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

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

In this paper, we present an equilibrium thermodynamic model to accurately predict the maximum depth of hydrate stability in the seafloor, including the effects of water salinity, hydrate confinement in pores, and the distribution of pore sizes in natural sediments. This model uses sediment type, geothermal gradient, and seafloor depth as input to predict the thickness of the hydrate zone. Using this hydrate model and a mass-transfer description for hydrate formation, we have also developed a predictive method for the occurrence of methane hydrates in the ocean. Based on this information, a prediction for the distribution of methane hydrate in ocean sediment is presented on a 1° latitude by 1° longitude (1° × 1°) global grid. From this detailed prediction, we estimate that there is a total volume of 1.2 × 1017 m3 of methane gas (expanded to atmospheric conditions), or, equivalently, 74 400 Gt of CH4 in ocean hydrates, which is 3 orders of magnitude larger than worldwide conventional natural gas reserves. ...

Global Distribution of Methane Hydrate in Ocean Sediment

https://cyberleninka.org/article/n/1118289.pdf

Laboratory characterisation of shale properties

We present an interpretational framework for the analysis of a diverse set of geological structures that breach sealing sequences and allow fluids to flow vertically or subvertically across the seal. In so doing, they act as seal bypass systems (SBS). We define SBS as seismically resolvable geological features embedded within sealing sequences that promote cross-stratal fluid migration and allow fluids to bypass the pore network. If such bypass systems exist within a given seal sequence, then predictions of sealing capacity based exclusively on the flow properties (capillary entry pressure and hydraulic conductivity) of the bulk rock can potentially be negated by the capacity of the bypass system to breach the grain and pore network. We present a range of examples of SBS affecting contrasting types of sealing sequences using three-dimensional (3-D) seismic data. These examples show direct evidence of highly focused vertical or subvertical fluid flow from subsurface reservoirs up through the seal sequence, with leakage internally at higher levels or to the surface as seeps.We classify SBS into three main groups based on seismic interpretational criteria: (1) fault related, (2) intrusion related, and (3) pipe related. We show how each group exhibits different modes of behavior with different scaling relationships between flux and dimensions and different short- and long-term impacts on seal behavior.

Seal bypass systems

This paper describes a series of experiments designed to investigate the influence of lithology on the compactional loss of porosity and permeability in mudstones. Two intact samples of London Clay with clay fractions of 40% and 67% were compacted to 33 MPa effective stress. Clay fraction, permeability, porosity, pore size distribution, and specific surface area were measured and their evolution was monitored throughout the compaction process. Electron microscopy was combined with mercury porosimetry to trace the collapse of the pore structure with increasing effective stress. In both cases, porosity loss occurred primarily by the collapse of large pores. This process is more obvious in the coarser-grained sample because throughout the compaction process it has a much broader range of pore radii and a much greater mean pore radius. Consistent with the pore size distributions, the permeability of the coarser sample ranges from ∼ 10−10 m s−1 to 10−12 m s−1 while that of the finer-grained sample ranges from ∼4 × 10−12 m s−1 to 5 × 10−14 m s−1 during progressive compaction from 2 to 33 MPa. The compressibility of the finer-grained sample is greater than that of the coarser-grained sample (0.15 as opposed to 0.07). However, in both cases the compressibility is much lower than that inferred for lithologically similar samples compacted over geological timescales. The demonstration that both porosity and lithology (clay fraction) influence the permeability of mudstones should allow the development of more realistic porosity-permeability relationships which take into account lithological variations exhibited by mudstones.

https://agupubs.onlinelibrary.wiley.com/doi/pdf/10.1029/97JB02540

Compaction‐driven evolution of porosity and permeability in natural mudstones: An experimental study

We report the results of a series of hydraulic conductivity tests carried out on seven natural, well-characterised specimens of London Clay mudstone. The clay fractions of the samples range from 27% to 66% and enabled a test of the influence of clay fraction on the hydraulic conductivity, pore size distribution, compressibility and specific surface area of natural mudstones. Hydraulic conductivities were determined at effective stresses between 1.5 and 33 MPa. Hydraulic conductivities of clay-rich samples (49–66% clay fraction) decreased from ∼10−11 m s−1 to ∼10−14 m s−1 over a porosity range of 48% to 25%. At a given porosity the hydraulic conductivities of two silt-rich samples (27 and 33% clay fraction) were 40–250 times greater than those of the five clay-rich samples. Variations in hydraulic conductivity are directly related to pore size distributions and are accurately predicted by a model which uses pore size distribution as its primary input. Clay-rich samples have unimodal pore size distributions with modal throat radii around 60–120 nm. Silt-rich samples have bimodal pore throat size distributions. One modal size is similar to that observed in clay-rich samples with a second modal value at 3–6 μm. Compaction under effective stresses up to 10 MPa results in the preferential collapse of larger pores, so that the rate of loss of hydraulic conductivity is greater in the silt-rich samples. Differences in hydraulic conductivity between silt-rich and clay-rich mudstones therefore decline with decreasing porosity. The range of porosity-hydraulic conductivity relationships means that hydraulic conductivity is not easily predicted from porosity alone; additional constraining parameters such as grain and pore size distributions are required.

https://agupubs.onlinelibrary.wiley.com/doi/pdf/10.1029/1999JB900276

Jean-Paul Sarda

Papers

Compaction‐driven evolution of porosity and permeability in natural mudstones: An experimental study

Influence of clay fraction on pore-scale properties and hydraulic conductivity of experimentally compacted mudstones