Coupled Flow and Geomechanics Model for CO 2 Storage in Tight Gas Reservoir

A review on pore-scale modeling and CT scan technique to characterize the trapped carbon dioxide in impermeable reservoir rocks during sequestration

Abstract: Global warming is increasing at a perpetual rate due to the emission of greenhouse gases in recent years. This spectacle has been mainly caused by the increase of carbon dioxide (CO2) in the environment. It is in need to find a path to reduce the greenhouse gases along with the additional benefit of energy demand in a sustainable way. A favorable long-term way out to mitigate global warming is to inject CO2 into geological formations of oil fields to achieve a goal of a combination of CO2 sequestration and enhanced oil recovery by CO2 flooding. Understanding the mechanism of CO2 sequestration under impermeable rock formation requires the knowledge of the pore-scale modeling concept. This review article provides an overview of pore-scale modeling and micro-CT scan imaging technique for CO2 sequestration including a background of basic concepts related to storage, CO2 enhanced oil recovery, simulators used, and storage estimation. Trapping mechanisms, geological description of the formation for CO2 sequestration, and reactions that have taken place during the trapping in underground formation are also discussed elaborately. Macro-scale and pore-scale modeling are depicted based on the current literature available. This review also presents petrophysical data that comes from the pore network modeling of CO2-brine pore structure for the formation of carbon-containing sandstone reservoirs. A discussion on the challenges of CO2 sequestration and modeling in pore-scale is also furnished to point out the problems and solutions in near future. Finally, the prospect of CO2 sequestration and pore-scale modeling are described for its uncountable value in greenhouse gas reduction from the environment.

Properties of Porous Media Affecting Fluid Flow

Abstract: Following the Burdine approach, based on a model developed by Wyllie and Spangler, a theory is presented that develops the functional relationships among saturation, pressure difference, and permeabilities of air and liquid in terms of hydraulic properties of partially saturated porous media. The theory is based only on the capillary pressure-desaturation relationships for porous media. Procedures for determining these hydraulic properties from capillary pressure-desaturation curves are described. Permeabilities to the wetting and nonwetting phases as a function of capillary pressure and saturation are predicted from the experimentally determined hydraulic properties. The results for all media studied are in close agreement with the theory.

An overview of current status of carbon dioxide capture and storage technologies

Abstract: Global warming and climate change concerns have triggered global efforts to reduce the concentration of atmospheric carbon dioxide (CO2). Carbon dioxide capture and storage (CCS) is considered a crucial strategy for meeting CO2 emission reduction targets. In this paper, various aspects of CCS are reviewed and discussed including the state of the art technologies for CO2 capture, separation, transport, storage, leakage, monitoring, and life cycle analysis. The selection of specific CO2 capture technology heavily depends on the type of CO2 generating plant and fuel used. Among those CO2 separation processes, absorption is the most mature and commonly adopted due to its higher efficiency and lower cost. Pipeline is considered to be the most viable solution for large volume of CO2 transport. Among those geological formations for CO2 storage, enhanced oil recovery is mature and has been practiced for many years but its economical viability for anthropogenic sources needs to be demonstrated. There are growing interests in CO2 storage in saline aquifers due to their enormous potential storage capacity and several projects are in the pipeline for demonstration of its viability. There are multiple hurdles to CCS deployment including the absence of a clear business case for CCS investment and the absence of robust economic incentives to support the additional high capital and operating costs of the whole CCS process.

The Finite Element Method in the Static and Dynamic Deformation and Consolidation of Porous Media

Abstract: Keywords: Methode des elements finis ; Sols non satures ; Consolidation Reference Record created on 2004-09-07, modified on 2016-08-08

Sequestration of CO2 in geological media in response to climate change: capacity of deep saline aquifers to sequester CO2 in solution

Abstract: Geological sequestration is a means of reducing anthropogenic atmospheric emissions of CO2 that is immediately available and technologically feasible. Among various options, CO2 can be sequestered in deep aquifers by dissolution in the formation water. The ultimate CO2 sequestration capacity in solution (UCSCS) of an aquifer is the difference between the total capacity for CO2 at saturation and the total inorganic carbon currently in solution in that aquifer, and depends on the pressure, temperature and salinity of the formation water. Assuming non-reactive aquifer conditions, the current carbon content is calculated using standard chemical analyses of the formation waters collected by the energy industry on the basis of the concentration of carbonate and bicarbonate ions. Formation water analyses performed at laboratory conditions are brought to in situ conditions using a geochemical speciation model to account for dissolved gasses that are lost from the water sample. To account for the decrease in CO2 solubility with increasing water salinity, the maximum CO2 content in formation water is calculated by applying an empirical correction to the CO2 content at saturation in pure water. The UCSCS in an aquifer is calculated by considering the effect of dissolved CO2 on the formation water density, the aquifer thickness and porosity to account for the volume of water in the aquifer pore space and for the mass of CO2 dissolved in the water currently and at saturation. The methodology developed for estimating the ultimate CO2 sequestration capacity in solution in aquifers has been applied to the Viking aquifer in the Alberta basin in western Canada. Considering only the region where the injected CO2 would be a dense fluid, the capacity of the Viking aquifer to sequester CO2 in solution in the formation water is calculated to be 100 Gt. Simple estimates then indicate that the capacity of the Alberta basin to sequester CO2 dissolved in the formation waters at depths greater than 1000 m is on the order of 4000 Gt CO2. The results also show that using geochemical models to bring the analyses of the formation waters to in situ conditions is not warranted when the current total inorganic carbon (TIC) in the aquifer water is very small by comparison with the CO2 solubility at saturation. Furthermore, in such cases, the current TIC may even be neglected.

How Permeability Depends on Stress and Pore Pressure in Coalbeds: A New Model

Abstract: In naturally fractured formations, such as coal, permeability is sensitive to changes in stress or pore pressure (i.e., effective stress). This paper presents a new theoretical model for calculating pore volume compressibility and permeability in coals as a function of effective stress and matrix shrinkage, using a single equation. The equation is appropriate for uniaxial strain conditions, as expected in a reservoir. The model predicts how permeability changes as pressure is decreased (i.e., drawdown). Pore volume compressibility is derived in this theory from fundamental reservoir parameters. It is not constant, as often assumed. Pore volume compressibility is high in coals because porosity is so small. A rebound in permeability can occur at lower drawdown pressures for the highest modulus and matrix shrinkage values. We have also history matched rates from a {open_quotes}boomer{close_quotes} well in the fairway of the San Juan basin using various stress-dependent permeability functions. The best fit stress-permeability function is then compared with the new theory.