Andrew R. Scott

Thermogenic and Secondary Biogenic Gases, San Juan Basin, Colorado and New Mexico--Implications for Coalbed Gas Producibility

The San Juan basin is the most prolific coalbed gas basin in the world with 1992 production exceeding 440 Gcf (FOOTNOTE *) (12.4 billion m3), resources of approximately 50 Tcf (1.4 trillion m3), and proved reserves of over 6 Tcf (170 billion m3). Coalbed gas wells with the highest production (initial potential greater than 10 Mcf/day or 0.28 million m3/day) occur in the overpressured, north-central part of the basin. Hydrologic analysis indicates that overpressure in the Fruitland Formation is artesian in origin and represents repressuring that developed during the middle Pliocene. Highly permeable, laterally continuous coal beds override abandoned shoreline Pictured Cliffs sandstones and extend to the elevated recharge area in he northern basin to form a dynamic, regionally interconnected aquifer system. Coal rank and basin hydrodynamics control the composition of Fruitland coalbed gases, which varies significantly across the basin. Chemically dry gases in the north-central part of the basin coincide with meteoric recharge and regional overpressure. The consistency of methane ^dgr13C values across the basin, the presence of isotopically heavy carbon dioxide in coalbed gases and bicarbonate in formation waters, and biodegraded n-alkane distributions of some coal extracts indicate that coalbed gases in the north-central basin are a mixture of thermogenic (25-50%), secondary biogenic (15-30%), and migrated thermogenic (12-60%) gases. Migrated, conventionally and hydrodynamically trapped gases, in-situ generated secondary biogenic gases, and solution gases result in gas content that plot on or above the coal sorption isotherm. Bacteria transported basinward in groundwater flowing from the elevated northern basin margins metabolized wet gas components, n-alkanes, and organic compounds in the coal and generated secondary biogenic methane and carbon dioxide subsequent to coalification, uplift, erosion, and cooling. These gases may be limited to basin margins, where shallow depths and structural deformation result in higher permeability, or may extend more than 35 mi (56 km) basinward from the recharge zone. The presence of appreciable secondary biogenic gas indicates an active dynamic flow system with overall permeability sufficient for high productivity. Basin hydrogeology, reservoir heterogeneity, location of permeability barriers (no-flow boundaries), and the timing of biogenic gas generation and trap devel pment are critical for exploration and development of unconventional gas resources in organic-rich rocks.

Geological and hydrological controls on the producibility of coalbed methane

Geological and hydrological comparison of two United States coalbed methane basins, the prolific San Juan Basin and the marginally producing Sand Wash Basin, indicates that coal distribution and rank, gas content, permeability, ground-water flow, and depositional and structural setting are critical controls on coalbed methane producibility. A complex interplay, and moreover, a synergy amongst these controls determines high productivity. This paper proposes a basin-scale explanation for the prolific and marginal production in the two basins and that can be applied to evaluation of coalbed methane potential in coal basins worldwide. High productivity is governed by (1) thick, laterally continuous coals of high thermal maturity, (2) basinward flow of ground water through coals of high rank and gas content orthogonally toward no-flow boundaries (regional hingelines, fault systems, facies changes, and/or discharge areas), and (3) conventional trapping along those boundaries to provide additional gas beyond that sorbed on the coal surface.

Improving Coal Gas Recovery with Microbially Enhanced Coalbed Methane

Microbially enhanced coalbed methane (MECoM) imitates and enhances the natural process of secondary biogenic gas generation in coal beds that occurs in coal basins worldwide. MECoM involves the introduction of anaerobic bacterial consortia, which consists of hydrolyzers, acetogens and methanogens, and/or nutrients into coalbed methane wells. Coalbed methane production may increase through generation of additional methane, removal of pore-plugging coal waxes, and permeability enhancement as cleat-aperture size increases during biogasification. The amount of coal gas potentially generated by MECoM is large. If only one-hundredth of 1% (1/10,000) of U.S. (lower 48) coal resources were converted into methane using MECoM, gas resources would increase by 23 Tcf, or approximately 16% of current lower 48 nonassociated reserves. However, coal surface area and biogasification reaction rates in the subsurface may potentially limit gas generation, indicating that permeability enhancement may be the most significant benefit of MECoM. Additional research, including microbial sampling of deeply buried bituminous coals to identify genetically unique bacterial consortia, is required to fully evaluate MECoM and determine if the process will improve coalbed methane producibility. Successful implementation of MECoM requires an integrated approach towards understanding the geologic, hydrologic, organic and inorganic geochemistry, microbiological, and engineering factors that may limit MECoM in the subsurface. If economically feasible, MECoM can generate methane in coal beds that currently have limited coalbed methane potential, and thereby provide cheap, environmentally clean energy for many parts of the world.

A modified approach to estimating coal and coal gas resources; example from the Sand Wash Basin, Colorado

The significant increase in United States gas production from coal beds over the past 5 yr has encouraged exploration and development of coal gas resources worldwide. Accurate assessment of coal and coal gas resources and delineating areas within basins containing the largest resources are important aspects of resource development. Previous resource studies may have overestimated or underestimated coal gas resources because the ash and density terms of resource equations were inconsistently or inappropriately considered. In basins where coal analysis data are sparse, coal gas resources are best calculated on an ash-free basis. The density contrast between ash-forming minerals and organic matter is large enough that the weight percent ash is much larger than the corresponding volume percent. Therefore, a correction factor relating weight percent ash-free coal and ash yield (determined from proximate analysis) to ash-free coal volume is required to accurately calculate coal gas resources. Rather than using one density value, as has been done in previous studies, our calculations require that bulk coal density (including mineral matter) be distinguished from ash-free coal density. Coal and coal gas resources of the Williams Fork and Fort Union formations in the Sand Wash basin, determined from modified resource equations, are 291 billion tons (short tons) (264 billion t [metric ton]) and 79 Tcf(FOOTNOTE *) (2.2 Tm3). These resources are significantly higher than previous estimates of basin resources of 34.5 billion tons (31.3 billion t) of coal and 14 Tcf (0.4 Tm3) of coal gas. The Williams Fork Formation contains 79% of the coal and 95% of the coal gas resources, reflecting greater maximum burial depth and higher gas contents. The Fort Union Formation contains 21% of the coal, but only 5% of the coal gas resources. Coal gas resources are greatest in the central part of the basin where Williams Fork resources approach 70 Gcf(FOOTNOTE *)/mi SUP>2 (0.8 Gm3/km2). In comparison, the San Juan basin, the nations most prolific coal gas-producing basin, has maximum coal gas resources approaching 35 Gcf/mi2 (0.4 Gm3/km2). The high resource density in the Sand Wash basin is due to greater net coal thickness rather than high gas content.

Defining Coalbed Methane Exploration Fairways: An Example from the Piceance Basin, Rocky Mountain Foreland, Western United States

A basin-scale coalbed methane producibility and exploration model has been developed on the basis of research performed in the San Juan, Sand Wash, Greater Green Rivers, and Piceance Basins of the Rocky Mountain Foreland and reconnaissance studies of several other producing and prospective coal basins in the United States and worldwide. The producibility model indicates that depositional setting and coal distribution, coal rank, gas content, permeability, hydrodynamics, and tectonic/structural setting are controls critical to coalbed methane production. However, knowledge of a basin’s geologic and hydrologic characteristics will not facilitate conclusions about coalbed methane producibility because it is the interplay among geologic and hydrologic controls on production and their spatial relation that govern producibility. High producibility requires that the geologic and hydrologic controls be synergistically combined. That synergism is absent in the marginally producing, hydrocarbon-overpressured Piceance Basin. As predicted from the coalbed methane producibility model, significant coalbed methane production (greater than 1 MMcf/d [28 Mm3/d]) may be precluded in many parts of the hydrocarbon-overpressured Piceance Basin by the absence of coalbed reservoir continuity, high permeability, and dynamic groundwater flow. The best potential for coalbed methane production may lie in conventional and compartmentalized traps basinward of where outcrop and subsurface coals are in good reservoir and hydraulic communication and/or in areas of vertical flow potential and fracture-enhanced permeability. In the low-permeability, hydrocarbon-overpressured Piceance Basin, exploration and development of migrated conventionally and hydrodynamically trapped gases, in-situ-generated secondary biogenic gases, and solution gases will be required to achieve high coalbed methane production.