INDUSTRY INSIGHTThought Leadership

Part 1: A review of alternative and supplemental technologies to flare systems in the oil and gas industry

By Abdulrahman AlMashaan, Production Engineer, Operations Department, PIC

1. Introduction

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.

Chemical plants flare process gas for a variety of reasons. First and foremost, flaring offers a safe way to protect the plant and its equipment in different scenarios. The most important of these is to prevent over-pressurization of the process. If a certain line or vessel is unintentionally pressurized due to any reason, the process gas can be routed to the flare to mitigate safety risks and prevent accidents as severe as hydrocarbon cloud explosions. This is also a way to protect equipment from damage and constant, costly replacements. Flaring is also used in planned scenarios in which by-products must be safely discarded. These purge streams offer plants an effective way to start up and shut down, control stream composition, and maintain system operating parameters.

Figure 1 – Changes in flaring intensity vs volume of the top 30 flare-producing countries between 2016 to 2021

(Source: NOAA, Payne Institute and Colorado School of Mines, EIA, GGFR). Reproduced from the 2022 Global Gas Flaring Report by The World Bank[2].

In an environmental aspect, flaring does reduce the harmful impact of some process gases, such as methane, by converting it to carbon dioxide before venting. According to the Environmental Defense Fund, methane is 80 times more potent with warming power compared to carbon dioxide in the first 20 years. In fact, methane alone accounts for 25% of today’s global warming[1].

However, the environmental cost of flaring still cannot be ignored. Carbon dioxide, while better than methane, does have longer-lasting effects, contributing to global climate change. In its Global Gas Flaring Tracker Report, The World Bank estimates that 144 billion cubic meters of gas was flared across the globe upstream oil and gas facilities in 2021, releasing approximately 400 million cubic meters of CO2 equivalent emissions[2]. CO2 contributes to global climate change by absorbing and radiating heat in all directions from the atmosphere, unlike O2 and N2, while also dissolving into the oceans and increasing the water acidity[3].

As a result, global entities have been pushing for a significant reduction in flaring. The World Bank has also launched the Zero Routine Flaring (ZRF) initiative, which urges governments and companies to eliminate routine flaring by 2030[2].


2. Technology review

While the elimination of flaring is ideal, several studies have been conducted in recent years to develop improvements and alternatives to flaring. These processes range from supplementing exist flare stacks to completely replacing flares with other processing units.

2.1 Power generation

A promising development in this field is utilizing flare streams for power generation. Depending on the source, flare hydrocarbon streams can be energy-rich through high temperatures or pressures. The current flare technology does not take advantage of these parameters, and burns the streams as is. In fact, the World Bank reports that the 144 billion cubic meters of natural gas flared had the potential to generate 1,800 Terawatt-hours of energy, which is approximately equivalent to two thirds of the European Union’s energy generation[2].

Different technologies can be used to generate power through these hydrocarbon streams. One of the attractive features of power generation is its customizability. A study conducted by Nezhadfard et al explores different power-generating configurations for methane-rich streams, including gas turbine cycles, combined cycle gas turbines, and reciprocating internal combustion engines[4].

Each of these technologies takes advantage of a different characteristic of the hydrocarbon flare stream, whether mechanical or chemical. In the case of gas turbine cycles, the high pressure of the incoming flare gases is used to drive the turbine and generate power. The gas turbines can also be combined with steam cycles in the combined case, where the high temperature of the incoming flare gas is used to heat the steam in steam turbines to generate electricity. In contrast, reciprocating internal combustion engines take advantage of the chemical nature of hydrocarbons and the heat released when undergoing combustion to drive turbines.

Figure 2 – Proposed schematic of the Combined Cycle Gas Turbine configuration. Reproduced from Nezhadfard et al.[4]

Figure 3 – Simplified diagram outlining the operating mechanism of SOFC. Reproduced from Mirzababaei et al.[5]

Nezhadfard et al analyzed the economic and environmental impacts of the different technologies for a wide variety of flare gases, particularly in the oil and gas refinery settings. These simulated gases ranged in temperature, pressure, flowrate, and composition. The results of the study indicate that, if chosen correctly for the process stream and plant specifications, these alternatives to flare do not simply recoup losses due to flaring, but actually turn a profit.

Along with the stream parameters, the generated power capacity was calculated based on the sample stream’s high heating value, which is provided in the study for each sample. It is reported that for the simple gas turbine cycle to be profitable, a minimum capacity of roughly 100 MW is recommended. The sample that corresponds to this minimum generates 101 MW, with a NPV of roughly $110 million and a payback period of 12 years. Other streams have been reported to have better economic performance, such as a 489 MW-producing stream with a payback period of only 3.56 years. The same trend can be seen with the combined gas turbine cycle, with a minimum capacity recommendation of 50 MW. It is reported that this technology has better overall performance, which is seen by comparing the payback periods for the same streams studied. The stream corresponding to the minimum in the first case now has a NPV value of $274 million and a payback period of only 5.24 years. Finally, reciprocating internal combustion engines were found to be the most effective, being suitable for a large variety in stream composition and capacities. Comparing the same stream as was done previously, this technology provides a NPV of $412 million and a payback period of 2.36 years.

It should be noted that these cases are directly impacted by the composition of the stream analyzed. Some simulated streams do not contain H2S – so-called “sweet streams” – and so do not require sweetening or certain processing. In other cases, H2 is included in the stream composition, and so an additional fuel source for reciprocating internal combustion engines is not needed. These factors significantly reduce the capital and operating costs of the suggested technologies compared to the others discussed above, even if the provided capacity is less than the recommended values. As a result, the technologies used must be catered to the plant or facility to optimize both performance and value.

Nezhadfard et al also inspected the environmental emissions of these power-generating alternatives. Since the technologies supplement existing flares without eliminating the final combustion stage, the CO2 emissions are approximately the same for that of a conventional flare stack. However, these systems do provide significant reductions in SOx and CO emissions due to the required processing embedded in the systems. It is also concluded that the reciprocating internal combustion engine scheme provides the lowest emission per kWh generated.


2.2 Solid oxide fuel cells

Power generation also can take the form of solid-oxide fuel cells (SOFC), which utilize methane to produce power through the transfer of electrons in electrochemical reactions. SOFC features a solid electrolyte phase that separates the cell’s anode and cathode. First, an oxygen source, typically pressurized air, is introduced in the cathode, where it is reduced to O2- ions. The ions move through the electrolyte to meet the fuel source at the anode, which in the case of a hydrocarbon fuel source, can be methane. The methane is then oxidized by reacting with the O2- ions, producing byproducts such as CO and CO2 and releasing electrons. The transfer of these electrons from the anode to the cathode generates electricity[5].

A study by Al-Khori et al explores the feasibility of using flare gas as a fuel source for SOFC to generate electricity. Al-Khori simulates the performance of SOFC by using a proposed flare gas stream with the electrochemical reactions of the fuel cells, while also considering the minimum flow to keep the flare stack running. The simulation revealed that the proposed system recovers a maximum of 70% of the flare gas, producing approximately 20 MW of electricity. This also implied a 61% reduction in greenhouse gas emissions. The project is also reported to have a NPV of $20 million, an IRR of 6%, and a ROI of 1.41, suggesting the economic benefit of the technology[6].

It is interesting to note that Nezhadfard et al also explored SOFC as an alternative technology for power generation. However, it was found to be economically unfeasible. Comparing the two studies reveal that the gas stream studied have very similar composition, flow rate, heating value, as well as power generation values; the difference between the two is in the proposed design itself. Nezhadfard combines the SOFC unit with a gas turbine cycle, while Al-Khori does not. Al-Khori also opts for simpler H2S treatment methods as it is assumed that the gas has minimal, yet not trivial, amounts of H2S. These decisions, among others, ultimately impact the total capital costs of the proposed design, which explains the discrepancy between the approaches. This reinforces the idea that these technologies must be catered to the specific plant and a standard design cannot be assumed.

This is part 1 of a two-part article examining alternative and supplemental technologies to flare systems in the oil and gas industry. Part 2 will be published in the next edition of GPCA’s Insight Express newsletter.


[1] “Methane: A Crucial Opportunity in the Climate Fight.” Environmental Defense Fund,

[2] The World Bank, 2022, 2022 Global Gas Flaring Tracker Report,

[3] Lindsey, Rebecca. “Climate Change: Atmospheric Carbon Dioxide.” NOAA, 23 June 2022,

[4] Nezhadfard, M., & Khalili-Garakani, A. (2020). Power generation as a useful option for flare gas recovery: Enviro-economic evaluation of different scenarios. Energy, 117940.doi:10.1016/

[5] Mirzababaei, J., & Chuang, S. (2014). La0.6Sr0.4Co0.2Fe0.8O3 Perovskite: A Stable Anode Catalyst for Direct Methane Solid Oxide Fuel Cells. Catalysts, 4(2), 146–161.doi:10.3390/catal4020146

[6] Al-Khori, K., Bicer, Y., Aslam, M. I., & Koç, M. (2021). Flare emission reduction utilizing solid oxide fuel cells at a natural gas processing plant. Energy Reports, 7, 5627–5638.doi:10.1016/j.egyr.2021.08.164