Underground CO2 Storage Concepts

The main concepts that have been put forward for underground storage sites for CO2 fall into four categories: natural and man-made caverns, unused porous and permeable reservoir rocks, depleted oil and gas fields, and coal beds.

Realistically, storage in caverns and mines cannot make a significant impact on the greenhouse effect. The majority of mines are not leakproof, especially at pressures much greater than atmospheric. Most abandoned mines gradually fill with water, and any gas within them will eventually be forced out. The leakproof mines have alternative uses — for example, storage of documents, natural gas and chemical waste. Solution-mined salt caverns are also unsuitable as they are not stable in the long term because rock salt is a ductile substance that can creep and rupture under the in situ stresses within the Earth's subsurface.

4.8.1 Storage in Porous and Permeable Reservoir Rocks

CO2 can be stored in geological formations by filling the intergranular pore space within rocks with CO2. This is how oil, natural gas and indeed carbon dioxide, occur in the subsurface in nature. Porous and permeable sedimentary rocks (known as reservoir rocks) commonly occur in major accumulations known as sedimentary basins that may be up to a few kilometres thick and may cover thousands of square kilometres. However, although very common, sedimentary basins do not occur in every country in the world. Nor are all sedimentary basins suitable for CO2 storage.

Pressure — Temperature conditions underground

The average temperature in many sedimentary basins increases by about 25-30 °C km"1 below the ground surface or seabed as a result of heat flow from the inside to the outside of the Earth. However there is considerable variation in such geothermal conditions, both locally within basins and between basins worldwide [6].

Pressure also increases downwards within the subsurface. Pressure in the pore spaces of sedimentary rocks is commonly close to hydrostatic pressure, that is, the pressure generated by a column of (commonly saline) water of equal height to the depth of the pore space. This is because the pore space is mostly filled with water and is connected, albeit tortuously, to the ground surface or seawater. However, under conditions where the pore space is either not connected to the surface, or not equilibrated to the surface, pressure may be greater than hydrostatic. Underpressure may also exist, either naturally, or as the result of abstraction of fluids such as oil and gas from a reservoir rock.

Physical properties of CO2 underground

The physical properties of CO2 define the density at which it can be stored underground [5, 6]. They are also relevant because large volume changes are associated with CO2 phase changes.

When CO2 is injected underground, there is a sharp increase in its density and corresponding decrease in volume at depths between approximately 500 m and 1000 m depending on the precise geothermal conditions and pressure [30] (Figure 1). This is associated with the phase change from gas to supercritical fluid. Consequently, CO2 occupies much less space in the subsurface than at the surface. One tonne of CO2 at a density of 700 kg/m3 occupies 1.43 m3, or less than 6 m3 of rock with 30% porosity if 80% of the water in the pore space could be displaced. At 0°C and 1 atmosphere one tonne of CO2 occupies 509 m3.

Storage of large masses of CO2 in shallow reservoir rocks is not so practical, because the physical conditions at shallow depths underground mean that relatively small masses of CO2 would occupy relatively large volumes of pore space. Also, shallow reservoir rocks commonly have a more important use — groundwater supply.

900 800 700 600 500 400 300 200 100 0

900 800 700 600 500 400 300 200 100 0

density @ 20C/km density @ 25C/km density @ 30C/km density @ 35C/km

500 1000 1500 2000 2500 3000 3500 depth (m)

density @ 20C/km density @ 25C/km density @ 30C/km density @ 35C/km

500 1000 1500 2000 2500 3000 3500 depth (m)

Fig. 1. Density of CO2 at a range of geothermal gradients and CO2 storage depths, assuming a hydrostatic gradient and a surface temperature of 10°C

4.8.2 Principles of Storage in Underground Reservoir Rocks

CO2 can be injected into the porosity of a reservoir rock via a well or wells. CO2 permeates the rock, displacing some of the fluid (commonly saline water) that was originally in the pore spaces. In order for injection and displacement of the native pore fluid to occur, the injection pressure must be greater than the pore fluid pressure. If the permeability of the rock is low or there are barriers to fluid flow within the rock (for example faults that compartmentalize the reservoir) injection may cause a significant increase in pressure in the pore spaces, especially around the injection well [92]. This may limit both the amount of CO2 that can be injected into a rock and the rate at which it can be injected. For example, in Alberta, the maximum allowable injection pressure is 90% of the fracture pressure at the top of the reservoir [58]. This factor could make heavily compartmentalised reservoirs unsuitable for CO2 injection.

Once injected into the reservoir rock, the processes of migration and trapping begin. The injected CO2 is buoyant and migrates towards the top of the reservoir until it reaches the cap rock. A fraction of it may be retained in traps formed by internal permeability barriers within the reservoir, and these also make the migration path of the CO2 through the reservoir more tortuous. The cap rock at the top of the reservoir retains the CO2. Cap rocks can be divided into two categories: essentially impermeable strata such as thick rock salt layers (known as aquicludes) and those with low permeability such as shales and mudstones, known as aquitards, through which fluids can migrate, albeit extremely slowly [8]. The effectiveness of homogeneous cap rocks (or seals) is dependent mainly on their capillary entry pressure, which is essentially a function of the size of the pore throats connecting the pores within the rock and the fluid attempting to enter the rock. However, in real situations they also may contain faults or fractures that could cause them to leak. Methods for assessing the risk of imperfectly sealing cap rocks in petroleum systems are given in [90].

Providing the reservoir is big enough, it may not be necessary to inject CO2 into a single large closed structure such as a dome, analogous to an oil or gas field, to ensure its safe and stable containment in the long term. When CO2 is injected into a relatively flat-lying subsurface reservoir and rises to its top, it will be trapped in any small domes or other closed structures that occur on the underside of the cap rock. Once one of these structures becomes full, the CO2 will spill from it and migrate to the next such structure along the migration path and fill that. Thus, as the CO2 migrates within the reservoir, it may become divided into many small pools in many small closures.

Over time, depletion of these accumulations is likely to take place as a result of CO2 dissolution into the contacted water in the pore spaces of the reservoir rock. Moreover, CO2 will be trapped by capillary forces in pores and by adsorption onto grain surfaces along the migration path of the CO2 within the reservoir. This "residual" CO2 saturation along the migration path could be in the order of 5-30% [30]. The solubility of CO2 in water depends on temperature, pressure and salinity [24]. For typical subsurface conditions, solubility of CO2 in 1 M brine plateaus at about 41-48 kg/m3 below 600 m depth. Increasing the salinity to 4 M decreases the maximum solubility to around 24-29 kg m3 [30]. The solubility under typical reservoir conditions at a salinity of 3% will vary between 47 and 51 kg/m3, corresponding to a volume of free CO2 of 6.7 to 7.3% of the pore volume [61]. Thus, potentially, this is a very important storage mechanism if a large proportion of the formation water becomes saturated with CO2 — the challenge is to achieve this.

The rate of dissolution will depend on how well the CO2 mixes with the formation water once it is injected into the reservoir. Once a CO2 accumulation has reached a stable position within the reservoir, diffusion of CO2 into the water will be faster if it is a thin but widespread accumulation, with a high surface area to volume ratio [24, 30]. However, for many accumulations, dissolution could be slow, on the order of a few thousand years for typical injection scenarios [5], unless there is some form of active mixing induced by fluid flow within the reservoir [61]. Even so, if a relatively small amount of CO2 is injected into a very large reservoir, the combination of a series of small traps and dissolution of the CO2 into the formation water means it is unlikely ever to reach the edge of the reservoir, even if there are no major structures to trap it [e.g. 62]. This is the situation with the CO2 from the Sleipner West gas field that is being stored in the Utsira Sand [101].

In other circumstances, the CO2 may be hydrodynamically trapped [7, 8, 68]. Once outside the radius of influence of the injection well, the CO2 will migrate in the same direction as the natural fluid flow within a reservoir rock. If it is a free gas within the reservoir, it will migrate faster than the brine (the native pore fluid) because it is less viscous. However, if it is dissolved it will migrate at the (commonly very low) rates at which natural fluid flow occurs within reservoir rocks. If the migration of the CO2 is very slow and the proposed injection point is a very large distance from the edge of the reservoir, the CO2 may not reach the edge of the reservoir for millions of years. Some of the CO2 may also become trapped by chemical reaction with either the formation water or the reservoir rock (the latter will take place only over long timescales), the amount depending on the pore water chemistry, rock mineralogy and the length of the migration path [24, 35, 36, 82].

Thus, in the long term, the interaction of five principle mechanisms will determine the fate of the CO2 in the reservoir. These are: immobilization in traps, immobilization of a residual saturation of CO2 along the CO2 migration path, dissolution into the surrounding formation water, geochemical reaction with the formation water or minerals making up the rock framework and, if the seal is not perfect, migration out of the geological storage reservoir. Escape of CO2 from the storage reservoir may not necessarily be important, providing there is no adverse impact on man, the natural environment or other resources such as groundwater, and the required storage period is exceeded.

The amount of CO2 that can be injected during a particular project or into a particular reservoir is limited by the undesirable effects that could occur. Some of these might be important in the short term, others may occur in much longer timescales, as the result of migration of the injected CO2. They include: an unacceptable rise in reservoir pressure, conflicts of use of the subsurface (e.g., unintentional interaction with coal mining, or the exploitation of oil and gas), pollution of potable water by displacement of the saline/fresh groundwater interface, pollution of potable water by CO2 or substances entrained by CO2 (e.g., hydrocarbons), escape of CO2 to the outcrop of a reservoir rock and escape of CO2 via an unidentified migration pathway through the cap rock.

4.8.3 CO2 Storage at the Sleipner West Gas Field

The Sleipner West gas field [19, 56] is in the centre of the North Sea approximately 200 km from land. The Sleipner West natural gas reservoir is faulted, with different pressure regimes and different fluid properties in the various fault blocks. The natural gas in the reservoir (mainly methane) includes between 4% and 9.5% CO2. To get the natural gas to sales quality, the amount of CO2 has to be reduced to 2.5% or less. In order for the gas to be exported under the Troll gas sales agreement, mainly via the Zeepipe export pipeline to Zeebrugge, which passes through Sleipner, this operation is carried out offshore. The gas is produced via 18 production wells drilled from a wellhead platform (Sleipner B) and transported to a process and treatment platform (Sleipner T) located next to and with a bridge connected to the main Sleipner A platform (Figures 2 and 3).

Around 1 x 106 tonnes of CO2 are separated from the natural gas annually. This amounts to some 3% of total Norwegian CO2 emissions. Rather than vent this CO2 to the atmosphere, Statoil and partners made the decision

Fig. 2. The Sleipner T CO2-processing platform (left) and Sleipner A platform (right) in the North Sea (Courtesy of Statoil)
Fig. 3. Schematic cross section through the Sleipner CO2 injection facility (Courtesy of Statoil)

to store it underground in the Utsira Sand. This is a sandstone reservoir approximately 150-200 m thick, at a depth of between 800 and 1000 m.

At the injection site, the cap rock consists of two parts: firstly a lower sedimentary unit consisting of more than 100 m of shale, the so-called "Shale Drape" that immediately overlies the reservoir, and secondly the remainder of the strata above the Shale Drape, which also appears to con-

Fig. 4. Detailed time-lapse seismic images of carbon dioxide stored in the Utsira Sand at the Sleipner West field. The 1996 image was pre-CO2 injection. The 1999-2002 images show successive increases in the amount of CO2 stored in the Utsira Sand. The CO2 is imaged as bright reflections corresponding to layers of sand with high CO2 saturations accumulated beneath thin shale layers within the sand reservoir (Courtesy of the CO2STORE partners and Andy Chadwick)

Fig. 4. Detailed time-lapse seismic images of carbon dioxide stored in the Utsira Sand at the Sleipner West field. The 1996 image was pre-CO2 injection. The 1999-2002 images show successive increases in the amount of CO2 stored in the Utsira Sand. The CO2 is imaged as bright reflections corresponding to layers of sand with high CO2 saturations accumulated beneath thin shale layers within the sand reservoir (Courtesy of the CO2STORE partners and Andy Chadwick)

sist predominantly of mudstones or silty mudstones. These strata effectively prevent the CO2 from leaking back to the seabed and thus to the atmosphere.

CO2 injection started in August 1996 and will continue for the life of the field (estimated to be approximately 20 years). Additional costs of the operation are about US$15/tonne of CO2 avoided [42].

A demonstration project, acronym SACS, jointly funded by the EU, industry and national governments, and its successor, acronym CO2STORE, is currently evaluating the geological aspects of the subsurface disposal operation [2, 3, 12, 20, 64, 74]. This involves assessing the capacity, storage properties and performance of the Utsira reservoir, modelling CO2 migration within the reservoir and monitoring the subsurface dispersal of the CO2 using time-lapse seismic techniques. It is clear from Figure 4 that the underground situation is well-imaged; the CO2 is currently trapped within the reservoir above and around the injection point. It has reached the base of the cap rock and is migrating horizontally beneath it. Seismic and reservoir modelling is now being carried out to further quantify and constrain the CO2 subsurface distribution and predict its future behaviour.

The Utsira Formation appears to be an excellent repository for CO2. It acts as essentially an infinite aquifer; fluid is being displaced from the pore spaces above the injection point without a significant measurable pressure increase at the wellhead.

4.8.4 Storage in Depleted or Abandoned Oil and Gas Fields

Oil and gas fields are natural underground traps for buoyant fluids. In many cases there is geological evidence that the oil or gas has been trapped in them for hundreds of thousands or millions of years. In such cases, they will not leak in the geologic short term (a few hundred to a few thousand years) providing their exploitation by man has not damaged the trap and the cap rock is not adversely affected by the injection of CO2.

CO2 is widely used for enhancing oil recovery in depleted oil fields [91] so it should be possible to sequester CO2 in such fields and increase oil production at the same time [e.g. 9, 17, 48]. The production of additional oil would offset the cost of CO2 sequestration. Approximately 2.5 to 3.3 barrels of oil can be produced per tonne of CO2 injected into a suitable oilfield.

Some of the CO2 used in EOR projects is anthropogenic; e.g., at Enca-na's Weyburn field in Saskatchewan anthropogenic CO2 from a coal gasification plant in North Dakota [96, 97] is used. The progress of this CO2 flood will be monitored from a CO2 sequestration perspective. It is expected to permanently sequester about 18 million tonnes of CO2 over the lifetime of the project. The Rangely EOR project in Colorado has also been monitored to determine whether CO2 is leaking from the reservoir to the ground surface [54]. Further opportunities for EOR abound, especially if recent increases in the price of oil are maintained. There is undoubtedly significant potential in many of the world's major onshore oil provinces, for example the Middle East, and there may be potential in offshore areas such as the North Sea [16, 31].

The small amounts of CO2 sequestered in such projects indicate that EOR would have to take place on a massive scale to have a significant impact on global CO2 emissions to the atmosphere [88].

When natural gas is produced from a gas field, the production wells are opened and the pressure is simply allowed to deplete, usually without any fluid being injected to maintain the pressure. Thus, depending on the rate of water inflow into the porosity that comprises the gas reservoir, a large volume of pressure-depleted pore space may be available for CO2 storage. In many cases there is little or no water flow into a gas reservoir. Therefore it may be possible to store underground a volume of CO2 equal to the underground volume of the gas produced. Furthermore, there is a possibility that CO2 injection could enhance natural gas production towards the end of field life.

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