UK upstream eyes rescue package [NGW Magazine]
UK's offshore oil and gas industry has committed to halving its greenhouse gas (GHG) emissions by 2030 and reaching net-zero emissions by 2050. This makes it one of the first industry sectors to set out a timetable, it said in a report published June 16, as it announced talks had begun with government on a sector deal.
The upstream regulator Oil & Gas Authority has also laid emphasis on the net-zero objective and said that unless something were done, the offshore could lose its social licence to operate. It has however welcomed the targets and said it would incorporate them into its data benchmarking.
OGUK published Roadmap 2035, its plan for the offshore energy transition, last September, but since then the Covid-19 pandemic has struck, cutting oil and gas prices to historic lows and so risking tens of thousands of jobs and long-term upstream investment.
However, the UK independent organisation, the Committee for Climate Change, thinks that by 2050, the UK will still need 400mn barrels oil equivalent/yr. OGUK says half of that could be met by its own oil and gas reserves. So there is much to play for: the offshore industry supports 270,000 jobs, brings in £10.6 ($13)bn of supply-chain exports and £1.2bn in production taxes alone, while also playing a key role in UK energy security.
The offshore’s GHG emissions in 2018 – the most recent year for which there are data -- were 18mn metric tons CO2 equivalent (mn mtCO2)/yr – just 4% of the UK total.
A limited amount of that initial 50% will come from operational improvements early on: the low hanging fruit. This includes replacing valves, re-sizing pumps or reducing spinning reserve on power generation turbines, it said. Another 40% are to go by 2040.
Achieving the whole 100% – the only allowed emissions will be flaring for safety reasons – will require a range of options including carbon offsets and be very capital-intensive, according to OGUK’s report, Pathway to a Net-Zero Basin: Production Emissions Targets.
OGUK CEO Deirdre Michie said that a “transformational sector deal could enable the industry to support a green recovery…. With support from governments and regulators, we can protect domestic energy supplies, jobs and communities whilst embracing the opportunities which will come from being at the forefront of delivering a low carbon economy."
Welcoming the report, UK energy minister Kwasi Kwarteng said he supported a sector that has "a vital role to play in our energy transition in the years to come. The UK government will continue to work tirelessly with all partners to deliver a dynamic sector deal." He did not give any specific commitments as to how the government would support it, and some in the industry see it as only words at the moment.
His Scottish counterpart Paul Wheelhouse said the initiative was timely as it follows the Scottish government’s announcement June 12 announcement of £62mn to support the energy transition. Aberdeen is the logistics capital of the UK oil and gas offshore sector.
Nearly all the GHGs – 91% are CO2 and 8% are methane – come from offshore installations; 15% come from onshore terminals; and 5% from logistics, such as support vessels and helicopter flights. Across the sector, 70% are from power or heat generation, gas compression and so on while 29% were from flares and vents. Achieving these reductions will be supported by improvements in the measurement and monitoring of emissions.
Report author Louise O'Hara Murray said that many of the major capital investment projects needed for decarbonisation, such as offshore wind and carbon capture, use and storage (CCUS) will need to be developed at scale to help other industries accelerate their own efforts to reduce emissions. It will take time to develop a regulatory framework for CCS, and offshore wind might need a separate contractual system for a generation and transmission network to power the platforms.
OGUK told NGW said there would be no trade-off with the other primary objective of maximising the economic recovery of the remaining reserves, despite the extra costs likely to be involved in electrification, for example. This added burden might be expected to push some marginal projects beyond commercial sense (see box, Premier Oil). However the target is not for each asset but the basin as a whole.
OGUK said that a large portion of the decarbonisation effort – at least half and possibly two thirds – will probably come from the decommissioning of existing and old platforms later this decade. However, it said it was difficult to be precise as timings will be influenced by factors such as commodity prices.
Flaring and venting are significant sources of methane emissions for the sector. OGUK is developing a detailed Methane Action Plan for release later in 2020, to promote continuous reduction in methane emissions supported by improvements in quantification.
The report considers likely the development of offshore hubs where a number of interconnected offshore platforms share a centralised renewable power supply. They might produce hydrocarbons or hydrogen and/or storing CO2 in offshore reservoirs and lay the foundations for large scale emissions capture for the wider UK economy.
Step-change actions to reduce emissions could include more use of electrical power, re-sizing to reduce the number of compressor trains and consolidation of processing to increase efficiency by maximising throughput.
Alternative approaches to process heat generation include harnessing waste heat from other processes such as hydrogen production and alternative fuels such as ammonia or hydrogen.
Premier Oil’s two-pronged strategy
NGW also spoke to Robin Allan, director of Premier Oil’s UK and international upstream businesses and chairman of Brindex, an association of British independent oil companies.
“At just 4%, the upstream share of the total UK GHG emissions is very small and there is a question of proportionality and costs jeopardising marginal fields. However every little bit helps and our unmanned Tolmount gas field platform, at full production, will emit just 1,500 metric tons/yr of CO2. That is the equivalent to the emissions of 1,500 mt of cement. Shell's Shearwater platform emits 360,000 mt/yr CO2.
“Premier is pursuing two low carbon themes in the UK upstream: to make projects low carbon by design, we use the best available technology, the cleanest equipment we can -- such as micro gas-turbines -- at each stage of the design process; we are also extraordinarily vigilant in reducing and removing all of our emissions, wherever possible.
“To the extent we cannot reduce an emission, we will offset that carbon footprint principally by investing in forestry projects. In the case of Tolmount off the coast of Yorkshire, we have designed it to be extremely low carbon and invested in making the platform normally unmanned so there will be no regular carbon emitting helicopter or boat journeys from shore. This is not something new for Premier, however: our Catcher oilfield floating production, storage and offtake vessel was also designed to have a minimal carbon footprint.
“Owing to Covid 19 halting work on construction yards in Italy, we have pushed back first gas from Tolmount from late December to next April. Work on the jacket and topsides in the Ravenna yard has now restarted.
“Tolmount gas is landed at Easington, where in the future it could become part of a decarbonised industrial hub, generating power and hydrogen with the exhaust gases and CO2 being returned to depleted offshore gas fields for permanent sequestration.
“In considering carbon capture and storage, Britain needs a long-term stable regulatory framework to attract companies to invest in CCS. The upstream industry has the expertise needed for all the separate parts of this but it needs government support. At this moment in time, with Covid-19 to deal with, it is not clear that the government has the necessary horsepower to drive these things through, and the successive UK governments have a poor track record of commitment to CCS projects.”
Deltic Energy talks up low-carbon gas
Deltic Energy’s COO Andrew Nunn talked to NGW about the UK CS and the growing importance of gas for what was formerly Cluff Natural Resources.
“The OGUK’s Roadmap 2035 project, which feeds into the UK’s Net Zero 2050 target, is a subject of significant concern and debate within the industry but we feel that it does depend on where you are as a company in the development cycle. If you have a portfolio of midlife or older assets then it may be much harder to physically and commercially meet those targets.
“But if you are looking to design and operate a new offshore installation which incorporates best in class gas turbine technologies and efficiency controls, or alternatively electrification, which in turn reduce the tonnage of platforms and the energy used to run them, then you can potentially get your emissions down to a level where it becomes commercially viable to offset the unavoidable emissions through various schemes such as forestry (planting or preservation) or carbon capture and storage.
“The noises we are hearing from Premier with respect to the Tolmount gas field development in the southern North Sea, which we understand is being designed to be a ‘net zero’ development from the outset, are very encouraging and could prove to be a watershed moment for the industry (see box, Premier Oil).
“Which approach to the challenge is taken on our Pensacola and Selene prospects will be for the operator, the Anglo-Dutch major Shell, to decide; but that company is taking a strong lead within the industry on the 'net zero' agenda.”
OGA: a force for good
“We see the introduction of the OGA as a positive step forward and we feel that its thinking is generally more aligned with the processes that are going on within the larger operating companies working in the basin. That said, there does seem to be less of a focus on the issues that affect some of the smaller exploration focussed companies that also operate in the North Sea.
“However, the introduction of the Innovate licensing regime has been a key benefit for smaller companies like ourselves, which combined with the OGA taking a much stricter line on the bidding of contingent wells in licence applications, has really levelled the playing field when competing for licences in the bidding rounds. It really does let smaller, nimble companies with good ideas and new approaches compete for high quality acreage rather than being marginalised under the previous two tiered Traditional and Promote licensing regime.
“We still question some of the initiatives undertaken by the OGA and wonder if the industry got value out of the OGA acquired seismic over the mid-North Sea high and other ‘frontier’ areas of the UKCS. While the data collected is interesting from a purely geological knowledge standpoint I’m not sure it has opened up any significant new exploration opportunities yet or benefited our understanding of the more prospective areas which are the focus of most exploration investment.
“In their defence through I think there were a number of issues with the EU definition of ‘state aid’ which did impact on the OGA’s ability to direct this investment to the areas they may have ultimately wanted to.”
Assets and activity
“We like the southern North Sea (SNS) gas basin because it has prospectivity at multiple geological intervals from the Carboniferous, the traditional Leman and Bunter Sandstone play and the emerging Zechstein reef play.
“There has been a number of significant discoveries and field developments in the SNS in recent years including Breagh (Carboniferous), Cygnus (Leman), Tolmount (Leman) and more recently the Pegasus (Carboniferous) and Darach (Zechstein) discoveries. Although there is a lack of data and some of the reservoirs are variable, we feel that the northern fringes of the basin have been significantly under-explored and that there are a number of large discoveries to be made.
“We’ve demonstrated our ability to identify new prospects and this resulted in us farming out two licences to Shell in the first half of 2019. These licences contained the Selene prospect in the Rotleigendes in the more mature part of the basin and the Pensacola prospect which is a Zechstein reef in the northern part of the basin.
“We see the Zechstein reef play as a big opportunity for the basin following recent discoveries including the West Newton field onshore Yorkshire and the Darach Central discovery which was drilled by ONE Dyas in 2019 and flowed oil at a rate of 3,500 barrels/day which was extremely positive for the play.
“Despite the Darach results, Pensacola is still seen as a gas opportunity given that it is close to Breagh and hydrocarbons are to have likely been sourced from the same area. Shell acquired new 3D seismic over the Pensacola prospect in August 2019 and the processing of that data is coming to an end. While there is still some further subsurface work to complete, we are planning for an exploration well, which will be operated by Shell, on the Pensacola prospect in the latter half of 2021. Pensacola gas use infrastructure at the producing Breagh field or go directly to Teesside.
“The second opportunity that Shell farmed into was the Selene prospect in the established Leman Sandstone play fairway. It was hoped that a well could have been drilled on this prospect later this year or early 2021 but with low gas prices and the Covid-19 crisis, this has been pushed back to 2022. The Selene prospect is north of Shell infrastructure at Barque and Clipper and would use this infrastructure to the Bacton gas terminal in Norfolk.
“Reprocessed legacy 2D seismic data over the Cupertino area has identified potential Zechstein reefs which look analogous to the Pensacola prospect. We also see potential upside in the Rotliegendes and the deeper Carboniferous reservoirs and work is ongoing to try to mature these prospects.”
Gas price and impact on operations
“The short-term softness in gas price is of concern from a sentiment and investment view point but we do expect gas prices to recover going forward given the focus on hydrogen as the key part of the transition to a net zero future.
“We feel that natural gas is likely to be the key feedstock for hydrogen production and demand for natural gas will naturally increase as the hydrogen economy matures. Locally sourced natural gas is significant as well because it has half the climate change related emissions when compared to imported LNG which is critical for the ‘net zero’ 2050 plan.
“While we see increased volatility, we also see increased gas pricing and believe that most new SNS developments should be attractive at gas prices from about 30p/therm. History has also shown us that the industry and the basin has been able to respond and adapt to different pricing environments over time. Assuming exploration success, our own prospects are unlikely to be producing within the next three to four years and we could see quite a different pricing environment at that time.”
“Deltic Energy, originally floated on AIM as Cluff Natural Resources, in 2012, was envisaged as a generalist natural resources investing company and looked at a number of projects including offshore underground coal gasification.
“But when this was side-lined by the same issues that stymied the onshore coalbed methane and shale gas industries in the UK it re-focussed on conventional gas and won licences in the southern North Sea in the 28th Offshore licensing round. It also hopes to pick up licences this summer in the 30th round.
“Deltic has a strong institutional shareholder base with Michael Spencer, whose investing vehicle IPGL is the largest shareholder. Significant institutional shareholders include Cannacord, Janus Henderson and Lombard Odier and others attracted by the £15mn equity raise following the farm-ins to the Pensacola and Serene prospects by Anglo-Dutch major Shell. The addition of this capital to the balance sheet means we are well capitalised and are fully funded for our operations, including drilling, well into 2022.”