Statoil may not have the biggest R&D budget, but company officials say the operator's technological track record on the Norwegian continental shelf will help it push recovery rates to new highs and create the first subsea factory, including seafloor separation, by 2020. In this opener to OE's Scandinavian offshore industry review, Russell McCulley talks to Statoil's Astrid Sorensen about the company's efforts to leverage its experience offshore Norway to crack the Paleogene in the Gulf of Mexico.
Statoil has set a production goal of 2.5 million boe/d by the year 2020, up from a current 1.9 million b/d, a target the company plans to meet not only by shoring up reserves but by applying technologies to better characterize reservoirs and boost recovery rates. A long history on the Norwegian continental shelf where Statoil has embarked on a number of projects to breathe new life into aging fields gives the company a leg up, officials say. As Siri Espedal Kinden, senior VP technology, put it at this year's Offshore Technology Conference in Houston: We cannot outcompete our competitors when it comes to both resources or on spending. But we can compete with our ability to innovate, to collaborate, and the courage to take technology into work.
The end of the decade is a significant marker for Statoil in other ways: 2020 is the target date the company has set to develop a subsea factory for seabed operations, including subsea compression, which Statoil hopes to achieve by 2015. The closer the compressor is to the well, the higher the efficiency and the production is, senior VP of R&D Karl Johnny Hersvik told an audience at OTC. The subsea factory concept is actually a process facility on the seabed. That makes it possible to use remote control transfer of hydrocarbons to any facility. It has compact separation facilities on the seabed. This will be a key success in both Atlantic and Arctic waters, he said.
With the startup of the Anadarko-operated Caesar/Tonga project, in which Statoil holds a 23.55% stake, Statoil's offshore US Gulf of Mexico production is running about 50,000boe/d, up from 37,000boe/d in 1Q 2012. By 2020, the company aims for US offshore production to reach more than 100,000boe/d and overall North American production to climb to 500,000boe/d. Upon government approval of Statoil's high bid on 26 leases in the 20 June Central Gulf of Mexico lease sale including Mississippi Canyon Block 718, for which Statoil paid US$157.1 million, the sale's highest single bid for a tract the company will hold interests in more than 350 leases in the Gulf, including the recently sanctioned, Chevron-operated Jack/St Malo, Big Foot and Tahiti phase two developments. Statoil has an interest in six producing fields and is involved in the appraisal concept phase at five other deepwater prospects: Julia, Vito, Knotty Head, Heidelberg and the Statoil-operated Logan field.
Almost three years ago, the company set out to develop a toolbox to increase production from Paleogene reservoirs in the Gulf of Mexico. The effort involves some 20 separate projects applying proven technologies in four main areas: imaging and reservoir description, reservoir drainage, well and completion design, and facilities. Statoil field development VP Astrid Sorensen, who is based in Houston, says the project is about half complete.
Paleogene reservoirs have significant volumes in place, Sorensen says, but are tight reservoirs characterized by lateral heterogeneity and fairly dead oil, or little gas, and thus low recovery rates. Statoil's toolbox aims to increase recovery from a rate of less than 10% to more than 20%. A significant part of the Crack the Paleogene program will adapt technology skills honed on the Norwegian continental shelf to water and reservoir depths and characteristics found in the deepwater Gulf of Mexico. This is the kind of challenge that Statoil is good at, she says.
Among our strengths are our capabilities as an organization to implement new technology and manage the associated risk we have a long history of achieving this on the NCS.
Water and gas injection techniques hold perhaps the greatest promise in the tight Paleogene plays, and are methods that the company first implemented in the 1980s, Sorensen says. Statoil has a long history of applying these technologies on the Norwegian continental shelf, in fields such as Gullfaks and Oseberg. Water or gas injection adds energy to the reservoirs, she says; the characteristics of each field will determine the secondary recovery technique employed there, whether water injection, CO2, methane, nitrogen or even air; what is available, what can be injected, she says. "I think this can be a game-changer in producing oil from these very difficult Paleogene reservoirs."
Another door-opener, as Sorensen puts it, is multilateral drilling. It is extremely expensive to drill deepwater wells, she says. Again, this is a technology where Statoil has a lot of experience. We have drilled more than 150 multilateral wells, including some on the NCS Troll field that have as many as seven branches. At Oseberg, the company has set junctions as deep as 6900m into the well. To reduce the investments, we plan to drill multilateral wells, where two wells can be drilled for the price of 11/2, she says.
Statoil is running dual-gradient drilling pilots in Norway, and field partner Chevron plans to drill a dual-gradient well at Big Foot. The beauty is that we can use wells on the NCS to test and qualify new technologies both relevant for the NCS and Gulf of Mexico, Sorensen says. In a short time we will also be able to use selected US onshore wells for testing of new technologies.
Statoil is also working to develop more efficient subsea and downhole pumping systems. The company has deployed downhole pumps at the Statfjord field and Peregrino development offshore Brazil, and seabed pumps at Gullfaks, among other sites. Electrical submersible pumps are traditionally run in tubing, which requires a rig to perform well interventions when a pump, with a life expectancy of two to three years, runs its course. Statoil is developing an approach that will run ESPs on a wire that also includes a power supply and can be retrieved by a vessel other than a more expensive rig. The company also hopes to modify pumps for use at increased pressure up to 15,000psi and to increase durability to give the hardware a life expectancy greater than five years.
We are also looking at the possibilities of extreme drawdown as we produce from these reservoirs going from the current 15,000-plus psi to something below 5000psi, Sorensen says. This requires the development of new materials that can withstand the pressure differentials.
Other technology initiatives focus on heating and insulating multiphase flowlines to transport hydrocarbons greater distances subsea, improved subsalt imaging and reservoir description, and single-trip multi-zone frac packs, which can cut completion time and costs by performing completions in one trip down the hole. The technique is being used at Jack/St Malo and will likely be used at all of Statoil's Paleogene completions, the company has said.
We have built a quality portfolio across several plays and across varying maturities, from exploration through production, Sorensen notes. We are very active on the exploration side. We are in many, if not most, of the current big developments in the deepwater Gulf of Mexico.
While production at Statoil-operated fields in the Gulf of Mexico may be some years off, we see several advantages in playing a supporting and collaborative role in non-operated projects, she says, working closely with other producers to share knowledge and build competence and trust, and develop technology to increase recovery, safety and efficiency. It's Statoil's way of doing business. OE