Coal bed methane extraction

Coal bed methane extraction (CBM extraction) is a method for extracting methane from a coal deposit.

Contents

Basic principles

The methane is adsorbed into the solid coal matrix (coal macerals) and is released when the coal seam is depressurised. To economically retrieve reserves of methane, wells are drilled into the coal seam, the seam is dewatered, then the methane is extracted from the seam, compressed and piped to market. The goal is to decrease the water pressure by pumping water from the well. The decrease in pressure allows methane to desorb from the coal and flow as a gas up the well to the surface.

While dewatering is occurring, the operator should make sure that the pumpjack is not running too long. If the water level is pumped too low, this will allow the gas to travel up the tubing into the water line, causing the well to become "gassy". The main objective is not to put the gas in the water line, but to allow it to flow up the backside of the well (casing) and into the pipeline, where it can be transported to the compressor station and delivered to the customer for sales. Once the gas goes up the tubing, it is usually recovered in a water-gas separator at the surface. However, pumping water and gas is inefficient and can cause pump wear and breakdown.

Areas with coal bed methane extraction

This process has resulted in the drilling of tens of thousands of gas wells, and extensive support facilities such as roads, pipelines, and compressors.

The use of this method is currently expanding in the Powder River Basin of northeast Wyoming and southeast Montana. Seven percent of the natural gas (methane) currently produced in the United States comes from CBM extraction. Methane from coalbed reservoirs can be recovered economically, but disposal of water is an environmental concern.

Most gas in coal is stored on the internal surfaces of organic matter. Because of its large internal surface area, coal stores 6 to 7 times more gas than the equivalent rock volume of a conventional gas reservoir. Gas content generally increases with coal rank, with depth of burial of the coalbed, and with reservoir pressure. Fractures, or cleats, that permeate coalbeds are usually filled with water; the deeper the coalbed, the less water is present, but the more saline it becomes. In order for gas to be released from the coal, its partial pressure must be reduced, and this is accomplished by removing water from the coalbed. Large amounts of water, sometimes saline, are produced from coalbed methane wells, especially in the early stages of production. While economic quantities of methane can be produced, water disposal options that are environmentally acceptable and yet economically feasible, are a concern. Water may be discharged on the surface if it is relatively fresh, but, often, it is injected into rock at a depth where the quality of the injected water is less than that of the host rock. Another alternative, not yet attempted, is to evaporate the water and collect the potentially saleable solid residues; this scheme might be feasible in regions having high evaporation rates.[1]

Measuring the gas content of coal

Coalbed gas content measurements are commonly used in mine safety as well as coalbed methane resource assessment and recovery applications. Gas content determination techniques generally fall into two categories: (1) direct methods which actually measure the volume of gas released from a coal sample sealed into a desorption canister and (2) indirect methods based on empirical correlations, or laboratory derived sorption isotherm gas storage capacity data.

The total gas content by the in direct methods is based on the empirical formula given by Meinser and Kim. The quantity of gas is determined by Meisner and Kim formula with using the moisture content, volatile content, volume of gas adsorbed on wet coal, fixed carbon, thickness of coal and temperature.
Meinser (1984) observed that the amount of methane gas (VCH4) is related to volatile matter (daf).


VCH4 = −325.6 × log (V.M/37.8)


Estimation of in-situ gas content of the coal will be evaluated by using Kim’s (Kim 1977) equation


V = (100 −M − A) /100 × [ Vw /Vd ] [K(P)N – (b × T)]
Where,
V = Volume of methane gas adsorbed (cc/g)
M = Moisture content (%)
A = Ash content (%).
Vw/Vd = 1/(0.25 ×M + 1)
Vw = Volume of gas adsorbed on wet coal (cc/g)
Vd = Volume of gas adsorbed on dry coal (cc/g)
The values of K and N depend on the rank of the coal and can be expressed in terms of ratio of fixed carbon (FC) to Volatile matter(VM)
K = 0.8 (F.C /V.M) + 5.6 Where
F.C = Fixed carbon (%)
VM = Volatile matter (%)
N = Composition of coal (for most bituminous coals, N = (0.39 - 0.013 × K)
b =Adsorption constant due to temperature change (cc/g/◦C).
T = Geothermal Gradient × (h/ 100) + To
T = Temperature at given depth
To = Ground temperature
h = Depth (m)


Estimation of methane content in coal seams by Karol curve


In the absence measured methane content of coalbeds, and production data from coalbed methane wells, gas content can be estimated using the Eddy curve. Eddy and other construct a series of curve the give the estimated maximum producible methane content of coalbed as a function of depth and rank.
The estimation of methane content of a coalbed is determined from the Eddy curve by locating the average depth of each coal seam on the depth axis. A normal line is extended upward from the depth axis (feet) to intersect the specific coal rank curves. A line from the point on the curve is extended normal to the lost and desorbed gas axis(cm3/gm). The intersection of the line and the axis is the estimated methane content of the coal seam.

Interpretation of Ash analysis

Ash is an important indicator of clastic input, likely derived from marine or fluvial deposition of clay, silt, and sand during peat development. When comparing ash contents of subsurface samples with outcrop samples, ash content on average appears to be lower for outcrop samples. Lower ash contents of outcrop samples may be due to coal deposits being up dip and further away from a marine influence than samples down-dip.

See also

References


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