(645d) Technoeconomic Framework of Natural Gas Pyrolysis As an Alternative to Flaring and Venting in the Oil Extraction Sector

Among the world's leading oil and gas producers there is Canada. Canadian extraction sites are dispersed in a broad region, almost as big as Europe’s surface (< 140000 km²), corresponding to Alberta and Saskatchewan provinces [1].

Every time oil is extracted, generally through fracking technology, the light hydrocarbons present on top of the bituminous mass in the form of natural gas are usually flared or, even worse, vented. This is done because of the scattered nature of the extractive sites and because of their location, miles away from the main inhabited areas. Building pipelines and infrastructures to collect the natural gas - which is less than 5% of the total bitumen production - is unfeasible, as it would be very expensive, considering the required length and the necessity of having pressurized pipelines [2].

Flaring and venting practices represent a severe issue for Canada, both economic and environmental. In fact, 1.7% of the overall gas emissions are due to venting [3].

Natural gas is mostly composed of methane, which is the second highest contributor to the greenhouse effect. Its global warming potential is 37 times that of CO₂ [4]. To partially solve the situation, a stricter taxation system, the so-called carbon tax, has lately been introduced, which restricts total carbon emissions and obliges oil producer to reduce their emission by 1% per year [5]. Parallel to this, some new technologies have been developed to either trap or convert these gases, mainly into hydrogen. The gas-to-liquid (GtL) technologies are among the most common, along with steam methane reforming (SMR) and methane pyrolysis.

In particular, SMR provides approximately 48% of the global H₂ demand [6]. SMR allows the production of the so-called grey H2. One main issue connected with this H₂ production is that CO₂ is also produced [7].

An alternative solution is outfitting the plant with Carbon Capture and Storage (CCS) technologies to mitigate the emissions, but this often represents a prohibitive additional cost [6], [8].

In this context, decarbonizing fossil fuels by recovering and sequestering solid carbon instead of gaseous CO₂ can be a suitable alternative [9], [10].

Methane pyrolysis splits CH₄ directly into its components, i.e., hydrogen and carbon. Unlike other technologies involving fossil fuels, the major benefit of methane pyrolysis is the production of CO₂-free hydrogen. Theoretically, this is the best possible option since it is not as endothermic as steam reforming and produces two valuable commodities: the so-called turquoise hydrogen and solid carbon. Notably, the latter is not emitted and therefore not transformed into CO that becomes CO₂ afterward. This route is particularly attractive, but there are some technical challenges related to commercialization. Particularly, the low cost of turquoise hydrogen and the uncertainty around C as a source of income are still research questions.

Here we aim to demonstrate that methane pyrolysis is a viable and potentially profitable technology in the context of Canadian remote extraction sites.

Here we propose the technical and economic framework of an innovative process, performed in situ to avoid flaring and venting of natural gas. The proposed process is based on non-catalytic methane pyrolysis at T = 950 °C and atmospheric pressure, performed directly at the extraction site, converting the gas into solid carbon and hydrogen.

Part of produced hydrogen is used as a fuel to sustain the process energetically, while solid carbon can find many applications in industry as a reducing agent, in the production of batteries, or in soil amendment and environmental remediation. Two configurations were conceptualized and simulated in Aspen Plus. In Configuration 1, 39 % of H₂ is burnt to sustain the reactor, while the main part is compressed and sent to a turbine to produce electricity. In Configuration 2, 23 % we admit the possibility of selling the hydrogen that is not used to sustain the reactor. In this case, a PSA is introduced to obtain 99.9 % pure hydrogen.

For each Configuration economic indicators were calculated, and environmental issues were discussed to identify the most promising configuration given the current context. Both configurations reduce CO₂ emissions by more than 92 % compared to flaring.

From a profitability perspective over 10 years, Configuration 1 is characterized by a Simple Payback Period (SPBP) of 2.6 years and an IRR of 25.2 %, while they are equal to 3.2 years and 19.5 % for Configuration 2.

References

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[2] Alberta Energy Regulator, “Upstream Petroleum Industry Emissions Report - Industry Performance for Year Ending December 31, 2020,” 2021. [Online]. Available: www.aer.ca

[3] Environment and Climate Change Canada, “NATIONAL INVENTORY REPORT 1990-2020: GREENHOUSE GAS SOURCES AND SINKS IN CANADA,” 2022.

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[8] S. Pelucchi, F. Galli, C. Vianello, and P. Mocellin, “Integrating the Benefits of Turquoise Hydrogen to Decarbonise High-Emission Industry,” Chem Eng Trans, vol. 105, pp. 25–30, 2023, doi: 10.3303/CET23105005.

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