Factpages Norwegian Offshore Directorate
Factpages Norwegian Offshore Directorate
Factpages Norwegian Offshore Directorate
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6406/8-1

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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.
    6406/8-1
    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).
    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
    Multilateral
    Indicator telling if the parent well is multilateral, meaning it has more than one branch radiating from the main borehole. Example of legal values: YES, NO. See also Norwegian Offshore Directorate guidelines for designation of wells and wellbores.
    NO
    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
    Well name
    Official name of the parent well for the wellbore based on Norwegian Offshore Directorate guidelines for designation of wells and wellbores.
    6406/8-1
    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.
    Elf Petroleum Norge 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.
    560-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.
    210
    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,
    15.09.1987
    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.
    11.04.1988
    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.
    11.04.1990
    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.
    28.06.2007
    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
    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 SHOWS
    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
    Kelly bushing elevation [m]
    Elevation of the rotary kelly bushing (RKB) above mean sea level.
    27.0
    Water depth [m]
    Depth in metres betweem mean sea level and sea floor.
    348.0
    Total depth (MD) [m RKB]
    Total measured length of wellbore from kelly bushing to total depth (driller's depth).
    4910.0
    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).
    4900.0
    Maximum inclination [°]
    Maximum deviation, in degrees, from a vertical well path.Shown only for released wells.
    6.3
    Bottom hole temperature [°C]
    Estimated temperature at final total depth of the wellbore. Shown only for released wells. See discription.
    172
    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.
    ÅRE FM
    Geodetic datum
    Reference system for coordinates. Example of legal values: ED50.
    ED50
    NS degrees
    Geographic coordinate of the wellhead, north-south degrees.
    64° 21' 55.01'' N
    EW degrees
    Geographic coordinate of the wellhead, east-west degrees.
    6° 26' 48.16'' E
    NS UTM [m]
    Universal Transverse Mercator coordinate of the wellhead, north-south.
    7140372.60
    EW UTM [m]
    Universal Transverse Mercator coordinate of the wellhead, east-west.
    376765.25
    UTM zone
    Universal Transverse Mercator zone. Examples of legal values: 31, 32, 33, 34.
    32
    NPDID wellbore
    Norwegian Offshore Directorate's unique id for the wellbore.
    1136

  • Wellbore history
    General
    Block 6406/8 is located on the Haltenbanken offshore Mid-Norway, in the southwestern corner of the Halten Terrace, approximately 215 km west north west of Trondheim. The primary objective of exploration well 6406/8-1 was to test the hydrocarbon potential in the Middle Jurassic Fangst group and the Lower Jurassic Båt group (Ror and Tilje formations). Possible intra-Cretaceous sands related to a seismic marker were considered as second target. Well 6406/8-1 was the first well drilled on the licence. It is located on a domal structure at the Base Cretaceous Unconformity. The prognosed TD for the well was 5027 m.
    Operations and results
    Well 6406/8-1 was spudded with the semi-submersible installation SSDV Vinni on 15 September 1987 and drilled to final TD at 4914 m in the Early Jurassic Åre Formation. The well was drilled water based.
    It was drilled initially to a total depth of 4942 m where it had penetrated the Fangst Group. The well kicked and the drill string was lost in the hole. Due to incomplete fishing operation a sidetracked well was drilled. The sidetrack was spudded on 22 January 1988 at 4262 m. The Fangst Group was once again penetrated and an intermediate logging was performed. Drilling commenced to 4914 m. Due to hazardous drilling with gains and stuck pipe it was agreed that 4914 m was to become the TD of this well. A final logging operation was made comprising FMT and RFT. The Fangst Group down to top Ile Formation was interpreted from data available from the first hole. Due to failed MWD and no wire line logs below 4500 m in the first hole the Båt Group is interpreted from the sidetrack. Horner corrected wire line log BHTs at TD gave a formation temperature of 172 deg C.
    Some gas dissolved in water was tested in the Ile Formation; otherwise no moveable hydrocarbons were seen in the well. Dull yellow spots and weak pale green cut fluorescence was described on sandstone from 3145 to 3190 m. Dull orange fluorescence and no cut was described on sandstone from 3985 to 4000 m. Orange/bright orange fluorescence with whitish cut fluorescence was seen on limestone from 4045 to 4060 m. All along the cores from 4368 to 4493 m, 5 to 20 % spots on sandstone with dull orange direct fluorescence and pale milky cut fluorescence was seen.
    Five cores were cut in the Fangst Group from 4370 m to 4499 m and one core was cut in the Båt Group, Ror Formation from 4649.5 m to 4659 m. No fluid samples were taken on wire line. The well was permanently abandoned on 11 April 1988 as a dry well with shows.
    Testing
    Two DST tests were performed in the well. DST 1 tested the Tilje Formation in the interval 4701 - 4718.0 m. It gave no flow to surface and all results showed a water bearing and tight formation. Maximum temperature during the 4 hours test was 161 deg C. DST 2 tested the Ile Formation between 4413.5 - 4453.5 m. The first two attempts (DST 2 and DST 2B) from this interval were aborted due to technical problems and bad weather. The third attempt (DST 2C) flowed ca 1050 Sm3 gas and 145 m3 water /day through a 16/64" choke. The gas gravity was 0.765 (air=1). Gas samples were taken in this test and analyses showed a gas containing 77% methane, 3% ethane, and 19% CO2 (volume/volume). The maximum temperature was 166.3 deg C, which is ca 10 deg higher than a linear temperature gradient drawn from the log-derived BHT at TD.
    Due to poor pressure recordings on wire line in the Fangst Group and uncertain formation water salinity, no test was performed in the Garn Formation.

  • 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]
    1320.00
    4905.00

  • 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
    4370.0
    4388.5
    [m ]
    2
    4388.5
    4416.0
    [m ]
    3
    4416.0
    4443.8
    [m ]
    4
    4443.8
    4471.7
    [m ]
    5
    4471.7
    4498.6
    [m ]
    6
    4649.5
    4658.9
    [m ]
    Cores at the Norwegian Offshore Directorate
    Total core sample length [m]
    138.0
    Cores at the Norwegian Offshore Directorate
    Cores available for sampling?
    YES

  • Core photos
    Core photos
    Core photo at depth: 4370-4375m
    Core photo at depth: 4375-4380m
    Core photo at depth: 4380-4385m
    Core photo at depth: 4385-4388m
    Core photo at depth: 4388-4389m
    4370-4375m
    4375-4380m
    4380-4385m
    4385-4388m
    4388-4389m
    Core photo at depth: 4393-4398m
    Core photo at depth: 4398-4403m
    Core photo at depth: 4403-4408m
    Core photo at depth: 4408-4413m
    Core photo at depth: 4413-4416m
    4393-4398m
    4398-4403m
    4403-4408m
    4408-4413m
    4413-4416m
    Core photo at depth: 4416-4421m
    Core photo at depth: 4421-4426m
    Core photo at depth: 4426-4431m
    Core photo at depth: 4431-4436m
    Core photo at depth: 4436-4441m
    4416-4421m
    4421-4426m
    4426-4431m
    4431-4436m
    4436-4441m
    Core photo at depth: 4441-4443m
    Core photo at depth: 4443-4448m
    Core photo at depth: 4448-4453m
    Core photo at depth: 4453-4458m
    Core photo at depth: 4458-4463m
    4441-4443m
    4443-4448m
    4448-4453m
    4453-4458m
    4458-4463m
    Core photo at depth: 4463-4468m
    Core photo at depth: 4468-4471m
    Core photo at depth: 4471-4476m
    Core photo at depth: 4476-4481m
    Core photo at depth: 4481-4486m
    4463-4468m
    4468-4471m
    4471-4476m
    4476-4481m
    4481-4486m
    Core photo at depth: 4486-4491m
    Core photo at depth: 4491-4496m
    Core photo at depth: 4496-4498m
    Core photo at depth: 4649-4654m
    Core photo at depth: 4654-4658m
    4486-4491m
    4491-4496m
    4496-4498m
    4649-4654m
    4654-4658m

  • 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
    DST2C
    0.00
    0.00
    YES
    DST
    DST2C
    4453.50
    4413.50
    WATER
    26.03.1988 - 20:15
    YES

  • 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
    436.0
    36
    477.0
    1.10
    LOT
    SURF.COND.
    20
    1301.0
    26
    1316.0
    1.50
    LOT
    INTERM.
    13 3/8
    2635.0
    17 1/2
    2650.0
    1.85
    LOT
    INTERM.
    9 5/8
    4195.0
    12 1/2
    4210.0
    2.09
    LOT
    INTERM.
    7
    4640.0
    8 1/2
    4649.0
    2.05
    LOT
    LINER
    5
    4914.0
    6
    4914.0
    0.00
    LOT

  • Drill stem tests (DST)
    Drill stem tests (DST)
    Test number
    From depth MD
    [m]
    To depth MD
    [m]
    Choke size
    [mm]
    1.0
    4718
    4711
    6.3
    2.0
    4413
    4453
    9.5
    Drill stem tests (DST)
    Test number
    Final shut-in pressure
    [MPa]
    Final flow pressure
    [MPa]
    Bottom hole pressure
    [MPa]
    Downhole temperature
    [°C]
    1.0
    71.000
    48.000
    2.0
    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
    2.0

  • Logs
    Logs
    Log type
    Log top depth [m]
    Log bottom depth [m]
    ACBL VDL GR
    375
    4195
    BHC GR
    4195
    4282
    CDL
    1300
    4191
    CDL CN GR
    4195
    4497
    CDL CN GR
    4360
    4907
    CN GR
    4334
    4497
    COREGUN GR
    1453
    2623
    COREGUN GR
    2660
    3585
    COREGUN GR
    3610
    4205
    DIFL AC GR
    4195
    4911
    DIFL BHC GR
    371
    1136
    DIFL BHC GR
    1300
    4497
    DIPLOG
    2631
    4207
    DIPLOG
    4195
    4911
    DLL MLL GR
    4361
    4642
    FMT HP
    4368
    4465
    MWD
    430
    4825
    RFT
    4671
    4713
    VELOCITY
    675
    4900

  • Lithostratigraphy

  • Composite logs
    Composite logs
    Document name
    Document format
    Document size [MB]
    pdf
    0.82

  • Geochemical information
    Geochemical information
    Document name
    Document format
    Document size [MB]
    pdf
    0.10
    pdf
    0.72
    pdf
    1.90

  • 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
    26.82

  • Drilling mud
    Drilling mud
    Depth MD [m]
    Mud weight [g/cm3]
    Visc. [mPa.s]
    Yield point [Pa]
    Mud type
    Date measured
    815
    1.08
    26.0
    8.8
    WATER BASED
    19.05.1987
    1805
    1.30
    34.0
    5.8
    WATER BASED
    05.10.1987
    2110
    1.31
    28.0
    5.8
    WATER BASED
    05.10.1987
    2236
    1.35
    36.0
    10.7
    WATER BASED
    06.10.1987
    2320
    1.40
    31.0
    8.8
    WATER BASED
    08.10.1987
    2444
    1.40
    36.0
    9.8
    WATER BASED
    08.10.1987
    2770
    1.65
    33.0
    7.8
    WATER BASED
    16.10.1987
    2956
    1.65
    40.0
    10.7
    WATER BASED
    19.10.1987
    2969
    1.72
    26.0
    7.8
    WATER BASED
    19.10.1987
    3095
    1.72
    34.0
    7.8
    WATER BASED
    20.10.1987
    3126
    1.75
    38.0
    10.7
    WATER BASED
    21.10.1987
    3190
    1.75
    28.0
    8.3
    WATER BASED
    22.10.1987
    3195
    1.75
    32.0
    8.8
    WATER BASED
    23.10.1987
    3264
    1.75
    38.0
    8.3
    WATER BASED
    26.10.1987
    3355
    1.74
    36.0
    9.3
    WATER BASED
    26.10.1987
    3442
    1.75
    37.0
    11.2
    WATER BASED
    26.10.1987
    3497
    1.75
    36.0
    12.2
    WATER BASED
    27.10.1987
    3526
    1.75
    42.0
    11.7
    WATER BASED
    28.10.1987
    3584
    1.75
    38.0
    8.8
    WATER BASED
    29.10.1987
    3655
    1.75
    38.0
    10.7
    WATER BASED
    30.10.1987
    3734
    1.75
    38.0
    9.8
    WATER BASED
    02.11.1987
    3802
    1.75
    35.0
    9.8
    WATER BASED
    02.11.1987
    3886
    1.75
    36.0
    10.7
    WATER BASED
    03.11.1987
    3933
    1.75
    35.0
    10.7
    WATER BASED
    03.11.1987
    3958
    1.75
    38.0
    9.8
    WATER BASED
    05.11.1987
    4015
    1.75
    38.0
    10.7
    WATER BASED
    06.11.1987
    4130
    1.75
    37.0
    9.8
    WATER BASED
    09.11.1987
    4200
    1.75
    36.0
    9.8
    WATER BASED
    09.11.1987
    4219
    1.57
    35.0
    8.3
    WATER BASED
    18.11.1987
    4262
    1.57
    28.0
    10.7
    WATER BASED
    19.11.1987
    4286
    1.57
    35.0
    7.8
    WATER BASED
    20.11.1987
    4301
    1.57
    31.0
    6.8
    WATER BASED
    23.11.1987
    4349
    1.57
    33.0
    7.8
    WATER BASED
    23.11.1987
    4351
    1.57
    34.0
    7.8
    WATER BASED
    23.11.1987
    4351
    1.57
    37.0
    7.3
    WATER BASED
    24.11.1987
    4443
    1.57
    36.0
    8.8
    WATER BASED
    26.11.1987
    4443
    1.65
    33.0
    6.8
    WATER BASED
    27.11.1987
    4450
    1.84
    68.0
    11.7
    WATER BASED
    27.01.1988
    4472
    1.68
    39.0
    7.8
    WATER BASED
    30.11.1987
    4555
    1.77
    46.0
    5.8
    WATER BASED
    07.12.1987
    4578
    1.84
    66.0
    14.7
    WATER BASED
    28.01.1988
    4616
    1.77
    45.0
    10.7
    WATER BASED
    07.12.1987
    4649
    1.84
    66.0
    13.7
    WATER BASED
    29.01.1988
    4649
    1.77
    42.0
    17.6
    WATER BASED
    07.12.1987
    4668
    1.77
    45.0
    10.7
    WATER BASED
    09.12.1987
    4751
    1.77
    60.0
    2.9
    WATER BASED
    10.12.1987
    4752
    1.84
    78.0
    15.6
    WATER BASED
    08.02.1988
    4760
    1.77
    46.0
    11.7
    WATER BASED
    11.12.1987
    4763
    1.77
    42.0
    10.7
    WATER BASED
    14.12.1987
    4786
    1.77
    34.0
    13.7
    WATER BASED
    14.12.1987
    4852
    1.84
    68.0
    13.7
    WATER BASED
    09.02.1988
    4901
    1.78
    48.0
    8.8
    WATER BASED
    15.12.1987
    4914
    1.84
    63.0
    14.7
    WATER BASED
    10.02.1988
    4926
    1.77
    56.0
    11.7
    WATER BASED
    16.12.1987
    4942
    1.79
    43.0
    9.8
    WATER BASED
    17.12.1987

  • Palynological slides at the Norwegian Offshore Directorate
    Palynological slides at the Norwegian Offshore Directorate
    Sample depth
    Depth unit
    Sample type
    Laboratory
    2590.0
    [unknown]
    DC
    RRI
    2610.0
    [unknown]
    DC
    RRI
    2630.0
    [unknown]
    DC
    RRI
    2650.0
    [unknown]
    DC
    RRI
    2670.0
    [unknown]
    DC
    RRI
    2690.0
    [unknown]
    DC
    RRI
    2710.0
    [unknown]
    DC
    RRI
    2730.0
    [unknown]
    DC
    RRI
    2750.0
    [unknown]
    DC
    RRI
    2770.0
    [unknown]
    DC
    RRI
    2790.0
    [unknown]
    DC
    RRI
    2810.0
    [unknown]
    DC
    RRI
    2830.0
    [unknown]
    DC
    RRI
    2850.0
    [unknown]
    DC
    OD
    2870.0
    [unknown]
    DC
    RRI
    2890.0
    [unknown]
    DC
    RRI
    2910.0
    [unknown]
    DC
    RRI
    2930.0
    [unknown]
    DC
    RRI
    2950.0
    [unknown]
    DC
    OD
    2970.0
    [unknown]
    DC
    RRI
    2990.0
    [unknown]
    DC
    RRI
    3010.0
    [unknown]
    DC
    RRI
    3040.0
    [unknown]
    DC
    RRI
    3050.0
    [unknown]
    DC
    OD
    3070.0
    [unknown]
    DC
    RRI
    3090.0
    [unknown]
    DC
    RRI
    3110.0
    [unknown]
    DC
    RRI
    3130.0
    [unknown]
    DC
    RRI
    3150.0
    [unknown]
    DC
    OD
    3170.0
    [unknown]
    DC
    RRI
    3190.0
    [unknown]
    DC
    RRI
    3210.0
    [unknown]
    DC
    RRI
    3230.0
    [unknown]
    DC
    RRI
    3250.0
    [unknown]
    DC
    OD
    3270.0
    [unknown]
    DC
    RRI
    3290.0
    [unknown]
    DC
    RRI
    3310.0
    [unknown]
    DC
    RRI
    3330.0
    [unknown]
    DC
    RRI
    3350.0
    [unknown]
    DC
    OD
    3370.0
    [unknown]
    DC
    RRI
    3390.0
    [unknown]
    DC
    RRI
    3410.0
    [unknown]
    DC
    RRI
    3430.0
    [unknown]
    DC
    RRI
    3450.0
    [unknown]
    DC
    OD
    3470.0
    [unknown]
    DC
    RRI
    3490.0
    [unknown]
    DC
    RRI
    3510.0
    [unknown]
    DC
    RRI
    3530.0
    [unknown]
    DC
    RRI
    3550.0
    [unknown]
    DC
    OD
    3570.0
    [unknown]
    DC
    RRI
    3590.0
    [unknown]
    DC
    RRI
    3610.0
    [unknown]
    DC
    RRI
    3630.0
    [unknown]
    DC
    RRI
    3650.0
    [unknown]
    DC
    OD
    3670.0
    [unknown]
    DC
    RRI
    3690.0
    [unknown]
    DC
    RRI
    3710.0
    [unknown]
    DC
    RRI
    3730.0
    [unknown]
    DC
    RRI
    3750.0
    [unknown]
    DC
    OD
    3770.0
    [unknown]
    DC
    RRI
    3790.0
    [unknown]
    DC
    RRI
    3810.0
    [unknown]
    DC
    RRI
    3830.0
    [unknown]
    DC
    RRI
    3850.0
    [unknown]
    DC
    OD
    3870.0
    [unknown]
    DC
    RRI
    3890.0
    [unknown]
    DC
    RRI
    3910.0
    [unknown]
    DC
    RRI
    3925.0
    [unknown]
    DC
    RRI
    3950.0
    [unknown]
    DC
    OD
    3970.0
    [unknown]
    DC
    RRI
    3990.0
    [unknown]
    DC
    RRI
    4010.0
    [unknown]
    DC
    RRI
    4030.0
    [unknown]
    DC
    RRI
    4050.0
    [unknown]
    DC
    OD
    4070.0
    [unknown]
    DC
    RRI
    4090.0
    [unknown]
    DC
    RRI
    4110.0
    [unknown]
    DC
    4150.0
    [unknown]
    DC
    OD
    4250.0
    [unknown]
    DC
    OD
    4460.8
    [unknown]
    C
    4650.4
    [unknown]
    C
    4650.4
    [unknown]
    C
    4658.9
    [unknown]
    C
    4658.9
    [unknown]
    C
    I.S.P.G