Country
Assessment
A development plan needs to be approved by ALNAFT, according to Law No. 19-13, 2019 . There is no explicit requirement for this plan to include associated gas disposal, but the plan must cover all commercially exploitable hydrocarbons (Article 106). According to Article 107, the plan must also include measurement and delivery points for all extracted hydrocarbons and allow for production optimization throughout the life of the asset.
Article 73 of the Petroleum Law, 2004 , states that the development plans for petroleum deposits should always be formulated in such a way as to allow for the use, preservation, or commercial exploitation of associated gas. Article 22 of the Regulation on Petroleum Operations, 2009 , states that the general development and production plan must include a plan for utilizing the associated natural gas. Article 23 states that annual production plans must include a provision for flaring and venting of natural gas and estimated volumes of special fluids to be injected for enhanced recovery.
No information specific to requiring a development plan for associated gas as part of the field development approval for greenfield projects was identified. However, Federal Resolution No. 105/1992 requires the operator to prepare an EIA for the development phase. The EIA must specify the installations to manage associated gas or dispose of it after a technical-economic study confirms that its use is not viable. Article 20 of the Neuquén province’s Decree No. 2.656/1999 outlines norms and procedures regulating environmental protection during oil exploration and production similar to those in Resolution No. 105/1992.
The OPGGS (Resource Management and Administration) Regulations, 2011, require field development plans. However, the section on the content of the field development plan (Regulation 4.07) is not explicit regarding flaring, venting, or methane emissions, Regulation 7.19 requires petroleum production licensees to include “gaseous petroleum flared or vented” in their monthly production report. Also, Regulation 4.14 requires “details of any proposed disposal or flaring of any produced hydrocarbons” in an application to recover petroleum before the acceptance of a field development plan. This suggests that the plans will likely include flaring details. Victoria’s OPGGS Regulations, 2021 , include the same requirements as Regulations 7.19 and 4.14. In addition, Victoria’s Petroleum Act, 1998 , requires a petroleum production development plan (Division 6). NOPTA reviews field development plans. Regulation 4.18 of the OPGGS (Resource Management and Administration) Regulations, 2011, requires operators to submit to NOPTA a rate of recovery application, which must be supported by “evidence that the equipment and procedures used to determine the quantity and composition of petroleum and water have been approved.” The submission on equipment and procedures should describe the metering of flaring and additional discharge (if any) within the processing facility. If the Offshore Petroleum (Royalty) Act, 2006, applies, the equipment and procedures application should be submitted to Western Australia’s DMIRS. Once this is approved, the rate of recovery application can be submitted to NOPTA. Part D.5.1 of the Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019 , requires a Methane Emissions Management Plan (MEMP), which demonstrates operators’ plans to reduce emissions to a level that is ALARP and acceptable through active monitoring and management. The MEMP must contain the practices followed for selecting equipment, designing standards, and maintaining equipment; the methodology and frequency of monitoring; leak classification and response; and emissions reporting. In Queensland, the Code of Practice for Leak Detection, Management & Reporting for Petroleum Operating Plant, 2022 , requires operators to develop a leak management plan to ensure leaks from wells, gathering systems, and processing facilities are detected, classified, controlled, and reported. In Western Australia, Part 6 of the Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations, 2015 , requires a field management plan (FMP) for petroleum recovery. The FMP must include detailed arrangements for petroleum disposal, venting, or flaring during production operations (Schedule 3) and must be consistent with the environment plan. The DMIRS must approve the FMP before production can begin. Regulation 58 requires submitting “details of any proposed disposal or flaring of produced petroleum” in an application to recover petroleum before the acceptance of an FMP. Part 3 of the regulations also requires a well management plan, which demonstrates that the risks of well activities will be ALARP, including those associated with flaring. In South Australia, the Petroleum and Geothermal Energy Act, 2000 , requires work programs to be submitted as part of the application for exploration, retention, and production licenses. There are no specific instructions concerning flaring, venting, or methane emissions, but “sound production practice” is expected for a royalty waiver, and the minister may consider variations to the work plan before approving it. In Tasmania, the Mineral Exploration Code of Practice, 2012, requires work programs to include details on potential environmental impacts and mitigation measures.
Article 44 of the Petroleum Law, 1997 requires the inclusion of associated gas use in the field development plan submitted to the ANP for approval after the declaration of commercial viability for a given project. The plan should consist of a schedule and investment estimate. Resolution 17/2015 provides guidelines for field development plans. Article 16(3) requires the submission of volumes expected for gas lift, internal consumption, re-injection, and flaring and venting, as well as mitigation plans for reducing gas flaring.
Directive 056: Energy Development Applications and Schedules, first released in 2021, presents the requirements and procedures for filing a license application to build or operate any petroleum industry on-site installations and the volume that is disposed of by burning in a flare or incinerator. Applicants proposing to flare, incinerate, or vent gas should comply with the requirements of Directive 060, 2020 , and Section 8 of Alberta Regulation 151/71: Oil and Gas Conservation Rules, 1971 . Since 2018, management of fugitive emissions has been based on a systematic program of detecting and repairing leaks and malfunctioning equipment. The AER requires operators to develop and document a Methane Reduction Retrofit Compliance Plan containing a schedule to replace and retrofit existing equipment and allocating funding to reduce venting. The plan must set an overall limit on the volume of vented gas at all existing and future oil and gas sites by 2023.
Development plans are required and published on the Canada–Newfoundland and Labrador Offshore Petroleum Board website. An example is the public review of the Hebron Development Plan Application.
Articles 31–33 in MME Resolution 40066/2022 requires new projects to be designed to capture vented gas. Existing projects have to upgrade their facilities for capture or flaring of otherwise vented gas within the required timeframe of two years.
Article 50 of the Hydrocarbon Operations Regulations, 2018 , requires operators to seek the MEM’s approval before development and production activities by presenting the operations program with technical or economic justifications. The operations program should include estimated volumes of associated gas for various destinations (as described in section 7 of this case study). The MEM’s authorization allows the flaring of the volumes of associated gas estimated in the operations program. Article 4 of Ministerial Agreement MEM-MEM-2022-0047-AM, 2022 , requires a plan for the progressive reduction of routine flaring for existing facilities, while Article 7 asks for an associated gas optimization plan for new facilities.
No evidence could be found on development plans for associated gas as part of the overall field development approval for greenfield projects.