Leveraging methane emissions monitoring
There is a “tectonic shift” towards Net Zero, as stated by BlackRock’s CEO, Larry Fink, in his 2020 annual letter to CEOs. International oil companies like Repsol, Shell, Total, BP, and national ones like Petronas have endorsed 100% Net Zero goals under Scopes 1 and 2 for 2050. But what does this mean?
Net-zero refers to the balance between Greenhouse Gases (GHG) produced and those reduced, where emissions produced must be equal to emissions reduced. Although the first concept is universally known; oil and gas production and consumption generate GHG emissions, the second is not as widely known.
Therefore, it refers to extract emissions from the atmosphere using technologies like reducing fugitive methane emissions, carbon capture and storage, gas decarbonization, and hydrogen.
For instance, Scope 1 refers to direct GHG from company operations. On the other hand, Scope 2 refers to indirect emissions from energy consumed by the company. Third, Scope 3 considers indirect emissions generated by the goods and services produced by the company. (For more information, see GHG Protocol Initiative).
Moreover, the financial sector is also endorsing Net Zero goals, translating into less funding for projects with a deficit in their emission balances. Therefore, is this a punishment or an incentive? As we will discuss below, Net Zero goals have public and private interests aligned.
Methane, environment, and business: a case of aligned interests
Methane has been responsible for 40% of global warming since the industrial revolution. Additionally, its effect on climate change is 84x carbon dioxide’s over 20 years; and fossil fuels represent 36% of the world’s methane emissions. Thus, tackling methane emissions in the oil and gas industry can be a shortcut; capable of obtaining results in a couple of decades.
According to the International Energy Agency (IEA), 40% of the world’s methane emissions from oil and gas can be repaired with a positive economic return. Thus, making the accurate repairment of methane leakage from facilities and equipment a “no brainer” towards Net-Zero.
For example, take three representative cases out from our 150 projects portfolio in Canada where direct measurement methods are mandatory. Applying Optical Gas Imaging (OGI) technology for methane emissions quantification allowed for immediate repairs and economic benefits from stopping the gas waste.
Regulation and best practices in the North American region
In 2016, the USMCA region (NAFTA at the time); became the raw model for the rest of the world in regulating methane emissions in oil&gas activities. Then, presidents Trudeau, Obama, and Peña jointly committed to reducing the 2012 levels of methane emissions from the oil and gas sector by 2025.
In fulfilling this goal, the US issued the methane-specific requirements for regulations (NSPS-2016). Hence, requesting direct measurement for quantification and monitoring methane leaks using OGI technology and Method 21 from the Environmental Protection Agency (EPA). The Canadian regulation also followed this best practice, requiring any technology that shows equal or better results than OGI. Besides, it is the only country of the USMCA region with traceable results, environmentally and economically, in this matter.
Another best practice followed by all three countries in the North American region is the requirement to perform Leak Detection and Repair (LDAR) programs based on direct measurement methods like OGI and Method 21.
Deviations from best practices
Unfortunately, Mexican regulations (ASEA-2018) deviate from best practices allowing indirect methods for the methane emission baseline quantification without any conditioning.
For instance, these methods refer to an estimation of emissions through engineering calculations; thus, like the widespread use of emission factors (which are typically designed for overestimation). By requiring LDAR programs based on direct methods such as OGI. Besides, contradictorily, allowing indirect methods for estimating emission baseline, there is a technical inconsistency in ASEA-2018.
Therefore, the first LDAR program in Mexico must be performed within three months after the emission baseline submittal. Given this inconsistency, companies should opt for direct measurement right from the emission baseline.
However, the most drastic departure from best practice was when in 2020; President Trump’s administration rescinded the NSPS 2016 applicable to sources in the production and processing segments.