Matrix-related pore networks in mudrocks are composed of nanometer- to micrometer-size pores. In shale-gas systems, these pores, along with natural fractures, form the flow-path (permeability) network that allows flow of gas from the mudrock to induced fractures during production. A pore classification consisting of three major matrix-related pore types is presented that can be used to quantify matrix-related pores and relate them to pore networks. Two pore types are associated with the mineral matrix; the third pore type is associated with organic matter (OM). Fracture pores are not controlled by individual matrix particles and are not part of this classification. Pores associated with mineral particles can be subdivided into interparticle (interP) pores that are found between particles and crystals and intraparticle (intraP) pores that are located within particles. Organic-matter pores are intraP pores located within OM. Interparticle mineral pores have a higher probability of being part of an effective pore network than intraP mineral pores because they are more likely to be interconnected. Although they are intraP, OM pores are also likely to be part of an interconnected network because of the interconnectivity of OM particles. In unlithifed near-surface muds, pores consist of interP and intraP pores, and as the muds are buried, they compact and lithify. During the compaction process, a large number of interP and intraP pores are destroyed, especially in ductile grain-rich muds. Compaction can decrease the pore volume up to 88% by several kilometers of burial. At the onset of hydrocarbon thermal maturation, OM pores are created in kerogen. At depth, dissolution of chemically unstable particles can create additional moldic intraP pores.

Spectrum of pore types and networks in mudrocks and a descriptive classification for matrix-related mudrock pores

The importance of shale composition and pore structure upon gas storage potential of shale gas reservoirs

Pore structure characterization of North American shale gas reservoirs using USANS/SANS, gas adsorption, and mercury intrusion

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.

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

https://www.searchanddiscovery.com/abstracts/pdf/2011/hedberg-texas/abstracts/ndx_zhang.pdf

Effect of organic-matter type and thermal maturity on methane adsorption in shale-gas systems

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.

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

The Lower Jurassic Gordondale Member is an organic-rich mudrock and is widely considered to have potential as a shale gas reservoir. Influences of Gordondale mudrock composition on total gas capacities (sorbed and free gas) have been determined to assess the shale gas resource potential of strata in the Peace River district, northeastern British Columbia. Sorbed gas capacities of moisture-equilibrated samples increase over a range of 0.5 to 12 weight percent total organic carbon content (TOC). Methane adsorption capacities range from 0.05 cc/g to over 2 cc/g in organic-rich zones (at 6 MPa and 30°C). Sorption capacities of mudrocks under dry conditions are greater than moisture equilibrated conditions due to water occupation of potential sorption sites. However, there is no consistent decrease of sorption capacity with increasing moisture as the relationship is masked by both the amount of organic matter and thermal maturation level. Clays also affect total gas capacities in as much as clay-rich mudrocks have high porosity which may be available for free gas. Gordondale samples enriched with carbonate (calcite and dolomite) typically have lower total porosities than carbonate-poor rocks and hence have lower potential free gas contents. On a regional reservoir scale, a large proportion of the Gordondale total gas capacity is free gas storage (intergranular porosity), ranging from 0.1-22 Bcf/section (0.003-0.66 m3/section). Total gas-in-place capacity ranges from 1-31.4 Bcf/section (0.03-0.94 m3/section). The greatest potential for gas production is in the south of the study area (93-P) due to higher thermal maturity, TOC enrichment, higher reservoir pressure, greater unit thickness and improved fracture-potential.

Shale Gas Potential of the Lower Jurassic Gordondale Member, Northeastern British Columbia, Canada

Investigating the use of sedimentary geochemical proxies for paleoenvironment interpretation of thermally mature organic-rich strata: Examples from the Devonian–Mississippian shales, Western Canadian Sedimentary Basin

Daniel J.K. Ross

Papers

The importance of shale composition and pore structure upon gas storage potential of shale gas reservoirs

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

Shale Gas Potential of the Lower Jurassic Gordondale Member, Northeastern British Columbia, Canada

Investigating the use of sedimentary geochemical proxies for paleoenvironment interpretation of thermally mature organic-rich strata: Examples from the Devonian–Mississippian shales, Western Canadian Sedimentary Basin

Impact of mass balance calculations on adsorption capacities in microporous shale gas reservoirs