R. Marc Bustin

Characterization of gas shale pore systems by porosimetry, pycnometry, surface area, and field emission scanning electron microscopy/transmission electron microscopy image analyses: Examples from the Barnett, Woodford, Haynesville, Marcellus, and Doig units

The nanometer-scaled pore systems of gas shale reservoirs were investigated from the Barnett, Marcellus, Woodford, and Haynesville gas shales in the United States and the Doig Formation of northeastern British Columbia, Canada. The purpose of this article is to provide awareness of the nature and variability in pore structures within gas shales and not to provide a representative evaluation on the previously mentioned North American reservoirs. To understand the pore system of these rocks, the total porosity, pore-size distribution, surface area, organic geochemistry, mineralogy, and image analyses by electron microscopy were performed. Total porosity from helium pycnometry ranges between 2.5 and 6.6%. Total organic carbon content ranges between 0.7 and 6.8 wt. %, and vitrinite reflectance measured between 1.45 and 2.37%. The gas shales in the United States are clay and quartz rich, with the Doig Formation samples being quartz and carbonate rich and clay poor. Higher porosity samples have higher values because of a greater abundance of mesopores compared with lower porosity samples. With decreasing total porosity, micropore volumes relatively increase whereas the sum of mesopores and macropore volumes decrease. Focused ion beam milling, field emission scanning electron microscopy, and transmission electron microscopy provide high-resolution (∼5 nm) images of pore distribution and geometries. Image analysis provides a visual appreciation of pore systems in gas shale reservoirs but is not a statistically valid method to evaluate gas shale reservoirs. Macropores and mesopores are observed as either intergranular porosity or are confined to kerogen-rich aggregates and show no preferred orientation or align parallel with the laminae of the shale. Networks of mesopores are observed to connect with the larger macropores within the kerogen-rich aggregates.

Characterizing the shale gas resource potential of Devonian–Mississippian strata in the Western Canada sedimentary basin: Application of an integrated formation evaluation

Devonian–Mississippian strata in the northwestern region of the Western Canada sedimentary basin (WCSB) were investigated for shale gas potential. In the subsurface, thermally mature strata of the Besa River, Horn River, Muskwa, and Fort Simpson formations attain thicknesses of more than 1 km (0.6 mi), encompassing an area of approximately 125,000 km2 (48,300 mi2) and represent an enormous potential gas resource. Total gas capacity estimates range between 60 and 600 bcf/section. Of particular exploration interest are shales and mudrocks of the Horn River Formation (including the laterally equivalent lower Besa River mudrocks), Muskwa Formation, and upper Besa River Formation, which yield total organic carbon (TOC) contents of up to 5.7 wt.%. Fort Simpson shales seldom have TOC contents above 1 wt.%. Horn River and Muskwa formations have excellent shale gas potential in a region between longitudes 122W and 123W and latitudes 59N and 60N (National Topographic System [NTS] 94O08 to 94O15). In this area, which covers an areal extent of 6250 km2 (2404 mi2), average TOC contents are higher (3 wt.% as determined by wire-line-log calibrations), and have a stratal thickness of more than 200 m (656 ft). Gas capacities are estimated to be between 100 and 240 bcf/section and possibly greater than 400 tcf gas in place. A substantial percentage of the gas capacity is free gas caused by high reservoir temperatures and pressures. Muskwa shales have adsorbed gas capacities ranging between 0.3 and 0.5 cm3/g (9.6–16 scf/t) at reservoir temperatures of 60–80C (140–176F), whereas Besa River mudrocks and shales have low adsorbed gas capacities of less than 0.01 cm3/g (0.32 scf/t; Liard Basin region) because reservoir temperatures exceed 130C (266F). Potential free gas capacities range from 1.2 to 9.5 cm3/g (38.4 to 304 scf/t) when total pore volumes (0.4–6.9%) are saturated with gas. The mineralogy has a major influence on total gas capacity. Carbonate-rich samples, indicative of adjacent carbonate platform and embayment successions, commonly have lower organic carbon content and porosity and corresponding lower gas capacity (1% TOC and 1% porosity). Seaward of the carbonate Slave Point edge, Muskwa and lower Besa River mudrocks can be both silica and TOC rich (up to 92% quartz and 5 wt.% TOC) and most favorable for shale gas reservoir exploration because of possible fracture enhancement of the brittle organic- and siliceous-rich facies. However, an inverse relation between silica and porosity in some regions implies that zones with the best propensity for fracture completion may not provide optimal gas capacity, and a balance between favorable reservoir characteristics needs to be sought.

Volumetric strain associated with methane desorption and its impact on coalbed gas production from deep coal seams

The permeability of deep (1000 m; 3300 ft) coal seams is commonly low. For deep coal seams, significant reservoir pressure drawdown is required to promote gas desorption because of the Langmuir-type isotherm that typifies coals. Hence, a large permeability decline may occur because of pressure drawdown and the resulting increase in effective stress, depending on coal properties and the stress field during production. However, the permeability decline can potentially be offset by the permeability enhancement caused by the matrix shrinkage associated with methane desorption. The predictability of varying permeability is critical for coalbed gas exploration and production-well management. We have investigated quantitatively the effects of reservoir pressure and sorption-induced volumetric strain on coal-seam permeability with constraints from the adsorption isotherm and associated volumetric strain measured on a Cretaceous Mesaverde Group coal (Piceance basin) and derived a stress-dependent permeability model. Our results suggest that the favorable coal properties that can result in less permeability reduction during earlier production and an earlier strong permeability rebound (increase in permeability caused by coal shrinkage) with methane desorption include (1) large bulk or Youngs modulus; (2) large adsorption or Langmuir volume; (3) high Langmuir pressure; (4) high initial permeability and dense cleat spacing; and (5) low initial reservoir pressure and high in-situ gas content. Permeability variation with gas production is further dependent on the orientation of the coal seam, the reservoir stress field, and the cleat structure. Well completion with injection of N2 and displacement of CH4 only results in short-term enhancement of permeability and does not promote the overall gas production for the coal studied.

Variation in micropore capacity and size distribution with composition in bituminous coal of the Western Canadian Sedimentary Basin : Implications for coalbed methane potential

The effects of lithotype, maceral and mineral contents on the micropore capacity and size distribution are investigated for a medium-volatile bituminous coal from the mid-Cretaceous Gates Formation of north-east British Columbia and a high-volatile bituminous coal from the Cretaceous of Alberta. Vitrinite content (vol.% mmf) ranges from 18 to 95 for the Gates coal and 36 to 85 for the Alberta coal. Ash yields (wt%) vary from 4.4 to 33.7 for the Gates coal and 1.2 to 10.6 for the Alberta coal. Dubinin-Radushkevich CO2 micropore capacities (cm3 g−1 mmf) measured at 273 K range from 23.7 to 43.9 for the Gates coal and 37.0 to 54.7 for the Alberta coal. Low-pressure Dubinin micropore capacities and Langmuir and BET monolayer volumes measured at 273 K generally increase with increasing total and structured vitrinite content and decrease with increasing inertinite and mineral matter content. The increase in micropore capacity with vitrinite content is due to an increase in the number of micropores, as demonstrated by Dubinin-Astakhov micropore size distributions. For the Gates suite, a sample with high total vitrinite and semifusinite contents has the largest micropore capacity, which may be due to the creation of micropore capacity in semifusinite through burning (charring). Micropore heterogeneity increases with an increase in inertinite and mineral matter content. Coal composition is important in determining the micropore capacity and size distribution and hence the gas capacity of bituminous coals.

Electron microprobe and micro-FTIR analyses applied to maceral chemistry

Abstract Combined electron microprobe and reflected micro-FTIR analysis permit maceral scale chemical characterization of coal and organic matter dispersed in rocks. Elemental composition derived from electron microprobe compares closely with the composition of the same samples analyzed following ASTM procedures. Reflected micro-FTIR yields spectra comparable to those obtained in transmission micro-FTIR mode and maceral concentrates analyzed using KBr pellet techniques. The application of the electron microprobe and reflected micro-FTIR techniques is demonstrated by analyses of macerals from a suite of coal of varying rank. With increasing rank there is a progressive decrease in elemental O and increase in C content. The change in functional groups associated with increase in maturation is most conspicuous in the decrease in intensity of absorbance of aliphatic stretching bands (2800–3000 cm −1 ), and carboxyl/carbonyl band (1710 cm −1 ) and an increase in the 1600 cm −1 aromatic band. Elemental composition together with reflectance analyses suggest that liptinite and vitrinite attain a similar coalification path at about 88.5% C and reflectance of 1.25% and semifusinite merges with the vitrinite/liptinite coalification path at 89.5% C and a reflectance values of about 1.8–2.0%.

Micro-FTIR spectroscopy of liptinite macerals in coal

Abstract Reflectance FTIR microspectroscopy has been used to investigate the chemical structure of the liptinite macerals, alginite, bituminite, sporinite, cutinite and resinite in bituminous coals of Carboniferous to Tertiary age. In comparison with the spectra of vitrinite in the same coals, the micro-FTIR spectra of liptinite macerals are characterized by stronger aliphatic CH x absorptions at 3000–2800 and 1460–1450 cm −1 , less intense aromatic CC ring stretching vibration and aromatic CH out of plane deformation at 1610–1560 and 900–700 cm −1 respectively and various intense acid CO group absorptions at 1740–1700 cm −1 . The peaks at 1000–900 cm −1 due to aliphatic CH 2 wagging vibrations in olefins and at 730–720 cm −1 due to CH 2 rocking vibration in long chain aliphatic substances ([CH 2 ] n , n ≥4), are characteristic of liptinite macerals. Collectively the micro-FTIR spectral characteristics indicate that liptinite is composed of greater numbers of long chain aliphatics, fewer aromatics and a broader range of oxygen-containing groups than other macerals. Marked differences exist in micro-FTIR spectra within the liptinite maceral group. Alginite has the strongest aliphatic and least aromatic absorptions followed by bituminite, resinite, cutinite and sporinite. The aliphatic components in alginite are the longest chained and least branched whereas those in sporinite are the shortest chained and most branched. Bituminite, resinite and cutinite are intermediate. Notable differences in micro-FTIR spectra of individual liptinite macerals, such as intensities and peak locations of aromatic CC in alginite, CO groups in bituminite and resinite and substituted aromatic CH and C–O–C groups in cutinite and sporinite, also exist, which are attributed to differences in depositional environments or biotaxonomy.

Application of reflectance micro-Fourier transform infrared spectrometry in studying coal macerals: comparison with other Fourier transform infrared techniques

The applicability of the reflectance micro-Fourier transform infrared (FT-i.r.) technique to analyse the distribution of functional groups in coal is discussed. The spectra of a series of coals from lignite to anthracite obtained using reflectance micro-FT-i.r. were compared with those of the same materials but obtained using transmission micro-FT-i.r. and KBr pellet techniques. This comparison shows that (1) band absorbances in the transmission mode are much higher than those in the reflectance mode; (2) band peak positions are the same in the transmission and reflectance modes as long as Kramers-Kroning transformation is applied; and (3) the 700–900 cm−1 aromatic-dominated region has higher absorbance in the reflectance than transmission mode. Reflectance spectra and KBr pellet technique spectra compare very closely; band absorbances and band locations are the same or almost the same. The main difference between reflectance micro-FT-i.r. and KBr pellet techniques is a much higher absorbance in the 700–900 cm−1 region in the reflectance mode. The results indicate that reflectance spectra can be utilized to characterize functional groups in organic matter under most conditions. The ease of sample preparation, the potential to analyse large intact samples and the ability to characterize areas as small as 30 μm are the main advantages of reflectance micro-FT-i.r.. The quantitative aspects of reflectance micro-FT-i.r. require further study.

Comparing maceral ratios from tropical peatlands with assumptions from coal studies: Do classic coal petrographic interpretation methods have to be discarded?

Petrographic investigations of tropical peat deposits from the Tasek Bera Basin, Malaysia, show that petrographic methods can contribute valuable information about paleoecological settings of mire deposits. Comparing modern peat-forming environments and the pre-maceral composition of peat samples allows the reconstruction of paleoecological conditions, such as floral composition, fires, microbial activity, etc., and gives insight into paleodepositional environments. In the past, maceral ratios of coals have been used to interpret paleodepositional settings of coal deposits. Such a procedure assumes that coal texture and coal maceral composition are dictated solely by the depositional environment, and thus different depositional environments should be clearly discriminated based on maceral ratios. In the modern peat deposits of Tasek Bera, divergent petrographic results occur in similar depositional environments, hence, poor correlation occurs between the petrography, the degree of decomposition, and the depositional environment. Furthermore, from the time of peat deposition, peat is subject to considerable alteration. During subsequent diagenesis, preservation of structured and strongly altered material, such as inertinite, gelified material or funginite, is favoured and results in biased coal maceral compositions. Because maceral indexes in modern peat studies are of little utility in the reconstruction of paleoenvironmental settings, it follows that coal maceral indexes should not be utilized in the future to interpret paleodepositional environments of coals.

Late Devonian and Early Mississippian Bakken and Exshaw Black Shale Source Rocks, Western Canada Sedimentary Basin: A Sequence Stratigraphic Interpretation

The Late Devonian and Early Mississippian Bakken and Exshaw formations are a continuum of regionally correlated, organic-rich (up to 35% total organic carbon), black shale source rocks covering much of the Western Canada sedimentary basin. The Bakken Formation is composed of (1) a black mudstone lower member, (2) a gray mudstone/sandstone middle member, and (3) a black mudstone upper member. The Exshaw Formation, beneath the Alberta Plains and in exposures in the Foothills and Front Ranges of the Rocky Mountains, is composed of (1) a lower black shale member and (2) an upper siltstone member. The basal black shale unit of the Lower Mississippian Banff Formation, overlying the Exshaw Formation, is a second organic-rich interval. These black shales are regionally significant hydrocarbon source rocks and local reservoirs. The middle Bakken member is a locally important reservoir rock with substantial economic potential. The Bakken and Exshaw formations and the basal Banff black shale are divisible into three systems tracts: (1) a transgressive systems tract, (2) a lowstand systems tract, and (3) a second transgressive systems tract. Lodgepole and Banff formation carbonates, overlying the Bakken and Exshaw formations, are part of a highstand systems tract. A sequence boundary occurs between the lower and middle Bakken members. The conformable equivalent of this sequence boundary is within the Exshaw black shale member. Variations in the internal composition of these systems tracts imply that two depocenters, (1) the Williston basin and (2) the Prophet trough and the western margin of the North American craton, were affected differently by relative sea level rise and fall during Bakken and Exshaw deposition because of differences in water depth and sediment accommodation. Spatial and temporal changes in black shale and gray mudstone/sandstone, as highlighted by this sequence stratigraphic interpretation, may have significant impacts on source rock potential and hydrocarbon reservoir size, location, and quality.

Direct determination of carbon, oxygen and nitrogen content in coal using the electron microprobe

Abstract Recent advances in electron microprobe technology together with the development of synthetic crystals have enabled development of techniques for direct light element (C, O, N) analyses of coal macerals. The analytical results are both accurate compared to ASTM methods and highly precise, and provide an opportunity to assess the variation in coal chemistry at the micrometre scale. Our experiments show that analyses using a 10 kV accelerating voltage and 10 nA beam current yield the most reliable data and result in minimum sample damage. High sample counts were obtained for C, O and N using PC2, a nickel-carbon pseudocrystal ( d = 9.5 nm), as an analysing crystal. Vitrinite isolated from anthracite rank coal proves the best carbon standard and was more desirable than graphite which has higher porosity, whereas lower rank vitrinite is too heterogeneous to use routinely as a standard. No significant carbon or oxygen X-ray peak to be constant over a range of beam sizes and currents for counting times to 160 s, and no correction factor was necessary in determination of oxygen content. Probe-determined carbon contents agree closely with those reported from ASTM analyses and some minor deviations are attributed to heterogeneity of the vitrinite on the micrometre scale. Our results show that the electron microprobe technique can provide accurate compositional data for both minor and major elements in coal without the necessity and inherent problems associated with mechanical separation of macerals.