Coal porosity is the void space of this naturally fractured organic rock, which has a wide spectrum of pore sizes.
Coal gas reservoir engineering is often concerned only with mobile water porosity, defined as the void space of a coal containing water that will flow through the fractures in response to an applied pressure differential. This is the porosity that is emptied, partially or totally, during “dewatering” and is suspected to be primarily cleat, macropore, and perhaps some mesopore porosities. Mobile water porosity does not include bed moisture or other immoveable water in the reservoir. Mobile water porosity is the void fraction of a coal deposit that conveys gas and water to a wellbore, and fluid flow is described by Darcy’s law in conjunction with two-phase gas-water relative permeabilities. A review of various coal porosity definitions provides a better conceptual understanding of mobile water porosity but no definitive method for its measurement.
Separation of coal void space into cleat and matrix porosities for reservoir engineering purposes is artificial but useful. As estimated below, cleat or fracture porosity is on the order of 1% or less, typical of naturally fractured reservoirs.52 Porosity of the coal matrix is comprised of irregularly shaped voids in the organic matrix.
Some of the porosity is due to relict plant material, while some is the product of coalification. At the molecular level, coal is a tangle of long, complex polymers yielding highly irregular pores. Experimental evidence indicates the characteristic dimension of these voids in the matrix, often termed pore diameter, can vary in size by two orders of magnitude.53 Organic components of a coal metamorphose with thermal maturation, resulting in rank-dependent pore size distributions. Regardless of geological age, rank, or purity, porosity of a coal deposit is difficult to quantify. Cleat porosities are typically estimated from conceptual models or simulation history matches, while matrix porosities are determined indirectly from laboratory experiments.
One of the conceptual models for quantifying cleat porosities combines permeabilities determined from well tests with cleat spacings observed in coal cores and hand samples. Assuming a coal deposit can be idealized as a collection of matchsticks, cleat permeability is related to cleat spacing and porosity by54
kf = 1055.47d2ϕf3 where
kf = cleat permeability, md, d = cleat spacing, cm, and ϕf = cleat porosity, %.
Solving for cleat porosity,
kf 1/3
ϕf = 0.09822
[
—— d2]
(2.3)Cleat width is related to cleat porosity and cleat spacing by55
b = 50dϕf (2.4)
where
b = cleat width, microns.
As noted above, cleat spacing can vary by two orders of magnitude. Assuming bounding permeabilities of 0.1 and 100 md and cleat spacing limits of 0.2 and 5 cm in equation (2.3) yields cleat porosities of 1% down to 0.02%.
Cleat apertures, calculated from equation (2.4), range from 1 to 40 microns.
Techniques available for characterization of coal matrix porosity include low-pressure nitrogen and CO2 sorption analysis, mercury and helium porosimetry, and mercury injection. However, none of these techniques provide a direct measure of the total pore volume available to methane and CO2, the primary gases present in coals. Carbon dioxide can access smaller pores than other adsorbates, and low-pressure (up to 1 atm), low- temperature (0°C, 32°F) CO2 sorption is commonly used to investigate microporosity of coals. Porosities derived from low-pressure sorption of nitrogen at –196°C (–321°F) are indicative of mesoporosities. Helium and mercury porosimetry are utilized to investigate total open pore volume of the samples.
Gan et al. reported porosities of American coals, dividing them into groups with diameters less than 1.2 nm, diameters between 1.2 and 30 nm, and pores with diameters greater than 30 nm.56 Complete sample histories were not given, but measured porosities were not in-situ porosities, as the final steps in sample preparation involved heating sieved samples at 105°C (221°F) for 1 hr before degassing for 12 hr at 130°C (266°F) or 2 hr at room temperature. Thus, porosities reported by Gan et al., ranging from 4.1% to 23.2%, are almost certainly greater than in-situ porosities; however, the observed trends are probably correct. Total porosities of the laboratory samples, plotted as a function of fixed carbon (FC), % daf, in figure 2–2, decrease with increasing rank. The fraction of porosity in the smallest pores steadily increases with %C, daf, as shown in figure 2–3, while that of the largest pores shows the opposite trend. The porosity of pores of intermediate diameters is significant in subbituminous through high-volatile B bituminous rank samples. Porosity of low-rank coals, < 75% fixed carbon content, was primarily due to macropores. Porosity of medium-rank coals, with fixed carbon between 76% and 84%, was comprised mainly of micro and transitional pores. In high-rank coals, with fixed carbon
> 85%, porosity was mostly due to micropores.
Fig. 2–2. Coal porosity vs. fixed carbon, % daf57
Fig. 2–3. Coal porosity distributions vs. rank58
The effect of maceral type on coal porosity was partially addressed by Gan et al. in reporting vitrinite fraction of the porosity samples on a mineral-matter-containing basis (mmcb).59 As seen in figure 2–4, total coal porosity is roughly proportional to the volume percent vitrinite, but the significant scatter indicates a secondary control, probably mineral matter.
Levine defined water porosity as the volume percent water on an ash-free basis.60 Water porosity of bituminous coals varied with rank, declining from a maximum of 22% in coals with 81% carbon on a dry, mineral-matter-free basis (high-volatile bituminous) to a minimum of 2% at 90% carbon (low-volatile bituminous), then rebounding to 6% at 95% carbon (anthracite). Experimental methods and sample histories were not specified, complicating extrapolation of these results to in-situ conditions.
Porosities of selected North American and Australian coals were characterized by Bustin and Clarkson using the International Union of Pure and Applied Chemistry (IUPAC) pore size classifications of micropores (diameters less than 2 nm), mesopores (diameters between 2 and 50 nm), and macropores (diameters greater than 50 nm).61 This study found that total porosity decreases with rank, primarily due to a decline in macro and mesoporosities. In contrast, micropore volume increased with coal rank. These trends are in agreement with those of Gan et al., discussed above.62
Although this study had a very limited number of samples, total porosity declined from an average of 13%
in the subbituminous samples to an average of 4% in the medium-volatile samples. Complete sample histories were not discussed; therefore, these reported porosity values are probably higher than in-situ coal porosities.
Modal pore size for microporosity in coals of all ranks was approximately 1.2 nm, whereas mesoporosity peaked at about 4 nm in all samples with experimental indications of slit-shaped pores. For perspective, molecular diameters of gases typically found in coals are on the order of 0.5 nm.
Variation of total porosity as a function of maceral composition was not specifically addressed, but micropore porosity was seen to increase with increasing vitrinite on a mineral-matter-free basis. Bright, vitrinite-rich coals had a greater micropore volume fraction than dull, vitrinite-poor coals of equivalent rank. In contrast, the dull coals had a greater fraction of meso and macropore porosity than did the bright coals.
Fig. 2–4. Total porosity vs. vitrinite (mmcb = mineral-matter-containing basis)63
Sorbed gas volumes at a reservoir pressure 6 MPa (870 psia), calculated from methane sorption isotherms and assuming a sorbed gas density of 0.42252 g/cm3, were compared with total porosity measurements. The comparisons led to the conclusion that sorbed gas occupied more than 90% of total porosity in the semianthracite sample, more than 60% of total porosity of the medium-volatile bituminous sample, and less than 10% of the high-volatile bituminous and subbituminous samples. Thus in high-rank coals, sorption is the dominant storage mechanism, whereas low-rank coals can hold significant free gas volumes compressed in the pores.
Nelson found that effective porosity, defined as the ratio of interconnected cleat volume to bulk coal volume, of Fruitland coals of the San Juan Basin was linearly related to effective stress and vitrinite reflectance.64 Although increasing effective stress decreased effective porosity for a given sample, opposite behavior was noted for a collection of samples, indicating the role of areal and stratigraphic stress variations cannot be neglected. Effective porosities ranged from 0.6% to 1.2%.
Porosity sensitivity to stress in Carboniferous coal mine samples was reported by Wolf et al.65 The Belgian coal was high-volatile A bituminous in rank with 44% inertinite, while the German sample was medium-volatile bituminous rank and 87% vitrinite. Initial porosities of the Belgian coal, 2% to 5.5%, decreased to 0.5% when subjected to a stress of 6 MPa (870 psi). Initial porosities of the German coal, 5.5% to 6.5%, decreased to 5.0%
under the same stress loading, indicative of a stiffer coal. As the samples were vacuum dried for 24 hr and perhaps autoclaved prior to testing, reported porosities are greater than native porosities, but the overall trend of porosity reduction with stress is correct.
Simulation studies often vary coal fracture porosity, among other reservoir properties, to match performance of a well or a field. Porosities obtained from such history matching exercises are often on the order of 0.5% or less, similar to cleat porosities estimated above. Conway et al. reported a “natural fracture mobile water porosity”
of 0.53% from simulation of wells completed in the Blue Creek coal in the Warrior Basin.66 A simulation history match of Fruitland coal wells in the Tiffany area of the San Juan Basin by Ramurthy et al. yielded a porosity of 0.25%.67 Using a blend of well test analysis and simulation, Mavor obtained a porosity of 0.45% for a well in the fairway of the San Juan Basin.68 A modeling study of production from Rock Springs Formation coals of the Great
Divide (Greater Green River) Basin by Young et al. resulted in a porosity of 1.2%.69 However, these simulation porosities are probably lower than actual porosities for several reasons.
Simulated water production is affected by gas-water relative permeabilities, which often have an irreducible water saturation of zero, implying the model is concerned only with mobile water porosity. This simulation porosity represents water that is important for production operations and does not reflect the true void space of a coal deposit. In addition, coal gas simulations typically use a single model layer for each coal seam, rarely breaking an actual seam into multiple model layers. This approach, while computationally efficient and often sufficient for prediction of gas and water production, neglects buoyancy-driven vertical segregation of gas and water within a seam. Gas flowing across the upper one-third or one-half of a coal with 1% or 2% total porosity is thus described in a simulator using porosities of only a fraction of a percent.
Coal porosity is smaller than that of conventional reservoirs and difficult to determine. Cleat porosities calculated from a matchstick model with reported permeabilities and observed cleat spacing yields porosities of 1% or less. Coal matrix porosities measured in laboratory studies are typically on the order of a few percent. As most studies utilize samples of uncertain history held at conditions other than in situ, these reported porosities provide an upper bound on in-situ porosities. Simulation-derived coal porosities are on the order of 1% or less but suffer from inclusion of other physics, such as buoyancy and capillary pressures, which are not treated explicitly in the reservoir model. For reservoir engineering purposes, porosity of subbituminous coals is often assumed to be 10%, while that of bituminous coals is assumed to be 1%.