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Flaring: continuous production

Topic last reviewed: 10 April 2013

Sectors: Downstream, Midstream, Upstream

Continuous production flaring occurs for a variety of reasons, e.g. the long-term absence of an economical gas valorization route for a satellite field, an absence of compression stages, or the routine venting of flash gas in upstream production. Some examples of good practices to reduce continuous flaring are given below, together with technology considerations and potential financial incentives.

Technology considerations

  • Condensate recovery: Check the condensable hydrocarbons (HC) percent in the flare gas. If the flare gas has high content of condensable hydrocarbons at the flare conditions, this liquid fraction should be recovered enabling the facility to spike them back into the main oil export stream.
  • Gas recovery from atmospheric separators or tanks: Install flare gas recovery system for recovering gas routed to the flare from tanks and process separators. The gas can be routed back to the process. When flare gas recovery evaluations are made, safety, environmental, technical and economic aspects should be included in the evaluation. Even where small volumes of gas from atmospheric separators are concerned, this gas should be recompressed and used as additional gas lift, injection gas or fuel gas instead of sent to flare. Note that this flare reduction technique involves the installation of compression equipment.
  • Gas recovery/transfer as a multiphase stream: Transfer gas from satellite wells to the main facility by transforming an oil-water pipe into a gas-liquid pipe (e.g. use a multiphase pump that would require less space than a compressor).
  • Gas re-injection or enhanced oil recovery: In some cases, flaring can be avoided by re-injecting the gas downhole. Gas injector wells can be drilled as new wells. However, it may also be possible to transform an existing producer or water injector into a gas injector via well works (re-perforations, etc.). If it is not possible to use gas re-injection for enhanced oil recovery, an option that should be evaluated is the injection of the gas into another non-producing reservoir/geological formation.
  • Gas recovery using an internal combustion (IC) engine: For operations where a gas turbine cannot be installed, an associated gas engine can provide power for compression. Gas engines have high energy efficiency (40%) and when coupled with a reciprocating compressor, they can be adapted to a low flow volume and high compression ratio. IC engines are heavier than turbines for an equivalent power generated, and maintenance and vibration aspects can be an issue. Fuel gas conditioning might also be required for an IC engine.
  • Gas recovery via a gas ejector: Install a gas ejector to recover the energy from a high pressure well to recompress low pressure gas instead of flaring it. Ejectors can also be used to recover gas from storage tanks (vent reduction application). (See the template for Ejectors.)
  • Gas recovery in a vapour recovery unit: Recover LP/LLP gas or flare gas/blanket gas from oil storage tanks into a flare gas recovery unit. (See the template for VOC recovery systems.)
  • Gas recovery in vapour recovery compressors: Install vapour recovery compressors to capture vented or flared gas, or route the gas stream into the suction of an existing compressor. (See Reference 2.)
  • Dehydrator flash gas recovery: During dehydration by absorption in the glycol contactor, methane and other hydrocarbons are also absorbed. In the flash drum and the reboiler, part of the hydrocarbons are flashed and vented to atmosphere or flared. Furthermore, the stripping gas can also be sent to flare. To recover the gas, redirect the dehydration skid flash drum vapours/overhead drum gas to the reboiler fuel gas supply, either directy to a dedicated burner or mixed with the rest of the fuel gas. Recovered gas can be also routed to other LP fuel gas consumers such as an amine reboiler, gas motors and crude heating. Also, the stripping gas consumed in the glycol regenerator can be optimized to reduce the stripping gas consumption of the glycol unit but still maintain the dew point specification. Optimization needs to be carried out with care due to, e.g. hydrate risk, off-spec gas.


Financial incentives for recovered gas

  • Incentivize flare reduction through Clean Development Mechanism (CDM) projects: The reduction of continuous flaring can generate carbon credits, which are tradable assets with a market value that may be fungible in regulatory schemes such as the EU Emissions Trading Scheme. The recovery and utilization of associated gas from oil wells is eligible under the CDM and Joint Implementation (JI) using a dedicated methodology (methodology AM0009) developed and approved by the United Nations Framework Convention on Climate Change (UNFCCC). This methodology is applicable to project activities that recover and utilize associated gas and/or gas-lift gas from oil wells, which would otherwise be flared or vented prior to the implementation of the project activity.

AM0009 projects typically generate large volumes of carbon credits, easily ranging from 100,000 to 1,000,000 tCO2e/yr, or more, depending on the volume and composition of the recovered associated gas. Note that only recovery of associated gas is eligible; reinjection of flare gas into the reservoir is not eligible at this stage. In order to generate such credits and be eligible for CDM/JI, strict applicability conditions need to be met, additionality requirements demonstrated, and a ‘Prior Consideration Form’ must be submitted before the project start date (meaning the earliest date of real action, typically when equipment purchase contracts are signed).

The additionality requirement includes the review of plausible alternative scenarios, including the evaluation of legal aspects, financial attractiveness, common practice and technical aspects to demonstrate that Carbon Credits are necessary for the project scenario to be approved by the oil and gas company. Additionality arguments (Excel files, board meeting decisions, financial analysis) must prove to be dated before the approval of the project by the investment committee, and the investment committee decision on the project must refer specifically to the use of Carbon Credits in its decision. It shall demonstrate that CDM benefits were considered necessary in the decision to undertake the project as a CDM project activity (i.e. at the moment of the investment decision). Therefore, it is important to gather and archive all CDM-related documents proving that CDM was considered in the project go/no-go decision. The financial analysis undertaken at the moment of the investment decision has to be made available, and it shall clearly show the project financial balance with and without carbon revenues/cost. More information on the AM0009 methodology, its applicability conditions and specific requirements can be found on the UNFCCCweb site (see Reference 3).

A ‘Prior Consideration Form’ must be submitted to the UNFCCC for all projects at an early stage, such as the screening of the project. This will prove the early intention to use Carbon Credits in projects. Guidelines on the demonstration and assessment of prior consideration of the CDM can be found on the UNFCCC website (see Reference 4).

  • Revenues from flare gas recovery usage: As discussed above, the recovery and utilization of associated gas from oil wells is potentially eligible under the CDM/JI, and can generate additional revenues for a proposed project activity. Flare reduction projects typically foster energy efficiency in E&P facilities, enhance environmental and social performances and use carbon financing as a means to ensure project profitability and promote the company’s image.
    • The recovered flare gas can be sold as AG, LPG, LNG, or CNG to third parties to generate significant additional revenues. Above a threshold of 500,000 m3/year, it usually makes sense for the oil and gas company to develop the project and find international or large local markets for the processed gas.
    • When the quantities of flare gas are too small (say under 500,000 m3/year) and/or where the gas market is not mature enough, the oil and gas company should consider tendering the associated gas to a local third party for treatment and local use—either bottling or any other local market activities. In this case, the custody transfer is at the flare point, and the third party—the municipality or local gas contractor—has responsibility to process and sell or utilize the gas. In this case, the CO2 emissions from the flare are then offset from the oil and gas company balance. This is a typical solution for flare gas quantities below 500,000 m3/year where the sales of flare gas at the flare point allows the oil and gas company to promote local energy projects with local authorities.
    • An alternative is to analyse the profile of the flare gas production and find a fit with the base load of energy needed to produce electricity directly by using the flare gas in a gas turbine, mini-turbine or gas engine. In this case, the need for a consistent supply of power would mean that a varying oil production profile presents an inherent risk.

Technology maturity

Commercially available?:   Yes
Offshore viability: Yes 
Brownfield retrofit?: Yes 
Years experience in the industry: 21+ 

Key metrics

Range of application:  Process units (e.g. glycol dehydrator) or storage tanks routed to flare system
Efficiency: Efficiency by preventing continuous flaring; losses due to continuous flaring can be significantly reduced by implementing good practice measures
Guideline capital costs: Cost depends on reduction measure employed; gathering pipelines and recovery compressors are examples of higher cost technologies to recover gas
Guideline operational costs: Cost savings from gas recovery
Typical scope of work description: 
The typical scope of work to avoid continuous flaring would entail the evaluation of alternatives to recover flared gas, including, but not limited to, flash gas recovery as low BTU fuel gas, incentivizing flare reduction projects through the CDM, and gathering pipeline infrastructure to recover gas for sales.

Decision drivers

Technical:   Hydrocarbon content and volume of flared gas.
Suitability of reservoir for gas reinjection or enhanced oil recovery.
Site space limitations for addition of gas turbine or IC engine.
Flash gas or stripping gas volume from glycol dehydration system, and ability to recover as LP fuel.
Operational: Optimize stripping gas in glycol regenerator.
Commercial: Saving energy and fuel cost .
Environmental: Reduction in air emissions of nitrogen oxides, sulphur dioxide, mercury, particulate matter, and greenhouse gases (GHGs).

Alternative technologies

The following are technologies that provide similar benefits and may be considered as alternatives to minimizing continuous flaring:

  • Compressors/drivers
  • Ejectors
  • Recovery of volatile organic compounds (VOCs)

Operational issues/risks

Issues and risks are few and known. Flare reduction technology has been used for many years. Operational risks may be associated with some techniques to reduce continuous venting, such as the optimization of stripping gas in glycol dehydration unit regenerator.


  1. Labeyrie, H. and Rocher, A. (2010). ‘Reducing Flaring and Improving Energy Efficiency: An Operator’s View’. Society of Professional Engineers (SPE) Paper 126644.
  2. EPA (2009). ‘Installing Vapor Recovery Units: Lessons Learned from the Natural Gas STAR Program'. Interstate Oil and Gas Compact Commission, Charleston, West Virginia, February 2009.
  3. UNFCCC (website). Clean Development Mechanism (CDM) AM0009 methodology. United Nations Framework Convention on Climate Change.
  4. UNFCCC (website). Clean Development Mechanism (CDM) large-scale project guidance. United Nations Framework Convention on Climate Change.