DIVSION COLUMNS ARCHIVES

By JACK C. PASHIN

It Loves Acid Gas

Coal Has CO₂ Capture Opportunities

(Editor's note: Pashin, with the Alabama Geological Survey in Tuscaloosa, Ala., is chair of the EMD Coal Committee.)

Figure 1. Geologic factors affecting coalbed methane production are similar to those affecting the acid-gas sequestration potential of coal.

Coalbed methane accounts for about 8 percent of the natural gas produced in the United States. With global exploration and development in an early phase, coalbed methane is poised to continue for decades as an important energy source.

Coal also is a potentially important sink for greenhouse gases like carbon dioxide (CO₂), as well as other acid gases such as sulfur dioxide (SO₂) and hydrogen sulfide (H₂S). Sequestration of CO₂ in coal is attractive because coal has greater affinity for acid gas than for methane (CH₄).

Because of this, injection of CO₂ and other gases has potential not only to benefit the environment, but to enhance coalbed methane recovery in much the same way that waterflooding or CO₂ injection can be used to enhance oil recovery.

With the promise of environmental benefits and enhanced gas recovery come technical challenges that need to be confronted. Among the greatest challenges for implementing sequestration programs is developing economically feasible technology for separation of acid gas at the source, and developing the infrastructure to transport the gas to prospective sequestration sites.

The National Energy Technology Laboratory of the U.S. Department of Energy has implemented a vigorous and diverse research and development program to address these and a host of other geologic and engineering issues that must be faced before CO₂ sequestration can be demonstrated at a broad scale.

Coal-fired power plants are significant sources of CO₂ and SO₂, and separation technologies being considered range from cryogenic and chemical separators to membrane separators and pressure-swing adsorption units.

H₂S is a hazardous waste product of oil and gas fields, and chemical separation of H₂S from hydrocarbon streams is a long-standing practice. Once acid gas is separated from the source, it can be transported by pipeline, truck or some other method to where it can be injected into coal.

Although much of the technology required to inject gas into coal already is available, a detailed understanding of reservoir geology is indispensable for ensuring that the gas is sequestered safely and effectively.

The geologic factors that must be considered for sequestering acid gas in coal include stratigraphy, sedimentology, structural geology, coal quality, basin geothermics and hydrology. For example:

Stratigraphic and sedimentologic variables are important because the thickness, continuity and geometry of coal bodies are determined largely in the original depositional environment.

Geologic structure is a fundamental consideration because faults limit the continuity of coal, and fractures may pose risk for leakage of injected gas from coal into the adjacent country rock or to the atmosphere.

Coal quality, specifically rank and grade, affect how much acid gas can be sequestered in coal and the relative proportions of gas that can be sequestered.

For individual gases, adsorption capacity increases significantly with rank. Researchers at the U.S. Geological Survey have confirmed that coal of bituminous rank can adsorb about twice as much CO₂ as CH₄ at reservoir pressure, and have discovered that sub-bituminous coal and lignite can adsorb many times more CO₂ than CH₄.

Along these same lines, researchers at the University of British Columbia have found that coal is an exceptional sorbent for H₂S and SO₂, with adsorption ratios relative to CH₄ approaching or even exceeding 100:1 at low pressure. Coal grade is important because the mineral constituents of coal can adsorb only minimal amounts of gas relative to the microporous organic constituents.

Thus, coal with high ash content tends to have reduced gas capacity.

Hydrology and geothermics are significant from the standpoints of water chemistry and phase relationships. Fresh water is common in coalbed methane reservoirs, and current regulations limit injection for enhanced hydrocarbon recovery to formations with total dissolved solids content greater than 3,000 mg/l.

Phase changes occur for acid gases within the realm of common reservoir conditions.

For example, the Alabama Geological Survey has determined that about half of the coalbed methane wells in the Black Warrior Basin had bottom-hole pressures and temperatures beyond the critical point for CO₂ prior to gas production. Understanding phase relationships for CO₂ is especially important, because supercritical CO₂ can react with and weaken coal.

Pilot programs for the injection of CO₂ in coal have been conducted for a number of years in the San Juan Basin of Colorado and New Mexico (BP-Amoco and Burlington Resources) and in the western Canada foreland basin (Alberta Research Council). These programs point toward success, and new pilot programs are set to begin in West Virginia (CONSOL) and southern Poland (RECOPOL).

A key concern has been the reduction of permeability by swelling of coal as CO₂ is adsorbed. However, long-term gas flooding in the San Juan Basin indicates that careful monitoring of injection can result in sustained CO₂ sequestration and enhanced coalbed methane recovery.

As challenges are identified and overcome, a future that couples environmental benefit with enhanced resource recovery is emerging.