3.5.1 The Utsira Sand, Sleipner, northern North Sea
The sleipner project is the prototypical test site for Co2 sequestration into a deep saline aquifer. It is the world’s first commercial CO2 capture and storage project (Gale et al., 2001), motivated by the high tax norway imposes on offshore oil and gas activity. started in september 1996, it sequesters about one million metric tons of Co2 each year into the utsira formation at statoilhydro’s north-sea sleipner facility (Chadwick et al., 2004, 2006).
as of 2009, about 10 mt Co2 had been stored in utsira at a cost of $17/t (hermanrud et al., 2009) with a final target of 20 Mt. The injection site lies 1000 m below the seafloor and is composed largely of uncemented fine- grained sand, primarily quartz (75 %) with some feldspar (13 %) (Chadwick et al., 2004) (Fig. 3.11). Porosity of the utsira sand is ~30 %, locally up to 42 % (Chadwick et al., 2004). The caprocks are non-organic mudstones composed of 30 % quartz, 30 % mica, and 14 % kaolinite. as of 2004, the plume area extended to 2.8 km2 and the maximum distance from the injection site was 2560 m (Torp and Gale, 2004). extensive seismic monitoring was carried out by saline aquifer Co2 storage (saCs) (Fig. 3.12), and these studies indicated only limited interaction with formation rocks (Torp and Gale, 2004). although the activities of saCs ended in 2002, part of its effort continues in the eu-co-funded project Co2sToRe, a research project with 19 participants from industry and research institutes, whose aim is to prepare the ground for widespread underground storage of Co2 in aquifers.
sleipner has been and continues to be the subject of much geophysical study (i.e. arts et al., 2008; hermanrud et al., 2009.
3.5.2 The Snứhvit project
The snứhvit plant in the barents sea is another statoilhydro commercial project in which Co2 is captured and stored. In this case, the target formation is below a gas reservoir in the Tubồsen sandstone formation (Kồrstad, 2002).
This case deals with StatoilHydro’s Snứhvit natural gas field and liquid natural gas (LNG) facility in northern Norway. Gas production began at Snứhvit in 2007 and Co2 storage in April 2008 (Estublier and Lackner, 2009). At full capacity, 700 000 t of Co2 is expected to be stored per year. The field consists of a fully subsea offshore development in the barents sea, a 160 km pipeline to shore and a liquification plant for LNG (Kồrstad, 2002). The Tubồsen sandstone is 45–75 m thick with an overlying shale cap (maldal and Tappel, 2004).
81dioxide (CO2) sequestration in deep saline aquifers
© Woodhead Publishing Limited, 2010
Utsira Formation
Sleipner Scotland
Norway
Utsira formation 800 -1000 m depth
Gas field (3000 m)
productionGas
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3.11 Schematic diagram depicting gas production at depth and re-injection of CO2 into the Utsira sand at StatoilHydro’s North- Sea Sleipner facility. Shown also is a location map for the facility in the North Sea (image courtesy of StatoilHydro, ASA).
Developments and innovation in CCS technology
© Woodhead Publishing Limited, 2010
Pre-injection (1994)
Top of Utsira sand
Base of Utsira sand
4.3 Mt CO2 (2001) 8.4 Mt CO2 (2006)
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3.12 Seismic monitoring of Sleipner CO2 injection plume. Time-lapse seismic images showing changes in reflectivity due to injected CO2. Arrows indicate CO2 accumulations (modified from original image created by Ola Eiken, StatoilHydro, ASA).
3.5.3 The Frio formation
The first US sequestration field experiment was completed in 2008 at the Frio site located within the South Liberty oil field, near Houston, Texas (Doughty et al., 2002, 2007; hovorka et al., 2006, 2009). Injection and updip observation wells perforated the target Frio ‘C’ sandstone at ~ 1540 m, above a zone of oil production at 2900 m (Kharaka et al., 2006b). The Frio ‘C’
unit is a poorly cemented subarkosic sandstone dominantly comprising fine grained quartz with minor amounts of illite/smectite, feldspar, and calcite with a porosity of 32 % and permeability of 2–3 darcys. (Kharaka et al., 2006b). The caprock is the regional miocene–oligocene anahuac shale (hovorka et al., 2005). Aquifer fluids are 100 ppt NaCl at a temperature of 65 °C (Kharaka et al., 2006b).
a test injection of 1600 t Co2 was carried out while monitoring downhole pressure, temperature, and fluid compositions. Intensive fluid sampling and analyses by methods described in Kharaka and hanor (2007) showed large ph decreases and increases in concentrations of hCo3–, Ca+2, Fe+2, and mn+2, likely resulting from the rapid dissolution of carbonate and iron oxyhydroxide minerals in the Frio Formation (Kharaka et al., 2006a,b).
The time to Co2 breakthrough and the spatial distribution of the Co2 plume in the subsurface, measured with cross-well tomography and wireline logs, compare well with values and patterns predicted by transport modeling using TouGh2 (hovorka et al., 2005) (Fig. 3.13)
3.5.4 Other carbon dioxide (CO2) sequestration projects other international Co2 sequestration demonstration and pilot projects (Fig.
3.10) either online or planned (IPCC, 2005) include the minami-nagaoka in Japan, the otway and Gorgon in australia, and the Ketzin in Germany. The Minami-Nagaoka gas field in Nagaoka City, 200 km north of Tokyo is the first pilot Co2 injection site in Japan. The target reservoir is the early Pleistocene sandstone formation that lies 3000 m above the gas reservoir and 1100 m below the surface. about 10 000 t Co2 were injected from 2003 through 2005 (Tanase and Yoshimura, 2008). The Co2CRC otway Project, located in southwest Victoria is Australia’s first demonstration of deep geological storage of Co2. It will inject Co2 obtained from the Buttress gas field into a nearby depleted gas field in the Waarre Formation at depth of ~1700 m.
although technically not Co2 storage in a deep saline aquifer, the otway Project is one of the largest research and geologic sequestration demonstration projects with a planned injection of about 100 000 t Co2 by 2010 (sharma et al., 2009). The Gorgon Project, located in northwest australia, will extract Co2 from produced gas within the Greater Gorgon gas fields prior to liquefaction into LNG and re-inject it into the Dupuy Formation located 2000 m beneath
barrow Island. The volume of reservoir Co2 to be re-injected is about 100 mt (Flett et al., 2008). Thirteen CCs projects involving the capture and/or storage of Co2 in australia are currently proposed or underway. The Co2
Modeled CO2 plume Nov 30, 2004
Top of C sand
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3.13 (a) CO2 plume in the sub-surface Frio after CO2 injection, measured with cross-well tomography and wireline logs; (b) CO2 plume in the sub- surface Frio predicted by transport modeling using TOUGH2 (Hovorka et al., 2005) (image modified from original created by Christine Doughty and Thomas M. Daley in Hovorka et al. (2006), reprinted with kind permission of Springer Science+Business Media).
storage site near the town of Ketzin in Germany is the first onshore pilot site in europe. The target formation is the Triassic stuttgart silt and sandstones at a depth of 700 m. Injection started in June 2008 and will continue for two years. a maximum of 60 000 t Co2 will be injected. extensive geophysical and geochemical monitoring is being carried out to follow the spread of the Co2 plume (schilling et al., 2008).
also, each of the seven us Department of energy (Doe) Regional Carbon sequestration Partnerships has plans for Co2 capture and storage projects in deep geologic formations. These include tertiary sandstones in the san Joaquin Valley of California, the Wingate (Jurassic–Triassic-aged) sandstone in the southwest usa, the deep carbonate saline formation in the Williston basin in north Dakota, the mount simon sandstone formation in central Illinois, the Tuscaloosa Massive Sandstone in Mississippi and Louisiana, and the nugget sandstone formation in southwest Wyoming.
3.5.5 Weyburn
The Iea Weyburn Co2 monitoring and storage project is neither a deep saline aquifer site nor technically even a Co2 sequestration site. It is a large-scale commercial Co2–enhanced oil recovery (eoR) site that, under the management of the Petroleum Technology Research Center (PTRC), has provided a wealth of geophysical and geochemical research that is applicable to Co2 sequestration in saline aquifers. In the Weyburn eoR Project, located in Prairie Province of saskatchewan, Canada, Co2 has been used to increase recovery of oil from the carbonate midale beds of the mississippian Charles Formation, where about 3 billion m3 of supercritical Co2 have been injected since 2000 at a rate of 5000 t/day (Riding and Rochelle, 2005; Cantucci et al., 2009). Carbon dioxide is obtained from the Dakota Gasification Company, near beulah nD and transported 320 km via pipeline to the Weyburn and Midale oil fields where it is injected with water at 800 m depth. A mixture of oil, water, and Co2 is extracted; extracted Co2 is re-injected.
The database obtained at this site has provided an opportunity to monitor dynamic reservoir response and study effective trapping mechanisms, seals, hydraulic isolation, hydrogeological regime, and pathways for migration along faults and fractures (Preston et al., 2009). seismic monitoring has provided detailed Co2 plume distribution and containment within the reservoir (Davis et al., 2003; Preston et al., 2009). Changes in the fluid chemistry and isotopic composition of the produced fluid, pre- and post-injection, provide evidence of dissolution of injected Co2, an increase of total dissolved solids, and both dissolution and precipitation of carbonate minerals (emberley et al., 2004, 2005; Perez et al., 2006; mayer et al., 2008). most of the injected Co2 exists in a supercritical state but has reacted with the reservoir rock sufficiently to mask some of the strontium isotope signature caused by 40 years of water
flooding (Riding and Rochelle, 2009). Geochemical modeling suggests that eventually most of the Co2 will be stored by solubility and mineral trapping (via dawsonite precipitation) (Cantucci et al., 2009). Pre- and post-injection soil gas surveys have not found any evidence for leakage of the injected Co2 to surface (Riding and Rochelle, 2009).