Side-alternativer

Experiences in CO2 storage

To date, most actual or planned commercial projects are associated with major gas production facilities that have gas streams containing CO2 in the range of 10–15% by volume, such as Sleipner in the North Sea, Snohvit in the Barents Sea, In Salah in Algeria and Gorgon in Australia (Figure 1), as well as the acid gas injection projects in Canada and the United States. At the Sleipner Project, operated by Statoil, more than 13 MtCO2 has been injected into a deep subsea saline formation since 1996.

At the In Salah Gas Field in Algeria, Sonatrack, BP and Statoil inject CO2 stripped from natural gas into the gas reservoir outside the boundaries of the gas field. At the Snohvit field in the Barents Sea, CO2 is stripped from the gas before the LNG plant, and injected into a geological formation below the gas field. In The Netherlands, CO2 is being injected at pilot scale into the almost depleted K12-B offshore gas field (van der Meer et al., 2005). Forty-four CO2-rich acid gas injection projects are currently operating in Western Canada, ongoing since the early 1990s (Bachu and Haug, 2005). The Gorgon field off Western Australia, containing approximately 14% CO2. The investment decision is taken for the LNG plant and the CO2 injection into the Dupuy Formation at Barrow Island (Oen, 2003).

Content

1. Sleipner, storage in saline formation, Norway

2. In Salah, storage in a gas reservoir, Algeria

3. Natural gas storage

4. References

5. External links

Sleipner, storage in saline formation, Norway

The Sleipner Project, operated by Statoil in the North Sea about 250 km off the coast of Norway, is the first commercialscale project dedicated to geological CO2 storage in a saline formation. The CO2 (about 9%) from Sleipner West Gas Field is separated, then injected into a large, deep, saline formation 800 m below the seabed of the North Sea. The Saline Aquifer CO2 Storage (SACS) project was established to monitor and research the storage of CO2. From 1995, the IEA Greenhouse Gas R&D Programme has worked with Statoil to arrange the monitoring and research activities. Approximately 1 MtCO2 is removed from the produced natural gas and injected underground annually in the field. The CO2 injection operation started in October 1996. Over the lifetime of the project, a total of 20 MtCO2 is expected to be stored. The saline formation into which the CO2 is injected is a brine-saturated unconsolidated sandstone about 800–1000 m below the sea floor. The formation also contains secondary thin shale layers, which influence the internal movement of injected CO2. The saline formation has a very large storage capacity, on the order of 1–10 GtCO2. The top of the formation is fairly flat on a regional scale, although it contains numerous small, low-amplitude closures. The overlying primary seal is an extensive, thick, shale layer. This project is being carried out in three phases. Phase-0 involved baseline data gathering and evaluation, which was completed in November 1998. Phase-1 involved establishment of project status after three years of CO2 injection. Five main project areas involve descriptions of reservoir geology, reservoir simulation, geochemistry, assessment of need and cost for monitoring wells and geophysical modelling. Phase-2, involving data interpretation and model verification, began in April 2000. The fate and transport of the CO2 plume in the storage formation has been monitored successfully by seismic time-lapse surveys. The surveys also show that the caprock is an effective seal that prevents CO2 migration out of the storage formation. Reservoir studies and simulations covering hundreds to thousands of years have shown that CO2 will eventually dissolve in the pore water, which will become heavier and sink, thus minimizing the potential for long-term leakage (Lindeberg and Bergmo, 2003).

In Salah, storage in a gas reservoir, Algeria

The In Salah Gas Project, a joint venture among Sonatrach, BP and Statoil located in the central Saharan region of Algeria, is the world’s first large-scale CO2 storage project in a gas reservoir (Riddiford et al., 2003). The Krechba Field at In Salah produces natural gas containing up to 10% CO2 from several geological reservoirs and delivers it to markets in Europe, after processing and stripping the CO2 to meet commercial specifications. The project involves re-injecting the CO2 into a sandstone reservoir at a depth of 1800 m and storing up to 1.2 MtCO2 per yr. Carbon dioxide injection started in April 2004 and, over the life of the project, it is estimated that 17 MtCO2 will be geologically stored. The project consists of four production and three injection wells. Long-reach (up to 1.5 km) horizontal wells are used to inject CO2 into the 5-mD permeability reservoir.
The Krechba Field is a relatively simple anticline. Carbon dioxide injection takes place down-dip from the gas/water contact in the gas-bearing reservoir. The injected CO2 is expected to eventually migrate into the area of the current gas field after depletion of the gas zone. The field has been mapped with three-dimensional seismic and well data from the field. Deep faults have been mapped, but at shallower levels, the structure is unfaulted. The storage target in the reservoir interval therefore carries minimal structural uncertainty or risk. The top seal is a thick succession of mudstones up to 950 m thick. A preliminary risk assessment of CO2 storage integrity has been carried out and baseline data acquired. Processes that could result in CO2 migration from the injection interval have been quantified and a monitoring programme is planned involving a range of technologies, including noble gas tracers, pressure surveys, tomography, gravity baseline studies, microbiological studies, four-dimensional seismic and geomechanical monitoring.

Natural gas storage

Underground natural gas storage projects that offer experience relevant to CO2 storage (Lippmann and Benson, 2003; Perry, 2005) have operated successfully for almost 100 years and in many parts of the world. These projects provide for peak loads and balance seasonal fluctuations in gas supply and demand. The Berlin Natural Gas Storage Project is an example of this. The majority of gas storage projects are in depleted oil and gas reservoirs and saline formations, although caverns in salt have also been used extensively. A number of factors are critical to the success of these projects, including a suitable and adequately characterized site (permeability, thickness and extent of storage reservoir, tightness of caprock, geological structure, lithology, etc.). Injection wells must be properly designed, installed, monitored and maintained and abandoned wells in and near the project must be located and plugged. Finally, taking into account a range of solubility, density and trapping conditions, over pressuring the storage reservoir (injecting gas at a pressure that is well in excess of the in situ formation pressure) must be avoided. While underground natural gas storage is safe and effective, some projects have leaked, mostly caused by poorly completed or improperly plugged and abandoned wells and by leaky faults (Gurevich et al., 1993; Lippmann and Benson, 2003; Perry, 2005). Abandoned oil and gas fields are easier to assess as natural gas storage sites than are saline formations, because the geological structure and caprock are usually well characterized from existing wells. At most natural gas storage sites, monitoring requirements focus on ensuring that the injection well is not leaking (by the use of pressure measurements and through in situ downhole measurements of temperature, pressure, noise/ sonic, casing conditions, etc.). Observation wells are sometimes used to verify that gas has not leaked into shallower strata.

References

The main source of this article is the IPCC (2005) Special Report on Carbon Dioxide Capture and Storage, available from Cambridge University Press.