GoM Figures Big in Statoil Strategy
Gulf of Mexico Bidders Focused
You’d have to call leasing in the Gulf of Mexico more focused than frenetic.
In August, the U.S. Minerals Management Service (MMS) said its latest leasing round in the western Gulf attracted about $290 million in high bids.
The lease sale offered 3,338 tracts offshore Texas and drew bids on 282 tracts, less than 10 percent of the total.
Geophysics apparently influenced the lease-bid decisions.
“Most of them are focusing in on plays in the Keithley Canyon and Alaminos Canyon that can be imaged fairly easily with depth-migrated data,” said David Cooke, an AAPG member who is MMS deputy regional supervisor, Resource Evaluation Office in New Orleans.
Other areas that drew bids included the expanse from Alaminos Canyon to north and west of the Perdido hub and the south part of Garden Banks.
“Data quality there will improve during the next 10 years under the lease cycle, so they can discover the new Jacks and the new Tahitis,” said Mike Prendergast, MMS section chief, Reserve Section.
Statoil Gulf of Mexico LLC far outdistanced all other bidders with 36 high bids totaling almost $138.9 million.
BP Exploration & Production Inc. followed with about $31 million in high bids.
Statoil assessed prospects worldwide several years ago and decided to re-enter the Gulf of Mexico with a strong presence, according to Øivind Reinertsen, Statoil senior vice president for Gulf of Mexico operations.
The company’s aggressive bidding in the recent lease sale tracked part of a four-part plan, he said.
“The first step was, we decided we should farm-in to some major operators, mainly to get access to data and to learn from them,” Reinertsen explained.
“Secondly, we said that we should try to make some bigger acquisition to get a flying start with respect to the deepwater and get access to a number of leases. We did that in 2005 and 2006,” he said.
In 2005, Statoil paid $2 billion for the deepwater Gulf portfolio of EnCana Corp. It got an average 40 percent working interest in 239 gross blocks, spread over 1.4 million acres.
Key assets in that acquisition included interests in the Tahiti development and the Jack, Tonga, Fox, St. Malo and Sturgis discoveries. Statoil now holds a 25 percent interest in Tahiti, as well as in the Jack discovery.
Last year, Statoil paid $700 million to Plains Exploration & Production Co. for additional interests in the Greater Tahiti area. It acquired a 17.5 percent interest in the Shell-operated Caesar discovery and 12.5 percent in Chevron’s Big Foot discovery and Big Foot North prospect.
The company then paid $901 million to Anadarko Petroleum Corp. to acquire a 25 percent working interest in the deepwater Knotty Head oil discovery and an additional 15 percent working interest in both Big Foot and Big Foot North.
Reinertsen said that the company’s third step “was to be very active in the lease sales coming up in 2007-08, because we knew there would be a turnover of leases in deepwater based on the lease grab back in 1997-98,” Reinertsen said.
Successful bidders had 10 years to begin drilling on their deepwater Gulf of Mexico blocks “and not much has been done to those leases,” he noted.
In planning its acquisitions and lease bids, Statoil decided to target a few promising, key areas.
“One of the main things in our strategy when we re-entered the Gulf of Mexico was to be very focused. If you look at our portfolio, we are strong in the Tahiti area, we are strong in the Walker Ridge area and we also are strong in the Great White area from the last lease round,” Reinertsen said.
So far, Statoil has partnered with other operators in the Gulf but expects to begin drilling prospects on its own within a year, explained Reinertsen.
“The fourth step is to operate on our own leases and that will happen next year,” he said. “We have contracted a new rig from Maersk presently being built in Singapore – that will come into the Gulf of Mexico by the summer of 2008.”
Reinertsen said Statoil was drawn back to the Gulf by the possibility of promising reserves and the political stability and open availability of the area.
As a third reason, he cited Statoil’s experience in offshore operations.
“Based on our experience from the harsh-environment, deepwater Norwegian continental shelf, we believe we have something to add to the deepwater Gulf of Mexico,” he said.
“We are one of the biggest operators of subsea production wells in the world, second to Petrobras,” he added. “We have developed a lot of new technology, like subsea processing. We have flow assurance. We have a pressure protection system that could be requalified from 500 meters to 1,500 meters.”
Statoil is in the process of finalizing its merger with the oil and gas arm of Norsk Hydro.
Both companies have extensive offshore experience and hold interests in the Gulf of Mexico. The companies have invested a combined total of about $6 billion recently in Gulf properties.
“Based on the successful project experience we have both from Statoil and from Hydro, I’m sure we can take on deepwater development here,” Reinertsen said.
To oversee Gulf operations, the company opened its Houston office in the summer of 2005 with three people. By October, the office will have 250 people after the merger of Statoil and Hydro closes.
“If you look at us after October, we will probably be second in the deepwater Gulf of Mexico after Anadarko in water depth more than 4,000 feet. Overall, we will be number four,” Reinertsen said.
Remarkably, Statoil has invested billions of dollars in 200 Gulf properties plus another 36 leases in the latest MMS sale, but will wait at least five years for any significant payday. Even the initial start-up production from Tahiti has been pushed back from its projected start month in 2008.
“We have a lot of discoveries that are going through the different decision gates,” Reinertsen said, “so I don’t think we will see a major build-up of production before 2012, in that range.”
Looking forward, he sees two major challenges to operating in the Gulf.
“First of all, it’s the subsalt,” he noted. “Everything is below the salt and to see seismic below the salt is a challenge, so you can be more precise in selecting drilling locations, etc.
“The second thing is the cost of the wells. A well in deepwater in the Gulf of Mexico today in this area costs more than 100 million (U.S.) dollars. And that is a challenge,” he said.
One answer to the cost challenge, according to Reinertsen, is developing and using new technology to make development more efficient, by having less expensive wells or fewer wells.
A joint Chevron-Statoil technology team was established in 2006 to explore technology options for development in the Gulf.
Reinertsen described it as “a group of people sitting together identifying what sort of new technologies we have in both companies, and how we can qualify this for the water depths we have here in the Gulf of Mexico. And also, what sort of new technology will be required.
“I think we have to look at new ways of developing fields,” Reinertsen observed.
“We are looking at hub solutions instead of only pursuing independent development,” he said, “as has been the case on the shelf and also the first part of the deepwater.”