COGIS - COA/BMP Information

GMT EXPLORATION COMPANY LLC           L&S 3-65-12-11-11HN           Well API # 05-001-10417           Status: XX        Status Date: 03/06/2019           Location ID #:463062       NESE 12 3S 65W ADAMS

COGIS - Conditions of Approval
COA Search Results - 5 record(s) returned.
Source
Document
Conditions of Approval
Form: (02 )
401682899
03/06/2019
COGCC COA: Operator will insure the wellbore beyond the unit boundary setback is physically isolated and is not completed. In the Operator Comments on the Form 5A the operator will (1) report the footages from the section lines of the bottom of the completed interval (2) describe how the wellbore beyond the unit boundary setback is physically isolated and (3) certify that none of the wellbore beyond the setback was completed.
Form: (02 )
401682899
03/06/2019
Per COGCC Order 1-232, Bradenhead tests shall be performed according to the following schedule and Form 17 submitted within 10 days of each test: 1) Within 60 days of rig release, prior to stimulation. If any pressure greater than 200 psi, must contact COGCC engineer prior to stimulation. 2) If a delayed completion, 6 months after rig release and prior to stimulation. If any pressure greater than 200 psi, must contact COGCC engineer prior to stimulation. 3) A post-production test within 60 days after first sales, as reported on the Form 10, Certificate of Clearance.
Form: (02 )
401682899
03/06/2019
Operator acknowledges the proximity of the listed non-operated well: Operator agrees to: provide mitigation option 3 (per the DJ Basin Horizontal Offset Policy) to mitigate the situation, ensure all applicable documentation is submitted based on the selected mitigation option chosen, and submit a Form 42 (“OFFSET MITIGATION COMPLETED”) for the remediated wells, referencing the API number of the proposed horizontal well(s) stating what appropriate mitigation occurred and that it has been completed, prior to the hydraulic stimulation of these wells. Champlin 249 Amoco A-1 (API 001-07102) Bass Box Elder Farms 10-33 (API 001-08450) Box Elder Farms 11-24 (API 001-08871) Webb-Champlin 12-6 (API 001-06993) Webb Champlin 12-6X (API 001-07081) Linnebur 44-12 (API 001-08060) Bass Linnebur 12-31 (API 001-08420)
Form: (02 )
401682899
03/06/2019
Operator acknowledges the proximity of the following non-operated listed wells: Operator agrees to: provide mitigation option 1 or 2 (per the DJ Basin Horizontal Offset Policy) to mitigate the situation, ensure all applicable documentation is submitted based on the selected mitigation option chosen, and submit a Form 42 (“OFFSET MITIGATION COMPLETED”) for the remediated wells, referencing the API number of the proposed horizontal well(s) stating what appropriate mitigation occurred and that it has been completed, prior to the hydraulic stimulation of this well. UPRR Amoco 1-13 (API 001-07656) Jeff Drohan 2-16 (API 001-06886) Cottonwood-UPRR 248-1 (API 001-08446) Amoco-UPRR 11-10 (API 001-08461) Liberty 1 (API 001-08818) Amoco-UPRR 11-10X (API 001-08926) Bass Linnebur 12-21 (API 001-08329)
Form: (02 )
401682899
03/06/2019
1) Submit Form 42 electronically to COGCC 48 hours prior to MIRU (spud notice) for the first well activity with a rig on the pad and provide 48 hour spud notice via Form 42 for all subsequent wells drilled on the pad. 2) Comply with Rule 317.j. and provide cement coverage from TD to a minimum of 200' above Niobrara. Verify coverage with cement bond log. 3) Oil-based drilling fluid is to be used only after all fresh water aquifers are covered.


COGIS - Best Management Practices
BMPSearch Results - 4 record(s) returned.
Source
Document
BMP TypeBMP
Form: (02 )
401682899
03/06/2019
Drilling/Completion Operations
Prior to drilling operations, operator will perform an anti-collision scan of existing wells that have the potential of being within close proximity of the proposed well. This anti-collision scan will include definitive MWD or gyro surveys of the offset wells with included error of uncertainty per survey instrument, and compared against the proposed well path with its respective error of uncertainty. If current surveys do not exist for the offset wells, operator may have gyro surveys conducted to verify bottom hole location. The proposed well will only be drilled if the anti-collision scan results indicate that there is not a risk for collision, or harm to people or the environment.
Form: (02 )
401682899
03/06/2019
Drilling/Completion Operations
Alternative Logging Program: One of the first wells drilled on the pad will be logged with Open Hole Resistivity Log and Gamma Ray Log from the kick-off point to into the surface casing. All wells on the pad will have a cement bond log with gamma-ray run on production casing (or on intermediate casing if production liner is run) into the surface casing. The horizontal portion of every well will be logged with a measured-while-drilling gamma-ray log. The form 5, Completion Report, for each well on the pad will list all logs run and have those logs attached. The Form 5 for a well without open-hole logs shall clearly state "Alternative Logging Program - No open-hole logs were run" and shall clearly identify (by API#, well name & number) the well in which open-hole logs were run.
Form: (02 )
401682899
03/06/2019
Drilling/Completion Operations
No drill stem test will be performed.
Form: (02 )
401682899
03/06/2019
Drilling/Completion Operations
Upon initial rig up and at least once every thirty (30) days during drilling operations thereafter, pressure testing of the casing string and each component of the blow out equipment including flange connections will be performed to seventy percent (70%) of the internal yield of casing, whichever is less. Pressure testing will be conducted. The documented results will be retained by operator for inspection by the Director for a period of one (1) year. Activation of the pipe rams for function testing shall be conducted daily when practical. A BOP with a minimum pressure rating of three thousand (3,000) psi will be utilized. At a minimum, it will consist of two (2) ram preventers and one (1) annular preventer. A backup system of pressure control will be onsite consisting of a minimum of one thousand (1,000) psi accumulator. All onsite representatives will be certified in Well Control Operations.