Carbon Sequestration: Injecting Realities
The amount of carbon dioxide used in enhanced oil recovery projects indicates the number of wells needed for large-scale sequestration projects. And that number is huge.
Carbon dioxide sequestration has become part of the lexicon in the media, in government proclamations, and even in professional papers. What is real, what is realistic, and what is practical? Candidates for geological sequestration can be oil and gas reservoirs and deep saline formations. Although each kind of formation is different, their suitability can basically be assessed by injectivity, storage capacity, and containment. Injection depth is recommended at intervals between 800 and 3,300 meters to insure the safety of potable water aquifers, to keep the carbon dioxide at supercritical states (CO2 critical point: 1,071 psi and 87.9^0F), to optimize storage capacity, and to keep compression costs reasonable. The ability to inject liquefied carbon dioxide is primarily a function of the reservoir permeability, its formation thickness, and the injection pressure. The injection rate is also controlled by the technical limits of the compression equipment.
The petroleum industry has been injecting carbon dioxide for enhanced oil recovery (E.O.R.) for over 30 years. Thus, the injection rates for E.O.R. may provide the approximate ranges for sequestration.
According to the Energy Information Administration, fossil-fuel related carbon dioxide emissions in the U.S. totaled 5,005 million metric tons in 1990 and 5,945 MMt in 2005. By 2030, the E.I.A. expects carbon dioxide emissions will increase by about 2,005 MMt, to 7,950 MMt. If the Kyoto Protocol emission standard (5 percent below the 1990 emission level) is executed, or if emissions are kept at the 2005 level, enormous amounts of carbon dioxide will have to be injected, requiring thousands of wells to be drilled.
Table 1 shows the CO2 injection rates for two CO2-EOR units, SACROC Unit and Wasson Denver Unit in the Permian Basin (Stevens et al., 1998; Kinder Morgan “FlashNews,” 2004), and a case study for potential CO2-EOR and sequestration for the Grieve field in Wyoming (Wo et al., 2008). Permeability of 10 millidarcies is used as a cutoff for selection of suitable sequestration sites. The average injection rates at the Wasson Denver Unit can be used as the lower limit for evaluation. The Grieve field has exceptionally high permeability and low reservoir pressure, providing an optimistic example of the upper limit for carbon dioxide injection rates.
These parameters were used to calculate the number of wells needed in the U.S. for carbon dioxide injection if it were to meet the Kyoto Protocol emission requirement and to keep total carbon emissions at 2005 levels, assuming that carbon dioxide emissions increase linearly between 2005 and 2030 (Table 2).
To inject all of the additional gas and thus keep total emissions at 2005 levels, the U.S. will need to drill 100,830 more wells (assuming the permeabilities and pressures found in the Wasson Denver Unit) to dispose of the additional 2,005 MMt per year of carbon dioxide. For comparison, about 40,000 oil and gas wells are drilled annually in the United States.
A serious problem for geologic carbon sequestration is the decrease of injectivity over time, because of the scaling induced by reactions between CO2 and the surrounding rock and/or other formation damage factors. For instance, the injection rate at the SACROC unit decreased by about two-thirds over a 24-year period. Furthermore, the estimates in Table 2 are for CO2 injection that is accompanied by the production of oil and gas. In that scenario, about two-thirds of the injected CO2 returns to the surface with the oil and gas, and thus the hydrocarbon formation is allowed to maintain a near-steady state in terms of pressure maintenance. Permanent CO2 injection in deep saline formations will be far more difficult because of the formation pressure build-up during the injection. Given the problems of pressure build-up, at least triple the number of wells cited here will be needed if injectivity doesn’t decrease. And as soon as the reservoir capacity is reached, new reservoirs must be located and new wells drilled.
Thus, if 302,490 wells are need for injection and we assume an average of $10 million to drill and complete each well, along with the ancillary piping, storage, valves, and other equipment, by 2030 the total cost of the injection wells alone will exceed $3 trillion. But the number and cost of the injection wells are just two of many factors in the carbon dioxide geological sequestration process. Before injection, carbon dioxide has to be separated from flue gas, which contains only 8 to 13 percent carbon dioxide. The separation cost alone is about $150 per ton, according to the Department of Energy’s 2006 estimate. This translates into some $300 billion per year just for the separation (and assumes only the costs associated with treating the 2,005 MMt of incremental carbon dioxide cited above). Estimates for compression and transportation vary considerably. But all told, the total cost of such an ambitious carbon dioxide geo-sequestration effort could easily surpass $1.5 trillion per year, based on calculations I have done in collabation with Michael J. Economides.
An aspect of geologic sequestration that is seldom discussed is the management scenario once a given well has reached its carbon dioxide limit. Ensuring that the carbon dioxide doesn’t leak from the formation requires monitoring, and any leakage could present legal problems to the sequestration wells’ owners.
Whether, when, and how much carbon dioxide sequestration will ever occur on a commercial scale remains in question, and to achieve it will be expensive and problematic. The proposition has yet to be properly addressed in either a real or a practical context.
Xina Xie is a senior research engineer at the University of Wyoming who specializes in enhanced oil recovery.