Info

Mass flow rate (MtCO2 yr-1)

Figure TS.5. Transport costs for onshore pipelines and offshore pipelines, in US$ per tCO2 per 250 km as a function of the CO2 mass flow rate. The graph shows high estimates (dotted lines) and low estimates (solid lines).

Distance (km)

Figure TS.6. Costs, plotted as US$/tCO2 transported against distance, for onshore pipelines, offshore pipelines and ship transport. Pipeline costs are given for a mass flow of 6 MtCO2 yr-1. Ship costs include intermediate storage facilities, harbour fees, fuel costs, and loading and unloading activities. Costs include also additional costs for liquefaction compared to compression.

The costs associated with CO2 compression and liquefaction are accounted for in the capture costs presented earlier. Figure TS.6 compares pipeline and marine transportation costs, and shows the break-even distance. If the marine option is available, it is typically cheaper than pipelines for distances greater than approximately 1000 km and for amounts smaller than a few million tonnes of CO2 per year. In ocean storage the most suitable transport system depends on the injection method: from a stationary floating vessel, a moving ship, or a pipeline from shore.

5. Geological storage

This section examines three types of geological formations that have received extensive consideration for the geological storage of CO2: oil and gas reservoirs, deep saline formations and unminable coal beds (Figure TS.7). In each case, geological storage of CO2 is accomplished by injecting it in dense form into a rock formation below the earth's surface. Porous rock formations that hold or (as in the case of depleted oil and gas reservoirs) have previously held fluids, such as natural gas, oil or brines, are potential candidates for CO2 storage. Suitable storage formations can occur in both onshore and offshore sedimentary basins (natural large-scale depressions in the earth's crust that are filled with sediments). Coal beds also may be used for storage of CO2 (see Figure TS.7) where it is unlikely that the coal will later be mined and provided that permeability is sufficient. The option of storing CO2 in coal beds and enhancing methane production is still in the demonstration phase (see Table TS.1).

Existing CO2 storage projects

Geological storage of CO2 is ongoing in three industrial-scale projects (projects in the order of 1 MtCO2 yr-1 or more): the Sleipner project in the North Sea, the Weyburn project in Canada and the In Salah project in Algeria. About 3-4 MtCO2 that would otherwise be released to the atmosphere is captured and stored annually in geological formations. Additional projects are listed in Table TS.5.

In addition to the CCS projects currently in place, 30 MtCO2 is injected annually for EOR, mostly in Texas, USA, where EOR commenced in the early 1970s. Most of this CO2 is obtained from natural CO2 reservoirs found in western regions of the US, with some coming from anthropogenic sources such as natural gas processing. Much of the CO2 injected for EOR is produced with the oil, from which it is separated and then reinjected. At the end of the oil recovery, the CO2 can be retained for the purpose of climate change mitigation, rather than vented to the atmosphere. This is planned for the Weyburn project.

Storage technology and mechanisms

The injection of CO2 in deep geological formations involves many of the same technologies that have been developed in the oil and gas exploration and production industry. Well-drilling technology, injection technology, computer simulation of storage reservoir dynamics and monitoring methods from existing applications are being developed further for design and operation of geological storage. Other underground injection practices also provide relevant operational experience. In particular, natural gas storage, the deep injection of liquid wastes, and acid gas disposal (mixtures of CO2 and H2S) have been conducted in Canada and the U.S. since 1990, also at the megatonne scale.

CO2 storage in hydrocarbon reservoirs or deep saline formations is generally expected to take place at depths below

800 m, where the ambient pressures and temperatures will usually result in CO2 being in a liquid or supercritical state.

Under these conditions, the density of CO2 will range from 50 to 80% of the density of water. This is close to the density of some crude oils, resulting in buoyant forces that tend to drive CO2 upwards. Consequently, a well-sealed cap rock over the selected storage reservoir is important to ensure that CO2 remains trapped underground. When injected underground, the

CO2 compresses and fills the pore space by partially displacing the fluids that are already present (the 'in situ fluids'). In oil and gas reservoirs, the displacement of in situ fluids by injected CO2 can result in most of the pore volume being available for CO2 storage. In saline formations, estimates of potential storage volume are lower, ranging from as low as a few percent to over 30% of the total rock volume.

Figure TS.7. Methods for storing CO2 in deep underground geological formations. Two methods may be combined with the recovery of hydrocarbons: EOR (2) and ECBM (4). See text for explanation of these methods (Courtesy CO2CRC).

Once injected into the storage formation, the fraction retained depends on a combination of physical and geochemical trapping mechanisms. Physical trapping to block upward migration of CO2 is provided by a layer of shale and clay rock above the storage formation. This impermeable layer is known as the "cap rock". Additional physical trapping can be provided by capillary forces that retain CO2 in the pore spaces of the formation. In many cases, however, one or more sides of the formation remain open, allowing for lateral migration of CO2 beneath the cap rock. In these cases, additional mechanisms are important for the long-term entrapment of the injected CO2.

The mechanism known as geochemical trapping occurs as the CO2 reacts with the in situ fluids and host rock. First, CO2 dissolves in the in situ water. Once this occurs (over time scales of hundreds of years to thousands of years), the CO2-laden water becomes more dense and therefore sinks down into the formation (rather than rising toward the surface).

Next, chemical reactions between the dissolved CO2 and rock minerals form ionic species, so that a fraction of the injected CO2 will be converted to solid carbonate minerals over millions of years.

Yet another type of trapping occurs when CO2 is preferentially adsorbed onto coal or organic-rich shales replacing gases such as methane. In these cases, CO2 will remain trapped as long as pressures and temperatures remain stable. These processes would normally take place at shallower depths than CO2 storage in hydrocarbon reservoirs and saline formations.

Geographical distribution and capacity of storage sites

As shown earlier in Section 2 (Figure TS.2b), regions with sedimentary basins that are potentially suitable for CO2 storage exist around the globe, both onshore and offshore. This report focuses on oil and gas reservoirs, deep saline

Table TS.5. Sites where CO2 storage has been done, is currently in progress or is planned, varying from small pilots to large-scale commercial applications.

Project name

Country

Injection start

Approximate average

Total (planned)

Storage reservoir

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