The energy transition march toward net zero moves to different beats all around the world. With much of the initial focus on industry and what it can do to help curb CO2 emissions, attention soon turns to the worst offenders.
According to the US Environmental Protection Agency in 2020, one quarter of all CO2 emissions came from electricity generation. Approximately 60% of our electricity comes from burning fossil fuels, mostly coal and natural gas. Coming in second, at 24%, was industry. Greenhouse-gas (GHG) emissions from industry primarily come from burning fossil fuels for energy, as well as GHG emissions from certain chemical reactions necessary to produce goods from raw materials.
While these numbers pertain to the US, they ring mostly true around the globe where across the Atlantic Ocean some oil and gas companies are facing the challenge on both fronts by working to eliminate gas-fired turbines that generate electricity offshore. No country has done more with offshore electrification to date than Norway.
Oil and gas extraction on the Norwegian Continental Shelf (NCS) accounts for 27% of the country’s total CO2 emissions. Norway’s top producer Equinor has been on the forefront of offshore electrification for almost 3 decades. Electrification requires an efficient solution to convert electric power transmitted to an offshore field into mechanical motion to operate components. Size, weight, efficiency, cost, and equipment availability play key factors in determining the outcome. Historically, the solution has been the use of shore power but today, innovative approaches can be implemented using renewable sources.
“The Norwegian Climate Action Plan for 2021 to 2030 came one-and-a-half year ago, where the previous government, then with actually strong support from most politicians, said that the CO2 tax shall rise to NOK 2,000 ($200) per tonne within 2030,” explained Simen Moxnes, senior advisor, new energy systems, Climate Initiative Norway for Equinor. “CO2 tax is a quite strong signal because then abatement projects that earlier had negative net present value suddenly get profitable since we don’t have to pay that tax if we can avoid emissions. Then we got the new government one year ago and, in their platform, they said that the target of 40% for oil and gas industry shall be increased to 50%. We have a quite large toolbox to obtain this. Operational measures that need energy efficiency is the go-to solution first. The best energy is the energy we don’t use.”
Moxnes added, “We also have several other technologies developed like carbon capture and storage on brownfield platforms. These have proved to be very difficult to implement due to weight and space limitations. Weight and space on platforms are a scarce quality resource. Even these compact plants are quite weight intensive. In addition, you must install big equipment close to exhaust channels to catch the flue gas, and a lot of the brownfield projects have really struggled with that. For greenfield it’s much simpler.”
In 1996, Troll A became the first platform on the NCS to utilize power from shore. Later, a 100-km-long cable from Mongstad out to the Gjøa field resulted in the first floating production system in the North Sea to be powered from shore. When Martin Linge was brought on line in 2021, it received shore power from the world’s longest alternating current cable—163 km. The electrification of Johan Sverdrup created one of the most carbon-efficient oil and gas field operations in the world (Fig. 1). The field has CO2 emissions of just 0.67 kg/bbl, compared with an average of some 9 kg/bbl on the NCS and 15 kg/bbl globally. Additionally, the shore power being used by these facilities is made up from mostly renewable sources—92% hydropower as of 2020.
Norway currently has seven fields that are fully or partially electrified from shore: Troll, Ormen Lange, Johan Sverdrup, Martin Linge, Valhall, Goliat, and Gjøa. Combined, these hubs account for nearly 40% of Norway’s 2022 production, but only 10% of the region’s CO2 emissions, with an average emissions intensity of 1.7 kgCO2/BOE, according to a study by Westwood Global Energy, and Equinor has more electrification projects in the queue.
“Hywind Tampen is offshore wind tied into Gullfaks and Snorre,” said Stuart Leitch, senior analyst for carbon and emissions at Westwood Global Energy Group. “That’s just starting up now. Equinor has Utsira High Phase 2, which is five platforms being electrified as part of the same project. Then they’ve recently announced Trollvind, a study looking at additional offshore wind in the area to further electrify that region.”
In addition, there is work underway to supply power from shore to the Troll B and C platforms and to the Oseberg field. Equinor is also exploring the possibility of supplying the LNG plant in Hammerfest with power from the grid.
“It’s the gas turbines that are the main emission source responsible for 85% of our emissions, and we have on the Norwegian Continental Shelf in use today approximately 80 gas turbines emitting approximately 100,000 tons each,” said Moxnes. “The total emissions on the Norwegian Continental Shelf are approximately 8 mtpa from Equinor-operated assets, so that adds up. It’s these gas turbines that we must attack.”
Of course, there is a level of legislated motivation behind Norway’s move to electrify—the country has its own carbon tax as well as the EU ETS (Emission Trading Scheme), or cap‑and‑trade program. Another motivator was simply an easy path to approvals as generally these assets have fewer stakeholders than others across the globe.
By 2025, Westwood forecasts that a further seven hubs will be electrified. The Utsira High Phase 2 project is due on line by 2023. The initial proposal was to electrify Gina Krog, Ivar Aasen, and Edvard Grieg with power from shore, but an additional power cable from Gina Krog to Sleipner will now be installed which will also allow partial electrification of the Sleipner hub and indirectly Gudrun, with an existing power cable already being available between the two.
“As part of the Johan Sverdrup Phase Two that we are starting just now, we have installed another HVDC cable of 200 MW delivered offshore,” explained Moxnes. “Johan Sverdrup has a total power requirement of approximately 150 MW. That means that we have 150 MW available for the surrounding phase.”
The Hywind Tampen floating offshore wind farm will be used to partially electrify the Snorre and Gullfaks platforms by 2023, while Njord A and Draugen are also expected to be electrified by 2025 (Fig. 2).
As a result, Westwood forecasts more than 50% of Norway’s production in 2025 will come from fully or partially electrified platforms, bringing the country’s emissions intensity close to 6 kgCO2/BOE.
“The challenge with Troll B and Troll C is a little funny,” said Kamran Torki Sharifabadi, chief engineer at Equinor. “Troll B runs at 50 Hz, while Troll C runs at 60 Hz. So, we needed to find a solution. Running the power from land to Troll B wouldn’t have been a problem; we could supply it easily with the AC cable and some transformers, but how could we supply the Troll C?
“Equinor uses variable speed drives to power its big compressors. We can control the speed of the compressor and electro-motors there. If you use the largest type of the variable speed drive technologies, you can change the frequency of the 50 Hz to 60 Hz. So, we have the equipment installed on the Troll B and then, with the cable, we send 60 Hz to Troll C. Weight and space limitations wouldn’t let the variable speed drives be located onboard Troll C.”
New technology continues to emerge to meet the challenges of electrification. At the recent Offshore Northern Seas (ONS) conference in Norway, services giant Baker Hughes debuted its new fast, all-electric tieback solution designed to optimize existing architecture and reduce topside footprint while delivering environmental benefits for subsea operations.
The contractor touts that the all-electric tiebacks, when combined with its all-electric controls system and electrification solutions, can deliver more than 15% savings in spending vs. traditional electro-hydraulic multiplexed systems. The system can also reduce or eliminate the need for long umbilicals and topside power when linked with renewable power sources.
Baker Hughes expects the technology will be ready for commissioning in late 2023.
Neighbors to the South
The question remains if the push by Equinor to electrify its assets in the Norwegian North Sea will spur others in the region to look to do the same.
“The UK is a slightly different story in Norway,” said Leitch. “In Norway, because of the relatively young infrastructure and fields with long design lives out there, the economics of electrification start making sense. Whereas in the UK, there is quite a lot of aging infrastructure. If you do the economics on electrification on assets that might shut down in the short term, it doesn’t make commercial sense.”
For the future in the UK, Leitch sees a more collaborative effort toward electrification, looking at projects that include an element of offshore wind transmitting power into a centralized power hub, and ultimately several hubs that can then tie into that.
“You’re sharing the cost,” he said. “You’re sharing the infrastructure, because unlike Johan Sverdrup that just started up and is going to run for the next 25-plus years, they could afford to electrify and just think of themselves. In the UK, no one wants to take that hit on the cost.”
There is an expectation, however, that any new iron that finds its way into the North Sea may be future-proofed for a time when other new facilities could all share in a centralized electrification project. That could mean space considerations on the platform or pre-investment of equipment in anticipation of a future electrification opportunity.
One hurdle that must be cleared before offshore wind can be used to electrify facilities is an answer to its intermittency. The wind doesn’t always blow, even in the North Sea. Solutions to the problem include both power storage options and the option of simply relying on wind power for part of your power generation needs.
“The Snorre and Gullfaks platforms are only partially electrified by wind from Hywind Tampen because power is not available all of the time,” explained Leitch. “The concepts that are looking at these centralized power hubs will either have a connection to shore to ensure that power is available (when wind power is unavailable), or they will look at a microgrid concept whereby they will produce power in a more conventional way—burning gas— but because they are sharing that load across a lot of facilities, you can do it more efficiently than having each individual unit producing its own power.”
For short-term power support, battery storage technology is also being examined as a possible answer if the wind dies down or underperforms in meeting its expected generation load.
“For Hywind Tampen, what we are doing is having several floating wind turbines,” explained Sharifabadi. “At minimum, we can shut down one gas turbine on a platform and keep the others as a kind of spinning reserve going in case the wind speed goes down or the wind stops blowing, then we have the possibility to start up the reserve gas turbines there. We are looking at storage technologies, which will need to be large to be able to supply the load if the wind is not there for several days.”
The layout for Hywind Tampen as planned is for 11 wind turbines altogether. Six of them will be reserved for Snorre, while the remaining five will be hooked into Gullfaks. All of them are interconnected, so it is possible to redirect for the most-efficient use of the generated energy. The power can replace gas turbine generators. Gas turbine compressors cannot be replaced by this solution.
A public report in June 2022 dubbed Project Neos, sponsored by Danish green energy developer Orsted, oil and gas operator Neptune Energy, and energy solutions outfit Goal7, demonstrated the technical feasibility of electrification of an oil and gas installation using an offshore wind farm to provide electricity. However, it found the wind farm was not suitable in isolation, and there is a possibility to implement a more sophisticated hybrid model using existing backup power generation through energy-balanced technologies such as energy storage operated as an offshore microgrid. It is needed to provide stability, balancing during times of low and no wind, and aid transition between generation sources and modes of operation during low- and no-wind periods.
One company that is moving forward with a wind-aided electrification project in the UK North Sea is Ping Petroleum. The subsidiary of Malaysia’s Dagang NeXchange Berhad (DNeX) recently purchased the FPSO Sevan Hummingbird, renamed it Excalibur, and it planning to deploy it onto the Avalon field. The FPSO will be retrofitted with electrification capabilities at the Port of Nigg in Scotland. The facility will be supported by a dedicated floating offshore wind turbine that is purpose-built for Avalon’s requirement.
“The Excalibur can set the benchmark for a greener upstream operation with the deployment of a wind turbine technology that powers the entire production facility,” said Tan Sri Syed Zainal Abidin Syed Mohamed Tahir, group managing director of DNeX. “This is a significant milestone for the Avalon development and timely as we progressively move forward with the energy transition.”
Ping expects to make a final investment decision later this year.
What About the US Gulf or Brazil?
In the US, the deepwater Gulf of Mexico (GOM) represents some of the lowest emission numbers around. Operators report facility emissions to the EPA’s Greenhouse Gas Reporting Program: these emissions totaled approximately 4.5 million tonnes of carbon dioxide equivalent (CO2e) in 2019. This equates to 6.34 tonnes of CO2e per thousand barrels of oil equivalent (CO2e/KBOE)—a decrease in intensity of 8.3% from 2011 reported levels, according to analysts at Wood Mackenzie. Deepwater GOM ranks in the first quartile and is well below both the unweighted average of 41.6 tonnes of CO2e/KBOE and the median figure of 26.4 tonnes of CO2e/KBOE.
Based on this information, one could see why there is no rush to electrify operations in the deep Gulf. However, the Biden administration’s plan for expanding wind energy projects in the region could spur some localized or partial electrification projects.
By 2025, the US Interior Department plans to potentially hold up to five additional offshore lease sales and complete the review of at least 16 plans to construct and operate commercial, offshore wind energy facilities, which would represent more than 22 GW of clean energy.
In July, the Bureau of Ocean Energy Management said it would seek public input on a pair of new wind energy areas (WEA) in the Gulf. The first draft WEA is located approximately 24 nautical miles (nm) off the coast of Galveston, Texas. The area for review totals 546,645 acres. The second draft WEA is located approximately 56 nm off the coast of Lake Charles, Louisiana, and totals 188,023 acres.
Another aspect of moving from gas-powered generation vs. renewables or shore-powered electricity generation for offshore facilities is an export solution for the gas no longer being used for power. For markets with mature gas transportation infrastructure, like the US or UK, it isn’t as much of a problem as it would be for other places around the world that do not have the benefit of existing gas transportation assets. It could limit the potential for electrification in those regions.
In Brazil, Equinor has undertaken feasibility studies to see the boundaries of electrification of some of the deepwater assets there.
“The challenge in Brazil is that in the area where you would have installations, the grid infrastructure onshore isn’t strong enough,” explained Sharifabadi. “It’s a deficit area. It imposes serious challenges to public consumption. Serious investment would need to happen to move forward with offshore electrification projects there.”
Clean Power Tapped for Far East Fields
China has committed to carbon neutrality by 2060, and one of the projects that has stemmed from that goal is the lowering of emissions from oil and gas operations.
Paper OTC 31550 explored the transformation of a pair of Bohai Bay megafields operated by CNOOC from their current offshore power solution to one to be powered from shore. The coauthors review the strategy behind the decision as well as regulatory drivers behind the project.
Two complex offshore oil fields, QHD 32-6 and CDF 11-1, have been modified to transform their power solution from offshore generation to power from shore to reduce carbon emissions and improve offshore energy efficiency. The two fields comprise 25 production platforms, and two FPSOs with 21 crude-oil generators and nine gas turbine generators. The total peak power demand is about 200 MW. Both oil fields have established their own offshore microgrid by interlinking centralized offshore power generation platforms via 35-kV and 10-kV submarine cables (Fig. 3). The total capacity of QHD 32-6 oilfield power stations is 152.08 MW, while the total capacity of CFD 11-1 is 128 MW.
The two offshore power substations were joined by a pair of new onshore switch stations as part of the overall electrification project. Additionally, not all the gas-fired generators were removed from the project due to the lack of gas export pipelines to move it elsewhere.
China established a national carbon market and a carbon-emission trading system as active measures to control carbon emissions. The Bohai Bay electrification project was partially motivated by these regulatory regimes.
The paper found that the brownfield project is expected to reduce a total of about 2.52 million tons of CO2 and 0.067 million tons of NOx emissions, save 2.17 Bcm of fuel gas and 1.13 million tons of standard coals during its lifespan. In addition to the reduction in emissions, the project establishes new basic infrastructure of regional oilfield development, which can lower costs in surrounding discoveries. According to the paper, a new find in the QHD 32-6 area has already benefited from this project to the tune of about a 440-million-yuan ($65.1 million) reduction compared to the conventional self-generation scheme. Its construction period will also be shortened by up to 6 months due to materials and equipment no longer required.
For Further Reading
OTC 31550 Electrification Transformation from Offshore Power Grid to Power from Shore, a Case Study to Minimize Carbon Emissions for Two Extensive Offshore Oil Fields by Yiru Hu, Hao Zhang, and Yinfeng Qiu, CNOOC Research Institute.
