By Katherine Scott, associate editor
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.”