CO2 In Sandstone Research Articles

Experimental Study on Relative Permeability Characteristics for CO2 in Sandstone under High Temperature and Overburden Pressure

In this study, CO2 seepage of sandstone samples from the Taiyuan-Shanxi Formation coal seam roof in Ordos Basin, China, under temperature-stress coupling was studied with the aid of the TAWD-2000 coal rock mechanics-seepage test system. Furthermore, the evolution law and influencing factors on permeability for CO2 in sandstone samples with temperature and axial pressure were systematically analyzed. The results disclose that the permeability of sandstone decreases with the increase in stress. The lower the stress is, the more sensitive the permeability is to stress variation. High stress results in a decrease in permeability, and when the sample is about to fail, the permeability surges. The permeability of sandstone falls first and then rises with the rise of temperature, which is caused by the coupling among the thermal expansion of sandstone, the desorption of CO2, and the evaporation of residual water in fractures. Finally, a quadratic function mathematical model with a fitting degree of 98.2% was constructed between the temperature-stress coupling effect and the permeability for CO2 in sandstone. The model provides necessary data support for subsequent numerical calculation and practical engineering application. The experimental study on the permeability characteristics for CO2 in sandstone under high temperature and overburden pressure is crucial for evaluating the storage potential and predicting the CO2 migration evolution in underground coal gasification coupling CO2 storage projects.

Selective dissolution of feldspars in the presence of carbonates: The way to generate secondary pores in buried sandstones by organic CO2

Carbonates are suggested to dissolve rapidly than feldspars by laboratory experiments. Petrography texture of selective dissolution of feldspars in the presence of carbonates, however, is widespread in buried sandstones and even shales, inspiring a revisit to the chemistry of burial secondary pores.Feldspar dissolution, precipitation of secondary minerals (quartz, clays), and carbonate cementation are common chemical reactions in the Eocene sandstones in the northern Dongying Sag. Petrography evidence demonstrates the selective dissolution of feldspars in the presence of carbonate minerals (both detrital and authigenic minerals) in these buried sandstones. The equilibrium constant of calcite leaching reactions is much smaller than that of K-feldspar leaching reactions. Numerical simulations of chemical reactions in K-feldspar-calcite–CO2–H2O systems utilizing the Geochemist's Workbench 9.0 (GWB) indicate that only a small amount of calcite was dissolved at the onset of simulation processes, while much K-feldspar was dissolved with precipitation of quartz, clays and some calcite for extended periods of time. Precipitation of secondary calcite could also promote feldspar dissolution. Simulation of reactions in a simplified sandstone system with constraints of present-day pore water and partical pressure of carbon dioxide (pCO2) in the northern Dongying Sag indicates that the pore waters are close to equilibrium with calcite. Petrography evidence and modeling results share consistence in confirming that only feldspar could be dissolved extensively, with precipitation of quartz, clays and some carbonate minerals.The organic CO2-leaching theory (Schmidt and McDonald, 1979) regarding the dissolution of mainly carbonates and, to a lesser degree, feldspars to form secondary pores has been questioned due to supposed extensive internal consumption of organic CO2 in source rocks by carbonate minerals. The CO2 in sandstones and shales and the isotopic composition of CO2 and carbonate cements in sandstones, however, suggest migration of organic CO2 from mudstones (even with large amounts of carbonate) to sandstones. Calculations in this study indicate that, with suppression of carbonate dissolution in sedimentary rocks, many secondary pores can be generated in sandstones through selective dissolution of feldspar by organic CO2 from thermal evolution of organic matter. Selective dissolution of feldspars, rather than carbonates, in sedimentary rocks is then likely a general mechanism to decipher the chemistry of secondary porosity.Other secondary porosity generation mechanisms were also reevaluated with numerical simulations. Results demonstrate that reverse weathering reactions of silicates may take place with increasing of temperatures, but cannot provide enough H+ to dissolve carbonates at elevated temperatures. Additionally, cooling of hot fluids can dissolve only insignificant amounts of carbonate unless significant amounts of water are provided.

Hysteretic trapping and relative permeability of CO2 in sandstone at reservoir conditions

Hysteretic nonwetting phase trapping behavior is predicted to be a significant factor determining long term immobilization of injected CO2. This paper presents results from an experimental investigation of hysteresis in residual trapping and relative permeability of CO2 in a CO2/water system at 50°C and 9MPa in a Berea sandstone core. Carbon dioxide saturation data were collected using the steady-state method in a horizontal core-flooding apparatus with X-ray computed tomography. Three flooding cycles were completed at a constant total volumetric flow rate by incrementally increasing and decreasing the fractional flow rates of supercritical CO2 and water. The fractional flow rates were chosen such that the maximum CO2 saturation of each cycle was greater than that of the previous cycle. During the injection stage of a cycle, CO2 displaced water in a wetting-phase drainage process (water saturation decrease). Following injection, water displaced CO2 in a wetting-phase imbibition process (water saturation increase). The fractional flow of CO2 was then increased during the next cycle. Results showed the CO2 saturations trapped during wetting-phase imbibition increased with the maximum CO2 saturations reached during each cycle. The residually trapped CO2 saturation is a hysteretic function, depending on the maximum saturation reached by the core before imbibition. A linear model with coefficient 0.5 describes the nonwetting trapping relationship. The experimental relative permeability data for CO2 fit a single bounding primary drainage curve while CO2 saturations increased, but followed three different scanning curves during wetting-phase imbibition. The CO2 relative permeability data can be fit by making a minor modification in the Van Genuchten–Burdine relative permeability data to account for hysteresis.

Interfacial Tension Effect on Cluster Size Distributions for Residual Trapping of CO2 in Sandstones

Abstract The residual trapping of CO2 could ensure long-term carbon geological storage. The understanding of the characteristic of the residual phase including saturation, size distribution is essential. The residual phase distribution is a complex function of pore morphology, interfacial tension (IFT) and wettability. Here, we numerically study IFT effect on the residual saturation and sizes distribution by using a highly efficient GPU (Graphic Processing Unit) based multi-phase lattice Boltzmann method. The results of direct simulation on real reservoir rocks imply that there is less trapping of CO2, but with a greater surface area for dissolution in low IFT condition.

Estimation of CO2 Storage Capacity in Porous Media by using X-ray Micro-CT

CO2 storage in deep geological structures is considered to be a promising method for the mitigation of CO2 emission. Estimation of the capacity of a geological reservoir is of great importance. Core level study of CO2 storage mechanism and estimation of CO2 storage capacity at laboratory scale have shown to be great helpful for CO2 geological storage studies.This paper is proposed against the background of long term and safe storage of CO2 in deep saline aquifers. Experiments for CO2 storage in glass beads bed were inducted at laboratory scale. Quartz beads were filled and packed tightly in the imaging vessel. Gaseous CO2 was then injected into the sample at a constant flow rate and saturated water was driven out. Two CO2 injection directions in the vessel were chose, namely upwards and downwards to observe the effect of buoyancy. Three dimensional scans were carried out using a micro focus X-ray CT system to investigate the distribution of CO2 in sandstone cores.Digital cores of those samples were obtained after a series of imaging processing of media filtering, rescaling, and thresholding. Then a maximal ball (MB) algorithm was used to extract the equivalent pore networks. The parameters of the pore networks, such as coordination number, size distributions and shape factors of pore and throat were computed. Gas channeling phenomena was obviously found in water saturated beads bed while CO2 was injected upwards during displacement experiments. A short breakthrough time resulted in low sweep coefficient and only about 10% of saturated water was displaced. Nevertheless, about 80% of saturated water could be driven out and displaced by CO2 while it was injected downwards. Storage capacity of residual trapping was enhanced while CO2 was injected downwards along the beads bed. X-ray micro CT was proved to be an effective technique for the investigation of CO2 storage in core sample and a novel method for the estimation of CO2 storage capacity.

Modeling of fate and transport of coinjection of H2S with CO2in deep saline formations

[1] The geological storage of CO2 in deep saline formations is increasingly seen as a viable strategy to reduce the release of greenhouse gases into the atmosphere. However, costs of capture and compression of CO2 from industrial waste streams containing small quantities of sulfur and nitrogen compounds such as SO2, H2S, and N2 are very expensive. Therefore, studies on the coinjection of CO2 containing other acid gases from industrial emissions are very important. In this paper, numerical simulations were performed to study the coinjection of H2S with CO2 in sandstone and carbonate formations. Results indicate that the preferential dissolution of H2S gas (compared with CO2 gas) into formation water results in the delayed breakthrough of H2S gas. Coinjection of H2S results in the precipitation of pyrite through interactions between the dissolved H2S and Fe2+ from the dissolution of Fe-bearing minerals. Additional injection of H2S reduces the capabilities for solubility and mineral trappings of CO2 compared to the CO2-only case. In comparison to the sandstone (siliciclastic) formation, the carbonate formation is less favorable to the mineral sequestration of CO2. In sandstone and carbonate formations, the presence of Fe-bearing siliciclastic and/or carbonate is more favorable to the H2S mineral trapping.