Revealing the strategies to limit hydrocarbon emissions

Credit: M. Schuppich / Shutterstock

The oil and gas industry is responsible for approximately half of all energy-related emissions, presenting a complex landscape for the sector to tackle.  

Scope 1 emissions are released directly by an oil and gas organisation from owned and controlled sources, while Scope 2 covers indirect emissions from production, processing, and transportation.  

Most emissions are from sold products or Scope 3 – the result of activities from assets not owned or controlled by the reporting organisation, but that the organisation indirectly affects in its value chain. This includes the use of oil and gas for power generation, heating, vehicle fuel, and industrial processes.  

Upstream emissions are closely linked to production and processing, whereas downstream activities account for roughly 70-90% of lifecycle emissions from oil products and 60-85% from natural gas, as per the International Energy Agency (IEA).  

Common strategies are emerging in the form of renewable energy, carbon capture, and electrification, with potential for the oil and gas industry to pioneer advancements in these technologies to the benefit of the global energy transition.  

However, effective measurement systems and the impact on bottom lines pose significant barriers to realising an industry-wide mitigation of emissions.  

Before emissions can be addressed, they must be accurately detected and measured. At the core of this challenge is the greenhouse gas (GHG) methane, which is 21 times more potent than carbon dioxide (CO₂). It is a byproduct of leaks and flaring in oil production, processing, and distribution and comes directly from gas.  

The IEA identifies methane as the “single most important measure that contributes to the overall fall in emissions from oil and gas operations” but highlights that “global methane emissions are underreported by 70%”.  

The scale of such underreporting is being gradually uncovered by the increased use of aerial, satellite, and infrared imaging which have improved accuracy alongside traditional point-source and multiplication measurements.  

The UK’s North Sea Transition Authority (NSTA) tells Offshore Technology that emissions can be accurately measured by a “combination of direct measurement, using meters attached to flares and vents, and modelling [and] several operators are verifying these estimates using drone monitoring surveys.” 

Offshore Technology’s parent company GlobalData singles out methane as “low-hanging fruit” for emissions reduction across the oil and gas industry. The GHG has a short-term life of seven to 12 years in the atmosphere, offering potential for near-term abatement progress. 

Jim Lenton, global sector lead of upstream, midstream and liquified natural gas at Australian engineering and professional services company Worley, highlights BP as an example of an organisation “making investments in technology to measure what it is emitting from its assets for more accuracy.” 

Since 2019, BP has deployed continuous measurements of methane emissions in all of its new oil and gas processing projects.  

To reduce wasteful emissions, the World Bank suggests that oil and gas operators should focus their efforts on eliminating all non-emergency flaring of natural gases under its Zero Routine Flaring Initiative 2030. 

Such progress is further aided by the United Nations Environment Programme (UNEP)’s Oil & Gas Methane Partnership 2.0, which is the only comprehensive, measurement-based international reporting framework for the sector. 

Paul Bansil, director at science, technology, and engineering at solutions provider KBR, points out that in a “complex global supply chain and sales context, the issue of limiting emissions is perhaps more one of consistency and clarity, rather than accuracy of measurement.” 

Assigning responsibility once emissions are measured differs between Scope 1, 2, and 3. Jared Sharp, project lead at the Transition Pathway Initiative, explains: “A company's Scope 1 and 2 emissions reporting and targets will be more ambitious than their Scope 3 emissions, because they are directly responsible for those. But culpability is difficult, though there has been movement to include upstream producers more.” 

To reduce emissions, oil and gas companies are switching to lower-carbon sources of energy. A fundamental enabler for this is electrification, which involves the conversion or replacement of equipment and facilities that run on fuel with electricity. 

Making this change is vital as otherwise “mechanical drivers and fired equipment ‘lock in’ emissions for the lifetime of an asset”, according to the International Association of Oil and Gas Producers (IOGP). 

Major industry players are investing in electrification, bridging the gaps between onshore and offshore infrastructure to address upstream emissions. Electricity can be sourced from onshore power grids, a neighbouring offshore facility for increased operational connectivity, or an electrification-ready asset on a remote facility.  

On the Norwegian Continental Shelf (NCS), Equinor has electrified its oilfields and platforms with power from mainland Norway and offshore wind farms with the goal of reaching near zero emissions by 2050.  

Everingham added that the technology that has allowed the extraction, processing, and eventual

Lenton underlines the technical and financial challenges in connecting oil and gas assets with power infrastructure. “We’ve seen movement in this space, but nothing in the Gulf of Mexico for example, where most facilities are about 5,000 feet deep. So, whatever you put in place is going to require something floating to power the facilities.”

He proffers floating nuclear power for offshore assets as a promising path for decarbonisation, with the caveat that this would “require big investment and take at least 10 years to execute.”

Bansil asserts that no matter the technology used, the focus must be on “circularity and efficiency, or useful energy generated as a function of energy input.”

Research from the NSTA highlights the role of emissions in building “commercial opportunities” between renewable energy suppliers and the oil and gas sector, alongside electrification’s “critical preservation of the industry’s social licence to operate.”

Emissions from refineries are a key point of concern within an organisation’s value chain. Developing electrolysis technology is limiting this impact through the production of green hydrogen, aiding the desulfurisation of crude oil without CO₂ emissions.  

Green hydrogen can then be integrated into natural gas grids and pipelines, utilised as industrial furnace fuel, converted into synthetic hydrocarbons, or used in fuel cells. 

To further progress towards climate mitigation targets under the Paris Agreement, an estimated 2,000-plus large-scale carbon capture and storage (CCS) facilities must be deployed by 2050, and the oil and gas industry has a central role to play.  

CCS offers an additional solution for low to negative emission intensity, capturing CO₂ at its source before it is transported to storage locations. It can then be injected into depleting oil reservoirs, which can increase ‘enhanced oil recovery’ (EOR), or support gas processing in LNG reservoirs.  

According to the Global CCS Institute, the majority of CO₂ that is currently used for EOR comes from naturally occurring deposits underground, so there is significant potential to “replace this with CO₂ that is captured from large emissions sources or from the atmosphere.” 

GlobalData predicts that the number of active oil and gas CCS sites will increase from 66 in 2023 to 285 by the end of the decade, at a compound annual growth rate of 38%. 

The International Institute for Sustainable Development points out that the economic viability of CCS for oil and gas operators “continues to rely heavily on federal and provincial government financial support, in contrast to renewable technologies.” 

The IEA forecasts that $600bn upfront spending is required by 2030 to achieve a full 50% reduction in the emissions intensity of oil and gas operations, which is 15% of the industry’s windfall net income in 2022. 

The largest oil and gas producing nations in the world are taking steps to reduce emissions. Most recently, Canada announced draft regulations to cap GHG emissions from the sector, aiming for a 35% reduction from 2019 levels by 2030. 

For electrification, hydrocarbon, and CCS, Sharp asserts that “technologies such as solar, wind and batteries have far outstripped the development and the cost of these. CCS in particular is wildly expensive. But we’re still early on in the transition.” 

But oil and gas giants are increasingly recognising the benefits of investing in alternative technologies to diversify their portfolios and reduce transition risk if revenues from oil and gas fall. A prime example is Equinor, which has set a goal to invest more than 50% of its capital expenditure in renewables and low-carbon solutions by 2030.  

Bansil asserts that there are “now various policy mechanisms coming into play, including international agreements and local regulatory requirements, which are effectively enshrining decarbonisation as a ‘licence to operate’, or a prerequisite for project finance. As 2050 gets closer, it would take a brave person to bet on these motivating factors easing off.” 

Any costs are worth it in the long term, claims Lenton. “Our industry tends to be a bit of a super tanker that takes a long time to do things. Ultimately, it’s about picking those things that can be done. Companies want to retrofit and upgrade their power supplies with better technology to reduce emissions, as well as give themselves a longer life and overcome obsolescence.”