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%.
density of the water held in the coal is 1.00 g/cm3. Further assume a bituminous coal with an equilibrium moisture of 3%. Thus, this coal is 47% ash with a density of
gρ = 1.63 ——
cm3
Assuming a subbituminous coal with an equilibrium moisture of 23% and repeating the calculation yields a density of
gρ = 1.36 ——
cm3
Experience shows that while the above densities provide reliable pay cutoffs for identifying mineable coal, they are often too conservative for defining a coal reservoir, as higher density rocks can hold substantial volumes of gas. Current coal gas reservoir engineering practice employs a coal pay cutoff of 2.0 g/cm3. Assuming 3%
equilibrium moisture, this density cutoff corresponds to an ash fraction of 75%, whereas an equilibrium moisture of 23% yields an 84% ash fraction.
Density of the organic fraction of a coal depends on maceral composition and can be calculated from
ρo = ρvVv + ρlVl + ρiVi (2.6)
where
ρv = vitrinite density, g/cm3, ρl = liptinite density, g/cm3, ρi = inertinite density, g/cm3, Vv = volume fraction vitrinite,
Vl = volume fraction liptinite, and Vi = volume fraction inertinite.
Average vitrinite, liptinite, and inertinite maceral densities reported by Mavor and Nelson are 1.29, 1.18, and 1.35 g/cm3, respectively.72 Maceral density varies with coal rank and perhaps geological age.73 However, for reservoir engineering purposes, the organic fraction of a coal deposit can be estimated from a maceral distribution and the average maceral densities of Mavor and Nelson.
Densities of the organic fraction and the ash can be estimated from proximate analyses and bulk densities.
Equation (2.5) can be rewritten as
(2.7) The left-hand side of this relation is termed the reciprocal dry density, and inspection of the equation shows it to be linearly related to the dry ash weight fraction, defined as the ash fraction divided by one minus the equilibrium moisture fraction.
A correlation relating in-situ gas content of a fully saturated coal to wireline log density can be developed from the above equations. Construction of such a relation requires substantial and expensive field and laboratory tests on samples from the initial corehole(s) or well(s). However, once developed, it minimizes coring time and costs required to estimate gas in place of a particular property or play. Solving equation (2.5) for ash fraction as a function of coal density gives
(2.8)
The equilibrium moisture fraction, w, is available from proximate analyses, while coal water density is typically assumed to be 1.0 g/cm3. Densities of the organic fraction and ash are determined from the intercepts of equation (2.7). Density of the organic fraction of a coal can also be calculated from equation (2.6) if the maceral distribution is known.
As the coal is saturated, gas content can be calculated from pressure and the Langmuir isotherm
V = VLdaf (1 – a – w) ——–— p (2.9)
p + pL where
V = gas content, scf/t or cm3/g,
VLdaf = dry, ash-free Langmuir volume constant, scf/t or cm3/g, p = pressure, psia or MPa, and
pL = Langmuir pressure constant, psia or MPa.
Determination of ash and organic densities and construction of a bulk density–gas content curve are illustrated in the following example.
Example 2.3. Organic fraction and ash density of San Juan Basin Fruitland coal
Coal bulk densities and ash and moisture fractions for Fruitland coal from San Juan Basin reported by Mavor and Nelson are shown in table 2–6.74 The samples were sourced from the Valencia Canyon 32-1 well. Reciprocal dry density, based on a brine density of 1.0 g/cm3, is plotted as a function of dry ash weight fraction in figure 2–5.
Fitting equation (2.7) to the data gives the line shown in the figure. The vertical axis intercept of that line gives an organic fraction density of 1.181 g/cm3, while the horizontal axis intercept yields an ash density of 2.384 g/cm3. Table 2–6. Density, ash, and moisture—Valencia Canyon 32-1, Fruitland coal, San Juan Basin
Seq. no. Density, g/cm3 Ash, fraction Moisture, fraction Dry ash fraction Reciprocal dry density, g/cm3
1 1.40 0.078 0.012 0.079 0.711
2 1.26 0.082 0.018 0.083 0.790
3 1.25 0.105 0.014 0.107 0.797
4 1.24 0.115 0.023 0.118 0.802
5 1.10 0.177 0.007 0.178 0.908
6 1.28 0.244 0.008 0.246 0.780
7 1.72 0.488 0.007 0.491 0.578
8 1.80 0.649 0.013 0.657 0.550
9 1.82 0.749 0.026 0.769 0.537
Average moisture = 0.143 Note: Water density = 1.0 g/cm3.
Source: Mavor, M. J., and Nelson, C. R. 1997.
dry ash weight fraction
Fig. 2–5. Reciprocal dry density vs. dry ash weight fraction
Average maceral composition of this data set is 84.6% vitrinite, 3.1% liptinite, and 12.3% inertinite. Density of the organic component calculated from equation (2.6) with these maceral fractions and the maceral densities of Mavor and Nelson given above is 1.294 g/cm3, higher than the intercept-based value derived above by about 10%. The computed ash density of 2.384 g/cm3 is slightly lower than densities of materials typically comprising coal ash. For example, density of kaolinite is 2.42 g/cm3, quartz is 2.65 g/cm3, and feldspar ranges from 2.55 to 2.76 g/cm3. Mineralogy of the coal ash was not discussed by Mavor and Nelson, and reasons for this low computed ash density are not known.
Mavor and Nelson report the Valencia Canyon 32-1 dry, ash-free Langmuir volume constant as 946.9 scf/t, and the Langmuir pressure constant as 368.5 psia. Average equilibrium moisture for this set of samples is 0.0143.
The coal is slightly overpressured, with an initial reservoir pressure of 761 psia. Utilizing these constants in equations (2.8) and (2.9) yields the relation between coal density and gas content shown in figure 2–6.
3
Fig. 2–6. Example 2.3 in-situ gas content vs. density correlation