Country
Assessment
Article 11 of ESDM 17/2021 requires contractors or processing business permit holders to identify flared volumes. They can do so using measurement instruments, mass balance calculations, or other engineering calculations that follow good technical rules.
Flaring during oil and gas operations must be measured and reported to the Ministry of Energy. Article 76 of the Law on Subsoil and Subsoil Use, 2017 , requires licensees to report on their activities covered under the permits issued by the Ministry of Energy. These reports may be periodic or one-time in nature. The Ministry of Energy develops standards for permissible raw gas flaring volumes, measurement, and calculation in accordance with Article 146. These standards should be observed in all reporting. Order 164, 2018, is the most recent ministerial order approving the methodology for calculating flare volumes. Article 203 of the Environmental Code, 2021 , details monitoring requirements for emissions, including from flares. Environmental permits, based on the environmental impact assessments, require the measurement of emissions to ensure compliance. They should also include a list of acceptable metering methodologies or, if metering is not feasible, allowed calculation methodologies. Article 186 states that monitoring at Category I facilities, which includes upstream oil and gas, “should include the use of an automated system for monitoring emissions into the environment.” Facilities operating before July 1, 2021, have until January 1, 2023, to install automated systems for monitoring emissions (Article 418). The data from automated emissions monitoring are considered primary data and are to be included in the new “National Bank of Data on the State of the Environment and Natural Resources of the Republic of Kazakhstan” (Articles 155 and 156). MEGNR will use these data to monitor compliance with environmental permits with or without a site visit (Article 174). The Environmental Code, 2021, introduces the concept of the integrated environmental permit, which is mandatory for Category I facilities (Article 111) starting January 1, 2025, for facilities commissioned on or after July 1, 2021 (Article 418). The permit is granted by MEGNR, in collaboration with other state entities if appropriate. Companies in Category I still need to conduct an environmental impact assessment. Article 113 defines the best available techniques, their purpose, and criteria for determining such techniques across sectors listed in Appendix 3. Techniques are intended to cover technologies as well as processes, practices, and approaches to designing, building, operating, maintaining, and decommissioning facilities. Article 113 establishes the Bureau of Best Available Technologies, falling within MEGNR, and outlines its tasks. The bureau will develop guidelines on the best techniques for all areas by July 1, 2023 (Article 418).
The PPGUA provides guidance regarding minimum technical requirements and the approval process for metering systems. Flaring and venting volumes need to be reported, in line with measurement requirements. The MES Greenhouse Gas Reporting and Management Plan has specific measuring equipment and methods as well as frequency requirements for existing assets, and to a reduced extent also for new developments. In line with Section 8 of the Malaysia-Thailand Joint Authority Procedures for Production Operations, 2009 , the license holder must maintain production reports, including volumes of flared and vented gas, and submit them to the authorities. Sections 12–15 also detail metering and measurement requirements.
Article 16 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons requires the operator to follow the standards established in the CNH Technical Guidelines in Hydrocarbon Measurement, 2015, for measuring and reporting the volumes of the associated natural gas used. These guidelines were subsequently updated in February 2016, August 2016, December 2017, and February 2021. Articles 23 and 24 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons require the operator to provide quarterly reporting of progress in implementing the associated gas use program. The report should follow the CNH format outline and include the volumes of associated gas used, justification for any deviations from the gas use program, and a summary of unscheduled events that had resulted in gas flaring. Article 25 requires the CNH to review the quarterly reports within 15 business days of receipt and authorizes the CNH to request additional information from the operator. The ASEA Guidelines for the Prevention and Comprehensive Control of Methane Emissions from the Hydrocarbons Sector require operators to identify the source and quantify the volume of methane emissions. The information must be reported annually.
Section 106 of the Petroleum Industry Act codifies the requirements of metering according to the regulations of the Commission or the Authority. Part V of the Gas Flaring, Venting and Methane Emissions (Prevention of Waste and Pollution) Regulations, 2023 , contains measurement and reporting requirements, including procedures, that are further detailed in the Guidelines for Flare Gas Measurement, Data Management and Reporting Obligations. NUPRC Guide 0024-2022 requires proper tracking and reporting of activities that emit fugitive emissions, including flaring and venting and other methane leaks. Appendix A of the Guide summarizes various reporting requirements. An annual report should demonstrate compliance with each section of the guidelines. The report should include the total number of facilities inspected, inspections, leaks identified (by component and type of facility), leaks repaired, and leaks waiting to be repaired. Data on flare efficiency, cold venting, unlit flares, and records on testing of flares should be included for each flare.
Section 48 of the Regulations to Act Relating to Petroleum Activities, 1997 , requires the operator to submit information to the NPD on the use, injection, flaring, and venting of natural gas. Such information should be based on metering as much as possible. The Measurement Regulations, 2001 , stipulate functional and compliance requirements, including reporting and documentation, related to the planning, design, construction, and operation of metering systems and equipment to measure and report the quantities of gas flared or vented in petroleum activities. The NPD approves the equipment and procedures. Section 29 of the Measurement Regulations, 2001, requires the reporting of carbon dioxide tax metering to support the payment of the carbon dioxide tax every six months (calculated per field or facility). Section 3 of the Comments to Regulations Relating to Measurement of Petroleum for Fiscal Purposes and for Calculation of CO2 Tax, 2018, holds the operator of each individual field or facility directly responsible for the duties placed with the licensees jointly pursuant to the Norwegian Petroleum Act, 1996 , and the CO2 Tax Act, 1990 . Such duties include the design, purchase, and operation of metering systems, associated reporting, and payment of tax. The CO2 Tax Act, 1990, authorizes the Ministry of Finance to issue additional provisions for the carbon dioxide tax and equipment requirements for metering, measurement methods, and documentation.
According to the Regulations for Air Pollution Control from Stationary Sources , air emissions listed in the appendix are to be measured by instruments. Fugitive emissions can be estimated using mass balance equations. Flaring and venting guidelines under development since 2017 suggest that reporting will be required to ensure compliance with targets to be established.
Article 22 of Federal Law No. 2395-1 on Subsoil, 1992 requires the oil and gas producer to submit to the Federal Geological Information Fund reliable information on volumes explored and produced. To ensure the uniformity of measurements, meters must meet the metrological and technical requirements as defined by a normative guideline issued by the Federal Ministry of Energy. Section 3 of Federal Decree No. 1148, 2012 requires oil producers to report their “flaring rate”—the percentage of associated gas that is flared and vented (see the Monetary Penalties section of this case study).
SAES-A-102 mandates all Saudi Aramco facilities with flares to have an FMP, which must be updated annually and must cover: policies and procedures to minimize flaring, measuring, monitoring, and recording of flared gases to be reported monthly (daily volumes of vent, pilot, and purge gases), causes of flaring (safety, leaks, upset, mechanical failure, startup/shutdown, and process/fuel imbalance), and preventive measures implemented and to be implemented per FMP. SAEP-400 provides the guidelines for facility FMPs, which are to be developed based on the FMS, developed by Saudi Aramco’s Process & Control Systems Department. This standardized tool must be implemented at all flare systems across Saudi Aramco facilities. According to SAEP-400, all facilities must provide daily, monthly, and annual reports, with the goal of mitigating flare volumes by area and plant. These reports are to outline the sources and reasons for flaring as described in Section 8.4 of the guidelines. The FMS was granted a US patent and is described in Appendix 8, SAEP-400A . The guidelines call for identifying and monitoring all equipment that may cause flares to malfunction; offer detailed system design recommendations and engineering equations; and set key performance indicators. The FMS software allows for the collection of real-time data from all equipment. Monthly reports from the FMS help operators distinguish between routine and nonroutine flaring, identify volumes released from each piece of equipment, and estimate financial impacts, all of which inform each facility’s FMP and allow analysts to benchmark recent flaring data against each facility’s best historical performance. Stations in the Air Quality and Meteorology Monitoring Network (AMMNET) track ambient air quality. Saudi Aramco’s Emissions Monitoring Solution tracks greenhouse gas emissions across company operations. The company plans to include air emissions in this system according to Saudi Aramco’s 2021 sustainability report . SAES-A-100, Section 5.16, requires major new facilities to install at least one new AMMNET station, the location of which has to be approved by the Environmental Engineering Division. The Executive Regulation for Air Quality includes technical requirements for flare systems burning volatile organic compounds (VOCs) (Article 5, Section 7). These regulations apply to petroleum refineries and petrochemicals facilities not operated by Saudi Aramco as well as other industries. Reporting requirements are not included in the Executive Regulation for Air Quality but NCEC may develop such requirements in the future. According to RCER-2015 , Volume I (Regulations and Standards), Section 8, operators are to report the quantity and estimated composition of gases flared monthly, fugitive emissions annually, point source emission data annually, and an air emissions inventory for renewal of their environmental permit. Table 2D of RCER-2015 Volume I (Regulations and Standards) lists air emission sources subject to continuous monitoring, which include refineries. The monitoring focuses on opacity, carbon monoxide, and sulfur dioxide, and not explicitly on flaring, venting, or methane emissions.
Under Rule 903(d) of the Environmental Impact Prevention 900 Series, 2021 , gas flared or vented needs to be metered subject to the requirements of Rules 429 and 430 of the Operations and Reporting 400 Series, 2021, or estimated and reported on a per-well basis in the operator’s monthly operations report as required by Rule 413. Regulation Number 7 of the Colorado Department of Public Health and Environment provides detailed requirements on monitoring emissions, including fugitive methane and VOCs, from upstream and midstream oil and gas operations.