Back on the upswing

Permian draws increasing attention in US; global markets resilient as Middle East, Russia, Europe seek modern, fit-for-purpose rigs

By Joanne Liou, associate editor

Steadily high oil prices – WTI oil continues to hover around $100/bbl – along with expanding opportunities around the world have drilling contractors, operators and analysts sharing a generally favorable outlook for the onshore drilling industry. In the eastern hemisphere, “it’s fair to say that there are more opportunities around the world than I have rigs to deploy,” Andy Hendry, KCA Deutag President of Land Operations, said. “Within the short, immediate term, it’s extremely encouraging.”

North America continues to lead the way in unconventionals as further improvements in drilling efficiencies are realized. Although the Permian Basin was once a declining area, “it’s a very active and rapidly growing unconventional play,” John Willis, Chief of Drilling at Occidental Petroleum (Oxy), said. One of the operator’s “biggest activities is growing the unconventional developments in the Permian,” with plans to double its rig count in the Permian within the next three years, from 27 rigs in early 2014.

Activity in North America also continues to shift to development projects in horizontal plays and tight formations. While development wells vary based on geographical areas, Latshaw Drilling has drilled a maximum of approximately 10,000-ft vertical and 10,000-ft horizontal. In northern Oklahoma in the Mississippi Lime play, wells are averaging from 5,000 to 6,000-ft vertical and 4,000 to 6,000-ft horizontals. Trent Latshaw, President of Latshaw Drilling, said he has no doubt industry will push those numbers higher. From North America to Russia, markets around the globe are at various stages of maturity, presenting room for growth and efficiency improvements.

Making the horizontal shift

Latshaw Drilling is one of the largest privately owned drilling contractors in the US, with a fleet of 41 rigs spread between the Permian and Anadarko basins, all of which are drilling for oil. “We’ve been putting some of our additional rigs that had been laid down back to work,” Mr Latshaw said, noting that his fleet utilization will reach 95% in Q2. “Pretty soon, we’re going to be out of rigs.”

Latshaw Drilling acquired Keen Energy Services in October 2012, “just as everybody ran out of budget money and had to shut rigs down. We got caught up in that because not all of our rigs were under term contracts,” Mr Latshaw explained. “In 2013, we were working through that, and people had new budget money, and oil prices actually stayed quite a bit higher than most people were anticipating throughout the year.” Activity started to pick up by late 2013, and Mr Latshaw said that trend has continued into 2014. “It has some more running room. I don’t think it’s a rocket ship to the moon by any means, but I think there is still some room for increase in activity.”

Dayrates are on the upside, as well. Mr Latshaw estimates dayrates have increased year over year by 10-15%. “They’ve been slowly increasing. For a 1,500-hp, top drive, walking rig, depending on the geographic area, the average we’re seeing is in the $21,500 to $23,500 range.”

In Q4 2013, Latshaw Drilling deployed two 1,500-hp newbuilds to the Permian Basin under one-year contracts. The SCR-powered Rig 19 is completing horizontal development work for Energen. Rig 42, an AC-powered rig, is drilling horizontal development wells for Laredo Petroleum. Both rigs are capable of walking, and each features a top drive, which has become a key enabler for horizontal drilling. “Almost 100% of what we’re doing is horizontal,” Mr Latshaw noted. “Every rig we have running has a top drive.”

Further, “the rig du jour is 1,500 hp,” Mr Latshaw stated. His fleet includes some 1,000-hp rigs that are essentially drilling the same wells as a 1,500-hp rig would, and “we also have some 2,000-hp rigs doing the same, but ideally everybody wants a 1,500 hp,” since the higher horsepower rigs typically have bigger – 1,600 hp – mud pumps, he explained. Another feature that operators are requesting is upgraded mud pumps, from 5,000 psi to 7,500 psi. The increasing use of downhole motors, rotary steerables and the wellbore hydraulics associated with horizontal drilling are driving the demand for this increase, he said.

Multiwell pad drilling also has made high mobility a necessity, not only for newbuilds but also for older rigs. This is true particularly for development drilling programs where there can be two to six wells per pad. “We’ve been retrofitting quite a few of our existing rigs to put walking systems on them,” Mr Latshaw said. His company now has 13 rigs with walking systems and 18 with skidding systems. “There are a couple more rigs we are currently putting walking systems on. That covers the majority of our fleet.”

Operators are also trending toward bifuel capabilities to make use of natural gas directly from the fields. “The operator, in most cases, is willing to pay to have the system put on rigs because it’s to his benefit of fuel savings,” Mr Latshaw said. For drilling contractors building new rigs, “it costs less than a couple hundred thousand dollars to put a (bifuel system) on a new rig that costs $17-$20 million,” he stated. So far, Latshaw Drilling has seen bifuel systems to be most prevalent in areas with ample dry natural gas. Further, “people now are pushing LNG for these rigs because if you have a bifuel-capable rig in an area that doesn’t have access to field dry gas, then they’re proposing to truck in LNG and putting a tank by the rig.” Four Latshaw rigs, including the two rigs that were deployed late last year, have bifuel engines, and the company plans to retrofit more.

Operations in the Permian

The bustling West Texas market continues to keep rigs busy. Of the total 1,778 onshore rigs working in the US as of 11 April, 536 were operating in the Permian Basin, according to the Baker Hughes rig count. Almost all are drilling for oil or liquids. Bandera Drilling has five rigs – two AC and three mechanical – that are all working in the Permian region. Ray Brazzel, President of Bandera Drilling, said he sees potential for expanding his fleet there in the coming year.

The two AC-powered rigs, newbuilds that began operations in May 2009 and March 2012, were designed for horizontal drilling and feature mechanization equipment such as an Iron Derrickman and an Iron Roughneck. The 1,150-hp rigs are capable of drilling to 15,000 ft and are operated from a climate-controlled driller’s cabin. Mr Brazzel said that, for any future newbuilds, he would likely continue to use technologies that remove people from the rig floor. He “would probably build a rig where no one was in the derrick, whether or not it be the Iron Derrickman or some other choices. The ultimate goal is to have no one in the derrick.”

Bandera’s mechanical rigs, which were built in 2006, are capable of drilling to 8,500 ft and have drilled horizontal wells to 13,500-ft measured depths, Mr Brazzel said. All five of Bandera’s rigs are on multiwell, development drilling contracts targeting oil.

Concerns surrounding endangered species is one of the biggest issues affecting operations in the Permian Basin, he added. “We fought the lizard last year, fighting the chicken this year, and I think there’s (more) coming down the pipe,” Mr Brazzel said. Bandera has joined other contractors, service companies and operators in support of the Permian Basin Petroleum Association to fund studies and gather scientific information to help guide the US Fish and Wildlife Service (FWS) in its decision to list animals as endangered.

IADC, along with nine other industry organizations, issued a letter in March 2013 to the FWS regarding the listing of the lesser prairie chicken (LPC) as a threatened species. FWS extended the final listing determination to March this year and recently designated the LPC as a threatened species. Mr Brazzel said the effects of the ruling are not fully understood yet.

“While this broad-based industry effort did not prevail in keeping the LPC from being listed as a threatened species, the final rule fell short of the endangered status many NGOs were seeking,” Bill Tanner, IADC Vice President – Government & Regulatory Affairs, said. “It was a disappointment to IADC and our member companies that the US Fish and Wildlife Service chose to ignore the substantial body of scientific evidence that bird populations were more impacted by natural factors, including cyclical drought conditions, more so than oil and gas operations. The concern now is that the listing affords NGOs with opportunities to further challenge oil and gas operations through the Endangered Species Act.”

Near the Permian, Mexico also is drawing increasing attention. The energy reform bill passed by Mexico’s legislature in December will be followed by secondary legislation addressing the framework for production-sharing and concession agreements. Mexico ranks sixth globally in technically recoverable shale gas reserves, with an estimated 545 trillion cu ft, according to a 2013 US Energy Information Administration report.

Mr Brazzel said he foresees the reforms eventually leading to a movement of rigs to Mexico, which could mean fewer rigs available in the Permian. Mark Plummer, CEO of Chestnut Exploration and Production, an independent operator based in Texas, also commented that Mexico could put pressure on the number of available rigs, leading to increased dayrates. “There would be some upward movement in the dayrates, especially with West Texas being so busy,” he said.

Chestnut’s primary operating areas are South Louisiana and East Texas, with some work spilling over into New Mexico. A full 80% of its portfolio is dedicated to oil. “In the last couple of years, we decided to expand and really get into developing plays in older basins like East Texas,” where dayrates have been averaging $20,000, Mr Plummer said.

The operator is drilling approximately one well per quarter in East Texas and prefers to pick up rigs on the spot-contract market for the flexibility of picking between contractors. Chestnut believes it is able to significantly reduce mobilization and demobilization costs if a contractor is transitioning a rig in its area. However, as Chestnut continues to grow and develop a continuous rig program, it expects to work with one company on a long-term contract. “By next year, we will probably be drilling one well a month, and at that point, we’ll start looking at longer-term, multiwell drilling contracts.”

In March, Chestnut contracted Energy Drilling’s Rig 7 to drill a horizontal oil well in Anderson County in East Texas. “We want to get fresh geologic information on the formation and then set a plug, come up the hole and go into our directional mode and drill a 3,200-ft lateral,” Mr Plummer explained. “For a 1,000-hp rig with 1,200-hp mud pumps and a top drive, we’re very pleased with the ($20,000) dayrates.”

He also expects rig demand to stay high for the rest of the year, with the price of oil hovering around $100/bbl. “The United States is one of the best places to drill and develop oil and gas reserves. The political environment is very stable. Property rights are well established, mineral rights are well established, and the infrastructure is in place,” he noted. “The beauty of drilling a horizontal oil well in East Texas is that there is infrastructure in place for services, for rigs and for production. The demand is just going to keep growing.”

California, in contrast, is not as favorable for operations, with high taxes and pushback from communities and environmentalists. Chestnut owns royalties in that state but does not currently operate there. “In California, high taxes and a government trying to squeeze more out of less seem to be creating an exodus both of people and of talent,” Mr Plummer said. He does not see relief in sight but retains the royalties in hopes of future opportunities. “When you look at the Signal Hill Basin in Long Beach, there’s a tremendous amount of reserves, and there’s a tremendous number of cars in California, so the need for oil is not going anywhere in California.”

Increasing budget, decreasing costs

In September 2013, California Gov. Jerry Brown signed Senate Bill 4, which will require oil and gas companies to apply for a permit to conduct well stimulation operations, publicly disclose fracturing chemicals used, notify landowners before drilling, and monitor groundwater and air quality. Interim well stimulation regulations became effective 1 January this year, and additional regulations from the bill will go into effect in July 2015. Click here to read more about the bill.

Oxy has had its headquarters in California since 1922. Regarding new state regulations, the operator has been able to comply and does not expect significant delays in its development plans, Mr Willis said. Approximately 40% of Oxy’s 2014 capital budget for California is for unconventionals and other developing plays.

In February, Oxy announced plans to move its headquarters from Los Angeles to Houston and spin off its California assets into an independent and separately traded company. “Creating two separate energy companies will result in more focused businesses that will be competitive industry leaders,” Stephen I. Chazen, President and CEO, stated in a news release. The new California-based company will be the state’s largest natural gas producer and its largest oil and gas producer on a gross-operated barrels of oil equivalent basis. The company will hold approximately 2.3 million net acres, making it also the largest oil and gas mineral acreage holder in California. Oxy will keep E&P operations in the Permian Basin and other parts of Texas, North Dakota, the Middle East and Colombia. The separation is expected to be complete by early 2015.

Oxy currently operates a fleet of 90 onshore rigs, including 67 in the US. Of those 67, approximately 30 rigs are in the Permian and 27 in California, up from 20 in 2013, operating in the San Joaquin Valley and the Los Angeles Basin. The company plans to drill approximately 1,050 wells in California this year, an increase from 770 in 2013. It also added approximately 15 rigs to its global fleet in 2013 and has added a few more rigs in 2014.

Specifically in the Permian, “we expect to double our rig count over the next three years,” Mr Willis said. The company estimates it will drill approximately 345 development wells there this year, slightly up from the 335 wells drilled in 2013. Oxy’s Permian operations are divided into two businesses: Permian Enhanced Oil Recovery (EOR) and Permian Resources, which is oriented toward growth in unconventionals. Oxy is shifting to more horizontal drilling and expects half of its wells in the Permian to be horizontal by the end of this year, which will require more advanced 1,500-hp rigs with 1,600-hp pumps. “Capabilities like big pumps and top drives are essential,” he said. “That trend will continue in the industry.”

Oxy increased its capital budget in the Permian from approximately $1.7 billion in 2013 to $2.2 billion this year. That increase is targeted specifically at unconventional activity, Mr Willis noted. Wells vary from 8,000- to 10,000-ft vertical depth and between 3,000- to 7,500-ft lateral length. Over the next few years, Oxy plans to shift much of its Permian operations to manufacturing mode, similar to its pad drilling operations in the Williston Basin. This means that, in addition to advanced drilling capabilities, “the ability to move rigs, either walking or skid-based rigs, will be needed for the multiwell pads.”

In 2013, Oxy’s operations exceeded its capital efficiency goals by reducing US drilling costs by 24% from 2012. The reduction was due to numerous efforts, including optimized well designs, faster rig moves, faster drilling times and improved contracting, Mr Willis said. “We drill with predominately PDC bits. You need torque capability, pump capacity, a well-designed bit and bottomhole assembly, and good operating practices to get maximum efficiency from PDC bits. That enables us to drill many hole sections with one bit,” Mr Willis said. Advanced, modular rigs also have reduced rig moves to between two and four days, compared with seven or more days for a conventional rig. Some smaller rigs can even move in less than one day, he said.

In the unconventional reservoirs, Oxy also is devoting more focus to completions, which are taking an increasing portion of the overall budget – up to half the total well cost – due to the number of frac jobs, he said. However, scrutinizing operational details is leading to improvements. “Our completions groups are optimizing the scheduling and the utilization of the equipment,” Mr Willis said. “They look closely at the specifications of the frac, the amount of proppant, the type of proppant and the fluids.”

Water is also becoming more of a challenge in the Permian and especially in California. “We’re using more produced water. We’re tracking how we use our water sources and certainly eliminating waste at every possibility.”

In the Middle East, Oxy has invested $9 billion since 2010, with 75% of it in Oman, Abu Dhabi and Qatar. Since 2010, the operator has drilled more than 2,500 wells in the region. “In Oman, we continue to drill development wells and some exploration wells. Oxy’s operations in that country are concentrated in south-central Oman in the Mukhaizna Field and in northern Oman in the Safah and Wadi Latham fields and Block 62.

Fit-for-purpose rigs

Operations in the Middle East are performing well for KCA Deutag. In Oman, the contractor operates seven rigs ranging from 750 to 3,000 hp and recently secured a contract with BP for the construction and operation of three fast-moving desert rigs. Bentec, a KCA Deutag subsidiary, will manufacture the rigs, and drilling is expected to commence in Q4 2014. The specification of the 2,000-hp, fast-moving rigs improves safety and drilling performance by optimizing rig power management and minimizing drive components, which will reduce the total drilling cost, Mr Hendry explained. The rigs feature 1 million-lb hookload, three 1,600-hp Bentec mud pumps and a 500-ton Bentec top drive.

“Transportation between rig locations is important. However, it is project specific in many cases. The actual component technology – the latest variable frequency drive, drilling information systems, brake force recovery in the power system, elimination of the auxiliary brake and brake cooling system, and bi-directional data access and control – which is designed and built by Bentec, provides the backbone with regard to efficiency and reliability of the rig package,” Mr Hendry said.

Besides the Middle East, KCA Deutag’s fleet of more than 60 land rigs also operate across Europe, Africa, Russia and Asia. Mr Hendry noted that expansions are planned for all these regions through newbuilds and possible acquisitions. The company’s rig utilization currently stands at approximately 95% and could reach 100% by the summer. This is a measurable improvement from 2013, when utilization ranged from the high-80s to the low-90s percentile, he said. As a function of tighter supply, dayrates also have appreciated since mid-2013. “The Eastern Hemisphere is very robust, and there’s a limited amount of fit-for-purpose equipment. When you’re at 100% utilization, pricing is going to go up.”

KCA Deutag’s onshore fleet ranges from 750 to 3,000 hp and varies from the desert rigs suitable for North Africa and the Middle East, which are often also suitable for tropical environments, to rigs designed for the Arctic. The company has 15 rigs operating in Russia, rated to -45°C. For components, simple things like the impact on lubrication systems requires a different level of engineering to be integrated into the entire drilling system, Mr Hendry explained.

New rig contracts also are in the pipeline for Russia this year, Mr Hendry confirmed. The aging rig fleet in Russia is creating greater demand and a requirement for modern assets. “Russia has a very large fleet, but it is, in general, an aging fleet that may not be technically capable of executing all of the more challenging drilling programs in the future. That has generated opportunities for Western rig components and manufacturers,” he said. The Russian market is experiencing an expansion of horizontal drilling in both conventional and unconventional applications. “The rigs’ pressure capacity, drilling depth capability and the requirement for top drives in preference to the older kelly systems all demand a step-change in the rig fleet.”

In Europe, “a lot of the design features are dictated by legislation with respect to engine emissions, noise suppression and the physical transportation of the rig between European countries, via roads in many cases,” he said. KCA Deutag’s European fleet is spread among five countries, with current operations in France, Spain, Albania, Germany and the Netherlands. In the past 12 months, the company has also operated in the UK and Poland. “The market is characterized by relatively short-term contracts, and the fleet is very mobile,” Mr Hendry said. “The major challenge with the European market today compared with 10 to 20 years ago is the contract duration. Operators, whether it be geothermal, oil or gas, are operating between a six to 18-month contract period. Newbuild rigs are in general commercialized over longer-term periods, but this remains a challenge in what is now a very fragmented market.”

Design specifications required in Europe, such as low noise emission at less than 80 dB(A) at 1 m from the worksite and transport dimensions less than 13 ft wide, 69 ft long and 10 ft high, can prove useful in other markets. “We spend a great deal of time and energy working on our component technology and rig designs, either newbuilds or modifications of our existing fleet, to provide fuel efficiency, low noise emissions and, in the case of newbuilds, small rig footprints – all of which has started to become more and more important around the world. Environmentally sensitive locations dictate the use of many of the features found on our European fleet. A lot of that European legislation and technology puts us in an ideal position to have a technical advantage moving into some of these new markets.”

KCA Deutag is actively looking at a market-entry strategy into East Africa, targeting Kenya and Uganda for exploration and appraisal drilling. “Given the need in Russia for increased technology, a robust and resilient Middle East market, environmentally sensitive rigs in Europe generating interest around the world, along with increasing activity in Africa, demand is robust,” Mr Hendry stated.

Upgrading rigs, efficiency

Similar to the Russian market, Romania is seeing demand for newer equipment. The Eastern European country continues to be a hot spot for drilling, and OMV Petrom currently has 12 land rigs and one offshore rig operating there. The rig fleet is evolving due to efforts to upgrade, including requirements for top drives and fast move capabilities. “With any new rig tender, we try to see if we can improve the quality of the rig we ask for,” Jaap van der Sijp, Well Construction Team Leader at OMV Petrom, said. For example, “some of the rigs might not have been suitable for oil-based mud, so we ask the drilling contractor to modify the drill floor and mud system to help prevent environmental spills.”

Romanian drill sites also present unique challenges. “Some locations are in hillsides and mountains, and locations can be very small,” Mr van der Sijp said. “We’re looking for fairly compact rigs that can be transported on small roads and sit on small locations.” Last year, the operator drilled 170 wells in Romania and plans to maintain that level of activity in 2014. Although the majority of those 170 wells were near-vertical – only 37 wells were highly deviated or horizontal – there is a strong drive to improve value efficiency in shifting operations to more deviated, horizontal wells. “Many of the reservoirs are quite thin, so it can be very effective to drill horizontal wells,” he stated.

OMV Petrom is also considering ultra-short radius (USR) wells for already developed, low-pressure fields. “We have so many vertical wells, so if we can use these vertical wells to drill short horizontal sidetracks, we could get more life from these wells,” he said. OMV Petrom is working with USR Drilling Services and plans to drill its first USR well in late July or August 2014. The radius of the hole is approximately 3 ½ in. and requires “running with a very short MWD with gyro in it and a kickoff tool,” Mr van der Sijp explained. The build section of USR wells have a build-up rate (BUR) between 100° and 250°/100 ft, while conventional horizontal wells have a BUR of about 4°/100 ft.

If successful, Mr van der Sijp sees opportunities to apply the USR technique to hundreds of vertical wells that have already been drilled in Romania’s older fields. “But we need to establish the technology, make people comfortable with it, and once we start doing it in volume, ultimately the cost of ultra-short radius will come down.”

OMV Petrom recently stepped up its efforts to improve and increase its drilling with casing operations, from eight wells in 2012 to 28 wells in 2013. So far OMV Petrom has only carried out vertical drilling with casing, but five of a total 50 planned drilling-with-casing wells this year are expected to be directional. “By improving the process with the service companies, drilling with casing now is competitive on its own compared to standard drilling” for sections less than 400 m, Mr van der Sijp said. OMV Petrom is able to save at least one day on a top-hole section, he explained, “because we don’t need to run the casing once we are at section TD.”

OMV Petrom has further optimized drilling with casing and has worked with service companies to modify a design of disposable bits that are left at the bottom of the hole, making the cost of the modified bits competitive with a normal bit. “Although there are costs attached to drilling with casing, the efficiency and cost-benefit of doing it is well worth the effort.”

This summer, OMV Petrom plans to implement its first directional drilling with casing project approximately 90 km west of Bucharest. The technology was selected for the well to lower the risk of drilling the 800-m section, Mr van der Sijp said. One of the challenges is the length of the casing, which is limited since the drilling is “done on a fairly small rig. On these small rigs, we have to use selected casing joints that are shorter than 10 m.”

On the upswing

Like the industry, analysts are sharing an optimistic outlook for the global onshore industry. “Efficiencies both by the operator, as well as the service providers, are really gaining some ground” in North America, Deborah Byers, Managing Partner at Ernst & Young, stated. The Marcellus is likely to draw additional CAPEX, she said, adding that “the Bakken will continue to be very strong, and the next basin people are interested in is the Permian.”

Mexico’s ongoing energy reform also is reminding the industry that the Eagle Ford play does not stop along the border of Texas. “We should expect to see a lot of interest from US independents, as well as from some of the big foreign players,” Foster Mellen, Senior Analyst at Ernst & Young, said. Further south, opportunities in South America could become more attractive “if there’s more positive economic financial reforms, which could lead to a ramp-up of onshore activities in Argentina and ongoing activity in Colombia,” Ms Byers said.

The next region likely to see an uptick in shale activity is China, both analysts said. The country boasts a centralized government that removes some obstacles, such as regulatory hurdles to hydraulic fracturing, and supports state-owned companies in China.

“It’s going to be a challenge, but we should start seeing more shale output out of China in the next couple of years,” Mr Mellen said. From near-zero in 2012, the Chinese are aggressively targeting shale gas production of about 6.5 bcm (about 0.6 bcf/d) by 2015 and 60-100 bcm (about 6-10 bcf/d) by 2020. (See Page 88 for more on China’s shale development.)

In Europe, Mr Mellen said there is still relatively little activity in the onshore sector. “Poland looked like it was going to be a big center of shale gas activity, but industry has been mostly disappointed,” Mr Mellen said. There has been a fair amount of shale gas drilling in Poland since 2010, but no well has yet flowed at commercial rates.

Three of the early main operators, ExxonMobil, Marathon Oil and Talisman, have pulled out due to disappointing results; however, Chevron has announced plans to partner with Polish Oil & Gas Company to pursue shale gas development, and ConocoPhillips is proceeding with its modest drilling program, Mr Mellen explained. While the government remains committed to shale gas development, there have been some complaints around regulatory delays and uncertainty.

In contrast, Mr Mellen noted, “industry is established in the UK with a supportive infrastructure, so if they can overcome politics there, operations should go forward.” A recent government report suggested that UK unconventional gas reserves could be as high as 5.3 tcf. That was followed in late 2013 by a tax proposal that would sharply improve onshore shale gas economics, he said.

Introduction of a new onshore pad allowance could improve the economics of costly unconventional developments in the UK. The pad allowance would operate similarly to existing field allowances, by exempting a portion of production income from the supplementary charge – reducing the effective tax rate from 62% to 30%, according to the HM Treasury, the UK government’s economic and finance ministry. The allowance is due to be passed in the 2014 Finance Bill.

GlobalData forecasts that the attractiveness of the incentive, along with promising resource estimates, are demonstrated by Total’s entry into two UK shale exploration licenses. In January, Total became the first major operator to enter into shale gas licenses in the UK. The operator acquired a 40% interest in Petroleum Exploration & Development Licenses 139 and 140 in the Gainsborough Trough area of the UK’s East Midlands region.

“(Total) is already involved in shale gas projects in the US, Argentina, China, Australia and, in Europe, in Poland and in Denmark, and will leverage its expertise in this new venture in the UK,” Patrice de Viviès, Total Senior Vice President for Northern Europe, said in a news release.

Total’s partners in the project will be GP Energy (17.5%), Egdon Resources UK (14.5%), Island Gas (14.5%) and eCorp Oil & Gas UK (13.5%). Island Gas will be the operator of the initial exploration program, with Total subsequently taking operatorship as the project moves toward development.