Operator envisions developing deepwater GOM with standardized equipment on sea floor, eliminating floating installations
By Katie Mazerov, contributing editor
Global exploration will be the primary growth engine for Statoil in the near term, and the US Gulf of Mexico (GOM) will play an important role in that strategy as the company looks to increase value through a balanced and prioritized portfolio and streamline drilling and well construction operations to optimize recovery.
“Going forward, exploration will be measured on the value it creates per barrel,” Jez Averty, Senior Vice President, Exploration North America, said at a media briefing on 24 March in Houston. “Our strategy has three main pillars: to deepen our position in our established core areas of the GOM, Norwegian Continental Shelf, Brazil, Angola, Tanzania and eastern Canada; drill high-impact wells; and secure early access at scale.” Alongside that strategy, the company will adhere to high-grading, capital discipline and prioritization in adapting to the changing realities of progressively challenging operating environments, he said.
“We have an opportunity-rich, geographically diversified and oily portfolio that is stronger than it was three years ago,” Mr Averty continued. Over the past three years, Statoil has discovered more than 3.9 billion BOE and made 11 high-impact discoveries in Canada, Norway, Brazil and Tanzania at a finding cost of $3/bbl, he said. Six new plays include a significant discovery, Flemish Pass, in offshore Newfoundland, estimated to hold at least 400 million bbl of recoverable oil. The company will use 3D seismic to firm up the value and has contracted the Seadrill West Hercules semisubmersible to commence an 18-month drilling campaign in Q3 2014.
In the GOM, where Statoil is strictly a deepwater player, the Martin, Perseus and Monument fields are the top three impact prospects, with exploratory drilling expected to begin this year in Martin and Perseus. The company is investing $1.5 billion annually in the deepwater Gulf, where it currently produces approximately 25,000 bbl/day, down slightly from last year due to divestments and natural decline, said Jason Nye, Senior Vice President, US Offshore.
Production projects include the prolific Tahiti field, now in phase two with Chevron as the operator, which produced 100 million bbl in 33 months using water-injection, and first phase of the Caesar Tonga field, where Statoil, with Anadarko, is looking to maximize value with phase two on the horizon.
Initial production from the Jack/St Malo project, Statoil’s first major foray into the Paleogene, will begin in Q4 this year with Chevron, with 170,000 bbl/day tied back to a large semisubmersible production facility. First oil from the Big Foot field with Chevron is expected in summer 2015, while the 6 billion bbl Julia field with ExxonMobil will tie back to Jack/St Malo and begin production in 2016. Heidelberg, with Anadarko, is being fast-tracked to begin production in 2016. Stampede, with Hess as 20% owner, is on track to be sanctioned later this year, with first oil anticipated in 2017.
Gas injection an option
Statoil is considering using gas injection for the new Vito field, with Shell as a 30% partner. “We have had a lot of experience with gas injection in Norway and believe we can at least double recovery in Vito due to the nature of the reservoir and the oil,” Mr Nye said.
Well integrity, particularly as it relates to barriers, plugs, cement, seat assemblies and other equipment, is a priority. “We haven’t seen many changes in the way we plan and execute our operations because our internal management system was already identical to the new (SEMS) regulations,” said Erik Kirkemo, Drilling and Well Engineering Manager, US Offshore.
Statoil also has achieved strong HSE results in the GOM with the Maersk Developer, a sixth-generation semi that has drilled as deep as 30,000 ft but could be taken farther, Mr Kirkemo said. “HSE is our license to operate, and we are working on that very seriously. We support HSE tools and procedures common with the drilling contractors we work with. Statoil has a rigorous approval process for our contractors. We like them to continue working with their systems, which gives us more confidence in their HSE results over time using long-term contracts.”
Deepwater GOM is more challenging to drill in than other basins due to water depths, higher pressures, faulted reservoirs, low permeability, greater uncertainty and challenging subsurface conditions that require maintaining the drilling margin above the pore pressure and below the fracture strength of the rock, he said.
Mr Kirkemo also noted that Statoil has designed an equivalent circulating density system, which includes a pump on the riser to protect the wellbore from pressure surges. The system will be installed on the Maersk Developer later this year.
Statoil also has adopted what it calls the Perfect Well concept to make drilling as efficient as possible through standardization, simplification and use of best practices. “Time is $1 million a day, and every day we can reduce on the well is important,” Mr Kirkemo said. “We take a 150-day delivery time, split it into many parts we call key performance indicators, and then set ambitious targets with step-by-step goal achievement for drilling the well.” The program has delivered 60% improvement every year since it was implemented, he said.
Through its “Cracking the Paleogene” project, Statoil envisions the ability to develop the GOM and other complex basins using standardized equipment installed on the sea floor, ultimately eliminating the need for floating installations.
“The program is targeting four areas: better mapping, enhancing production and recovery, reduced well costs and reduced development costs,” said Ola Gussias, Technology Manager, US Offshore for Statoil. “We are developing a toolbox for the entire value chain – discovery, drill and drain – with components already in place and some still under development. By implementing new technologies, we believe we can increase recovery in the GOM from 10 to 20%.”