Wellbore: 31/2-3 - Factpages - Norwegian Offshore Directorate

General information

General information
Attribute	Value
Wellbore name Official name of wellbore based on Norwegian Offshore Directorate guidelines for designation of wells and wellbores.	31/2-3
Type Wellbore type. Legal values: EXPLORATION, DEVELOPMENT, OTHER (see 'Purpose' for more information)	EXPLORATION
Purpose Final classification of the wellbore. Legal values for exploration wellbores: WILDCAT, APPRAISAL, WILDCAT-CCS, APPRAISAL-CCS. Legal values for development wellbores: OBSERVATION, PRODUCTION, INJECTION, INJECTION-CCS, OBSERVATION-CCS. Legal values for other wellbores: SOIL DRILLING (drilling in connection with track surveys and other subsurface surveys to investigate the soil conditions prior to placement of facilities), SHALLOW GAS (drilling to investigate shallow gas before the first 'real' drilling on the location), PILOT (drilling to investigate the geology and fluid connectors for location of the main wellbore), SCIENTIFIC (drilling according to Law of Scientific research and exploration), STRATIGRAPHIC (driling according to Law of Petroleum activities §2-1).	APPRAISAL
Status Status for the wellbore. Legal values are: BLOWOUT: A blowout has occurred in the well. CLOSED: A development wellbore that has been closed in a shorter or longer periode. Also applies to development wellbores where drilling is completed, but production/injection has not yet been reported. DRILLING: The well is in the drilling phase - can be active drilling, logging, testing or plugging, JUNKED: The drilling operation has been terminated due to technical problems. P&A: Exploration: The well is plugged and abandoned, and can not be reentered for further use. Development wells: The production/injection from/to the well is stopped and the well is plugged. The wellhead is removed or else made unavailable for further well operations. PLUGGED: The wellbore has been plugged, but the upper parts of the wellbore can be re-used. A sidetrack might be drilled at a later stage. PRODUCING: It was produced from the wellbore at the time of the operators last monthly report to the Norwegian Offshore Directorate. INJECTING: It was injected to the wellbore at the time of the operators last monthly report to the Norwegian Offshore Directorate. PREDRILLED: The upper part of the well has been drilled, usually as part of a batch-drilling campaign covering several wellbores. RE-CLASS TO DEV: Exploration wellbore that is reclassified to a development wellbore. RE-CLASS TO TEST: Exploration wellbore that is reclassified to test production. SUSPENDED: The drilling operation in the wellbore has been temporarily stopped. The current plan is to continue drilling later on.	P&A
Factmaps in new window	link to map
Main area Name of the area on the Norwegian Continental Shelf where the wellbore is located. Legal values: BARENTS SEA, NORWEGIAN SEA, NORTH SEA.	NORTH SEA
Field Name of the field the wellbore is related to.	TROLL
Discovery Name of the discovery the wellbore is related to.	31/2-1 (Troll Vest)
Well name Official name of the parent well for the wellbore based on Norwegian Offshore Directorate guidelines for designation of wells and wellbores.	31/2-3
Seismic location Position of spud location on seismic survey lines. SP: shotpoint.	62-4421 SP.175
Production licence Official designation of the production licence the wellbore was drilled or planned to be drilled from ( well head posistion).	054
Drilling operator Name of the licensee starting the drilling operation on behalf of the active production license (well head position). This will usually equal the operator of the production license.	A/S Norske Shell
Drill permit The drilling permit number together with the version of the drilling permit as stated in the drilling permit granted by the Norwegian Offshore Directorate.	247-L
Drilling facility Norwegian Offshore Directorate's name of the facility which the wellbore was drilled from.	BORGNY DOLPHIN
Drilling days Number of days from wellbore entry to wellbore completion.	115
Entered date The date when he wellbore was spudded. For sidetracks: The date when new formation was drilled by kicking off from the mother-wellbore,	28.03.1980
Completed date Exploration wellbores from moveable facilities: For floating facilities - date when anchor handling is started. For jackups - date the jacking-down started. Exploration wellbores from fixed facilities and all development wellbores: Date when the wellbore is at total depth, and last casing, liner or screen is set. In case of immediate plugging of the wellbore, completed date equals the date the last plug i set in the wellbore. Date when the wellbore is at total depth, and last casing, liner or screen is set. In case of immediate plugging of the wellbore, completed date equals the date the last plug i set in the wellbore.	20.07.1980
Release date Date when raw data which has been reported to the authorities from the wellbore is not confidential any longer. Normally 2 years after finishing the drilling. May be earlier if the area of the production license is relinquished.	20.07.1982
Publication date Date quality control of the wellbore information was completed, so it can be published on the internet as a 'Well Data Summary Sheet' wellbore with more information available than other wellbores.	15.02.2006
Purpose - planned Pre-drill purpose of the wellbore. Legal values for exploration wellbores: WILDCAT, APPRAISAL, WILDCAT-CCS, APPRAISAL-CCS. Example of legal values for development wellbores: OBSERVATION, PRODUCTION, INJECTION.	APPRAISAL
Reentry Status whether the wellbore has been re-entered (YES) or not (NO). Re-entered wellbores are not included in the count when wellbores are presented in statistical overviews.	NO
Content For exploration wellbores, status of discovery. Legal values: DRY, SHOWS (trace amounts of hydrocarbons), GAS, GAS/CONDENSATE, OIL or OIL/GAS. SHOWS (GAS SHOWS, OIL SHOWS or OIL/GAS SHOWS) are detected as fluorescent cut (organic extract), petroleum odour, or visual stain on cuttings or cores, or as increased gas reading on the mud-loggers gas detection equipment. Legal values for WILDCAT-CCS and APPRAISAL-CCS: WATER For development wellbores, type of produced/injected fluid. Legal values: WATER, CUTTINGS, NOT AVAILABLE, OIL, GAS/CONDENSATE, OIL/GAS, CO2, GAS, WATER/GAS, NOT APPLICABLE.	OIL/GAS
Discovery wellbore Indicator which tells if the wellbore made a new discovery. Legal values: YES, NO. Prior to press-release or other information regarding drilling results, the indicator will be “NO” as a default.	NO
1st level with HC, age Age of lithostratigraphic unit, 1st level, where hydrocarbons were encountered. Examples of legal values: CRETACEOUS, EARLY CRETACEOUS, LATE JURASSIC, EOCENE. See also Norwegian Offshore Directorate bulletins.	LATE JURASSIC
1st level with HC, formation Name of lithostartigraphic unit, 1st level, where hydrocarbons were encountered. Shown only for released wells. Examples of legal values: BASEMENT, COOK FM, EKOFISK FM, HEIMDAL FM, SANDNES FM, SOGNEFJORD FM, TARBERT FM, BRENT GP. See also Norwegian Offshore Directorate bulletins.	SOGNEFJORD FM
2nd level with HC, age Age of lithostratigraphic unit, 2nd level, where hydrocarbons were encountered. Examples of legal values: CRETACEOUS, EARLY CRETACEOUS, LATE JURASSIC, EOCENE.	MIDDLE JURASSIC
2nd level with HC, formation Name of lithostartigraphic unit, 2nd level, where hydrocarbons were encountered. Shown only for released wells. Examples of legal values: BASEMENT, COOK FM, EKOFISK FM, HEIMDAL FM, SANDNES FM, SOGNEFJORD FM, TARBERT FM, BRENT GP.	FENSFJORD FM
Kelly bushing elevation [m] Elevation of the rotary kelly bushing (RKB) above mean sea level.	25.0
Water depth [m] Depth in metres betweem mean sea level and sea floor.	334.0
Total depth (MD) [m RKB] Total measured length of wellbore from kelly bushing to total depth (driller's depth).	2601.0
Final vertical depth (TVD) [m RKB] Vertical elevation from total depth to kelly bushing. Shown only for released wells. Referred to as true vertical depth (TVD).	2600.0
Maximum inclination [°] Maximum deviation, in degrees, from a vertical well path.Shown only for released wells.	2.65
Bottom hole temperature [°C] Estimated temperature at final total depth of the wellbore. Shown only for released wells. See discription.	73
Oldest penetrated age Age (according to Geologic Time Scale 2004 by F. M. Gradstein, et al. (2004)) of the oldest penetrated formation. May differ from age at TD for example in deviated wellbores. Examples of legal values: CRETACEOUS, EARLY CRETACEOUS, LATE JURASSIC, EARLY PERMIAN, EARLY TRIASSIC, EOCENE.	LATE TRIASSIC
Oldest penetrated formation Name of the oldest lithostratigraphic unit penetrated by the wellbore. Shown only for released wells. In most wellbores this is formation or group at total depth. May differ from formation or group at TD for example in wellbores drilled with high deviation or through faults. Examples of legal values: AMUNDSEN FM, BALDER FM, BASEMENT, BLODØKS FM, BRYNE FM, BURTON FM, COOK FM, DRAKE FM, DRAUPNE FM, EKOFISK FM, DUNLIN GP.	HEGRE GP
Geodetic datum Reference system for coordinates. Example of legal values: ED50.	ED50
NS degrees Geographic coordinate of the wellhead, north-south degrees.	60° 50' 27.84'' N
EW degrees Geographic coordinate of the wellhead, east-west degrees.	3° 35' 10.82'' E
NS UTM [m] Universal Transverse Mercator coordinate of the wellhead, north-south.	6745386.82
EW UTM [m] Universal Transverse Mercator coordinate of the wellhead, east-west.	531872.26
UTM zone Universal Transverse Mercator zone. Examples of legal values: 31, 32, 33, 34.	31
NPDID wellbore Norwegian Offshore Directorate's unique id for the wellbore.	236

Well 31/2-3 was drilled in the Troll West area, approximately 8 km NNE of the Troll Discovery well 31/2-1. The well was drilled to appraise the Troll Discovery. It should evaluate reservoir parameters along the axis of maximum gross hydrocarbon column; prove maximum hydrocarbon reserves in the major northern fault block; confirm the significance of the seismic flatspot as a direct hydrocarbon indicator; further assess the significance of the oil shows found in 31/2-1; and evaluate the influence of earlier Kimmerian fault movements on reservoir characteristics.

Operations and results

Appraisal well 31/2-3 was spudded with the semi-submersible installation Borgny Dolphin on 28 March and drilled to TD at 2601 m in Late Triassic sediments in the Statfjord Formation. Drilling took 115 days. The reason for the long drilling period was safety inspection of the rig as a result of the "Alexander Kielland" accident and a strike amongst the Norwegian rig crew. The well was drilled with bentonite and seawater down to 816 m and with a gypsum/lignosulphonate mud from 816 m to TD.

No potential reservoir zones were encountered above top Jurassic. The well confirmed that the Late Jurassic sandstone reservoir encountered in wells 31/2-1 and 2 was well developed also in this more northerly part of the structure. A gross gas column of 189 m was penetrated with top at 1384 m. The uppermost 120 m was in a good clean sand (Sognefjord Formation) while the lower part of the gas column was in a micaceous and poor reservoir sand (Heather and Fensfjord Formations). Below the gas a 12 m thick oil zone was encountered, the same thickness and at the same level as in well 31/2-2. In this well however, the oil was in a very micaceous and poorly developed reservoir. The reservoir was uncomformably overlain by Palaeocene claystones, which thus act as an effective seal for the reservoir. Below the OWC at 1585 no moveable hydrocarbons were seen in the well, but shows continued down to 1612 m and isolated shows were seen at 1630 m and at 1638 m.

The seismic Flatspot did coincide with the base of the gas column in well 31/2-3, supporting that the Flatspot indeed is a direct hydrocarbon indicator over the entire prospect.

Coring was performed in the Middle to Late Jurassic interval from 1412 m to 1645.5 m. Twenty-one cores with a total recovery of 194.4 m (84%) were cut. Coring started approximately 28 m below the top reservoir and continued well below the hydrocarbon/water contact. Prior to the full scale production test programme, a series of runs were made with the Schlumberger Repeat Formation Tester (RFT). A total of 10 RFT runs were made. The first run indicated pressure gradients very similar to those obtained in Wells 31/2-1 and 31/2-2. It was, however, impossible to confirm the 12-meter oil gradient indicated by RFT's in well 31/2-2. Sampling attempts in the water zone failed as only mud filtrate was recovered. In the suspected oil zone, no samples were obtained in spite of numerous attempts as the tool probe always plugged in the relatively tight and poorly consolidated formation. Only two gas samples were obtained, at 1458 m and 1568.5 m.

The well was permanently abandoned on 20 July 1980 as a gas and oil appraisal well.

Testing

Four Production Tests were conducted in the Middle to Late Jurassic. PT1 tested the interval 1600.5 m to 1605.5 m in the water zone, PT2 tested the interval 1577.5 m to 1582.5 m in the oil zone, PT3 tested the interval 1520 m to 1535 m in the micaceous part of the gas bearing section, and PT4 tested 1435 m to 1460 m in the top clean sand of the gas section.

After the bottom hole test valve was opened for the test in the water zone, the well flowed for 17 minutes until it died. Some 87.5 litres of formation water (70.000 ppm NaCl equivalent) were recovered.

In the oil zone test (PT2) the well came in at a low rate and flowed at about 4.5 - 6.6 Sm3/day for four days. The oil was about 24 deg API and the GOR around 36 Sm3/Sm3. The micaceous gas zone test (PT3) stabilized at a rate of about 142000 Sm3/day on 28/64" choke during the clean up period. The produced fluids were gas of gravity 0.617 (air = 1) and condensate of 50.3 API, with some water (mostly brine) and traces of sediment. The gas contained no detectable H2S and approximately 0.4% C02. Sequential rate tests followed where the rates continuously improved up to 923000 Sm3/day. The test was terminated while production rates were still increasing. The reason for the increasing rates was assumed to be development of a channel behind the casing creating communication with the better sand some 10 meters above the top of the perforations. The clean sand gas test was performed with a gravel pack completion. Severe turbulence effects dominated it. After the initial clean up at 368000 - 481000 Sm3/day flow rate, the well produced at maximum rate of about 1133000 Sm3/day. The fluids had similar composition as in PT3.

Temperatures measured during the test gave a formation temperature of 60 - 62 deg C in the gas-bearing section of the reservoir. This corresponds to a linear temperature gradient from seafloor to top reservoir of ca 50 deg C, which is very high for the area.

Cuttings at the Norwegian Offshore Directorate

Cuttings at the Norwegian Offshore Directorate
Cuttings available for sampling?	YES

Cuttings at the Norwegian Offshore Directorate
Cutting sample, top depth [m]	Cutting samples, bottom depth [m]
460.00	2599.00

Cores at the Norwegian Offshore Directorate

Cores at the Norwegian Offshore Directorate
Core sample number	Core sample - top depth	Core sample - bottom depth	Core sample depth - uom
1	1412.0	1415.5	[m ]
2	1421.0	1425.0	[m ]
3	1425.0	1441.0	[m ]
4	1443.0	1449.3	[m ]
5	1450.0	1461.2	[m ]
6	1462.4	1467.8	[m ]
8	1469.2	1473.0	[m ]
9	1473.0	1475.0	[m ]
10	1484.5	1496.4	[m ]
11	1496.4	1514.5	[m ]
12	1514.5	1529.6	[m ]
13	1533.0	1540.9	[m ]
14	1551.0	1564.5	[m ]
15	1564.5	1566.5	[m ]
16	1566.6	1584.3	[m ]
17	1584.0	1599.7	[m ]
18	1601.0	1619.3	[m ]
19	1619.0	1623.9	[m ]
20	1624.0	1627.7	[m ]
21	1628.0	1645.4	[m ]
22	2116.0	2133.9	[m ]

Cores at the Norwegian Offshore Directorate
Total core sample length [m]	216.4

Cores at the Norwegian Offshore Directorate
Cores available for sampling?	YES

Core photos

Core photos

1412-1414m	1414-1416m	1421-1423m	1423-1425m	1425-1427m

1427-1430m	1430-1433m	1433-1435m	1435-1438m	1438-1441m

1443-1445m	1445-1448m	1448-1449m	1450-1452m	1452-1455m

1455-1458m	1458-1460m	1460-1461m	1462-1463m	1469-1471m

1471-1473m	1473-1475m	1484-1487m	1487-1489m	1489-1492m

1492-1495m	1495-1496m	1496-1499m	1499-1501m	1501-1504m

1504-1507m	1507-1509m	1509-1512m	1512-1514m	1514-1517m

1517-1519m	1519-1522m	1522-1525m	1525-1528m	1528-1529m

1533-1535m	1535-1538m	1538-1540m	1551-1553m	1553-1556m

1556-1559m	1559-1561m	1561-1564m	1564-1566m	1566-1569m

1569-1572m	1572-1574m	1574-1577m	1577-1580m	1580-1582m

1582-1584m	1584-1586m	1586-1589m	1589-1592m	1592-1594m

1594-1597m	1601-1603m	1603-1606m	1606-1609m	1609-1611m

1611-1614m	1614-1617m	1617-1619m	1619-1621m	1621-1623m

1624-1626m	1626-1627m	1628-1630m	1730-1633m	1633-1636m

1636-1638m	1638-1641m	1641-1644m	1644-1645m	2116-2118m

2118-2121m	2121-2124m	2126-2129m	2129-2132m	2132-2133m

Oil samples at the Norwegian Offshore Directorate

Oil samples at the Norwegian Offshore Directorate
Test type	Bottle number	Top depth MD [m]	Bottom depth MD [m]	Fluid type	Test time	Samples available
DST	DST1	1577.00	1582.00	WATER	06.06.1980 - 20:00	YES

Lithostratigraphy

Lithostratigraphy
Top depth [mMD RKB]	Lithostrat. unit
359	NORDLAND GP
643	HORDALAND GP
1145	ROGALAND GP
1145	BALDER FM
1200	SELE FM
1242	LISTA FM
1374	VÅLE FM
1384	VIKING GP
1384	SOGNEFJORD FM
1508	HEATHER FM
1561	FENSFJORD FM
1677	KROSSFJORD FM
1755	HEATHER FM
1812	BRENT GP
1902	DUNLIN GP
1902	DRAKE FM
2010	COOK FM
2055	AMUNDSEN FM
2097	JOHANSEN FM
2176	AMUNDSEN FM
2236	STATFJORD GP
2358	HEGRE GP

Composite logs

Composite logs
Document name	Document format	Document size [MB]
236	pdf	0.45

Geochemical information

Geochemical information
Document name	Document format	Document size [MB]
236_1	pdf	1.29
236_2	pdf	0.51

Documents – older Norwegian Offshore Directorate WDSS reports and other related documents

Documents – older Norwegian Offshore Directorate WDSS reports and other related documents
Document name	Document format	Document size [MB]
236_01_WDSS_General_Information	pdf	0.15
236_02_WDSS_completion_log	pdf	0.18

Documents – reported by the production licence (period for duty of secrecy expired)

Documents – reported by the production licence (period for duty of secrecy expired)
Document name	Document format	Document size [MB]
236_01_31_2_3_Completion_Report	pdf	35.06
236_02_31_2_3_Completion_log	pdf	1.29
236_31_2_3_Biostratigraphy_appendix	pdf	2.43
236_31_2_3_Bottom_hole_press.calc	pdf	0.44
236_31_2_3_Core_description_core_1-21	pdf	10.79
236_31_2_3_Core_report_core_1-22_final_report	pdf	10.10
236_31_2_3_Form.testing_services_report_DST1	pdf	0.36
236_31_2_3_Formation_survey_analysis	pdf	0.06
236_31_2_3_Geochem_eval_of_source_rock	pdf	0.44
236_31_2_3_Geochem_eval_of_source_rock_encl_1	pdf	0.12
236_31_2_3_Geological_investigation_cores_vol _3	pdf	139.86
236_31_2_3_Geological_investigation_cores_vol_1	pdf	17.61
236_31_2_3_Geological_Investigation_cores_vol_2	pdf	20.73
236_31_2_3_Palynofacies_invest_on_the_Juras	pdf	6.05
236_31_2_3_Press.surv.rep_test1_run3	pdf	1.25
236_31_2_3_Press.surv.rep_test2_run1	pdf	0.77
236_31_2_3_Press.surv.rep_test2_run2	pdf	1.51
236_31_2_3_Press.surv.rep_test3_run1	pdf	1.22
236_31_2_3_Press.surv.rep_test3_run2	pdf	1.66
236_31_2_3_Press.surv.rep_test3_run3	pdf	1.43
236_31_2_3_Press.surv.test1_run1	pdf	0.60
236_31_2_3_Press.surv.test_clean_sand	pdf	0.84
236_31_2_3_Prod.test sampling	pdf	0.54
236_31_2_3_Production_test	pdf	1.97
236_31_2_3_Production_test_programme	pdf	2.69
236_31_2_3_PVT_study_on_b.h.sample	pdf	0.50
236_31_2_3_Rapport_fra_prod.test	pdf	1.12
236_31_2_3_Res.fliud_study	pdf	0.32
236_31_2_3_Res.fliud_study_2	pdf	0.71
236_31_2_3_Res.fluid_analysis_80167	pdf	0.35
236_31_2_3_Res.fluid_analysis_80167B	pdf	0.34
236_31_2_3_Res.fluid_analysis_80168	pdf	0.33
236_31_2_3_Res.fluid_analysis_80169	pdf	0.34
236_31_2_3_Res.fluid_analysis_81.12	pdf	0.56
236_31_2_3_Res.fluid_analysis_91.13	pdf	0.28
236_31_2_3_Res.fluid_study_80090	pdf	0.20
236_31_2_3_Res.fluid_study_80091	pdf	0.23
236_31_2_3_Res.fluid_study_by_Sintef	pdf	0.38
236_31_2_3_Rock_mineral_analysis	pdf	0.14
236_31_2_3_Sidewall_sample_description	pdf	0.69
236_31_2_3_Sieve_analysis	pdf	2.60
236_31_2_3_Test_information_micace	pdf	0.75
236_31_2_3_Well_summary_by_Anchor	pdf	2.06
236_31_2_3_Well_testing_data_sheet	pdf	2.29
236_31_2_3_Well_test_interpretation	pdf	11.20
236_31_2_3_Well_test_report_DST1_DST2	pdf	6.07
236_31_2_3_Well_test_report_gas_no1	pdf	5.32
236_31_2_3_Well_test_report_gas_no1_micaceous	pdf	9.81
236_31_2_3_Well_test_report_gas_no2	pdf	3.63
236_31_2_3_Well_test_report_gas_no2_annexes	pdf	6.10
236_31_2_3_Facies_inndeling_basert_paa_logg	pdf	1.31

Drill stem tests (DST)

Drill stem tests (DST)
Test number	From depth MD [m]	To depth MD [m]	Choke size [mm]
1.0	1575	1580	0.0
2.0	1552	1557	6.4
3.0	1495	1510	50.8
4.0	1410	1435	38.1

Drill stem tests (DST)
Test number	Final shut-in pressure [MPa]	Final flow pressure [MPa]	Bottom hole pressure [MPa]	Downhole temperature [°C]
1.0
2.0
3.0
4.0

Drill stem tests (DST)
Test number	Oil [Sm3/day]	Gas [Sm3/day]	Oil density [g/cm3]	GOR [m3/m3]
1.0
2.0	14	560	0.910	40
3.0		914000
4.0		1133000

Logs

Logs
Log type	Log top depth [m]	Log bottom depth [m]
CBL	350	1816
CBL	630	1352
CST	1	0
CST	2	0
CST	3	0
DLL MSFL GR	1352	1824
FDC CNL GR CAL	445	818
FDC CNL GR CAL	803	1367
FDC CNL GR CAL	1352	1824
FDC CNL GR CAL	1817	2590
HDT	1352	1819
HDT	1817	2596
ISF BHC GR SP	445	814
ISF BHC GR SP	803	1368
ISF BHC GR SP	1352	1821
ISF BHC GR SP	1817	2593
LSS GR	445	816
LSS GR	803	1364
LSS GR	1352	1819
LSS GR	1817	2594
RFT	1387	1750

Casing and leak–off tests

Casing and leak–off tests
Casing type	Casing diam. [inch]	Casing depth [m]	Hole diam. [inch]	Hole depth [m]	LOT/FIT mud eqv. [g/cm3]	Formation test type
CONDUCTOR	30	420.0	36	425.0	0.00	LOT
SURF.COND.	20	779.0	26	789.0	1.43	LOT
INTERM.	13 3/8	1328.0	17 1/2	1339.0	1.55	LOT
INTERM.	9 5/8	1791.0	12 1/4	1798.0	1.74	LOT
LINER	7	2576.0	8 1/2	2576.0	0.00	LOT

Drilling mud

Drilling mud
Depth MD [m]	Mud weight [g/cm3]	Visc. [mPa.s]	Mud type
789	1.31	54.0	seawater
1338	1.32	60.0	seawater
1433	1.28	52.0	seawater
1941	1.18	52.0	seawater
2267	1.19	48.0	seawater

Thin sections at the Norwegian Offshore Directorate

Thin sections at the Norwegian Offshore Directorate
Depth	Unit
1414.40	[m ]
1432.80	[m ]
1443.45	[m ]
1450.20	[m ]
1471.25	[m ]
1486.90	[m ]
1492.80	[m ]
1505.10	[m ]
1534.35	[m ]
1540.40	[m ]
1553.70	[m ]
1558.45	[m ]
1563.90	[m ]
1565.65	[m ]
1568.65	[m ]
7574.45	[m ]
1574.45	[m ]
1579.86	[m ]
1585.79	[m ]
7586.92	[m ]
1586.92	[m ]
1590.54	[m ]
1599.08	[m ]
1609.86	[m ]
1615.50	[m ]
1623.24	[m ]
1628.12	[m ]
1414.00	[m ]
1433.00	[m ]
1443.00	[m ]
1450.00	[m ]
1471.00	[m ]
1487.00	[m ]
1493.00	[m ]
1505.00	[m ]
1513.00	[m ]
1523.00	[m ]
1534.00	[m ]
1540.00	[m ]
1554.00	[m ]
1558.00	[m ]
1564.00	[m ]
1566.00	[m ]
1569.00	[m ]
1575.00	[m ]
1580.00	[m ]
1586.00	[m ]
1587.00	[m ]
1628.00	[m ]

Pressure plots

Pressure plots
The pore pressure data is sourced from well logs if no other source is specified. In some wells where pore pressure logs do not exist, information from Drill stem tests and kicks have been used. The data has been reported to the NPD, and further processed and quality controlled by IHS Markit.

Pressure plots
Document name	Document format	Document size [MB]
236_Formation_pressure_(Formasjonstrykk)	pdf	0.22

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