Abstract This volume examines the current best practice and new challenges in reservoir characterization and modelling of small- to subseismic-scale deformation features through case studies, experimental results and modelling. The papers in this volume include contributions on four themes related to the small-scale deformation of hydrocarbon reservoirs: the characterization of deformation in porous sandstones; novel characterization techniques; quantifying and characterizing deformation in carbonates; and modelling small-scale features. It includes eight papers from the conference Small to Subseismic-Scale Reservoir Deformation, organized by the Petroleum Group of the Geological Society and held in London from 29 to 30 October 2014, plus two additional papers. The observations in this introduction reflect the authors’ experiences and opinions, presentations at the conference and the papers within this volume.

Abstract Deformation bands are common subseismic structures in porous sandstones that vary with respect to deformation mechanisms, geometries and distribution. The amount of cataclasis involved largely determines how they impact fluid flow, and cataclasis is generally promoted by coarse grain size, good sorting, high porosity and overburden (usually >500–1000 m). Most bands involve a combination of shear and compaction, and a distinction can be made between those where shear displacement greatly exceeds compaction (compactional shear bands or CSB), where the two are of similar magnitude (shear-enhanced compaction bands or SECB), and pure compaction bands (PCB). The latter two only occur in the contractional regime, are characterized by high (70–100°) dihedral angles (SECB) or perpendicularity (PCB) to σ 1 (the maximum principal stress) and are restricted to layers with very high porosity. Contraction generally tends to produce populations of well-distributed deformation bands, whereas in the extensional regime the majority of bands are clustered around faults. Deformation bands also favour highly porous parts of a reservoir, which may result in a homogenization of the overall reservoir permeability and enhance sweep during hydrocarbon production. A number of intrinsic and external variables must therefore be considered when assessing the influence of deformation bands on reservoir performance.

Abstract A classical Upper Jurassic fault block in the North Sea, the Fulla Structure, has Brent Group sandstones with good reservoir quality and apparently insignificant fault-related reservoir damage. Core data show high-porous sandstones that extend close to the main faults and there is no evidence of catalase, only of soft-sedimentary deformation. Shear bands are relatively thin with high offsets, and have a texture comparable to the wall rock. To investigate the deformation mechanism and products synthetic Brent Group sands are deformed in a triaxial plane strain box with pre-defined effective consolidation in the range of 100–8000 kPa, simulating a burial depth in the range of 10–800 m. This range covers the burial depth at the time of active faulting for most Jurassic traps in the North Sea, including the Fulla Structure. The experiments demonstrate that grain rolling and grain-boundary sliding are the dominant deformation mechanisms at all the simulated burial depths, and this deformation has no impact on the reservoir quality. The experiments concur with observations from the investigated wells and strengthen an interpretation of limited reservoir damage associated with the Late Jurassic fault activity.

Abstract Little is known about the effect of thrusting on lithological and petrophysical properties of reservoir sandstone. Here we use field observations, probe permeability measurements and thin-section analysis along ten transects from the Muddy Mountain thrust contact downwards into the underlying Jurassic Aztec Sandstone to evaluate the nature and extent of petrophysical and microstructural changes caused by the thrusting. The results reveal a decimetre- to metre-thick low-permeable (≤50 mD) and indurated (0–3% porosity) zone immediately beneath the thrust contact in which dominant microscale processes, in decreasing order of importance, are (1) cataclasis with local fault gouge formation; (2) pressure solution; and (3) very limited cementation. From this narrow zone the petrophysical and microstructural effect of the thrusting decreases gradually downwards into a friable, highly porous ( c. 25%) and permeable (≤2 D) sandstone some 50–150 m below the thrust, in which strain is localized into deformation band populations. In general, the petrophysical properties of the sandstone as a result of overthrusting reveal little impact in overall primary reservoir quality below some tens of metres into the footwall, except for the relatively minor baffling effect of deformation bands.

Abstract The distribution of fault rocks interpreted across a modelled fault in oil or gas reservoirs is most often described by its clay content derived from standard industry algorithms such as shale gouge ratio and clay smear factor. These distributions are below the mapping resolution in seismic data, and the actual processes and mechanisms for the fault-rock development are not well understood. A well-exposed and well-preserved low-throw fault in an old railroad tunnel near Salina, Utah provides the access and scale to interpret fault-rock distributions, measure their clay contents and describe the fault-rock development. A significant number of fault-rock elemental compositions were measured quickly on the outcrop surface using a hand-held X-ray fluorescence (XRF) elemental analyser with a novel surface preparation and analysis strategy. The elemental data were converted to clay contents using a small set of samples where elemental composition was calibrated to X-ray diffraction mineralogy. The mineralogy data provide a basis for evaluating the degree of mixing of protolith beds during fault-rock development in the fault core. The fault core is not randomly mixed fragments derived from the protolith (gouge or breccia), but rather discrete, thin layers parallel to the fault surface, many of which can be traced back to a source sandstone or mudstone bed. The mineralogical composition of some fault-rock layers are unchanged from their protolith source bed, but other layers are mechanical mixtures of several source beds. The shale gouge ratio algorithm under-represents the average measured fault-rock clay content. The clay smear algorithm more accurately describes the clay content distribution, but underestimates the clay content heterogeneity along the smear length. A key uncertainty for predicting fault sealing remains prediction of the lengths and continuity of smears.

Abstract X-ray computed tomography (CT) is frequently used for non-destructive imaging and analysis of internal features in rock samples. In this paper we review the method for analysis of subseismic deformation structures in reservoir rocks, and provide some examples of different types of structures. Both medical CT and high-resolution µCT have great potential for identification of small-scale deformation structures in reservoir rocks and samples from outcrop analogues. The CT imaging techniques provide 3D data that are used in combination with 2D information from core or outcrop, thin-section and scanning electron microscopy (SEM). CT and µCT are used for quantitative and qualitative analysis of individual fractures and fracture networks, and for imaging and analysis of internal heterogeneities of fault rocks and deformation bands. The benefit of CT is that 3D properties (e.g. structure size, connectivity and variation in aperture) are actually characterized in 3D, contrary to traditional 2D methods using core surface, thin-section and outcrop. Limitations and uncertainties arise from artefacts during acquisition and processing, scale of observation and resolution, and manual steps involved in the segmentation of the CT volume. Increased availability of medical CT and µCT scanners and improved resolution should in the future lead to improved description and modelling of small-scale reservoir structures.

Abstract It is common practice to incorporate deterministic transmissibility multipliers into simulation models of siliciclastic reservoirs to take into account the impact of faults on fluid flow, but this is not common practice in carbonate reservoirs due to the lack of data on fault permeability. Calculation of fault transmissibilities in carbonates is also complicated by the variety of mechanisms active during faulting, associated with their high heterogeneity and increased tendency to react with fluids. Analysis of the main controls on fault-rock formation and permeability from several carbonate-hosted fault zones is used to enhance our ability to predict fault transmissibility. Lithological heterogeneity in a faulted carbonate succession leads to a variety of deformation and/or diagenetic mechanisms, generating several fault-rock types. Although each fault-rock type has widely varying permeabilities, trends can be observed dependent on host lithofacies, juxtaposition and displacement. These trends can be used as preliminary predictive tools when considering fluid flow across carbonate fault zones. Fewer mechanisms occur at lower displacements (<30 m), creating limited fault-rock types with a narrow range of low permeabilities regardless of lithofacies juxtaposition. At increased displacements, more fault-rock types are produced at juxtaposition of different lithofacies, with a wide range of permeabilities.

Abstract The productivity of wells in fractured reservoirs depends, in terms of rate and sustainability, on the heterogeneity and variable connectivity of the open fracture network. Outcrop studies in Cretaceous carbonates from the Catalan Pyrenees illuminate this issue and reveal the degree of uncertainty associated with the interpretation of fracture data from wells and seismic. Three examples are chosen to provide verifiable data, parameters and concepts which can be applied to the workflow of fractured reservoir characterization. We discuss fracture properties and distributions in the subseismic volume, the coupled behaviour between litho-mechanical properties, in situ stress and fracturing, and the permeability properties of fault damage zones. The outcrops also highlight some of the difficulties involved in constructing static reservoir models and evaluating fracture interpretations derived from software-based techniques such as surface curvature.

Abstract This study investigates the Late Aptian–earliest Albian platform carbonates of the Benicàssim area (Maestrat Basin, Spain) in order to assess the relationship between bed-parallel stylolites and the flow of diagenetic fluids during dolomitization and subsequent hydrothermal alteration. Dolostones and burial dolomite and calcite cements were studied by a combination of field geology and standard petrographic and isotope analysis. Field data indicate that dolostones are closely associated with seismic-scale synsedimentary faults, preferentially replace grain-dominated facies and typically show wavy dolomitizing fronts that mostly correspond to bed-parallel stylolites. The dolostones are corroded and contain bed-parallel pores that are filled with hydrothermal saddle dolomite and blocky calcite cements. This late calcite cement frequently engulfs clasts of the host dolostones, suggesting that hydraulic brecciation likely associated with overpressured fluid occurred. Results indicate that stylolites play a key role in the distribution of dolostones and subsequent hydrothermal mineralization. During the replacement stage, stylolites acted as baffles for the dolomitzing fluids controlling lateral fluid flow and resulting in the stratabound dolostone distribution. During the post-dolomitization stage, stylolites became preferred pathways for overpressured hydrothermal corrosive and mineralizing fluids that likely came from the underlying basement, and increased bed-parallel stylolitic porosity and probably also permeability.

Abstract Flow simulations of fractured and faulted reservoirs require representation of subseismic structures about which subsurface data are limited. We describe a method for simulating fracture growth that is mechanically based but heuristic, allowing for realistic modelling of fracture networks with reasonable run times. The method takes a triangulated meshed surface as input, together with an initial stress field. Fractures initiate and grow based on the stress field, and the growing fractures relieve the stress in the mesh. We show that a wide range of bedding-plane joint networks can be modelled simply by varying the distribution and anisotropy of the initial stress field. The results are in good qualitative agreement with natural joint patterns. We then apply the method to a set of parallel veins and demonstrate how the variations in thickness of the veins can be represented. Lastly, we apply the method to the simulation of normal fault patterns on salt domes. We derive the stress field on the bedding surface using the horizon curvature. The modelled fault network shows both radial and concentric faults. The new method provides an effective means of modelling joint and fault networks that can be imported to the flow simulator.

Abstract Discrete fracture and matrix (DFM) homogenization, simultaneously capturing reservoir layers and contained fractures, is an alternative to discrete fracture network (DFN) upscaling. Here, the DFM approach was applied to a fractured carbonate reservoir. Honouring geostatistical data from well logs, near-well multilayer reservoir models were constructed and analysed. Fracture aperture variations were modelled with a new semi-analytical model including a special treatment of layer-restricted fractures. Important results concern both pre-processing of stochastically generated DFMs for finite-element meshing, and the ensemble permeability values obtained by numerical homogenization of single v. multilayer models, respectively. Upscaling by volume averaging of vertically stacked single-layer DFMs results only in a fraction of the equivalent horizontal permeability that is obtained by homogenization of the multilayer models. Inspection of the flow patterns shows that this discrepancy arises because many fractures contact each other at layer boundaries fostering cross-flow. This effect is further enhanced where fractures intersect multiple layers. Compared to earlier DFN models for this reservoir, the DFM-derived fracture and matrix ensemble permeabilities are up to four times higher, highlighting how important it is to include the rock matrix into equivalent permeability calculations.

Abstract The carbonate reservoirs in the Late Oligocene—Early Miocene Asmari Formation in the Dezful Embayment of SW Iran are characterized by low matrix permeability, and effective drainage is dependent on the occurrence of open fractures. Limited information on fracture orientation and fracture density is available from core and borehole image data, and high-quality/high-resolution three-dimensional seismic is often lacking in this area. Well and core data do not contain information on important fracture parameters like length distribution, crosscutting relationships, fracture density v. lithology and bed thickness. The understanding of fracture distribution and formation in the region and their effects on fluid flow has been greatly improved by the use of outcrop analogue data. Exposures of the Asmari Formation in the Khaviz Anticline are in close vicinity to the giant hydrocarbon fields. The Khaviz Anticline has a similar geometry and structural history to the major hydrocarbon fields in the area, and represents an excellent analogue for these. Two types of fracture features were observed: diffuse fracturing and fracture swarms. The diffuse fractures form networks and comprise structures grouped into four fractures sets, which are the typical for this type of anticline. Two orthogonal fracture sets are oriented parallel and perpendicular to the fold axis, and two conjugate fracture sets are oblique to the fold axis with their obtuse angle intersecting the trend of the fold axis. The fractures are typically stratabound, sub-perpendicular to bedding and commonly about the bounding stratigraphic surfaces. To a large extent the density and height of fractures in the Asmari Formation are controlled by the mechanical stratigraphy, which is controlled by the depositional environment and cycles. These outcrop data have been essential in the generation of discrete fracture network (DFN) models and the population of the fracture properties in the reservoir models.