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Facility TypeFacility ID/
API		Facility Name/
Number		Operator Name/
Number		StatusField Name/
Number		LocationLocation IDRelated Facilities
WELL05-123-39073Becker Ranch
5E-223 		PDC ENERGY INC
69175		PA
6/19/2025		WATTENBERG
90750		WELD  123
NWNW 5 3N64W 6		436361View Related
 
COGIS - Conditions of Approval Results
TypeSource DocumentConditions of Approval
EngineerForm: (02)
400521567
02/04/2014		Operator acknowledges the proximity of The Becker 5-2 ( API NO 123-13742), the Becker 5-7 ( API NO 123-13764), the Becker 5-8 (API NO 123-13839), the Becker 5-3 (API NO 123-17299), the Becker 5-11 ( API NO 123-17300), the Becker 5-13 ( API NO 123-17302), the Becker 5-14 (API NO 123-18180), and the Dechant 7-11 (API NO 123-15476). 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 (“OTHER – AS SPECIFIED BY PERMIT CONDITION”) stating what appropriate mitigation occurred and that it has been completed, prior to the hydraulic stimulation of this well.
EngineerForm: (02)
400521567
02/04/2014		Operator acknowledges the proximity of the non-operated wells: The McKenney 6-2 (API NO 123-11907), the McKenney 6-3 (API NO 123-14815), the McKenney 6-14 (API NO 123-15780), the UPRR OCOMA II C31-16 (API NO 123-13603), the Howell 1 (API NO 123-07827), and the McGuirk-Howell C 32-14 (API NO 123-15882). Operator assures that these offsets will be remediated per the DJ Basin Horizontal Offset Policy (options 1 or 2) or operator will address this well with mitigation option 4. Operator will submit a Form 42 (“OTHER – AS SPECIFIED BY PERMIT CONDITION”) stating what appropriate mitigation occurred and that it has been completed, prior to the hydraulic stimulation of this well.
EngineerForm: (02)
400521567
02/04/2014		1) Submit Form 42 electronically to COGCC 48 hours prior to MIRU. 2) Comply with Rule 317.i and provide cement coverage from the bottom of the production casing to a minimum of 200' above Niobrara and from 200’ below the Sussex to 200’ above Sussex . Verify coverage with cement bond log. 3) Run and submit Directional Survey from TD to base of surface casing. The operator shall comply with Rule 321, and it shall be the operator’s responsibility to ensure that the wellbore complies with setback requirements in commission orders or rules prior to producing the well.
EngineerForm: (02)
400852183
06/11/2015		1) Submit Form 42 electronically to COGCC 48 hours prior to MIRU. 2) Comply with Rule 317.i and provide cement coverage from the bottom of the production casing to a minimum of 200' above Niobrara and from 200’ below the Sussex to 200’ above Sussex . Verify coverage with cement bond log. 3) Run and submit Directional Survey from TD to base of surface casing. The operator shall comply with Rule 321, and it shall be the operator’s responsibility to ensure that the wellbore complies with setback requirements in commission orders or rules prior to producing the well.
EngineerForm: (02)
400852183
06/11/2015		Operator acknowledges the proximity of the non-operated wells: The McKenney 6-2 (API NO 123-11907), the McKenney 6-3 (API NO 123-14815), the McKenney 6-14 (API NO 123-15780), the UPRR OCOMA II C31-16 (API NO 123-13603), the Howell 1 (API NO 123-07827), and the McGuirk-Howell C 32-14 (API NO 123-15882). Operator assures that these offsets will be remediated per the DJ Basin Horizontal Offset Policy (options 1 or 2) or operator will address this well with mitigation option 4. Operator will submit a Form 42 (“OTHER – AS SPECIFIED BY PERMIT CONDITION”) stating what appropriate mitigation occurred and that it has been completed, prior to the hydraulic stimulation of this well.
EngineerForm: (02)
400852183
06/11/2015		Operator acknowledges the proximity of The Becker 5-2 ( API NO 123-13742), the Becker 5-7 ( API NO 123-13764), the Becker 5-8 (API NO 123-13839), the Becker 5-3 (API NO 123-17299), the Becker 5-11 ( API NO 123-17300), the Becker 5-13 ( API NO 123-17302), the Becker 5-14 (API NO 123-18180), and the Dechant 7-11 (API NO 123-15476). 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 (“OTHER – AS SPECIFIED BY PERMIT CONDITION”) stating what appropriate mitigation occurred and that it has been completed, prior to the hydraulic stimulation of this well.
OGLAForm: (06)
404102197
02/28/2025		COA's provided by the Operator as Best Management Practices under Technical Detail / Comments: Notification: Notification will be given to any adjacent building unit occupants within a 1000 feet of the wellhead of planned P&A start date. Wildlife: 3rd party wildlife surveys will be conducted on this well prior to rigging up for P&A activities. Chevron’s Environmental Site Screening Process incorporates full environmental field clearances within 7 days of a scheduled well-work activity once the well is added to the active workover rig schedule. 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.
OGLAForm: (06)
404102197
02/28/2025		Operator will implement measures to capture, combust, or control emissions to protect health and safety, and to ensure that vapors, odors and noise from plugging operations do not constitute a nuisance or hazard to public health, welfare and the environment.
EngineerForm: (06)
404102197
03/05/2025		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.
EngineerForm: (06)
404102197
03/05/2025		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 (1350') : 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 1131' 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 465' or shallower and provide a minimum of 10 sx plug at the surface. 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)
404102197
03/05/2025		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)
404102197
03/05/2025		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.
 
COGIS - Best Management Practice Results
BMP TypeSource DocumentBest Management Practices
PlanningForm: (02 )
400521567
3/10/2014		604c.(2).E. Multiwell Pads: This 2A application is for a 4-well pad. No suitable existing locations are in the area.
PlanningForm: (02 )
400521567
3/10/2014		604c.(2).I. BOPE Testing for Drilling Operations: PDC's contractors will supply a double ram-5000’ PSI rated BOPE (Blinds and pipes) and always function test BOPE’s prior to placement on the well head and inspect and replace all seals and ram block rubbers. After installation of the BOPE, PDCE conducts a pressure test on the BOPE at a low pressure of (200-400 psi) and a high pressure test to the maximum amount of the BOPE rating with a third party tester, all tests are digitally recorded.
PlanningForm: (02 )
400521567
3/10/2014		604c.(2).J. BOPE for Well Servicing Operations: All valves will also be tested to maximum rating by a third party prior to being delivered to location. Whenever snubbing operations are being used the snubbing stack will be pressure tested at the same time the BOPE is being tested which consist of a single pipe ram and a annular bag.
PlanningForm: (02 )
400521567
3/10/2014		604c.(2).L. Drill Stem Tests: PDC does not conduct drill stem tests, but will seek prior approval from the director if a drill stem test will be preformed.
PlanningForm: (02 )
400521567
3/10/2014		604c.(2).U. Identification of Plugged and Abandoned Wells: Pursuant to rule 319.a. (5)., once the well has been plugged and abandoned, PDC will identify the location of the wellbore with a permanent monument that will detail the well name and date of plugging.
PlanningForm: (02 )
400521567
3/10/2014		604c.(2).V. Development From Existing Well Pads: An existing pad was not available to utilize to develop these wells.
Traffic controlForm: (02 )
400521567
3/10/2014		604c.(2).D. Traffic Plan: If required by the local government, a traffic plan will be coordinated with the local jurisdiction prior to commencement of operations.
General HousekeepingForm: (02 )
400521567
3/10/2014		604c.(2).N. Control of Fire Hazards: PDC will ensure that any material that might be deemed a fire hazard will be will remain no less than twenty-five (25) feet from the wellhead(s), tanks and separator(s). PDC installs automation equipment for tank level and pressure monitoring inside the bermed area that complies with API RP 500 classifications and with the current national electrical code as adopted by the State of Colorado.
General HousekeepingForm: (02 )
400521567
3/10/2014		604c.(2).T. Well Site Cleared: The wellsite will be cleared of all non-essential equipment within ninety (90) days after all wells associated with the pad have been plugged and abandoned.
General HousekeepingForm: (02 )
400521567
3/10/2014		604c.(2).P. Removal of Surface Trash: A commercial size trash bin for removing debris will be located on site. This bin will be for use by all parties affiliated with the operation.
Material Handling and Spill PreventionForm: (02 )
400521567
3/10/2014		604c.(2).F. Leak Detection Plan: Attached.
Material Handling and Spill PreventionForm: (02 )
400521567
3/10/2014		604c.(2).K. Pit Level Indicators: PDC uses an Electronic Drilling Recorder (EDR) with pit level monitor(s) and alarm(s) for production rigs. Basic level gages are used on steel pits utilized for the surface rig.
ConstructionForm: (02 )
400521567
3/10/2014		604c.(2).G. Berm Construction: A geosynthetic liner will be laid under the tanks on this location and a metal containment has been constructed. Operator must implement site-specific best management practices in accordance with good engineering practices, including, but not limited to, construction of a berm or diversion dike, site grading, or other comparable measures, sufficient to protect the down gradient water sources located 321 feet south-west and 444 feet north-west from the nearest well head.
ConstructionForm: (02 )
400521567
3/10/2014		604c.(2).M. Fencing Requirements: The completed wellsites will be surrounded with a fence and gate. PDC personnel will monitor the wellsites regularly upon completion of the wells. Authorized representatives and/or PDC personnel shall be on-site during drilling and completion operations.
ConstructionForm: (02 )
400521567
3/10/2014		604c.(2).Q. Guy Line Anchors: Rig guy wires are anchored to the rig’s base beam that the rig stands on, temporary and permanent anchors will not be set on this location.
ConstructionForm: (02 )
400521567
3/10/2014		604c.(2).R. Tank Specifications: Condensate storage tanks will be designed, constructed and maintained in accordance with National Fire Protection Association (NFPA) Code 30 (2008 version). PDC will maintain written records to verify proper design, construction and maintenance. All records will be available for inspection by the Director.
ConstructionForm: (02 )
400521567
3/10/2014		604c.(2).S. Access Roads: PDC will utilize the lease access road from WCR 53 for drilling operations and maintenance equipment. The road will be properly constructed and maintained to accommodate for local emergency vehicle access.
Noise mitigationForm: (02 )
400521567
3/10/2014		604c.(2).A. Noise: PDC has conducted baseline noise surveys for all drilling rigs that are being contracted and has also conducted a baseline noise survey for hydraulic fracture stimulation operations on a representative horizontal well. These baseline surveys are utilized for site specific noise modeling to determine if any mitigation measures are warranted. A review will be conducted to identify potential receptors within 1000 feet of the proposed Becker Ranch 5J-HZ pad site. The building units of concern are located north-east of the proposed pad at a distance of approximately 758 feet, 776 feet and 908 feet respectively. Noise modeling will be conducted for the proposed pad. If results exceed the Light Industrial Zone standard of 65 decibels (db) at the receptor location, additional methods of noise mitigation shall include but not be limited to hay bales, noise walls, or customized semi-trailers.
Emissions mitigationForm: (02 )
400521567
3/10/2014		604c.(2).C. Green Completions: Flowlines, 48” HLPs, sand traps all capable of supporting green completions as described in rule 805 shall be installed at any Oil and Gas location at which commercial quantities of gas and or oil are reasonable expected to be produced based on existing wells. All green flow back equipment will be able to handle more than 1.5 times the amount of any know volumes in the surrounding field. First sign of salable gas will be put into production equipment and turned down line.
Drilling/Completion OperationsForm: (02 )
400521567
3/10/2014		Operator will comply with COGCC Policy for Bradenhead Monitoring During Hydraulic Fracturing Treatments in the Greater Wattenberg Area dated May 29, 2012. The Colorado Oil and Gas Conservation Commission (COGCC) has established this Policy Regarding Bradenhead Monitoring During Hydraulic Fracturing Treatments (“Treatment”) in the Greater Wattenberg Area (“GWA”) pursuant to COGCC 207.a. (“Policy”). This Policy applies to oil and gas operations in the GWA as defined by the COGCC Rules of Practice and Procedure.
Drilling/Completion OperationsForm: (02 )
400521567
3/10/2014		604c.(2).O. Loadlines: All loadlines shall be bullplugged or capped.
Drilling/Completion OperationsForm: (02 )
400521567
3/10/2014		Open hole resistivity log with gamma ray will be run on one of the wells on this pad to describe the stratigraphy of the vertical section of the wellbore and to adequately verify the setting depth of the surface casing and aquifer coverage. The Drilling Completion Report - Form 5 for every well on the pad shall identify which well was logged.
PlanningForm: (02 )
400852183
6/12/2015		604c.(2).E. Multiwell Pads: This 2A application is for a 4-well pad. No suitable existing locations are in the area.
PlanningForm: (02 )
400852183
6/12/2015		604c.(2).I. BOPE Testing for Drilling Operations: PDC's contractors will supply a double ram-5000’ PSI rated BOPE (Blinds and pipes) and always function test BOPE’s prior to placement on the well head and inspect and replace all seals and ram block rubbers. After installation of the BOPE, PDCE conducts a pressure test on the BOPE at a low pressure of (200-400 psi) and a high pressure test to the maximum amount of the BOPE rating with a third party tester, all tests are digitally recorded.
PlanningForm: (02 )
400852183
6/12/2015		604c.(2).J. BOPE for Well Servicing Operations: All valves will also be tested to maximum rating by a third party prior to being delivered to location. Whenever snubbing operations are being used the snubbing stack will be pressure tested at the same time the BOPE is being tested which consist of a single pipe ram and a annular bag.
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