Sorption capacities and pore characteristics of bulk shales and isolated kerogens have been determined for immature, oil-window, and gas-window mature samples from the Lower Toarcian Posidonia shale ...formation. Dubinin–Radushkevich (DR) micropore volumes, sorption pore volumes, and surface areas of shales and kerogens were determined from CO2 adsorption isotherms at −78 and 0 °C, and from N2 adsorption isotherms at −196 °C. Mercury injection capillary pressure porosimetry, grain density measurements, and helium pycnometry were used to determine shale and kerogen densities and total pore volumes. Total porosities decrease through the oil-window and then increase into the gas-window. High-pressure methane isotherms up to 14 MPa were determined at 45, 65, and 85 °C on dry shale and at 45 and 65 °C on kerogen. Methane excess uptakes at 65 °C and 11.5 MPa were in the range 0.056–0.110 mmol g–1 (40–78 scf t–1) for dry Posidonia shales and 0.36–0.70 mmol g–1 (253–499 scf t–1) for the corresponding dry kerogens. Absolute methane isotherms were calculated by correcting for the gas at bulk gas phase density in the sorption pore volume. The enthalpies of CH4 adsorption for shales and kerogens at zero surface coverage showed no significant variation with maturity, indicating that the sorption pore volume is the primary control on sorption uptake. The sum of pore volumes measured by (a) CO2 sorption at −78 °C and (b) mercury injection, are similar to the total porosity for shales. Since mercury in our experiments occupies pores with constrictions larger than ca. 6 nm, we infer that porosity measured by CO2 adsorption at −78 °C in the samples used in this study is largely within pores with effective diameters smaller than 6 nm. The linear correlation between maximum CH4 surface excess sorption and CO2 sorption pore volume at −78 °C is very strong for both shales and kerogens, and goes through the origin, suggesting that the vast majority of sorbed CH4 occurs in pores smaller than 6 nm. The DR micropore volume obtained from CO2 adsorption at 0 °C was 40%–62% of the corresponding CO2 sorption pore volume. Sorption mass balances using kerogen and shale isotherms showed that approximately half of the CO2 sorption in these dry shales is in organic matter, with the rest likely to be associated with the inorganic phase (mainly clay minerals). A similar distribution was observed for supercritical CH4 adsorption. Mass balances for adsorption isotherms for kerogen and clay minerals do not always account for the total measured sorbed CH4 on dry shales, suggesting that some sorption may not be completely accounted for by the minerals identified and kerogens in the shales.
Low and high resolution petrographic studies have been combined with mineralogical, TOC, RockEval and porosity data to investigate controls on the evolution of porosity in stratigraphically ...equivalent immature, oil-window and gas-window samples from the Lower Toarcian Posidonia Shale formation. A series of 26 samples from three boreholes (Wickensen, Harderode and Haddessen) in the Hils syncline was investigated. The main primary components of the shales are microfossiferous calcite (30–50%), clay minerals (20–30%) and Type II organic matter (TOC = 7–15%, HI = 630–720 mg/gC in immature samples). Characteristic sub-centimetric light and dark lamination reflects rapid changes in the relative supply of these components. Total porosities decrease from 10 to 14% at Ro = 0.5% to 3–5% at Ro = 0.9% and then increase to 9–12% at Ro = 1.45%. These maturity-related porosity changes can be explained by (a) the primary composition of the shales, (b) carbonate diagenesis, (c) compaction and (d) the maturation, micro-migration, local trapping and gasification of heterogeneous organic phases. Calcite undergoes dissolution and reprecipitation reactions throughout the maturation sequence. Pores quantifiable in SEM (>ca. 50 nm) account for 14–25% of total porosity. At Ro = 0.5%, SEM-visible macropores1 are associated mainly with biogenic calcite. At this maturity, clays and organic matter are not visibly porous but nevertheless hold most of the shale porosity. Porosity loss into the oil window reflects (a) compaction, (b) carbonate cementation and (c) perhaps the swelling of kerogen by retained oil. In addition, porosity is occluded by a range of bituminous phases, especially in microfossil macropores and microfractures. In the gas window, mineral-hosted porosity is still the primary form of macroporosity, most commonly observed at the organic-inorganic interface. Increasing porosity into the gas window also coincides with the formation of isolated, spongy and complex meso- and macropores within organic particles, related to thermal cracking and gas generation. This intraorganic porosity is highly heterogeneous: point-counted macroporosity of individual organic particles ranges from 0 to 40%, with 65% of organic particles containing no macropores. We suggest that this reflects the physicochemical heterogeneity of the organic phases plus the variable mechanical protection afforded by the mineral matrix to allow macroporosity to be retained. The development of organic macroporosity cannot alone account for the porosity increase observed from oil to gas window; major contributions also come from the increased volume of organic micro- and meso-porosity, and perhaps by kerogen shrinkage.
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•Porosity of organic-rich, calcareous Posidonia Shale halves in oil window and doubles in gas window.•Porosity changes driven by carbonate diagenesis and retention/gasification of bitumen.•Pores quantifiable by SEM (>ca. 50 nm) only account for 14–25% of total porosity.•Macroporosity of single organic particles in gas window range from 0 to 40%.•Much of porosity generated in gas window is in micro- and mesopores.
Shale gas is an important hydrocarbon resource in a global context. It has had a significant impact on energy resources in the US, but the worldwide development of this methane resource requires ...further research to increase the understanding of the relationship of shale structural characteristics to methane storage capacity. In this study a range of gas adsorption, microscopic, mercury injection capillary pressure porosimetry and pycnometry techniques were used to characterize the full range of porosity in a series of shales of different thermal maturity. Supercritical methane adsorption methods for shale under conditions which simulate geological conditions (up to 473 K and 15 MPa) were developed. These methods were used to measure the methane adsorption isotherms of Posidonia shales where the kerogen maturity ranged from immature, through oil window, to gas window. Subcritical methane and carbon dioxide adsorption studies were used for determining pore structure characteristics of the shales. Mercury injection capillary pressure porosimetry was used to characterize the meso and macro porosity of shales. The sum of the CO
2
sorption pore volume at 195 K and mercury injection capillary pressure pore volumes (1093–5.6 nm) were equal to the corresponding total pore volume (< 1093 nm) thereby giving an equation accounting for virtually all the available shale porosity. These measurements allowed quantification of all the available porosity in shales and were used for estimating the contributions of methane stored as ‘free’ compressed gas and as adsorbed gas to overall methane storage capacity of shales. Both the mineral and kerogen components of shale were studied by comparing shale and the corresponding isolated kerogens so that the relative contributions of these components could be assessed. The results show that the methane adsorption characteristics were much higher for the kerogens and represented 35–60% of the total adsorption capacity for the shales used in this study, which had total organic contents in range 5.8–10.9 wt%. Microscopy studies revealed that the pore systems in clay-rich, organic-rich and microfossil-rich parts of shale are very different, and also the importance of the inter-granular organic-mineral interface.
Mudstones exert a fundamental control on the flow of both aqueous and nonaqueous fluids in sedimentary basins. Predicting their flow and storage properties requires an understanding of pore size and ...connectivity, yet there are very few quantitative descriptions of pore systems of mineralogically and texturally well‐characterized mudstones. We use a combination of electron microscopy, mercury injection capillary pressure porosimetry, and CO2 sorption methods to generate a quantitative description of the size distribution, connectivity, and evolution of pore systems in a sequence of Posidonia Shale mudstones buried to 100–180 °C. We place the pore data into a detailed mineralogical, petrographical, and textural context to show that the nature and evolution of porosity and pore systems can be described in terms of associations with clay‐rich, microfossil‐rich, and organic matter‐rich domains, common to many mudstones. Pore size distributions are described by power laws, and pore systems are well connected across the full nanometer‐micrometer spectrum of pore sizes. However, connected networks occur primarily through pores <10 nm radius, with typically 20–40% of total porosity associated with pores with radii < ~3 nm, within both organic matter and the clay matrix. Clay‐rich, microfossil‐rich, and organic matter‐rich domains have distinct pore size distributions which evolve in very different ways with increasing thermal maturity. We suggest that the flow of aqueous and nonaqueous fluids depends not only on the overall connectivity of pores but also the larger‐scale connectivity and wetting state of clay‐rich, microfossil‐rich, and organic matter‐rich domains.
Plain Language Summary
Mudstones are Cinderella sediments: important but neglected. The most abundant sediment type, they act as unconventional oil and gas reservoirs, as top seals to conventional hydrocarbon reservoirs, and as critical barriers to the leakage of CO2 and radionuclides from underground storage sites. Risking and predicting flow and leakage through these rocks requires a quantitative description of pore systems and their connectivity. This is challenging since even the biggest pores in shales are smaller than a micron, with many pores only a few nanometers in size. Our work uses a combination of techniques to characterize and quantify the nanoporous nature of shales. Pores are generally smaller than 100 nm but are well connected, but mainly through throats less than 20 nm. We have also placed the pore system data into a geological framework in order to be more predictive about the pore systems of shales generally. By quantifying the nature of pores in the various mineral and organic building blocks of shales we can consider the larger scale flow properties of shales and thus their potential either to transmit fluid (useful for a shale gas reservoir) or to retain fluid (useful for a CO2 or nuclear waste storage site).
Key Points
Nature and evolution of mudstone pore systems are quantified as a function of: texture, mineralogy, organic matter content;, and thermal maturity
Pore systems are well connected across the full nanometer‐micrometer spectrum of pore sizes; connected networks occur mainly through pores with <10‐nm radius
Multiphase flow is influenced not only by connectivity of pores but also larger‐scale connectivity of clay‐rich and organocarbonate domains
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