Energy giant Ineos has urged the Government to relax the “unworkable” regulations on tremors caused by fracking.
Current rules on the process for extracting shale gas, which involves pumping liquid at high pressure deep underground to fracture rocks and release gas, halt work when seismic activity above 0.5 local magnitude is detected.
Shale firm Cuadrilla, the only company to start fracking in the UK, has been forced to pause operations in Lancashire on a number of occasions when seismic activity above thresholds have occurred.
Ineos, which also hopes to frack for shale gas in the UK, said the 0.5 limit is thousands of times lower than levels set in the US and called for it to be raised.
The company’s chairman Sir Jim Ratcliffe said the typical limit in the US of 4.0 magnitude was one the American Environmental Protection Agency “feels is safe and will not lead to any damage to land, property or people”.
The 4.0 magnitude limit is 3,162 times higher than the 0.5 limit in the UK, and 177,827 times stronger in terms of energy release, he said.
Of the UK rules, he said: “The Government’s position is unworkable and unhelpful. They are playing politics with the future of the country.
“We have a non-existent energy strategy and are heading towards an energy crisis that will do long term and irreparable damage to the economy, and the Government needs to decide whether they are finally going to put the country first and develop a workable UK onshore gas industry.”
But ministers have already said they have “no intention of altering” the regulations on tremors caused by fracking.
A letter from Energy and Clean Growth Minister Claire Perry, obtained through a Freedom of Information request by Greenpeace’s investigative news team Unearthed, indicates the Government is standing firm on the issue.
Writing to Cuadrilla chief executive Francis Egan late last year after he called for an urgent review of the system, Ms Perry reiterated her backing for shale gas.
But she said the company had not flagged the issue as its hydraulic fracture plan was developed and reviewed with reference to the regulations.
Any shale developments must be safe and environmentally sound, she said, concluding: “The Government believes the current system is fit for purpose and has no intention of altering it.”
Dr Doug Parr, chief scientist for Greenpeace UK, said: “For years those worried about fracking have been assured that our safety regulations are far tougher than those in the US.
“Now that the industry is having trouble sticking to UK regulations, we’re assured US regulations are perfectly adequate and should be copied here. We do not feel reassured.”
French oil giant Total SA is working with advisers as it weighs an offer for Eneco Groep NV, joining a number of financial and industry bidders for the Dutch utility, including rival Royal Dutch Shell Plc, people familiar with the matter said.
The firm, which is owned by dozens of Dutch municipalities and is due to be auctioned this year, could fetch as much as 4 billion euros ($4.6 billion), said one of the people, who asked not to be identified because the deliberations are private. It joins companies including Engie SA, Enel SpA, Macquarie Group Ltd. and Mitsubishi Corp., which may also be interested in the asset, they said.
Total and Shell are working to sell energy directly to customers, using the power business as a hedge against a potential drop in gasoline and diesel demand as European governments promote electric cars and introduce more stringent rules on carbon emissions.
Representatives for Total, Eneco, Enel, Engie and Macquarie declined to comment. A representative for Mitsubishi didn’t have an immediate response when contacted outside of regular business hours.
Last month, Shell said it planned to team up with Dutch pension fund PGGM to bid for Eneco, following a 2017 deal that gave the oil major direct access to the U.K. retail market.
Deal activity for European utilities has surged in the past year on the back of large transactions such as China Three Gorges Corp.’s 9.1 billion-euro bid to take control of Portugal’s EDP-Energias de Portugal SA and German utility EON SE’s offer for Innogy SE. Last month, a plan by Danish utility Orsted A/S to sell power distribution assets worth almost $4 billion was scuppered after the country’s finance ministry said there was no political backing for the sale.
The Dutch government must be notified of any change in control at Eneco, giving legislators the power to block or amend the sale, Dutch Minister of Economic Affairs and Climate Policy Eric Wiebes wrote in letter to the lower house of parliament last month.
For Total, an acquisition of Eneco would boost its clean-power production and retail portfolio, following its purchase Belgian utility Lampiris SA in 2016 and French utility Direct Energie last year. Total has said it aims to have more than 6 million power and gas customers in France and 1 million in Belgium by 2022.
A leading steel firm has announced the award of a multimillion-pound contract to supply a pipeline for North Sea gas.
Liberty said its mills at Hartlepool will produce around 22 miles of heavy duty pipe that will lie 90 metres under the sea to help channel gas to the St Fergus onshore terminal in Aberdeenshire.
The company, part of the GFG Alliance, said the order was one of the biggest secured by the mill since it was acquired from Tata in 2017.
The number of workers at the site has increased from 120 to 200 in recent months.
Sanjeev Gupta, executive chairman of the GFG Alliance, said: “Hartlepool went through tough times, but we always had faith that, as part of Liberty, the skills and commitment of the management and workforce there would restore the plant’s fortunes, and this is now being borne out by their increasing success.
“It’s really encouraging to see a great British engineering company, with a long heritage, not only come back from such difficulty but prosper and go from strength to strength.”
The Glengorm gas condensate discovery announced last week could be the biggest in the UKCS since 2008. It will reignite interest in the high temperature, high pressure plays in the North Sea and heralds a mini renaissance in UK exploration.
The Chinese national oil company CNOOC (formerly Nexen CNOOC) with 50% equity and Joint Venture (JV) partners Total (25%) and Edison (25%) have announced the results of the 22/21c-13 Glengorm well in 28th Round licence P2215. The well encountered gas condensate in 37.6m of net pay, interpreted to be in Upper Jurassic aged turbidite reservoirs.
Total has reported recoverable resources of ‘close to 250 mmboe’, which would make this the largest discovery on the UKCS since the Culzean discovery in 2008 with resources of 250 mmboe. The only larger discoveries made in the last 20 years are the 1.1 billion-barrel Buzzard field in the North Sea discovered in 2001 and the 292 mmboe Rosebank discovery in 2004, West of Shetlands. So, this is a significant discovery for the UKCS. Note that neither CNOOC nor Edison has commented on discovered volumes.
The result is at the extreme upper end of pre-drill expectations and the geology in the discovery well must have delivered some pleasant surprises, but it is not clear yet what these were. Upper Jurassic turbidites are highly variable in terms of both thickness and quality across the Central North Sea.
Total did not specify whether 250 mmboe was a probable or possible estimate and Westwood is assuming the latter for now given the limited information. The JV will now appraise the structure which is likely to be compartmentalised like many HPHT fields in the Central Graben to confirm the potentially developable resources. There are follow up Upper Jurassic prospects mapped on the block to test.
Glengorm lies 24 km northwest of Elgin-Franklin and 44 km west of Culzean, so there could be long subsea tie-backs to either installation. Total holds 25% equity in Glengorm and operates both installations. The timing of a development could align with capacity availability at Culzean, due to start production this year, which Westwood estimate to come off plateau around 2023.
The other option would be a subsea tie-back to the BP-operated ETAP infrastructure, which lies 35 km NW of Glengorm. CNOOC may prefer a standalone development. If the discovery be confirmed as c. 250 mmboe following appraisal, this should be an economic option given current development costs.
2019 is the most significant year for high impact exploration in NW Europe in a decade. 27 high impact prospects are planned to be drilled, on par with central and south America. The total of over 60 wildcat wells planned in the region is double 2018 and the highest number since 2014. Glengorm shows that high impact discoveries are possible in the UK North Sea, and not just by drilling prospects deemed high impact pre-drill. The unexpected upside can happen.
Norway has built a reputation as one of the calmest and most predictable corners of the global oil industry, but lately it’s been full of surprises.
During the worst downturn in a generation, from 2014 to 2016, companies would regularly exceed official forecasts as oil production rose in defiance of falling prices. More recently, with crude surging back to multiyear highs, they’ve run into trouble.
The Norwegian Petroleum Directorate now expects output to fall to a 31-year low in 2019, with production expected to be almost 60 million barrels short of its previous forecast for this year and in 2018. That’s 80,000 barrels a day less than expected.
So what happened?
1. Maintenance Backlog
One of the most frequently cited reasons for oil production missing forecasts in the NPD’s monthly updates through 2018 was maintenance shutdowns. Back in 2016, when output surpassed forecasts by 6 percent, oil companies cut maintenance outages. They insisted back then that the reductions were due to efficiency gains and weren’t creating a backlog.
“Maybe they’ve stretched it too far in terms of avoiding maintenance,” said Simon Sjothun, an analyst at consulting firm Rystad Energy AS. “It works in the first couple of years,” but it’s a “very realistic hypothesis” that they’re now picking up the slack, he said.
2. Glitches and Delays
Technical challenges on platforms or under the seabed, and delayed output last year will also impact 2019, the NPD’s Director General Bente Nyland said in an interview.
Wintershall AG’s Maria is one example of a field that hasn’t performed as expected, while Equinor ASA’s Gina Krog, which also started up in 2017, is “probably on the list,” Nyland said.
The NPD declined to provide more details on individual fields before a broad resource update in February or March. Alv Bjorn Solheim, a vice president at Wintershall’s Norway unit, confirmed Maria had produced less than planned, but declined to say how much. Equinor declined to comment on Gina Krog.
Postponed startups include Equinor’s Oseberg Vestflanken, which came online in October last year instead of a planned startup in the second quarter. After taking over the Martin Linge project from Total SA, Equinor also pushed back startup to the beginning of 2020.
3. Hubris and Tiny Fields
Both authorities and companies might have been too optimistic in their assumptions about reserves and production rates for certain fields, said Nyland. She declined to mention any examples, but the NPD recently said that Spirit Energy Ltd had cut the oil-reserves estimate for its Oda field, due to start producing by March, by about 30 percent to 33 million barrels.
Pressured to improve profitability after crude prices fell in 2014, oil companies turned over every stone to cut costs and pick solutions that raised the resource count for their projects. That could have led some to take an excessively optimistic view on how many barrels they would be able to squeeze out, said Sjothun.
Oda is also a typical example of smaller developments, which make up an increasing part of the project pipeline in Norway as the North Sea becomes a more mature oil basin and exploration in the Arctic Barents Sea continues to disappoint. The trouble with small fields is that the operator often has less data about the reservoir under the seabed, because a project of a smaller size doesn’t warrant drilling numerous wells, Nyland said.
“Small fields are the most difficult to forecast,” she said. “On bigger fields you’ll have more wells before you make a final decision. On a small field, you think that one well might be OK, and all of a sudden it doesn’t deliver.”
A Brighter Future
To be sure, the abrupt slump in Norway’s oil production is temporary. The Nordic country will enjoy a spectacular bump in oil production in 2020 thanks to Equinor’s Johan Sverdrup field, which is scheduled to start production in November this year.
With as much as 3.2 billion barrels in oil reserves and production of as much as 440,000 barrels a day in its first phase, the giant North Sea field should in 2020 contribute to the biggest year-on-year increase in Norway’s output since the 1980s.
An “ambitious” oil and gas sector deal will be crucial to protect the north-east’s status as a global energy powerhouse, a new report said.
The Scottish Affairs Committee (SAC) said opportunities presented by a pact between the oil industry and the UK Government were “too significant to be overlooked”, and urged Westminster to agree a deal.
It believes a well-executed plan could help industry capitalise on its strengths and address several challenges, including climate change and declining North Sea production.
But SAC said the details had to be fleshed more out to show how the state would get a return on any additional investment.
SAC’s report — the culmination of a lengthy inquiry featuring six evidence sessions — was hailed by politicians and trade bodies as a glowing testament to the oil industry’s virtues and bright future.
But energy industry veteran and observer Dick Winchester argued that the case for a support package was “not yet completely proven”.
SAC said industry should stick with its strategy of maximising economic recovery from the North Sea, given that two-thirds of UK energy demand will be met by oil and gas until at least 2035.
Up to 20 billion barrels of oil and gas could yet be extracted from the UK Continental Shelf.
To ensure a sector deal would provide value for money, SAC called for a host of strategies, roadmaps and yardsticks to be drawn up, relating to decommissioning costs and knowledge sharing, exports, tax breaks, subsea and low carbon technology and skills transfers.
The oil and gas sector deal application — submitted last year by a group of industry bodies — predicts a total spend of £176 million “has the potential” to deliver £110 billion for the UK economy between now and 2035, with Scotland being one of the main beneficiaries.
The oil and gas industry currently supports 135,000 jobs in Scotland.
The bid calls for the creation of three new centres of excellence, focusing on transformational technology, underwater innovation and decommissioning.
But that wish list has already been partly fulfilled, even in the absence of a sector deal.
The £38m National Decommissioning Centre (NDC) was launched in Newburgh last month, with support coming from the Aberdeen City Region Deal.
Partners are also progressing their plans for the other two bases, which would command the remaining £138m of co-investment from industry and government.
The government could provide funding for those initiatives, but ditch the “sector deal” nametag.
Westminster has supported North Sea industry in recent years, creating one of the world’s most favourable fiscal regimes for oil producers.
And it has stumped up millions to pounds, alongside the Scottish Government, for the Oil and Gas Technology Centre (OGTC).
At the final evidence session in December, UK Energy Minister Claire Perry appeared to hint at the possibility of providing further support, without applying the sector deal “badge”.
After saying industry and government may “announce some things” they are “going to do together”, Ms Perry added: “Whether we call that a sector deal or an on-going partnership is a moot point, but clearly this is a sector that is absolutely vital to our economy.”
Work conducted at the three centres would benefit other industries, including renewables, defence and mining, so calling the package an “oil and gas” sector deal could be deemed inappropriate or misleading.
Committee chairman Pete Wishart MP urged the government to help the sector export its talents around the world and share its engineering nous with other industries.
“Only by doing this can the government ensure that in 30 years the north-east of Scotland is still home to a world class energy sector,” he said.
SAC wants the government to take steps to ensure that an underwater innovation centre would truly build on the OGTC’s work. But it called for quick action to prevent the UK falling behind other countries in that area.
The committee was also concerned by the risk of premature removal of North Sea oil infrastructure that could be used for carbon capture, usage and storage.
The government should consider taking on liability for those installations while options for re-use are explored, SAC said.
A spokeswoman for the UK Government said: “Oil and gas remains one of the most productive and important sectors of the UK economy. We welcome this report and will consider the committee’s recommendations.”
REPORT CONFIRMS OIL INDUSTRY’S IMPORTANCE
Deirdre Michie, chief executive of Oil and Gas UK (OGUK), said SAC’s report confirmed the industry’s vital role in providing energy security, jobs and revenues for the Treasury.
“This was a considered inquiry into the future of the UK’s offshore oil and gas industry and we welcome the rounded support provided by SAC,” said Ms Michie, a key lobbyist for the sector deal.
OGTC chief executive Colette Cohen said: “The committee’s report clearly recognises the critical role of technology in both maximising economic recovery from the UK North Sea and supporting the continued development of a balanced, low carbon energy mix for this country.”
Mr Winchester, a member of the Scottish Government’s Energy Advisory Board, insisted the need for new technologies for exploration and production was “probably quite limited”.
Mr Winchester believes industry has all the tools it needs to make the most of the North Sea’s remaining reserves, and decommission efficiently.
More emphasis has to be placed on sustainability and “eliminating the risk of hydrocarbons causing climate change”, he warned.
The Scottish Government said it supported plans for an underwater innovation centre, and reminded that it had provided funding for the NDC.
Ross Thomson, Scottish Conservative MP for Aberdeen South, said a sector deal for oil and gas was a “no-brainer”.
The creation of a decommissioning export strategy would strengthen the north-east’s bid to become the global leader in oilfield dismantling, Mr Thomson added.
WHAT’S A SECTOR DEAL?
Sector deals are partnerships between the UK Government and industry which aim to boost productivity, employment, innovation and skills.
Seventeen sector deals have already been agreed for some industries, including nuclear energy and life sciences.
As part of its Industrial Strategy, the government is planning on extending these partnerships to other parts of the economy.
An oil and gas sector deal would form a key plank of Vision 2035, North Sea industry’s best-case scenario for the next 16-17 years.
Devised by the Oil and Gas Authority and OGUK, the vision targets the generation of an additional £290bn worth of revenue for the economy — raising the sector’s total contribution to almost £1 trillion by 2035.
A sector deal would deliver a large chunk of the £290bn by helping the UK supply chain increase its turnover by capturing a larger share of export markets.
The oil and gas industry needs to ditch negative perceptions of private equity (PE) and get to grips with reality, a top North Sea executive said.
Verus Petroleum chief executive Alan Curran said PE was a “force for good” and that too many people associate the funds with shady characters from Hollywood films.
Mr Curran is convinced the mature UK Continental Shelf (UKCS) will be strengthened by a new group of PE-backed firms ready to maximise economic recovery and generate revenue for the country.
“Everyone needs to park the Hollywood image and understand the reality,” Mr Curran said.
“The problem is that many people do not understand what PE is about.
“They get The Wolf of Wall Street in their heads. The image is bad, but there are different types of PE with different characteristics.
“We have a single investor in HitecVision, but some might have two or three.
“PE is just another form of finance. Public limited companies have hundreds or thousands of investors, but most are faceless.
“PE will invest and exit, but it will be replaced with different types of finance.”
Mr Curran said he was working with Oil and Gas UK (OGUK) to improve the understanding of PE within the trade body, and throughout the sector.
He said the organisation had “done a good job” over the years, but had to keep up with industry, or risk becoming “irrelevant”.
From what he has seen and heard in recent weeks, Mr Curran’s impression is that OGUK is determined to “move with the times”.
He said: “If I have a criticism, it’s that views are dominated by majors’ opinions. Majors are paying the bulk of the bills, but as a trade body representing a broad cross-section, the views and opinions should not have been so dominated by a few.
“But credit to OGUK, they are working hard to address that. They reached out. We’ve met and spoken about how we can improve understanding of PE.”
Mr Curran, a former petroleum engineer at Shell, said he was “excited” by what he described as a “changing of the guards” in the North Sea.
Large corporations are either exiting completely or selling chunks of their portfolios, while a crop of smaller, aspiring companies are entering the fray, ready to take the UKCS forward.
Now is the time to “reshape” the industry and build the “right type of companies for the 21st Century”, he said.
Verus, which recently moved into the Silver Fin building on Union Street, Aberdeen, has secured a number of acquisitions in recent years. The firm was launched by Norwegian PE firm HitecVision in summer 2014, just before the oil price went “plop”.
The emphasis in the fledgling years was on survival and tidying up the portfolio it had inherited from former HitecVision firm Bridge Energy UK.
Verus came through those trying times with its reputation “intact” and started to build up the business in 2016.
Its first transaction was completed in January 2017 when it bought an additional 9.8% interest in the Boa field from Maersk Oil, taking its total stake to 11.35%.
That deal convinced the team at Verus that they could “make it”.
Verus had a lot of “near misses” in 2017, but that only stiffened its team’s resolve.
Success followed in 2018 with the acquisitions of 47% of the Babbage gas field from Premier Oil and 17% of the Alba field from Equinor – both announced in April.
The company’s “big deal” followed in September, when it struck an agreement to buy Cieco Exploration and Production (E&P) UK from Japanese corporation Itochu for £300 million.
It gave Verus interests in the Western Isles and Hudson projects, operated by Dana, and added production of about 11,000 barrels of oil equivalent per day (boepd) to the portfolio. Verus also received stakes in the Brent pipeline and Sullom Voe Terminal in Shetland.
It means Verus started 2018 with a production profile of about 1,500 boepd, but finished the year on 18,000.
Three acquisitions in one year sounds like a lot of work, but Mr Curran said Verus “maintained its discipline” and “walked away” from a number of deals.
He also said it was “ridiculous” that the Alba deal took until November to complete, despite the deal being signed in spring.
He blamed slow progress on bad behaviour in the “Alba joint venture”, but said the Oil and Gas Authority had helped remove “log jams”.
“It’s unfortunate that we had to go to the headmaster, but that’s what they are there for and they delivered,” he said.
Verus’ starting strategy was to build up a portfolio with an emphasis on production, creating a solid foundation.
That phase of Verus’ growth has been accomplished, Mr Curran feels.
He is confident Verus now has the balance sheet and cash flow at its disposal to take on the risk of development opportunities in the North Sea.
Mr Curran described Verus’ 20-strong workforce as “deal-making team” which is always on the lookout for opportunities.
“We look at more deals than we complete, for sure,” he said.
“But we are very precise about the type of target we’re looking at – that’s a feature of PE.
“We are looking at high-quality targets and will maintain our discipline. We will miss some deals, but we will hit the right ones.”
The businessman also reckons the Brent crude price slump in the fourth quarter of 2018 was “great” for the market.
Mr Curran said: “A lot of froth was coming back into the market when the oil price was rising last year, and there was a concern that bad behaviours might return.
“The oil price going down means we have a chance to set up the right business models in the UK and provide a vibrant future.
“We do not want the oil price to run away. A lot of people wanted to do business but the key is a stable oil price. We will still see a lot of mergers and acquisitions activity.”
While “hotspots” of good behaviour and collaboration emerged during the last downturn, the industry has not been “transformed”, he said.
The dominant trends were negative. There were sweeping redundancies and the supply chain took a “beating”.
Mr Curran said: “If we can establish a quality relationship with the supply chain we can take a long-term view and move away from boom and bust.
“The UK has been able to withstand these challenges, but as the North Sea gets older, its ability to recover declines.
“As we get older, we need to look after ourselves – that applies to assets and businesses, too.”
The UK’s £7.5 billion subsea sector will be championed before a global audience at a three-day conference in Aberdeen this week.
Exhibitors from throughout the UK will be showcasing their products and services, alongside firms from overseas, at Subsea Expo 2019.
Britain’s innovative subsea sector comprises about 650 companies, employing more than 45,000 people, in supply chain activities for oil and gas, defence, oceanology and marine renewables markets.
Its flagship annual event, Subsea Expo, is organised by industry body Subsea UK. The 14th edition gets under way tomorrow, when Energy Minister Paul Wheelhouse will deliver the opening keynote address.
More than 5,000 people are due to descend on Aberdeen Exhibition and Conference Centre for Europe’s largest annual subsea event.
Pre-registrations were up by 19% on last year and more than 170 organisations from across Europe, the US, and Japan are expected to showcase their products and services.
The 2019 expo has Innovating the Future as its theme, inspired by conference sessions focused on the rise of digitalisation and accelerating the delivery of sustainable energy and operational efficiency.
Speakers from companies including One Subsea, Haliburton, SubC Imaging, Stats Group, and Tracerco will give presentations on topics ranging from digital transformation, remotely operated / autonomous underwater vehicles, field life extension, decommissioning, global opportunities, construction and intervention, marginal fields, and inspection, repair and maintenance.
Subsea UK chief executive Neil Gordon said: “Over the past few years the word innovation has been talked about, but not put into practice as cost-cutting has been the main focus. The challenge we now face is increasing efficiency in oil and gas, as we grow and move into other sectors, and how we take the underwater supply chain with us.
“It will be a slow and steady evolution, but we have to understand how the industry is going to move forward and how everyone will play their part.”
Bosses at DeltaTek Global are targeting “aggressive growth” in the wake of a year of breakthroughs for the Dyce-based well construction pioneer.
They are prepared to invest £250,000 in inventory to help cope with demand.
A recent contract win with Energean means the firm will need to take on two more full-time staff members – lifting the total to six − to cover the workload.
The project heralds DeltaTek’s first foray into the international scene and has been described as a “huge milestone” by founder and chief executive Tristam Horn.
The firm’s SeaCure technology will be deployed from the Stena DrillMAX vessel at the Karish field off Israel. The tool was designed for constructing wells with more reliability and speed.
It will be used for four wells in the Mediterranean during the current quarter, and DeltaTek hopes to be involved in more wells later this year.
It was trialled in the North Sea by Chevron and Siccar Point Energy in summer 2018.
Siccar subsequently awarded DeltaTek a contract to provide SeaCure in the North Sea for two years.
Mr Horn, formerly of BP, said 2018 had been an incredible year for DeltaTek and that he was determined to build on those successes in 2019.
He has been emboldened by SeaCure’s speedy market entry and the willingness of operators to adopt the time and cost-saving technology.
The prospects for SeaCure’s follow-on product, QuikCure, also look encouraging.
DeltaTek has already secured a deal to supply the product to an unspecified client.
Mr Horn said QuikCure uses warm water to help the cement set rapidly, significantly reducing waiting times, which can range from 10-18 hours.
He said: “One of the real beauties of QuikCure is that it uses the same hardware as SeaCure but has a profound impact on cement setting.
“The expectation of QuikCure taking 90% off waiting times is an added bonus of the value proposition we bring through SeaCure. It’s a nice feature. A lot of the time when we have a meeting, clients ask, ‘where are you going to get the warm water from?’
“We are going to recycle our client’s waste water from the rig’s main engines. That waste water is usually dumped in the sea. So, with this, we’re improving the well production programme but also reusing waste water so there is an environmental slant. People are excited about that.”
DeltaTek is also making progress with another of its products, ArticuLock.
It has been described as a sort of ball-and-socket joint used to reduce the bending stress on landing strings – heavy duty pipes which can be used to deploy heavy equipment and casing to the well site.
The technology was recently trialled, and the results were highly promising.
Mr Horn said: “When we got the equipment back from the trial and did an inspection we recognised the tool has a long lifespan. No wear and tear was found after three months of continuous use, so it maintained its integrity.”
The last year or so was also marked by the appointments of Dave Shand as chief commercial and operations officer and Steve Bruce as chairman and chief technology officer.
Experienced drilling engineer Chris Johnstone came aboard as operations supervisor towards the end of last year.
With another two appointments on the cards, DeltaTek could soon be looking to uproot from its current base near Aberdeen International Airport.
Mr Horn said: “I’m keeping my ears close to the ground. Where we are now is suitable for the time being, but we are quickly going to outgrow it.
“If something comes up, we will jump at the chance.”
DeltaTek was given another boost by Wood Mackenzie’s prediction of a renaissance for North Sea drilling, which will mean more wells.
Mr Horn said: “It’s quite an exciting time in the market for us. We are providing really novel technology for subsea well construction.
“The feeling in the market is good and analysts are forecasting more project FIDs and capital coming into the market, so it’s a really exciting time for us. That’s where our technology has a big impact – to support well construction.
“Subsea Expo will present a good chance to hear about operators’ plans for subsea tiebacks.
“It feels like there is more confidence within finance departments for making investment decisions.”
Former EY Scottish entrepreneur of the year David Lamont has been unveiled as the new chairman of north-east subsea company Rovop.
Mr Lamont, who achieved his prestigious EY title in 2013, has been a non-executive director at Rovop, which has its headquarters in Westhill near Aberdeen, since November.
He boasts more than 35 years in the oil and gas sector, starting at oilfield services company Schlumberger and ending up as chief executive of Westhill-based controls technology firm Proserv.
Mr Lamont, 58, is also on the board of the Aberdeen-based Oil and Gas Innovation Centre.
He stepped down from the Proserv hotseat last May, following the completion of a restructuring deal
which saw the firm taken over by its two largest lenders.
Rovop was founded in 2011 by chief executive Steven Gray, former chairman Mark Vorenkamp, who left the company in December 2017, and Scott Freeland, who was technical director before moving to Ecosse Subsea Systems in October 2012.
The firm specialises in remotely operated vehicle (ROV) services for the oil and gas, offshore wind, telecoms and power transmission industries.
It has operations in Westhill and Houston, in the US, backed by investors including the Business Growth Fund and London-based private equity firm Blue Water Energy.
Mr Lamont’s appointment was announced alongside news that Lee Wilson has joined Rovop, from Subsea 7, in the newly created role of head of technology.
Mr Wilson’s background is in subsea robotics. As ROV and autonomy programme manager at Subsea 7, he led several remote technology projects and played a key role in developing a new autonomous inspection vehicle.
Kevin Lyon, who was chairman after Mr Vorenkamp, and non executive director Ken McHattie have both stepped down from Rovop’s board.
Mr Lyon said: “Rovop has evolved from the successful niche player in 2015 to one of the leading operators in the ROV and subsea robotics market.
“This has been achieved by focusing on the quality of delivery for customers and acquiring assets through the downturn in the subsea market.
“The company now has the track record, team and asset base to achieve its objective of being a major global player in its market, and the time is right to capitalise on that position with David.”
Mr Gray added: “Kevin and Ken have contributed very significantly to
Rovop’s stability and growth, through both the strong market and the industry downturn. It is a tribute to them that as they hand on their roles Rovop is in such a strong position.
“We are also thrilled to have Lee come on board. His skills and experience are essential parts of our strategy to further service our customers’ subsea intervention needs.”
After a difficult few years, the exploration sector is back in the black – and keen to stay there. New analysis from Wood Mackenzie shows that explorers’ success in 2018 reflects a disciplined approach that’s set to continue this year.
Dr Andrew Latham, vice president, Global exploration, said: “We are seeing a long-overdue recovery in the sector. Last year conventional exploration returns hit 13% – the highest calculated in more than a decade. As 2018’s discoveries are appraised and projects move through the development cycle, we expect these economics to improve further.”
In 2018, exploration added at least 10.5 billion barrels of oil equivalent (boe) in conventional new field volumes. This was split 40:60 oil to gas. Dr Latham said: “These volumes are currently the lowest for several decades, but we expect they will increase, thanks to both further disclosure and appraisal. Similar resource creep from the initial year-end estimates has averaged around 40% over the decade. In 2017, it was 50%.”
While overall volumes might be modest, there were some very encouraging wells. Last year saw three play-opening discoveries – Ranger and Hammerhead on Guyana’s prolific Starbroek Block, and the Dorado find, which confirms a new liquids play in the Roebuck sub-basin, offshore Australia.
Last year also saw three giant finds – Novatek’s 11.3 trillion cubic feet North Obskoye gas find offshore Russia, the Calypso gas discovery, offshore Cyprus, and Guyana’s Hammerhead. This trio, together with the 18 large discoveries made last year, account for 80% of the total discovered resources.
So how will 2019 shape up? Dr Latham said: “The Americas will receive a lot of attention this year. Latin American plays account for one third of global large and giant prospects scheduled for drilling in 2019. This region will also see one-third of the potential play-opening wells. Exceptional reservoirs in Brazil, Guyana and Mexico will attract the most investment. We expect billion-barrel scale volumes from these emerging and newly-proven plays, as has been the case in the last couple of years.”
He added that southern and western Africa will also see a resurgence in offshore exploration.
“Many of this year’s planned wells have the potential to open new plays or add large volumes,” he said. “Worldwide, we expect 2019 discoveries to add around 15 billion-20 billion boe of new resource.”
Dr Latham singled out five wells in particular as ones to watch. Top of the list is Peroba, a giant pre-salt prospect in Brazil’s Santos basin, estimated to hold in-place volumes of more than 5 billion boe. Peroba lies on trend with the giant Lula discovery. If the well is successful, partners Petrobras, BP and CNODC are likely to be sitting on a very significant find.
Next is Brulpadda-1, in South Africa’s frontier Outeniqua basin. Total operates this potentially play-opening well, with drilling results expected this quarter. Prospect volumes are pegged at around 1 billion boe.
Nour-1, in Egypt’s prolific Nile Delta, is currently drilling. If Eni and its partners are successful, Nour could have an impact on other projects in the region, especially as its near-shore location means it could be brought on stream quickly, strengthening Egypt’s gas export prospects. Nour’s resource is estimated to be about 860 million boe.
Chevron will spud Kingsholm-1 in the US Gulf of Mexico’s prolific Mississippi Canyon area towards the end of the first quarter. The prospect is high-pressure, high-temperature (20 ksi) and holds an estimated 300 million boe of resource. Last on this list is the Jethro prospect, on the Orinduik Block, offshore Guyana. This well is on acreage adjacent to ExxonMobil’s prolific Stabroek Block and will target a 200 million boe prospect in the same play as the recent Hammerhead find.
While not in Dr Latham’s top five, Total’s Venus-1 well, in Namibia’s ultra-deep offshore, has the potential to be the year’s largest discovery. The ultra-deepwater wildcat will target 2 billion barrels of oil in a giant Cretaceous fan play, close to the South African maritime boundary.
However, the exploration sector will continue to be an exclusive club in 2019. The recent uptick in exploration economics over the last two years shows how the sector has slimmed down. Fewer companies are drilling fewer wells, and many companies, regardless of size, have cut their exploration spend.
“Even as average exploration returns rise to double digits, newcomers will be few and far between. If anything, the current corporate landscape will continue to narrow,” Dr Latham said.
He added: “Exploration remains critical for the majors and all eyes will continue to follow their wells. A small number of independent IOCs and international NOCs will also be readying their high-impact prospects. Less active in exploration in the coming year will be the private equity-backed explorers.”
Those companies that are sticking with exploration have renewed confidence. “A stronger oil price, lower cost base, refocused portfolios and greater drilling success in 2017-2018, and a healthy inventory of new quality acreage have cheered up the industry. It is using more efficient rigs at lower rates, and avoiding technical complexity. These changes will help the industry stay on track and continue to be profitable.
“However, this more upbeat spirit has been hard-won and companies will be loath to give it away. Purse strings are not about to burst open. We expect companies will focus on their best prospects, with global exploration and appraisal spending for 2019 staying close to its 2018 level of just under US$40 billion per year,” Dr Latham said.
Not all the changes have been so supportive. While some governments have made adjustments to fiscal and regulatory regimes to encourage exploration, others have opted to speed up the shift to a non-carbon future by banning exploration.
Dr Latham said: “Sustainable energy technologies are advancing and public attitudes towards oil and gas exploration are changing, too. As a result, we foresee more partial or complete exploration bans. However, so far this is a trend for economies that can afford a declining hydrocarbon contribution in their energy mix. The industry will be watching closely to see if such bans spread to countries with greater subsurface potential.”
Hydrocarbon supply is still key for meeting global energy demand and while a continued focus on maximising recovery from existing wells is important, it is also crucial for the industry to continue to identify new prospects as many aging assets come to the end of field life.
With increased production of hydrocarbons delivered through subsea wells, more demand is placed on bringing new technologies to the market that can ensure the safe development and intervention of these wells, located in thousands of meters of water.
There are some 6,826 active subsea wells globally with an average age of 11 years, which all require to be monitored and maintained to the relevant standards until they are safely decommissioned. Optimising the recoverable hydrocarbon volumes from this subsea well stock is recognised as an obvious target to bring incremental production to the energy sector. To carry out these well optimisation activities, the operator will often require some form of well intervention.
When planning to complete any type of subsea well intervention it is crucial that the appropriate well access system is identified based on capability and efficiency, while ensuring safety is paramount.
Expro is at the forefront of supporting improvements to increase integrity and safety in subsea well intervention through its involvement in the industry’s API17G 3rd edition standard, which provides clarity on the requirements for in-riser well intervention equipment, which was not captured in earlier editions.
The next generation landing string (NGLS) system has been designed to fully comply with all aspects of API 17G. The NGLS comprises a five-phase programme of work to deliver a complete landing string package, including a range of functionality across its large bore valves. It incorporates a high debris tolerant ball mechanism and hydraulic latch mechanism, dual seal protection for both environment and control systems, increased cutting capability, and a fail ‘as is’ retainer valve with the ability to close after a blowout preventer shear scenario.
Typically, there are three recognised methods for subsea well access. A Subsea Test Tree Assembly (SSTTA) is deployed with the rig marine riser and safety system which offers full well intervention capability for new and existing wells including flow testing back to the rig. It provides the ability to control tubing pressure with dual barrier isolation to rapidly shut-in the well and disconnect safely from the rig as required. As subsea test trees have become the established safety system for well commissioning and intervention, industry standards have been developed to ensure well integrity is maintained at all times.
However, where the scope of work is to improve production, repair and remediate, or carry out abandonment activities, a Subsea Intervention Riser system (IRS) would offer the required capability to safely complete and maintain access throughout the operations, being deployed through water, with tubing from a rig or vessel.
An IRS package provides the well operator with a through tubing well access system with disconnect capability for all types of well intervention, often utilised on multi-well campaigns, and removes the necessity for running a marine riser, thus making significant cost savings. The IRS system is deployed quickly from a vessel or rig but is not used for installing completions on new wells where an operator would typically utilise the SSTTA.
Due to being vessel-based and deploying the system through water, a Riserless Well Intervention (RWI) system is able to offer a very efficient method of well access as there is no requirement for vessel anchoring and, in the absence of a drilling riser, makes the intervention more efficient. Typically, the most common type of RWI vessel is mono-hull, offering significant advantages in transit speed when moving from different well locations or fields for multi-well campaigns when compared to a rig. An RWI vessel can be ready for well operations in less than a day, compared to a rig-based marine riser and safety system using the SSTTA which can take longer to deploy than the IRS or RWI packages. Detailed knowledge of the in-well activity is required to select RWI as the appropriate system to allow maximum efficiencies of a vessel-based, through water system which does not have the ability to remove the well completion tubulars.
Expro can deliver all three types of well access solutions detailed above, ensuring that each subsea well access solution will safely manage the containment of hydrocarbons between the seafloor and the rig or vessel. Our systems provide the mechanism for safe disconnect and reconnect during adverse weather and are designed to maintain well integrity throughout.
With more than 30 years of market-leading experience, Expro supports the global subsea well access arena in standard and harsh operating environments including deep water, high pressure and high temperature. All well access operations will require a specialised intervention tooling solution and possible topside package, which Expro further supports by offering a complete capability.
It is clear that subsea well intervention is becoming increasingly important in the delivery of reliable hydrocarbons production with the decline in many mature oil and gas fields around the world, especially so in the UKCS. The increased requirement for intervention is to ensure safe and optimised production as the global subsea well inventory increases in age.
Innovative thinking and technology solutions will be essential for the next generation of subsea projects, as the industry looks to reduce costs, enable increased recovery and deal with harsher and more complex environments.
Established at the outset of Aberdeen’s oil boom in 1973, Bilfinger Salamis UK began as an industrial blasting and painting specialist.
Four decades later the business stands as an industry leader having grown and strategically broadened its offering.
Few businesses have come out of the downturn with a wider service range, more employees, and new contracts across new industries, so how has Bilfinger achieved it?
Operating across north-west Europe, with bases in Aberdeen, Esbjerg and Groningen, as well as a new state-of–the-art Southern North Sea base in Great Yarmouth, Bilfinger has more than 20 major customers in the North Sea.
Remaining a trusted player within the oil and gas industry, the business’s skill and experience have been successfully transferred to the offshore wind industry in the UK, Denmark and Germany. Based on previous successful campaigns, Bilfinger teams will soon be mobilising to the Sheringham Shoal wind farm off the south-east coast of England, as well as to the Global Tech wind farm in northern Germany.
Bilfinger expertise has been applied to various topside removal scopes
Expansion into the offshore wind industry is not the only way that the application of Bilfinger services is strategically differentiating in the face of a changing industry. Having emerged from the oil downturn stronger and with a wider client portfolio, an increase in decommissioning work will see Bilfinger expertise applied in UK projects in the Southern North Sea as well as Dundee quayside in 2019.
Decades of experience in maintaining and improving offshore assets means Bilfinger teams, now working directly with heavy-lift barge operators, understand the best way to safely and efficiently decommission fixed and floating production facilities. Teams have worked on topside removal scopes, transferring existing skills from offshore construction and maintenance.
As the industry moves forward, Bilfinger has thoughtfully expanded its portfolio of capabilities from its origins as a fabric maintenance specialist; now employing 2,300 personnel in the UKCS and a further 35,000 globally. Today the business provides inspection, maintenance manpower, architectural, deck crews, platform modifications and specialist services.
Always on the lookout for new technology to stand out from the crowd, this is a business keen to differentiate from is competitors and keep pace with market demand for enhanced productivity.
on the up: A recent large modification scope delivered by Bilfinger teams
The days of large and costly administrative efforts supporting offshore operations are over, and the business is embracing technological developments, enabling streamlining and more effective work execution. Bilfinger has a digitally enabled workforce, using tablet technology to improve links with offshore teams and accelerate inspection reporting and asset integrity delivery.
In conjunction with key clients in Aberdeen, Bilfinger is working to integrate its software and tablet technology with client integrity management systems, further increasing productivity gains.
Sandy Bonner, managing director, is rightly proud of the Bilfinger teams and the pace of strategic expansion with new and existing customers, however he points out that it requires continual effort and investment.
He said: “In 2018 we were able to achieve and exceed our growth targets due to our strategic investment in new services, training and technology.
“We have a stable, motivated and trusted operations team that remain committed to modernising the business and further expanding our service capability.”
Two years ago, following fantastic collaborative efforts from 70 people in 31 companies, Oil & Gas UK’s Efficiency Task Force (ETF) team published the first Subsea Standardisation guidelines and the signs are they’ve been put to good use.
While subsea engineering has helped maximise the life of existing production infrastructure, producing more oil and gas at lower cost, our subsea standardisation project addressed the UK oil and gas industry’s tendency to “gold-plate” projects and push up operating costs.
We first looked at developing guidance to help the industry improve the economic viability of small pools, defined as those with fewer than 50 million barrels of oil equivalent, and increase their attractiveness to investors. A diverse group of operators, design consultants, manufacturers, fabricators and installation contractors committed to working together to understand the challenge.
From the start it was apparent these experts shared the ETF ethos, in seeking out, promoting and providing access to efficient practice while maintaining safe operations. Their collaborative mindset was instrumental in helping the ETF to deliver the Subsea Standardisation guidelines, which revealed many opportunities for improving the competitiveness of project delivery, with the potential to deliver significant savings in subsea projects.
Various companies provided case studies, with Spirit Energy offering its West Pegasus field as a theoretical example for analysis. By applying the guidelines, our project team identified savings of potentially up to 25% in areas including design optimisation, revised field layouts, efficiencies in valves, trees and control systems and by combining umbilical cables in pipeline trenches.
The feedback from firms like Spirit is they see guidelines as a useful reference point during the completion of design reviews, helping to ensure they continue working towards the optimum solution.
We are seeing an evolution in the way the industry is using the guidelines. They are now being applied as firms seek to reassess a broader range of projects considered marginal and requiring a more effective framework, or different way of thinking, to unlock their potential.
At this larger-scale perspective, we are observing the same potential to deliver cost savings, in this case of up to 24% including project management and engineering, procurement, manufacture and fabrication, transportation and installation activities.
How a company approaches and adopts these principles is crucial and early engagement between client and the supply chain is a priority. We’ve seen major contractor companies like WorleyParsons extract value by adopting the structure and underpinning philosophy of the guidelines to develop a customised framework that will continue to support its drive to capture standardisation-based efficiencies across its portfolio.
Overall, we’re seeing growing evidence the principles of standardisation can be used to save project costs and we are collaborating with companies to capture what they have achieved to date and how this was accomplished. It is this continued focus on project delivery efficiency that will unlock the next generation of North Sea development and help us realise the ambition of Vision 2035.
Cleaner power and the falling demand for energy across homes and industry have driven cuts in UK carbon emissions of nearly two-fifths since 1990, analysis suggests.
The UK’s carbon dioxide emissions peaked in 1973 and by 2017 were 38% lower than they were in 1990, research by climate and energy website Carbon Brief shows.
Declining emissions are largely down to a switch to a cleaner electricity mix, based on gas and renewables instead of coal and falling demand for energy across homes, businesses and industry.
UK emissions have declined from around 600 million tonnes of carbon dioxide in 1990 to 367 million tonnes in 2017, the last full year for which figures are available.
The Carbon Brief analysis finds that with a growing population and without the changes that have driven down pollution, emissions would have grown from 1990 and have been twice as high as they were in 2017.
The pollution from electricity generation and use would have been nearly four times higher than it is, the assessment estimates.
A cleaner electricity mix is responsible for 36% of the emissions savings in 2017 compared to what it would have been.
Lower heating and other fuel use in industry, business and homes makes up 31% of the reduction.
Lower electricity demand due to changes in manufacturing and low-energy light-bulbs and appliances in homes, and emissions savings from more efficient vehicles have also played a part.
As the UK continues to phase-out coal by 2025, emissions reductions are likely to continue.
Reductions in domestic emissions were largely cancelled out by rising carbon emissions associated with imported goods until the mid 2000s, but since 2007 that has not been the case, the analysis indicates.
Today, unions accused Prosafe of enticing loyal employees to accept voluntary redundancy packages and offering to hire them back when activity increased.
The Offshore Coordinating Group (OCG), a coalition of UK unions, and Norway’s Industri Energi, said posts were being advertised in Poland and Croatia.
They claimed the pay packages being offered through the OSM agency were “substantially lower”.
They called for oil and gas companies, including clients BP, ConocoPhillips and Equinor, to stop giving Prosafe contracts to provide flotels in support of UK North Sea projects.
Furthermore, they have asked the International Transport Federation to alert trade unions around the world to the situation “unfolding in the UK sector”.
And they have asked the UK Health and Safety Executive to look into the competence and training standards of short term agency workers.
RMT regional organiser Jake Molloy said: “We would hope that the clients using these barges will act responsibly and moreover act in accordance with their own internal policies associated with codes of ethics.
“What is happening here is completely unethical and the likes of BP, Equinor and ConocoPhillips should recognise this.”
Unite regional officer John Boland said: “The industry has repeatedly claimed that the sector must become more competitive.
“However, if the actions of Prosafe are to be considered competitive then we want no part of it.
“Our member’s jobs are not for sale to the lowest bidder in a drive to be competitive.”
Prosafe said it always “aimed to comply” with the laws and regulations of the countries in which it operates.
A spokeswoman for Prosafe said: “We have always used agency personnel to supplement Prosafe staff, but given both the nature of our business with short-term contracts, and the industry downturn resulting in longer lay-up periods, Prosafe has to move to an even more scalable crewing model to remain competitive and sustainable as a business.”
She added: “Prosafe has entered into an agreement with a manning agency, OSM, for some of the offshore positions.
“OSM is a recognised international supplier which offers staff with the right qualifications and expertise, and some of our former employees have chosen to apply for jobs with them.
“To ensure thorough knowledge of the respective accommodation vessels, efficient operations and a high level of safety, there will be Prosafe employees in the leading positions on our accommodation vessels.”
BP, ConocoPhillips and Equinor have been contacted for comment.
A multi-million pound fund created to get unemployed oil and gas workers back into the world of work by using the skills they developed in the industry has helped 4,000 people.
The Scottish Government established the £12 million Transition Training Fund in February 2016.
The scheme sought to assist those affected by the global downturn in oil and gas by providing training grants to help them find new jobs.
With the three-year fund due to close at the end of next month, anyone eligible for its help is now being encouraged to apply as soon as possible if they wish take part.
Energy minister, Paul Wheelhouse, said: “The Transition Training Fund was a key part of the work done to support people through the downturn in the oil and gas sector.
“From my meetings with participants, it has been a great success.
“With Scotland being a global leader in the energy sector, it was essential to retain those highly-valued skills and help people continue people’s careers.”
More than 3,700 people have had individual applications for support through the fund approved and 300 more people have accessed support. network of local centres to help people get the right advice, find work or access training.”
More than two thirds of those who have used the fund are now back in employment, and more than half of those in employment have remained in the oil and gas sector.
One user who credits the fund with helping him take the next steps in his career in Douglas McInally.
The father-of-three from Arbroath had been working offshore when he was made redundant, and has now updated the previous qualifications he had as a gas engineer and secure work with SSE.
French oil major Total is reportedly close to selling a stake in the Laggan-Tormore project west of Shetland to private equity firms.
It is understood Albion Energy and First Alpha Energy Capital are ready to pay £1 billion for 20% of Laggan-Tormore and interests in a number of smaller North Sea fields Total acquired from Maersk Oil last year.
Reuters reported in December that talks were being held.
The deal is expected to be announced this week, The Telegraph said yesterday, citing “sources”.
First Alpha is a private equity firm in London which was established in 2016.
Albion Energy is the investment vehicle of Heritage Oil founder Tony Buckingham.
The Laggan and Tormore fields came on stream early in 2016 following £3.5 billion worth of investment in a new plant in Shetland to process the gas.
In September, Total said project partners had sanctioned the drilling of a fifth well on Laggan, called L5, with the campaign slated to start in March 2019.
Total said the well would help it crack “compartmentalisation” issues on a reservoir which came off plateau about a year after first gas.
Total owns 60% of Laggan-Tormore, while SSE and Ineos each have 20%.
Paris-headquartered Total has been busy reshaping its portfolio following the Maersk Oil takeover.
It recently sold interests in the Bruce and Keith assets to Serica Energy.
But it announced a major gas discovery at Glendronach, and was involved in the Glengorm find, operated by Chinese firm CNOOC.