North Sea Oil: A Resurgent Benchmark Basin

Credit: The Intercontinental Exchange

Crude oil from the North Sea forms the basis for global oil prices and is the foundation of the Brent crude oil price. The durability of this price benchmark comes from its ability to reflect global market conditions and its seaborne capacity which means it can be transported to anywhere in the world. The discovery of North Sea oil marked a new era in Europe with the supply of light sweet crude oil for the first time. It was also the start of the region’s role in the global pricing of crude oil.

Since 2014, North Sea oil production has increased 16%, driven by production efficiency and new field start-ups.

The Discovery of North Sea Oil

The discovery of oil in the North Sea can be dated back to the mid-19th century. In the 1900s much of the oil and gas exploration took place in this area. However it was in the early 1970s that both United Kingdom listed and international entities began making significant North Sea oil investments. Parallel to growing production and the commercialization of related markets, came the ‘first oil price shock’ where oil prices quadrupled following the Yom Kippur war in the Middle East in 1973.

Two of the biggest North Sea oil fields, Forties and Brent, were discovered by BP and Shell in 1970 and 1971 respectively. Alongside Norwegian crudes Oseberg and Ekofisk, these two oil fields still form part of the BFOE (Brent-Forties-Oseberg-Ekofisk) basket of crudes that underpin the ICE Brent crude futures market today.

In the Norwegian sector of the North Sea, the large, commercial Ekofisk and Oseberg oil fields were discovered in 1969 and 1979. And although crude oil from Norway’s Troll field was only added to the BFOE basket in January 2018, it was discovered in 1979 with production commencing in 1995.

Today, Troll which is operated by Statoil, still produces more than 75,000 barrels a day which is a considerable amount of overall North Sea oil production. It remains one of the ten largest oil fields in Europe.

North Sea Oil Production Today

Despite a decline in some well-known North Sea oil fields, the region remains an important global oil producing region. New technologies, new discoveries and falling operating costs are making it easier and cheaper to extract oil from the region. Estimates by the UK Government’s Oil and Gas Authority for the total remaining recoverable reserves range between 10 and 20 billion barrels of oil from the UK continental shelf alone. Today, the BFOE basket of oils represents a daily output of around a million barrels per day.

Renewed Investment and New Discoveries

In recent years, the region has been buoyed by a new wave of discoveries, investment and technologies. North Sea oil has attracted investment from around the world with companies as far away as Asia announcing new projects to extend the life of some of the UK North Sea’s largest oil fields.

Since 2014, North Sea oil production has increased 16%, driven by production efficiency and new field start-ups. Operating costs in the North Sea have also almost halved since 2016.

New drilling technology has made it easier and more efficient to extract oil from the North Sea and in many cases new technology has extended the life of older fields by decades, making it possible to extract previously unreachable oil. Thanks to a wave of investment in the region, new fields are being discovered which are expected to significantly contribute to output levels in the coming years.

New Fields

In 2016, nine new North Sea oil fields began production (Laggan, Tormore, Conwy, Solan, Aviat, Cygnus, Alder, Crathes and Scolty) and several more began production in 2017 (for example, Schiehallion Quad 204, Callater, Stella, Shaw, Flyndre, Kraken and Cayley). An additional 12 fields are due on-stream by the end of 2018. The output from these new developments is expected to add a further 600,000 barrels of oil per day by the end of 2018.

New Technology

In 2017, Chevron approved investment to boost production from its Captain oilfield by using new technology which involves injecting polymerized water into an oil field’s reservoir, making it easier to tap reserves in areas that are difficult to reach with conventional drilling techniques. This will be the first time this technology has been used on such a scale in the North Sea and is expected to improve the recovery rate from older fields and help extend the life of existing assets.

Also in 2017, BP started extracting oil from the largest new North Sea project in recent years. The Quad 204 project uses new technology to redevelop the Schiehallion and the adjacent Loyal fields. This project is expected to unlock a further 450 million barrels, extending the lives of these fields beyond 2035.

New Investment

New technology, stabilizing oil prices and new discoveries have spurred investment and exploration in the region by a number of the leading energy companies.

In 2017, start-ups in the region surged to a 10-year high according to a report by Wood Mackenzie and recently there has been a renewed appetite for oil and gas assets in the North Sea. Total boosted its presence in the North Sea when it agreed to buy $7.45 bn of North Sea assets from AP Moller-Maersk in 2017.

New fields, such as the Johan Sverdrup field, and other recent significant discoveries in the North Sea are extending exploration and production in the region by decades. The Johan Sverdrup field is expected to add up to 3 billion barrels output over the next 50 years according to Statoil.

In Summary

New discoveries are driving the role of the North Sea and its leading position in global oil pricing. Established in 1988, the ICE Brent futures contract, is the world’s most liquid oil futures contract and has expanded since inception to include a family of more than 400 related Brent-based hedging instruments.

World Will Continue to ‘Gulp’ North Sea Oil, OPEC Chief says

Credit: David McPhee, Energy Voice

The world will continue to “gulp” North Sea oil despite the growth of other energy markets, according to the Organisation of Petroleum Exporting Countries’ (OPEC) chief.

Mohammed Barkindo, secretary general for OPEC, said that leading up to 2040 oil and gas will continue to account for 50% of the energy need worldwide, with North Sea oil an important part of that percentage.

Speaking at Dundee University’s annual Energy Forum, he said: “Despite all the occasional volatility and the challenges and the hype, the world will continue to gulp North Sea oil. What we’ve seeing in the North Sea, in particular here in Scotland, is the right path, not only in meeting current demand but also in the medium to long term. The future of hydrocarbons remains bright. The data and the signs support this. What we say and report in our outlook is all based on hard data and proven science.”

Mr Barkindo said that while he “commends Scotland” for its efforts in energy diversification, he said that OPEC figures show that renewables will still only account for 10% by 2040. But added that investment in alternative energy sources was necessary.

He said: “We will all continue to rely upon fossil fuels, but we do acknowledge that going forward we need all these sources of energy. That’s why we have not totally invested in just exploration and production, but also in these other sources – if we didn’t we’d be shooting ourselves in the foot.”

Giant North Sea Redevelopment Can Help End False Perceptions, says Former Oil Boss

Credit: Allister Thomas, Energy Voice

A giant North Sea project could help disprove false perceptions on redeveloping old fields, according to a former oil boss.

It was only last year that exploration drilling hit rock bottom in the UK sector with just eight wells drilled, the lowest level since the 1960s. However, late-2018 and early-2019 brought two large discoveries – Glengorm and Glendronach – which have made firms look again at the region, Nick Richardson said. He said: “It always helps when you’ve had a couple of big discoveries under your belt. I think they’ve served as a beacon to the rest of the industry that now companies have started to sit up and look at the North Sea again. They see that what was previously written off as a mature basin actually does have some big, impactful potential still sitting there.”

Jon Gluyas, a founder of Acorn Oil and Gas and Fairfield Energy, believes there is a wrongly held perception among geologists that a field’s performance is mainly determined by technical aspects, rather than company decisions.

Mr Gluyas, now head of Durham University’s Energy Institute, is advising Bridge Petroleum on Galapagos, a huge redevelopment of the North West Hutton and Darwin fields east of Shetland, thought to have around 900million barrels still in place.

North West Hutton changed hands several times over the years, including with Fairfield, and encountered a number of issues, including a material called barium which effectively “stuffed” the reservoir. Commercial decisions, such as a previous operator realising their mistake but not paying to rectify it, had a hand to play in its chequered past but Mr Gluyas believes the time could be right for Bridge to make it a success.

He said: “They’re approaching it in an extremely systematic way and I think if anyone’s going to make this work now is the time, with all the knowledge that’s been built up over the last 30 or 40 years developing in what is essentially a tight oil reservoir. A key point is there is a perception amongst geologists, geophysicists and reservoir engineers that the technical aspects of a field – the geometry, the quality or not of the rock, the viscosity of the oil – are complete determinants to the way a field performs. And they’re not.”

Glendronach, discovered west of Shetland in September by Total was, at the time, the biggest find in a decade. It could produce 175 million barrels of oil equivalent. It was then surpassed by Cnooc’s Glengorm discovery in the central North Sea, with potential for up to 250m barrels.

From an exploration perspective, they represent two very different prospects. Mr Richardson said: “Glengorm is something that has been sitting there and known about as a prospect for a long time, about 15 years. It has been through a number of hands in terms of different operators. A challenging well, but it finally got drilled and they could see there’s potential for a sizable discovery there.

“Glendronach on the other hand only came onto our radar relatively recently. Total had it mapped as a kind of concept and it was very rapidly put onto their drilling schedule. They drilled it and it looks very promising indeed, not just on its own but in terms of the potential for similar types of discovery that could be along that trend. The North Sea is great because it can encompass lots of different business strategies. You can be a relatively small company chasing undeveloped discoveries, a mid-sized company with producing assets or a larger operator where you need something that really does make an impact in terms of your global portfolio. These discoveries are particularly important from that perspective.”

These big finds come at a good time for the OGA. The regulator is on the verge of announcing its awards for the 31st licensing round, which focuses on frontier areas, and that’s ahead of launching the 32nd round later this year for mature regions. Mr Richardson said the 31st round has proved more popular than its last auction for frontier areas awarded in 2017. Along with the 31st has come a supplementary round for the Greater Buchan Area in the outer Moray Firth.

The region had some disappointment recently, when Equinor, Jersey Oil and Gas and Cieco found out that their Verbier discovery holds just 25m barrels of oil equivalent. They had been hoping for well over 100m barrels. Despite this setback, the OGA sees the area’s potential through a holistic approach.

Mr Richardson said: “We’re evaluating the applications and will make the awards as soon as possible. It’s certainly an area that we have high hopes for with Buchan as a hub and then the surrounding prospectivity and discoveries tied into it. I think this is the first step in a longer journey. It has demonstrated to us the value of taking areas thematically. Us doing some work, saying ‘this is our view as the OGA’ and then how we can then get industry to best act upon what we or they think should be done to maximise the potential in a particular area. I think industry can expect that in the future we might do similar types of things, maybe not as discrete rounds that exist within licensing rounds and say this is something we want to be tackled holistically.”

Drumming up interest and extracting value from mature areas has its own set of challenges which the OGA will need to contend with for the 32nd round. To do so, it is providing a suite of products with vast sums of information on the licences on offer across the UK sector, such as rock physics studies, a geochemical database and a “megamerge” with 23,000 square kilometres of seismic data on the southern North Sea.

Putting the data into new hands will bring new possibilities, according to Mr Richardson. He said: “I’m constantly surprised when you’ve got two different teams looking at the same area, and working independently they can come up with different ideas. By broadening the access to the data, you get that breadth of knowledge and experience which can bring out new ideas and concepts which can be exploited. By getting someone else to look at it you will find something different. It’s an interpretation, there’s no single version of the truth, and it very much depends on the individual scientist. The early wells on NW Hutton were good, but the last few did nothing at all because they basically stuffed the reservoir. The new programme needs to avoid some of those damaged areas.”

One of the ways that is best evidenced is through the life of the Argyll field – the first to produce oil in the North Sea – which has been redeveloped twice. Mr Gluyas’ firm Acorn Oil and Gas became the first company to ever redevelop a North Sea field when it picked up the licence for Argyll in 2002, which had been abandoned more a decade earlier. It would later be redeveloped again by EnQuest under a new name, Alma, which is still producing today. This was all possible due to the Hamilton Brothers, who won the race to produce the first North Sea field in 1975, abandoning it prematurely in pursuit of prospects elsewhere like Vietnam.

Another example is in Murchison, an oilfield where production peaked and troughed in line with the priorities of the firm who owned it at a given time. Mr Gluyas believes there are still opportunities in many regions of the North Sea, but it may mean more expensive methods.

He added:  “There are opportunities everywhere. From something like Lyle with five percent recovery in a really difficult reservoir, maybe up to some of the best-performing fields if you can install things like C02 enhanced oil recovery. It’s down to decisions in companies. Changes in strategy, the desire to move a production vessel from the North Sea to Vietnam, which then determines to a larger extent, I think than the technical aspects, how a field performs or whether or not it is worth redeveloping.”

Exploration: Do Not Write the North Sea Off

Credit: Allister Thomas, Energy Voice

New North Sea discoveries have acted as a “beacon” for the rest of the industry, according to the Oil and Gas Authority’s (OGA) head of exploration.

It was only last year that exploration drilling hit rock bottom in the UK sector with just eight wells drilled, the lowest level since the 1960s. However, late-2018 and early-2019 brought two large discoveries – Glengorm and Glendronach – which have made firms look again at the region, Nick Richardson said. He said: “It always helps when you’ve had a couple of big discoveries under your belt. I think they’ve served as a beacon to the rest of the industry that now companies have started to sit up and look at the North Sea again. They see that what was previously written off as a mature basin actually does have some big, impactful potential still sitting there.”

Glendronach, discovered west of Shetland in September by Total was, at the time, the biggest find in a decade. It could produce 175 million barrels of oil equivalent. It was then surpassed by Cnooc’s Glengorm discovery in the central North Sea, with potential for up to 250m barrels.

From an exploration perspective, they represent two very different prospects. Mr Richardson said: “Glengorm is something that has been sitting there and known about as a prospect for a long time, about 15 years. It has been through a number of hands in terms of different operators. A challenging well, but it finally got drilled and they could see there’s potential for a sizable discovery there.

“Glendronach on the other hand only came onto our radar relatively recently. Total had it mapped as a kind of concept and it was very rapidly put onto their drilling schedule. They drilled it and it looks very promising indeed, not just on its own but in terms of the potential for similar types of discovery that could be along that trend.

“The North Sea is great because it can encompass lots of different business strategies. You can be a relatively small company chasing undeveloped discoveries, a mid-sized company with producing assets or a larger operator where you need something that really does make an impact in terms of your global portfolio. These discoveries are particularly important from that perspective.”

These big finds come at a good time for the OGA. The regulator is on the verge of announcing its awards for the 31st licensing round, which focuses on frontier areas, and that’s ahead of launching the 32nd round later this year for mature regions. Mr Richardson said the 31st round has proved more popular than its last auction for frontier areas awarded in 2017. Along with the 31st has come a supplementary round for the Greater Buchan Area in the outer Moray Firth.

The region had some disappointment recently, when Equinor, Jersey Oil and Gas and Cieco found out that their Verbier discovery holds just 25m barrels of oil equivalent. They had been hoping for well over 100m barrels. Despite this setback, the OGA sees the area’s potential through a holistic approach.

Mr Richardson said: “We’re evaluating the applications and will make the awards as soon as possible. It’s certainly an area that we have high hopes for with Buchan as a hub and then the surrounding prospectivity and discoveries tied into it. I think this is the first step in a longer journey. It has demonstrated to us the value of taking areas thematically. Us doing some work, saying ‘this is our view as the OGA’ and then how we can then get industry to best act upon what we or they think should be done to maximise the potential in a particular area. I think industry can expect that in the future we might do similar types of things, maybe not as discrete rounds that exist within licensing rounds and say this is something we want to be tackled holistically.”

Drumming up interest and extracting value from mature areas has its own set of challenges which the OGA will need to contend with for the 32nd round. To do so, it is providing a suite of products with vast sums of information on the licences on offer across the UK sector, such as rock physics studies, a geochemical database and a “megamerge” with 23,000 square kilometres of seismic data on the southern North Sea.

Putting the data into new hands will bring new possibilities, according to Mr Richardson. He said: “I’m constantly surprised when you’ve got two different teams looking at the same area, and working independently they can come up with different ideas. By broadening the access to the data, you get that breadth of knowledge and experience which can bring out new ideas and concepts which can be exploited. By getting someone else to look at it you will find something different. It’s an interpretation, there’s no single version of the truth, and it very much depends on the individual scientist.”

UK Oil Production Up 9% In First Quarter

Credit: Tsvetana Paraskova, OilPrice

The UK’s crude and natural gas liquids (NGL) production increased by 9 percent annually to reach 1.18 million bpd in the first quarter of 2019, S&P Global Platts quoted statistics from the UK Department of Business, Energy & Industrial Strategy as showing on Thursday.  

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.  

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.

Edinburgh Oil Firm Sees Exploration Potential in North Sea

Credit: Mark Williamson, The Herald

CAIRN Energy chief executive Simon Thomson has said problems suffered with a big field off Shetland have not dented the firm’s enthusiasm for the North Sea where it sees the potential to make big finds.

Bosses of Edinburgh-based Cairn faced a grilling about the Kraken field east of Shetland at the company’s annual general meeting after cutting the valuation of the asset by $166 million (£130m) recently.

Read more: Cairn slashes valuation of flagship East of Shetland oil field

Noting production had lagged well behind initial expectations one shareholder asked what had gone wrong.

Mr Thomson said the heavy oil field had been plagued by production equipment issues. But he said Cairn has been making progress with partners towards improving the performance of the field, with production hitting 45,000 barrels per day yesterday. After the meeting he told journalists the problems did not in any way put Cairn off the thought of investing in other North Sea field developments. He pointed out that the Catcher field that Cairn has a stake in east of Aberdeen has been producing ahead of expectations.

Read more: North Sea heavyweight eyes growth as investment in giant Catcher field pays off

Mr Thomson noted that Cairn is generating huge amounts of cash from Kraken and Catcher. The company can use this to build on the success it has achieved as an exploration firm working in frontier areas. Cairn announced yesterday that it has acquired early stage acreage off Nicaragua in Central America. “It’s a real frontier play and therefore relatively high risk but it’s very interesting,” said Mr Thomson.

However, he stressed that Cairn reckons there is still exploration potential left in the well-worked waters off the UK. “One of the wells that I’m really excited about this year is Chimera in the UK,” said Mr Thomson. “It’s a big prospect, relatively high risk but if it comes in it’s extremely valuable.” Cairn sold a 40 per cent interest in Chimera to Suncor Energy last year and has had approaches from other potential farm-in partners.

The fact there is extensive production infrastructure in place in the UK North Sea increases the appeal of the area. Mr Thomson said 2018 was a landmark year for Cairn, which enjoyed a first full 12 months of production from its UK assets.

The company has funding in place to develop the giant SNE find it made off Senegal, from which first oil is expected in 2022. Mr Thomson noted Cairn has said it may look to realise some value from its stake in the field when a formal decision to proceed with the development is made by the firm and partners in the development. A Final Investment Decision is expected to be made in the second half of this year.

With Cairn expecting to start producing oil from the Nova field off Norway in 2021, the company should be well placed for growth regardless of the outcome of its long-running tax dispute in India. Cairn is seeking $1.4 billion damages from the Indian government.

Read more: Cairn Energy shares plunge after setback in Indian tax dispute

Mr Thomson said it was frustrating that the international arbitration panel that is considering the case is not expected to issue its findings until late 2019. However, Cairn’s confidence in its case is undiminished. Mr Thomson reiterated that Cairn expects to make a significant payout to shareholders if it wins its claim.

Kraken was expected to produce 50,000 barrels per day at peak when the field was brought onstream in 2017. Production last year averaged 30,300 bopd. The field is operated by EnQuest, which has not cut its valuation of the asset. The Catcher field is operated by Premier Oil, which increased its exposure to the North Sea amid the downturn triggered by the crude price plunge from 2014 to 2016. At Premier’s AGM on Thursday directors noted the potential to bring other finds in the Catcher area onstream.

Premier suffered a revolt on executive pay at the meeting, with 42% of votes cast opposing the company’s remuneration report. A spokesperson said yesterday: “The Remuneration Committee will analyse the voting outcome and will continue to engage with major shareholders to more fully understand their perspectives.”

Premier’s chief executive, Tony Durrant, has seen his basic pay frozen since 2014 with his total remuneration heavily dependent on the company’s performance. Cairn Energy’s remuneration report was approved by 96.1% of votes cast at the AGM.

Mr Thomson succeeded Cairn’s founder Sir Bill Gammell as chief executive of the firm in 2011. Cairn made bumper finds in India under Sir Bill. The Indian government launched a $1.6bn claim against Cairn in 2014, regarding events leading up to the flotation of its former subsidiary Cairn India in 2007. The panel considering the dispute in The Hague had expected to issue an award soon after the conclusion of the main merits hearings in August until procedural matters cropped up.

2019 Oil and Gas Exploration Off to Flying Start

Credit: Andreas Exarheas, Rigzone

Oil and gas exploration is off to a flying start in 2019, according to independent energy research and business intelligence company Rystad Energy. Global discoveries of conventional resources in the first quarter reached 3.2 billion barrels of oil equivalent (boe), Rystad revealed Monday in a statement sent to Rigzone. Most of the gains were recorded in February, which saw 2.2 billion barrels of discovered resources, Rystad highlighted.

Majors reported more than 2.4 billion boe of the discovered resources for the quarter, Rystad outlined in the statement. ExxonMobil was the most successful, with three offshore discoveries accounting for 38 percent of total discovered volumes. “If the rest of 2019 continues at a similar pace, this year will be on track to exceed last year’s discovered resources by 30 percent,” Rystad Upstream Analyst Taiyab Zain Shariff said in the company statement.

The total volume of global conventional discoveries in 2018 was 9.1 billion boe, according to Rystad. Total global conventional discoveries were 10.3 billion boe in 2017 and 8.4 billion boe in 2016.

No Signs of Slowing Down

In the statement, Rystad said the push for “substantial” new discoveries shows no signs of slowing down, with another 35 “high impact” exploration wells expected to be drilled this year, both onshore and offshore.

Rystad highlighted that three such wells are already underway; the Shell-operated Peroba well off Brazil – with pre-drill prospective resource estimates of 5.3 billion boe, Eni’s Kekra well in Pakistani waters -with pre-drill prospective resource estimates of 1.5 billion boe and the Total-operated Etzil well off Mexico -with pre-drill prospective resource estimates of 2.7 billion boe. “If these wells prove successful, 2019’s interim discovered resources will be the largest since the downturn in 2014,” Shariff stated.

Earlier this year, Rystad said improved market conditions and lower well costs had led exploration and production players to “ramp up” their 2019 exploration activities in all parts of the world.

“Renewed optimism in exploration activities is anticipated in 2019, with operators from various segments aiming for multiple high-impact campaigns – both onshore and offshore – in essentially all corners of the world,” Rystad Energy Senior Analyst, Rohit Patel, said in a company statement back in February. “These include wells targeting large prospects, play openers, wells in frontier and emerging basins and operator communicated high impact wells,” Patel added.

Rystad is headquartered in Oslo and has locations in Houston, Singapore, London, New York, Sydney, Moscow, Stavanger, Rio de Janeiro, Tokyo, Dubai and Bangalore. The company traces its roots back to 2004.

How 3D Seismic Imaging Revolutionized the Drilling Industry

Credit: Dome Energy

The oilfield industry over the past several years has been making vast leaps in drilling efficiency. These gains are not only tallied through advances in casing, drill string or cutting technologies but also through the unsung technologies that have been recently employed and of them, 3D seismic imaging has seen the greatest returns on investment.

Until very recently, the motto of the drilling industry was: Ready. Fire. Aim. There was no room for lost time. Through rather crude  geologic surveys (at least compared to modern techniques), drilling companies went into formations somewhat blind. Without full knowledge of reservoir characteristics, drilling was far more financially risky and a mortally dangerous endeavor. Further, even if oil or natural gas was able to flow from the reservoir, lack of information related to the exact hydrocarbon payout ran the risk of the well not being able to cover the the costs associated with the drilling operations.

This economic limit is where 3D seismic imaging has proved with worth. With full knowledge of the depths, pressures and reservoir payouts, drillers can now conduct their operations with more precision, safety and economic efficiency.

The Way It Was

Until 3D technology became for cost-effective for exploration & production and drilling companies, most opted for 2D imaging technology.

Otherwise known as reflection seismic, this technology resembled sonar and ultrasound technologies. By inducing acoustic waves into the geologic subsurface, geologists would be able to listen to the echoes returning from the stratigraphic boundaries and form a picture of the formation. These acoustic waves would typically be generated by underground explosive charges or by thumping the ground with a large mallet mounted on a specially designed vehicle known as a vibroseis truck.

The reverberations felt in the subsurface would be reflected back to the surface and would be “collected” using a special microphone known as a geophone. This data would be collect onto a magnetic tape and then transmuted into readable data via computers. As elementary as this process was, it was far more informative that going off of purely surface-oriented geological surveys. Though it was effective in proving subsurface reservoirs, its shortcoming was a lack of an articulate understanding of subsurface characteristics.

The Way It Is Now

Now companies like Dome Energy are cost-effectively implementing 3D seismic imaging  to prove the economics of a rather financially risky drilling process. 3D seismic imaging has shares similar technological hallmarks to that of 2D imagining but the differences between the two are undeniable.

The technology employs acoustics imaging but rather than one source of vibration, 3D seismic imaging involves creating a perimeter where multiple acoustic receivers, rather than microphones, are established. These areas for the receivers are known as patches. By capturing seismic shots that lie between two patches geologists and drilling companies obtain uniform reflection information from a subsurface area.  By changing the locations of each patch and repeating the vibration and recording process, companies accumulate overlapping subsurface readings which build a very articulate three dimensional picture.

3D seismic imaging doesn’t eliminate 100% of the exploration and drilling risk, it definitely improves success rates and productive wells.  The technology allows explorers and drillers with more pinpoint accuracy that goes to should deliver better production and a slightly longer well life. More importantly, 3D seismic imaging eliminates the possibility of drilling dry holes in the pool development process.

Brexit or Not, Britain’s Oil and Gas Business Is Booming

LONDON—Norwegian oil giant Equinor AS EQNR +0.53% A is doing something few companies have dared to do as the U.K. prepares to leave the European Union. It’s investing in Britain.

The state-backed energy company, formerly known as Statoil, has an ambitious plan for investments in the oil-rich North Sea, and, at a time when much of the U.K. economy is on ice, Equinor is hiring across Britain to support that plan.

British Prime Minister Theresa May responded to the triggering of a vote of no confidence in her leadership by members of her Conservative Party, saying that a leadership challenge at this time would complicate Brexit negotiations.

“How many companies ahead of March 29 are saying they’re recruiting and doing more in the U. K.?” said Al Cook, Equinor’s executive vice president for global strategy and business development, referring to Britain’s planned EU departure date.

While a chunk of Equinor’s current investment was committed well before Brexit became a reality in 2016, the company is hardly an outlier within its industry. In the past year, BP PLC,Total SA and Royal Dutch Shell PLC have all approved long-term projects off the U.K. coast.

The country’s once-stagnant oil industry has proved itself resilient to Brexit risk. Companies are expected to spend around $4 billion to develop the new projects announced so far this year, according to industry trade group Oil & Gas U.K.

Falling costs and a rash of asset sales following the oil-price crash in 2014 are contributing to a mini-renaissance in the U.K.’s oil industry. Rising crude prices for much of this year boosted activity across the sector, and many companies see projects in the U.K. as competitive despite the more recent market selloff.

Across the North Sea region, operating costs have roughly halved while production has increased by around 20% since 2014, according to Oil & Gas U.K. The upswing has included new players, many of whom view the export-oriented dollar-denominated sector as relatively immune to Brexit.

“I don’t think Brexit risk is as significant for the oil and gas sector as it is for others,” said Julian Regan-Mears, director of corporate affairs at Neptune Energy, a private-equity-backed oil-and-gas company that counts the North Sea as a core region.

The relatively relaxed attitude toward Brexit stems largely from the industry’s global nature. Oil and gas companies that operate in dollars are insulated from fluctuations in the pound that have been painful for other industries; and the price of oil is determined by global supply and demand and geopolitics, rather than the health of the U.K. economy.

“[Brexit is] not something we at Serica have even thought about,” said Antony Craven Walker, executive chairman at Serica Energy SQZ +1.39% PLC. The U.K.-based oil-and-gas company has transformed its position in the North Sea this year with acquisitions from BP, Total, BHP Group and Marubeni Corp. and has said it will hunt for more deals.

Still, Brexit isn’t without risk for the industry, which could face regulatory, logistical and recruitment headaches as the U.K. goes its own way.

“A messy Brexit would add complexity and probably cost to our industry,” said Gareth Wynn, communications director at Oil & Gas U.K. “At a time when we’ve worked so hard to remain competitive, that wouldn’t be helpful.”

Nevertheless, energy companies are willing to invest in the North Sea while other sectors are holding off due to Brexit. Economic growth has slowed since the U.K.’s Brexit vote in 2016, as uncertainty over the outcome has discouraged many businesses from making big investments. The FTSE 250 index, made up of domestically oriented U.K. companies, has fallen around 15% this year.

By contrast, shares in British-Dutch energy company Shell and U.K.-based BP have dropped only about 1% and 5%, respectively. An industry survey conducted by Aberdeen & Grampian Chamber of Commerce and released in November put business confidence among oil and gas contractors operating in British waters at its highest level since 2013.

A Sea Change: The Future of the North Sea Oil & Gas

Credit: Alan McCrae, PwC

As one of the oldest producing hydrocarbon basins in the world, the North Sea has been a major contributor to European economies for fifty years, but what can we expect that contribution to be in thirty or fifty years’ time? What does the future of the North Sea hold?

The window of opportunity is now

Set against the backdrop of the Wood Review and “lower for longer” oil prices, the North Sea oil and gas industry is undergoing a significant period of change. And as the pressures to transition to a lower carbon world mount following the COP21 initiative, this may suggest the basin’s days are numbered. Or are they?

We interviewed more than 30 senior stakeholders from the UK, the Netherlands and Norway, across the value chain in the North Sea. This report is the culmination of their insights and views on the state of play in the North Sea, alongside some potential solutions for sustainable success.

The general consensus is that the North Sea does have a future. However, a number of fundamental issues will need to be addressed in the next 24 months if the basin is to avoid a rapid and premature decline.

Potential

The North Sea is an exciting prospect play with potentially 20-30bn boe of undiscovered resources – particularly West of Shetland, the Atlantic Margin and on the UKCS/NCS border;

Window of opportunity

Some say there are 24 months to turn around performance. Time is of the essence if a suite of solutions can be deployed to rescue the basin;

Report card

Significant progress has been made with the Wood Review, establishing the Oil and Gas Authority, the favourable changes in taxation – but there is more still to do;

Collaboration

This is important but not at any price. It has to be to the mutual benefit of all parties despite the ingrained culture of the basin;

Need for leadership

The basin needs new ideas. It needs disruption and change at the same time as recognising the benefit of the existing wisdom and experience ;

Cost efficiency

It’s agreed that it’s essential to attack the cost base of the North Sea. Cost efficiency needs to be embedded irrespective of the vagaries of the oil price;

Deals

M&A activity has stalled due to the decommissioning liability issue, unnecessary complexity and lack of funding. However, deals are going through with innovative solutions;

Low carbon

This wasn’t top of mind for UK industry participants as they focus on cost reduction. In contrast, the responses from the Netherlands reflected a sector already planning an expansion of renewables post decommissioning.

The Super Joint Venture

The Super JV is an idea – a prompt for the industry to consider innovative and collaborative ways of working which reduce risk and increase cost efficiency, with the aim of making late life assets more competitive.

This idea has been met with widespread interest in the industry, but also a general feeling that the mechanics might be unworkable. In this paper we set out seven key steps for the creation of such a vehicle whilst outlining the elements where industry needs to work together to create a solution.

It’s worth stating that the Super JV may be one of many options for improving execution and cost outcomes, not necessarily the answer. But it is worth exploring.

Oil Field Services: Emerging from a downturn

How will the oilfield service sector emerge from the crisis to position itself for future success in a new world?

Oscar Wilde once said, “We are all in the gutter, but some of us are looking at the stars.” And to some extent that sentiment must resonate with many oilfield service (OFS) companies. The past two years has been a torrid time for the sector.

Now there appears to be light at the end of the tunnel. With supply and demand seeking a gradual equilibrium, the oil price has recovered a little. Among some companies there is a growing confidence that perhaps we have reached the trough.