Norsk Hydro used technology applied and honed at its Troll and Oseberg fields offshore Norway to maximize recovery from Grane, the Norwegian North Sea’s heaviest oil field.
In many respects, Grane field, in Block 25/11 of the Norwegian sector of the North Sea about 115 miles (185 km) west of Haugesund, is a beautiful reservoir.

It lies in 420 ft (128 m) of water at a total depth of 5,578 ft (1,700 m). The 10-sq-mile (27-sq-km) reservoir has an average pay thickness of 164 ft (50 m) with an average porosity of 33% and average permeability of 5 to 10 Darcies.

Grane field is the first heavy oil reservoir in the Norwegian sector of the North Sea. (All photos courtesy of Norsk Hydro)
One of the stumbling blocks is the 19°-gravity oil that flows reluctantly, even through the high permeability. Another sticky situation is that the water drive communicates with other fields in the area and that doesn’t leave much pressure to drive the heavy oil at Grane to wells. In addition, the migration noise created by the broken-up top Cretaceous layer made mapping the reservoir a significant challenge.

The interspaced sands and calcite intervals made drilling difficult, hole integrity touchy to maintain and seismic often hard to interpret. Challenges included lost-circulation zones, unstable wellbore walls, displaced completion fluid, reduced production because of incomplete well cleaning and plugging of sand screens on several wells.

Changing design

Still, the field did have an estimated 700 million bbl (110 million cu m) of proven + probable (expected) reserves, and it could produce up to 214,000 b/d (34,000 cu m) of oil under the plan originally devised for the field and put into effect when Hydro drilled its first vertical well in 2003.

That plan went through a radical transformation with advanced technology, starting with the drilling of the first horizontal well in the field March 2006 and a new production plan. Reserves jumped to 755 million bbl (120 million cu m) of oil, and Hydro already saw peak production of 243,000 b/d (38,600 cu m/d) of oil on March 10. The company anticipates 55% recovery from the field.

That makes the field a third the size of Oseberg and twice the size of Brage.

Management

Øisten Bøe, head of technology and competence at Hydro, defined reservoir management from Hydro’s point of view, as “the process of maximizing hydrocarbon recovery from an asset in a smart and cost-effective manner. For huge offshore developments with large investments and large modification costs, it is important to address reservoir management issues in the field development phase. By early addressing future reservoir management issues, one can more easily ensure flexibility for future optimal hydrocarbon offtake.”

Hydro planned to use horizontal wells at Grane from the start, backed by solid knowledge of the reservoir characteristics and experience at Troll and Oseberg. Field managers now plan 11 multilateral production wells by 2010. The laterals will extend horizontally in different directions within the Heimdal sand.

Grane had no gas cap and little drive from the underlying water. Under the new plan, gas would have to be imported. In addition, the heavy oil was more conducive to water and gas coning than the lighter oils Hydro produced in other fields.

Experience counts

The Hydro planners looked at giant Oseberg field. That field had anticipated reserves of 1 billion bbl (159 million cu m) of oil in 1983 based on calculations using water drive.
Later in the 1980s, studies show that the Oseberg reservoir would produce more with gravity-stable gas displacement using gas imported from Troll field and injected into the Oseberg reservoir. Planners ended up with a plan that uses gas injection with some flank water injection late in the life of the reservoir. The gas injection also improved economics in the north end of the field, and the injection project increased reserves by as much as 314 million bbl (50 million cu m).

Again, based on increased understanding of the reservoir, the company took on the complex Ness fluvial channel system with horizontal wells, smart wells and advanced completions. The horizontal wells increased reserves by as much as 157 million bbl (25 million cu m) more.
Horizontal wells and gas injection help Hydro get the highest returns from the Grane heavy oil field offshore Norway.
Hydro experts now expect Oseberg to recover some 2.2 billion bbl (350 million cu m) of oil.
They also looked at giant Troll gas field, a huge field that might not have been commercial with standard vertical wells because of the thin oil zones. There they conducted two long-term tests with 1,640-ft (500-m) horizontal laterals in an 88-ft (27-m) oil column followed by a 2,625-ft (800-m) horizontal section in a 43-ft (13-m) oil column. That field now has more than 150 horizontal wells, many with as many as seven branches.

The learning curve the company conquered to successfully drill and complete 9,843-ft (3,000-m) horizontal wells with sand screens from offshore rigs took 15 years of learning and technology, but it raised Troll’s reserves from nearly nothing in 1986 to approximately 1.5 billion boe (238 million cu m equivalent) today.

Lessons applied

With those technologies firmly in hand, Hydro went to work on Grane’s Tertiary turbidite reservoir, starting by importing injection gas from Heimdal field 31 miles (50 km) away. For this development, learning and technology from the Oseberg and Troll projects has been important. Long horizontal wells (learned from Troll and a long-term test at Grane) now are located 30 ft (9 m) above the oil-water contact.

The immiscible gas injection provides pressure to move the heavy oil. The horizontal wells provide a distributed outlet for the oil to minimize the potential for water or gas coning. They also offer a more balanced recovery, Bøe said, and they expose more of the producing Heimdal formation to the production strings.

The length and placement of the horizontal wells are important, as well. Hydro used Schlumberger’s Ultra Deep Resistivity Tool to help precisely measure the oil-water contact during drilling. It also used seismic-while-drilling, which allowed engineers to “see” 984 ft to 1,312 ft (300 m to 400 m) ahead of the drill bit. Those technologies allowed the company to place the horizontal producers as close to the oil-water contact as feasible so the injected gas would sweep most of the oil column.

As production reduces the thickness of the oil column, the last phase of production will reclaim the injected natural gas for sale.

Recovery

From the head-office point of view, the gas injection will allow the company to recover 55% of the original oil in place compared to 35 to 40% for water injection alone.

Bøe said, “We do not set a goal for the recovery factor but focus on maximizing reserves and target undrained oil. Advanced seismic interpretation techniques and 3-D reservoir modeling are used to construct a reservoir model which forms a basis for uncertainty analysis. The potential recovery (with uncertainty ranges) is then estimated based on a combination of reservoir simulation, field analogs and decline analysis. For fields in production, 4-D seismic is used to monitor dynamic changes in the field and locate undrained parts.” Normally, that 4-D seismic is conducted with towed seismic arrays tailored to Hydro’s specifications at different times during the lives of its fields.

At Grane, Hydro uses permanently installed ocean-bottom cable/multicomponent seismic for monitoring of the difficult reservoir. That supplements the standard pressure and temperature monitoring operations for the field. The combination provides the company with a reality check for its models.

Project development

As they have with Troll and Oseberg, Hydro managers carefully tabulate the lessons they learn at Grane. There may be other discoveries in the area, Bøe said.
Hydro approaches project development with a capital value process, he said. That process consists of:
• Business idea development;
• Feasibility phase;
• Concept selection phase;
• Preparation for execution;
• Execution; and
• Operation.

Each phase is separated by a decision gate guided by analysis of subsurface, drilling, engineering, economics, and health and safety factors.

Adopting new technology that leads to sharp gains in production and profits is not a haphazard process. It’s carefully controlled.

“The technology unit in Hydro is responsible for the technology management process. The unit makes a technology strategy based on the corporate strategy, business unit needs and innovations. This strategy forms the basis for the yearly research and development (R&D) plan. The R&D centers in the oil and energy division are located in Porsgrunn and Bergen and report to the technology unit. A separate implementation plan for new technology is also developed, and the business units take ownership of this plan,” Bøe said.

During each stage of drilling and production, Grane managers were free to use advanced visualization in decision/ visualization rooms. There managers can look at cores from the research and development center at the same time they consider 3-D images of fields and wells. Experts in each phase of the operation — including geosteering of the horizontal wells — can participate from a distance with the same information they would have had if they were on the platform working directly on the drilling operation.

“This is a big part of reservoir management,” he added.

The government lends a hand, too. “The Norwegian authorities stimulate R&D and technology developments through various research initiatives,” he added.

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