Metering and recording practices have to follow methods and use instruments certified under the legal standards in force and in compliance with good technical standards. Article 34 of the Regulation on Petroleum Operations, 2009 , states that operators must propose to the MMRPG the measurement system, equipment, and procedures for measuring oil and gas production and sales. Article 39 lists the gas measurement system components; Article 40 describes the requirements for measurement facilities. Article 24 requires operators to submit a report providing information on all activities related to natural gas by December 30 of each year. Article 44 requires the quarterly submission to the MMRPG of a report on the systems for measuring, testing, and calibrating the equipment. The reports must include information related to daily production and respective shipments. For PSCs, contractors are required to record the monthly quantities of crude oil, natural gas, and water produced from each development area. These data must be sent to Sonangol within 30 days of the end of the month reported on.

Section 6 of Annex 1, on norms and procedures for venting gas, of Resolution No. 143/1998  covers flow rate measurement and registering. It requires the establishment and implementation at each venting point of a system to measure and record the flow of flared or vented gas and its composition in all cases. Article 14 of the Neuquén province’s Decree No. 29/2001 includes similar requirements.

At the national level, GHG emissions, including those associated with flaring and venting, and fugitive emissions from oil and gas operations, are measured according to NGER (Measurement) Determination, 2008, which the CER administers. Emissions measurement follows four general principles: transparency, comparability, accuracy, and completeness (Section 1.13). Several methods are described; those applicable to oil and gas operations are discussed in section 15 of this case study. The environment plan required by the OPGGS (Environment) Regulations, 2009 , must provide for “appropriate environmental performance outcomes, environmental performance standards, and measurement criteria” (Regulation 10A[d]) and include “an appropriate implementation strategy and monitoring, recording and reporting arrangements” (Regulation 10A[e]). Regulation 14 states that the titleholder must report to NOPSEMA on its environmental performance at least annually according to the accepted environment plan. Part 3 details reporting and recordkeeping requirements and noncompliance penalties. According to the Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019 , emissions associated with flaring and venting during flowback and workovers must be measured—using methods consistent with NGER (Measurement) Determination, 2008—and reported. Part D.4 of the Code of Practice requires three types of regional methane monitoring programs. The first of these are baseline methane assessments, which are required to identify major methane sources before a proposed upstream oil and gas activity. These baseline studies should include measurement of carbon dioxide, oxides of nitrogen, and particulate matter before and after gas production starts. During the baseline study, fixed monitoring stations may be installed for routine monitoring after gas production begins. The second type are regional methane assessment programs, which are required to characterize the existing natural and anthropogenic sources of methane emissions in a license area and in adjacent areas before exploration activity begins and immediately after full-scale production starts. Three assessments are required for exploration or production with hydraulic fracturing. The emissions may be estimated or directly measured. The third type are routine periodic atmospheric monitoring programs, which are required every five years to detect any changes in methane emissions during the life of a producing asset. Fixed atmospheric monitoring stations must be established at least a year before gas production begins. According to the Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019, “The number and location of monitoring sites must be sufficient to demonstrate shale production activities have not resulted in a regional enrichment of methane (and where relevant other GHG and particulate matter) above the background.” If significantly higher methane levels are detected, operators are required to identify the source and repair any leaks. A report must be submitted within a month of detection. In Queensland, according to the Petroleum and Gas (Production and Safety) Act, 2004 , a producer must measure volumes flared or vented (Section 801). The measurement must be with a meter—chapter 8 of the act details petroleum and fuel gas measurement schemes and meter criteria. The contents of a measurement scheme for metering include identifying each meter (by type), applicable Australian or other standards, testing methods and frequency, maintenance procedures, and other specifications (Section 637). Annual measurement reports are required (Section 650). The Code of Practice for Leak Detection, Management & Reporting for Petroleum Operating Plant, 2022 , requires operators in Queensland to conduct routine visits to well sites, gathering systems, and processing facilities to inspect for leaks and ensure compliance with a leak management plan. Leaks from the surface equipment at a petroleum well and in gathering systems must be reported to the Petroleum and Gas Inspectorate within five days of detection. According to Petroleum Regulations, 2021 , operators in Victoria must submit an annual report, which should include “a summary of actions taken to monitor, measure, eliminate or minimize” emissions from leaks, flaring, or venting during petroleum operations based on the ALARP criteria. In Western Australia, as per the Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations, 2015 , companies must submit to DMIRS daily drilling reports, monthly production reports, and reports upon well completion. Volumes of gaseous petroleum (flared or vented) should be included in annual assessment reports (Schedule 2) and monthly production reports (Schedule 17). Regulation 34 of the Petroleum and Geothermal Energy Resources (Environment) Regulations, 2012 , requires operators to monitor and report emissions and discharges every three months. In New South Wales, all petroleum operations require an environmental protection license, which mandates reporting land, noise, air, and water monitoring data as specified in each license. In South Australia, the Environment Protection Act, 1993 , mandates regularly reporting environmental quality and compliance with statutory requirements. No specific instructions on flaring, venting, or methane emissions were found in the legal and regulatory documents consulted for either state. In Tasmania, the Mineral Exploration Code of Practice, 2012, requires licensees to ensure systems are implemented to control environmental, health, and safety hazards, and detect and respond to emergencies. Systems must be continuously improved via regular audits and reviews.

ANP Joint Resolution No. 1/2013 contains the technical regulation for the measurement of oil and natural gas. According to Article 9 of Resolution 806/2020 , operators should provide the ANP with monthly production reports that include gas flaring and venting data. The report must be submitted by the 15th day of each month. Operators should report estimates of flared or vented associated gas for each of the following categories: safety scheduled maintenance works in progress, such as facilities under construction low gas production (insufficient volume of gas to be used) economics (associated gas whose use or re-injection would make the field uneconomic) venting in tanks (associated natural gas vented). The Model Contract-Concession Agreement for Exploration and Production of Oil and Gas explicitly mentions the requirement for reporting the volumes of gas flared or vented in Section 12. Licensees should submit to the ANP a monthly report on the production of each development area or field according to the applicable laws and regulations. Gas flaring and venting of natural gas with a variation above 15 percent of the volumes authorized in the PAP must be accompanied by due justifications. The licensee’s flaring and venting of gas should be included in the total production volume to be calculated for the purpose of paying royalties to the government. In this case, the flared volumes are monitored daily through the Production Inspection System (Sistema de Fiscalizacao da Producao).

Companies must accurately measure and report volumes of associated gas at all oil facilities. Requirements for measuring and reporting volumes of gas flared, incinerated, and vented are provided in Directive 017  and Directive 007: Volumetric and Infrastructure Requirements, and the Oil and Gas Conservation Rules . For the upstream sector, Section 2.13 of Directive 060  requires flared and vented solution gas to be reported monthly through Petrinex (Canada’s Petroleum Information Network) as per Directive 007. Section 5 of Directive 060 requires separate reporting of all monthly flared and vented volumes at gas processing plants. Flaring of sour gas must also be reported on the S-30 Monthly Gas Processing Plant Sulphur Balance Report. According to Section 8 of Directive 017, an annual methane emissions report must be submitted electronically to the AER by June 1 of the following calendar year. The first reporting period was 2019. The operator must include the following information in its annual methane emissions report: the volume of fugitive emissions by facility the corresponding mass of methane emitted by facility the type and date of survey the number of sources per site per facility.

Chapter 10 of the Flaring and Venting Reduction Guideline  states the requirements for measuring and reporting volumes of gas flared, incinerated, or vented. These requirements are in addition to the requirements specified in the Measurement Guideline for Upstream Oil and Gas Operations, 2020; Oil and Gas Activity Operations Manual, 2020; the Oil and Gas Royalty Handbook, 2014; and the Drilling and Production Regulation, 2010 . Permit holders of oil and natural gas production and processing facilities must report volumes of gas greater than or equal to 100 m³ a month that are flared, incinerated, or vented in Petrinex. For royalty calculation purposes, these volumes are also reported through the BC-S2 or BC-19 forms of the Ministry of Finance. All flaring, incinerating, and venting from routine operations; emergency conditions; and depressurizing pipelines, compressors, and processing systems must be disclosed. Gas used for a pilot, a purge, or a blanket must be reported as either flared or vented. The Greenhouse Gas Emissions Reporting Regulation, 2015, details the conditions and criteria for the mandatory reporting of GHG emissions by operators. Operators that emit more than 10,000 tCO2e a year must collect and report data on their emissions to the BCER. Submissions must be based on a process-flow diagram and include emissions from flaring, venting, and other fugitive emissions. The regulation also establishes verification bodies to evaluate reports from operators.

Part 7 of the Canada Oil and Gas Drilling and Production Regulations, 2009 (“Measurements Flow and Volume”; see footnote 8), states that unless otherwise included in the approval, the operator should ensure the rate of flow and volume of any produced fluid that enters, leaves, is used, or is flared, vented, burned (incinerated)—or otherwise disposed of—are measured and recorded. This requirement encompasses any oil storage tanks, treatment facilities, or processing plants. The Newfoundland Offshore Petroleum Drilling and Production Regulations, 2009 , and the Nova Scotia Offshore Petroleum Drilling and Production Regulations, 2009 , have similar provisions. The CER Event Reporting Guidelines, 2018 , require operators to submit an annual production report covering the previous year no later than March 31 of each year. This report must include details on the production forecast and gas conservation as well as efforts to maximize recovery and reduce costs. The report must also demonstrate how the operator manages or intends to manage the resource and avoid waste. An annual environmental report must also be submitted. This report should include a summary of any incidents that may have had an environmental impact, discharges that had occurred and the waste material produced, and a discussion of the efforts undertaken to reduce pollution and waste material. The ECCC first developed the GHG reporting program in 2004. It has updated reporting and GHG quantification requirements several times. Compliance with the annual reporting of GHG is mandatory. All facilities emitting more than 10,000 tonnes of carbon dioxide equivalent (tCO2e) in a given year must submit a report on their GHG emissions by June 1 of the following year. Facilities emitting less than the threshold can report voluntarily. The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) SOR/2018-66  include monthly reporting requirements to improve emissions estimates. They include inventories of emitting components at upstream facilities; reports on volumes of gas vented, flared, and delivered off-site; and results of leak-detection-and-repair inspections and monitoring.

Directive PNG017: Measurement Requirements for Oil and Gas Operations, 2015 , provides the regulatory requirements for the measurement, accounting, and reporting of flaring and venting across a variety of oil and gas operations, including flaring and venting at various sites. Directive PNG032: Volumetric, Valuation and Infrastructure Reporting in Petrinex, 2016 , requires all operators to provide well and facility infrastructure information, monthly pipeline split, and volumetric and valuation information electronically via the website of Petrinex. This requirement is stipulated in Section 66 of the Oil and Gas Conservation Act, 1978 , and Section 3 of the Petroleum Registry and Electronics Documents Regulations, 2012. Directive PNG032 also requires all emissions to be calculated and expressed in CO2e. Directive PNG076: Enhanced Production Audit Program, 2016 , sets out the requirements for operators to declare the degree to which they have the infrastructure in place to ensure compliance with the regulator’s measurement and reporting requirements.

Article 73 of the Hydrocarbon Operations Regulation, 2018 , requires operators to measure the volume of gas flared and report the results to the ARC. It ensures compliance with volumes from technical documents approved by the MEM. Article 87 of the Hydrocarbon Operations Regulation, 2018, states that annual emission reports are due to the ARC the first month of each subsequent year. The report should describe the use and flaring of associated natural gas. In line with the Hydrocarbon Operations Regulation, 2018, Article 11 of Ministerial Agreement MEM-MEM-2022-0047-AM, 2022 , requires operators to provide the ARC with an overview of the volumes of associated gas, and their use including routine and nonroutine flaring. Articles 30 and 57 of Executive Decree 1215, 2001 , require operators to monitor their emissions, including from flaring. Emissions from flares must comply with maximum limits set in Table 3 of Annex 2 of the decree.

Article 12 of the 2021 proposal  requires operators to submit a report containing source-level methane emissions to the competent authorities. Starting 48 months after this regulation comes into effect, operators must submit to the competent authorities annual reports containing direct measurements of source-level methane emissions from their operated and nonoperated assets. The EP amendments  further detail the reporting requirements. Amendments are more stringent in terms of direct measurement and emissions quantification, and shorten the reporting times. The provisional agreement reached between the EP and European Council in November 2023 follows these recommendations. For example, operators must submit reports quantifying source-level methane emissions within 18 months and direct measurements quantification of source-level methane emissions for operated assets within 24 months from the entry into force of the regulations. Reports on nonoperated assets are due within 48 months. Article 12 also mentions that the Commission will develop a reporting template. The EP amendments add that upstream, midstream, and downstream oil and gas operators can use the technical guidelines and templates of the OGMP 2.0 until the new template is available. Article 14 requires operators to develop LDAR programs within six months of the date on which this regulation comes into effect and start conducting the first survey within nine months.  Article 27, Paragraph 1, requires importers to report their products’ methane footprint within nine months of the date on which this regulation comes into effect. The provisional agreement of November 2023 requires exporters to EU to comply with a maximum methane intensity threshold by 2030.