Country
Assessment
Article 15 of the 2021 proposal explicitly separates economic arguments from the permission to flare (see section 9 of this case study).
Article 3 of ESDM 17/2021 requires contractors and processing business permit holders to prioritize the utilization of flare gas. According to Article 4 of ESDM 17/2021, economic and technical studies must demonstrate that the utilization of low-combustion gas or gas with an impure gas share exceeding 50 percent is not feasible, and those volumes must be flared. Article 3 of ESDM 30/2021 requires contractors requesting a utilization of flare gas determination to provide technical, commercial, and financial documents and a copy of the price agreement with the flare gas buyer.
Article 147 of the Law on Subsoil and Subsoil Use, 2017 , prohibits the extraction of hydrocarbons without processing all raw gas. However, the law provides for several exceptions, all of which must be outlined in the field development plan. Article 146 provides exceptions under which flaring is permitted; Article 147 adds several others. The field development plan may include the operator’s own use of the gas or its sale to other parties. If these options cannot be justified economically, the field development plan may include re-injection for storage or enhanced oil recovery as long as other methods are ineffective in maintaining reservoir pressure and re-injection does not harm the environment. There are also regional considerations. For example, Article 274 of the Environmental Code, 2021 , prohibits the injection of associated gas for enhanced oil recovery in excess of the design parameters and volumes approved in the field development plan in the northern Caspian Sea region. These plans must be reviewed by an expert panel organized by the Department of Subsoil Use of the Ministry of Energy before being considered by the latter for approval.
Article 13 of the Model Production Sharing Contract, 2006 , assigns the commerciality assessment of excess associated gas to the Management Committee. If the gas is not commercial, NOCORP can exercise the right to take the gas free of charge after separating it from oil.
Article 6 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons allows flaring only when technical and economic analysis shows that it is the only viable option. Article 11 requires operators to conduct a technical and economic analysis to develop alternatives for the use of associated gas, to be carried out in line with the targets established and the criteria detailed in Articles 4 and 5 of the Technical Provisions. The analysis should consider the composition and volume of the gas; the proximity of the processing, transport, and distribution infrastructure; the value of the gas; and the necessary investments to utilize it. The guidelines contain case-by-case evaluation elements. The regulator and operator are expected to work together to find the best solution for a particular field. If operators wish to modify their associated natural gas utilization program, their proposal to do so needs to be supplemented with an update of the technical and economic analysis, justifying the actions, alternatives, and where appropriate, a new target to be adopted. Article 7 requires operators to maintain the financial resources to cover any damages caused by flaring. The allowed amounts of flaring are determined according to the Hydrocarbons Law, 2014 , or the project-related contracts. The CNH website provides examples of implementation experience. Two examples are the Tierra Blanca and the Muro fields.
Paragraph 43 of the Petroleum (Drilling and Production) Regulations, 1969 , requires the producer to submit a feasibility study, program, or proposals for the utilization of natural gas no later than five years after the commencement of production. However, the Petroleum Industry Act grants the ownership of all associated gas produced in PSCs to the restructured national oil company NNPC Ltd, which also signs all future PSCs representing the Federation. As such, there is no stand-alone economic evaluation of associated gas monetization. The costs of gas capture are recovered from the crude oil revenue, and gas flaring is an offense under Section 104 of the Petroleum Industry Act (see section 10 of this case study).
Section 4 of the Norwegian Petroleum Act, 1996 , requires oil and gas to be produced according to prudent technical and sound economic principles that mitigate the waste of petroleum resources. Toward that end, the licensee should continuously evaluate the production strategy and technical approach being used and adjust these as needed. Facts 2012– the Norwegian Petroleum Sector, 2012, illustrates several projects implementing opportunities to minimize gas flaring and venting. An example is the Goliat Project, centered on an oil and gas field located in the Barents Sea. The discovery well was drilled in 2000, and the field went into production in 2016. Associated gas has been re-injected or transported through a pipeline to Melkøya.
At the macroeconomic level, the MGS, implemented by Saudi Aramco and supported by the government via large upfront capital investments in the 1970s, resulted directly from the desire to meet the country’s growing energy demand with gas-fired electricity generation and to increase value-added production of petrochemicals, while freeing oil, previously combusted for electricity generation and industrial uses, for exports. Such economic assessment continues to drive investments to capture associated gas that could be otherwise flared and deliver it to industrial and electricity generation facilities across the country. At the facility and corporate level, monthly reports from the FMS help operators estimate the financial impacts of flaring, and its reduction (see section 13 of this case study).
The Net Zero Stewardship Expectation 11 lists various expectations as applicable across the exploration, appraisal, development, production, late-life, and decommissioning phases of an oil and gas asset. Opportunities to reduce GHG emissions, including from flaring and venting, include improved measuring, reporting, tracking, and incorporating of net-zero targets in corporate decision making across all lifecycle phases of an asset. Some design considerations for greenfield projects are relevant to flaring and venting. Both the Net Zero Stewardship Expectation 11 and the North Sea Transition Deal call for a sharper focus on energy hubs, the sharing of facilities, and long-term planning for infrastructure repurposing. Improved measurement and tracking of emissions are key requirements for better economic assessment by operators the OGA asks to develop reduction strategies for flaring and venting. The OGA benchmarking analysis for flaring shows that some facilities have much lower flaring intensities than others. More accurate and detailed data are expected to improve the understanding of the lowest-cost approaches to reducing volumes of flared gas. The OGA is also developing a database for methane emissions, in order to replicate the benchmarking exercise for venting. The OGA Flaring and Venting Guidance, 2021 , formalizes these expectations. Operators are expected to demonstrate that they evaluated all options to reduce flaring and venting when applying for consents and when developing credible plans to reach zero routine flaring and venting.
If the required gathering infrastructure (as discussed in the previous section) is unlikely to be available, an operator may either shut in the well or make a formal variance request to COGCC under Rule 502 of The Rules of Practice and Procedure 500 Series, 2021 . A formal variance request requires the operator to prove in a formal hearing that it would suffer undue economic hardship and that there will be no net adverse impacts from continued flaring or venting.