000 m to TD. This study shows that the penetrated sections are immature. Samples from the Draupne Formation show good source characteristics with TOC from 3% to 7% and one extract from this section contained minor amounts of probably locally generated hydrocarbons. No conventional cores were cut and no fluid samples taken. The well was plugged and abandoned as a dry hole on 29 October 1976. </p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
335
|
7/6/2016 12:00:00 AM
|
04.11.2024
|
|
16/8-2
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<p><b>General</b></p>
<p>Exploration well 16/8-2 is located in the Ling Depression south of the Utsira High and North of the Danish Norwegian Basin. The primary target was Late Jurassic sandstones; secondary target was the Danian/Late Cretaceous limestones and Rotliegendes/Devonian sandstones. </p> <p><b>Operations and results</b></p> <p>Well 16/8-2 was spudded from the semi-submersible installation Sedco H on 3 April 1980 and drilled to TD at 3585 m in Late Permian Zechstein evaporites. The well was drilled with bentonite and seawater down to 542 m, with a Spersene lignosulphonate/gypsum/CMC mud from 542 m to 2275 m, and with a salt saturated Drispac polymer/XC polymer/Polysal starch mud from 2275 m to TD.</p> <p>Down to the setting of the 13 3/8" casing, the well progressed as programmed. However, the absence of the Triassic and the appearance of the Zechstein evaporites much shallower than expected caused the 9 5/8" casing to be set 474 metres higher than programmed. The drilling of the 8 1/2" hole commenced with a 1.45 SG salt saturated mud as programmed. Two runs with a turbine/Stratapac bit were made. However, on pulling out of the hole from 3519 m, tight hole was encountered and while attempting to work through this section, the drill string parted leaving 32.81 m of BHA at a depth of 3462 m. On running in with an overshot, the well was observed to be flowing. It was shut in but pressure continued to increase even after the appropriate mud weight increases had been effected. The mud weight was eventually raised to 2.03 SG creating a fine balance between sufficient fluid density and exceeding fracture pressure. The influx (thought to be from a Carnallite zone at approximately 3513 m) had an adverse effect on the mud properties causing the barite to settle out and reducing the pH to an acidic level. The magnesium and calcium sensitive Drispac polymer was replaced with the more tolerant 'XC Polymor1 to maintain the barite in suspension, and an inhibitor was added to prevent corrosion occurring. After many attempts at setting cement plugs and controlling well flow, the hole was plugged back into the 9 5/8" shoe, leaving 823 metres of drill pipe in the hole. Sidetracking was performed from 2325 m, drilling with a 1.82 SG mud until reaching 3481 m when again an influx was observed. The mud weight increased to 1.90 SG although full control of the influx was not gained until drilling beneath the zone.</p> <p>Due to the uncertainty attached to the pore pressures in the Rotliegendes, it was decided not to drill into it with this high mud weight. The programme was therefore amended and the 7" liner was set at the base of the Zechstein with the intention of reducing the mud weight before drilling ahead. However due to further problems with cleaning out the 7" liner a decision was made to plug and abandon the well.</p> <p>The well penetrated a relatively complete Tertiary and Cretaceous section including the secondary target Ekofisk, Tor, and Hod formations. No shows were observed in the chalk formations. The primary target Late Jurassic was also encountered but proved to consist of 51 m Draupne and 13.5 m Heather Formation shales intercalated by only stringers of sand. One of these, a thin Oxfordian sand was penetrated from 2247.5 to 2250 m, average porosity in this bed was approximately 30%. The Heather Formation was found unconformably on the Late Permian Zechstein salt. The further target of the Rotliegendes/Devonian sandstone was not accomplished due to the technical problems described above. Geochemical analyses showed that the only significant source rock was the Draupne Formation which had excellent potential for oil, but immature in the well location (%Ro in the range 0.45 - 0.50). No cores were cut and no fluid samples were taken. The well was permanently abandoned as dry on 13 August 1980.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
234
|
7/6/2016 12:00:00 AM
|
04.11.2024
|
|
16/8-3 S
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>The 16/8-3 S Lupin well was drilled in the Ling depression in the North Sea. The Lupin prospect was defined by a tilted horst block with several small internal rotated fault blocks of Permian age. The objective was to prove a commercial accumulation of hydrocarbons in Permian Rotliegendes sandstones. </span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/8-3 S was spudded with the semi-submersible installation Songa Trym on 11 March 2013 and drilled to TD at 3261 m (3243 m TVD) in the Permian Rotliegendes Group. A 9 7/8” pilot hole was drilled to 827 m to check for shallow gas. No shallow gas was seen. The well was drilled with spud mud down to 940 m, with Performadril water based mud from 940 m to 1765 m, and with XP-07 oil based mud from 1765 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well penetrated rocks of Quaternary, Neogene, Paleogene, Cretaceous, Jurassic, and Permian age. The top of the expected main reservoir, the Rotliegendes Group was picked at 3015 m (2998.4 m TVD), 99 m TVD deeper than prognosed. There were no indication of hydrocarbons in the well. </span></p> <p class=MsoBodyText><span lang=EN-GB>One core (from 2574.5 m to 2584 m) was cut in the shale of the Late Jurassic Draupne Formation in the 12 1/4” section, for rock mechanical studies. No wire line fluid samples were taken.</span></p> <p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1 May 2013 as a dry well.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p> |
7115
|
4/11/2017 12:00:00 AM
|
04.11.2024
|
|
16/9-1
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<p><b>General</b></p>
<p>Well 16/9-1 is located in the Ling Depression between the Utsira High and the Danish Norwegian Basin. A relatively thick Jurassic/Triassic section was anticipated and was expected to contain porous sandstones. The main objectives were to test the oil and gas potential and investigate the lithology of the sedimentary section on an anticlinal structure between salt dome features. </p> <p><b>Operations and results</b></p> <p>Wildcat well 16/9-1 was spudded with the vessel Glomar Grand Isle on 8 May 1968 and drilled to TD at 3654 m in salt of the Permian Zechstein Group. Drilling operations were normal to 3654 m (TD), while drilling at this depth on 24 June 1968, a sudden storm struck the Glomar Grand Isle causing the drill pipe to part and drop in the hole. The top of the fish was at 859 m. A jet cutter was run, the drill pipe was cut at 3321 m and recovered on 28 June. Attempts to recover the remaining fish failed and on 7-8 July final logs were run to the top of the fish at 3321 feet. Following final logs, the well was prepared for abandonment. Initial drilling from the sea floor to 402 m was with seawater and gel. Returns were to the sea floor. Below 402 m to 3395 m, the mud system consisted of a sea water/Spersene/XP-20 Salinex mud with 5% to 8% diesel oil. From 3395 to TD a salt saturated mud system was used.</p> <p>The Danian and Cretaceous carbonates had no shows. The remaining sections penetrated by the well were predominantly clays, shales or evaporites. The well penetrated a 169 m Jurassic section and a 735 m thick Triassic sequence before entering the Late Permian Zechstein Group at 3199 m. Some porous sandstones were present in the Jurassic and Triassic on structure but these had no hydrocarbon shows and were indicated to be water bearing on the electric logs. Two conventional cores were cut, one from 1227 m to 1245 m in the Tertiary Hordaland Group and one from 2396 m to 2404.5 m in the Middle Jurassic Vestland Group. No fluid samples were taken in the well. The well was permanently abandoned on 12 July 1968 as a dry well.</p> <p><b>Testing</b></p> <p>No drill stem test was performed</p> |
151
|
5/19/2016 12:00:00 AM
|
04.11.2024
|
|
17/10-1
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<p><b>General</b></p> <p>Well 17/10-1 is situated in the Norwegian- Danish Basin near the western margin of the Sele High, which is a shallow basement feature. The structure on which the well was drilled is a very gentle anticline in an area with prominent salt walls. The objective of the 17/10-1 well was to test the Mesozoic section.</p> <p><b>Operations and results</b></p> <p>Well 17/10-1 was spudded with the semi-submersible installation Sedneth I and drilled to TD at 3590 m in the Triassic Smith Bank Formation. The hole was drilled with a 18 1/2" bit to 160 m, but during enlarging with a 36" hole opener the temporary guide base sank 2.5 m into the seabed and tilted, due to heavy washing out. This made it impossible to enter the hole and the rig was moved 30 m NNE of its original position where a new hole was spudded. An 18 1/2" hole was drilled to 430 m. Seawater was used as drilling fluid and the returns were to the sea floor. Thereafter the mud system was converted to a Spersene/XP-20 seawater mud. At 3367 m the mud was converted to a salt saturated system since this was below the prognosed depth for top Zechstein salt. </p> <p>The chief reservoir zone of interest was the massive Jurassic/Triassic sandstone (Gassum and Skagerrak Formations) from 2682 m to 3405 m. This section had porosities mainly between 20 % and 25 % and was entirely water bearing. There is a major unconformity on top of these sands to the overlying Late Jurassic shales. The claystone section from about 2651 m to 2682 m (Tau and Egersund Formations) had an exceptionally high gamma ray with readings up to 300 API units. Resistivities varied between 2 and 7 ohm/m compared with 1 - 1.5 ohm/m for the overlying shales. Cuttings from this section were very carbonaceous and were bleeding gas when first examined. Chromatograph readings were up to 700 ppm C1 with small quantities of C2, C3, and C4. Above and below this section the C1 reading was about 300 ppm. Nearly 700 m of Lower Cretaceous shales were deposited in the area, and they are overlain by about 350 m of limestones. From the early Tertiary on wards clastic deposition prevailed, and fine grained sediments were deposited in a subsiding basin. Organic geochemical analyses showed oil-window maturity from a depth of ca 3000 m to TD.</p> <p>The well was permanently abandoned on 24 March 1969 as dry hole.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
161
|
5/19/2016 12:00:00 AM
|
04.11.2024
|
|
17/11-1
|
<p><b>General</b></p> <p>Well 17/11-1 was drilled close to the western edge of the Sele High in the North Sea. The original objective to test the Tertiary and Mesozoic sequences, was extended to penetrate the Zechstein salt and investigate the underlying formations. This latter could not be reached due to drilling difficulties in the salt.</p> <p><b>Operations and results</b></p> <p>Wildcat well 17/11-1 was spudded with the jack-up installation Orion on 24 May 1968 and drilled to TD at 3269 m in the Late Permian Zechstein Group. When logging at 1173 m the logging tool got stuck in the "gumbo" section and an inflow of 2 - 5 bbl/hr of salt water occurred. Several of the tools failed to reach the bottom, among these the gamma-ray/sonic logging tool. Therefore a laterolog is included on the final composite log in the interval 1017-1158 m. The pipe stuck when drilling in potassium and magnesium salt (carnallite). Efforts to free the pipe by jarring and spotting Pipelax were unsuccessful. After working the stuck pipe for 19 hours the drill string parted, leaving a bit and junk sub in the hole. An unsuccessful attempt was made to jar the fish free. It was then decided that further efforts to drill to the base of the salt could not be justified. The well was drilled with seawater down to 166 m, a Spersene/XP-20 mud system from 166 m to 2539 m, converting to a salt-saturated mud from 2539 m through salt to TD.</p> <p>Shetland Group chalk (Ekofisk Formation) came in at 1020 m. Top Cretaceous is set at 1040 m where Tor and Hod chalks extend down to 1447 m. Porosities in the chalks were estimated between 15 % to 25%. At 1447 m 63 m of Ran Sandstone Units were penetrated. The remaining Early Cretaceous consisted of mudstones. The Boknfjord Group was encountered at 2083 m, with shales extending down to 2211 m. These shales rest directly on Triassic sediments. The Skagerrak Formation from 2211 m to 2315 m consisted of claystone with sand and siltsone stringers. The sandstone stringers were generally less than 2 m thick with 20 - 30 % estimated porosity. The Smith Bank Formation is set at 2315 m to 2517 m. From 2517 m to 2538 m anhydrite was present. Below 2538 m massive salt is shown on the logs with occasional beds of anhydrite and claystone. Between 3205 m and 3269 low density beds indicate carnallite interbedded with the normal halite. There were no hydrocarbon indications in the well. </p> <p>Conventional cores were not cut. A total of 41 sidewall cores were taken from 427 m to 3226 m. No fluid samples were taken.</p> <p>The well was permanently abandoned on 30 June 1968 as dry hole.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
906
|
7/6/2016 12:00:00 AM
|
04.11.2024
|
|
17/11-2
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<p><b>General</b></p> <p>The prospect lay in the Egersund Basin West of Phillips' marginal Bream and Brisling discoveries. Well 17/11-2 was located to penetrate Middle Jurassic/Triassic sands on the west flank of a NNE-SSW piercement salt wall. A pair of prominent west-dipping growth faults marks the western edge of the salt wall. </p> <p>The well is reference well for the Åsgard Formation and Ran sandstone units.</p> <p><b>Operations and results</b></p> <p>Wildcat well 17/11-2 was spudded with the semi-submersible installation Chris Chenery on 12 April 1976 and drilled to TD at 2644 m in the Triassic sediments. The well was drilled without significant problems with bentonite/seawater spud mud down to 436 m and with Lime/PAC (Drispac)/seawater from 436 m to TD.</p> <p>Top chalk was picked at 1323 m. Dipmeter evidence indicated several faults within the Early Cretaceous sequence, at 2025 m, 2244 m and 2382 m. Apart from minor gas shows while drilling in the Early Cretaceous/Late Jurassic shales, no hydrocarbon indications (shows and logs) were seen in the well. Dark grey to black carbonaceous Kimmeridgian shales were penetrated from 2495 m to 2521 m. The top of the target ?Triassic sandstone at 2521 m was marked by a sudden increase in penetration rate and sand grains in the cuttings. A total of 35 m net sand with 17 - 30 % porosity was evaluated, the thickest single sand unit was 7.5 m. One conventional core was cut from 2532.7m to 2540.4 m. No fluid samples were taken.</p> <p>The well was permanently abandoned on 24 March 1969 as dry hole.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
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04.11.2024
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17/12-1
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<p><b>General</b></p>
<p>Exploration well 17/12-1 is located on the northern margin of the Egersund Basin in the North Sea, towards the Åsta Graben. Its primary target was Jurassic sands (Bream prospect) with estimated top at 2161 m (7090 feet) and with 61 m (200 feet) thickness. Sand developments within the Early Cretaceous and Triassic sections were regarded as secondary objectives. Planned TD was 8 m (25 feet) into the Zechstein salt.</p> <p><b>Operations and results</b></p> <p>Well 17/12-1 was spudded with the 3 leg jack-up installation Mærsk Explorer on 27 October 1971 and drilled to TD at 458 m in the 26" section where it was suspended on 1 November for later re-entry with a different rig, Ocean Viking.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
339
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7/6/2016 12:00:00 AM
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04.11.2024
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17/12-1 R
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<p><b>General</b></p>
<p>Exploration well 17/12-1R was drilled on the northern margin of the Egersund Basin in the North Sea, towards the Åsta Graben. Its primary target was Jurassic sands with estimated top at 2161 m (7090 feet) and with 61 m (200 feet) thickness. Sand developments within the Early Cretaceous and Triassic sections were regarded as secondary objectives. Planned TD was 8 m (25 feet) into the Zechstein salt.</p> <p>The top hole down to TD in the 26" section at 458 m, well 17/12-1, had been spudded and drilled the year before by the jack-up installation Mærsk Explorer.</p> <p>Well 17/12-1R is Reference Well for the Egersund Formation.</p> <p><b>Operations and results</b></p> <p>Well 17/12-1 was re-entered (17/12-1R) with the semi-submersible installation Ocean Viking on 14 March 1972 and drilled to TD at 4298 m, 165 m into the Late Permian Zechstein Formation. The well bore was drilled water based with a 3 % - 6 % diesel addition.</p> <p>Top of the primary reservoir target was encountered in the Middle Jurassic at 2292 m. The reservoir section contained several sands separated by mudstone beds. The two uppermost sands in the Sandnes Formation were water wet. The next two sands below, in the Bryne Formation, yielded 162 Sm3 oil/day on a six hours test. The tests indicated an OWC between DST 1 and DST 7, i.e between 2337.2 m and 2344 m. No sands were encountered in the Early Cretaceous and sand development within the Triassic was limited to thin, fine to course grained, continental-type clastic beds. No conventional cores were cut and no fluid samples were taken on wire line. Twenty-six sidewall cores were recovered in the interval 1371 m to 2382 m.</p> <p>The well was permanently abandoned on 21 June 1972 as an oil discovery.</p> <p><b>Testing</b></p> <p>Three out of 7 DST's produced oil and gas to surface. </p> <p>DST 1 perforated the interval 2337.2 m to 2341.4 m and produced 141 Sm3 oil /day on a 12/64" choke. GOR was 20.5 Sm3/Sm3 and oil gravity was 29 deg API. </p> <p>DST 2 perforated the interval 2316.4 m to 2325.0 m and produced 80 Sm3 oil /day on a 1 1/2" choke. GOR was 48 Sm3/Sm3 and oil gravity was 34.1 deg API. </p> <p>DST 5 and DST 6 perforated the intervals 2316.4m to 2325 m, 2331.7 m to 2332.9 m, and 2337.2 m to 2341.4 m. After acid treatment DST 5 was run with full water cushion. This test did not produce. DST 6 was run without water cushion, and after clean-up flow this test produced 162 Sm3 oil/day through an 8/64" choke based on a 6 hrs flow. GOR was Sm3/Sm3 and oil gravity was 32.4 deg API.</p> <p>DST 3 (2308.6 m to 2314.7 m) and DST 4 (2295.1 m to 2304.3) in the two uppermost sands did not produce hydrocarbons. DST 7 perforated the interval from 2344 m to 2347.9 m and did not produce hydrocarbons.</p> < |
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7/6/2016 12:00:00 AM
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04.11.2024
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17/12-2
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<p><b>General</b></p>
<p>Well 17/12-2 is located on the northwestern margin of the Egersund Basin in the North Sea, ca 14 km southwest of the 17/12-1R Discovery. The primary objective was to test Middle Jurassic and/or Triassic sands. Both had been found present in the 17/12-1R well where the Middle Jurassic sand was oil-bearing (Bream Discovery). The Triassic sands could be oil-bearing, especially if overlain by Jurassic shale. A secondary objective was seen in the Late Cretaceous limestones. Planned TD was at 3658 m (12000 ft) or 100 m into Zechstein salt.</p> <p><b>Operations and results</b></p> <p>Wildcat well 17/12-2 was spudded with Ocean Viking on 31 August 1973 and drilled to TD at 2334 m in Devonian sand. </p> <p>No shows were present in the Late Cretaceous Limestone. An oil-bearing Jurassic sand 13 m thick (7 m net pay) was encountered at 2157 m. The Triassic was absent and the Jurassic Sandnes and Bryne Formations rested directly on a 50 m thick layer of Permian salt at 2243 m. Below the salt was a 7 m thick Rotliegendes sequence. Sandstone of possible Devonian age was encountered at 2300 m. This remnant Paleozoic feature caused the well to be terminated higher than originally anticipated.</p> <p>One conventional core was cut at TD from 2330.8 m to 2333.9 m. No wire line fluid samples were taken.</p> <p>The well was permanently abandoned on 9 October 1973 as an oil Discovery.</p> <p><b>Testing</b></p> <p>Two drill stem tests were carried out. DST1 from 2166 m to 2169 m produced 16 m3 water cushion and 1 m3 oil. After the final flow period water cushion and formation fluid was reversed out. DST2 from 2157 m to 2162 m produced at maximum 366 m3 oil and 31800 m3 gas / day. Gas-oil ratio was 87 m3/m3 and oil gravity was 27.9 °API. </p> |
340
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7/6/2016 12:00:00 AM
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04.11.2024
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17/12-3
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<p><b>General</b></p>
<p>Well 17/12-3 is located on the northern margin of the Egersund Basin in the North Sea, ca 3 km west of the 17/12-1R Bream Discovery well. The Bream structure is a domal (salt-induced) anticline. The pay zone is the Middle Jurassic sands at a sub-sea depth of 2377 m (7800 feet). The 17/12-1R well was drilled on the crest of the Bream structure. Here Late Jurassic black marine shales with excellent source rock potential overlie a 156 m thick Early - Middle Jurassic sequence of interbedded sands and shales in which net sand thickness totals 38 m. Two 8 m thick sands near the top of the Middle Jurassic section tested oil. The Upper sand was oil saturated and the lower sand contained an oil/water contact between 2337.2 m and 2344 m (2310.4 m and 2317 m MSL). Two overlying sands, however, contained only water, which indicates that individual sands possess independent hydrodynamic characteristics and, therefore, probably are lenticular and laterally discontinuous. It was expected that on the flank of the structure potential reservoir sands would be thicker, and additional sands would be encountered. </p> <p>Hence, primary objective was Middle Jurassic sands. Estimated top and thickness of the sand was 2313 m (7590 ft) and 91 m (300 ft), respectively. Planned TD was at 2591 m (8500 ft), 120 m into Triassic sediments</p> <p><b>Operations and results</b></p> <p>Wildcat well 17/12-3 was spudded with the semi-submersible installation Nortrym on 12 December 1979. Due to technical problems it was re-spudded 19 December. The well was then drilled without significant problems to TD at 2730 m in m in the Triassic Skagerrak Formation. </p> <p>Top Cretaceous (Tor Formation) came inn at 817 m, 28 m deeper than prognosed. The target Middle Jurassic reservoir sand (Sandnes and Bryne Formations) came in at 2370 m (2345 m MSL), which was 57 m deep to prognosis and ca 30 m MSL deeper than the OWC indicated by the DST's in 17/12-1R. No significant shows were encountered in the well other than in a bituminous shale at 2236 m (Tau Formation). Sidewall cores and RFT results from the sand section were not encouraging and no testing program was undertaken. Organic geochemical analyses show moderate to good source rock potential in the Sauda Formation, with the best properties towards the base. Excellent source potential was found in the Tau Formation with TOC typically around 6 % and Hydrogen Index between 500 and 600 mg HC/ g TOC. Below this depth shales and coals in the Sandnes and Bryne formation also show good source potential. Based on the vitrinite reflectance and rock-eval Tmax data the well is immature, possibly early mature (Ro = 0.5 %) at TD of the well. </p> <p>No conventional core was cut. Sidewall cores were taken from 2225 m to 2701 m. The RFT tool was run in the interval 2373 m to 2678 m. One RFT fluid sample was taken at 2373 m and another at 2687 m. Both recovered water.</p> <p>The well was permanently abandoned on 3 February 1980 as a dry hole.</p> <p><b>Testing</b></p> <p>No drill stem test was performed.</p> |
341
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7/6/2016 12:00:00 AM
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04.11.2024
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17/12-4
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<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 17/12-4 was drilled on a crestal location on the 17/12-1 R Bream Discovery in the north-western part of the Egersund Basin in the North Sea. The Bream discovery well, 17/12-1R was drilled in 1972 by Phillips Petroleum. Two more wells (17/12-2 (Brisling oil discovery) and 17/12-3 (dry)) have previously been drilled by Phillips Petroleum on the 17/12 block during the 1970's and early 1980's. Oil was also found in the nearby 18/10-1 well. The primary objectives of all these wells were the Middle Jurassic fluvio-deltaic Bryne Formation sandstones. </span></p> <p class=MsoBodyText><span lang=EN-GB>The purpose of the 17/12-4 well was to investigate the hydrocarbon potential in reservoirs up dip of the discovery well, in order to make decisions regarding a future development of the Bream Discovery. Planned TD of the well was into the Bryne Formation, at approximately 2440 m TVD MSL.</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p> <p class=MsoBodyText><span lang=EN-GB>Well 17/12-4 was spudded with the semi-submersible installation West Alpha on 17 June 2009 and drilled to TD at 2470 m in the Triassic Skagerrak Formation. Drilling proceeded without significant technical problems. The well was drilled with spud mud down to 1212 m and with Versatec DW oil based mud from 1212 m to TD.</span></p> <p class=MsoBodyText><span lang=EN-GB>The Vestland Group, Sandnes Formation came in at 2276.5 m, 5.5 m deep to prognosis, while top Bryne Formation was picked at the first coal at 2297.8 m, 10.8 m deep to prognosis. The Sandnes Formation contained some good quality sands with average porosity of approximately 23%, but was water-bearing with only few and weak shows. The Bryne Formation contained several sands of good quality, and was oil-bearing down to a common OWC at 2334.5 m (2316.5 m TVD MSL). Below the main OWC there were further oil bearing sands with possibly three OWC's, but these sands were too thin to provide conclusive pressure data. No shows or other hydrocarbon indications were recorded above or below the Vestland Group.</span></p> <p class=MsoBodyText><span lang=EN-GB>Pressure data was obtained through Sandnes water bearing sands, and Bryne hydrocarbon and water bearing sands. Two cores were cut, beginning from just above the Sandnes Formation and continuing through to below the Bryne OWC. MDT water and oil samples were taken from main water and hydrocarbon bearing sands in the Sandnes Formation at 2284.81m (water), and in the Bryne Formation at 2308.24 m (oil), 2312.99 m (oil), 2331.00 m (oil), 2331.02 m (oil), 2358.00 m (water), and at 2379.01 m (oil).</span></p> <p class=MsoBodyText><span lang=EN-GB>The 17/12-4 well bore was plugged back to 13 3/8 casing shoe for sidetracking on 10 July 2009. After sidetracking the well was permanently abandoned on 27 August 2009 as an oil appraisal well</span></p> <p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p> <p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p> |
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4/11/2017 12:00:00 AM
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04.11.2024
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