Factpages Norwegian Offshore Directorate
Factpages Norwegian Offshore Directorate
Factpages Norwegian Offshore Directorate
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21.11.2024 - 01:28
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6305/4-1

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  • General information
    General information
    Attribute Value
    Wellbore name
    Official name of wellbore based on Norwegian Offshore Directorate guidelines for designation of wells and wellbores.
    6305/4-1
    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
    Press release
    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.
    NORWEGIAN 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.
    6305/4-1
    Seismic location
    Position of spud location on seismic survey lines. SP: shotpoint.
    inline 4152 & x-line 5028
    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.
    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.
    1025-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.
    82
    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,
    14.03.2002
    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.
    03.06.2002
    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.
    03.06.2004
    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.
    29.06.2004
    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.
    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.
    PALEOCENE
    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.
    EGGA FM (INFORMAL)
    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.
    1002.0
    Total depth (MD) [m RKB]
    Total measured length of wellbore from kelly bushing to total depth (driller's depth).
    2975.0
    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).
    2974.0
    Maximum inclination [°]
    Maximum deviation, in degrees, from a vertical well path.Shown only for released wells.
    5.7
    Bottom hole temperature [°C]
    Estimated temperature at final total depth of the wellbore. Shown only for released wells. See discription.
    84
    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 CRETACEOUS
    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.
    SPRINGAR FM
    Geodetic datum
    Reference system for coordinates. Example of legal values: ED50.
    ED50
    NS degrees
    Geographic coordinate of the wellhead, north-south degrees.
    63° 34' 17.76'' N
    EW degrees
    Geographic coordinate of the wellhead, east-west degrees.
    5° 17' 55.93'' E
    NS UTM [m]
    Universal Transverse Mercator coordinate of the wellhead, north-south.
    7051501.85
    EW UTM [m]
    Universal Transverse Mercator coordinate of the wellhead, east-west.
    614148.32
    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.
    4441

  • Wellbore history
    General
    The appraisal well 6305/4-1 is located in the north western part of the direct hydrocarbon indicator (DHI) area of the Ormen Lange Field, in the eastern part of block 6305/4 in PL209. There were three main objectives for the well, all having equal priority. The first objective was to reduce the risk of the worst-case scenario of reservoir compartmentalisation. The second objective was to address the potential slide risk due to reservoir drainage of the main production area, and the third objective was to reduce the risk of worst-case GIIP through improved knowledge on the hydrocarbon distribution. Further important objectives were to test the reservoir quality closer to the NW margin of the gas field as well as to acquire a new check point for geophysical, geological and petrophysical interpretations.
    Operations and results
    The well was spudded on 16 March 2002 and reached a total depth of 2975 m in the Late Cretaceous Springar Formation. In general, the drilling conditions experienced in well 6305/4-1 are as predicted. The well was drilled with seawater and hi-vis pills to 1756 m and with KCl/polymer/glycol (Glydril) mud from 1756 m to TD. In tie-well 6305/5-1 problems with borehole instability was experienced in the Eocene deposits. No such problems were reported from well 6305/4-1, but loss of mud to the formation was experienced during the leak off test at 1749 m.
    All drilling objectives were met. All logging and well test objectives were met. The well proved good reservoir quality in the Egga Reservoir Unit, which was thinner than prognosed. A ôGas Down Toö situation was encountered in the lowermost Egga Formation. Isolated, overpressured water filled sands were found in the underlying units. Shows were recorded only in the reservoir section. A single day production test indicates dynamic sealing for parts of 3 of the 4 seismically interpreted faults, which surround the well location. One 60 ft core was cut in the Ooze section of the Brygge Formation from 1761 m to 1779 m (Core #1). Additional 3 x 60 ft cores were cut from 2769 m in the Egga reservoir sand to 2817.3 m. When Core # 3 was at rig floor it started to expand due to trapped gas. Approximately 1,5 - 2m of core came out of the inner barrel and partly disintegrated on rig floor. The upper part of the inner barrel contained therefore gaps between core pieces. As a result, the measured depths do not fit the actual depth of the reservoir for core # 3.
    Formation temperatures using Horner plots were estimated at 2660 m and 2975 m giving 72¦C and 84¦C, respectively. This gives an average formation temperature gradient of 4.31oC / 100m TVD assuming û1.8¦C at seafloor. It was prognosed a gradient of 4.4¦C. The small discrepancy may be due to the uncertainty of the method used. The result was within the range of data from nearby wells. The average gradient may be further divided into one gradient of 4,52¦C from seafloor to 2660 m and then one gradient of 3,81¦C from 2660 m to 2975 m. However, the long marine riser is known to cool down the mud to such an extent that the use of only Horner plots to estimate the formation temperature becomes doubtful. The well was tested and a temperature of 86,9¦C was estimated at 2783.5 m. This would give an average formation temperature gradient of 4,84¦C/ 100 m TVD, which is higher than prognosed. With a gradient of 4,84¦C/ 100 m TVD the BHST at TD (2975m) equals to 96,1¦C. Eight MDT samples were taken in the Reservoir at 2788.8 m. All eight recovered gas. One MDT sample taken at 2811.1 m recovered water.
    The well was permanently plugged and abandoned after testing as a gas appraisal well on 2 June 2002.
    Testing
    A production test was carried out, producing 1.87 mil Sm3 gas and 153 Sm3 condensate /day through a 80/64" choke at 135 bar.á

  • 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]
    1780.00
    2961.00

  • 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
    1761.0
    1778.6
    [m ]
    2
    2769.0
    2788.2
    [m ]
    3
    2788.0
    2806.4
    [m ]
    4
    2807.0
    2817.3
    [m ]
    Cores at the Norwegian Offshore Directorate
    Total core sample length [m]
    65.5
    Cores at the Norwegian Offshore Directorate
    Cores available for sampling?
    YES

  • Core photos
    Core photos
    Core photo at depth: 1761-1766m
    Core photo at depth: 1766-1771m
    Core photo at depth: 1771-1776m
    Core photo at depth: 1776-1778m
    Core photo at depth: 2769-2773m
    1761-1766m
    1766-1771m
    1771-1776m
    1776-1778m
    2769-2773m
    Core photo at depth: 2773-2777m
    Core photo at depth: 2777-2781m
    Core photo at depth: 2781-2785m
    Core photo at depth: 2785-2788m
    Core photo at depth: 2788-2792m
    2773-2777m
    2777-2781m
    2781-2785m
    2785-2788m
    2788-2792m
    Core photo at depth: 2792-2796m
    Core photo at depth: 2796-2800m
    Core photo at depth: 2800-2804m
    Core photo at depth: 2804-2806m
    Core photo at depth: 2807-2811m
    2792-2796m
    2796-2800m
    2800-2804m
    2804-2806m
    2807-2811m
    Core photo at depth: 2811-2815m
    Core photo at depth: 2815-2817m
    Core photo at depth:  
    Core photo at depth:  
    Core photo at depth:  
    2811-2815m
    2815-2817m

  • Palynological slides at the Norwegian Offshore Directorate
    Palynological slides at the Norwegian Offshore Directorate
    Sample depth
    Depth unit
    Sample type
    Laboratory
    1762.0
    [m]
    C
    OD
    1762.5
    [m]
    C
    RRI
    1762.9
    [m]
    C
    OD
    1765.5
    [m]
    C
    RRI
    1765.8
    [m]
    C
    OD
    1769.8
    [m]
    C
    OD
    1770.0
    [m]
    C
    OD
    1771.2
    [m]
    C
    RRI
    1771.9
    [m]
    C
    OD
    1780.0
    [m]
    C
    RRI
    1800.0
    [m]
    DC
    RRI
    1820.0
    [m]
    DC
    RRI
    1840.0
    [m]
    DC
    RRI
    1860.0
    [m]
    DC
    RRI
    1880.0
    [m]
    DC
    RRI
    1900.0
    [m]
    DC
    RRI
    1910.0
    [m]
    DC
    RRI
    1920.0
    [m]
    DC
    RRI
    1930.0
    [m]
    DC
    RRI
    1940.0
    [m]
    DC
    RRI
    1960.0
    [m]
    DC
    RRI
    1980.0
    [m]
    DC
    RRI
    2000.0
    [m]
    DC
    RRI
    2020.0
    [m]
    DC
    RRI
    2040.0
    [m]
    DC
    RRI
    2060.0
    [m]
    DC
    RRI
    2080.0
    [m]
    DC
    RRI
    2100.0
    [m]
    DC
    RRI
    2120.0
    [m]
    DC
    RRI
    2140.0
    [m]
    DC
    RRI
    2160.0
    [m]
    DC
    RRI
    2180.0
    [m]
    DC
    RRI
    2200.0
    [m]
    DC
    RRI
    2220.0
    [m]
    DC
    RRI
    2240.0
    [m]
    DC
    RRI
    2260.0
    [m]
    DC
    RRI
    2280.0
    [m]
    DC
    RRI
    2290.0
    [m]
    DC
    RRI
    2300.0
    [m]
    DC
    RRI
    2320.0
    [m]
    DC
    RRI
    2340.0
    [m]
    DC
    RRI
    2360.0
    [m]
    DC
    RRI
    2380.0
    [m]
    DC
    RRI
    2400.0
    [m]
    DC
    RRI
    2410.0
    [m]
    DC
    RRI
    2420.0
    [m]
    DC
    RRI
    2440.0
    [m]
    DC
    RRI
    2460.0
    [m]
    DC
    RRI
    2480.0
    [m]
    DC
    RRI
    2500.0
    [m]
    DC
    RRI
    2510.0
    [m]
    DC
    RRI
    2520.0
    [m]
    DC
    RRI
    2530.0
    [m]
    DC
    RRI
    2540.0
    [m]
    DC
    RRI
    2550.0
    [m]
    DC
    RRI
    2560.0
    [m]
    DC
    RRI
    2580.0
    [m]
    DC
    RRI
    2590.0
    [m]
    DC
    RRI
    2600.0
    [m]
    DC
    RRI
    2610.0
    [m]
    DC
    RRI
    2620.0
    [m]
    DC
    RRI
    2630.0
    [m]
    DC
    RRI
    2640.0
    [m]
    DC
    RRI
    2650.0
    [m]
    DC
    RRI
    2660.0
    [m]
    DC
    RRI
    2670.0
    [m]
    DC
    RRI
    2690.0
    [m]
    DC
    RRI
    2710.0
    [m]
    DC
    RRI
    2720.0
    [m]
    DC
    RRI
    2727.0
    [m]
    DC
    RRI
    2730.0
    [m]
    DC
    RRI
    2733.0
    [m]
    DC
    RRI
    2739.0
    [m]
    DC
    RRI
    2742.0
    [m]
    DC
    RRI
    2745.0
    [m]
    DC
    RRI
    2748.0
    [m]
    DC
    RRI
    2751.0
    [m]
    DC
    RRI
    2755.5
    [m]
    SWC
    RRI
    2757.0
    [m]
    SWC
    RRI
    2758.0
    [m]
    SWC
    RRI
    2758.7
    [m]
    SWC
    RRI
    2759.0
    [m]
    SWC
    RRI
    2759.6
    [m]
    SWC
    RRI
    2760.0
    [m]
    SWC
    RRI
    2764.0
    [m]
    SWC
    RRI
    2765.5
    [m]
    SWC
    RRI
    2767.5
    [m]
    SWC
    RRI
    2769.1
    [m]
    C
    RRI
    2769.5
    [m]
    C
    RRI
    2771.4
    [m]
    C
    RRI
    2773.3
    [m]
    C
    RRI
    2776.0
    [m]
    C
    RRI
    2777.3
    [m]
    C
    RRI
    2777.4
    [m]
    C
    RRI
    2779.7
    [m]
    C
    RRI
    2780.2
    [m]
    C
    RRI
    2781.7
    [m]
    C
    RRI
    2782.0
    [m]
    C
    RRI
    2783.5
    [m]
    C
    RRI
    2784.0
    [m]
    C
    RRI
    2784.2
    [m]
    C
    RRI
    2786.3
    [m]
    C
    RRI
    2787.9
    [m]
    C
    RRI
    2790.0
    [m]
    DC
    RRI
    2794.0
    [m]
    C
    RRI
    2794.7
    [m]
    C
    RRI
    2795.0
    [m]
    DC
    RRI
    2796.0
    [m]
    DC
    RRI
    2799.3
    [m]
    C
    RRI
    2800.6
    [m]
    C
    RRI
    2801.6
    [m]
    C
    RRI
    2802.0
    [m]
    DC
    RRI
    2802.5
    [m]
    C
    RRI
    2806.0
    [m]
    C
    RRI
    2808.0
    [m]
    DC
    RRI
    2808.6
    [m]
    C
    RRI
    2809.1
    [m]
    C
    RRI
    2810.3
    [m]
    C
    RRI
    2811.2
    [m]
    C
    RRI
    2812.2
    [m]
    C
    RRI
    2812.5
    [m]
    C
    RRI
    2812.8
    [m]
    C
    RRI
    2813.4
    [m]
    C
    RRI
    2814.0
    [m]
    DC
    RRI
    2814.0
    [m]
    C
    RRI
    2814.6
    [m]
    C
    RRI
    2815.5
    [m]
    C
    RRI
    2817.0
    [m]
    C
    RRI
    2819.0
    [m]
    SWC
    RRI
    2820.4
    [m]
    SWC
    RRI
    2821.5
    [m]
    SWC
    RRI
    2826.0
    [m]
    DC
    RRI
    2829.0
    [m]
    DC
    RRI
    2833.2
    [m]
    SWC
    RRI
    2835.0
    [m]
    DC
    RRI
    2835.5
    [m]
    SWC
    RRI
    2840.0
    [m]
    SWC
    RRI
    2841.0
    [m]
    DC
    RRI
    2844.0
    [m]
    DC
    RRI
    2853.0
    [m]
    DC
    RRI
    2856.0
    [m]
    DC
    RRI
    2859.0
    [m]
    DC
    RRI
    2862.0
    [m]
    DC
    RRI
    2865.0
    [m]
    DC
    RRI
    2871.0
    [m]
    DC
    RRI
    2877.0
    [m]
    DC
    RRI
    2880.0
    [m]
    DC
    RRI
    2883.0
    [m]
    DC
    RRI
    2886.0
    [m]
    DC
    RRI
    2889.0
    [m]
    DC
    RRI
    2892.0
    [m]
    DC
    RRI
    2898.0
    [m]
    DC
    RRI
    2904.0
    [m]
    DC
    RRI
    2910.0
    [m]
    DC
    RRI
    2916.0
    [m]
    DC
    RRI
    2925.0
    [m]
    DC
    RRI
    2931.0
    [m]
    DC
    RRI
    2937.0
    [m]
    DC
    RRI
    2943.0
    [m]
    DC
    RRI
    2949.0
    [m]
    DC
    RRI
    2955.0
    [m]
    DC
    RRI
    2961.0
    [m]
    DC
    RRI
    2967.0
    [m]
    DC
    RRI
    2970.0
    [m]
    DC
    RRI
    2973.0
    [m]
    DC
    RRI

  • Lithostratigraphy
    Lithostratigraphy
    Top depth [mMD RKB]
    Lithostrat. unit
    1027
    1027
    1662
    1701
    1701
    2394
    2394
    2529
    2769
    2829
    2829

  • Composite logs
    Composite logs
    Document name
    Document format
    Document size [MB]
    pdf
    0.28

  • 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
    0.54
    .PDF
    2.60
    .PDF
    1.07

  • Drill stem tests (DST)
    Drill stem tests (DST)
    Test number
    From depth MD
    [m]
    To depth MD
    [m]
    Choke size
    [mm]
    1.0
    2770
    2797
    31.7
    Drill stem tests (DST)
    Test number
    Final shut-in pressure
    [MPa]
    Final flow pressure
    [MPa]
    Bottom hole pressure
    [MPa]
    Downhole temperature
    [°C]
    1.0
    15.300
    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
    145
    1860000
    12827

  • Logs
    Logs
    Log type
    Log top depth [m]
    Log bottom depth [m]
    CMR+ HNGS
    2740
    2900
    DSI CSP GPIT EMS
    1765
    2674
    FMI DSI
    2713
    2964
    MDT
    2828
    2854
    MSCT
    2755
    2847
    MWD LWD - CDR
    1105
    1749
    MWD LWD - DIR
    1026
    1066
    MWD LWD - PP
    1026
    1108
    MWD LWD - PP ADN ARC GVR ISON
    1026
    1751
    MWD LWD - PP ARC5 RAB
    2719
    2975
    MWD LWD - PP CDR RAB
    2650
    2723
    MWD LWD - PP CDR RAB ADN ISON
    1749
    2786
    MWD LWD - PP VISION675 RAB
    2719
    2768
    PEX HALS SP
    996
    2692
    SP HRLA PEX
    2569
    2975
    VSP
    1100
    2960

  • 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
    1105.0
    36
    1108.0
    0.00
    LOT
    INTERM.
    20
    1749.0
    26
    1756.0
    1.40
    LOT
    INTERM.
    9 5/8
    2719.0
    12 1/4
    2725.0
    1.57
    LOT
    OPEN HOLE
    2975.0
    8 1/2
    2975.0
    0.00
    LOT

  • Drilling mud
    Drilling mud
    Depth MD [m]
    Mud weight [g/cm3]
    Visc. [mPa.s]
    Yield point [Pa]
    Mud type
    Date measured
    1022
    1.30
    WATER BASED
    1083
    1.10
    14.0
    WATER BASED
    1125
    1.03
    14.0
    WATER BASED
    1380
    1.03
    14.0
    WATER BASED
    1508
    1.07
    14.0
    WATER BASED
    1749
    1.25
    12.0
    WATER BASED
    1749
    0.00
    WATER BASED
    1756
    0.00
    WATER BASED
    2444
    1.30
    16.0
    WATER BASED
    2696
    1.30
    17.0
    WATER BASED
    2725
    1.33
    14.0
    WATER BASED
    2788
    1.30
    19.0
    WATER BASED
    2925
    1.32
    WATER BASED
    2974
    1.32
    16.0
    WATER BASED
    2975
    1.30
    17.0
    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]
    pdf
    0.30