Statoil discovers oil in Grane field in the North Sea

Posted on 05 June 2013

Statoil, together with partners in the Grane Unit, has made a new oil discovery in the Grane field in the North Sea.

Statoil and its partners are in the process of concluding drilling operations in exploration well 25/11-27 in the Grane Unit. Drilled by Songa Offshore’s Songa Trym semisubmersible, the well proved an oil column of 20 meters in the Heimdal Formation. The estimated volume of the discovery is in the range of 18 to 33 million bbls of recoverable oil.

“We are pleased with having proven new very high value resources in the Grane area,” Tore Løseth, vice president for exploration in the North Sea, said. “The oil discovery is located directly north of the Grane field and can be developed effectively.”

Timely near-field exploration is an important element in Statoil’s exploration strategy for the Norwegian continental shelf (NCS). This implies exploration close to existing installations that in the near future will have spare capacity for new tie-ins. “Near-field exploration is an important contribution in Statoil’s exploration portfolio on the NCS,” Mr Løseth said. “Even though volumes in these discoveries are moderate compared with the big finds over the last few years, these are fast, high-value barrels that are important for extending the production life of existing installations.”

In 2013, about 40% of Statoil’s exploration wells on the NCS will be near-field exploration. In addition to the Grane area, this includes the Oseberg, Fram/Gjøa and Tampen areas.

Exploration well 25/11-27 is situated in the Grane Unit in the North Sea. Statoil is operator with an interest of 36.66%. The partners are Petoro (28.94%), ExxonMobil Exploration & Production Norway (28.22%) and ConocoPhillips Skandinavia (6.17%).

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Statoil sanctions Julia development in GOM with ExxonMobil, pushes ahead with Logan

By Katherine Scott, associate editor

Speaking at the 2013 OTC, Jason Nye, senior vice president US offshore for Statoil, said the company is currently producing three fields in the Gulf of Mexico at approximately 40,000 bbls of oil/day but hopes to increase that number to approximately 200,000 bbls/day by 2020. Statoil recently also announced the sanction of the Julia field development with ExxonMobil.

Pursuing further growth in its US offshore portfolio, Statoil has sanctioned its fourth field development in the Gulf of Mexico (GOM). On 7 May, Statoil and operator ExxonMobil announced the sanction of the Julia field development; the partners each own 50%. “It’s about a $4 billion project for the first phase. I would have to say it’s one of the largest fields ever discovered in the GOM,” Jason Nye, senior vice president US offshore for Statoil, said on 8 May at the 2013 OTC in Houston. “It’s in the emerging Paleogene play, so we decided to do a phase development to reduce some of the risk because it hasn’t been widely drilled or widely produced.”

The first phase will consist of six wells, he said, and drilling operations are expected to start in 2014 and first production in early 2016. “This field is going to be producing for decades and decades, and there will be multiple phases. It’s also going to be a fantastic place to utilize some technology we’re developing and have developed going forward to extract more oil from those reservoirs.” The life of the Julia field is estimated to be up to 40 years, with an initial production rate of as much as 34,000 bbls of oil/day.

The field, located approximately 200 miles south of New Orleans, La., was discovered in 2007 and is estimated to have nearly 6 billion bbls of resource in place. The field development is projected to take approximately three years.

Julia, which is in some 7,000 ft of water and 30,000 ft under the seafloor, will be a subsea tieback to the Jack and St. Malo floating production platform, where Statoil is a co-owner with Chevron, Mr Nye said. The Jack and St. Malo platform is approximately 15 miles from Julia and was sanctioned in 2010.

Further, Statoil is pushing forward with operations in the Logan field, another Paleogene discovery and the company’s first operated discovery in the Gulf of Mexico. The company used the ultra-deepwater semisubmersible Maersk Developer to drill one well in the Logan field, which is currently in the appraisal phase, Mr Nye said. “With that one well, we’ve proved out somewhere between 1 and 2 1/2 billion bbls in place.”

With the block’s lease expiring in April 2015, Statoil has put together a tight schedule to develop Logan. “We expect to have first oil as early as 2018. This could be a stand-alone or a tie-back; it’s an interesting neighbor with some other discoveries.” Statoil will spud Logan’s appraisal well within the next week, again using the Maersk Developer, he said on 7 May, and in about 90 days will know whether to will move forward with project, though the company is very optimistic about the prospects.

Statoil currently has 340 leases in the deepwater GOM and 12 projects, operating in both the Miocene and Paleogene plays. The Miocene is more traditional, Mr Nye said, with high recoveries and high initial rates. The Paleogene play has deeper reservoirs in 7,000 to 10,000 ft of water and reservoirs at 30,000 to 31,000 ft under the seafloor. “I’d say we have a balanced portfolio because we’re evenly mixed between the more mature Miocene and the emerging Paleogene. And we have a significant presence in some of these emerging plays. (Industry has) been producing in the deepwater GOM since the ‘30s, but new plays are coming about, and we’re still finding new things.”

Statoil entered the GOM market in 2004 when the company was looking for areas with significant resource potential, Mr Nye said. “We have a long history of working in challenging and difficult environments, and we felt right at home here in the Gulf of Mexico.”

In addition to its four field developments, the company has three producing fields in its GOM portfolio, including Spiderman, Caesar Tonga and Tahiti. The three fields are currently producing at approximately 40,000 bbls of oil/day total, he said, but Statoil hopes to increase that number to about 200,000 bbls/day by 2020.

On the technology side, Statoil is pursuing a program known as “Crack the Paleogene,” which is focused on developing a tool kit of nearly 20 technologies, including electrical submersible pumps, multilateral technology, and water and gas injection. By applying these technologies, Statoil hopes to increase recovery rates from typical GOM fields from less than 10% to more than 20%, Mr Nye said. “The Gulf of Mexico has been a place where technology has been kind of the leading edge and push the envelope into deeper and deeper water and reservoirs.”

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Fit-for-purpose rigs, unconventionals drive Statoil production goals

By Joanne Liou, editorial coordinator

Statoil is directing its fit-for-purpose rig fleet and technology strategy to help reach a production goal of more than 2.5 million boe/day by 2020, up from 1.9 million boe/day in 2010. Noting recent successes in increasing the average oil recovery rate from Statoil-operated fields from 49% to 50%, the company wants to push that percentage even higher, Karl Johnny Hersvick, Statoil senior vice president of technology excellence, stated. The company outlined its growth strategy in a series of press conferences at the 2012 OTC last week in Houston.

Jon Arnt Jacobsen, chief procurement officer at Statoil, and Oystein Arvid Haland, senior vice president drilling and well, discussed their company’s shift from fixed platforms to using mobile rigs to drill subsea wells. In collaboration with Aker Solutions, Statoil’s Category B rig is under construction, with delivery of the first unit expected in the second half of 2015. The rig design fills the gap between light intervention vessels (Category A, which has been in operation since 2003) and conventional rigs (Category C), according to Statoil. The rig is designed to improve oil recovery, and its design has been optimized for heavy intervention and light drilling in existing wells.

A Category D rig, targeted for mid-water production operations, also is under construction and expected to be delivered in 2014 to 2015, while Category J is designed for shallow waters and harsh environments. The latter is expected to be delivered in 2015 and will provide 20% more cost-effective well construction.

Statoil’s developing rig fleet is compounded with the company’s focus on four areas: seismic imaging and interpretation, reservoir characterization and recovery, efficient well construction, and a “subsea factory.” The subsea factory project involves the development of the Åsgard subsea gas compression by 2015 and acquiring all the necessary elements for a subsea process facility on the seabed to accelerate production. “Our mission is that technology connected to (reservoir recovery) will contribute to increase an additional 1.5 mboe/d by 2020,” Siri Espedal Kindem, senior vice president of research and development, said. “Just as important is a step-change in well construction efficiency. We have a clear ambition ahead to reduce the time we spend on well construction by 30% and 15% in spending.”

Statoil currently has about 3,000 employees working on 300 increased-oil-recovery projects. In August, the research and development division will become the research, development and innovation division, Mr Hersvick stated. “It’s a concrete measure to get our hands on more good ideas, to push recovery rate even further. We cannot compete with supermajors of this world when it comes to funds and resources, but we can and we will compete when it comes to innovation.”

Statoil expects 12% of its portfolio to come from North American unconventionals by 2020, Torstein Hole, senior vice president of development production North America – US onshore, said.

Moving onshore, Statoil expects 500,000 million boe/day to come from North American unconventionals by 2020, Torstein Hole, senior vice president of development production North America – US onshore, said. The company’s strategy for growth in US shale plays is founded in its presence in the Marcellus, Eagle Ford and Bakken, with the Eagle Ford paving the way for Statoil’s operatorship. Statoil entered a 50/50 joint development agreement with Talisman in 2010. With 165,000 net acres and 12 rigs currently drilling, the play has produced about 640 million boe to date. Statoil is positioned to become operator within that play by the end of 2013.

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