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Abstract Natural gas, which is found as free, dissolved, and adsorbed gas, is abundant in organic-rich shales. Despite the growing relevance of sorbed gas, there are still questions about how lithological variables, as well as shale mineralogical, geochemical, and petrophysical features, influence gas sorption capacity. Therefore, the overall aim of this research was to relate variations in mineralogical, geochemical, and petrophysical properties of selected Paleozoic shale samples from Western Peninsular (WP) Malaysia comprising seven formations to their sorption capacities. Despite the apparent homogeneity at a mesoscale, micro-scale variations may exist between different ages and localities of the shales. These variations are significant enough to allow the classification of the shales into different categories based on their age instead of dealing with them as a single unit. Therefore, shales from WP Malaysia are grouped into four divisions i.e S-D (Silurian-Devonian), Devonian, Carboniferous, and Permian shales respectively. Low-pressure Nitrogen adsorption reveals older shales i.e., S-D and Devonian show higher average surface area and the lower average of pore diameter and total pore volume as compared to younger shales i.e., Carboniferous and Permian. The impact of methane sorption capacities (MSC) on studied shales revealed that total organic carbon (TOC) and Vitrinite Reflectance (Ro) are the primary controlling factor of methane adsorption on shale. However, S-D and Devonian shales revealed that TOC is not the primary factor as clay minerals contribute more towards MSC in these shales. Clay mineralogy roles are skeptical as they may have positive, negative, or sometimes no correlation with MSC. The impact of pore structure parameters i.e., pore diameter, pore-volume, and the specific surface area also shows the distinct influence on MSC. Furthermore, present investigations in shales help to understand the shale gas adsorption mechanisms and could deliver a scientific platform for the assessment and development of the green shale gas industry.
- Asia > Malaysia (0.93)
- North America > Canada > British Columbia (0.29)
- North America > United States > Texas (0.28)
- (3 more...)
- Phanerozoic > Paleozoic > Permian (0.92)
- Phanerozoic > Paleozoic > Devonian (0.91)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (34 more...)
Effect of Organic Matter Properties, Clay Mineral Type and Thermal Maturity on Gas Adsorption in Organic-Rich Shale Systems
Zhang, Tonwei (University of Texas, Austin) | Ellis, Geoffrey E. (US Geological Survey) | Ruppel, Stephen C. (University of Texas, Austin) | Milliken, Kitty (University of Texas, Austin) | Lewan, Mike (US Geological Survey) | Sun, Xun (University of Texas, Austin)
Summary A series of CH4 adsorption experiments on natural organic-rich shales, isolated kerogen, clay-rich rocks, and artificially matured Woodford Shale samples were conducted under dry conditions. Our results indicate that physisorption is a dominant process for CH4 sorption, both on organic-rich shales and clay minerals. The Brunauer-Emmett-Teller (BET) surface area of the investigated samples is linearly correlated with the CH4 sorption capacity in both organic-rich shales and clay-rich rocks. The presence of organic matter is a primary control on gas adsorption in shale-gas systems, and the gas-sorption capacity is determined by total organic carbon (TOC) content, organic-matter type, and thermal maturity. A large number of nanopores, in the 2-50 nm size range, were created during organic-matter thermal decomposition, and they significantly contributed to the surface area. Consequently, methane-sorption capacity increases with increasing thermal maturity due to the presence of nanopores produced during organic-matter decomposition. Furthermore, CH4 sorption on clay minerals is mainly controlled by the type of clay mineral present. In terms of relative CH4 sorption capacity: montmorillonite >> illite - smectite mixed layer > kaolinite > chlorite > illite. The effect of rock properties (organic matter content, type, maturity, and clay minerals) on CH4 adsorption can be quantified with the heat of adsorption and the standard entropy, which are determined from adsorption isotherms at different temperatures. For clay-mineral rich rocks, the heat of adsorption (q) ranges from 9.4 to 16.6 kJ/mol. These values are considerably smaller than those for CH4 adsorption on kerogen (21.9-28 kJ/mol) and organic-rich shales (15.1-18.4 kJ/mol). The standard entropy (???so) ranges from โ64.8 to โ79.5 J/mol/K for clay minerals, โ68.1 to โ111.3 J/mol/K for kerogen, and โ76.0 to โ84.6 J/mol/K for organic-rich shales. The affinity of CH4 molecules for sorption on organic matter is stronger than for most common clay minerals. Thus, it is expected that CH4 molecules may preferentially occupy surface sites on organic matter. However, active sites on clay mineral surfaces are easily blocked by water. As a consequence, organic-rich shales possess a larger CH4-sorption capacity than clay-rich rocks lacking organic matter. The thermodynamic parameters obtained in this study can be incorporated into model predictions of the maximum Langmuir pressure and CH4-sorption capacity of shales under reservoir temperature and pressure conditions. URTeC 1583690
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
High-Pressure/High-Temperature Methane-Sorption Measurements on Carbonaceous Shales by the Manometric Method: Experimental and Data-Evaluation Considerations for Improved Accuracy
Gasparik, M.. (RWTH Aachen University) | Gensterblum, Y.. (RWTH Aachen University) | Ghanizadeh, A.. (RWTH Aachen University) | Weniger, P.. (RWTH Aachen University) | Krooss, B. M. (RWTH Aachen University)
Summary In exploration for shale gas, experimental methane-sorption measurements represent a valuable source of information for resource estimates and for reservoir-modeling studies. Here, the main difficulty is the relatively low adsorption capacity of shales (typically 10% of the sorption capacity of coals), as well as the fact that the measurements need to be performed over a wide range of pressures and temperatures characteristic of past or present geological conditions. In this work, we demonstrate the capabilities of an adapted manometric apparatus to reliably measure excess sorption isotherms at pressures of up to 30 MPa and temperatures up to 423 K on carbonaceous shales. This is accomplished with an experimental design comprising separate heating zones for the sample cell and for the rest of the apparatus. An experimental and mass-balance approach is presented to quantify the temperature gradient existing between the two heating zones, as well as the thermal expansion of the sample cell, and to account for these in the calculation of the excess sorption. We demonstrate that the analysis of the helium-void-volume data over a large temperature range can be interpreted with respect to the thermal expansion of the sample and, in some cases, changes in pore-volume accessibility to helium. We propose to perform blank-expansion tests with non-adsorbing specimens (e.g., steel cylinders) as a quality check to eliminate device-specific artifacts resulting from unknown measurement uncertainties or from uncertainty in the equation of state. Two evaluation procedures are presented to quantitatively account for the blank tests in the final result of sorption measurements on shale samples. As an example, methane-sorption isotherms for carbonaceous shale at 311, 338, 373, and 423 K are presented. By use of a Monte Carlo algorithm to simulate the propagation of the experimental uncertainties, the final estimated uncertainty in excess sorption resulting from systematic errors was found to beโยฑโ0.007 mmol/g at 25 MPa. The consideration of the blank-expansion tests in the mass balance further reduces the systematic error, at least to a point at which an excellent intralaboratory consistency is obtained. The estimated uncertainty resulting from random errors was found to significantly overestimate the actual precision of the experimental setup, and an explanation is provided with respect to experimental design. A data-reduction approach using an excess-sorption function based on a Langmuir-type absolute-sorption model was found to provide an excellent representation of the measured sorption data. By means of simplified model calculations we demonstrate that the excess-sorption formalism is a sufficient, simple, and adequate approach to applications in shale-gas-resource estimation. The uncertainties pertaining to representativeness of experimental sorption data of in-situ reservoir conditions are briefly discussed.
- North America > United States (1.00)
- Europe (1.00)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.92)
Abstract For unconventional gas resources such as coal and organic-rich shale, sorbed-phase is an important component of storage and transport calculations. Routine measurements of sorption are, however, performed separately from the porosity and permeability measurements. In this work a new gas storage measurement technique is proposed combining the porosity and sorption measurements. Because the measurement is done using core plug under confining stress, it allows investigating the storage capacity for varying effective stress and incorporating the storage data into a subsequent permeability measurement under the same conditions. During construction of the sorption isotherm in the laboratory using Boyleโs law setup and a volumetric method, at each pressure step, volume of the sorbed gas taken up by the sample reduces the pore volume of the sample. As a result, the initially determined pore volume at low pressure must be corrected at the beginning and at the end of the pressure step. Also known as Gibbs correction, this correction can be done relatively easily during the routine sorption measurements with the crushed samples; however, it is a challenging task with core plugs under confining stress because at each pressure step the pore volume could also change due pore compressibility. Our approach is based on a new analytical model of total gas storability developed to interpret multiple-step laboratory measured pressure data on a graphical domain where the parameter estimation can be done fast and accurately using a straight line. The approach considers both the compressibility and sorbed- phase effects on the pore volume and the sorption parameters. Experimental storage data of various shale and coal samples with varying total organic content and maturity is used to demonstrate applicability of the analytical method to the measurements. Our results show that the sorption measurements can be done with increased accuracy and relatively fast. The work is important for organic-rich sample characterization in the laboratory, and for gas-in-place and transport calculations.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.59)
- Geology > Geological Subdiscipline > Geomechanics (0.52)
Sorption of CO2 in Shales Using the Manometric Set-up
Khosrokhavar, Roozbeh (Delft Uiniversity of Technology) | Schoemaker, Christiaan (Delft Uiniversity of Technology) | Battistutta, Elisa (Delft Uiniversity of Technology) | Wolf, Karl-Heinz (Delft Uiniversity of Technology) | Bruining, Hans (Delft Uiniversity of Technology)
Abstract In a transition period from a fossil fuel based society to a sustainable energy society it is expected that CO2 capture and subsequent sequestration (CCS) in geological formations will play a major role in reducing greenhouse gas emissions. Possibilities of sequestration include storage in aquifers and depleted gas reservoir. The storage capacity of gas reservoirs for CO2 depends also on the sorption in the omnipresent minerals and shales. It is important to investigate whether adsorption on shales gives an important contribution to the storage capacity. It is also important to relate the adsorption to the carbon content in the shale. Only a few measurements have been reported in the literature for high-pressure gas sorption on shales, and interest is largely focused on shales occurring outside Europe. We present results using a high pressure manometric setup on a dried black shale sample from Belgium. It consists of more than 57% of clay minerals and 6.58% organic matter. The excess sorption isotherm shows an initial increase to a maximum value of 0.19 mmol/gram and then starts to decrease until it becomes zero at 82 bar and subsequently the excess sorption becomes negative. Similar behavior was also observed for other shales and coal reported in the literature. We derive the equation for excess sorption in the manometric set-up allowing for a changing void volume. This equation is based on the finite density of the adsorbed phase. However, this is not the only mechanism causing a maximum in the sorption curve. Other reasons for void volume change are swelling of the shale and volume changes due to chemical reactions excluding sorption. Further research is necessary to investigate reasons for void volume changes in shales.
- Europe (1.00)
- North America > Canada > Alberta (0.28)
- North America > United States > Kentucky > Big Sandy Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Muderong Shale Formation (0.98)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Muskwa Field > Muskwa Formation (0.94)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- (2 more...)