Abstract We use a combination of experimental design, sketch-based reservoir modelling and flow diagnostics to rapidly screen the impact of sedimentological heterogeneities that constitute baffles and barriers on CO 2 migration in depleted hydrocarbon reservoirs and saline aquifers of the Sherwood Sandstone Group and Bunter Sandstone Formation, UK. These storage units consist of fluvial sandstones with subordinate aeolian sandstones, floodplain and sabkha heteroliths and lacustrine mudstones. The predominant control on effective horizontal permeability is the lateral continuity of aeolian-sandstone intervals. Effective vertical permeability is controlled by the lateral extent, thickness and abundance of lacustrine-mudstone layers and aeolian-sandstone layers, and the mean lateral extent and mean vertical spacing of carbonate-cemented basal channel lags in fluvial facies-association layers. The baffling effect on CO 2 migration and retention is approximated by the pore volume injected at breakthrough time, which is controlled largely by three heterogeneities, in order of decreasing impact: (1) the lateral continuity of aeolian-sandstone intervals; (2) the lateral extent of lacustrine-mudstone layers; and (3) the thickness and abundance of fluvial-sandstone, aeolian-sandstone, floodplain-and-sabkha-heterolith and lacustrine-mudstone layers. Future effort should be focused on characterizing these three heterogeneities as a precursor for later capillary, dissolution and mineral trapping.

Abstract The introduction reviews topics relevant to the fundamental controls on fluid flow in carbonate reservoirs and to the prediction of reservoir performance. The review provides research and industry contexts for papers in this volume only. A discussion of global context and frameworks emphasizes the value yet to be captured from compare and contrast studies. Multidisciplinary efforts highlight the importance of greater integration of sedimentology, diagenesis and structural geology. Developments in analytical and experimental methods, stimulated by advances in the materials sciences, support new insights into fundamental (pore-scale) processes in carbonate rocks. Subsurface imaging methods relevant to the delineation of heterogeneities in carbonates highlight techniques that serve to decrease the gap between seismically resolvable features and well-scale measurements. Methods to fuse geological information across scales are advancing through multiscale integration and proxies. A surge in computational power over the last two decades has been accompanied by developments in computational methods and algorithms. Developments related to visualization and data interaction support stronger geoscience–engineering collaborations. High-resolution and real-time monitoring of the subsurface are driving novel sensing capabilities and growing interest in data mining and analytics. Together, these offer an exciting opportunity to learn more about the fundamental fluid-flow processes in carbonate reservoirs at the interwell scale.

Abstract Field X comprises a giant Palaeogene limestone reservoir with a long production history. An original geomodel used for history matching employed a permeability transform derived directly from core data. However, the resulting permeability model required major modifications, such as horizontal and vertical permeability multipliers, in order to match the historic data. The rationale behind these multipliers is not well understood and not based on geological constraints. Our study employs an integrated near-wellbore upscaling workflow to identify and evaluate the geological heterogeneities that enhanced reservoir permeability. Key among these heterogeneities are mechanically weak zones of solution-enhanced porosity, leached stylolites and associated tension-gashes, which were developed during late-stage diagenetic corrosion. The results of this investigation confirmed the key role of diagenetic corrosion in enhancing the permeability of the reservoir. Insights gained from the available production history, in conjunction with petrophysical data analysis, substantiated the characterization of this solution-enhanced permeability. This study provided valuable insights into the means by which a satisfactory field-level history match for a giant carbonate reservoir can be achieved. Instead of applying artificial permeability multipliers that do not necessarily capture the impacts of geological heterogeneities, our method incorporates representations of fine-scale heterogeneities. Improving the characterization of permeability distribution in the field provided an updated and geologically consistent permeability model that could contribute to the ongoing development plans to maximize incremental oil recovery.

Abstract Naturally fractured reservoirs (NFR), such as the large carbonate reservoirs in the Middle East, contain a major part of the world’s remaining conventional oil reserves, but recovering these is especially challenging as the fractures only constitute fluid conduits while the oil is trapped in a low-permeability rock matrix. Recovery factors are therefore difficult to estimate, permeability anisotropy is high, size and shape of drainage areas are difficult to constrain, early water breakthrough is likely to be associated with a high and irreversible water cut, and secondary recovery behaviour is unusual. Outcrop-analogue model-based discrete fracture and matrix (DFM) simulations have emerged recently, helping us to disentangle and rationalize this erratic production behaviour. They allow us to understand the emergent flow behaviour and resulting saturation patterns in NFRs. Thus, classical simulation approaches, such as dual-continua conceptualizations, can be critically evaluated and improved where they fail to capture the flow behaviour of interest. This paper discusses recent advances in DFM simulation of single- and multi-phase flow processes in geologically realistic outcrop-analogue models, and solved with finite-element (FE) and finite-volume (FV) methods. It also reviews key results from recent DFM simulation studies, in particular how new measures such as the fracture–matrix flux ratio and velocity spectra can provide new means to analyse flow behaviour in heterogeneous domains or how results from outcrop-based simulations can be used to test the suitability of conventional upscaling approaches for NFR and guide the development of new ones. We close by enlisting outstanding challenges in outcrop-based flow simulations such as the need to capture the fracture–matrix transfer processes due to capillary, gravity and viscous forces accurately, which often implies detailed grid refinement at the fracture–matrix interface and small time-steps to resolve the physical processes adequately. Thus, we explore how outcrop-based flow simulation could be applied more routinely in NFR reservoir characterization and simulation workflows.

Abstract The dilatancy–diffusion hypothesis was one of the first attempts to predict the form of potential geophysical signals that may precede earthquakes, and hence provide a possible physical basis for earthquake prediction. The basic hypothesis has stood up well in the laboratory, where catastrophic failure of intact rocks has been observed to be associated with geophysical signals associated both with dilatancy and pore pressure changes. In contrast, the precursors invoked to determine the predicted earthquake time and event magnitude have not stood up to independent scrutiny. There are several reasons for the lack of simple scaling between the laboratory and the field scales, but key differences are those of scale in time and space and in material boundary conditions, coupled with the sheer complexity and non-linearity of the processes involved. ‘Upscaling’ is recognized as a difficult task in multi-scale complex systems generally and in oil and gas reservoir engineering specifically. It may however provide a clue as to why simple local laws for dilatancy and diffusion do not scale simply to bulk properties at a greater scale, even when the fracture system that controls the mechanical and hydraulic properties of the reservoir rock is itself scale-invariant.