Volcanoes in North Sea Could Hold huge Untapped Oil Reserves

Credit: John Jeffay, The Scotsman

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Geologists at Aberdeen University have revealed they have discovered “phantom” volcanoes covering a “huge swathe” of unexplored North Sea basin. For decades the 3,000sq mile area was believed to have the remains of three volcanoes that erupted 165 million years ago.

The Rattray Volcanic Province has for years been dismissed by North Sea oil and gas firms as empty magma chambers. But academics now claim it might yield an eruption of oil and gas reserves. Nick Schofield, from the university’s school of geosciences, said “several” large oil and gas operators had expressed interest in the study. And he said it was time North Sea firms looked at the basin with “fresh eyes”.

The new findings raise the possibility of future discoveries in the area, which has been untouched during 50 years of North Sea exploration activity. Mr Schofield said: “Essentially this gives us back a huge amount of gross rock volume that we never knew existed, in one of the world’s most prolific regions for oil and gas production. Below and on top of the Rattray could hold oil and gas reserves, though it’s way too early to tell how much. But often the best place to find oil is where you’ve discovered it before.”

The discovery was made during Aberdeen PhD student Ailsa Quirie’s postgraduate research for the Carnegie Trust scholarship. Mr Schofield and Ms Quirie were working on the data from the far North Sea, close to the Rosebank field, west of Shetland. He said the team combined 3D seismic data with methods used to look at other volcanoes elsewhere in the UK Continental Shelf.

Mr Schofield said: “What we found has completely overturned decades of accepted knowledge. We think most of the rock is untouched, it’s very exciting. People need to look at the North Sea with fresh eyes after this discovery. There is a huge area under there that hasn’t been looked at in detail for a long time, because of the previously incorrect geological model.”

UK: OGA Launches Licensing Round for Greater Buchan Area. Eyes 300 Million Barrels

Credit: Offshore Energy Today

UK’s Oil and Gas Authority (OGA) has launched the Supplementary 31st Offshore Licensing Round in an attempt to maximize economic recovery from the Greater Buchan area of the North Sea.

The UK’s crude oil production alone increased by 11 percent to 1.08 million bpd in Q1, according to the government statistics quoted by Platts—a welcome sign for the UK oil and gas industry which has managed to reverse a years-long downward trend in recent months, thanks to start-ups of projects in the North Sea.  

OGA said on Thursday that the licensing round presented an opportunity to collaborate and maximize economic recovery of up to 300 million barrels of oil equivalent in the Greater Buchan Area. Situated in the Outer Moray Firth in the North Sea, the area features around 5,800 square kilometers of currently unlicensed acreage, which includes a number of undeveloped discoveries and prospects.

The Buchan field, located in the area, came online in 1981 using the Buchan Alpha floating drilling rig which was on station for around 36 years. The rig which reached the end of its design life has been removed from the location. However, OGA claimed that significant oil and gas resources were estimated to remain in the Buchan reservoir and the Greater Buchan region, making it a valuable area of the North Sea. OGA added that it wanted to develop an Area Plan with the industry to maximize economic recovery of the remaining resources.

The Supplementary Round, announced in October 2018, was supported by an advanced release of substantial information and data, including seismic data packages. OGA is continuing to make more data available and this dataset included well data for 154 wells, 3D seismic surveys, relinquishment, and technical reports. In November 2018, OGA said that the Supplementary Round attracted 36 applications covering 164 blocks in the area.

Andy Samuel, chief executive of the OGA, stated: “There’s been excellent interest in the Greater Buchan Area. There’s much to play for from exploration through to development opportunities. We are encouraging prospective operators to look beyond individual opportunities and actively partner with other companies to establish a mutually beneficial Area Plan realizing the full economic potential in the area.”

The next round, the 32nd Offshore Licensing Round, is planned to open in the summer of 2019 and will focus on mature areas of the UKCS. According to the UK Department of Business, Energy & Industrial Strategy, provisional figures for 2018 showed that UK crude oil and NGL production rose by 8.9 percent compared to 2017, mainly due to multiple new projects on the UK Continental Shelf (UKCS) coming online in late 2017 and 2018 and increasing production through the year.

In November of 2018, BP and its co-venturers started up production at the giant Clair Ridge project in the West of Shetland region offshore UK. The project is targeting 640 million barrels of oil reserves and is expected to have peak production of 120,000 bpd. The UK’s petroleum reserves remain at a significant level, with overall remaining recoverable reserves and resources ranging from 10 to 20 billion barrels plus of oil equivalent, according to the UK Oil and Gas Authority (OGA). Currently proven and probable reserves on the UKCS can sustain production for another 20 years.

The UKCS yielded 20 percent more oil and gas in the last five years after 14 consecutive years of production declines, the industry’s association, Oil & Gas UK, said in its latest annual Business Outlook earlier this year. Exploration in the UK’s North Sea is definitely picking up and this year could see the drilling of up to 15 new wells, the association added. This is momentum that needs to be maintained, the association noted, as expectations were for another decline in production to begin after 2020.

Gas Find in North Sea Hailed as ‘Biggest in a Decade’

Credit: Kevin Keane, BBC

A significant gas discovery in the central North Sea is being described as the biggest find in more than a decade.

Chinese state-owned company CNOOC said it made the gas discovery – equivalent to 250 million barrels of oil – in its Glengorm project, east of Aberdeen. Further appraisal work is planned, but it is understood it could be extracted using existing infrastructure.

Friends of the Earth Scotland said the find was terrible news for the climate. Glengorm sits 118 miles (190km) east of Aberdeen, close to Total’s Elgin-Franklin and Culzean fields, and could be tied back to one of their platforms. Total owns a 25% stake in the Glengorm field. Xie Yuhong, of CNOOC, said the company was “looking forward to further appraisal”.

Still Life in Mature Waters

Kevin McLachlan, of Total, added: “Glengorm is another great success for Total in the North Sea, with results at the top end of expectations and a high condensate yield in addition to the gas. Our strong position in the region will enable us to leverage existing infrastructures nearby and optimise the development of this discovery. Glengorm is an achievement that demonstrates our capacity to create value in a mature environment thanks to our in-depth understanding of the basin.”

Analysts Wood Mackenzie described the find as the largest in the North Sea since the Culzean field was discovered in 2008. Senior analyst Kevin Swann said: “There is a lot of hype around frontier areas like West of Shetland, where Total discovered the Glendronach field last year. But Glengorm is in the Central North Sea and this find shows there is still life in some of the more mature UK waters.”

Environmental groups have criticised the discovery which, they say, will further contribute to climate change. They want energy companies to leave oil and gas in the ground and focus instead on renewable sources.

Climate Destruction

Caroline Rance, from Friends of the Earth Scotland, said: “It’s a disgrace that oil and gas exploration is still going ahead in the seas off Scotland. It’s high time our governments stopped supporting fossil fuel development, and get serious about planning a just transition away from this industry. These companies know all too well that their business is built on the destruction of the climate, which is devastating for millions of people around the world but they continue to seek profit from driving this catastrophe.”

The Oil and Gas Authority has welcomed the discover, and said it demonstrated the considerable potential the industry still had to offer. Chief executive Andy Samuel said: “This is very exciting news. Glengorm was first mapped as a prospect around 20 years ago and it is great to see CNOOC taking up the exploration opportunity and completing a difficult high-pressure, high-temperature exploration well. Our official estimate is that there still remains between 10 and 20 billion barrels plus to be recovered, so there is every chance of yet more significant finds, provided industry can increase exploration drilling and capitalise on the real value to be had here in the UK.”

Energy Minister Paul Wheelhouse said the announcement, “highlights the significant potential for oil and gas which still exists beneath Scotland’s waters”. He added: “Scotland’s offshore oil and gas industry has an important role to play with up to 20 billion barrels of oil equivalent remaining under the North Sea and in the wider basin and discoveries such as this help to support security of supply as we make the transition to a low carbon energy system.”

Chasing The Prize For North Sea Oil And Gas Decommissioning

Credit: Mark Venables, Forbes

There are currently around 320 fixed installations, such as oil platforms, in production in the UK, primarily in the North Sea. To date, oil and gas assets have enabled operators to recover more than 44 billion barrels of oil and gas. However, reserves are running out, with the remaining oil and gas becoming harder to find and extract. The government has an objective to maximize the potential economic value of the UK’s remaining oil and gas reserves.

Oil and gas operators in the UK are increasingly decommissioning their assets as they are reaching the end of their useful economic lives. Operators’ expenditure on decommissioning is rising: they have spent more than £1 billion on decommissioning in each year since 2014. According to the UK’s Oil & Gas Authority (OGA) decommissioning of the UK’s offshore oil and gas production facilities is a major industrial challenge which can create a global competitive advantage for the UK. With more than 100 offshore platforms and 5,700km of pipeline forecast to be decommissioned or reused over the next decade on the UK Continental Shelf there is a massive prize for those who can deliver the right services. The OGA estimate the total cost of oil and gas decommissioning to be £58bn.

However, the challenge is that the UK oil and gas industry is mostly unfamiliar with large-scale decommissioning projects, but much can be learned and transferred from other industries. While the innovation and transformation underway within the industry will determine our ultimate success, more immediate incremental improvements can also deliver significant results.

Step forward the National Decommissioning Centre (NDC), a global technology R&D hub, opened in Newburgh, in North-East Scotland’s Energetica Corridor late last year. The task of the NDC is to help industry deliver the >35% cost reduction target set by the regulator in 2016. Led by Professor Richard Neilson from the University of Aberdeen and the OGTC’s Dr Russell Stevenson, the NDC is developing a wide-ranging, industry-led research programme, with dedicated access to the brightest and best Ph.D. and MSc students, and several projects are already underway.

Linking industry demand and expertise with academic capability and skills will help create competitive advantage, not only for the oil and gas industry but for decommissioning challenges in the wider energy sector, for example, in offshore renewables. The NDC will also collaborate with R&D institutions and innovation centers across the country active in late life asset management and decommissioning, and partner with fishing, marine, safety, and environment organizations in the UK and internationally.

“The Centre will partner with industry and academia to deliver technology, share knowledge and provide thought leadership to reduce costs, extend field life, and challenge the conventional approach to decommissioning,” Colette Cohen, chief executive officer, the Oil & Gas Technology Centre, said.“With the global decommissioning market set to grow to £80bn over the next decade, we will work with supply chain companies and technology developers in Scotland, and across the UK, to help them develop the capability to meet domestic demand and drive export growth across the world.”

The NDC builds on the world-leading R&D capability at the University of Aberdeen in areas such as decommissioning technologies, predictive modeling, environmental assessment and the economics of decommissioning. “Our research programmes will nurture academic and technical expertise through Ph.D. opportunities that will anchor research talent here in the north-east of Scotland, while the University’s Masters programme and continuous professional development course in decommissioning will provide companies with the opportunity to upskill their staff,” George Boyne, principal of the University of Aberdeen, said.

“By building expertise at all levels – academic and within industry – we will create a competitive advantage for the oil and gas industry, and for decommissioning challenges in the wider energy sector, for example, offshore renewables.”

The NDC is home to the most powerful industrial laser at any UK academic institution, a state-of-the-art digital visualization and collaboration suite, and a supercomputer cluster enabling the fast simulation and modeling of innovative decommissioning scenarios. This includes facilities for technology trials and rapid prototyping, with a hyperbaric testing vessel that can simulate ocean conditions of 6,500m, an indoor freshwater immersion tank, environmental chambers for temperature testing from -40C to +180C and hangar space for the design and construction of decommissioning technology.

After Billion-Barrel Bonanza, BP Goes Global With Seismic Tech

Credit: Ron Bousso, Reuters

Buoyed by the success of seismic imaging that found an extra billion barrels of oil in the Gulf of Mexico, BP is looking to take its latest technology to Angola and Brazil. The software used in the Gulf, based on an algorithm created by Xukai Shen, a geophysicist straight out of Stanford University, led to BP discovering the crude in an area where it had long thought there was none to be found.

Industry experts said the scale of the discovery 8 km below BP’s Thunder Horse field, announced last week, marked a major leap forward for deepwater exploration – a costly business known for its low success rate and high risk. It is an example of how technology is helping deepwater make a comeback after a decade when the industry has focused on advances in onshore shale.

The new deposit was found with software known as Full Waveform Inversion (FWI), which is run on a super-computer and analyses reverberations of seismic soundwaves to produce high-resolution 3D images of ancient layers of rock thousands of meters under the sea bed, helping geologists locate oil and gas. It is more accurate than previous surveying methods, BP said, and processes data in a matter of days, compared with months or years previously.

While the discovery marked the biggest industry success for digital seismic imaging, the British oil major’s rivals are hot on its heel with similar techniques. BP scientist John Etgen, the company’s top adviser on seismic imaging, said it aimed to retain its edge with a new machine it has developed, Wolfspar, to be used alongside FWI. The submarine-like Wolfspar is dragged by a ship through the ocean and emits very low frequency soundwaves, which are particularly effective for penetrating thick salt layers that lie above rocks containing fossil fuels, he added.

Etgen told Reuters that BP planned to roll out Wolfspar alongside FWI in the second half of this year at the Atlantis field in the Gulf of Mexico, where a large salt layer still hides parts of the site. The company plans to expand the use of the technology to other big oil and gas basins, including Brazil next year and Angola at a later stage, he said. “Seeing through very complex, very distorted salt bodies was the hardest problem we had, the most challenging,” the Houston-based scientist said in an interview.

In both Brazil and Angola, oil deposits are locked under thick salt layers. Brazil’s deepwater oil fields comprise one of the world’s fastest-growing basins in terms of production. BP last year signed a partnership with Brazil’s national oil company Petrobras to develop resources there.


Billion-barrel oil finds are rare, particularly in mature basins like the Gulf of Mexico. But the scale of output from deepwater wells means they can compete with the most low-cost basins in the world, in particular U.S. shale. BP is far from alone in focusing on technology; all big oil companies have put a growing emphasis on digitalization to reduce costs following the oil price collapse of 2014. In fact, BP’s spend on R&D was the third lowest among the world’s top publicly traded oil companies in 2017 at $391 million, compared with Exxon Mobil’s $1.1 billion and Royal Dutch Shell’s and Total’s budgets of over $900 million.

Other majors have also made advances. Italy’s Eni has launched the world’s most powerful industrial computer to process seismic data, for example, while France’s Total is using drones to carry out seismic mapping in dense forests such as in Papua New Guinea. However Barclays analysts said in a report last year that BP and Norway’s Equinor had the most advanced deployment of technology among oil majors.


The seismic breakthrough for BP came when Xukai Shen tested a new idea he had for the FWI algorithm in 2016. “What happened was magic – the pieces came together,” recalled Etgen. “We finally had the right algorithm with the right data set to create the model of the salt formation and use the model to remove distortion.”

BP says its new seismic technology could save it hundreds of millions of dollars in exploration hours by pinpointing the location of the most promising deposits. “It allows us to drill the right wells, drill wells at lower costs, drill wells in the best part of the reservoir, drill fewer wells,” Etgen said. The costs of the technology are a fraction of BP’s oil and gas production budget of around $12 billion per year.

An FWI survey costs up to $20 million to carry out, while processing the data costs up to $10 million, Etgen told Reuters. The annual spend on the super-computer that runs the software is about $20 million. “The companies that are investing in technology are coming through and winning the race,” Henry Morris, technical director at independent North Sea-focused explorer Azinor Catalyst. “That’s where BP are doing a good job. It’s working.”

Seeing through salt layers with confidence “adds real value” and saves companies the premiums they must pay to acquire resources through acquisitions, according to Bernstein analysts. “With high-performance computing, the seismic processing and interpretations are being done in two weeks rather than 1,000 years, as it would have been if they still used 20th century computers. Investors should therefore expect more from BP with this edge.”

Enough UK Oil Reserves ‘For At Least 20 Years of Production’

Credit: BBC

The UK has enough oil reserves to sustain production for the next 20 years and beyond, according to a new industry report.

The Oil and Gas Authority (OGA) has estimated overall remaining recoverable reserves and resources of up to 20 billion barrels. However, it said significant investment was required in new field developments for untapped potential to be realised. The OGA said further collaboration between companies was also needed.

The report describes the UK’s petroleum reserves as remaining at a “significant” level.

Higher price

Gunther Newcombe, operations director at the OGA said: “OGA’s current estimate of remaining recoverable hydrocarbon reserves and resources from UKCS’s producing fields, undeveloped discoveries and mapped leads and prospects is in the range 10 to 20 billion boe (barrels of oil equivalent) plus.”

The OGA highlighted extended field life factors included lower operating costs and higher oil price. In September, official figures showed oil and gas production from Scottish waters had fallen by 1.7% after two consecutive years of growth.

They show that 73.7 million tonnes of oil, gas and liquid gas were produced in 2017-18, compared with 75 million during the previous year. However the value of the oil and gas grew by 18.2% to about £20bn, largely thanks to the rising oil price.

North Sea Oil and Gas Exploration Still Attracting Billions of Investment Dollars

Credit: Gaurav Sharma, Forbes

Stories about the demise of North Sea oil and gas exploration are aplenty. The mature prospect peaked in 1999 and admittedly its heyday has come and gone. However, every single prediction about its end of life date has been wrong.

Towards the turn of this decade, the only business uptick expected in the North Sea was a “decommissioning bonanza” in the eyes of many analysts. Instead, production rose as back-dated investment yielded incremental volumes of oil and gas.

That said, each time an international oil company decides to divest its North Sea assets, premature obituaries about the hydrocarbon prospect get dusted and queued up. So when Chevron said back in July that it wanted to divest most of its North Sea assets, the same familiar drill kicked into gear.

Except that fresh data, yet again, suggests North Sea exploration is alive and kicking, or in the eyes of some conservative industry forecasters – not quite dead yet. And it won’t be for sometime if industry data and projections from multiple sources are anything to go by. In its latest research, Westwood Global Energy forecasts that 17 exploration wells could be drilled on the U.K. continental shelf (UKCS) over the next 18 months, with a yield potential of over 2 billion barrels of oil equivalent (boe).

Admittedly, that figure is just over half of the wells drilled in 2008-09, but nowhere near an end-game scenario. Of the projected volume, over 50% is located in new West of Shetlands plays, and over 600 million boe in the Central North Sea, the U.K. consultancy says.

So far in 2018, operators have taken 11 final investment decisions (FIDs), adds Wood Mackenzie, another industry consultancy. More longer term and from a dollar valuation standpoint, the market would be looking at $43.1 billion worth of new North Sea project investment between 2018 and 2025, according to GlobalData. While Chevron, is heading to the door, the highest operating company in the North Sea – Norway’s Equinor (formerly Statoil) – has nine planned and announced projects in the said fiscal window.

Global data says of the projected $43.1 billion investment, around $18.9 billion is being spent to bring the planned projects online and $24.2 billion on key announced projects. Expected proceeds could contribute about 1,327.4 thousand oil barrels per day (bpd) of crude and condensate production, and about 1,924.4 million cubic feet per day (mmcfd) of gas production, the consultancy adds. In terms of the number of planned oil and gas projects by country, the U.K. leads with 11, followed by Norway and the Netherlands with eight and two, respectively.

As for majors shying away from the North Sea theory – BP has announced two fresh North Sea discoveries it is investing in. Shell has announced four positive North Sea FIDs in 2018 alone, including its decision to move ahead with development of the Arran field, alongside Penguins, Alligin and Fram prospects.

Finally, Total said last month it remains committed to the region following its natural gas find in the Glendronach prospect, in the West of Shetland. Whichever way you look at it, the North Sea continues to yield and defy predictions about its demise. Furthermore, call it necessity or clever fiscal policy, the U.K. government has of late tried to keep exploration competitive. Its fiscal measures in the 2015 and 2016 budgets reduced the tax burden on the sector significantly. Headline tax levies were cut from 62% for new prospects or 81% for mature producing fields to 40%. A 62.5% investment allowance was also introduced. All measures were maintained by U.K. Chancellor Philip Hammond on Monday (October 29) in his annual budget.

In light of the government’s current stance, Will Scargill, Oil  and Gas Analyst at GlobalData, believes the U.K. has “one of the most attractive fiscal regimes” for hydrocarbon production globally. “It offers the lowest discounted state take out of the top 50 producing countries. Therefore, the most important thing for the industry now is a stable investment climate conducive to long-term planning, particularly given the uncertainties already present through the Brexit process.”

It seems the decommissioning bonanza will have to wait for now.

The UK North Sea is Back with Successful Oil Licensing Round

Credit: Tsvetana Paraskova, OilPrice

The UK Oil and Gas Authority (OGA) awarded on Wednesday 123 licenses over 229 blocks or part-blocks to 61 companies in the 30th Offshore Licensing Round in the UK North Sea, expecting the round to lead very quickly to activity and boost exploration.

The new program commitments include eight firm exploration/appraisal wells, nine firm new-shoot 3D seismic surveys, and 14 licenses progressing straight to field development planning, the OGA said on Wednesday in what it said would be a “transformational” licensing round for the UK North Sea oil industry.

The latest round may help to unlock around a dozen undeveloped discoveries containing a central estimate of 320 million barrels of oil equivalent (boe) of resources in undeveloped oil and gas discoveries that were previously stranded but can now progress through further appraisal to field development, according to the OGA.

“The UKCS is back. Big questions facing the basin have been answered in this round. Exploration is very much alive with lots of prospects generated and new wells to be drilled. The results show a great diversity of active players from super-majors to new entrants, and the hard work promoting undeveloped discoveries is starting to pay off,” Andy Samuel, Chief Executive at the OGA, said.

Major companies and smaller firms won licenses in the 30th round, including BP, Shell, Chevron, ConocoPhillips, Total, Eni, and Equinor (formerly Statoil). Equinor alone picked up 9 new licenses, of which 8 as operator.

Related: OPEC Could “Relax” Production Cuts

Commenting on the round, Deirdre Michie, chief executive at industry association Oil & Gas UK, said: “We now need these opportunities to be pursued with a sense of urgency to help unlock activity for our hard pressed supply chain and ensure we start to mitigate the potential drop off in production post 2020.”

Kevin Swann, Research Analyst at Wood Mackenzie, told Energy Voice that Big Oil showed a vote of confidence to the UK North Sea. The analyst was excited that 14 licenses could move straight to field development planning. “The UK is in desperate need of new projects to fill a development pipeline that is all but empty beyond the early 2020s, and 14 new pre-FID projects could go a long way to rectifying that,” Swann told Energy Voice.