Aggressive recovery techniques will harvest most of Statfjord's oil and gas.
Statfjord field on the border between the United Kingdom and Norway played the role of cash cow, first for original operator Mobil and later for Statoil, and additional brownfield development plans will keep that 32-year-old tradition alive and thriving.
The goal: 68% of the oil in place and 73% of the gas in the original reservoir. The cost: US $2.54 billion. "This represents the largest and most complex offshore modification program we've ever pursued," said Bjarne Bakken, project director.
Statfjord already has recovered 60% of the original oil in place. The new strategy will allow it to increase gas recovery to 73%, compared with the 54% recoverable under the oil-production strategy.
Mobil discovered the field in 1974
and put it into production 5 years later. During that time, it added the Statfjord B platform in November 1982 and the Statfjord C in 1985. It passed the keys to the field to Statoil at the beginning of 1987.
Statfjord is the westernmost field in the prolific Tampen area, lying in Norwegian blocks 33/9 and 33/12 in Production License 037 and UK Block 211/25 in licenses 104 and 293. As part of a continuing program to extend production at the giant field, Statoil wants to keep the field on its cash-cow list until at least 2020.
That's where the Statfjord late-life project comes in. Statoil calls it a "commercially marginal" project, but it's marginal on a large scale. The field currently produces nearly 212 MMcf/d of gas and 180,000 b/d of oil.
To make the economics work better, Statoil embarked on a program to reorganize operations and increase efficiency to reduce operating costs by $109 million. It has completed that cost-optimization project a year ahead of schedule, but that's just part of the story. It will have to modify platforms and remap the production profile for the field to wring out maximum production value.
In all, the project will cost three million offshore hours over 4 years, and the company will handle the transformation while continuing to produce the field.
If everything works as planned, the field will increase total production by 1.13 Tcf of gas, 25 million bbl of oil and 60 million bbl of condensate, compared with continuing current operations.
Statoil already installed the building blocks for the transformation. "We have continuously monitored injection and production for allocation, mass balance, voidage and gas-oil contacts, and oil-water contact. This is supported by a comprehensive data sampling program in drilled new wells (logging program), existing wells (production logging, saturation logging, reservoir pressure, fluid quality and tracers in gas and water) and use of 4-D seismic," said Bakken. The company plans to continue using time-lapse seismic to track hydrocarbon volumes and movement during the remaining life of the field.
Gas injection, used as part of the water-alternating-gas (WAG) secondary recovery program in the field, left enough gas in place to make the late-life gas-priority program feasible.
Norway's Storting approved the project, including the Tampen Line pipeline system, on June 8 last year with the expectation that the three platforms would begin exporting gas through the Tampen Line to St. Fergus in the United Kingdom on Oct. 1, 2007, and platforms would be ready for low-pressure gas production late in 2009.
The first phase of the conversion is operating now and will continue into the second half of next year. This phase includes installation of gas lift and sand control in some of the wells and upgrading health, safety and environmental (HSE) standards and technical operations - including drilling operations - on the topsides of the platforms.
The second phase, from late 2007 until the end of 2009, involves the conversion of production equipment on the B and C platforms to treat both oil and gas under lower pressure.
Overall, the company will modify 70 of the field's 124 wells, including drilling sidetracks and re-completing wells with sand control and gas lift equipment.
Work on the processing facilities, in addition to accepting gas at lower pressure, includes debottlenecking.
That lower-pressure work involves upgrading and extending flow lines and manifolds to handle more producing wells, Bakken said. It also involves modification of injection hardware and flow lines to support the gas lift equipment for the new artificial lift program. Since part of the program includes depressuring the two main producing reservoirs, the gas lift will help keep the oil moving.
The field produces from three reservoirs, two Brent zones and the deeper Statfjord interval. The companies had planned to depressure all three to encourage gas production, but in June, Statoil (44.34%), ExxonMobil (21.37%), Norske ConocoPhillips (10.33%), Norske Shell (8.55%), BP Petroleum Development (4.84%), Centrica Resources (4.84%) and Enterprise Oil Norge (0.89%) decided to delay depressurization of the Brent reservoir for a year, until 2008. "This optimization will boost the oil production by more than 7 million new bbl from the Brent reservoir," according to a Statoil press release. It will not affect gas exports to the United Kingdom.
"Postponing the Brent reservoir depressurization is important to the field's value creation. This has a considerable positive net present value," said Lars Christian Bacher, senior vice president for the Tampen area.
Although that program will delay gas production, the company plans to increase gas production from the Statfjord zone, which will stay on schedule for depressurization. According to the company, production experience gave Statoil new information about the reservoir development and allowed it to further optimize Brent production.
Statfjord has been an oil-producing field with associated gas. The late-life program will make it a gas field with associated oil.
The company will lower the reservoir pressure to free the gas to move to
the well bores, which will be more gas-friendly because of the sand-control installations.
"When the reservoir pressure decreases, the liquid (oil and water) production will decrease from wells without artificial lift and without sand control completions. New wells will, in the beginning, be able to increase liquid production. The value of increased gas production will more than compensate for the loss of oil (caused by the depressurization)," Bakken said.
Part of the drilling planned for the project includes sidetracks to existing wells, he added. "When reservoir pressure decreases, the reservoir formation sand is weakened and wells may have to be choked back or shut down due to sand production unless corrective measures are taken. In addition, gas at high rates can not be processed if it contains sand, because erosion of the topside equipment and flow lines would be too high.
"Short sidetracks will be drilled to existing targets and longer sidetracks to new drainage points for gas and partly bypassed pockets of oil. If an old well sands up, the slot may be re-used sooner than in the original plan."
Asked if Statfjord would serve as a model for future projects, Bakken said this project is unique because of the long history of WAG injection. This project also contemplates continued production while the company changes the drainage strategy to primarily gas from primarily oil and while it is modifying the topsides of two of the platforms. The A platform already has been modified for low-pressure production.
Statoil can set out the plans, but in practice new challenges arise as it makes the necessary conversions. It has been able to meet those challenges.
This isn't the company's last project of this kind. "Statoil will pursue similar possibilities in other fields, but each field has to be treated on its own terms," he added.
For future efforts to improve the economics and extend the life of the field, Bakken said, "Statoil will work with lowering costs on topside facilities, maintenance and the overall processing cost from the fields in the area. Meanwhile, Statoil will develop new technology on the long range in order to be as robust as possible and realize gains from small targets. This will keep the field economic and may extend the life time beyond the planned time."

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