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COGIS DB
 
Facility TypeFacility ID/
API		Facility Name/
Number		Operator Name/
Number		StatusField Name/
Number		LocationLocation IDRelated Facilities
WELL05-123-43333Carlson
A08-625 		NOBLE ENERGY INC
100322		WO
2/1/2024		WATTENBERG
90750		WELD  123
NESE 7 6N64W 6		483512View Related
 
COGIS - Conditions of Approval Results
TypeSource DocumentConditions of Approval
EngineerForm: (02)
401037652
06/24/2016		Operator acknowledges the proximity of the listed non operated well(s). Operator agrees to provide mitigation Option 1 or 2 (per the DJ Basin Horizontal Offset Policy, ensure all applicable documentation is submitted based on the selected mitigation option chosen, and submit Form 42(s) “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 the proposed wells. Mile High Sheep 8-35 (API #123-24252)
EngineerForm: (02)
401037652
06/24/2016		Operator acknowledges the proximity of the listed non-producing well(s). Operator agrees to provide mitigation Option 3 (per the DJ Basin Horizontal Offset Policy, ensure all applicable documentation is submitted , and submit Form 42(s) “OFFSET MITIGATION COMPLETED” for the remediated well(s), referencing the API Number of the proposed horizontal wells stating what appropriate mitigation occurred and that it has been completed, prior to the hydraulic stimulation of the proposed wells. Grady 1 (API #123-14810) Dyer 42-7 (API #123-13959)
EngineerForm: (02)
401037652
06/24/2016		Operator acknowledges the proximity of the listed well(s). Operator agrees to provide mitigation Option 1 or 2 (per the DJ Basin Horizontal Offset Policy, ensure all applicable documentation is submitted based on the selected mitigation option chosen, and submit Form 42(s) “OFFSET MITIGATION COMPLETED” for the remediated well(s), referencing the API Number of the proposed horizontal wells stating what appropriate mitigation occurred and that it has been completed, prior to the hydraulic stimulation of the proposed wells. Carlson 33-7 (API #123-19548) Carlson 34-7 (API #123-14251) Carlson 44-7 (API #123-14171) Ehrlech 32-7 (API #123-20196) Ehrlich 1 (API #123-12382) Ehrlich 2 (API #123-12460) Ehrlich 22-7 (API #123-14184) Ehrlich 24-7 (API #123-20469) Francen 24-8 (API #123-14232) Peterson 42-12 (API #123-14070) Roy Carlson 43-7 (API #123-21867) Uhrich 44-8 (API #123-14418) Williamson 44-12 (API #123-14071)
EngineerForm: (02)
401037652
06/28/2016		Bradenhead tests shall be performed on all wells on this pad on the following schedule: 1) Within 60 days of rig release and prior to stimulation (wells already stimulated excepted). 2) Between 6 and 7 months after rig release or prior to stimulation. 3) Within 30 days of First Production as reported on Form 5A (wells already producing shall be tested within 30 days). Test results shall be submitted on Form 17 within 10 days of test.
EngineerForm: (02)
401037652
06/28/2016		1)Submit Form 42 electronically to COGCC 48 hours prior to MIRU for the first well activity with a rig on the pad and provide 48 hour spud notice for each subsequent well drilled on the pad. 2)Comply with Rule 317.j and provide cement coverage from end of 7” casing to a minimum of 200' above Niobrara. Verify coverage with cement bond log. 3)Operator has indicated that no oil based drilling fluids are to be used on this location.
EngineerForm: (02)
401654902
06/22/2018		Operator acknowledges the proximity of the listed well(s). Operator agrees to provide mitigation Option 1 or 2 (per the DJ Basin Horizontal Offset Policy, ensure all applicable documentation is submitted based on the selected mitigation option chosen, and submit Form 42(s) “OFFSET MITIGATION COMPLETED” for the remediated well(s), referencing the API Number of the proposed horizontal wells stating what appropriate mitigation occurred and that it has been completed, prior to the hydraulic stimulation of the proposed wells. Carlson 33-7 (API #123-19548)Carlson 34-7 (API #123-14251) Carlson 44-7 (API #123-14171Ehrlech 32-7 (API #123-20196 Ehrlich 1 (API #123-12382)Ehrlich 2 (API #123-12460) Ehrlich 22-7 (API #123-14184)Ehrlich 24-7 (API #123-20469) Francen 24-8 (API #123-14232)Peterson 42-12 (API #123-14070) Roy Carlson 43-7 (API #123-21867)Uhrich 44-8 (API #123-14418) Williamson 44-12 (API #123-14071)
EngineerForm: (02)
401654902
06/22/2018		Operator acknowledges the proximity of the listed non-producing well(s). Operator agrees to provide mitigation Option 3 (per the DJ Basin Horizontal Offset Policy, ensure all applicable documentation is submitted , and submit Form 42(s) “OFFSET MITIGATION COMPLETED” for the remediated well(s), referencing the API Number of the proposed horizontal wells stating what appropriate mitigation occurred and that it has been completed, prior to the hydraulic stimulation of the proposed wells Grady 1 (API #123-14810)Dyer 42-7 (API #123-13959)
EngineerForm: (02)
401654902
06/22/2018		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 the end of production casing 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 aquifers are covered.
EngineerForm: (02)
401654902
06/22/2018		Bradenhead tests shall be performed and reported according to the following schedule and Form 17 submitted within 10 days of each test: 1) Within 60 days of rig release and prior to stimulation or 2) If a delayed completion, 6-7 months after rig release and prior to stimulation. 3) Within 30 days after first production, as reported on Form 5A.
PermitForm: (02)
401654902
10/03/2018		COA: Operator shall comply with Notice to Operators: Interim Reclamation Procedures for Delayed Operations (dated January 5, 2017).
PermitForm: (02)
401654902
10/03/2018		COA: If location is not built by 2A expiration 6/28/2019, Operator must Refile Form 2A for approval prior to location construction.
PermitForm: (02)
401654902
10/03/2018		COA: This Permit to Drill is approved subject to all the BMPs and COAs on the most recently approved Form 2A and any subsequently approved Form 4 for the Oil and Gas Location. The most recently approved Form 2A and any subsequent Form 4s containing applicable COAs for this location shall be posted onsite during construction, drilling, and completions operations.
EngineerForm: (02)
402873925
01/30/2023		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”) 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. Uhrich 11-17 (API NO 123-23041)
EngineerForm: (02)
402873925
01/30/2023		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. Carlson 44-7 (API NO 123-14171) Carlson 34-7 (API NO 123-14251) Carlson 33-7 (API NO 123-19548) Roy Carlson 43-7 (API NO 123-21867)
EngineerForm: (02)
402873925
01/30/2023		1) Submit Form 42 electronically to COGCC 2 business days prior to MIRU (Spud Notice), for the first well/activity on the pad and provide 2 business days spud notice for all subsequent wells drilled on the pad. 2) Comply with Rule 408.j and provide cement coverage from the end of production casing to a minimum of 500' above Niobrara. Verify coverage with cement bond log. 3) Oil-based drilling fluid is to be used only after all aquifers are covered.
EngineerForm: (02)
402873925
01/30/2023		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, a second test is required between 6-9 months, of if there is pressure above 200 psi, 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.
PermitForm: (02)
402873925
04/12/2023		If location is not constructed by 2A expiration (3/24/2030), an approved OGDP and Form 2A are required prior to location construction.
EngineerForm: (06)
404383082
10/15/2025		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.
EngineerForm: (06)
404383082
10/15/2025		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.
EngineerForm: (06)
404383082
10/15/2025		1) Provide 2 business day notice of plugging MIRU via electronic Form 42, and provide 48 hours Notice of Plugging Operations, prior to mobilizing for plugging operations via electronic Form 42. These are 2 separate notifications, required by Rules 405.e and 405.I. 2) Prior to placing the 1974’ plug: verify that all fluid migration (liquid and gas) has been eliminated. If evidence of fluid migration or pressure remains, contact ECMC Engineer for an update to plugging orders. 3) After isolation has been verified, pump surface casing shoe plug. If cement is not circulated to surface, shut-in, WOC 4 hours then tag plug – must be at 1874’ or shallower and provide 10 sx plug at the surface. 4) Leave at least 100’ of cement in the wellbore for each plug without mechanical isolation. 5) After surface plug 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)
404383082
10/15/2025		FLOWLINE AND SITE CLOSURE 1)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. 2)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.
OGLAForm: (06)
404383082
11/06/2025		Operator committed to the following Best Management Practices under the Technical Detail/ Comments section on the Submit Tab: 3rd party wildlife surveys will be conducted on this well prior to rigging up for P&A activities. Notification will be given to any adjacent building unit occupants within a 1000 feet of the wellhead of planned P&A start date. 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)
404383082
11/06/2025		Due to proximity to a wetland, surface water and expected shallow groundwater, operator will use secondary containment for all tanks and other liquid containers. Operator will implement stormwater BMPs and erosion control measures as needed to prevent sediment and stormwater runoff from entering the wetland and surface water.
 
COGIS - Best Management Practice Results
BMP TypeSource DocumentBest Management Practices
PlanningForm: (02 )
401037652
7/1/2016		604c.(2).E. Multiwell Pads: This 2A application is for a 8-well pad. PDC Energy considered all options for this area including Landowner concerns. Landowner requested we place the location out of the large irrigated field and irrigation (transfer) ditch to the West. There is flood plain to the west as well, which we did our best to avoid. PDC would also like to combine the existing Carlson 44-7 Battery into this new Elvera battery/location.
PlanningForm: (02 )
401037652
7/1/2016		604c.(2).V. Development From Existing Well Pads: An existing pad was not available to utilize to develop these wells.
Traffic controlForm: (02 )
401037652
7/1/2016		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 )
401037652
7/1/2016		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 )
401037652
7/1/2016		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.
Storm Water/Erosion ControlForm: (02 )
401037652
7/1/2016		This Stormwater Management Plan contains required elements associated with PDC’s construction activities, as defined in the CDPS General Permit for Stormwater Discharges Associated with Construction Activity, Authorization to Discharge Under the Colorado Discharge Permit System (Permit No. COR-030000, re-issued and effective July 1, 2007).BMPs for sediment and erosion control will be accomplished through a combination of construction techniques, vegetation and re-vegetation, administrative controls, and structural features.
ConstructionForm: (02 )
401037652
7/1/2016		604c.(2).G. Berm Construction: Containment berms shall be constructed of steel rings with a geosynthetic liner, designed and installed to prevent leakage and resist degradation from erosion or routine operation. All berms will be visually checked periodically to ensure proper working condition. Secondary containment devices shall be sufficiently impervious to contain any spilled or released material. Due to a downgradient surface water body within 500’, tertiary containment (such as an earthen berm or the like), will be installed around Production Facilities.
ConstructionForm: (02 )
401037652
7/1/2016		604c.(2).S. Access Roads: PDC will utilize an improved lease access road off of County Road 70 (gravel) for all heavy truck traffic and rig moves along with drilling operations and maintenance equipment. The lease access road will be properly constructed and maintained to accommodate for local emergency vehicle access. Dust will be mitigated as necessary on lease access road.
ConstructionForm: (02 )
401037652
7/1/2016		804. Visual Impact: Production facilities, regardless of construction date, which are observable from any public highway will be painted with uniform, non-contrasting, non-reflective color tones (similar to the Munsell Soil Color Coding System), and with colors matched to but slightly darker than the surrounding landscape.
ConstructionForm: (02 )
401037652
7/1/2016		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 )
401037652
7/1/2016		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.
Noise mitigationForm: (02 )
401037652
7/1/2016		604c.(2).A. Noise: WELL PAD: 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 was conducted to identify potential receptors within 1000 feet of the proposed pad site. There are four (4) building units of concern located 779' NE, 805' SE, 824' SW and 851' NE. Light and sound mitigation will be installed to the North, East and South of the proposed location. Methods of noise mitigation shall include but not be limited to hay bales, sound walls, or customized semi-trailers. PRODUCTION FACILITIES: It is not anticipated that noise mitigation will be necessary at the proposed tank battery location. After construction is completed, equipment installed and production begins, noise levels will be assessed to determine if mitigation measures will be required to be compliant with Rule 802.
Emissions mitigationForm: (02 )
401037652
7/1/2016		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.
Odor mitigationForm: (02 )
401037652
7/1/2016		805.b(1)-(c) Odors and Dust: Oil and gas facilities and equipment will operate in a manner that odors and dust do not constitute a nuisance or hazard to public welfare. Odors: Oil and gas operations will be in compliance with the Department of Public Health and Environment, Air Quality Control Commission, Regulation No. 2 Odor Emission, 5 C.C.R. 1001-4, Regulation No. 3 (5 C.C.R. 1001-5), and Regulation No. 7 Section XVII.B.1 (a-c) and Section XII. Dust; PDC will employ practices for control of fugitive dust caused by operations include but not limited to the use of speed restrictions, regular road maintenance, restriction of construction activity during high-wind days, and silica dust controls when handling sand used in hydraulic fracturing operations. When necessary, PDC coordinates dust mitigation with the county on gravel roads, places road base where allowed by surface owner around tanks and wellheads to minimize dust, and will water the roads and locations when dry. In addition, automation is used on all new wells to minimize truck traffic.
Drilling/Completion OperationsForm: (02 )
401037652
7/1/2016		604.c.(2).W. Site Specific Measures: Lights should be turned downward and away from building units within the 1,000 foot buffer area. Dust mitigation will be provided as necessary on lease access roads.
Drilling/Completion OperationsForm: (02 )
401037652
7/1/2016		604c.(2).I. BOPE Testing for Drilling Operations: PDC's contractors will supply a double ram BOPE (Blinds and pipes). BOPE is always function tested and all seals and ram block rubbers are inspected. 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 with a third party tester, all tests are digitally recorded and any failed equipment or seals are replaced and re-tested.
Drilling/Completion OperationsForm: (02 )
401037652
7/1/2016		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.
Drilling/Completion OperationsForm: (02 )
401037652
7/1/2016		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.
Drilling/Completion OperationsForm: (02 )
401037652
7/1/2016		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.
Drilling/Completion OperationsForm: (02 )
401037652
7/1/2016		604c.(2).O. Loadlines: All loadlines shall be bullplugged or capped.
Drilling/Completion OperationsForm: (02 )
401037652
7/1/2016		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.
Drilling/Completion OperationsForm: (02 )
401037652
7/1/2016		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.
Drilling/Completion OperationsForm: (02 )
401037652
7/1/2016		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.
Drilling/Completion OperationsForm: (02 )
401037652
7/1/2016		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 )
401037652
7/1/2016		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.
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