Could underwater carbon storage clean up UK oil and gas?
A new report from Oil and Gas UK has highlighted the potential for underwater carbon storage, with the industry body confident that the country could stash away up to 100 million tonnes of carbon dioxide, offsetting a considerable volume of the sector’s emissions. Scarlett Evans asks if the technology could be our answer to a cleaner oil and gas industry.
Carbon capture and storage (CCS) is a technology long considered a potential Hail Mary solution to carbon emissions, originally perceived as a means of maintaining the fossil fuel industry while preventing emissions from leaching into the air. However, genuine efforts to develop the technology never took off and the possibility was side-lined. Now, the purpose of this technology has changed to be a solution separate from the fossil fuel sector, and one that could genuinely help nations curb emissions.
The rise in public as well as private investment also means that scaling up this solution is more viable now than ever before, with the UK Government announcing in November last year that it would be funding four CCS cluster projects over the course of the next 10 years.
The stage is seemingly set for the UK’s CCS industry to finally realise its potential. But what’s been standing in the way of this technology taking off? And could these challenges arise once more? We find out.
The potential of CCS
According to the ‘Energy Transition Outlook’, produced by Oil and Gas UK (OGUK), rock formations under the North and east Irish Sea have the capacity to hold 78 billion tonnes of carbon dioxide, a figure roughly 190 times greater than the UK’s annual emissions. Not only would tapping into this resource help to curb oil and gas emissions, but it would offer a means of decarbonising other heavy industries such as cement and steel makers, chemical manufacturers, and power stations.
Such potential has led the industry body to identify it as a key technology in transitioning to a net-zero economy, and the report follows hot on the heels of the government’s latest Net Zero Strategy, which says that CCS, linked with mass production of low-carbon hydrogen, will be essential.
However, Will Webster, energy policy manager at OGUK, says that the technology has some way to go before it can begin to meet its potential, and investment into projects is crucial if this is to change.
"We don't really have any CCS in the UK at the moment, apart from some very small pilot projects. And we've got to get from that situation, to one where we're capturing 20-30 million tonnes of carbon dioxide per annum, which is the new government target for 2030,” he says. “Then we have to reach 100 million tonnes by 2050, which would represent a quarter of the UK’s carbon dioxide emissions.”
Until other storage technologies are streamlined (such as nuclear fusion or battery storage), such carbon-cutting methods would, Webster says, be the fundamental means of maintaining lower emissions. While a lack of funding would previously have made this unlikely, a shift in government attitudes towards the sector is driving a change.
“Previous efforts to do CCS in the UK never got off the ground, and one of the reasons for that is it was seen as a purely private investment thing, and that’s a mindset that’s completely changed,” Webster says.
“We've now got a concept from the government that this is a national effort, and one that needs a bespoke framework to develop it. The idea is that the government gives a regulatory framework for the pipelines and storage, and will support private industry to develop those through kind of regulated charges.”
Even with government funding secured, the path to full scale CCS is not, of course, entirely smooth, and managing environmental concerns need to be considered before we can expect the change to be fully enacted.
The environmental question
Professor Stuart Haszeldine OBE, from the University of Edinburgh’s Scottish Carbon Capture and Storage Department, says that the UK has not yet managed “joined-up thinking” on how to manage offshore hydrocarbons.
“The International Energy Agency has made it very clear that no new hydrocarbon fields or coal mines should be developed, if the world is to remain within climate guardrails of 1.5°C, or even 2°C average warming,” he says. “The UK Oil and Gas Authority has been placed in an impossible position, with a mandate to produce maximum economic recovery of all oil and gas UK offshore, whilst simultaneously placing a climate review on any new developments.”
One solution that Haszeldine proposes is to implement a system of “producer responsibility”, where companies are held accountable for the impact of their products – from sourcing to consumption. Webster similarly says that environmental frameworks will need to be put in place to keep fears of misuse at bay.
“One of the things that's going to have to happen is there will need to be environmental monitoring of carbon dioxide pipelines and carbon dioxide stores,” he says. “You'll have to have remote monitoring, you have to have your IP verified, and then if you have an issue like a leak, you're going to have to have some kind of process for how industries will have to pay for their emissions.”
Smoothing out such issues would, however, be the case for any nascent technology, and general perception seems to err towards thinking the benefits outweigh the problems.
An economic incentive
From an economic perspective, while the investment needed is high, the payoff would be significant, and establishing a CCS industry could also provide a steady stream of job opportunities.
“Costs of capture vary by facility, with pure carbon dioxide streams costing £20-£50 ($26.72-$66.79) per tonne, power plants £80 ($106.87), with transport and storage £5-£20 ($6.68-$26.72) per tonne,” says Haszeldine. “Economic models simulate this to be much cheaper than International Energy Agency modelling projections of carbon taxes of several hundreds, rising to several thousands of pounds per tonne, and much more reliable than the present system of allowing carbon dioxide emissions to continue by purchase of emissions trading scheme certificates.”
When it comes to employment, many offshore specialists would be needed to develop underwater CCS, and there would be significant crossover. Not only does this mean much of the workforce is already in place, but the technology required to scale up is already known.
“You’ve got all of the subsurface skills,” says Webster. “Often for storage, they’ll be using depleted gas fields or saline aquifers; so there we can harness all of the expertise around geophysics and seismic data, making sure that the potential storage locations are secure and will keep the carbon dioxide there indefinitely. You’ve also got pipeline management and carbon dioxide handling – all things that the sector would be pretty familiar with.”
At a glance, it would seem that there’s nothing standing in the way of seeing CCS becoming a central part of the UK’s energy mix in the near future – with the skillset, workforce, and economic incentive already in hand. However, the road to industrial scaleup is long, and government support is needed to maintain momentum.
As Mike Tholen, OGUK’s sustainability director, writes in a statement: “This is a project that will take some years, but it is also one that will help secure our nation's low-carbon future.”
Main image: SARAWAK, MALAYSIA - Survey engineer on offshore platform during underwater inspection activity. Credit: deela dee / Shutterstock.com
US and the Gulf of Mexico
The number of active drilling rigs in the lower 48 states of the US, excluding the Gulf of Mexico, stood at 753 in February. This fell to 738 in March, before reaching a four-year low of 572 in April, the lowest since May 2016. As of 8 May 2020, the Lower 48 land rig count reached 355 rigs, according to Baker Hughes’ data.
When it comes to the sought-after oil and gas fields in the Gulf of Mexico, production is estimated to remain relatively flat. The US Energy Information Administration (EIA) forecasts an average of 1.9 million bpd over 2020 and 2021, almost unchanged from its 2019 average.
The administration said that it does not expect any cancellations to Gulf of Mexico projects announced in 2020 and 2021.
Before the oil price crisis in the first half of 2020, Shell had awarded a contract to Sembcorp Marine for construction of the topsides and hull of a floating production unit for the Whale exploration project in the US Gulf of Mexico. Later this year, uncertain economic conditions forced Shell to postpone the project to 2021.
Regarding crude oil production in Alaska, the EIA predicted that it would remain relatively stable, at an average of 460,000 b/d in 2020, and that it will slightly rise in 2021.
Oil companies operating in Norway, Western Europe’s largest petroleum producer, drilled just 30 exploration wells off the coast of Norway by the end of 2020. This marked the lowest level in 14 years, as announced by the Norwegian Petroleum Directorate (NPD) in October.
The search for new oil and gas reserves has also decreased from 57 drilled wells in 2019 and falls behind previous projections of about 50 wells.
The NPD said in a statement: "The decline in demand for oil and lower prices have led oil companies to reduce their exploration budgets for the year and postpone a number of exploration wells.”
Companies including Equinor, Aker BP, and Lundin Energy announced considerable cost cuts in the early phases of the Covid-19 crisis, attempting to preserve capital and weather the storm.
In response, NPD director of exploration Torgeir Stordal expressed concerns over the near future of the industry: "Without new discoveries, oil and gas production could decline rapidly after 2030."
In the meantime, Norway still believes that there are significant resources to be found beneath its seabed, which are projected at around 3.9 billion cubic meters (bcm), a slight decrease from 4 bcm two years ago, the NPD said.
The Brazilian oil and gas industry has been deeply influenced by the unusual events of 2020.
In November 2019, Petrobras announced its 2020–24 investment plan, with a new budget of approximately $75.7bn (84.94% allocated to exploration and production). Despite the challenges, the company has not reported massive obstacles.
It also continued with its divestment programme of some upstream, midstream, and downstream assets, opening new opportunities for foreign investment.
During the Covid-19 outbreak, Petrobras and other oil companies shifted focus from their own projects onto divesting in ancillary projects, which helped reduce their expenses while generating income for the sale of such non-core assets.
November’s bidding rounds by the National Agency of Petroleum, Natural Gas and Biofuels (ANP), showed that the usual interest in Brazil’s offshore upstream rounds has plunged, which led to the suspension of the Brazil Round 17 for exploratory blocks under the concession regime.
Despite the hardships, the ANP managed to keep the First Cycle of the permanent offer, which involves a continuous offer of fields returned and exploratory blocks offered in previous tenders that were not acquired or returned to the agency.
The UK Continental Shelf
British consultancy Westwood Global estimated in September 2020 that the UK Continental Shelf (UKCS) was on course to reach a record low of offshore exploration wells this year, its lowest since companies started exploring the North Sea for oil in the 1960s.
In May 2020, along with the publication of its annual review of global exploration activity and outlook for 2020 and beyond, the consultancy said that while dealing with the immediate Covid-19 crisis, “societal pressure is building for a rapid transition to a low-carbon future”.
In September, Alyson Harding, technical manager at Westwood, said in Energy Voice that the company predicts only five exploration wells will be drilled in 2020, one less than in 2018. By comparison, 14 exploration wells were drilled last year with only one becoming commercial.
According to Westwood’s early estimations from February, the UKCS was predicted to reach 17 wells by the end of the year, but the pandemic hampered these plans. So far, Chrysaor’s and Apache’s Solar well and Total’s Isabella well are commercially viable.
While the Oil and Gas Authority offered 113 licence areas over 259 blocks or part-blocks to 65 companies in early September, it is not certain that operations will take advantage of this opportunity because of current market instability.
Looking ahead, Harding said in a company webinar that the firm has been given indications from companies that 23 exploration and 10 appraisals wells could be drilled in the UKCS next year, depending on the impact of Covid-19 in 2021.
Mozambique’s untapped oil and gas potential was first revealed by initial exploratory drilling in 2007.
Later, natural gas became part of Mozambique’s oil and gas strategy to help industrialise the northern provinces of the country. However, after some recent project cancellations, Mozambique’s Council of Ministers is now planning to transport the north’s oil and gas to the better developed south.
In a tender process run in 2017, Shell was given the right to build a gas-to-liquids plant that would convert gas to synthetic diesel, naphtha, and kerosene; Norwegian chemical company Yara International was allowed to build a fertiliser plant to power the northern town of Palma using domestic market gas; and Kenyan power company Great Lakes Africa Energy was allocated gas to build a 250MW power plant in the north-eastern city of Nacala.
However, whether influenced by the Covid-19 crisis or rising environmental scrutiny in the country, it appears that only the Nacala power plant will take place. Yara has cancelled its fertiliser project and Shell’s CEO has been giving indications that the company does not expect to develop any new greenfield gas-to-liquids projects.