Methane Abatement in Developing Countries

7. Regulatory building block 4: Addressing fugitive methane emissions

Box 7.1. EFFECT recommendations: Fugitive methane emissions

What can governments do?

• Require over time the replacement of equipment that is designed to vent methane with technologies that are zero emitting or the use of vapour collection to reroute vented methane back into the pipeline.

• Design robust leak detection and repair programmes (LDAR) based on environmental outcomes that emphasise repairing detected leaks and preventing leaks.

• Require detection campaigns with specified frequency (e.g. quarterly), and specify equipment to be used, detection thresholds and time limits for repairs. Using methane regulations allows for the use of alternative leak detection and repair programmes that can achieve equivalent outcomes.

Source: (OECD, 2022[1]).

Fugitive emissions (also referred to as “leaks”) are the most significant source of methane emissions from the oil and gas sector (Mohlin et al., 2022[2]), and are widely recognised as both a source of global GHG emissions and of local air pollution. Fugitive emissions are caused by malfunctioning or poorly maintained natural gas infrastructure – primarily, improperly fitted connection points or deteriorating seals; and the changes in pressure, temperature, or mechanical stresses that can lead to equipment or component degradation (European Commission, 2019[3]). Consequently, regulatory measures to address fugitive methane emissions are critical to lowering emissions and methane intensity, throughout the value chain and, in particular in the upstream oil and gas sector.

Equipment and technology standards

In line with EFFECT recommendations, governments can set out equipment and technology standards that operators must meet during the oil and gas production process. Such requirements can be prescriptive or performance-based or a combination of both:

• Prescriptive instruments direct regulated entities to undertake or not to undertake specific actions or procedures (IEA, 2021[4]). For example, these can require operators to replace a device with an upgraded version that emits less methane or install new equipment that recovers emissions.

• Performance-based instruments establish a mandatory performance standard for regulated entities but do not dictate how the target must be achieved (IEA, 2021[4]). For example, defining an emissions intensity benchmark (amount of emissions per unit of oil or gas production), or specifying a percentage of gas (from total gas production) that must be captured and/or used (Mohlin et al., 2022[2]).

The use of either prescriptive or performance-based regulatory instruments will vary across jurisdictions depending on the nature of the industry and capabilities and resources of regulatory agencies. On the one hand, prescriptive instruments are not based on emission quantification and therefore, the required technologies can be put in place before methane quantification methods have been implemented (Mohlin et al., 2022[2]). As such, they are less difficult to enforce as compliance is linked to equipment used at a facility. However, the prescriptive approach is by its nature less flexible and less able to respond to rapidly evolving technologies. For example, Nigeria’s 2022 methane guidelines impose a number of equipment-specific standards on operators in the upstream oil and gas sector applicable to new and existing oil and gas facilities. Section 3.4.1 sets out requirements for centrifugal compressors, and specifies that operators route oil degassing unit emissions either to a vapor recovery or a combustion device. Alternatively, operators can design/retrofit the compressor using dry seals. In addition, in order for prescriptive regulations to be effective, governments will need to undertake sufficient upfront investigation to understand where emissions are coming from in order for the regulations to be correctly targeted.

On the other hand, performance-based instruments are easier to develop and allow more flexibility for operators to choose methods of compliance. They are agnostic as to the use of specific technology. For this reason, they support increased technology innovation and can prove more cost-effective as they incentivise operators to deploy latest available equipment and technologies and achieve faster methane emissions reductions. However, performance-based instruments rely on accurate emission monitoring, which may limit their application in jurisdictions with lower capacities due to the expertise needs and time required to ensure proper enforcement and compliance (Olczak, Piebalgs and Balcombe, 2023[5]).

Equipment and technology standards target high-emitting oil and gas equipment by requiring the installation or replacement of components and devices to meet methane emission standards. The adoption of best available equipment and technology can lead to significant reductions in methane emissions (as well as other GHGs and volatile organic compounds (VOCs)) due to their performance relative to existing equipment and components. For example, section 5(1) of the 2018 Canadian federal methane regulations provides that gas conservation equipment that is used at an upstream oil and gas facility must be operated in such a manner that at least 95% of the hydrocarbon gas that is routed to the equipment is captured and conserved.

Phasing-in zero emitting technologies

Governments should ensure that regulations require the replacement of old equipment with technologies that are zero emitting. For example, the EU’s Regulation to reduce energy sector methane emissions provides that where a site is built, replaced or refurbished in whole, operators shall utilise only commercially available zero-emitting pneumatic devices, compressors, atmospheric pressure storage tanks, sampling and measurement devices and dry gas seals (European Commission, 2023[6]). In another example, the U.S. EPA’s Final Rule to Reduce Methane and Other Harmful Pollution from Oil and Natural Gas Operations requires pneumatic controllers to meet a methane and VOC emission rate of zero. In Mexico, article 41 of the 2018 Mexico methane regulations provides that, during the design phase of new oil and gas facilities, the operator must select pneumatic pumps driven by compressed air or electric pumps. In British Columbia, regulatory provisions encourage the replacement of pneumatic pumps over time – see Box 7.2.

Box 7.2. British Columbia: Regulatory requirements for pneumatic pumps

Section 52.06 of the 2010 British Columbia Drilling and Production Regulation

(1) A facility permit holder who operates a facility must not use at the facility a pneumatic pump that emits natural gas unless the pump:

(a) was installed before January 1, 2021; or

(b) is operated 750 hours or less per year.

(2) Beginning on January 1, 2021, a facility permit holder who operates a facility that uses a pneumatic pump that emits natural gas must maintain a record that contains:

(a) description of the pump and the type of fluid pumped, and

(b) the following information for each calendar month:

(i) the number of hours the pump is operated

(ii) the volume of natural gas emitted from the pump.

Source: (Government of British Columbia, 2022[7]).

Governments adopting new methane regulations may opt for equipment and technology standards to be phased in over time to allow operators time and flexibility to adjust to these new requirements. For example, the U.S. EPA’s Final Rule provides a one-year phase-in for zero-emissions standards for new process controllers and most new pumps outside of Alaska in order to provide industry time to prepare to meet requirements and to secure necessary equipment (EPA, 2023[8]). Facilities in Alaska where access to electrical power from the power grid is not available are exempted from these requirements (EPA, 2023[9]). Regulations may also specify different equipment and technology standards for new and existing facilities. For example, Colombia’s methane regulations require that for new facilities, where reciprocating compressors are used, they must be connected to gas and vapor conservation equipment when technical conditions allow it, or to a controlled burning system in order to capture amounts of gas that are vented from reciprocating compressors during normal operations. Whereas, for existing facilities with centrifugal compressors with wet seals, operators must redirect emissions during degassing of wet seals to a vapor conservation equipment or replace wet seals with dry seals. Similarly, for pneumatic controllers, during the design phase of new facilities, operator should select pneumatic controllers that use compressed air rather than natural gas and/or are powered by electricity. Whereas, for existing facilities with pneumatic controllers powered by natural gas, operators should substitute the use of natural gas for compressed air or replace pneumatic controllers with mechanical or electricity ones.

In Nigeria, the methane guidelines prohibit the use of natural gas-driven pneumatic controllers at grid-connected facilities due to their leak potential and stipulates that operators shall instead retrofit facilities with zero bleed controllers, including controllers powered by electricity or instrument air or where emissions are directed to a vapor recovery system for capture. However, if these options are not feasible, the regulations provide that operators may use a flare, and production facilities that do not have access to grid-electricity are also exempted from these requirements. Nigeria’s methane guidelines provide a 5-year phase-in period for existing well production facilities without grid access:

• Within one year, an operator shall ensure that 25% of pneumatic controllers are zero-bleed controllers, and the remainder are low bleed1

• Within two years, the operator shall ensure that 65% of pneumatic controllers are zero-bleed controllers, and the remainder are low bleed

• Within three years, the operator shall ensure that 75% of pneumatic controllers are zero-bleed controllers, and the remainder are low bleed

• Within four years, the operator shall ensure that 85% of pneumatic controllers are zero-bleed controllers, and the remainder are low bleed

• Within five years, the operator shall ensure that all pneumatic controllers are zero bleed controllers (NUPRC, 2022[10]).

Leak detection and repair regulatory requirements

Alongside equipment and technology standards, governments should set out robust and effective leak detection and repair (LDAR) programmes to identify and address sources of fugitive methane emissions as they arise. The main elements of a robust and effective LDAR programme include:

• Scope of facilities to be inspected – LDAR requirements may specify which facilities and equipment are subject to inspection requirements

• Authorised LDAR equipment and technologies – LDAR requirements may direct operators to use a combination of traditional on-site techniques (e.g. optical gas imaging) or advanced techniques – including aircraft, unmanned aerial vehicles (drones), mobile ground labs, and satellites

• Frequency of inspections – the more frequent that monitoring is carried out (by the operator), the more effective the LDAR programme will be in identifying and repairing sources of fugitive methane emissions (Mohlin et al., 2022[2])

• Detection threshold and repair requirements – this may include a leak threshold that triggers the obligation to repair and the allowance timeframe for carrying out those repairs

• Reporting and recordkeeping – LDAR requirements may require companies to keep records of their surveys, detected leaks, and repair actions, and to report to competent authorities (CLDP, 2023[11]).

Governments should design robust LDAR programmes based on environmental outcomes that emphasise repairing detected leaks and preventing leaks. For example, in British Columbia, the 2018 Flaring and Venting Reduction Guideline provides that a facility permit holder must have an adequate fugitive emissions management programme. In addition, permit holders must develop and implement a programme to detect and repair leaks, and that these programmes should meet or exceed the Canadian Association of Petroleum Producer’s Best Management Practice for Fugitive Emissions Management. In another example, the 2018 Canadian federal methane regulations set out requirements directing operators to carry out LDAR programmes in order to limit fugitive emissions containing hydrocarbon gas from equipment components at oil and gas facilities.2

There are a number of different technologies and equipment that operators can use to detect methane emissions, and new technologies are developing rapidly. The International Association of Oil & Gas Producers (IOGP), an upstream oil and gas industry body, has created a filtering tool to assist operators to identify appropriate methane detection and quantification technology – see Box 7.3.

Box 7.3. Methane detection and quantification technology filtering tool

Several technologies are available to help producers detect and quantify methane emissions, a prerequisite to leak repair. To assist in narrowing down technologies appropriate for a particular site or operation, the IOGP, in partnership with other industry associations – OGCI and Ipieca, has developed a publicly available filtering tool.

This online technology filtering tool features detailed technology data sheets covering over 50 technologies, and decision trees to guide technology deployment.

Using a checkbox method, producers input factors such as the accessibility of the site, the characteristics of the area wherein the site is located, and the required sensitivity of the equipment. The database is non-exhaustive, but it is regularly updated.

Source: (IOGP, 2024[12]).

LDAR campaigns – frequency, thresholds and repairs

Regulatory frameworks should require operators to undertake detection campaigns with specified frequency, detection thresholds and time limits for repairs. More frequent surveys lead to faster detection and repair of methane leaks, but this comes with an added cost of compliance. According to the IEA, the most typical frequency for LDAR campaigns is quarterly (IEA, 2021[4]). Table 7.1 provides an overview of LDAR frequency, detection thresholds and repairs timeframes in selected jurisdictions.

Table 7.1. Regulatory requirements for leak detection and repair programmes

LDAR frequency, detection thresholds and repairs timeframes in selected jurisdictions

	Annual frequency of LDAR inspections	Leak threshold for repair	Timeframe for repair following detection
Canada (Federal)	3	500 ppm	30 days*
Canada (Alberta)	1 or 3	10 000 ppm	24 hours (safety issues); or 30 days*
Canada (British Columbia)	1 or 3	500 ppm	30 days**
Canada (Saskatchewan)	2	500 ppm	30 days*
European Union	***	500 – 7 000 ppm	30 days
Colombia	2	500 ppm	30 days**; or12 months (offshore)
Mexico	4	500 ppm	1, 3 or 15 days* (depending on leak size)
Nigeria	4	500 ppm	5 working or 14 days* (depending on leak size)
USA (Federal)	4-6	500 ppm	30-60 days
USA (Colorado)	1-12****	500 ppm	5 days (attempt to repair), 30 days (complete repair)

Note: * If the repair can be carried out while the equipment component is operating. If not, then repair must be made during the next planned shutdown.

** If the repair can be carried out while the equipment component is operating. If not, then repair must be made when the volume of natural gas from all leaks is greater than the volume of natural gas that would be released if the operating equipment is removed.

*** LDAR inspections differ according to the component and type of material – from 3-36 months.

**** LDAR inspections differ depending on magnitude of emissions.

Source: Authors’ compilation.

In the European Union, the inspection frequency differs according to the location of the specific component (i.e. onshore, offshore, underground) and type of material (i.e. asbestos, copper, protected steel). Similarly, the leak threshold for repair3 is determined by reference to the location of the component.

• 500 parts per million in volume of methane or 1 gram per hour of methane for aboveground components and for offshore components above the sea level

• 1 000 parts per million in volume of methane or 5 grams per hour of methane for the second step of underground components

• 7 000 parts per million in volume of methane or 17 grams per hour for offshore components below the sea level and below the seabed (European Commission, 2023[6]).

Box 7.4. Alternative LDAR survey frequencies in the European Union

Article 14 of the EU’s Regulation to reduce energy sector methane emissions provides that where operators producing or processing natural gas or oil can demonstrate that during the five preceding years less than 1% of all their components in each site are leaking and that the methane emissions associated with these leaks aggregated represent less than 0.08% of the total volume of gas or 0.015% of the total mass of oil processed or extracted, then different LDAR survey frequencies may be used.

Type 1 and 2 LDAR surveys

Operators shall repair or replace all components found to be emitting methane at or above the following levels at standard temperature and pressure and using detection devices in accordance with the manufacturer specifications for operation and maintenance:

(a) for type 1 LDAR surveys: 7 000 parts per million in volume of methane or 17 grams per hour of methane

(b) for type 2 LDAR surveys:

i. 500 parts per million in volume of methane or 1 gram per hour of methane for aboveground components and for offshore components above the sea level

ii. 1 000 parts per million in volume of methane or 5 grams per hour of methane for the second step of LDAR surveys of underground components

iii. 7 000 parts per million.

Alternative LDAR survey frequencies

These alternative LDAR survey frequencies are subject to the approval of the relevant authorities and must comply with the following requirements:

• For all components at processing locations, Type 1 LDAR surveys are performed at least every 12 months

• For at least 25% of all components at processing locations, Type 2 LDAR surveys are performed every 12 months, ensuring that all components are checked every 48 months

• For all components at production locations, Type 1 LDAR surveys are performed at least every 36 months

• For all components at production locations, Type 2 LDAR surveys are performed at least every 60 months.

Source: (European Commission, 2023[6]).

A similar approach is taken in the United States where inspection frequency and repairs timeframes differ according to the nature of the facility and specific LDAR activity. For example, quarterly audio, visual, and olfactory (AVO) monitoring surveys are required at small well sites and sites with a single wellhead. If a leak is detected, an initial attempt at repair must be made within 15 days after detecting fugitive emissions, and the repairs must be completed within 15 days after first attempt. For multi-wellhead sites (without major production and processing equipment), quarterly AVO monitoring surveys are required and if leaks are detected, initial attempt at repair must be made within 15 days, and repairs must be completed within a further 15 days. In addition, semi-annual optical gas imaging (OGI) surveys are required. Should a leak be detected, an initial attempt at repair must be made within 30 days after detecting fugitive emissions, and the repairs must be completed within 30 days after first attempt (EPA, 2023[9]).

In Canada, the 2018 Canadian federal regulations require inspections at least three times per year and at least 60 days after a previous inspection. This requirement (to limit inspection to three times per year), reflects the environment of the Canadian upstream oil and gas sector where LDAR inspections are not possible in offshore and arctic locations during winter months (IEA, 2021[4]). A release of hydrocarbons from an equipment component is considered a leak if the release consists of at least 500 parts per million by volume (ppmv) of hydrocarbons, as determined by an inspection conducted by means of an eligible portable monitoring instrument in accordance with EPA Method 21.4 If a LDAR inspection identifies an actionable leak, a repair must be made within 30 days if the repair can be carried out while the equipment component is operating, or if not, during the next planned shutdown.

In Colombia, article 42 of the 2022 Colombia methane regulations provides that the operator must carry out LDAR activities at its oil and gas facilities. Although there is an exemption for facilities that operate with a potential for emissions or leaks of less than 60 000 standard m³ per year. Inspections are required twice per year, and a leak is successfully repaired when it is reduced to less than 500 ppm or when the instruments used for detection do not detect visible emissions. In Mexico, article 71 of the 2018 Mexico methane regulations directs operators to carry out a LDAR programme for each project on a quarterly basis. The threshold for a leak that triggers a repair obligation in 500 ppm.

In Nigeria, the frequency for LDAR inspections is phased in over three years. In the first year after implementation of the Nigeria methane guidelines, an operator shall conduct one inspection at each facility, in the second year, two inspections are required, and in the third and subsequent years, three inspections are required. A leak is successfully repaired when it is reduced to less than 500 ppm (using EPA Method 21) or when an infra-red camera or any other detection technology approved by the regulator does not detect emissions. Repair obligations differ according to the size of the leak and/or if the component cannot be repaired without a shutdown:

• Larger leaks (50 000 ppmv) shall be repaired within 5 working days of discovery

• Small leaks (5 000 ppmv) shall be repaired within 14 days of discovery.

The Nigeria methane guidelines note that if the relevant component is a critical one that cannot be repaired without shutdown, operators shall minimise the leak within one day of detection and repair the leak by the end of the next planned process shutdown or within one year, whichever is sooner.

Regulations may provide exemptions or delays to repair timeframes due to the availability or access to certain equipment or components. For example, in response to supply chain concerns, the U.S. EPA’s Final Rule to Reduce Methane and Other Harmful Pollution from Oil and Natural Gas Operations allows operators additional time to repair fugitive emission components if a replacement is required but parts cannot be acquired or installed due to the following conditions:

• Replacement valve supplies have been sufficiently stocked but are depleted at the time of the repair

• Replacement fugitive emissions component (or a part) requires custom fabrication (EPA, 2023[9]).

LDAR campaigns – equipment specifications

Regulations should specify the equipment to be used in LDAR campaigns. For example, the U.S. EPA’s Final Rule specifies the use of detection instruments to be used at different facilities – small well sites and sites with a single wellhead (AVO), multi-wellhead sites, sites with major production and processing equipment, and compressor stations (AVO and OGI). In Nigeria, section 3.2.1 of the 2022 Nigeria methane guidelines specifies that LDAR must be conducted using OGI, laser beam technology or any other mature technology approved by the regulator. In Colombia, detection activities must be carried out using: OGI instruments, laser leak detectors, soap solution detection, organic vapor analysers or toxic vapor analysers, acoustic leak detection, electronic gas detectors, or any other that is authorised by the regulator.

As recommended in EFFECT, governments may also consider providing regulatory flexibility for operators to deploy alternative technologies for leak detection and repair programmes that can achieve equivalent outcomes to reflect technological developments. This approach has been implemented in the United States and the Canadian province of Alberta. For example, in recognition of the rapid and continued advancement of technologies, the U.S. EPA’s Final Rule allows operators, technology developers and other entities to seek approval for the use of new methane detection technologies to supplement their existing ground based OGI surveys and AVO inspections, and to ensure that the regulations keep up with the pace of innovation in the sector. The EPA will assess technology approval requests within 90 days and will issue an approval or disapproval within 270 days (EPA, 2023[8]).

In the Canadian province of Alberta, Directive 060 provides that the Alberta Energy Regulator will consider innovative and science-based alternatives to the standard fugitive emissions management programme. Such alternative programmes may incorporate technologies such as unmanned aerial vehicles, vehicle-mounted sensors, and continuous monitoring devices to detect, track, repair, and report fugitive emissions. Operators who wish to use an alternative fugitive emissions management programme must first submit a proposal to the Alberta Energy Regulator for approval.

References

[11] CLDP (2023), Methane Abatement Handbook, U.S. Department of Commerce, https://cldp.doc.gov/sites/default/files/2023-09/CLDP%20Methane%20Abatement%20Handbook.pdf.

[8] EPA (2023), EPA’s Final Rule for Oil and Natural Gas Operations, U.S Environmental Protection Agency, https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/epas-final-rule-oil-and-natural-gas.

[9] EPA (2023), EPA’s Final Rule for Oil and Natural Gas Operations Will Sharply Reduce Methane and Other Harmful Pollution., United States Environmental Protection Agency, https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/epas-final-rule-oil-and-natural-gas.

[6] European Commission (2023), Commission welcomes deal on first-ever EU law to curb methane emissions in the EU and globally, European Commission, https://ec.europa.eu/commission/presscorner/detail/en/IP_23_5776.

[3] European Commission (2019), Best available techniques guidance document on upstream hydrocarbon exploration and production – Final guidance document, European Commission, https://data.europa.eu/doi/10.2779/607031.

[7] Government of British Columbia (2022), BC Drilling and Production Regulation (B.C. Reg. 282/2010), Government of British Columbia, https://www.bclaws.gov.bc.ca/civix/document/id/crbc/crbc/282_2010.

[4] IEA (2021), Driving Down Methane Leaks from the Oil and Gas Industry, IEA, Paris, https://www.iea.org/reports/driving-down-methane-leaks-from-the-oil-and-gas-industry.

[12] IOGP (2024), Methane detection and quantification technology filtering tool, International Association of Oil & Gas Producers (IOGP), https://www.iogp.org/workstreams/environment/environment/methane-emissions-detection-and-quantification/methane-detection-and-quantification-technology-filtering-tool/tool/.

[2] Mohlin, K. et al. (2022), Policy instrument options for addressing methane emissions from the oil and gas sector, Environmental Defense Fund, https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4136535.

[10] NUPRC (2022), Guidelines for Management of Fugitive Methane and Greenhouse Gases Emissions in the Upstream Oil and Gas Operations in Nigeria, Nigerian Upstream Petroleum Regulatory Commission, https://www.nuprc.gov.ng/wp-content/uploads/2022/11/METHANE-GUIDELINES-FINAL-NOVEMBER-10-2022.pdf.

[1] OECD (2022), Equitable Framework and Finance for Extractive-based Countries in Transition (EFFECT), OECD Development Policy Tools, OECD Publishing, Paris, https://doi.org/10.1787/7871c0ad-en.

[5] Olczak, M., A. Piebalgs and P. Balcombe (2023), A global review of methane policies reveals that only 13% of emissions are covered with unclear effectiveness, One Earth, https://www.sciencedirect.com/science/article/pii/S2590332223001951.

Notes

← 1.  Emitting less than 0.17 standard cubic meters per hour of natural gas.

← 2.  Applicable to upstream facilities that produce or receive at least 60 000 standard m³ of hydrocarbon gas per year.

← 3.  Applicable to type 2 leak detection and repair surveys.

← 4.  Two methodologies are ordinarily used to detect leaking equipment in LDAR programmes: 1) EPA Method 21 developed by the U.S. Environmental Protection Agency uses a hydrocarbon ionisation detector, and is a widely accepted method; and 2) Optical Gas Imaging (OGI) uses an infra-red camera – this is a more recent methane detection technique but is gaining increasing acceptance.