Ladbroke Grove —_ Yolla Taranaki Basin
Figure 5.11 Examples of natural accumulations of CO2 around the world. Regions containing many occurrences are enclosed by a dashed line. Natural accumulations can be useful as analogues for certain aspects of storage and for assessing the environmental impacts of leakage. Data quality is variable and the apparent absence of accumulations in South America, southern Africa and central and northern Asia is probably more a reflection of lack of data than a lack of CO2 accumulations.
evidence of long-term trapping of CO2. Extensive studies have been undertaken on small-scale CO2 accumulations in the Otway Basin in Australia (Watson et al., 2004) and in France, Germany, Hungary and Greece (Pearce et al., 2003).
Conversely, some systems, typically spas and volcanic systems, are leaky and not useful analogues for geological storage. The Kileaua Volcano emits on average 4 MtCO2 yr-1. More than 1200 tCO2 day-1 (438,000 tCO2 yr-1) CO2 accumulations around the South China Sea include the
Russia, the Paradox Basin (USA) and the Alberta Basin (western Canada). In the North Sea and Barents Sea, a few fields have up to 10% CO2, including Sleipner and Snohvit (Figure 5.11). The La Barge natural gas field in Wyoming, USA, has 3300 Mt of gas reserves, with an average of 65% CO2 by volume. In the Appennine region of Italy, many deep wells (1-3 km depth) have trapped gas containing 90% or more CO2 by volume. Major leaked into the Mammoth Mountain area, California, between 1990 and 1995, with flux variations linked to seismicity (USGS, 2001b). Average flux densities of 80-160 tCO2 m-2 yr-1 are observed near Matraderecske, Hungary, but along faults, the flux density can reach approximately 6600 t m-2 yr-1 (Pearce et al., 2003). These high seepage rates result from release of CO2 from faulted volcanic systems, whereas a normal baseline CO2 flux is of the order of 10-100 gCO2 m-2 day-1 under temperate climate conditions (Pizzino et al., 2002). Seepage of CO2 into Lake Nyos (Cameroon) resulted in CO2 saturation of water deep in the lake, which in 1987 produced a very large-scale and (for more than 1700 persons) ultimately fatal release of CO2 when the lake overturned (Kling et al., 1987). The overturn of Lake Nyos (a deep, stratified tropical lake) and release of CO2 are not representative of the seepage through wells or fractures that may occur from underground geological storage sites. Engineered CO2 storage sites will be chosen to minimize the prospect of leakage. Natural storage and events such as Lake Nyos are not representative of geological storage for predicting seepage from engineered sites, but can be useful for studying the health, safety and environmental effects of CO2 leakage (Section 5.7.4).
Carbon dioxide is found in some oil and gas fields as a separate gas phase or dissolved in oil. This type of storage is relatively common in Southeast Asia, China and Australia, less common in other oil and gas provinces such as in Algeria,
Figure 5.12 Location of some natural gas storage projects.
world's largest known CO2 accumulation, the Natuna D Alpha field in Indonesia, with more than 9100 MtCO2 (720 Mt natural gas). Concentrations of CO2 can be highly variable between different fields in a basin and between different reservoir zones within the same field, reflecting complex generation, migration and mixing processes. In Australia's Otway Basin, the timing of CO2 input and trapping ranges from 5000 years to a million years (Watson et al, 2004).
5.2.4 Industrial analogues for CO2 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 (Figure 5.12). 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 (Box 5.5). 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, overpressuring 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.
Figure 5.12 Location of some natural gas storage projects.
The Berlin Natural Gas Storage Facility is located in central Berlin, Germany, in an area that combines high population density with nature and water conservation reservations. This facility, with a capacity of 1085 million m3, was originally designed to be a reserve natural gas storage unit for limited seasonal quantity equalization. A storage production rate of 450,000 m3 h-1 can be achieved with the existing storage wells and surface facilities. Although the geological and engineering aspects and scale of the facility make it a useful analogue for a small CO2 storage project, this project is more complex because the input and output for natural gas is highly variable, depending on consumer demand. The risk profiles are also different, considering the highly flammable and explosive nature of natural gas and conversely the reactive nature of CO2.
The facility lies to the east of the North German Basin, which is part of a complex of basin structures extending from The Netherlands to Poland. The sandstone storage horizons are at approximately 800 m below sea level. The gas storage layers are covered with layers of claystone, anhydrite and halite, approximately 200 m thick. This site has complicated tectonics and heterogeneous reservoir lithologies.
Twelve wells drilled at three sites are available for natural gas storage operation. The varying storage sand types also require different methods of completion of the wells. The wells also have major differences in their production behaviour. The wellheads of the storage wells and of the water disposal wells are housed in 5 m deep cellars covered with concrete plates, with special steel covers over the wellheads to allow for wireline logging. Because of the urban location, a total of 16 deviated storage wells and water disposal wells were concentrated at four sites. Facilities containing substances that could endanger water are set up within fluid-tight concrete enclosures and/or have their own watertight concrete enclosures.
Acid gas injection operations represent a commercial analogue for some aspects of geological CO2 storage. Acid gas is a mixture of H2S and CO2, with minor amounts of hydrocarbon gases that can result from petroleum production or processing. In Western Canada, operators are increasingly turning to acid gas disposal by injection into deep geological formations. Although the purpose of the acid gas injection operations is to dispose of H2S, significant quantities of CO2 are injected at the same time because it is uneconomic to separate the two gases.
Currently, regulatory agencies in Western Canada approve the maximum H2S fraction, maximum wellhead injection pressure and rate and maximum injection volume. Acid gas is currently injected into 51 different formations at 44 different locations across the Alberta Basin in the provinces of Alberta and British Columbia (Figure 5.13). Carbon dioxide often represents the largest component of the injected acid gas stream, in many cases, 14-98% of the total volume. A total of 2.5 MtCO2 and 2 MtH2S had been injected in Western Canada by the end of 2003, at rates of 840-500,720 m3 day-1 per site, with an aggregate injection rate in 2003 of 0.45 MtCO2 yr-1 and 0.55 MtH2S yr-1, with no detectable leakage.
Acid gas injection in Western Canada occurs over a wide range of formation and reservoir types, acid gas compositions and operating conditions. Injection takes place in deep saline formations at 27 sites, into depleted oil and/or gas reservoirs at 19 sites and into the underlying water leg of depleted oil and gas reservoirs at 4 sites. Carbonates form the reservoir at 29 sites and quartz-rich sandstones dominate at the remaining 21 (Figure 5.13). In most cases, shale constitutes the overlying confining unit (caprock), with the remainder of the injection zones being confined by tight limestones, evaporites and anhydrites.
Since the first acid-gas injection operation in 1990, 51 different injection sites have been approved, of which 44 are currently active. One operation was not implemented, three were rescinded after a period of operation (either because injection volumes reached the approved limit or because the gas plant producing the acid gas was decommissioned) and three sites were suspended by the regulatory agency because of reservoir overpressuring.
In many parts of the world, large volumes of liquid waste are injected into the deep subsurface every day. For example, for the past 60 years, approximately 9 billion gallons (34.1 million m3) of hazardous waste is injected into saline formations in the United States from about 500 wells each year. In addition, more than 750 billion gallons (2843 million m3) of oil field brines are injected from 150,000 wells each year. This combined annual US injectate volume of about 3000 million m3, when converted to volume equivalent, corresponds to the volume of approximately 2 GtCO2 at a depth of 1 km. Therefore, the experience gained from existing deep-fluid-injection projects is relevant in terms of the style of operation and is of a similar magnitude to that which may be required for geological storage of CO2.
5.2.5 Security and duration of CO2 storage in geological formations
Evidence from oil and gas fields indicates that hydrocarbons and other gases and fluids including CO2 can remain trapped for millions of years (Magoon and Dow, 1994; Bradshaw et al., 2005). Carbon dioxide has a tendency to remain in the subsurface (relative to hydrocarbons) via its many physico-chemical immobilization mechanisms. World-class petroleum provinces have storage times for oil and gas of 5-100 million years, others for 350 million years, while some minor petroleum
0 100 200 300 km
A Carbonate o Siliciclastic
■ Oil reservoirs A Gas reservoirs A Oil and gas reservoirs o Deep saline formations + Acid gas dissolved In water prior to injection
0 100 200 300 km
A Carbonate o Siliciclastic
Figure 5.13 Locations of acid gas injection sites in the Alberta Basin, Canada: (a) classified by injection unit; (b) the same locations classified by rock type (from Bachu and Haug, 2005).
accumulations have been stored for up to 1400 million years. However, some natural traps do leak, which reinforces the need for careful site selection (Section 5.3), characterization (Section 5.4) and injection practices (Section 5.5).
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