storage projects are also listed in Table 5.1.
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 (Box 5.2). Statoil is planning another project in the Barents Sea, where CO2 from the Snohvit field will be stripped from the gas and injected into a geological formation below the gas field. Chevron is proposing to produce gas from the Gorgon field off Western Australia, containing approximately 14% CO2. The CO2 will be injected into the Dupuy Formation at Barrow Island (Oen, 2003). 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). Although they are mostly small scale, they provide important examples of effectively managing injection of CO2 and hazardous gases such as H2S (Section 220.127.116.11).
Box 5.1 The Sleipner Project, North Sea.
The Sleipner Project, operated by Statoil in the North Sea about 250 km off the coast of Norway, is the first commercial-scale 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 and, by early 2005, more than 7 MtCO2 had been injected at a rate of approximately 2700 t day-1. Over the lifetime of the project, a total of 20 MtCO2 is expected to be stored. A simplified diagram of the Sleipner scheme is given in Figure 5.4.
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 (Figure 5.16). The surveys also show that the caprock is an effective seal that prevents CO2 migration out of the storage formation. Today, the footprint of the plume at Sleipner extends over an area of approximately 5 km2. 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).
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