Alberta Energy Regulator finalizes new Methane Requirements for Upstream Oil and Gas

Alberta Energy Regulator finalizes new Methane Requirements for Upstream Oil and Gas

As set out in Alberta Energy Regulator (AER) Bulletin 2018-37 issued December 13, new requirements meant to reduce methane emissions from the upstream oil and gas industry have been added to Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting, and Directive 017: Measurement Requirements for Oil and Gas Operation.  These changes will not take effect until January 1, 2020 with some changes taking effect at an even later date.  As well, the AER has issued Manual 015: How to Estimate Methane Emissions Reporting to the AER and Manual 016: How to Develop a Fugitive Emissions Management Program in support of the changes made to Directives 60 and 17.

See our 2017 report Methane Reduction under the Climate Change Leadership Plan which provides an overview of provincial methane regulations (prior to the recent changes which take effect in 2020), as well as, regulatory approaches taken in the US and the UK.  The report also provides a review of the federal regulations in their draft form.  See also our previous blog post summarizing the (then draft) provincial and federal requirements.

Changes to Alberta’s Methane Requirements

In Alberta, requirements relating to emissions from oil and gas activities are set out in a variety of directives and informational letters issued by the AER.   These include technical requirements for measuring and reporting emissions associated with wells, pipelines and facilities.  The most relevant is Directive 60:  Upstream Petroleum Industry Flaring, Incinerating, and Venting (Directive 60).

Changes – which do not come into effect until 2020 – have been made to specifically address methane emissions.  The majority of the changes relevant to methane emissions are found in section 8 of Directive 60.  Some definitions found in Appendix 2 of Directive 60 have been added or updated (including definitions for flare gas, vent gas, and fugitive emissions).  As well, Appendices 12 and 13 have been added to address fugitive emissions.

Under Directive 60, there is an overall vent gas limit for routine (i.e. part of normal operations) and non-routine venting.  It should be noted that the AER recommends, but does not require, the elimination of all routine venting.  The overall vent gas limit at a site is to be set at 15.0 103 m3 of vent gas per month or 9.0 103 kg of methane per month (this is the total of all routine and non-routine vent gas).  Vent gas from pneumatic devices, compressor seals, and glycol dehydrators are excluded from this overall vent gas limit until January 1, 2023.

Effective January 1, 2022, crude bitumen batteries must limit routine vent gas to either:

  • from each site, less than 3.0 103 m3 of vent gas per month per site or less than 1.8 103 kg of methane per month per site (excluding vent gas from pneumatic devices, compressor seals and glycol dehydrators), or
  • from the crude bitumen fleet, less than an average vent gas rate in each month of 3.0 103 m3 per facility ID.

However, vent gas for crude bitumen batteries that are thermal in situ schemes and thermal in situ operations under the Oil Sands Conservation Act and the Oil Sands Conservation Rule is excluded from the above vent gas limits.  Also excluded are batteries with either crude oil well or crude bitumen wells within the Peace River area as defined in Directive 084.

Part 8.6 of Directive 60 sets out some equipment-specific vent gas limits for pneumatic devices, compressor seals, and glycol dehydrators proposed:

  1. Pneumatic Devices:

For pneumatic devices installed after January 1, 2022, vent gas must be controlled from at least 90% of the instruments installed in a calendar year.  Level controllers that actuate between 0 and 15 minutes must use a relay to reduce or minimize venting or actuation frequency must be adjusted to greater than 15 minutes.  Pneumatic pumps that operate more than 750 hours per calendar year must not emit vent gas.  Other pneumatic instruments must have a steady-state vent gas rate less than 0.17m3/hr.  Effective January 1, 2023, any level controllers or pneumatic instruments installed before January 1, 2022 must be retrofitted with a low vent alternative (to meet the above parameters).

2. Compressor Seals:

Vent gas limits apply to vent gas from seals of a reciprocating or centrifugal compressor that is rated 75 kW or more and is pressurized for at least 450 hours per calendar year.  Such compressor seals must be tested at least every 9000 hours that it is pressurized.  Effective January 1, 2023, vent gas from reciprocating compressor seals must be limited to less than 0.83 m3/hr/throw.  With respect to centrifugal compressor seals installed after January 1, 2022, the vent gas rate must be limited to less than 3.40 m3/hr/compressor.  Those installed before January 1, 2022 must limit vent gas to less than 10.20 m3/hr/compressor.

3. Glycol Dehydrators:

Glycol dehydrators installed after January 1, 2022 must emit less than 68kg methane/day.  Effective January 1, 2023, the average methane emissions rate from the glycol dehydrator fleet (which consists of operating glycol dehydrators installed before January 1, 2022) must be less than 136 kg methane/day in the calendar year.

Aside from these equipment-specific limits, the overall vent gas limit on a site basis is what is applicable to methane emissions.  While the AER requires preparation of a Methane Reduction Retrofit Compliance Plan (MRRCP), there are no prescriptive requirements to adopt certain technology designed to reduce and prevent leaks of methane.

In addition to developing a MRRCP, operators must document a Fugitive Emissions Management Program (FEMP) designed to reduce fugitive emissions.  The mandatory elements of a FEMP are set out in Appendix 12 of Directive 60 and further direction (including best practices) is provided by Manual 016: How to Develop a Fugitive Emissions Management Program.  It should be noted that the AER will consider “innovative and science-based” alternative programs to the FEMP prescribed by Directive 60.  These could incorporate the use of unmanned aerial vehicles, vehicle-mounted sensors and continuous monitoring devices.

Under Directive 60, there are some monitoring and reporting requirements. Depending on the facility or equipment type, an operator must conduct fugitive emissions surveys either once or 3 times a year.  A survey must look at equipment components; pneumatic devices; tank-top equipment; surface casing vents and the area around the wellbore; equipment used to destroy vent gas; and equipment used to conserve vent gas (using the methodologies specified in Directive 60).

Where fugitive emissions surveys are not required, an annual fugitive emissions screening must be conducted by the operator at all well-sites.   A screening can be done via:

  • audio, visual, or olfactory (AVO) methods;
  • soap solution;
  • other methods or equipment that is capable of detecting fugitive emissions, such as unmanned aerial vehicles or truck mounted sensors; or
  • fugitive emission survey methods and equipment.

If a survey or screening detects a leak, repairs must be made within 30 days (24 hours if a leak is causing off-lease odours, results from a failed pilot or ignitor on a flare stack, or has the potential to cause safety issues).

In addition to operator conducted surveys and screenings, the AER may conduct an emissions survey or screening.   There is no indication in Directive 60 as to the frequency of AER conducted emissions surveys or screenings.  Further, there are no additional enforcement mechanisms specific to methane emissions provided in Directive 60 (so presumably typical AER enforcement mechanisms, such as warning and administrative sanctions will apply).

Overall these changes to Directive 60 do not reflect a significant shift from the current approach to the measurement, monitoring, and reporting of emissions in Alberta.   It remains a performance-based approach to emissions reductions, now with some direct references to methane.  And a question remains as to the equivalency of Alberta’s approach to the federal approach under the Canadian Environmental Protection Act which has a more comprehensive approach to leak detection and repair, and a more prescriptive approach to various sources of methane emissions.

As indicated on the AER website, the new methane requirements apply to AER regulated:

· upstream oil, gas and bitumen wells,
· oil and gas facilities,
· gas plants,
· pipeline installations,
· storage facilities, and
· tank terminals (i.e., production and injection wells, batteries, and central processing facilities within thermal in-situ oil sands schemes.

The new requirements do not apply to:

· AER regulated facilities that are not related to oil, gas or bitumen production (such as coal, shallow water wells, brine wells, NEB regulated facilities, midstream meter stations, or midstream pipelines),
· oil sands mining schemes,
· processing plants for removing bitumen from oil sands at mines including upgraders,
· refineries,
· rail car loading facilities,
· downstream distribution pipelines, and
· downstream facilities.

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