Skip to Main Content

COGIS DB
 
Facility TypeFacility ID/
API		Facility Name/
Number		Operator Name/
Number		StatusField Name/
Number		LocationLocation IDRelated Facilities
WELL05-001-09908Ivey LC
02-036HC 		PDC ENERGY INC
69175		PA
4/14/2025		WATTENBERG
90750		ADAMS  001
SWSE 11 1S68W 6		442411View Related
 
COGIS - Conditions of Approval Results
TypeSource DocumentConditions of Approval
EngineerForm: (02 )
400853357
7/12/2015		1) Submit Form 42 electronically to COGCC 48 hours prior to MIRU for first well on pad, subsequent wells 48 hours prior to spud. 2) Comply with Rule 317.j. and provide cement coverage from end of 7” casing to a minimum of 200' above Niobrara and from 200’ below Sussex to 200’ above Sussex. Verify coverage with cement bond log.
EngineerForm: (02 )
400853357
11/15/2015		Operator acknowledges the proximity of the 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”) stating that appropriate mitigation occurred and that it has been completed, prior to the hydraulic stimulation of this well. REHFELD K UNIT 1, API # 001-08886, SACK #1 API # 001-07059 BYDALAK #1-11 API # 001-08368, BYDALEK #2-11 API # 001-08881 SACK G UNIT #1 API # 001-08895
PermitForm: (02 )
402125793
10/7/2019		Drilling Beyond the Unit Boundary Setback: Operator will ensure 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.
EngineerForm: (02 )
402125793
10/21/2020		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.
EngineerForm: (02 )
402125793
10/21/2020		Operator acknowledges the proximity of the listed well. Operator assures that this offset list will be remediated per the DJ Basin Horizontal Offset Policy (option 4). Operator will submit a Form 42 (“OTHER – AS SPECIFIED BY PERMIT CONDITION”) stating that appropriate mitigation will be completed, during the hydraulic stimulation of this well. This Form 42 shall be filed 48 hours prior to stimulation. Operator will assure that the well’s Bradenhead is open and monitored during the entire stimulation treatment – a person will monitor for any evidence of fluid, a Bradenhead test will be performed prior to the beginning of stimulation. 05-001-08886 Rehfeld K Unit 1
EngineerForm: (02 )
402125793
10/21/2020		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. 05-001-08905 York G Unit 1
EngineerForm: (02 )
402125793
10/21/2020		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. 05-001-07059 Sack 1 05-001-08895 Sack G Unit 1
EngineerForm: (02 )
402125793
10/21/2020		1) Submit Form 42 electronically to COGCC 48 hours prior to MIRU (Spud Notice), for the first well/activity on the pad and provide 48 hour spud notice for all subsequent wells drilled on the pad. 2) Comply with Rule 317.j. and provide cement coverage from TD to a minimum of 500' above Niobrara and from 200’ below Sussex to 500’ above Sussex. Verify coverage with cement bond log. 3) Oil-based drilling fluid is to be used only after all fresh water aquifers are covered.
EngineerForm: (04 )
402736375
7/2/2021		The additional cement referenced shall be placed as indicated and comply with Rule 408.j. The placed cement shall be verified with a CBL and documented with a Form 5 Drilling Completion Report.
EngineerForm: (04 )
403080124
6/16/2022		1. Operator will implement measures to control venting, to protect health and safety, and to ensure that vapors and odors from well operations do not constitute a nuisance or hazard to public welfare. 2. Prior to starting bradenhead mitigation, if a sample has not been collected within the last twelve months collect bradenhead and production gas samples for laboratory analysis. Sampling will comply with Operator Guidance - Bradenhead Testing and Reporting Instructions, Appendix A: Liquid and Gas Sampling. Copies of all final laboratory analytical results will be provided to the COGCC within three months of collecting the samples. 3. Operator will implement measures to get an initial estimate of the gas flow rate and/or volume from the bradenhead. During the shut-in period record pressure data to adequately characterize the build-up. This mitigation plan may be used for six consecutive months from the date test reported on the Form 17. 4. At the conclusion of the six months (12/15/2022), conduct a new bradenhead test and submit the Form 17 within ten days of the test and submit a Form 4 Sundry that summarizes current well condition. The sundry should include details of the future plans, sample analysis interpretation, and the flow rate information and pressure data.
EngineerForm: (04 )
403294790
1/19/2023		1. Operator shall implement measures to control venting, to protect health and safety, and to ensure that vapors and odors from well operations do not constitute a nuisance or hazard to public welfare. 2. Bradenhead gas is not to be vented to the atmosphere; any gas from the Bradenhead will be routed to the specified abatement system. Shut in bradenhead pressure shall not exceed 50 psig. Operator shall implement measures to get an estimate of the gas flow rate and/or volume from the bradenhead. 3. Within thirty days of 10/19/2023, submit a Form 4 Sundry that summarizes current well condition. The sundry should include details of the future plans, sample analysis interpretation, bradenhead test description, and the flow rate information and pressure data. 4. Shut well in for at least seven days to monitor build up pressures then conduct a new bradenhead test and submit the Form 17 within ten days of the test. 5. If a sample has not been collected from surface casing within the last twelve months collect bradenhead gas samples for laboratory analysis. Sampling shall comply with Operator Guidance - Bradenhead Testing and Reporting Instructions, Appendix A: Liquid and Gas Sampling. Copies of all final laboratory analytical results shall be provided to the COGCC within three months of collecting the samples.
EngineerForm: (04 )
403459448
7/11/2023		1. Operator shall implement measures to control venting, to protect health and safety, and to ensure that vapors and odors from well operations do not constitute a nuisance or hazard to public welfare. 2. Bradenhead gas is not to be vented to the atmosphere; any gas from the Bradenhead will be routed to the specified abatement system. Shut in bradenhead pressure shall not exceed 50 psig. Operator shall implement measures to get an estimate of the gas flow rate and/or volume from the bradenhead. 3. Within thirty days of 06/22/2024, submit a Form 4 Sundry that summarizes current well condition. The sundry should include details of the future plans, sample analysis interpretation, bradenhead test description, and the flow rate information and pressure data. 4. Shut well in for at least seven days to monitor build up pressures then conduct a new bradenhead test and submit the Form 17 within ten days of the test. 5. If a sample has not been collected from surface casing within the last twelve months collect bradenhead gas samples for laboratory analysis. Sampling shall comply with Operator Guidance - Bradenhead Testing and Reporting Instructions, Appendix A: Liquid and Gas Sampling. Copies of all final laboratory analytical results shall be provided to the ECMC within three months of collecting the samples.
PermitForm: (06 )
404050411
1/7/2025		Submit “as drilled” GPS data on Subsequent Report of Abandonment. GPS data must meet the requirements of Rule 216.
EngineerForm: (06 )
404050411
1/15/2025		1) Provide electronic Form 42 Notice of MIRU 2 business days ahead of operations and electronic Form 42 Notice of Plugging Operations 48 hours prior to mobilizing for plugging operations. These are two separate notifications, required by Rules 405.e and 405.l. 2) Prior to placing cement above the base of the Upper Pierre (2240') : verify that all fluid (liquid and gas) migration has been eliminated. If evidence of fluid migration or pressure remains, contact ECMC Engineer for an update to plugging orders. 3) Pump surface casing shoe plug at 2227' only after isolation has been verified. If surface casing cement is not circulated to surface, shut-in, WOC 4 hours then tag plug – must be at 1977' or shallower and provide a minimum of 10 sx plug at the surface. 4)Pump aquifer plugs plug at 1927' only after isolation has been verified. If surface casing cement is not circulated to surface, shut-in, WOC 4 hours then tag plug – must be at 248' or shallower. 4) Leave at least 100’ of cement in the wellbore for each plug without mechanical isolation. 5) After cut and prior to cap, verify isolation by either a 15 minute bubble test or 15 minute optical gas imaging recording. If there is indication of flow contact ECMC Engineering. Provide a statement on the 6SRA which method was used and what was observed. Retain records of final isolation test for 5 years. 6) With the Form 6 SRA operator must provide written documentation which positively affirms each COA listed above has been addressed.
EngineerForm: (06 )
404050411
1/15/2025		Consistent with Rule 911.a, a Form 27 must be approved prior to cut and cap, conducting flowline abandonment, or removing production equipment. Allow 30 days for Director review of the Form 27; include the Form 27 document number on the Form 44 for offsite flowline abandonment (if applicable) and on the Form 6 Subsequent. Properly abandon flowlines per Rule 1105. If flowlines will be abandoned in place, include with the Form 27: pressure test results conducted in the prior 12 months as well as identification of any document numbers for a ECMC Spill/Release Report, Form 19, associated with the abandoned line.
EngineerForm: (06 )
404050411
1/15/2025		Prior to starting plugging operations a bradenhead test shall be performed if there has not been a reported bradenhead test within the 60 days immediately preceding the start of plugging operations. 1) If, before opening the bradenhead valve, the beginning pressure is greater than 25 psi, sampling is required. 2) If pressure remains at the conclusion of the test, or if any liquids were present during the test, sampling is required. The Form 17 shall be submitted within 10 days of the test. Sampling shall comply with Operator Guidance - Bradenhead Testing and Reporting Instructions. If samples are collected, copies of all final laboratory analytical results shall be provided to the ECMC within three (3) months of collecting the samples. If there is a need for sampling, contact ECMC engineering for verification of plugging procedure.
OGLAForm: (06 )
404050411
1/15/2025		Operator provided COAs:  3rd party wildlife surveys will be conducted on this well prior to rigging up for P&A activities. Should sensitive HPH conditions be identified during the screening process, Chevron will delay the work until conditions (nesting) clear and/or consult directly with CPW for guidance and discussion of potential mitigation measures that may be incorporated. Notification will be given to any adjacent building unit occupants within a 1000 feet of the wellhead of planned P&A start date.
OGLAForm: (06 )
404050411
1/15/2025		This oil and gas location is located within a CPW-mapped 500 foot buffer of the Ordinary High Water Mark of Dry Creek for protection of Aquatic Native Species Conservation Water High Priority Habitat. At a minimum, Operator will review the stormwater program and implement stormwater BMPs and erosion control measures as needed to prevent fine-grained sediment and impacted stormwater runoff from entering surface water. Operator will use secondary containment for all tanks and other liquid containers. 
EngineerForm: (06 )
404050411
1/15/2025		Operator shall implement measures to control venting, to protect health and safety, and to ensure that vapors and odors from well plugging operations do not constitute a nuisance or hazard to public welfare.
 
COGIS - Best Management Practice Results
BMP TypeSource DocumentBest Management Practices
PlanningForm: (02 )
400853357
11/20/2015		Multi-well Pads. It is a multi-well pad located in a manner which allows for resource extraction while maintaining the highest distances posssible from the offsetting residential areas.
Traffic controlForm: (02 )
400853357
11/20/2015		Access roads. The access road will be constructed to accommodate local emergency vehicles. This road will be maintained for access at all times.
General HousekeepingForm: (02 )
400853357
11/20/2015		Fencing requirements. A permanent fencing plan will be reviewed by the surface owner, and the applicant.
General HousekeepingForm: (02 )
400853357
11/20/2015		Removal of surface trash. All trash, debris and material not intrinsic to the operation of the oil and gas facility shall be removed and legally disposed of as is applicable.
Material Handling and Spill PreventionForm: (02 )
400853357
11/20/2015		Leak Detection Plan. Pumper will visit the location daily and visually inspect all tanks and fittings for leaks. Additionally, monthly documented SPCCP inspections are conducted pursuant to 40 CFR 112.
Material Handling and Spill PreventionForm: (02 )
400853357
11/20/2015		Berm Construction. Tank berms shall be constructed of steel rings with a synthetic or engineered liner and designed to contain 150% of the capacity of the largest tank. All berms will be visually checked periodically to ensure proper working condition.
Material Handling and Spill PreventionForm: (02 )
400853357
11/20/2015		Load Lines. All load lines shall be bull-plugged or capped.
Material Handling and Spill PreventionForm: (02 )
400853357
11/20/2015		Tank specifications. Tanks will be designed, constructed and maintained in accordance with NFPA Code 30. The tanks are visually inspected once a day for issues and recorded inspections are conducted once a month.
Drilling/Completion OperationsForm: (02 )
400853357
11/20/2015		Green Completions - Emission Control Systems. Test separators and associated flow lines and sand traps shall be installed on-site to accommodate Green completion techniques pursuant to COGCC Rules. In the anticipated absence of a viable gas sales line, the flow-back gas shall be thermally oxidized in an emissions control device (ECD), which will be installed and kept in operable condition for at least the first 90 days of production pursuant to CDPHE rules. The ECD shall have an adequate capacity for 1.5 times the largest flow-back within a 10 mile radius, will be flanged to route gas to other or permanent oxidizing equipment and shall be provided with the equipment needed to maintain combustion where non-combustible gases are present.
Drilling/Completion OperationsForm: (02 )
400853357
11/20/2015		Blowout preventer equipment ("BOPE"). A double ram and annular preventer will be used during drilling. At least the drilling company shall have a valid well blowout prevention certifications.
Drilling/Completion OperationsForm: (02 )
400853357
11/20/2015		BOPE for well servicing operations. Adequate BOP equipment shall be used. Stabbing valves shall be installed in the event of reverse circulationand shall be prior tested with low and high pressure fluid.
Drilling/Completion OperationsForm: (02 )
400853357
11/20/2015		Drill stem tests. Not applicable, no Drill stem tests are planned.
Drilling/Completion OperationsForm: (02 )
400853357
11/20/2015		Control of Fire Hazards. All materials which are considered fire hazards shall be a minimum of 25' from the wellhead tanks or separators. Electrical equipment shall comply with API RP 500 and will comply with the current national electrical code. An emergency response plan has been generated for this site.
Drilling/Completion OperationsForm: (02 )
400853357
11/20/2015		Guy line anchors. All guy line anchors shall be brightly marked pursuant to Rule 604.c(2)Q.
Drilling/Completion OperationsForm: (02 )
400853357
11/20/2015		Closed Loop Drilling Systems - Pit Restrictions. Not Applicable; a closed loop system will be used for drilling.
Drilling/Completion OperationsForm: (02 )
400853357
11/20/2015		Pit Level indicators. Not applicable; a closed-loop system will be used and no pits shall be dug.
Drilling/Completion OperationsForm: (02 )
400853357
11/20/2015		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 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 “No open-hole logs were run” and shall clearly identify (by API#, well name & number) the well in which open-hole logs were run.
Drilling/Completion OperationsForm: (02 )
400853357
11/20/2015		Anti-collision: Prior to drilling operations, Operator will perform an anti-collision scan of existing offset 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 wellpath with its respective error of uncertainty. If current surveys do not exist for the offset wells, Operator may have gyro surveys conducted to verify bottomhole 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.  For the proposed well, upon conclusion of drilling operations, an as-constructed gyro survey will be submitted to COGCC with the Form 5.
Drilling/Completion OperationsForm: (02 )
400853357
11/20/2015		Operator will comply with COGCC Policy for Bradenhead Monitoring During Hydraulic Fracturing Treatments in the Greater Wattenberg Area dated May 29, 2012. (attached)
Final ReclamationForm: (02 )
400853357
11/20/2015		Well site cleared. Within 90 days subsequent to the time of plugging and abandonment of the entire site, superfluous debris and equipment shall be removed from the site.
Final ReclamationForm: (02 )
400853357
11/20/2015		Identification of plugged and abandoned wells. P & A'd wells shall be identified pursuant to 319.a.(5).
Drilling/Completion OperationsForm: (02 )
402125793
11/10/2020		Drill stem tests (Rule 604.c.(2)L Conventional drill stem tests will not be conducted on DJ Basin horizontal wells currently being executed or planned by GWOC. If plans change in the future a well specific drill stem testing plan will be prepared for that particular well. Note that GWOC may elect to use one of several available wireline deployed tools for the purpose of measuring down hole formation pressures and/or collecting down hole fluid samples from the target formation(s) of a particular well.
Drilling/Completion OperationsForm: (02 )
402125793
11/10/2020		Wellbore Collision Prevention – Rule 317.r Prior to drilling operations, GWOG will perform an anti-collision scan of existing offset 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.
Drilling/Completion OperationsForm: (02 )
402125793
11/10/2020		BOPE for well servicing (Rule 604.c.(2)J A BOPE with a minimum pressure rating of 3,000 psi will be utilized. At a minimum it will consist of 2 ram preventers and 1 annular preventer. The blind rams will be positioned below the pipe rams. A backup system of pressure control will be onsite consisting of at a minimum 1,000 psi accumulator (backup pressure). Accumulator is tested to 1,000 psi. Operator may use fixed sized pipe rams matching the tubular size. The annular preventer will be pressure tested to 250 psi low and 2,000 psi high for 10 minutes each. The ram preventers will be tested to 250 psi low and 2,500 psi high for 10 minutes each. All remaining well control equipment will be tested to 250 psi low and 2,500 psi high for 10 minutes each. The pressure tests will be conducted when the equipment is first installed and every 30 days thereafter. Pipe rams and blind rams will be function tested before every well service operation. Annual BOP inspections and pressure tests will be performed by the service company and will be charted & retained for 1 year. Backup stabbing valves shall be used on operations that require reverse circulation. Valves will be pressure tested before each well service operation in low pressure and high pressure range. The GWOC onsite representative will be certified in Well Control Operations by a Well-Cap certified training service.
Drilling/Completion OperationsForm: (02 )
402125793
11/10/2020		Bradenhead Monitoring GWOC will comply with the “COGCC Policy for Bradenhead Monitoring during Hydraulic Fracturing Treatments in the Greater Wattenberg Area”, dated May 29, 2012.
12