| OGLA | Form: (02A)
401336812
09/08/2017 | The following COAs will apply to this Form 2A Permit if any temporary surface (COAs 1, 2, 3, and 4) or buried permanent (COA 1) flowlines and/or offsite pipelines (poly or steel) are used during operations at this oil and gas location:
COA 1 - Operator shall pressure test pipelines (flowlines from wellheads to separators to blowdown tank; pipelines from onsite separators to offsite storage tanks, and any temporary surface lines used for hydraulic stimulation and/or flowback operations) in accordance with Rule 1101.e.(1) prior to putting into initial service any temporary surface or permanent buried pipelines and following any reconfiguration of the pipeline network, and tested annually, unless agreed to by both parties that the flowlines can be managed under an approved COGCC variance.
COA 2 - Operator must routinely inspect the entire length of the surface pipeline to ensure integrity. Operator shall conduct daily inspections of surface poly pipeline routes for leaks during active transfer of fluids and implement best management practices to contain any unintentional release of fluids along all portions of the surface pipeline route where temporary pumps and other necessary equipment are located. Inspections shall be conducted by viewing the length of the pipeline; operator will endeavor to minimize surface disturbance during pipeline monitoring. In addition, pump stations along the surface poly or steel pipeline route will be continuously monitored when operating in order to swiftly respond to such a failure.
COA 3 - Operator will implement BMPs necessary to mitigate a potential for a release of fluids to impact streams, intermittent streams, ditches, and drainage crossings. For these crossings: if poly pipe is used on the surface, operator will ensure appropriate containment by either installing over-sized pipe “sleeves” which extend the length of the crossing and beyond to a distance deemed adequate to capture (catchment basins) and/or divert any possible release of fluids and prevent fluids from reaching the stream or drainage; installing over-sized pipe “sleeves” which extend the length of the crossing and installing shut off valves on either side of crossing instead of catchment basins; or develop an alternative means for containment. For all other pipeline materials, operator will implement BMPs necessary to mitigate a potential for E&P fluids not to reach groundwater or flowing surface water.
COA 4 - Operator will utilize, to the extent practical, all existing access and other public roads, and/or existing pipeline right-of-ways, when placing/routing the temporary surface pipelines. This will reduce surface disturbance and fragmentation of wildlife habitat in the area. |
| OGLA | Form: (02A)
401336812
09/08/2017 | Potential odors associated with the completions process and/or with long term production operations must be controlled/mitigated. |
| OGLA | Form: (02A)
401336812
09/08/2017 | The moisture content of water/bentonite based mud (WBM) generated drill cuttings managed onsite shall be kept as low as practicable to prevent accumulation of liquids greater than de minimis amounts. After drilling and completion operations have been completed, if any of the WBM drill cuttings will remain on the well pad location (cuttings management area, the cut portion of the pad, cuttings trench, dry cuttings drilling pit), they must be sampled and meet the applicable standards of Table 910-1. No liners (if used) are allowed to be disposed of with the drill cuttings. After the drill cuttings have been amended (if necessary) and placed on the well pad, sampling frequency of the drill cuttings (to be determined by the operator) shall be representative of the material left on location. No offsite disposal of cuttings to another oil and gas location (TEP’s permitted Cuttings Trench locations or nearby locations) shall occur without prior approval of a Form 4 Sundry Notice specifying disposal location and waste characterization method. Commercial disposal of drill cuttings will also require notification to COGCC via a Form 4 Sundry Notice.
Flowback and stimulation fluids must be sent to enclosed tanks, separators, or other containment/filtering equipment before the fluids can be placed into any pipeline storage vessel, or other open top containment located on the well pad; or into tanker trucks for offsite disposal. No open top tanks can be used for initial flowback fluids containment. The flowback and stimulation fluid tanks, separators, or other containment/filtering equipment must be placed on the well pad in an area constructed to be sufficiently impervious to contain any spilled or released material. No additional downgradient berming is required if operator constructs a sufficiently sized perimeter berm. |
| OGLA | Form: (02A)
401336812
09/08/2017 | Operator must ensure secondary containment for any volume of fluids contained at the well site during drilling and completion operations; including, but not limited to, construction of a berm or diversion dike, diversion/collection trenches within and/or outside of berms/dikes, site grading, or other comparable measures (i.e., best management practices [BMPs] associated with fluid containment/control as well as stormwater management for the control of run-on and run-off) sufficiently protective of nearby surface water.
The access road will be maintained as to not allow sediment to migrate from the access road to nearby surface water or any drainages leading to surface water.
Strategically apply fugitive dust control measures to reduce fugitive dust and coating of vegetation and deposition in water sources.
Since condensate storage tanks are not planned to be constructed on location, operator shall submit a scaled as-built drawing (plan view with distances) of this oil and gas location (showing wellheads, onsite flowlines, offsite pipelines, and production facilities [separators, etc.]) and the nearby production facility location to which the condensate and/or produced water will be sent to via underground pipelines (showing onsite flowlines, offsite pipelines, condensate and/or produced water storage tanks, and other production facilities) within 30 calendar days of construction of the production equipment on either or both locations. |
| OGLA | Form: (02A)
401336812
09/08/2017 | In addition to the notifications required by COGCC listed in the Northwest Notification Policy (Notice of Intent to Construct a New Location, Notice of Intent to Spud Surface Casing, and Notice of Intent to Commence Hydraulic Fracturing Operations) and Rule 316C. COGCC Form 42. FIELD OPERATIONS NOTICE (a. Notice of Intent to Conduct Hydraulic Fracturing Treatment and c. Notice of Construction or Major Change); operator shall notify the COGCC 48 hours prior to onsite flowline/pipeline testing (flowlines from wellheads to separators to onsite blowdown tank; and/or any temporary surface lines used for hydraulic stimulation and/or flowback operations) using the Form 42 (as described in Rule 316C.m. Notice of Completion of Form 2/2A Permit Conditions). The appropriate COGCC individuals will automatically be email notified. |
| Permit | Form: (04)
401486455
12/18/2017 | If the well is not drilled prior to the expiration of the original APD, the operator shall meet the requirements of the Conductor Notice to Operators dated10/6/2016 within 60 days of the expiration: (a) plug conductor and reclaim site, (b) request to keep conductor and provide additional financial assurance, or (c) submit an alternative plan as a variance request. |