Country
Assessment
Article 126 of Law No. 002/2019 requires operators to submit a gas flaring reduction plan for all their production fields for the joint approval of the MPGHM and the Ministry of Environment.
Article 2 of ESDM 17/2021 requires contractors and processing business permit holders to manage flare gas. Upstream contractors must prepare a flare gas management plan as part of field development plans. As per Article 17, contractors and processing business permit holders must submit their flare gas management plans to DG Migas every six months. The submissions must follow the format provided in the appendix of ESDM 17/2021. Article 15 enables contractors or processing business permit holders to flare or utilize flare gas collaboratively under the coordination of SKK Migas or the BPMA. This cooperation is intended to reduce the costs of individual companies and accelerate the mitigation of flaring. These collaborative activities must be reported to DG Migas.
Article 147 of the Law on Subsoil and Subsoil Use, 2017 , requires operators to minimize the volume of raw gas flaring and field development plans to include a section on raw gas processing or utilization. Field development plans are reviewed by the Central Commission for Exploration and Development “with the involvement of independent experts with special knowledge in the field of geology and development and not interested in the results of the examination,” as stipulated in Article 140. Articles 134–143 detail the necessary project documents and the review process. The Ministry of Energy’s Department of Subsoil Use organizes an independent review of project documents and development plans. According to Article 147, the gas-processing program is to be updated every three years. Annual reports on the implementation of the program must be submitted to the Ministry of Energy.
Article 13 of the Model Production Sharing Contract, 2006, requires the Management Committee to approve the development plan for any excess associated gas deemed commercial.
The PPGUA provides guidance on the field development plan and its review and approval, including arrangements for any potential gas flaring system in the overall development process. The MES Greenhouse Gas Reporting and Management Plan requires new developments to be designed for zero continuous flaring and venting; to include carbon capture, utilization, and storage for high-carbon-dioxide fields; and to apply a design philosophy that mitigates methane emissions. New developments must also include a carbon footprint assessment to determine the expected GHG emissions over their life cycle. Specific guidance will be provided for both on-field methane emissions measurements and remote measurements capable of capturing these emissions as part of the overall GHG emissions profile. Both new and existing operations must fulfill minimum requirements for the equipment measuring emissions. Section 34 of the Environmental Quality Act, 1974 , in conjunction with the First Schedule of the Environmental Quality (Prescribed Activity) (environmental impact assessment [EIA]) Order, 2015 , entitles the minister of environment and water to ask for an EIA for upstream oil and gas developments, including pipeline and storage construction plans (no requirements for installations specific to flaring and venting). The director-general of environmental quality reviews and approves or rejects the development plans based on the submitted report. In case of rejection, a resubmission with an improved development concept is typically allowed.
Article 44 of the Hydrocarbons Law, 2014 , requires oil and gas producers to seek approval from the CNH for exploration and development plans. The CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons require the treatment of associated natural gas, including flaring, to be specified in exploration and development plans: Article 5 of the Technical Provisions states that the operator may utilize associated natural gas for the needs of its operation (e.g., as fuel for turbines, or to aid pneumatic pumping or other lifting systems that require gas injection). Article 10 requires the operator to submit to the CNH a program to use associated gas as part of the development plan for each assignment and contract area. Article 22 requires information on flaring facilities and volumes to be included along with a flaring program. Annex II of the provisions provides detailed instructions on all these requirements. Operators submit all information to CNH via the Programa de Aprovechamiento de Gas Natural Asociado (PAGNA). The programs must include month-by-month forecasts for associated gas use during the first three years and annual forecasts thereafter. The CNH website provides examples of development plans that include approved programs using associated gas. One example is contract CNH-M4-ÉBANO/2018. The ASEA Guidelines for the Prevention and Comprehensive Control of Methane Emissions from the Hydrocarbons Sector require a Program for the Prevention and Integral Control of Methane Emissions (Programa para la Prevención y el Control Integral de las Emisiones de Metano, or PPCIEM) for all new and existing facilities. The first three annexes of the Guidelines provide templates for the various requirements of a PPCIEM.
Section 108 of the Petroleum Industry Act requires all licensees and lessees to submit a natural gas flare elimination and monetization plan (FEMP) to the Commission, which is codified in Section 3 of the Emissions Regulations . The FEMP must outline the methodology for flaring elimination and monetization, and an associated implementation plan and timeline. Also, NUPRC Guide 0024-2022 requires the submission of a GHG management plan during design, installation, and modification of facilities. This plan can be submitted as part of the field development plan, concept and front-end engineering design, or as requested by the Commission. GHG management plans are due within six months of the issuance date of the guidelines (November 2022). The Authority’s Environmental Regulations require mandatory monitoring, estimation of volume, and reporting of GHGs; and plans for carbon capture, decarbonization, and net-zero targets of midstream and downstream operations. The Authority is expected to release guidelines for GHG inventory reporting and mitigation.
Saudi Aramco’s stated aim is to eliminate routine flaring in its upstream operations by ensuring that oil wells do not go online until gas takeaway infrastructure is in place, and by deploying appropriate technologies across company assets as identified in the FMPs of each facility . According to SAEP-400, FMPs, updated annually or when there is a significant modification, must describe measures taken in the past five years that led to the reduction or elimination of flaring, as well as short- and long-term plans to reduce flared volumes further in the future.
The OGA guidance on offshore field development plans must demonstrate that operators are taking appropriate steps to reduce GHG emissions from flaring and venting among other sources. Paragraph 56 of the OGA guidance for UKCS field development plans ask for “a detailed technical, economic and emissions assessment” to justify any flaring or venting. Licensees are also required to design facilities for “less wasteful alternatives should the economic or technical circumstances change.” Onshore guidance reflects the same principle of avoiding “unnecessary wastage” via flaring and venting. The Net Zero Stewardship Expectation 11 asks the oil and gas industry to reduce GHG emissions from all aspects of its upstream operations “as far as reasonable in the circumstances.” Development plans for greenfield projects need to demonstrate “consideration and economic assessment of GHG Emissions Reduction Action Plans.” These plans include “zero routine non-safety-related flaring/venting” and “gas recovery systems” in addition to low-carbon electricity options, better GHG measurements, new technologies to reduce emissions, and coordination with others to create energy hubs to avoid duplication of infrastructure. The OGA Flaring and Venting Guidance, 2021 , requires a Flaring and Venting Management Plan, which can be incorporated in the GHG Emissions Reduction Action Plan.
Flaring approval during completion can be granted through an approved gas capture plan during the permitting process or a subsequent application explaining why flaring is necessary. The plan must detail how the operator will minimize adverse impacts and include information on the volume of gas that will be flared and the duration of flaring. All proposed new facilities must submit a gas capture plan as part of their permit application, in accordance with Rule 903.e. The gas capture plan must include a commitment to connect the production facility to a gathering line before production starts or a plan for how the operator will connect the facility to a gathering line or otherwise put natural gas to beneficial use. If the gas capture plan is not implemented, the director of the COGCC may require the well to be shut in until there is an acceptable gas capture plan. For wells completed before January 15, 2021, that are not connected to a gas gathering system or otherwise do not put natural gas to beneficial use, a formal application for permission to flare, including a gas capture plan, must be made. The director of the COGCC can approve the application once for up to 12 months, but in no case will such wells be allowed to flare or vent natural gas after January 15, 2022. According to Rule 904 of the Environmental Impact Prevention 900 Series, 2021 , starting in 2022, the director of the COGCC will carry out an annual environmental impact assessment of the cumulative impact of flaring and venting on key environmental metrics. Operators can be required to contribute as a condition of their development plans receiving approval.