Numerical simulation of fracture pattern development and implications for fuid flow

Simulations are instrumental to understanding flow through discrete fracture geometric representations that capture the large-scale permeability structure of fractured porous media. The contribution of this thesis is threefold: an efficient finite-element finite-volume discretisation of the advection/diffusion flow equations, a geomechanical fracture propagation algorithm to create fractured rock analogues, and a study of the effect of growth on hydraulic conductivity. We describe an iterative geomechanics-based finite-element model to simulate quasi-static crack propagation in a linear elastic matrix from an initial set of random flaws. The cornerstones are a failure and propagation criterion as well as a geometric kernel for dynamic shape housekeeping and automatic remeshing. Two-dimensional patterns exhibit connectivity, spacing, and density distributions reproducing en echelon crack linkage, tip hooking, and polygonal shrinkage forms. Differential stresses at the boundaries yield fracture curving. A stress field study shows that curvature can be suppressed by layer interaction effects. Our method is appropriate to model layered media where interaction with neighbouring layers does not dominate deformation. Geomechanically generated fracture patterns are the input to single-phase flow simulations through fractures and matrix. Thus, results are applicable to fractured porous media in addition to crystalline rocks. Stress state and deformation history control emergent local fracture apertures. Results depend on the number of initial flaws, their initial random distribution, and the permeability of the matrix. Straightpath fracture pattern simplifications yield a lower effective permeability in comparison to their curved counterparts. Fixed apertures overestimate the conductivity of the rock by up to six orders of magnitude. Local sample percolation effects are representative of the entire model flow behaviour for geomechanical apertures. Effective permeability in fracture dataset subregions are higher than the overall conductivity of the system. The presented methodology captures emerging patterns due to evolving geometric and flow properties essential to the realistic simulation of subsurface processes

Residual trapping of CO2 in an oil-filled, oil-wet sandstone core: Results of three-phase pore-scale imaging

CO2 geosequestration in oil reservoirs is an economically attractive solution as it can be combined with enhanced oil recovery (CO2-EOR). However, the effectiveness of the associated three-phase displacement processes has not been tested at the micrometer pore scale, which determines the overall reservoir-scale fluid dynamics and thus CO2-EOR project success. We thus imaged such displacement processes in situ in 3-D with X-ray microcomputed tomography at high resolution at reservoir conditions and found that oil extraction was enhanced substantially, while a significant residual CO2 saturation (13.5%) could be achieved in oil-wet rock. Statistics of the residual CO2 and oil clusters are also provided; they are similar to what is found in analogue two-phase systems although some details are different, and displacement processes are significantly more complex

Caprock integrity and public perception studies of carbon storage in depleted hydrocarbon reservoirs

Capture and subsurface storage of CO2 is widely viewed as being a necessary component of any strategy to minimise and control the continued increase in average global temperatures. Existing oil and gas reservoirs can be re-used for carbon storage, providing a substantial fraction of the vast amounts of subsurface storage space that will be required for the implementation of carbon storage at an industrial scale. Carbon capture and storage (CCS) in depleted reservoirs aims to ensure subsurface containment, both to satisfy safety considerations, and to provide confidence that the containment will continue over the necessary timescales. Other technical issues that need to be addressed include the risk of unintended subsurface events, such as induced seismicity. Minimisation of these risks is key to building confidence in CCS technology, both in relation to financing/liability, and the development and maintenance of public acceptance. These factors may be of particular importance with regard to CCS projects involving depleted hydrocarbon reservoirs, where the mechanical effects of production activities must also be considered. Given the importance of caprock behaviour in this context, several previously published geomechanical caprock studies of depleted hydrocarbon reservoirs are identified and reviewed, comprising experimental and numerical studies of fourteen CCS pilot sites in depleted hydrocarbon reservoirs, in seven countries (Algeria, Australia, Finland, France, Germany, Netherlands, Norway, UK). Particular emphasis is placed on the amount and types of data collected, the mathematical methods and codes used to conduct geomechanical analysis, and the relationship between geomechanical aspects and public perception. Sound geomechanical assessment, acting to help minimise operational and financial/liability risks, and the careful recognition of the impact of public perception are two key factors that can contribute to the development of a successful CCS project in a depleted hydrocarbon reservoir

Residual CO2 trapping in oil-wet sandstone

CO2 geo‐sequestration in oil reservoirs is an economically attractive solution as it can be combined with enhanced oil recovery (CO2‐EOR). However, the effectiveness of the associated three‐phase displacement processes has not been tested at the micrometer pore‐scale, which determines the overall reservoir‐scale fluid dynamics and thus CO2‐EOR project success. We thus imaged such displacement processes in‐situ in 3D with x‐ray micro‐computed tomography at high resolution at reservoir conditions, and found that oil extraction was enhanced substantially, while a significant residual CO2 saturation (13.5 %) could be achieved in oil‐wet rock. Statistics of the residual CO2 and oil clusters are also provided, they are similar to what is found in analogue two‐phase systems although some details are different, and displacement processes are significantly more complex

Caprock integrity and public perception studies of carbon storage in depleted hydrocarbon reservoirs

Capture and subsurface storage of CO2 is widely viewed as being a necessary component of any strategy to minimise and control the continued increase in average global temperatures. Existing oil and gas reservoirs can be re-used for carbon storage, providing a substantial fraction of the vast amounts of subsurface storage space that will be required for the implementation of carbon storage at an industrial scale. Carbon capture and storage (CCS) in depleted reservoirs aims to ensure subsurface containment, both to satisfy safety considerations, and to provide confidence that the containment will continue over the necessary timescales. Other technical issues that need to be addressed include the risk of unintended subsurface events, such as induced seismicity. Minimisation of these risks is key to building confidence in CCS technology, both in relation to financing/liability, and the development and maintenance of public acceptance. These factors may be of particular importance with regard to CCS projects involving depleted hydrocarbon reservoirs, where the mechanical effects of production activities must also be considered. Given the importance of caprock behaviour in this context, several previously published geomechanical caprock studies of depleted hydrocarbon reservoirs are identified and reviewed, comprising experimental and numerical studies of fourteen CCS pilot sites in depleted hydrocarbon reservoirs, in seven countries (Algeria, Australia, Finland, France, Germany, Netherlands, Norway, UK). Particular emphasis is placed on the amount and types of data collected, the mathematical methods and codes used to conduct geomechanical analysis, and the relationship between geomechanical aspects and public perception. Sound geomechanical assessment, acting to help minimise operational and financial/liability risks, and the careful recognition of the impact of public perception are two key factors that can contribute to the development of a successful CCS project in a depleted hydrocarbon reservoir.</p

Hydrogen flooding of a coal core: Effect on coal swelling

Hydrogen is a clean fuel which has the potential to drastically decarbonize the energy supply chain. However, hydrogen storage is currently a key challenge; one solution to this problem is hydrogen geo-storage, with which very large quantities of H2 can be stored economically. Possible target formations are deep coal seams, and coal permeability is a key parameter which determines how fast H2 can be injected and withdrawn again. However, it is well known that gas injection into coal can lead to coal swelling, which drastically reduces permeability. We thus injected H2 gas into a coal core and measured dynamic permeability, while imaging the core via x-ray micro-tomography at reservoir conditions. Importantly, no changes in coal cleat morphology or permeability were observed. We conclude that H2 geo-storage in deep coal seams is feasible from a fundamental petro-physical perspective; this work thus aids in the large-scale implementation of a hydrogen economy