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Part 2: A review of alternative and supplemental technologies to flare systems in the oil and gas industry

By Abdulrahman AlMashaan, Production Engineer, Operations Department, Petrochemical Industries Company

Welcome to the second and final part of my ‘Review of alternative and supplemental technologies to flare systems in the oil and gas industry’. In Part 1 of this article, I provided an introduction to gas flaring as well as a technology review involving power generation and solid oxide fuel cells. What follows is Part 2, which continues to look at the technology available, including:

  • Methane reforming
  • Gas reinjection into reservoirs

Finally, it provides a conclusion and recommendations on technology adoption and further research.

Gas flaring is a standard practice in which plants burn process gas and release the by-products into the atmosphere. In general, hydrocarbons gas streams are vented off these plants by being combusted into CO2 before release. The specifics of the flared gas will depend on the plant, the process, and the materials involved. Typically, oil and gas plants will flare methane gas, while petrochemical plants and refineries will flare small hydrocarbon chains.


2.3 Methane reforming

Some flaring alternatives focus on capturing the economic benefit of flared gases by converting them to more valuable products. A study by Mansoor et al investigates these approaches, including the production of syngas through methane reforming[7]. Syngas, a combination of CO and H2, can be used in Fischer-Tropsch (FT) reactions to produce longer hydrocarbon chains and valuable synthetic liquid fuel[8].

Mansoor investigates various methods of producing syngas through methane, which is typically the main component of flare gas. In steam methane reforming (SMR), methane reacts with water in the form of steam to produce hydrogen, CO, and CO2 through endothermic reactions. A side reaction also occurs between CO and steam to produce hydrogen and CO2, along with the generation of heat. However, a limitation of this reaction pathway is the generation of a significant amount of CO2. As a result, it is recommended to utilize CO2 suppression techniques to provide the correct syngas composition. These can include processes such as pressure swing absorption or CO2 capture through solid sorbents[7].

Another potential pathway includes dry methane reforming (DMR). As is suggested by the name, this reaction mechanism does not involve steam, and instead, utilizes a Ni-based catalyst. This approach seems to provide a suitable H2/CO ratio for higher hydrocarbon synthesis later downstream in FT reactions. From an industrial or flaring point of view, DMR can be an attractive approach as it consumes both methane and CO2 to generate syngas, which also contributes to the decrease in greenhouse gas emission. However, this approach has several constraints that make it difficult to implement on an industrial scale. The reactions employed are very endothermic, and require temperatures of roughly 1000 K. At these temperatures, several side reactions can occur that consume the previously produced hydrogen. This changes the H2/CO to be less than ideal. It is also reported that catalyst deactivation for the DMR process occurs readily at the industrial scale due to carbon formation[7].

Autothermal reforming (ATR) can also be used to convert methane to syngas and has been known to be the preferred technology due to its cost-effectiveness and high efficiency. This reaction pathway still includes steam, but also features the exothermic oxidation of methane. Not only does the oxidation produce CO and water, but it also produces heat that removes the need to provide an additional heat source. ATR systems have several advantages, including high productivity, compact size, and high heat efficiency. These systems provide more control over the desired H2/CO ratio. Nonetheless, ATR has been reported to have a lower hydrogen yield than SMR. In addition, the potential of coke formation is high, with various values reported from industrial applications. This in turn affects the catalyst productivity of the system[7].

In terms of economics, Mansoor reports that of the different routes to produce syngas, methane-rich sources are the least costly, making flare gas an attractive starting point for this process. A study conducted by Baltrusaitis et al explores the economics of these different technologies, particularly with a focus on whether DMR can compete with SMR or ATR given the CO2 consumption feature of DMR.

A full process was designed for five different combinations of these technologies, and it was reported that at a base case, a SMR/DMR combination results in the least total annual cost, but not the least capital cost. This combination also provides plants with the opportunity to consume CO2, resulting in better H2/CO ratios and a decreased environmental impact[9].

It should be noted that the economics of this approach can be sensitive to raw material costs as well as carbon taxes. Another factor to note is also the market price of syngas as well as transportation costs. Furthermore, the studies on methane reforming assume specific setup, whether on the reaction operating parameters or the equipment configuration, and so is expected to be different for different plants.

Figure 4 – Simplified value chain pathways of producing syngas from water, methane, and carbon dioxide. Reproduced from Baltrusaitis et al.[9]

2.4 Gas reinjection into reservoirs

Other technologies aim to prevent the release of hydrocarbons and combustion byproducts into the atmosphere. One such process, suggested by Hoffman et al, involves the injection of flare gases back into unconventional oil reservoirs to improve the recovery of liquid hydrocarbon[10]. When reinjected, natural gas or CO2 increases the pressure in oil wells, causing more gas molecules to dissolve into the oil, lowering the viscosity. This ultimately increases the well’s output[11].

A simulation by Hoffman was run on three wells running on primary production over a 30-year time period, where a base case provided a production of 470,000 stock tank barrels and a recovery factor of 12%. The simulation was then run with an injection of a hydrocarbon mixture, based on a produced gas sample from the field, after 5 years of primary production. Results of the simulation revealed that the cumulative production increased to 960,000 stock tank barrels and a recovery factor of 24%. An economic analysis of the injection case was also conducted, leading to a NPV of USD 16.1 million and a payback period of 5.8 years.

The economic assumptions were also made stricter in ways, such as a decreased recovery factor or less valuable products, and the simulation was still found to be economically feasible[10].

Other studies in this area focus on CO2 injection rather than hydrocarbon gas injection. A paper by Du et al inspects the effects of injecting CO2 into shale oil, gas, and condensate reservoirs. A variety of formations, with different parameter values for porosity and permeability, injection times, pressures, and models were reported. In the case of shale reservoirs, CO2 provided an increase in the oil recovery factor in the range of 10-22.8% compared to the primary depletion scheme. Injection into shale gas reservoirs also provided promising results, with a reported increase in gas recovery factor up to 185%. In addition to the increase in various recovery factors, Du highlights the potential of approach for carbon sequestration. By injecting CO2 into reservoirs to aid with oil or gas recovery, the CO2 molecules could be readily sequestered into small pores in an adsorbed state[12].

Figure 5 – Simulated increase in oil recovery factor through the injection of hydrocarbon gas mixture. Reproduced from Hoffman et al.[10]

3. Conclusion and recommendations

 Gas flaring in the oil and gas industry continues to be an economic and environmental issue. While plants rely on non-routine flaring for safety reasons, the constant use of these flares have contributed greatly to climate change. The release of CO2 from these flares, while less detrimental than methane in the short term, can be viewed as both an environmental cost as well as an economic one.

Nonetheless, there are several technologies that aim to reduce the costs and negative impacts of flaring. Utilizing flare gas can take many forms that exploit the gas’s physical and chemical properties, including generating power, producing more valuable products such as syngas, and even being reinjected into reservoirs to improve recovery factors of oil and gas. When applied to the correct setting, these alternatives to flaring have been proven to turn a profit while also potentially reducing harmful greenhouse gas emissions. While several of these alternatives have been discussed, there remains a myriad of viable technologies and combinations that can be implemented. Gas-to-liquid technology, carbon capture, and even using flare gas as petrochemical feedstock are some of such alternatives, each with its strengths and challenges.

However, it is evident that no technology is “one-size-fits-all.” There are advantages and disadvantages to each, and as a result, they must be studied carefully before implementation. Plants in the oil and gas industry are distinct and diverse, ranging in factors from size and flare gas composition to location and financials. Consequently, the selected approach must also be customized to the specific plant. The studies discussed reveal the sensitivity of these alternatives and how different assumptions on plant size, flow, and even technology configuration could change an economically unfeasible solution to a profitable one.

Moving forward, further research into these alternatives is recommended. By optimizing and developing technologies, the industry will be more susceptible to adopting these changes. Developing new technologies will also aid in this effort by catering to plants that do not currently have the specifications to properly utilize existing approaches. Ultimately, the goal of alternatives and supplements is not to reduce, but eliminate, the negative impact of flares.


[8] Mehariya, S., Iovine, A., Casella, P., Musmarra, D., Figoli, A., Marino, T., … Molino, A. (2020). Fischer–Tropsch synthesis of syngas to liquid hydrocarbons. Lignocellulosic Biomass to Liquid Biofuels, 217–248.doi:10.1016/b978-0-12-815936-1.00007-1

[9] Baltrusaitis, J., & Luyben, W. L. (2015). Methane Conversion to Syngas for Gas-to-Liquids (GTL): Is Sustainable CO2 Reuse via Dry Methane Reforming (DMR) Cost Competitive with SMR and ATR Processes? ACS Sustainable Chemistry & Engineering, 3(9), 2100–2111.doi:10.1021/acssuschemeng.5b00368

[10] Hoffman, T., Sonnenberg, S., & Hossein, K. (2014). The Benefits of Reinjecting Instead of Flaring Produced Gas in Unconventional Oil Reservoirs. Proceedings of the 2nd Unconventional Resources Technology Conference.doi:10.15530/urtec-2014-1922257

[11] Aregbe, A. (2017) Natural Gas Flaring—Alternative Solutions. World Journal of Engineering and Technology, 5, 139-153. doi: 10.4236/wjet.2017.51012.

[12] Du, F., & Nojabaei, B. (2019). A Review of Gas Injection in Shale Reservoirs: Enhanced Oil/Gas Recovery Approaches and Greenhouse Gas Control. Energies, 12(12), 2355. doi:10.3390/en12122355