New research from DNV GL reinforces the message that pressure on the global oil and gas industry to decarbonize its value chain to maintain its social license to operate will continue to increase in a rapidly changing world.
The 2020 Energy Transition Outlook estimates that fossil fuels will account for 74% of world energy-related CO2 emissions in the mid-century and more than 80% of combined emissions of CO2 and methane (measured as CO2 equivalents). While global energy-related emissions will be roughly halved between 2018 and 2050, emissions from the entire oil and gas value chain will fall by a third.
The Outlook sets out DNV GL’s modeling of a single likely future of the world’s energy system through to mid-century. It forecasts that industry trends will play out against the backdrop of the energy transition being too slow to achieve Paris Agreement targets to limit global warming. The implication is that governments, regulators, investors and society will make increasing demands on the industry to decarbonize its value chain.
Focus on upstream emissions
Outlook modeling suggests 75% of the industry’s emissions come from the combustion of oil and gas, three times as much as from production and distribution (Figure 1).
Scope 3 emissions across the value chain, including from end use, are far more than Scope 1 direct emissions from company-owned or controlled operations and greater than Scope 2 indirect emissions such as those from purchased electricity, steam, heating and cooling.
With 4% of carbon emissions coming from upstream and more focus on decarbonizing production, several large oil and gas companies are targeting carbon-neutral E&P by 2050 or sooner. Several emissions reduction efforts are already underway through varying applications.
Electrification of oil and gas platforms
Instead of using wellhead gas and diesel to fuel onboard generators, gas compressors and pumps, there is a growing trend to cut emissions by electrifying offshore operations.
China’s CNOOC is planning to bring power from an onshore grid to two fixed, high-voltage AC power platforms in the country’s first platform electrification. In the United Arab Emirates, ADNOC’s offshore production facilities will connect to Abu Dhabi Power Corp.’s onshore electricity grid via the region’s first high-voltage direct current subsea transmission system.
By 2023, 16 Norwegian Continental Shelf (NCS) installations will receive power from shore, according to the Norwegian Petroleum Directorate. The directorate estimates this will avoid emissions equivalent to a quarter of those from Norway’s oil and gas sector in 2019. The U.K. Continental Shelf (UKCS) operators, including bp, are also considering using renewable power via subsea cables.
Integration with renewables assets
Operators have started to integrate renewable power sources—solar photovoltaic (PV), wave energy and wind power—alongside onshore and offshore oil and gas production. For instance, Italian operator Eni and the Algerian NOC Sonatrach supply power for gas treatment in Block 403 fields in the Sahara Desert from their joint venture 10-MW solar PV plant at Bir Rebaa North. They may expand solar to other Algerian sites.
Likewise, Eni and Politecnico di Torino are progressing toward making a 100-kW peak power version of their Inertial Sea Wave Energy Converter available for industrial uses including medium-to-large offshore platforms.
The Outlook forecasts rapidly increasing offshore wind capacity (Figure 2) and that cheaper associated costs will open up greater use of wind power by oil and gas installations.
Equinor is to develop Tampen Hywind on the NCS as the first floating wind farm to power offshore oil and gas platforms. U.K. regulator the Oil and Gas Authority has called on the UKCS oil and gas industry to source electricity directly from offshore renewables for business benefits as well as to reduce emissions.
Reducing methane emissions
Other common targets for lowering emissions from production offshore and onshore include:
- Reducing incomplete flaring of waste gas from oil and gas processing;
- Stemming fugitive (unintended) leaks of methane along the value chain;
- Alleviating the need for intentional venting (for safety or technical reasons) of methane at points such as compressors, pumps and valves; and
- Making greater efforts to detect and stop methane.
Some operators already see flare/vent volumes as a key performance measure in day-to-day operations.
The International Energy Agency (IEA) 2020 Methane Tracker estimates the oil and gas industry methane emissions were equivalent to more than 81 MMtonnes of CO2 in 2019: 4% from incomplete flaring, 28% from fugitive releases and 68% from venting.
The U.S. shale gas boom has seen emissions from flaring quadruple in a decade, as lack of gathering infrastructure and pipeline capacity in some shale areas make it cheaper to vent or flare cheap natural gas than to transport it to buyers.
The IEA estimates that some 75% of emissions from flaring could be avoided and 40% overall could be prevented at no net cost if captured gas was commercialized.
By more accurately predicting problems, and enabling more timely interventions, the receiving and automated analysis of data from digital sensors and other sources in oil and gas field operations can reduce the chance of unintended releases of emissions.
Greater collaboration and urgency required
Partnerships will therefore be crucial in scaling up innovation and new technologies for decarbonization. Recent activity includes:
- bp, EDF, Eni, Equinor, Shell, Total and Wintershall Dea have collectively made policy recommendations to the EU to standardize methane emissions data collection;
- More than 20 leading oil and gas companies are committed to the Methane Guiding Principles partnership pledged to reduce methane emissions; and
- The Oil and Gas Climate Initiative, the International Association of Oil & Gas Producers, and IPIECA are collaborating toward developing a best practice guideline on detecting, monitoring and reporting such emissions.
Industry leaders are also discussing best practices for electrification and energy efficiency management and identifying supply chain emissions reductions. Some operators are also considering whether to adopt a common set of key performance indicators for reporting progress on emissions.
To develop technology to reduce upstream emissions, companies should seriously consider supporting collaborative joint industry projects (JIPs) and projects in research centers as well as their own R&D efforts. Recommended Practice DNVGL-RP-F302 Offshore leak detection is one example of a DNV GL-led JIP collaboration with 19 companies involved.
Currently, carbon emissions per barrel produced is commonly used to gauge the carbon intensity of production. By 2050, DNV GL expects the industry will be broadly measured by life-cycle emissions per barrel of oil or gas consumed. Drivers for this shift in reporting emissions will include national net-zero targets and other relevant policies as well as external pressure from investors, other industries and society.
The quicker that governments incentivize the industry to adopt technology, such as through a competitive carbon price, the earlier the industry will take the technology (e.g., carbon capture and storage [CCS] and hydrogen) down the cost-learning curve.
Ultimately, it is anticipated that from the mid-2030s, these policies could transform the oil and gas industry into the decarbonizer of hydrocarbons and supplier of CCS. However, this transition will be too slow to meet Paris Agreement targets.
References available upon request.
About the author: Liv A. Hovem is CEO of DNV GL – Oil & Gas.
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