draft directives 017 & 60: stakeholder feedback … 060...page 1 draft directives 017 and 060...

Draft Directives 017 and 060 (released April 2018)Stakeholder Feedback and AER Response

Issue Summary Sec # Response Change to Draft ReqsGENERALMany respondents supported reducing methane emissions by 45 per cent. Various comments were also in support of the draft directives, particularly of the approach taken, the distinction between new and existing facilities, pneumatic limits, the inclusion of enclosed combustors, the flexibility to adopt new technologies or innovative approaches to fugitive emissions detection, the fleet average for cold heavy oil production (CHOPs), and seeking equivalency with the federal government so that methane emissions are regulated provincially rather than federally.Some comments recommended two regulatory reviews—one prior to December 31, 2020, and the second prior to December 31, 2022.

1.8 The comprehensive review is planned for no later than December 31, 2022, which is when most of the research projects will be completed and we will have sufficient reported emissions data to update our model. Prior to the review, we will meet annually with stakeholders to identify data gaps and to review reported data and research outcomes. As the requirements will only come into effect January 1, 2020, a December 31, 2020, review date would not allow sufficient time for data gathering and analysis in order to conduct a meaningful review.

While there was broad support for the proposed regulatory review period, concerns were expressed about the process for regulatory review; in particular how transparent it would be.

1.8 The regulatory review process provides for an annual review of performance and other available data and also provides for multistakeholder consultation with the opportunity for stakeholders to make recommendations.

Some respondents felt that the in-effect date for new sites would encourage operators to build more facilities or install equipment before January 1, 2022, so that they will be categorized as existing facilities and subject to less stringent requirements.

A facility built before January 1, 2022, would still have to retrofit to meet the requirements that apply January 1, 2023. It would be more cost-effective to design facilities to meet the requirements instead of undertaking costly retrofits on existing facilities. Although the requirements for new facilities and equipment are generally more stringent than those for existing facilities and equipment, this difference allows us to meet the 45% reduction target while being cost effective.

On April 24, 2018, the AER released, for public comment, draft Directives 017 and 060 to implement the Alberta government's Climate Leadership Plan objective of a 45% reduction in methane emissions from upstream oil and gas operations.

During the public comment period, the AER received feedback from over 350 respondents, including industry, environmental nongovernment organizations, municipalities, investment firms, technology and emission control companies, research associations, and individual citizens. An overview of respondents can be found at the end of this table.

The AER considered and reviewed in detail each comment received. Many of the comments raised similar issues or concerns. What follows is a summary of the issues and concerns raised and responses, as well as changes made to the draft requirements. Unless otherwise noted, the section numbers refer to Directive 060.

Issue Summary Sec # Response Change to Draft ReqsSome comments were in support of the distinction between new and existing facilities and equipment. Others felt that this distinction was not justified and could undermine the methane reduction outcome.

The distinction between new and existing facilities optimises the overall cost effectiveness of these requirements. Less-stringent retrofit requirements are applied to existing facilities, and more stringent design standards are applied to new facilities, which reduces the costs of complying with the requirements. Reducing the stringency of requirements that apply to existing facilities will not compromise the emissions reduction target because older facilities will be decommissioned and replaced with new facilities that are subject to more stringent requirements.

Some respondents asked that "new facility" and "existing facility" be defined based on licensing date.

The AER considered defining new and existing facility by licence date, but because the licence date is fixed, such a change would not capture expansions, relocations, and modifications. Basing requirements on first receipt or on production, installation, modification, and relocation as appropriate means that the requirements will still apply even as facilities change.

Some respondents asked the AER to further clarify the scope of the regulations. Of particular interest was what midstream assets are in scope.

D060 applies to all upstream petroleum industry wells and facilities. The proposed requirements apply to AER regulated•upstream oil, gas, and bitumen wells;•oil and gas facilities;•gas plants;•pipeline installations;•storage facilities; and•tank terminals (e.g., production and injection wells, batteries, and central processing facilities within thermal in situ oil sands schemes)

The proposed 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.

Issue Summary Sec # Response Change to Draft ReqsComments were received that the number of different in-effect dates in the draft requirements was confusing and needed to be simplified

To give operators enough time to comply with requirements, Directive 060 will be released before the directive in-effect date of January 1, 2020. Directive requirements such as the FEMP, the MRRCP, reporting requirements, the overall vent gas limit, and the new fuel flare and vent definitions take effect on January 1, 2020, with two exceptions: requirements for new equipment or facilities (January 1, 2022) and requirements for existing equipment and facilities (January 1, 2023).

The Directive 060 effective date has been changed to January 1 2020. Table 4 was updated to reflect this change of date. 8.1 (1) date deleted. 8.2.1 (1) date deleted. 8.6.2.1 date deleted. 8.6.2.1 (3) date deleted. 8.10.1 (1) date deleted. 8.10.3.1 (1) date deleted.

Commenters said that there are many important dates associated with these requirements and asked the AER to provide a "Table of Important Dates."

The AER has released a timeline with the final requirements.

What is the in-effect date for the overall vent gas (OVG) limit? 8.3 The in-effect date for the OVG limit is the in-effect date for the requirements: January 1, 2020.

Please note that s. 8.3.1 specifies exclusions in effect until January 1, 2023.

Concerns were expressed that the requirements were developed without input from environmental and health groups

The Government of Alberta directed the AER to develop the draft methane requirements using input from multiple stakeholder groups, including representatives of industry, environmental nongovernmental organizations, research organizations, Alberta Energy, and the Alberta Climate Change Office.

The Government of Alberta's Climate Change Advisory Panel also engaged Albertans to recommend a plan for action. For more information please visit https://www.alberta.ca/climate-leadership-discussion.aspx

The AER received a number of comments that were editorial in nature. AER directives follow the AER style guide. The editorial comments were reviewed and, where appropriate, the AER made the necessary edits.

Some comments were received requesting defined terms, like "site" be capitalized in the directives.

AER directives follow the long-established norms of standard English and the AER style guide, including avoiding unnecessary capitalization.

A number of comments described early action that companies have taken to reduce their methane emissions in advance of the methane requirements coming into force. They asked that the AER take these actions into account when designing the requirements.

The AER supports early action that has been taken to reduce venting and took this into account in its modelling and regulatory design. Companies that have taken early action to reduce venting will see a reduction in compliance costs where they have already met the limits specified in the requirements.

Some comments asked why the AER didn't align their definition of “non-routine venting” with the federal definition.

Appendix 2 The definition of nonroutine venting is not standardized across jurisdictions. The AER has maintained its existing definition of nonroutine venting, which is meant to prevent extensive venting that can pose risks to safety and the environment.

A number of comments were received asking the AER to define "duty holder," not only in section 8, but also in the definitions.

8 For ease of reference, the definition of "duty holder" in section 8 has been added to appendix 2.

Added the definition of "duty holder" from section 8 to appendix 2

Issue Summary Sec # Response Change to Draft ReqsComments were received about the importance of the AER's compliance assurance procedures being transparent.

We will use a variety of tools, such as data analysis, data audits, facility inspections, and regional surveys, to ensure that operators comply with the requirements. Dealing with noncompliances will be in accordance with Manual 013: Compliance and Enforcement Program and may include enforcement tools ranging from warnings and administrative penalties to orders imposing conditions and prosecution.

Comments about the regulatory approach in the draft requirements included supporting the approach, advocating for more prescriptive or equipment-specific requirements, and advocating for more company-specific targets that would provide flexibility for operators to determine how reductions would be made.

The AER's regulatory approach is a hybrid of prescriptive and outcome-based regulation. It was developed through a multistakeholder approach that allowed us to use the collective knowledge of a diverse range of people, including experts from industry, environmental nongovernmental organizations, research organizations, Alberta Energy, and the Alberta Climate Change Office.

Multistakeholder committees provided technical input and advice in development of various regulatory approaches. We evaluated the different regulatory approaches using the following criteria:1) Cost effective : targets sources, operators, and activities that maximize emission reductions at the lowest cost.2) Adaptive : enables the AER and operators to accommodate technical innovation, operational constraints, socioeconomic contexts, and policy changes.3) Operationally feasible : integrates with operators’ existing business models and processes.4) Transparent and credible : demonstrates that performance objectives are met and governments are satisfied with the quality and rigour of requirements.

In addition to the methane reduction requirements, the AER has measurement, monitoring, and reporting requirements that allow the AER to enforce and demonstrate industry-wide performance.

A number of comments were received on Directive 017 and Directive 060 that were out of scope for the methane reduction requirements.

These comments were collected for consideration in future updates to these directives.

Issue Summary Sec # Response Change to Draft ReqsRETROFITS AND COMPLIANCERespondents commented that there should be fines for under-reporting methane emissions.

The AER uses a variety of enforcement tools ranging from warnings and administrative penalties to orders imposing conditions and prosecutions, depending on the nature of the noncompliance.

Some respondents highlighted the need for the AER to audit operator submissions to verify accuracy.

The AER is using multiple tools, including audits, to assess and verify the accuracy of operator submissions.

Some respondents requested more detail about how the AER will assess for compliance with the requirements in section 8 and how noncompliances will be treated.

The AER will test each submission for compliance using the OneStop system. Further investigation and verification will involve data audits, regional sweeps, and field inspections.

Responses to noncompliances will be based on several criteria, including the magnitude of the infraction and the operator history as outlined in the AER's Manual 013: Compliance and Enforcement and its Integrated Compliance Assurance Framework.

Some respondents underlined that the AER needs to be able to verify the volume of reported emissions.

The AER will use the monthly reported Petrinex data and the annual data reported in OneStop to automatically assess against the requirements to determine which facilities may be out of compliance and identify candidates for audit verification.

The AER will also be randomly auditing reported data to verify accuracy.

Some respondents recommended that enforcement mechanisms be expressly addressed in the regulations and noted that enforcement efficacy increases with prescriptive requirements.

Compliance assurance was a key consideration when designing the methane reduction requirements. The AER has a number of enforcement mechanisms available to it under various different enactments that specfically address noncompliance with AER requirements.

Some comments were critical of the crude bitumen fleet average (CBFA) approach; specifically the AER's ability to enforce compliance with this requirement.

8.5 The AER will enforce compliance of the crude bitumen fleet average by using monthly reported emissions to verify that operators are compliant. The AER has also increased how frequently operators must test gas-oil ratios for all facilities under the CBFA to address the fluctuating nature of CHOPS venting and to impose stricter testing requirements on lower-venting facilities.

Some respondents requested more detail about how the AER will assess for compliance with the Methane Reduction Retrofit Compliance Plan (MRRCP).

8.1 The AER will audit MRRCPs for adherence with the requirements in section 8.1. The MRRCP will be used as a tool to ensure that operators are positioned to meet the requirements. The quality of MRRCPs will be used to develop risk profiles for data audits and to determine priority areas for regional sweeps.

Some respondents requested that the text in section 8.1 make it clear that no update to the MRRCP will be required after 2023 when all retrofits and replacements should be complete.

8.1 The AER has revised section 8.1 to make this clear. Section 8.1(3) now indicates that the MRRCP must be updated annually until January 1, 2023.

Issue Summary Sec # Response Change to Draft ReqsSome respondents did not agree with the requirement to include the resources and budget to execute the MRRCP because it is proprietary and resource allocation is not necessarily correlated to compliance outcomes.

8.1 All information the AER receives is a matter of public record. The AER does not, however, intend to publish individual MRRCPs.

Some respondents asked if the MRRCP will be submitted to the AER or if they will they remain with the duty holder.

8.1 Operators do not have to submit the MRRCP to the AER. However, the AER will begin auditing the plans on January 1, 2020, and operators must make the plan available to the AER upon request as of this date.

Some respondents indicated that the June 1, 2019, deadline for the MRRCP does not leave enough time to gather information to outline the resources, budget, and schedule that will ensure compliance with the requirements of section 8.6.

8.1 The AER has extended the deadline to January 1, 2020, to give operators time to collect data and prepare meaningful documents.

Changed the MRRCP deadline to January 1, 2020.

MEASUREMENT, MONITORING, AND REPORTINGA number of comments were received that methane emissions from the upstream oil and gas industry are significantly higher than what is currently reported.

The AER acknowledges that there is a degree of uncertainty with current methane emission estimates in Alberta. Consequently, we included comprehensive measurement, monitoring, and reporting (MMR) requirements to enhance the coverage of reported methane emissions. The new MMR system will be used to ensure that reported emissions are consistent with facility and production type to increase accuracy.

Comments were received regarding the need for strong, standardized measurement and reporting, along with further studies to reduce this uncertainty and improve the accuracy of methane emissions reporting.

Currently, National Inventory Report emissions for Alberta are based on reported information that is supplemented with estimates. New measurement monitoring and reporting requirements in Directives 060 and 017 will improve emissions estimates to reduce uncertainty and improve accuracy.

Ongoing research and development projects to update and refine emission factors will also improve the quality of reported data. (See https://www.aer.ca/providing-information/by-topic/methane/reports-and-studies.)

There were requests for transparency in the data collected on methane emissions. Specifically, some commenters would like publicly available data on a per site basis to determine if a site is in compliance. Others asked for industry performance information for benchmarking against other operators.

The AER will make methane emissions data available publicly, which may be in a similar format to the pipeline performance and water use performance reports available on the AER website.

Concern was raised that where a transfer of ownership of a facility takes place late in a year, the records from the previous operator may not be transferred or be incomplete.

8.2 Holding the operator of record at the end of the calendar year responsible for reporting and record keeping is consistent with other AER directives. The OneStop system will retain annual methane emissions reports, keeping a record of previously submitted data.

Issue Summary Sec # Response Change to Draft ReqsSome respondents felt strongly that the measurement, monitoring, and reporting system needed to be improved by including detailed reporting by source venting category, the function and bleed rate of pneumatic devices, and taxation level reporting results, and by adjusting the economic calculations for vent gas conservation at heavy oil facilities. They also suggested the measurement, monitoring, and reporting system be continuously improved.

Annual vented methane emissions will be reported in OneStop by equipment source. Record-keeping requirements for pneumatic devices have been expanded to include device type, and bleed rate can be determined from device make and model. Emissions will be reported in OneStop at the Facility ID level and can be verified using Petrinex reported data. Adjusting the economic calculations for vent gas is out of the scope of the methane project but has been noted. The AER will continue to update and improve the measurement, monitoring, and reporting system as methane requirements are implemented.

Changed section 8.11 to address reporting.

Some respondents were unclear whether emissions from pneumatic devices that are exempted from requirements to maintain safe operating conditions or to achieve a necessary response time should be included in the calculation for the OVG limit.

8.3 & 8.6.1.1 Prior to 2023, the OVG limit excludes emissions from equipment sources (pneumatic instruments and pumps, compressors, and glycol dehydrators). After 2023, all vent gas from pneumatic instruments and pumps should be included in the OVG limit. For both before and after 2023, all equipment categories are reported in the VENT code in Petrinex. This is clarified in the measurement, monitoring, and reporting manual.

Some respondents said that 3.75 per cent of raw gas receipts in any year of operation is not sufficient, and many plants will be noncompliant when the new flare definition, with acid gas and dilution gas volumes included, takes effect.

5.2 The AER based the percentage of raw gas receipts per operating year on a sample set of data that indicated that 3.75 per cent will not significantly increase noncompliance. Acid gas volumes are excluded and a mechanism for their exclusion is being developed.

Comments were made that the methane requirements only use source level or "bottom-up" emissions quantification and reporting and asked if the requirements could accommodate atmospheric or "top-down" quantification methods and reporting.

Current top-down quantification methods are not able to distinguish whether a methane source is an upstream oil and gas source or a source outside the AER's regulatory mandate. The AER's quantification and reporting methodologies are aligned with other international standards that rely on bottom-up quantification.

The AER supports new emission quantification methods and has put provisions in the fugitive emissions requirements for alternative fugitive monitoring programs so more top-down measurement and monitoring approaches for fugitive emissions can be applied when feasible.

A comment was received that the compressor power rating should be included as one of the items in the annual methane emissions report

8.11 The AER has added to the record-keeping requirements. It is not a required reporting field.

The compressor seal power rating has been added as a record keeping requirement in 8.11(1)(k)(ii)

A number of comments were received that the definition of Facility ID in appendix 2 should not cross-reference the definition of Facility ID in Directive 047.

Appendix 2 For ease of reference, the Facility ID definition from Directive 047 has been added to appendix 2.

Added definition of Facility ID to appendix 2

Issue Summary Sec # Response Change to Draft ReqsComments asked that the AER reinforce the use of ABCS codes by specifically stating in the Facility ID definition that ABCS codes are included.

Appendix 2 Directive 060 uses the Facility ID from Directive 047 for consistency. The measurement, monitoring, and reporting manual clarifies the use of ABCS codes.

A number of comments expressed the need for changes to gas-to-oil ratio (GOR) test procedures to improve the accuracy and quality of reporting from cold heavy oil production with sand (CHOPS) operations.

D060 s.8.5 & D017 s12.2.2

The AER is studying GOR testing procedures to inform any future regulatory changes needed to improve reporting.

Commenters asked whether both volume and mass limits must be met for the DVG and OVG where limits are expressed by volume and mass.

8.3 & 8.4 A duty holder has the option to meet either the mass or the volume limit.

Some comments expressed a preference for direct emissions measurement rather that estimation methods.

8.2 Both estimation and metering are forms of measurement. The AER requirements use estimation or metering depending on what is appropriate to balance accuracy and cost. The AER is also conducting studies to improve emission factors and testing methods.

A number of comments were received requesting a measurement, monitoring, and reporting manual and expressing interest in participating in the manual's development.

8.2, 8.6 & 8.11 The AER has published the measurement, monitoring, and reporting manual to provide guidance for methane emissions estimation and reporting. Quantification methodologies and sample calculations for each source will be included. The manual was developed with input from consultants and other subject-matter experts.

A commenter asked whether nonroutine venting is to be reported into OneStop. If so, more time will be needed for implementation.

8.3 Duty holders do not need to report nonroutine venting in OneStop. However, these volumes are included in Petrinex reporting.

A commenter noted that there are no reporting requirements for the OVG limit in D060.

8.3 This information is captured through monthly reporting in Petrinex.

Some commenters asked whether the records are required to be kept onsite. 8.11 No, the records do not have to be stored onsite. Any records requested by the AER must be submitted within 30 days of the request.

A number of comments asked whether the operator physically operating the plant on December 31 or any active operator who operated the facility at some point during the year is responsible for methane emissions reporting.

8.2 The AER updated the directive to clearly define "operator of record" and made it clear that the operator of record as of December 31 is responsible for methane emissions reporting for that year.

In section 8.2, "operator" is changed to "operator of record." In appendix 2, a definition for "operator of record" was added.

Commenters asked that industry be given the flexibility to report to the well level (UWI) rather than in aggregate at the Reporting Facility ID level (ABBT battery level).

8.2 Reporting venting and fugitive emissions at the UWI level is included in Petrinex but will not be possible in the OneStop reporting system.

A comment was received that a template is needed for the annual methane emissions report.

8.2 The OneStop reporting system provides a template for the annual methane emissions report.

A commenter asked for the in-effect date for DVG reporting. 8.4.1 The DVG must be reported as part of the annual methane emissions report. The first annual methane emissions reporting is due June 1, 2020, for the 2019 reporting year.

Issue Summary Sec # Response Change to Draft ReqsSome comments indicated that it would be challenging to complete an inventory, particularly for the 2018 reporting year, and asked that compliance assurance be less stringent on inventories, particularly in the first years.

8.11 The AER expects compliance with all requirements and does not adjust how stringently they are enforced. Given the current in-effect dates, operators should have sufficient time to complete the inventories required to comply with requirements.

A number of comments wanted more simplified measurement, monitoring, and reporting, while other comments requested more detailed measurement, monitoring, and reporting.

8.2 In developing its measurement, monitoring, and reporting requirements, the AER carefully considered what information would be needed for compliance assurance and performance measurement. Only essential information was included in the measurement, monitoring, and reporting requirements.

A number of comments requested clarification of the record-keeping in-effect dates for various equipment-specific requirements.

8.11 To complete the annual methane emissions report, operators must have up-to-date records.

A commenter noted that when multiple facility codes could apply to a single site, the AER should provide guidance as to which facility code to select.

Appendix 2 As required in Directive 017, duty holders need to clearly delineate their sites and assets to reporting Facility IDs. More guidance is provided in the measurement, monitoring, and reporting manual.

Several commenters asked for clarity on the definition of “site.” They felt that it is not clear if it refers to a geographical location, a Facility ID, a UWI, or something else. They asked what happens if a facility is noncompliant with a limit at a Facility ID level, but compliant on a geographic basis.

Appendix 2 Site is defined in Appendix 2. To enforce compliance, the AER will identify high risk sites by utilizing risk rules and will determine non-compliances through the investigation of high risk submissions at the Facility ID level.

A commenter asked how the AER plans to manage electronic reporting. 8.2 Within OneStop, the AER is developing a new reporting system to accept methane emissions information by source as well as other defined attributes that support compliance and performance management. Training and more information on OneStop will be made available.

VENTINGComments were made about how the new limits in section 8 work with the timelines and limits for combined conservation, flaring, and venting in section 2.

2 The limits and timelines in section 2 remain in effect. However, venting may not exceed the limits in section 8 when calculating the combined flared and vented volumes.

This has been made clear in section 2.

Some commenters asked that the source-specific exceptions to the OVG limit end on January 1, 2022, instead of on January 1, 2023.

8.6 The source-specific exception date was set to provide industry with sufficient time to work out operational issues associated with installing new equipment.

Issue Summary Sec # Response Change to Draft ReqsComments were received that venting from in situ facilities should not be covered by the requirements because in situ facilities are already subject to limits and restrictions through AER scheme approvals, facility licences, and EPEA approvals.

They also noted that the only significant venting from these facilities would result from upset conditions (which occur infrequently at in situ facilities) that could result in venting a volume of gas that exceeds the limits.

8.3 All sites and facilities must be designed and operated to comply with the venting requirements in Directive 060. Section 8.5 of the directive states that thermal in situ schemes and operations are '... excluded from the vent gas limits for crude bitumen batteries’.

Upset conditions are not exempt from the venting requirements in Directive 060 because they can be routed to control devices. Please note that in situ facilities that are over the volumetric limit in an upset condition may still be under the mass limit because OVG may be stated in both volumetric and mass terms.

A commenter pointed out that operators could exceed a vent-gas volume limit but not exceed the associated vent-gas mass of methane limit when there are low concentrations of methane in the vent gas stream. The significance of this noncompliance risk should be highlighted in Directive 060 to help reduce false noncompliances and the associated administrative burden to both the regulator and industry.

8.3 Operators have the option to provide methane emissions in mass rather than volume and to use the actual methane composition when reporting volumes.

A comment requested that the AER allow for a special exception for vent-gas capture and use via catadyne heaters. While they are not as efficient as the Directive 060 requirements, catadyne heaters are a cost-effective methane abatement tool.

8.7 Catadyne heaters are not considered a control device under Directive 060. Vent gas directed to a catadyne heater should be reported as fuel gas.

Some commenters felt that a maximum vent rate should apply to all sites that are using the crude bitumen fleet average (CBFA) to impose an upper threshold on any single site's venting.

8.5 The OVG limit acts as an upper threshold for venting at all sites, including those using the CBFA.

Several comments noted that operations in the Peace River area are excluded from the CBFA. They argue that operators in the area have made significant efforts to reduce emissions and odours in this area and fairness demands that these efforts be included in the CBFA.

8.5 Directive 084 is an area-based regulation dealing specifically with odour issues, whereas Directive 060 is province-wide and addresses methane emissions. The inclusion of Directive 084 areas into the CBFA could allow for greater venting in areas outside of the Peace River area.

Additionally, only a small number of companies operate in the Peace River area and AER modelling indicates that operators with sites excluded because of the Directive 084 exclusion would not bear an undue burden as compared to other companies.

Several commenters felt that the CBFA will allow operators of crude-bitumen sites to increase emissions.

8.5 The CBFA requires operators to reduce emissions while still providing flexibility to address the limit as they determine.

A comment was received that the CBFA should be used for all sites, not just for crude bitumen batteries, for consistency and to not unduly harm natural gas and conventional light oil production. The comment argues that it is inequitable for one segment of the industry to have different rules.

8.5 Emissions from crude bitumen sites come primarily from venting, which allows the AER to monitor these sites more closely and ensure that the fleet average is met. Emissions from other site types are more varied and do not lend themselves as readily to a fleet average approach.

Issue Summary Sec # Response Change to Draft ReqsSeveral comments asked that the AER clarify how fleets are to be grouped. 8.5 As indicated in section 8.5 (1), the fleet average is calculated based on the

venting from all crude bitumen batteries of a duty holder that reported production or venting in a month.

A comment asked that in cases where there are multiple licences at a single site, does each licence have an OVG limit?

8.3 No. Multiple licences at a single site do not increase the single OVG limit at a site. The OVG limit is a site limit, not a Facility ID limit.

A comment asked that when there is a reference to controlled liquid hydrocarbon tanks, is there a size limitation or is it intended to encompass any hydrocarbon tank (including small diesel storage and large crude oil tanks)?

Table 5 The reference to controlled liquid hydrocarbon tanks is meant to encompass any hydrocarbon tank with emissions being routed to a control device such as a flare or a vapour recovery unit (VRU).

It is not typical for a diesel storage tank to be routed to flare or VRU.

A comment was made that "venting," as shown in figure 10, does not include all types of venting.

Figure 10 Figure 10 is not a requirement and is only included to add clarity.

Fundamentally, if an activity is regulated under Directive 060 and methane is emitted to atmosphere, it is subject to the requirements of Directive 060.

A commenter felt that the statement, "the AER recommends that duty holders eliminate all routing venting," is vague and potentially provides scope for the AER to require the elimination of all routine venting.

8.0 This is a recommendation, not a requirement.

A commenter felt that there should be a requirement that duty holders have a plan in place for existing facilities to meet the defined vent gas (DVG) limit associated with that facility.

8.4 We encourage operators to have a plan in place to meet the DVG limit, but we do not require one because it is up to operators to determine control or process changes that are needed to meet compliance when the DVG limit comes into force.

The AER is focussing our planning efforts on equipment retrofit and replacement requirements because these require longer lead times for procurement and installation.

We received some comments that the DVG limit is too low and will overshoot the 45% reduction target, putting an undue burden on the Alberta oil and gas industry. Others felt that the DVG limit was too high and should be lowered to ensure that the reduction target is met.

8.4 Vent gas limits were determined on a portfolio basis. This means that some vent gas sources may reduce methane venting by more than the overall 45% target and some sources may reduce methane venting by less than the target – so long as the overall 45% reduction target is reached.

The source reductions are determined by several factors, including cost, reporting complexity, and certainty of reductions.

A commenter asked why vent gas from pneumatic devices, compressor seals, and glycol dehydrators were excluded from the DVG limit.

8.4 They are excluded because limits specific to these types of equipment are in place (see section 8.6).

Issue Summary Sec # Response Change to Draft ReqsSeveral comments noted that section 8.3 ends with, "the duty holder must comply with the vent gas limits specified below," but that no list of limits was provided.

8.3 The AER has revised this text to aid in clarity. The various vent gas limits are located in the Equipment-Specific Vent Gas Limits section (section 8.6).

Updated text in 8.3 1) to clarify where the vent gas limits can be found

Some commenters asked the AER to provide scenario-based examples to help illustrate the difference between OVG limit and DVG limit applications.

8.3 The measurement, monitoring, and reporting manual has a sample calculation outlining the difference between the OVG limit and the DVG limit.

Some comments noted that DVG and "other routine sources" appear to be the same thing and asked the AER to add DVG to figure 10 to make this clear.

Figure 10 Figure 10 is for illustrative purposes only and does not include limits. Routine and nonroutine are defined terms and not limits per se. DVG is the name of the limit associated with some (but not all) of the items covered by the "routine" definition.

A commenter noted that vent limits will be applied on a monthly basis and that, as the AER is currently enforcing vent limits on a three-month rolling average, suggested that this practice continue. They note that sites that routinely exceed vent limits will need to be addressed in either case.

8.3 The AER does not enforce vent limits on a three-month rolling average basis. The AER is using a monthly limit to increase certainty that the methane reduction targets are met.

Several commenters recommended that due to normal fluctuations in operating conditions, the compliance enforcement of the CBFA be done on a three-month rolling average vent rate, not on a one-month vent rate. This would accommodate normal operational fluctuations, particularly around start-up and interventions.

8.5.1 In the case of crude bitumen facilities, the fleet-average approach provides flexibility for fluctuations in normal operating conditions; therefore, additional flexibility is not required.

A three-month rolling average approach would limit the AER's ability to meet the reduction target.

Comments were received stating that the OVG limit would allow existing sites to vent vast amounts of gas from tanks and other equipment with little constraint and that an approach to venting that allows those emissions to increase is more lax than in other jurisdictions and is not credible.

8.3 The OVG limit acts as a ceiling on all venting – both routine and nonroutine – and is in line with existing limits on venting. In addition to the OVG limit, there are additional vent-gas specific limits that will further reduce venting from tanks and other equipment. Taken together, these requirements will reduce venting and help achieve the methane reduction target.

A commenter noted that OVG limit is applied regardless of facility size and operation type and argued that it should be increased for larger facilities.

8.3 Larger facilities typically have controls in place to limit venting. The AER has consistently applied a 500 m3/month venting limit to all facilities.

A large number of comments were received asking for more clarity or suggesting changes to table 4.

Table 4 Table 4 is intended to be used as a summary and the requirements are contained in the sections that follow and has been updated to improve clarity.

Table 4 has been updated to improve clarity.

PNEUMATICSSome respondents were unclear if the vent rate or actuation requirements for instruments installed before January 1, 2022, apply to the 10% of venting instruments allowed if installed after January 1, 2022.

8.6.1 In the final requirements, the language has been changed to make it clear that the vent rate and actuation requirements apply to both instruments installed before January 1, 2022, and to those installed after.

Updated text in 8.6.1

Issue Summary Sec # Response Change to Draft ReqsSome respondents highlighted that the 10% set aside for venting pneumatics requires operators to retain an inventory of instruments on an ongoing basis, which increases administrative burden.

8.6.1 Duty holders only need to inventory as many instruments as required to support the calculation of any venting instruments up to 10%.

Additionally, operators are only required to maintain an inventory of instruments, not create a new one every year.

Some respondents indicated that time-based actuation requirements should account for production variations or recharge run times.

8.6.1.4 The AER understands that the actuation frequency of level controllers operating at well sites is related to production and well recharge. Level controllers can be installed in multiple different configurations and not only at wells. The AER has clarified that actuation frequency should be measured under normal operating conditions.

Reworded 8.6.1 to clarify that actuation frequency is to be measured during normal operating conditions

Some respondents indicated that removing exemptions and applying vent-rate requirements for devices installed before January 1, 2023, would be a clearer approach.

8.6.1 The approach selected by the AER is intended to optimize flexibility for operators and expand emissions-reduction coverage in low abatement cost source categories. Moving to vent-rate-based device requirements would require stricter requirements in other source categories to compensate for a loss in reductions.

Some respondents asked that an economic threshold be applied for retrofits that may be uneconomic at some sites.

8.6.1.4 The AER considered a variety of approaches to address economic considerations; however, these would be administratively burdensome and would increase the overall cost of regulation. The Government of Alberta (GoA) has offset credit programs in place to ease the economic burden of pneumatic requirements.

Some respondents asked why propane-driven pneumatic devices were exempted from the requirements.

8.6.1 Propane-driven pneumatic devices are now included in the requirements. The AER does not want to incentivize operators to install propane-driven pneumatic devices, which still emit gas, over nonemitting technologies.

Removed exception for propane-driven pneumatic devices in section 8.6.1

Some respondents were concerned that they would be required to annually inventory their sites to update their pneumatic inventory to meet the record-keeping requirements in 8.11(1)(c).

8.11 The AER reviewed the wording in 8.11 to ensure that it is clear that operators do not need to visit each site on an annual basis to inventory pneumatics so long as an accurate inventory is maintained.

"Annual" has been removed from the reference to "inventories" in section 8.11 (1) (c)

Some respondents requested that additional wording be added to suggest that operators go beyond the requirements and use no-bleed pneumatic solutions wherever possible.

8.6.1 Section 8 includes a statement recommending duty-holders to eliminate all routine venting. The definition of low-vent alternative was deleted and the language has been updated to not exclude non-emitting technologies as acceptable alternatives.

Low-vent alternative deleted

Some respondents asked what requirements apply to chemical injection pumps for sites constructed before 2022.

8.6.1.4 Chemical injection pumps for sites constructed before 2022 are covered under the OVG limit beyond 2023.

Some respondents requested that safety exemptions be expanded to include devices installed after 2022.

8.6.1.1 The AER reviewed the wording in 8.6.1 to ensure that it is clear that safety and response time exemptions are applicable for devices installed after 2022.

Updated sections 8.6.1

Issue Summary Sec # Response Change to Draft ReqsSome respondents suggested that the wording in section 8.6.1(4)(a) and (b) more explicitly state that low/no-vent alternatives, or controls, are acceptable options to allow for more flexibility.

8.6.1 (4) The AER has removed the reference to low-vent alternative and added language to clarify that zero-venting options will apply.

Updated 8.6. to use actuation frequency rather than "low vent." Also, deleted "low-vent alternative" from appendix 2.

COMPRESSORSOne commenter noted that mandating compressor packing vent metering with an uncertainty requirement that lines up with Directive 017 section 1.7.2 is too stringent at 5% single-point uncertainty (especially for such a low-flow-rate gas stream).

8.6.2 In section 8.6.2(2), the maximum single-point test uncertainty has been specified at +/- 10% based on an AER testing study for flows over 0.1 m3/hr with no stringency for flows below that volume.

Changed compressor seal testing uncertainty in section 8.6.2 (2)

A comment was made that the costs to reduce emissions from compressors may outweigh the benefits and that the AER should consider exempting them.

8.6.2 Compressors are a material source of emissions in the upstream oil and gas industry. Measurement activities and costs to reduce emissions from compressors can be coordinated with fugitive-emissions surveys or routine maintenance activities. Additionally, to reduce costs, the AER has included a fleet average for reciprocating compressor venting to give operators the freedom to determine where to incur costs.

Some commenters asked the AER to define "fleet." 8.6.2 The reciprocating compressor seal fleet is expressly defined in section 8.6.2.2 as the duty holder’s reciprocating compressors that are rated 75 kW or more, pressurized for more than 450 hours per calendar year, and eithera) were installed before January 1, 2022, orb) were installed on or after January 1, 2022, and have fewer than four throws

Changed 8.6.2.2 2) to define RCS fleet.

A commenter asked the AER to provide clarity on compressor "pressurized hours" and asked whether the AER would allow the use of "unit operating hours" as a proxy.

8.6.2 We expect pressurized hours to align with operating hours. In cases where they don't align, operators are expected to track pressurized hours.

The directive uses the term "throw," which appears to equate to "cylinder." A commenter asked if the AER would consider replacing "throw" with "cylinder" for consistency with the federal requirements.

8.6.2 The AER considered replacing throw with cylinder ; however, as defined in the directive, a throw contains the entire rod packing seal system and not just the cylinder. The term "throw" is more inclusive of the potential vent sources that need to be considered.

Commenters asked how a "deactivated throw" should be addressed in the fleet average calculation.

8.6.2 Throws that are not pressurized (e.g., a deactivated throw) have no weight in the fleet average (time pressurized = 0).

Some commenters noted that vent gas control systems for reciprocating compressors may cause backpressure to the crankcase and result in methane venting. And they asked for exceptions for certain makes and models where this will be an issue.

8.6.2 The AER has updated the requirements so that operators are not required to tie-in and control compressor crankcase vents. The exception can be found in section 8.6.2.2.

Changed the reciprocating compressor seal description in section 8.6.2.2

Issue Summary Sec # Response Change to Draft ReqsA commenter noted that many reciprocating compressors between 0.75 and 1 MW are being used in the upstream oil and gas sector in Alberta and that the provincial requirements for these compressors are much less stringent than the federal requirements.

8.6.2 The AER requirements capture compressors that are rated higher than 75 kW (0.75 MW) and operate for more than 450 hours per calendar year. The AER acknowledges that the federal reciprocating compressor requirements are different; however, the overall approach of these regulations achieves Alberta's methane reduction target.

Some respondents disagreed with the compressor fleet-average approach, arguing that it is essentially unenforceable. They argue that emissions-monitoring technologies have not advanced sufficiently and are not cost-effective enough for it to be possible for the AER to monitor each site individually. This would leave the proposed regulatory methodology open to abuse. They concluded that because the AER can in no way confirm that individual facilities are complying with the proposed regulations, the fleet-average approach should be avoided.

8.6.2 The measurement, monitoring, and reporting requirements, particularly those for compressors, enable the AER to effectively enforce compressor seal venting requirements under a fleet average approach. Compressor seal venting is well defined and practical to quantify. Managing compressor seals as a fleet will allow operators to best allocate capital and effort. Unit-specific vent-rate limits were deemed too restrictive and did not account for the different variables in managing compressor-seal maintenance.

A commenter asked the AER to provide the duration of the compressor seal test. 8.6.2 The AER considered adding a time requirement but given the wide range of flows and various measurement devices a minimum time was not practical and could cause confusion. The AER deems the measurement sufficiently accurate if the uncertainty and back pressure requirements are met regardless of the amount of time used for the test.

One reader asked the AER to indicate what flow meters would be fit-for-purpose for compressor seal vent tests as compressor seals typically vent at very low flow rates and are subject to backpressure issues.

8.6.2 The AER updated the measurement device criteria in section 8.6.2.1. to address backpressure issues and low vent rates.

Section 8.6.2.1(2) updated to specify test parameters.

One commenter asked the AER to consider a "step down" program, for duty holders who are able to demonstrate that they have an effective program in place to detect compressor-seal leaks, that would move the annual testing requirement to once every two years.

An example of an effective program could be monitoring the compressor temperature on a daily basis. Temperatures above normal would result in a packing change-out.

8.6.2 The AER is not considering a performance-based compressor-seal testing frequency program at this time. Annual testing can be aligned with regular service intervals, fugitive emissions surveys, or ongoing monitoring/ preventative maintenance. Compressor seal emissions vary by make, model, process conditions, and service. Due to the variance introduced by these factors, seal testing is the most appropriate way to estimate emissions from compressors.

Commenters asked why the AER is requiring that all testing points be accessible and clearly identified prior to January 1, 2020?

8.6.2 Testing points need to be clearly identified and accessible on January 1, 2020 to provide consistent measurements and allow for safe and accessible measurements. This timing aligns with the compressor-testing requirements.

Issue Summary Sec # Response Change to Draft ReqsCommenters argued that 30 days to bring a compressor seal into compliance following measurement is too short. For example, the compressor cannot be shut down if the ambient temperature is low because it is contributing to maintaining heat in other critical components, or if the vent rate is high due to a failure unrelated to the seals and replacement parts are unavailable.

8.6.2 The 30-day repair requirement only applies to very high venting (>5 m3/hr /throw) compressors. A four-throw compressor having a >5 m3/hr/throw vent will yield a vent rate higher than the OVG limit, meaning that the compressor vent is putting the entire site out of compliance. If this is true, the operator will be out of compliance regardless of the 30-day repair limit.

A comment asked what the AER's expectation for reporting vent gas emitted from compressors rated less than 75 Kw and operating less than 450 hours is, given that it may be difficult to schedule tests for such compressors, particularly if a third-party company is doing the testing.

8.6.2.4 Vent gas from compressors rated less than 75 Kw and operating less than 450 hours can be estimated. Vent-seal testing is only required for compressors rated more than 75 kW and operating for more than 450 hours.

For guidance, see the measurement, monitoring, and reporting manual.

Commenters asked the AER to include sample calculations for the RCS fleet average in the directive.

8.6.2 Sample calculations are in the measurement, monitoring, and reporting manual.

Several comments were made asking why testing begins in 2019 when the vent-gas limits for compressor seals not in effect until 2022.

8.6.2 In the draft requirements, the in-effect date was set to align with the first methane emissions annual report. However, a large number of comments requested that the AER streamline in-effect dates. As part of this effort, the AER has moved the testing in-effect date to 2020 to align with fugitive emissions and MRRCP dates. Testing before 2022 provides useful baseline data.

The AER changed the measurement date to January 1, 2020, in section 8.6.2.1 (1)

DEHYDRATORSA commenter asked if vent gas from glycol dehydrators includes flash-tank gas and still overheads gas

8.6.3 Flash-tank gas and still overheads gas are considered vent gas if they lead to a vent and should be included in the glycol dehydrator vent volumes.

Commenters asked for examples of the fleet-average calculation. 8.6.3 Examples are provided in the measurement, monitoring, and reporting manual.

Commenters asked the AER to define "fleet." 8.6.3 Fleet is defined in section 8.6.3 as the "number of glycol dehydrators that are authorized to the duty holder."

Commenters asked if there is an opportunity to streamline the reporting requirements from Directive 039 with the reporting requirements for glycol dehydrators in Directive 060.

8.6.3.2 When the requirements take effect, emissions from glycol dehydrators will be reported using OneStop in accordance with requirements in Directive 039. This includes benzene and methane emissions and will obviate the need to report glycol dehydrator emissions again under D060.

Issue Summary Sec # Response Change to Draft ReqsFUGITIVE EMISSIONSSome respondents requested additional detail on acceptable elements for the alternative FEMP.

8.10.6 The AER intentionally worded these requirements broadly so they would not be overly prescriptive and could accommodate a variety of programs and technologies. Operators should consider how their programs would meet outcomes that are equivalent to those prescribed in sections 8.10.1–8.10.5, and be able to justify these in their applications.

The AER is working with other jurisdictions to provide more details on a standard process for technology performance evaluations and alternative FEMP application requirements.

Some respondents noted that conducting fugitive emission surveys at sites where all emissions are captured under the DVG limit or OVG limit is redundant and that these sites should be exempted from survey requirements

8.10.2.1 The AER acknowledges that fugitive-emissions surveys at sites that vent all gas will not achieve fugitive-emission reductions. The directive has been updated to say that sites where all produced and received gas is vented are exempted from survey requirements.

Updated section 8.10.2.1 to exempt sites that don't have fuel/flare/disposition volumes

Some respondents felt that operators should not have to apply to the AER prior to implementing alternative FEMPs.

8.10.6 Approval is required prior to implementing an alternative FEMP so that the AER can ensure that emissions reduction targets will be met.

Some respondents indicated that the detection threshold in section 8.10.2.2 was based on the best achievable results in laboratory conditions; the results are not replicable in the field.

8.10.2.2 The AER updated section 8.10.2.2 to allow for technologies with higher minimum detection thresholds when used in the field. The threshold was amended to align with published field-level performance levels of gas imaging infrared cameras.

Section 8.10.2.2 1b) updated to include field-based performance threshold.

Some respondents requested that the AER clarify the survey frequencies that apply to single-well batteries and satellite facilities.

8.10.2 Table 5 has been updated to make it more clear what survey frequency applies to these facilities.

Table 5 was updated to make this clear.

Some respondents requested that the AER clarify why lower survey frequencies are applied at sour facilities.

8.10.2 Sour facilities are designed with more controls on emissions for safety reasons. These additional controls, along with a heightened awareness among duty holders of the potential risk of off-site release issues means that fugitive emissions may be detected more often at sour facilities than at sweet facilities.

Some respondents asked the AER to clarify whether a controlled liquid hydrocarbon or a controlled produced-water tank at site triggered a triannual survey requirement at sites that would otherwise have an annual survey frequency.

8.10.2.1 The AER reviewed the wording in table 5 to make it clear that only the controlled liquid hydrocarbon or controlled produced-water tank must be surveyed triannually, not the whole site.

Table 5 has been updated to make this clear.

Some respondents asked for clarification on how surveys should be conducted. 8.10.2.3 The AER has published a fugitive-emission manual, which provides more detailed guidance.

Some respondents indicated that an in-effect date of June 1, 2019, does not allow enough time to compile a complete FEMP.

8.10.1 The AER extended the effective date for fugitive-emissions management programs to January 1, 2020.

Section 8.10.1 has been updated

Some respondents indicated that the AER should be more prescriptive in the requirements for the fugitive emissions management program.

8.10.1 The level of detail provided in section 8.10.1 and appendix 12 strikes a balance between prescription and flexibility. More details about FEMP development and content are in the fugitive emissions manual.

Issue Summary Sec # Response Change to Draft ReqsSome respondents suggested that survey frequencies should take into account a facility's leak performance. Facilities that show consistently high fugitive-emission counts should be required to survey more frequently, and those with lower counts should be required to survey less frequently.

8.10.2 The AER considered a performance-based approach in its regulatory design process.

Some respondents suggested that survey frequencies in table 5 are too high and will result in significantly more emissions reductions than the 45% reduction target and will result in unwarranted costs to industry.

Other respondents suggested that the frequencies were too low and would miss significant volumes of fugitive emissions. They asked that the survey frequency be increased and expanded to cover sites currently covered under fugitive-emissions screenings.

8.10.2 The AER has completed modelling based on best available information that demonstrates approximately a 43% reduction in fugitive emissions as a result of these requirements.

The approach and stringency selected for the fugitive emissions source category balances emissions reductions with those from other sources to meet the overall target while keeping in mind costs and reporting burden.

During the regulatory review, data collected through the measurement, monitoring, and reporting system and additional R&D efforts may be used to inform an update to the stringency of the requirements.

Some respondents requested that the AER modify the requirement to use the survey record template in appendix 13. Instead, they asked to be able to use their existing record-keeping processes as a basis for reporting to the AER.

8.11 The AER has incorporated the fields from the survey record-keeping form template into section 8.11. Use of the survey record-keeping form template is not required, and operators may use their own record-keeping processes.

8.11 now includes the information previously in appendix 13. Appendix 13 has been moved to the fugitive emissions manual.

Some respondents were concerned that requirements to survey and screen for surface casing vent flows overlap with the testing, repair, and reporting requirements in the AER's ID 2003-1.

8.10 The requirements in Directive 060 are not intended to duplicate those of ID 2003-01. The requirements in Directive 060 will potentially result in more timely identification of SCVF issues, but the testing, repair, and reporting requirements fall under ID2003-01.

Some respondents were concerned that survey requirements at thermal wells would result in false positive test results where steam or thermal feedback from the well could be confused for methane.

8.10.4 Section 8.10.4 indicates that repairs are only required for fugitive emissions, which are defined as unintentional releases of hydrocarbons to the atmosphere. In cases where operators are concerned about false positives, they can be verified with a survey method that confirms the presence of hydrocarbons prior to triggering the repair requirements.

Some respondents indicated that requiring annual screenings at observation wells is not feasible as these sites are not accessible on an ongoing basis.

8.10.3.1 Observation wells licensed as oil sands evaluation wells or test holes under section 2.030 of the OGCR are exempt from the screening requirements.

Section 8.10.3.1 has been updated.

Some respondents requested that natural gas liquids extraction (straddle) plants be exempted from the AER methane requirement under Directive 060 because they are low-risk facilities.

8.10.2.1 Straddle plants are not exempted from the AER methane requirements. However, the AER has updated the frequency of fugitive emissions survey requirements for straddle plants to once per year.

Table 5 has been updated to reflect this change.

Issue Summary Sec # Response Change to Draft ReqsSome respondents indicated that equipment designed to emit gas under certain circumstances should also be included in the survey scope to capture emissions if it is emitting excessively due to poor operation or equipment failure.

8.10.2.3 To address this concern, we added pneumatic devices as inspectable equipment.

Updated section 8.10.2.3 to include hydrocarbon gas-driven pneumatic devices.

Some respondents felt that costs to complete fugitive emission surveys were underestimated by the AER.

8.10 Cost estimates were developed through a multistakeholder process, which included contracting an independent third party to compile cost estimates from literature and actual costs quotes using the best available information.

Some respondents requested that the AER remove pipeline integrity from the AER's list of conditions that may require additional action.

8.10.1 The statement was amended for clarity. Updated 8.10.1 to make it clear that pipeline integrity is a concern with regard to being a source of fugitive emissions.

Some respondents requested that more detail be included to describe how repair integrity is verified.

8.10.4.1 The AER intended this to be an open-ended statement to allow operators flexibility to use the most appropriate verification method for the type of repair.

Some respondents asked the AER to reduce the 10 000 PPM repair threshold. 8.10.4 The AER used industry and academic research that shows that a 10 000 PPM repair threshold is sufficient to meet the reduction target.

Some respondents asked the AER to extend the 30-day repair time to accommodate longer procurement timelines.

8.10.4 The AER acknowledges that there may be circumstances where equipment or components needed for repairs might take longer than 30 days to receive. However, given the nature of most fugitive emissions, we expect that these circumstances will be exceptional and can be dealt with through the AER's voluntary self-disclosure process.

Some respondents indicated that the AER should provide guidance on how to properly train personnel to complete repairs.

8.10.4 The AER agrees that duty holders should ensure that personnel are adequately trained before conducting action on a facility. However, due to the variable nature of facilities, operations, and sources of fugitive emissions, the AER is not in a position to dictate suitable repair-training requirements.

Some respondents found it difficult to identify which well sites should be screened or surveyed.

8.10.2.1 The AER has revisited the wording in section 8.10.2.1 to make this more clear. Updated section 8.10.2.1 and table 5

Some respondents requested that annual screenings at wells be removed from the requirements to align with those put out by Environment and Climate Change Canada (ECCC).

8.10.3 To increase coverage and emissions reductions, the AER has selected an approach that's different from ECCC's and has included annual screenings at well sites. Screenings are less resource-intensive than surveys.

Some respondents requested removal of sour-service components from surveys. 8.10.2.3 Sour-service components are not omitted from surveys because they can still wear or fail, resulting in fugitive emissions. Surveys are useful tools for detecting these emissions.

Some respondents suggested that survey and screening requirements should apply at suspended facilities.

8.10.2 Fugitive emissions from suspended facilities (i.e., surface casing vent flow and gas migration) are subject to the requirements of ID2003-01 rather than Directive 060.

Issue Summary Sec # Response Change to Draft ReqsSome respondents highlighted the importance of new emissions-detection technologies and opportunities to collaborate on developing new technologies.

8.10.2.2 The AER appreciates the importance of new detection technologies and has taken steps to facilitate their uptake through provisions for alternate detection technologies in survey and screening methods and equipment requirements as well as in the alternative fugitive emission management program option. The AER participates in a number of technology development and deployment research initiatives and makes research outcomes of AER-funded studies public.

Some respondents requested more detail describing how fugitive emission surveyors should be trained.

8.10.2.4 The fugitive emissions manual contains more detail regarding training.

A respondent asked the AER to define "malfunctioning equipment" as shown in the fugitives section of figure 10.

8.0 Figure 10 has been updated to simplify fugitive emissions Figure 10 was updated to delete examples of fugitive emissions.

ENCLOSED COMBUSTORSSome respondents suggested that enclosed combustors should be allowed a reduced conversion efficiency of 97% or 98% as long as the H2S content is low (<1%) and the heating value of gas is sufficient (>20 MJ/m³).

7.1 Given the design and operating parameters listed in section 7.1.3, it is reasonable for enclosed combustors to meet ≥99% conversion efficiency.

Some respondents requested that the AER provide a definition of an enclosed combustor.

7 An enclosed combustor is an incinerator that meets the design and operating parameters in section 7.1.3. The AER does not specifically define these types of equipment so vendors and operators have the flexibility to use appropriate equipment designs for each site, providing they meet the requirements in section 7.

Some respondents were concerned that requiring liquid separation on every enclosed combustor installation would result in unacceptably high costs. Instead, they proposed having liquid separation required only if performance is affected.

7.6 Section 7.6 gives a range of liquid separation options, so long as they are adequate for the system they are being used for.

Some respondents suggested that the AER use other terms instead of "enclosed combustor."

7 The term "enclosed combustor" is meant to denote any class of equipment meeting the design standards in section 7.1.3.

Some respondents were concerned about noise from enclosed combustors. 7.10 Directive 060 section 7.10 states, "Flares and incinerators must be designed and operate in compliance with Directive 038." Directive 038 contains the AER's requirements for noise control.

Some respondents requested that the AER review the 500-metre residential setback for enclosed combustors.

7.8 The residential setback for flares and incinerators is outside of the scope of the methane requirements. Enclosed combustor spacing requirements can be found in section 7.8.

Some respondents were concerned that enclosed combustors would increase the likelihood of forest fires.

7 The design parameters for enclosed combustors—no visible flame, flame arrestors, gasses and exposed surfaces below auto-ignition temperatures—specifically prevent the possibility of fire.

Some respondents asked whether new enclosed-combustor requirements will affect existing fuel-burning devices.

7 Existing fuel-burning appliances are not affected by the enclosed-combustor requirements.

Issue Summary Sec # Response Change to Draft ReqsSome respondents requested that the AER remove the requirement in section 7.1.3 c) that all surfaces exposed to the atmosphere must be below the auto-ignition temperature of gases in the atmosphere.

7.1.3 This design parameter is crucial to prevent the auto ignition of gases in the atmosphere; therefore, the AER requires that this parameter be met for the operation and spacing of an enclosed combustor.

Some respondents asked the AER to clarify whether "enclosed combustion technology" (section 7.1.2 (3)) and "enclosed combustor" mean the same thing.

7.1.2 To avoid confusion between the two, the AER removed "enclosed" from "enclosed combustion technology."

The AER removed "enclosed" from 7.1.2 (3).

FUEL/FLARE/VENT DEFINITIONSA number of comments raised concerns that changes to the fuel, flare, and vent definitions would increase reported flaring.

Appendix 2 The AER will implement a communications and engagement plan to make clear that the increase in reported flared volumes is attributed to the change to the definition of flare gas and does not reflect an actual increase in flaring.

Comments were received asking that incineration and flare be tracked differently as they have different combustion-efficiency rates.

For the methane requirements, flare and incineration will both be tracked as flare.

A number of commenters asked the AER to add "enclosed combustors" to the list of destruction devices in the flare-gas definition.

Appendix 2 As enclosed combustors are new to this version of Directive 060, we have added them to the flare-gas definition.

Added enclosed combustors to the definition of "flare" in appendix 2.

A comment noted that having the acid-gas volumes intermixed with other flare-gas volumes would be problematic for emissions calculations and reporting and would be different from how these emissions are currently reported federally and provincially.

Appendix 2 The AER is proposing a change to the ACGAS product type in Manual 11 to separate acid gas volumes from flare volumes. This project is underway and once completed, compliance will not be calculated on the acid gas intermixed in flare volumes.

The AER has made changes to sections 4 and 11 of Directive 017

A commenter asked whether nitrogen used to purge pipelines should be reported as a vent or a flare.

Appendix 2 Guidance on this issue can be found in the measurement, monitoring, and reporting manual, which will address reporting nuances in this and other activities and emission types.

A commenter asked how pilot gas will be treated under the changes to the fuel, flare, and vent definitions.

Appendix 2 If equipment that has a pilot is burning gas for a useful purpose (e.g., using the chemical energy of the gas to heat a process/fluid), it is fuel gas.

Pilots for flares, incinerators, and internal combustors that are only destroying gas that is being wasted would be categorized as flare.

A number of comments asked for more time before the changes to the fuel, flare, and vent definitions come into effect to ensure that the proper system training and procedures are in place.

Appendix 2 The changes to the fuel, flare, and vent definitions are important from a methane-emissions reporting perspective to get a more accurate picture of methane emissions.

However, we recognize the implementation challenges. Accordingly, the changes to the fuel, flare, and vent definitions will not take effect until January 1, 2020.

Changed the in-effect date of the directive to January 1, 2020.

Issue Summary Sec # Response Change to Draft ReqsThe distinction between vent gas and fugitive emissions should be made more clear. The vent-gas definition excludes fugitive emissions but includes examples such as gas from facility upsets, gas from production tanks, and gas vented during well unloading that could arguably be classified as unintentional releases of hydrocarbons to the atmosphere.

Appendix 2 The examples provided are cases of unplanned venting at a facility designed to vent. Fugitive emissions occur in circumstances where the facility is not designed to vent, such as equipment component leaks, wear and tear, improper assembly, inadequate material specifications, manufacturing defects, damage during use or installation, corrosion, and fouling. Further guidance is provided in the fugitive emissions manual.

Some respondents asked for additional types of control equipment to be added to the definitions of fuel, flare, and vent.

Appendix 2 The lists provided in these definitions are meant to be illustrative rather than exhaustive. Further guidance can be found in the measurement, monitoring, and reporting manual.

Respondents asked if "vent gas" includes fugitive emission volumes or if Petrinex will include a new reporting category to capture fugitive-emission volumes.

Appendix 2 The definition of vent gas expressly excludes fugitive emissions. Fugitive emissions will not be reported in Petrinex but are instead captured in the annual methane emissions report submitted through OneStop.

Concerns were expressed that with the change in the fuel, flare, and vent definitions, sulphur recover plants (subtype 405) would no longer meet their licensing conditions for combustion efficiency.

Appendix 2 The change in the fuel, flare, and vent definitions will not come into effect until January 1, 2020. This will provide time for the AER to ensure that the new definitions do not affect the ability of sulphur-recovery plants to meet their licensing conditions.

Some comments expressed concern that the changes to the fuel, flare, and vent gas definitions would mean that they were no longer in compliance with their licence conditions.

Appendix 2 The AER recognizes that the changes to the fuel, flare, and vent gas definitions could mean that some existing facilities will no longer meet their licence conditions. Based on preliminary analysis, this is not expected to affect many facilities.

The AER will review licensing conditions to ensure that companies are not out of compliance with licensing conditions simply as a result of this change in definitions.

DIRECTIVE 017One commenter asked that dilution gas be removed from the flare-gas definition and be kept in the fuel definition.

Appendix 2 AER analysis of the impact of including dilution gas in the definition of flare gas indicated that this change will primarily affect small acid-gas plants. To reduce the likelihood that these facilities will be out of compliance because of this change, the flare limit for acid-gas plants processing less than or equal to 0.1 109 m3 per year (raw gas inlet volume) was increased.

Why does the "What's New in this Edition" section reference changes to standard of accuracy when no changes were made?

Introduction The "What's New in this Edition" section has been updated. Deleted "standard of accuracy" from the 'What's New in this Edition section.

Some respondents asked for additional types of control equipment to be added to the definitions of fuel, flare, and vent.

Appendix 2 The definitions for fuel, flare, and vent have been deleted from Directive 017. They are only in Directive 060.

The fuel, flare and vent definitions have been deleted.

Issue Summary Sec # Response Change to Draft ReqsCommenters recommended that GOR testing frequency for low volume wells in the CBFA not be increased from once every three years to semi-annually because it will increase operational costs significantly and in some cases would be challenging to implement.

12.2.2 The GOR needs to represent actual venting to accurately estimate emissions from crude bitumen batteries. Increased testing frequency helps ensure that the estimated vent rates represent actual conditions.

Respondents were confused about whether new GOR testing frequency requirements for batteries in the CBFA would restrict operators from using hourly rates.

12.2.2 The AER has clarified the wording to make it clearer that operators can use GOR or hourly rate as appropriate.

Updated the wording in 12.2.2

POLICYSome respondents expressed concern that 30 days were not sufficient for consultation and that additional consultation should be done on these requirements.

The requirements were developed with input from environmental nongovernment organizations, the oil and gas industry, and technology groups who were engaged over a two year period.

Respondents asked for more clarity on policy aspects including baselines and timelines.

For information on the methane reduction policy, please visit https://www.alberta.ca/climate-methane-emissions.aspx

Some respondents asked for the complete socio-economic impact assessment. For information about the socio-economic impacts of the Climate Leadership Plan, please visit https://www.alberta.ca/climate-leadership-plan.aspx

Some respondents expressed concern that these requirements will erode Alberta's competitiveness for oil and gas investment, resulting in negative economic and social impact on some regions and communities.

For information about the socio-economic impacts of the Climate Leadership Plan, please visit https://www.alberta.ca/climate-leadership-plan.aspx

A number of respondents expressed concern that these requirements will be costly to comply with for oil and gas companies.

For information about the socio-economic impacts of the Climate Leadership Plan, including carbon levy exemptions, please visit https://www.alberta.ca/climate-leadership-plan.aspx

Operators can meet many of the requirements by making adjustments to their existing maintenance programs to reduce costs. The requirements also put emphasis on new facilities and equipment which is less expensive than retrofitting older facilities.

Some respondents expressed concern that these requirements will result in older facilities becoming uneconomic, possibly increasing the orphan well count and the corresponding liability onto the province

The requirements were designed to reduce the cost on older facilities by putting more stringent requirements on new facilities and equipment while still meeting the policy target. A number of factors contribute to facility retirement and entry into the orphan well program.

A few respondents shared their opinion that reductions will be achieved through market forces and lack of activity, removing the need for these requirements. Others felt that left to market forces, emissions reductions targets would not be achieved.

The AER developed the requirements to support the policy objective within the GoA’s Climate Leadership Plan. For policy related information, please visit https://www.alberta.ca/climate-leadership-plan.aspx

Issue Summary Sec # Response Change to Draft ReqsSome respondents expressed concern that small operators will be more impacted by these requirements and should be treated differently

Facilities that emit more methane will be more impacted by the requirements; this approach is not based on the size of the operator. For more information about GoA incentive programs, please visit https://www.eralberta.ca/

A number of respondents shared the opinion that the requirements are not sufficient to meet federal equivalency.

The AER developed the methane reduction requirements to meet the policy objectives of the Climate Leadership Plan. The Government of Alberta is leading discussions with the federal government on equivalency. For more information, please visit https://www.alberta.ca/alberta-climate-leadership.aspx

A few respondents expressed concerns that the draft requirements will not achieve the policy target reductions.

The AER developed a comprehensive model to estimate the costs and emissions reductions that result from the methane requirements. Our results demonstrate that the emissions target will be achieved. For more details on the model inputs and assumptions please visit https://aer.ca/providing-information/by-topic/methane-reduction

A few respondents shared general criticism that the Climate Leadership Plan does not do enough to protect the environment.

For information about the Climate Leadership Plan, please visit https://www.alberta.ca/alberta-climate-leadership.aspx

R&DSome respondents felt that the requirements do not do enough to encourage innovation.

The requirements are technologically neutral where possible to allow for the development and use of innovative technologies to meet these requirements.

Some commenters advocated for an exception for new, specialized equipment that might not otherwise meet the requirements.

The AER will consider new technologies on a case-by-case basis, so long as the technology meets engineering, environmental, safety, and regulatory performance outcomes.

Commenters asked how the AER intended to address new technology under development.

Proven, commercially viable new technologies will be considered as part of the regulatory review by 2022 and could be incorporated into requirements where appropriate.

Commenters noted the requirements might need to be adjusted as leak-detection technologies improve.

8.10.2.2 The requirements already allow for methods or equipment that is equally capable of detecting fugitive emissions and that can accommodate improved leak-detection technologies. As well, LDAR data collected through the OneStop system and supplemented through studies could lead to an adjustment of the requirements as part of the regulatory review.

Commenters wished to make the AER aware that Petroleum Technology Alliance of Canada (PTAC) is working on studies that should inform the regulatory review

The AER is participating in these studies, and there is a direct line of sight to regulatory development.

Commenters noted that non-thermal infrared gas imaging is missing from the list of survey detection technology under fugitive emissions.

8.10.2.2 We have added a reference to non-thermal infrared gas imaging in section 8.10.2.2 1 c) to "other equipment or methods that are equally capable of detecting fugitive emissions. The duty holder must, however, assess equivalency and, upon request by the AER, provide documentation demonstrating equivalence."

Updated section 8.10.2.2 to include equivalent equipment and methods.

Issue Summary Sec # Response Change to Draft ReqsA commenter urged the AER to commit to developing new technology as part of measurement, monitoring, and reporting.

The AER is not a technology developer or endorser; however, it does support the development of new technology through various research and innovation initiatives. For examples of research studies completed by the AER, see https://aer.ca/providing-information/by-topic/methane/reports-and-studies

ECONOMICSSome comment were made that the requirements would be too onerous for small operators and asked that they be exempted. Others commented that it was reasonable for all operators to have to reduce methane.

The AER will apply requirements to all facilities in the province, except where explicitly stated, to ensure that a large number of facilities in the province will be reducing emissions. The greater the number of facilities covered, the greater the certainty that reductions targets will be met. An additional benefit of having more facilities covered by requirements is that the AER has more flexibility to adjust how stringent the requirements are in each emissions source category. We can make more reductions in categories with the lowest abatement costs by making requirements in those categories more stringent. Or we can reduce the cost burden in categories with the highest abatement costs by making requirements less stringent, knowing that the overall reduction target will not be compromised because the overall coverage is still high.

Alberta's requirements must be modelled before they are finalized to ensure that they meet or exceed the cumulative GHG reductions identified in the new federal methane regulations.

The AER has a comprehensive model used to estimate the costs and emissions reductions for the methane requirements.

The Government of Alberta is leading discussions with the federal government on equivalency. For more information, please visit: https://www.alberta.ca/alberta-climate-leadership.aspx

Why didn't the AER use the federal accelerated capital cost allowance (CCA) under classes 43.1 and 43.2 of the Income Tax Regulations that allow investors to accelerate the write-off of equipment used to produce energy more efficiently?

Most methane mitigation technologies do not fall under class 43 for either heat or electricity; therefore, the AER is using class 29, which has a CCA rate of 25%.

The Government of Canada demonstrated the impact of the federal regulations by modelling CO2e reductions and associated cost projections. Will the AER also release the results from its economic modelling? Has any sensitivity analysis been conducted?

The AER has modelled the methane emissions reductions and associated costs. The estimated methane reductions are modelled to be between 42% and 46% by 2025. The AER has completed a sensitivity analysis on fugitive emission factors, the reduction potential for fugitive emissions surveys and pneumatics: the percentage of level controllers that are actuating 15 minutes or less.

Overview of Respondents Industry 54%

Technology/Emissions Control/ Instrumentation and Control/Sustainability Company

14%

Environmental Non-Governmental Organization (ENGO) 8%

Research Association/Consulting Firm 8%

City Affiliation 8%

Indigenous/First Nations 3%

Concerned Citizen/No Association 2%

Financial/Investment Firm 2%

Individual Industry Worker 1%

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