Factpages Norwegian Offshore Directorate
Factpages Norwegian Offshore Directorate
sodir.no          Norsk
19.06.2024 - 01:33
Time of last synchronization with Norwegian Offshore Directorate's internal systems

9/2-3

Export: PDF icon PDF
  • General information

    General information
    Attribute Value
    Wellbore name
    Official name of wellbore based on Norwegian Offshore Directorate guidelines for designation of wells and wellbores.
    9/2-3
    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).
    WILDCAT
    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
    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.
    Discovery
    Name of the discovery the wellbore is related to.
    Well name
    Official name of the parent well for the wellbore based on Norwegian Offshore Directorate guidelines for designation of wells and wellbores.
    9/2-3
    Seismic location
    Position of spud location on seismic survey lines. SP: shotpoint.
    ST 8626 - 410 SP 210
    Production licence
    Official designation of the production licence the wellbore was drilled or planned to be drilled from ( well head posistion).
    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.
    Den norske stats oljeselskap a.s
    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.
    624-L
    Drilling facility
    Norwegian Offshore Directorate's name of the facility which the wellbore was drilled from.
    Drilling days
    Number of days from wellbore entry to wellbore completion.
    67
    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,
    04.12.1989
    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.
    08.02.1990
    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.
    08.02.1992
    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.
    25.04.2005
    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.
    WILDCAT
    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
    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.
    YES
    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.
    SANDNES 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.
    79.0
    Total depth (MD) [m RKB]
    Total measured length of wellbore from kelly bushing to total depth (driller's depth).
    3424.0
    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).
    3421.0
    Maximum inclination [°]
    Maximum deviation, in degrees, from a vertical well path.Shown only for released wells.
    1.6
    Bottom hole temperature [°C]
    Estimated temperature at final total depth of the wellbore. Shown only for released wells. See discription.
    106
    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.
    MIDDLE 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.
    BRYNE FM
    Geodetic datum
    Reference system for coordinates. Example of legal values: ED50.
    ED50
    NS degrees
    Geographic coordinate of the wellhead, north-south degrees.
    57° 45' 20.2'' N
    EW degrees
    Geographic coordinate of the wellhead, east-west degrees.
    4° 22' 13.5'' E
    NS UTM [m]
    Universal Transverse Mercator coordinate of the wellhead, north-south.
    6402472.09
    EW UTM [m]
    Universal Transverse Mercator coordinate of the wellhead, east-west.
    581556.09
    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.
    1294
  • Wellbore history

    General
    Well 9/2-3 is located ca 11.5 km southwest of the Yme Field in the Egersund Basin. The objectives of the well were to test the sandstones of Late/Middle Jurassic age, the Sandnes- and Bryne formations. Furthermore the 9/2-3 well will test the geophysical and structural interpretation of the area and improve the paleontological, geological and geochemical understanding of this area in the North Sea. A strong reflector was observed at 253 m, but was expected to be a change in lithology rather than shallow gas.
    Operations and results
    Wildcat well 9/2-3 was spudded with the semi-submersible installation Vildkat Explorer 4 December 1989 on and drilled to TD at 3424 m in the Middle Jurassic Bryne Formation. No shallow gas was encountered in this well. Drilling went on without significant difficulties. The well was drilled with seawater/gel/bentonite down to 376 m, with gypsum/polymer mud from 376 m to 3210, and with a polymer/Resinex mud from 3210 m to TD.
    The Sandnes Formation was encountered at 3252 m and proved oil. The OWC was difficult to place from the logs, but was estimated at 3273 m. This gives a 21 m oil column. Gross reservoir interval was found to be 115 m. Core and log analysis indicate a fairly low porosity sandstone with small amounts of silt, shale and limestone (calcite cement). The Bryne Formation proved to be water bearing, and no test was performed in this formation.
    Organic geochemical analyses show that the Tau Formation (3098 m to 3188 m) is an excellent source rock with TOC in the range 3 to 13 % and hydrogen index in the range 360 to 700 mg HC/g TOC. The Tau Formation is early oil-window mature (%Ro around 0.6 and Tmax from 430 to 435 deg C) in the well. Analyses of the DST oil show a somewhat higher maturity than the in-well source rock. Furthermore, the oil showed a close resemblance to the 9/2-1 DST 3 oil.
    One conventional core was cut in the Sandnes formation in the interval 3264 to 3291 m. Sidewall cores were shot in two rounds with a total of 45 shots whereof 30 were recovered. One run with the FMT tool was made in the interval 3260 to 3329 m in the Sandnes/Bryne formations. Only 9 out of 64 attempts were successful and no fluid gradients could be evaluated from the pressure plot. One segregated sample was taken at 3263.1 m. The 2 3/4-gallon chamber contained mud and the 1-gallon chamber was empty due to plugging in the chamber line.
    The well was permanently abandoned on 8 February 1990 as an oil discovery.
    Testing
    One DST test was performed in the interval 3258 to 3268 m. The Sandnes formation was confirmed oil bearing. The production rate was very low due to low permeability. Gas was not produced during the test, and 4 Sm3/d oil was produced through a 12,7 mm choke. The static bottom hole temperature measured in the test was 102.5 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]
    380.00
    3420.00
  • 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
    3264.0
    3292.3
    [m ]
    Cores at the Norwegian Offshore Directorate
    Total core sample length [m]
    28.3
    Cores at the Norwegian Offshore Directorate
    Cores available for sampling?
    YES
  • Core photos

    Core photos
    Core photo at depth: 3264-3269m
    Core photo at depth: 3269-3274m
    Core photo at depth: 3274-3279m
    Core photo at depth: 3279-3284m
    Core photo at depth: 3284-3289m
    3264-3269m
    3269-3274m
    3274-3279m
    3279-3284m
    3284-3289m
    Core photo at depth: 3289-3292m
    Core photo at depth:  
    Core photo at depth:  
    Core photo at depth:  
    Core photo at depth:  
    3289-3292m
  • Palynological slides at the Norwegian Offshore Directorate

    Palynological slides at the Norwegian Offshore Directorate
    Sample depth
    Depth unit
    Sample type
    Laboratory
    400.0
    [m]
    DC
    HALIB
    420.0
    [m]
    DC
    HALIB
    440.0
    [m]
    DC
    HALIB
    460.0
    [m]
    DC
    HALIB
    480.0
    [m]
    DC
    HALIB
    500.0
    [m]
    DC
    HALIB
    520.0
    [m]
    DC
    HALIB
    540.0
    [m]
    DC
    HALIB
    560.0
    [m]
    DC
    HALIB
    580.0
    [m]
    DC
    HALIB
    600.0
    [m]
    DC
    HALIB
    620.0
    [m]
    DC
    HALIB
    640.0
    [m]
    DC
    HALIB
    660.0
    [m]
    DC
    HALIB
    680.0
    [m]
    DC
    HALIB
    700.0
    [m]
    DC
    HALIB
    720.0
    [m]
    DC
    HALIB
    760.0
    [m]
    DC
    HALIB
    780.0
    [m]
    DC
    HALIB
    800.0
    [m]
    DC
    HALIB
    840.0
    [m]
    DC
    HALIB
    860.0
    [m]
    DC
    HALIB
    880.0
    [m]
    DC
    HALIB
    900.0
    [m]
    DC
    HALIB
    920.0
    [m]
    DC
    HALIB
    940.0
    [m]
    DC
    HALIB
    950.0
    [m]
    DC
    HALIB
    960.0
    [m]
    DC
    HALIB
    970.0
    [m]
    DC
    HALIB
    980.0
    [m]
    DC
    HALIB
    990.0
    [m]
    DC
    HALIB
    1000.0
    [m]
    DC
    HALIB
    1020.0
    [m]
    DC
    HALIB
    1030.0
    [m]
    DC
    HALIB
    1040.0
    [m]
    DC
    HALIB
    1050.0
    [m]
    DC
    HALIB
    1900.0
    [m]
    DC
    HALIB
    1920.0
    [m]
    DC
    HALIB
    1930.0
    [m]
    DC
    HALIB
    1940.0
    [m]
    DC
    HALIB
    1950.0
    [m]
    DC
    HALIB
    1960.0
    [m]
    DC
    HALIB
    1970.0
    [m]
    DC
    HALIB
    1985.0
    [m]
    DC
    HALIB
    2000.0
    [m]
    DC
    HALIB
    2015.0
    [m]
    DC
    HALIB
    2030.0
    [m]
    DC
    HALIB
    2045.0
    [m]
    DC
    HALIB
    2060.0
    [m]
    DC
    HALIB
    2075.0
    [m]
    DC
    HALIB
    2105.0
    [m]
    DC
    HALIB
    2120.0
    [m]
    DC
    HALIB
    2135.0
    [m]
    DC
    HALIB
    2150.0
    [m]
    DC
    HALIB
    2195.0
    [m]
    DC
    HALIB
    2240.0
    [m]
    DC
    HALIB
    2255.0
    [m]
    DC
    HALIB
    2270.0
    [m]
    DC
    HALIB
    2285.0
    [m]
    DC
    HALIB
    2300.0
    [m]
    DC
    HALIB
    2315.0
    [m]
    DC
    HALIB
    2330.0
    [m]
    DC
    HALIB
    2345.0
    [m]
    DC
    HALIB
    2360.0
    [m]
    DC
    HALIB
    2375.0
    [m]
    DC
    HALIB
    2390.0
    [m]
    DC
    HALIB
    2405.0
    [m]
    DC
    HALIB
    2420.0
    [m]
    DC
    HALIB
    2430.0
    [m]
    DC
    HALIB
    2440.0
    [m]
    SWC
    STATO
    2455.0
    [m]
    DC
    HALIB
    2470.0
    [m]
    SWC
    STATO
    2485.0
    [m]
    DC
    HALIB
    2495.0
    [m]
    SWC
    STATO
    2505.0
    [m]
    SWC
    STATO
    2525.0
    [m]
    SWC
    STATO
    2535.0
    [m]
    SWC
    STATO
    2555.0
    [m]
    DC
    HALIB
    2570.0
    [m]
    DC
    HALIB
    2585.0
    [m]
    DC
    HALIB
    2600.0
    [m]
    DC
    HALIB
    2615.0
    [m]
    DC
    HALIB
    2630.0
    [m]
    DC
    HALIB
    2645.0
    [m]
    DC
    HALIB
    2660.0
    [m]
    DC
    HALIB
    2675.0
    [m]
    DC
    HALIB
    2690.0
    [m]
    DC
    HALIB
    2705.0
    [m]
    DC
    HALIB
    2720.0
    [m]
    DC
    HALIB
    2735.0
    [m]
    DC
    HALIB
    2750.0
    [m]
    DC
    HALIB
    2765.0
    [m]
    DC
    HALIB
    2780.0
    [m]
    DC
    HALIB
    2795.0
    [m]
    DC
    HALIB
    2810.0
    [m]
    DC
    HALIB
    2825.0
    [m]
    DC
    HALIB
    2840.0
    [m]
    DC
    HALIB
    2855.0
    [m]
    DC
    HALIB
    2870.0
    [m]
    DC
    HALIB
    2885.0
    [m]
    DC
    HALIB
    2900.0
    [m]
    DC
    HALIB
    2915.0
    [m]
    DC
    HALIB
    2930.0
    [m]
    DC
    HALIB
    2945.0
    [m]
    DC
    HALIB
    2960.0
    [m]
    DC
    HALIB
    2975.0
    [m]
    DC
    HALIB
    2990.0
    [m]
    DC
    HALIB
    3005.0
    [m]
    DC
    HALIB
    3020.0
    [m]
    DC
    HALIB
    3035.0
    [m]
    DC
    HALIB
    3050.0
    [m]
    DC
    HALIB
    3065.0
    [m]
    DC
    HALIB
    3080.0
    [m]
    DC
    HALIB
    3090.0
    [m]
    DC
    HALIB
    3094.0
    [m]
    SWC
    STATO
    3100.0
    [m]
    DC
    HALIB
    3108.0
    [m]
    SWC
    STATO
    3122.0
    [m]
    SWC
    STATO
    3131.0
    [m]
    SWC
    STATO
    3143.0
    [m]
    SWC
    STATO
    3155.0
    [m]
    DC
    HALIB
    3170.0
    [m]
    DC
    HALIB
    3185.0
    [m]
    DC
    HALIB
    3200.0
    [m]
    DC
    HALIB
    3251.0
    [m]
    SWC
    STATO
    3255.5
    [m]
    C
    STATO
    3264.2
    [m]
    C
    STATO
    3265.9
    [m]
    C
    STATO
    3270.8
    [m]
    C
    STATO
    3274.0
    [m]
    C
    STATO
    3278.5
    [m]
    C
    STATO
    3281.3
    [m]
    C
    STATO
    3290.0
    [m]
    C
    STATO
    3290.9
    [m]
    C
    STATO
    3305.0
    [m]
    SWC
    STATO
    3330.0
    [m]
    DC
    HALIB
    3341.0
    [m]
    SWC
    STATO
    3345.0
    [m]
    SWC
    STATO
    3360.0
    [m]
    DC
    HALIB
    3375.0
    [m]
    DC
    HALIB
    3390.0
    [m]
    DC
    HALIB
  • 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
    TEST1
    3258.00
    3268.00
    29.01.1990 - 05:55
    YES
  • Lithostratigraphy

  • Composite logs

    Composite logs
    Document name
    Document format
    Document size [MB]
    pdf
    0.40
  • Geochemical information

    Geochemical information
    Document name
    Document format
    Document size [MB]
    pdf
    0.82
    pdf
    2.50
    pdf
    0.58
  • 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]
    pdf
    20.47
  • Drill stem tests (DST)

    Drill stem tests (DST)
    Test number
    From depth MD
    [m]
    To depth MD
    [m]
    Choke size
    [mm]
    1.0
    3258
    3268
    12.7
    Drill stem tests (DST)
    Test number
    Final shut-in pressure
    [MPa]
    Final flow pressure
    [MPa]
    Bottom hole pressure
    [MPa]
    Downhole temperature
    [°C]
    1.0
    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
    4
  • Logs

    Logs
    Log type
    Log top depth [m]
    Log bottom depth [m]
    ACBL VDL GR
    275
    1106
    ACBL VDL GR
    3194
    3396
    CDL CNL GR
    3192
    3404
    DIFL ACL GR
    1106
    3182
    DIFL ACL GR
    3192
    3397
    DIPLOG
    3195
    3358
    FMT
    3260
    3329
    MWD - GR RES DIR
    166
    3422
    SWC GR
    2440
    3143
    SWC GR
    3234
    3349
    VELOCITY
    490
    3190
  • 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
    163.0
    36
    169.0
    0.00
    LOT
    INTERM.
    20
    350.0
    26
    375.0
    1.39
    LOT
    INTERM.
    13 3/8
    1106.0
    17 1/2
    1121.0
    2.04
    LOT
    INTERM.
    9 5/8
    3195.0
    12 1/4
    3210.0
    1.87
    LOT
    LINER
    7
    3424.0
    8 1/2
    3424.0
    0.00
    LOT
  • Drilling mud

    Drilling mud
    Depth MD [m]
    Mud weight [g/cm3]
    Visc. [mPa.s]
    Yield point [Pa]
    Mud type
    Date measured
    1121
    1.10
    20.0
    6.0
    WATER BASED
    11.12.1989
    1121
    1.14
    17.0
    3.5
    WATER BASED
    12.12.1989
    1272
    1.15
    27.0
    4.5
    WATER BASED
    14.12.1989
    1481
    1.16
    17.0
    3.5
    WATER BASED
    14.12.1989
    1618
    1.13
    20.0
    4.5
    WATER BASED
    19.12.1989
    1618
    1.13
    19.0
    4.0
    WATER BASED
    19.12.1989
    1618
    1.13
    16.0
    3.5
    WATER BASED
    19.12.1989
    1618
    1.13
    20.0
    5.0
    WATER BASED
    19.12.1989
    1696
    1.13
    20.0
    5.0
    WATER BASED
    21.12.1989
    1792
    1.13
    20.0
    4.5
    WATER BASED
    21.12.1989
    1941
    1.14
    19.0
    4.5
    WATER BASED
    22.12.1989
    2170
    1.14
    17.0
    4.5
    WATER BASED
    28.12.1989
    2511
    1.14
    18.0
    4.5
    WATER BASED
    28.12.1989
    2720
    1.14
    14.0
    3.5
    WATER BASED
    28.12.1989
    2753
    1.20
    17.0
    3.5
    WATER BASED
    28.12.1989
    3145
    1.33
    29.0
    5.0
    WATER BASED
    28.12.1989
    3145
    1.33
    31.0
    5.0
    WATER BASED
    29.12.1989
    3145
    1.35
    32.0
    5.0
    WATER BASED
    03.01.1990
    3145
    1.35
    28.0
    5.5
    WATER BASED
    03.01.1990
    3210
    1.48
    29.0
    5.5
    WATER BASED
    03.01.1990
    3210
    1.26
    20.0
    4.0
    WATER BASED
    05.01.1990
    3210
    1.26
    23.0
    5.0
    WATER BASED
    05.01.1990
    3210
    1.26
    22.0
    3.5
    WATER BASED
    08.01.1990
    3210
    1.26
    22.0
    5.0
    WATER BASED
    08.01.1990
    3210
    1.26
    25.0
    5.5
    WATER BASED
    09.01.1990
    3210
    1.26
    24.0
    5.5
    WATER BASED
    09.01.1990
    3210
    1.26
    30.0
    7.0
    WATER BASED
    10.01.1990
    3210
    1.63
    36.0
    6.5
    WATER BASED
    16.01.1990
    3258
    1.63
    36.0
    5.0
    WATER BASED
    19.01.1990
    3258
    1.63
    42.0
    5.0
    WATER BASED
    23.01.1990
    3258
    1.63
    26.0
    3.5
    WATER BASED
    25.01.1990
    3258
    1.63
    31.0
    4.0
    WATER BASED
    23.01.1990
    3258
    1.63
    33.0
    4.5
    WATER BASED
    23.01.1990
    3258
    1.63
    28.0
    4.0
    WATER BASED
    23.01.1990
    3258
    1.63
    27.0
    4.0
    WATER BASED
    24.01.1990
  • 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]
    pdf
    0.22