(Colorado) Regulation No. 7: Control of ozone precursors and control of hydrocarbons via oil and gas emissions (as amended in February 2021)
This regulation introduces requirements for potential sources of ozone precursors, including hydrocarbons, volatile organic compounds (VOC), and oxides of nitrogen (NOx). Part B covers storage, transfer, and disposal of VOC, petroleum liquids and petroleum processing and refining. Part D covers oil and gas operations, including sources of methane and ethane emissions.
Part B addresses maintenance requirements, routine inspection requirements, equipment mandates as well as applicable reporting and recordkeeping. It also defines procedures to limit or minimize vapour loss, prohibiting disposal of VOC by evaporation or spillage. With regards to petroleum processing and refining (VI), in particular, all blowdown systems, process equipment vents, and pressure relief valves are required to be vented to a vapour recovery system, or to a combustion system that assures at least 90% combustion efficiency. Furthermore, monitoring programs and related reporting are compulsory, with Leak Detection and Repair (LDAR) requirements outlined for petroleum refinery complexes.
Below is a summary of the requirements outlined in Part D (Oil and Natural Gas Operations).
Transmission and storage segment
2020 marks the beginning of a performance-based program to reduce methane emissions from transmission and storage facilities (Part D, Sec. IV). By 31 Dec 2020, each owner/operator must develop a company-specific best management practice plan; by 1 Jan 2021, they must begin to implement the plan and collect emissions inventory data. A steering committee will set a segment-wide emissions intensity target by 1 Oct 2023, to be achieved by 1 Jan 2025. Annual emissions inventory reporting is required, with certifications.
All pneumatic controllers placed in service at upstream sites on or after 1 Feb 2009, must be low-bleed controllers (pneumatic controllers in service prior to 1 Feb 2009 must be replaced or retrofit by 1 May 2009) (Part D, Sec. IIIC). For natural gas processing plants placed in service on or after 1 Jan 2018, operators must install zero-bleed controllers (pneumatic controllers in service prior to January 1, 2018 must be replaced or retrofit by 1 May 2018). High-bleed controllers must be tagged, inspected monthly, and maintained. Recordkeeping and annual reporting required.
Owners or operators of all pneumatic controllers placed in service on or after May 1, 2014 and before May 1, 2021 must utilize no-bleed controllers where on-site electrical grid power is being used and where it is technically and economically feasible. Well production facilities and natural gas compressor stations that commence operations or change particular operational characteristics after 1 May 2021 must use only non-emitting controllers.
Well production facilities and natural gas compressor stations that commenced operation before May 2021 must phase out emitting controllers. Operators of natural gas compressor stations are obligated to determine total controller count and total historic non-emitting percent of controllers for their natural gas compressor stations that commenced operation before May 1, 2021 (Part D, Sec. IIIC).
Operators must demonstrate compliance with “Additional Required Non-Emitting Facility Percent Production”, steadily increasing from May 1, 2022 to May 1, 2023. This can be done either by retrofitting controllers, plugging and abandoning wells, or removing natural gas compress stations from service. This does not apply to well production facilities with 15 barrels of oil equivalent or less state-wide in oil and natural gas production. Operators of well production facilities must place on-site signage by October 1, 2021, and operators of natural gas compressor stations must report company-wide compliance plans no later than September 1, 2021 (Part D, Sec. IIIC).
On or before June 30th (and on June 30th each year thereafter), operators of oil and natural gas operations in Colorado are required to submit annual reports detailing emissions, including methane (Part D, Sec. V).
Beginning 1 Jan 2015, operators must reduce emissions from wet seal centrifugal compressors by at least 95%, and replace rod packing on reciprocating compressors every 26,000 hours of operation or every 36 months (Part D, Sec. IIB).
Some of the storage tank requirements only apply in parts of the state with serious ozone pollution.
Storage tanks with VOC emissions must meet a 95% control efficiency and/or route emissions to an enclosed combustion device with 98% efficiency. In 2014, regulators lowered the threshold for larger tanks to 6 tpy, down from 20 tpy; beginning 1 Mar 2020, this threshold is lowered again to 2 tpy, and now applies state-wide (Part D, Sec. IIC). Storage tanks constructed on or after 1 March, 2020 must be in compliance by commencement of operation of that storage tank. Storage tanks constructed before 1 March 2020 that are not already controlled must be in compliance by 1 May 2021.
Enclosed combustion devices must have a design destruction efficiency of at least 98% for hydrocarbons (Part D, Sec. IIC) and have auto-igniters (Part D, Sec. I).
Beginning 1 May 2014, operators must conduct audio-visual-olfactory inspections of tanks not more than every 7 days/at least every 31 days (unless dangerous, difficult, or inaccessible); inspect emissions monitoring systems, and implement tank emission management plans (Part D, Sec. IIC).
From 1 May 2015, increased reduction target from 90% to at least 95% for new glycol dehydrators emitting greater than 2 tpy (or existing within 1,320 feet of a building/outside activity area; otherwise, 6 tpy) (Part D, Sec. IID).
Leak Detection and Repair (LDAR)
Beginning 1 Jan 2015, operators must conduct LDAR at wells and compressor stations, on a one-time, annual, quarterly, or monthly basis depending on magnitude of emissions. As of 2020, facilities with estimated VOC emissions greater than zero but less than 2 tpy must conduct a one time inspection; facilities with estimated VOC emissions greater than 2 but less than 12 tpy must inspect at least semi-annually; facilities with VOC emissions greater than 2 tpy and less than 12 tpy and within 1,000 feet of an “occupied area” (a residence, school, large commercial establishment, or outdoor venue), at least quarterly; and facilities with estimated VOC emissions greater than 12 tpy and within 1,000 feet of an “occupied area”, at least monthly. (Part D, Sec. IIE). Exceptions for unsafe, difficult or inaccessible situations (defined terms) (Part D, Sec. IIE).
Beginning March 2021, for identified leaks at a well production facility located within 1,000 feet of an “occupied area”, operators must either attempt to repair the leak within five working days of discovery or conduct follow-up monitoring using EPA Method 21 within five working days of discovery (Part D, Sec. IIE).
Recordkeeping and annual reporting required. From January 2020, records must be kept for two years and made available upon request. From June 2021, annual reports must include instances that resulted in emissions (Part D, Sec. IIG).
Beginning 1 May 2018, operators of pneumatic pumps at natural gas processing plants must ensure a VOC emission rate of zero. Operators of pneumatic pumps located at well production facilities must reduce VOC emissions by 95 percent if it is technically feasible to route emissions to an existing control device or process at the well production facility (Part D, Sec. IK).
Oil/NGL storage, processing, handling
Operators must minimize leakage of VOCs, hydrocarbons “to the extent reasonably practicable,” through vapour recovery systems or enclosed combustion devices. As of 1 May 2014, new enclosed combustion devices must have auto-igniters; existing enclosed combustion devices must be retrofitted by 1 May 2016 (Part D, Sec. IIB).
By 1 Jan 2015, open-ended lines or valves must have caps, blind flanges, plugs or second valves that seal the open end at all times except when in use (Part D, Sec. IIB).
Gas coming from a separator must be sent to a gathering line or an air pollution control system with an average hydrocarbon control efficiency of 95%, or an enclosed combustion device with a design destruction efficiency of at least 98% for hydrocarbons (Part D, Sec. IIF).
Operators are required to use best practices to minimize venting from 2014 (unless for safety reasons). Enhanced recordkeeping and reporting measures were put in place in 2020 (Part D, Sec. IIG).
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- Performance-based policies
- Mandatory reporting
- Recordkeeping requirements
- Procedural requirements
- Leak detection and repair requirements
- Preventative maintenance requirements
- Emissions estimates
- Prescriptive requirements and standards
- Mandatory technology use
- Emission standards
- Public disclosure requirements
- Flaring/venting (prescriptive)
- Company- or facility-level
- Equipment- or process-level
- Flaring/venting (performance)