CO 2 injection studied for Norwegian field

Environmental concerns about global warming from CO 2 have been coupled with an option being considered for recovering heavy (19° API gravity) oil from Grane field off Norway. The option is to first generate carbon dioxide and hydrogen from natural gas, then to inject supercritical carbon dioxide offshore and use the hydrogen to fuel gas-fired power plants onshore. Norsk Hydro Produksjon a.s. is operator of the Grane discovery in the southern North Sea Block 25/11, about 160 km offshore

Oct. 19, 1998

3 min read

Environmental concerns about global warming from CO₂have been coupled with an option being considered for recovering heavy (19° API gravity) oil from Grane field off Norway.

The option is to first generate carbon dioxide and hydrogen from natural gas, then to inject supercritical carbon dioxide offshore and use the hydrogen to fuel gas-fired power plants onshore.

Norsk Hydro Produksjon a.s. is operator of the Grane discovery in the southern North Sea Block 25/11, about 160 km offshore and east of the Balder field, which is being developed by Esso Norge a.s.

According to Norsk Hydro, the hydrogen-fired power plants (Hyrokraft project, Fig. 1 [58,067 bytes]) would use steam reforming to convert natural gas to hydrogen and carbon monoxide. In the process, water also combines with carbon monoxide to form CO₂and hydrogen. The hydrogen is burned to generate electric power.

Norsk Hydro estimates that its process reduces CO₂emissions by 90% compared to conventional gas-fired power plants. CO₂injection into an oil field eliminates CO₂releases to the atmosphere as well as improving oil recovery.

CO₂is not usually associated with heavy oil enhanced production projects, although one example is the Batman field in Turkey, where CO₂has been injected since 1986 to produce an even heavier, 13° API gravity crude (OGJ Apr. 20, 1998, p. 76).

Norsk Hydro describes the Grane reservoir (Fig. 2 [73,844 bytes]) as a very permeable, 1-12 Darcy, poorly consolidated turbidite sandstone at about 5,500 ft true vertical depth with an areal extent of about 6,700 acres and a 100-ft thick oil column. Reservoir porosity is 33% and reservoir temperature and pressure is about 170° F. and 2,550 psi.

The producing gas/oil ratio is a low 83 scf/bbl. Norsk Hydro estimates that the field contains 1.2 billion bbl original oil in place and that between 500 and 750 million bbl can be recovered, depending on the drainage strategy.

Norsk Hydro plans to develop the field with fixed platforms in 425 ft of water. Three platforms (drilling, production, and quarters) are envisioned. Norsk Hydro will use horizontal wells with branches to reduce the number of drilling slots on the platform. More than 40 production wells are expected (all horizontal) plus 10 vertical gas injectors.

Produced gas and water will be reinjected. Crude will either be piped to shore or to a storage vessel. Two segments of the field are planned to be developed with subsea wells tied back to the production platform.

Grane processing platform capacity is expected to be 215,000 bo/d and 390 MMcfd of gas. Development cost is estimated to be $1.8-2.2 billion (OGJ, Aug. 17, 1998, p. 84).

Besides CO₂injection in the top of the reservoir, two other production options are being considered for the field. One is to inject formation water along with water from the Utsira aquifer. The other option is to inject imported natural gas into the top of the reservoir.