Wellbore: 31/3-2 - 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.	31/3-2
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.	31/6-1 (Troll Øst)
Well name Official name of the parent well for the wellbore based on Norwegian Offshore Directorate guidelines for designation of wells and wellbores.	31/3-2
Seismic location Position of spud location on seismic survey lines. SP: shotpoint.	ST 8007 - 338 A SP. 204.5
Production licence Official designation of the production licence the wellbore was drilled or planned to be drilled from ( well head posistion).	085
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.	Norsk Hydro Produksjon AS
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.	403-L
Drilling facility Norwegian Offshore Directorate's name of the facility which the wellbore was drilled from.	TREASURE SEEKER
Drilling days Number of days from wellbore entry to wellbore completion.	57
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,	05.03.1984
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.	30.04.1984
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.	30.04.1986
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.	06.06.2006
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
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.	340.0
Total depth (MD) [m RKB] Total measured length of wellbore from kelly bushing to total depth (driller's depth).	2090.0
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).	2090.0
Maximum inclination [°] Maximum deviation, in degrees, from a vertical well path.Shown only for released wells.	1.4
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.	EARLY JURASSIC
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.	DRAKE FM
Geodetic datum Reference system for coordinates. Example of legal values: ED50.	ED50
NS degrees Geographic coordinate of the wellhead, north-south degrees.	60° 52' 11.41'' N
EW degrees Geographic coordinate of the wellhead, east-west degrees.	3° 40' 41.79'' E
NS UTM [m] Universal Transverse Mercator coordinate of the wellhead, north-south.	6748639.40
EW UTM [m] Universal Transverse Mercator coordinate of the wellhead, east-west.	536836.48
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.	100

Well 31/3-2 was drilled immediately to the southeast of a fault that was interpreted as a boundary fault between Troll West and Troll East. The main objectives of the appraisal well 31/3-2 were to determine if hydrocarbons were present on the downthrown south side of the fault, to determine the contacts, and to determine the degree of communication across the fault plane. A test would be performed in the case of moveable hydrocarbons, in order to observe boundary effects where the pay zone is narrow and thin. The well was planned to reach total depth in the Early Jurassic Drake Formation at 2050 m if drilling through the "boundary fault". In the case of drilling entirely within the hanging-wall block the total depth was estimated to 2130 m.

Operations and results

Well 31/3-2 was spudded with the semi-submersible installation Treasure Seeker on 5 March 1984 and drilled to TD at 2090 m in claystones of the Early Jurassic Drake Formation. No significant technical problems occurred during drilling and testing. The well was drilled with pre-hydrated gel/seawater with sweeps of high viscous mud down to 629 m and with KCl/polymer mud from 629 m to TD.

The Sognefjord Formation (1567 - 1706 m) was found oil bearing down to 1578.5 m where the oil/water contact was established. The oil-bearing reservoir consisted of very fine to very coarse-grained sandstones. They are friable to loose with only traces of siliceous or calcareous cement. The total net sand in the Sognefjord Formation was calculated to 132 m out of 139 m gross thickness, giving a net/gross ratio of 0.95 and an average porosity of 26.6%. A thin (0.5 m) gas cap could be present on top of the oil column. This was identified from LDT/CNL logs and was also consistent with the GOR development during the test, but was not confirmed by RFT data. There were no oil shows above the Sognefjord Formation, and no oil shows below1595 m, and the Middle to Early Jurassic sandstones was found water bearing.

Evidence from seismic interpretations, dip meter analysis, and subsequent geometrical considerations indicated that well 31/3-2 penetrated the "boundary fault" at top Brent Group level, between 1940 and 1955 m. In this zone two calcite cemented bands were encountered thought to be associated with the fault plane. The OWC was found to be 3.5 m shallower than in well 31/2-6, but the pressure data from wells in the area did not have sufficient reproducibility and resolution to support different pressure regimes in the different compartments.

Five cores were cut between 1565 m and 1640 m from the lower part of the Draupne Formation and into the Sognefjord Formation. RFT pressure recordings and sampling were performed in the reservoir interval and pressure tests were also made in sand intervals in the underlying formations with the deepest point in the Drake Formation (Dunlin Group). Segregated RFT fluid samples were recovered from 1567.6 m (two samplings, one with oil and one with gas and oil), 1576 m (mud filtrate and water), and 1577.8 m (mud filtrate with trace oil and gas),

The well was permanently abandoned on 30 April 1984 as a gas and oil appraisal.

Testing

One production test was performed over the interval 1567 - 1577 m in the oil zone at the top of the Sognefjord Formation. The test produced 1271.9 Sm3 /day of 27.5 deg. API oil together with 562588 Sm3/day of gas with gravity 0.620 (air = 1). The choke size was 63.5 mm. The GOR was 442 Sm3/Sm3 and the CO2 content was 1.0%. The pore pressure at the top of the reservoir was measured to be 158.15 bara (2293.8 psi). The temperature measured during the test was 69.5 deg. C.

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	2090.00

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	1565.0	1575.5	[m ]
2	1581.0	1590.7	[m ]
3	1593.0	1606.3	[m ]
4	1608.0	1626.0	[m ]
5	1626.0	1639.9	[m ]

Cores at the Norwegian Offshore Directorate
Total core sample length [m]	65.3

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

Core photos

Core photos

1565-1570m	1570-1575m	1575-1576m	1581-1586m	1586-1590m

1593-1598m	1598-1603m	1603-1606m	1608-1613m	1613-1618m

1618-1623m	1623-1626m	1626-1631m	1631-1636m	1626-1639m

Palynological slides at the Norwegian Offshore Directorate

Palynological slides at the Norwegian Offshore Directorate
Sample depth	Depth unit	Sample type	Laboratory
700.0	[m]	DC	RRI
720.0	[m]	DC	RRI
740.0	[m]	DC	RRI
760.0	[m]	DC	RRI
780.0	[m]	DC	RRI
800.0	[m]	DC	RRI
820.0	[m]	DC	RRI
880.0	[m]	DC	RRI
940.0	[m]	DC	RRI
960.0	[m]	DC	RRI
980.0	[m]	DC	RRI
1000.0	[m]	DC	RRI
1020.0	[m]	DC	RRI
1040.0	[m]	DC	RRI
1060.0	[m]	DC	RRI
1080.0	[m]	DC	RRI
1100.0	[m]	DC	RRI
1120.0	[m]	DC	RRI
1140.0	[m]	DC	RRI
1160.0	[m]	DC	RRI
1180.0	[m]	DC	RRI
1200.0	[m]	DC	RRI
1220.0	[m]	DC	RRI
1240.0	[m]	DC	RRI
1260.0	[m]	DC	RRI
1280.0	[m]	DC	RRI
1300.0	[m]	DC	RRI
1320.0	[m]	DC	RRI
1340.0	[m]	DC	RRI
1360.0	[m]	DC	RRI
1380.0	[m]	DC	RRI
1400.0	[m]	DC	RRI
1420.0	[m]	DC	RRI
1440.0	[m]	DC	RRI
1460.0	[m]	DC	RRI
1480.0	[m]	DC	RRI
1565.0	[m]	C	OD
1566.0	[m]	C	OD
1567.0	[m]	C	OD
1569.0	[m]	DC	OD
1571.0	[m]	DC	OD
1575.0	[m]	C	OD
1582.5	[m]	C	OD
1583.5	[m]	C	OD
1584.7	[m]	C	OD
1588.0	[m]	C	OD
1590.3	[m]	C	OD
1593.0	[m]	C	OD
1597.5	[m]	C	OD
1600.8	[m]	C	OD
1610.8	[m]	C	OD
1610.9	[m]	C	OD
1613.2	[m]	C	OD
1613.6	[m]	C	OD
1614.6	[m]	C	OD
1614.7	[m]	C	OD
1615.5	[m]	C	OD
1616.0	[m]	C	OD
1616.1	[m]	C	OD
1617.0	[m]	C	OD
1618.0	[m]	C	OD
1618.2	[m]	C	OD
1618.8	[m]	C	OD
1620.1	[m]	C	OD
1622.2	[m]	C	OD
1624.5	[m]	C	OD
1626.0	[m]	C	OD

Lithostratigraphy

Lithostratigraphy
Top depth [mMD RKB]	Lithostrat. unit
365	NORDLAND GP
540	HORDALAND GP
540	NO FORMAL NAME
605	NO FORMAL NAME
1121	ROGALAND GP
1121	BALDER FM
1194	SELE FM
1280	LISTA FM
1452	VÅLE FM
1471	SHETLAND GP
1533	CROMER KNOLL GP
1533	MIME FM
1541	VIKING GP
1541	DRAUPNE FM
1567	SOGNEFJORD FM
1706	HEATHER FM
1725	FENSFJORD FM
1851	KROSSFJORD FM
1929	HEATHER FM
1939	BRENT GP
1939	TARBERT FM
1952	NESS FM
1966	ETIVE FM
2006	DUNLIN GP
2006	DRAKE FM

Composite logs

Composite logs
Document name	Document format	Document size [MB]
100	pdf	0.32

Geochemical information

Geochemical information
Document name	Document format	Document size [MB]
100_1	pdf	0.33
100_2	pdf	3.30

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]
100_01_WDSS_General_Information	pdf	0.18
100_02_WDSS_completion_log	pdf	0.21

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]
100_01_31_3_2_Completion_repor_and_Competion_log	pdf	13.56
100_01_31_3_2_Final_Well_Report_by_Exlog	pdf	5.88
100_02_31_3_2_Drilling_program	pdf	3.26
100_02_31_3_2_Prospect_descr.and_prognosis	pdf	2.30
100_02_31_3_2_Prospect_descr_and_prognosis_encl_1	pdf	0.52
100_02_31_3_2_Prospect_descr_and_prognosis_encl_2	pdf	9.51
100_02_31_3_2_Prospect_descr_and_prognosis_encl_3	pdf	8.08
100_02_31_3_2_Prospect_descr_and_prognosis_encl_4	pdf	0.38
100_02_31_3_2_Prospect_descr_and_prognosis_encl_5(7)	pdf	0.24
100_03_31_3_2_Biostrat._kerogen_analysis_by_Stratlab	pdf	10.30
100_03_31_3_2_Formation_resistivity_meas	pdf	0.27
100_03_31_3_2_Grain_size_distr.analysis	pdf	0.68
100_03_31_3_2_Historie-tilpasning_by_Statoil	pdf	0.97
100_03_31_3_2_Hydrocarbon_characterisation	pdf	3.55
100_03_31_3_2_Permeability_thin_section	pdf	0.12
100_03_31_3_2_Petrophysical_evaluation	pdf	1.97
100_03_31_3_2_Petrophysical_evaluation_encl_1	pdf	0.71
100_04_31_3_2_Core_gamma_surface_log	pdf	0.15
100_04_31_3_2_Routine_core_analysis	pdf	1.79
100_05_31_3_2_31_3_2_High_acc.press.temp.meas_82816_Flopetrol	pdf	4.43
100_05_31_3_2_Drillsteam_test_report	pdf	8.08
100_05_31_3_2_High acc.press.temp.meas_82816_encl_1	pdf	0.16
100_05_31_3_2_High_acc.press.temp.meas_82802_Flopetrol	pdf	6.25
100_05_31_3_2_Oil_test_program	pdf	2.30
100_05_31_3_2_Pressure_survey_report	pdf	2.40
100_05_31_3_2_Production_test_report	pdf	1.39
100_05_31_3_2_PVT_Analyse_av_olje_fra_Troll	pdf	1.40
100_05_31_3_2_Repeated_formation_tester	pdf	0.30
100_05_31_3_2_Results_and_implications	pdf	1.28
100_05_31_3_2_Results_and_implications_encl_1	pdf	0.17
100_05_31_3_2_Results_of_the quality_by_Oilplus	pdf	2.86
100_05_31_3_2_Sampling_report	pdf	1.68
100_05_31_3_2_SDP_CRG_press.and_temp.survey0_by_Flopetrol	pdf	10.05
100_05_31_3_2_SDP_CRG_press.and_temp.survey_29C_ Flopetrol	pdf	10.28
100_05_31_3_2_SDP_CRG_press.and_temp.survey_29C_encl_1	pdf	0.13
100_05_31_3_2_SDP_CRG_press.and_temp.survey_29E_encl_1	pdf	0.16
100_05_31_3_2_SDP_CRG_press.and_temp.survey_29E_encl_2	pdf	0.14
100_05_31_3_2_SDP_CRG_press.and_temp.survey_29E_Flopetrol	pdf	9.98
100_05_31_3_2_SDP_CRG_press.and_temp.survey_encl_1	pdf	0.12
100_07_31_3_2_Borehole_geoph.well_Geophone	pdf	0.24
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_1	pdf	0.38
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_10	pdf	0.42
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_11	pdf	0.44
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_12	pdf	0.34
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_13	pdf	0.28
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_14	pdf	0.40
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_15	pdf	0.39
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_16	pdf	0.26
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_17	pdf	0.28
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_18	pdf	0.17
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_19	pdf	0.35
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_2	pdf	1.09
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_20	pdf	0.31
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_21	pdf	0.39
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_22	pdf	0.38
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_23	pdf	0.31
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_24	pdf	0.32
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_25	pdf	0.19
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_26	pdf	0.16
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_27	pdf	0.14
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_28	pdf	0.14
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_29	tif	0.14
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_3	pdf	0.03
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_4	pdf	0.04
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_5	pdf	0.82
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_6	pdf	1.06
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_7	pdf	3.81
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_8	pdf	3.34
100_07_31_3_2_Borehole_geoph.well_Geophone_encl_9	pdf	0.09

Drill stem tests (DST)

Drill stem tests (DST)
Test number	From depth MD [m]	To depth MD [m]	Choke size [mm]
1.0	1567	1577	63.5

Drill stem tests (DST)
Test number	Final shut-in pressure [MPa]	Final flow pressure [MPa]	Bottom hole pressure [MPa]	Downhole temperature [°C]
1.0				60

Drill stem tests (DST)
Test number	Oil [Sm3/day]	Gas [Sm3/day]	Oil density [g/cm3]	Gas grav. rel.air	GOR [m3/m3]
1.0	1272	563000	0.890	0.620	442

Logs

Logs
Log type	Log top depth [m]	Log bottom depth [m]
CBL VDL	610	1499
CBL VDL	1390	1705
CBL VDL	1400	1736
CET GR	1385	1702
CST	1040	1494
CST	1505	1979
CST	1750	2087
DLL MSFL GR SP CAL	1502	1639
HDT	610	1492
ISF LSS GR SP	451	622
ISF LSS GR SP	610	1491
ISF LSS GR SP	1502	2085
LDT CNL CAL GR	451	624
LDT CNL CAL GR	610	1493
LDT CNL CAL GR	1502	1639
LDT CNL CAL GR	1502	2086
RFT	1567	1567
RFT	1567	1725
RFT	1567	1567
RFT	1576	1576
RFT	1577	1577
RFT	1725	2022
SHDT	1502	2087
VSP-O	1000	2075

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	451.0	36	451.0	0.00	LOT
SURF.COND.	20	609.0	26	625.0	1.45	LOT
INTERM.	13 3/8	1502.0	17 1/2	1515.0	1.56	LOT
INTERM.	9 5/8	1805.0	12 1/4	2090.0	0.00	LOT

Drilling mud

Drilling mud
Depth MD [m]	Mud weight [g/cm3]	Visc. [mPa.s]	Mud type
460	1.06		WATER BASED
560	1.37	11.0	WATER BASED
650	1.20	18.0	WATER BASED
1250	1.25	19.0	WATER BASED
1355	1.30	18.0	WATER BASED
1650	1.22	40.0	WATER BASED

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]
100_Formation_pressure_(Formasjonstrykk)	pdf	0.19

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