Water adsorption and its impact on the pore structure characteristics of shale clay

Geothermal energy development by circulating CO2 in a U-shaped closed loop geothermal system

Dynamic microstructural evolution of hardened cement paste during first drying monitored by 1H NMR relaxometry

The development of hydraulic fracturing and horizontal drilling techniques has promoted the exploitation of shale gas resources. However, using water has several potential drawbacks including environmental issues, e.g., the contamination of groundwater, surface water, and soil. Supercritical carbon dioxide (SC-CO2), with its special physical properties, has shown potential to enhance shale gas recovery replacing water as the stimulation fluid. This review summarizes the current status of shale gas recovery, the potential role of SC-CO2 as a working fluid for shale gas recovery, and CO2 geological sequestration in shale reservoirs. SC-CO2 has a better rock-breaking capability than water, which is useful when drilling through shale formations. SC-CO2 fracturing creates rougher and more complex fracture networks than hydraulic fracturing, leading to higher permeabilities. Some of the injected CO2 for shale gas recovery could also be safely sequestered in shale reservoirs, thereby lowering carbon emissions and accessing CO2 tax credits. However, shale–CO2 or shale–water/brine–CO2 interactions during & after shale gas recovery and sequestration can affect reservoir properties. The implied shale–CO2 imbibition process from available data generally persists for several years, far more than the several days assumed for most laboratory tests. A more detailed understanding is required for SC-CO2 injection on the efficiency of shale gas recovery and the cost and environmental concerns of this technology. This will support the development of safe sequestration methods, supported by suitable laboratory and field tests, especially those focusing on geochemical, petrophysical, geomechanical and hydraulic properties.

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The role of supercritical carbon dioxide for recovery of shale gas and sequestration in gas shale reservoirs

Water vapor adsorption/desorption isotherms are measured on five shales from Illinois basin by dynamic vapor sorption method. The experimental adsorption data are modeled by the Guggenheim, Anderson, and De Boer model and the Freundlich model over the entire range of measured relative humidity (Rh) values (0–0.95). Modeling results show that shale hydration is controlled by surface chemistry at low Rh through a strong intermolecular bonding, while is mainly influenced by the pore structure at high Rh (>0.9) through capillary condensation. This is consistent with the progressive decrease of isosteric heat of adsorption with water content, obtained by the Clausius‐Clapeyron equation. Exceptionally, for the one shale containing 8.6% montmorillonite, mesopore condensation only accounts for 33% of the measured water adsorption even at Rh ~0.95 due to the limited external pores and the important role of clay swelling. The specific surface area defined by Guggenheim, Anderson, and De Boer analysis as available for water adsorption is larger than that available for low‐pressure N2 adsorption due to the complex surface chemistry. The one shale rich in expansive montmorillonite and with a large interlayer capacity for water but inaccessible to N2 molecules conditions this result. Among the other four shales, one with high kerogen content behaves the highest water adsorption, possibly due to the high content of oxygen‐containing functional groups and the potentially high pore volume of kerogen. These findings contribute to a better understanding of water storage and transport behavior in shales and impact behavior relevant to structures and reservoirs founded in such media.

Xu Zhang

Papers

Water adsorption and its impact on the pore structure characteristics of shale clay

Capillary filling under nanoconfinement: The relationship between effective viscosity and water-wall interactions