Abstract: Prediction of sandstone body dimensions within paralic depositional systems is crucial for the development of predictive 3D reservoir models. Continental-scale paralic reservoir targets have complex architectures, with interpretation often further compounded because they are often located at subsurface depths ≥2 km in pre- and synrift basinal settings, typified by poor seismic resolution. As such, in many cases analysis relies on core and wireline-log data, from which depositional facies are interpreted and thicknesses of sandstone reservoir units measured. Estimation of width:thickness (W:T) ratios for different reservoir elements relies on analogue data. However, the inherent uncertainty in the initial interpretation of core/log data and the wide W:T ranges for different sandstone bodies within published analogue datasets hinders prediction of accurate reservoir geometry/dimensions. Without access to quality seismic data, constraining the evolution and dimensions of reservoirs in these depositional systems is challenging. This paper presents a detailed case study of the Triassic Mungaroo Formation, and assesses the uncertainty and limitation of interpretations that can be made about reservoir architecture and the evolution of a paralic depositional system, if only wireline and core data are available. The Mungaroo Formation is characterized by upper and lower delta-plain channel sandstones, swamps and restricted embayments, through to delta-front and pro-delta heterolithics. Core-to-wireline-log calibration allowed identification of key marine intervals that enabled well correlations to be established across the study area, based on candidate flooding surfaces. Applying classic sequence stratigraphic models to low gradient fluvio-deltaic systems is difficult, due to a lack of preservation and/or confident identification of laterally continuous chronostratigraphic markers. The large-scale temporal change in reservoir architecture was likely to have been controlled by eustatic sea level causing overall transgression of the depositional system. However, the observed complex spatial facies variability is most likely controlled by climatic-induced changes in sediment supply/fluvial discharge and autocyclic processes. Four classes of sandstone bodies/reservoir elements have been identified from core and wireline data based on their thickness distributions. Whereas core to wireline to seismic calibration has enabled large-, medium- and small-scale geobodies to be identified representing fluvial channel belt complexes; multistorey channel belts; and single-storey channel belts, respectively. To predict channel body widths and sinuosity from thickness data extracted from wells, typically, analogue data are used. However, for each geobody type there is a large range of possible sandstone body dimensions based on published literature. The largest-scale sand bodies, with most significance as reservoir targets, have possible interpretations as either incised valleys or amalgamated channel belts, based on their thickness ranges alone. This poses significant uncertainty for understanding the evolution of the depositional system and input into predictive reservoir models. This study emphasizes the importance of understanding the range of uncertainty of interpretation and the need for refined analogue data to better constrain reservoir element dimensions when relying solely on well-log datasets. Where seismic attribute analysis from high-quality 3D seismic data are available, W:T dimensions for reservoir elements can be constrained more accurately and correlated to core and log data. The existing global database is limited, often poorly constrained due to the use of variable terminology and potential for misinterpretation. Many studies lack statistical rigour. We conclude that further high-resolution studies are required to build more robust and quantitative analogue datasets.

Abstract Naturally fractured reservoirs, within which porosity, permeability pathways and/or impermeable barriers formed by the fracture network interact with those of the host rock matrix to influence fluid flow and storage, can occur in sedimentary, igneous and metamorphic rocks. These reservoirs constitute a substantial percentage of remaining hydrocarbon resources; they create exploration targets in otherwise impermeable rocks, including under-explored crystalline basement, and they can be used as geological stores for anthropogenic carbon dioxide. Their complex fluid flow behaviour during production has traditionally proved difficult to predict, causing a large degree of uncertainty in reservoir development. The applied study of naturally fractured reservoirs seeks to constrain this uncertainty and maximize production by developing new understanding, and is necessarily a broad, integrated, interdisciplinary topic. Some of the methods, challenges and advances in characterizing the interplay of rock matrix and fracture networks relevant to fluid flow and hydrocarbon recovery are reviewed and discussed via the contributions in this volume.

Abstract The Mesaverde Group, Uinta Basin, Utah is the source of current significant natural gas production and contains several trillion cubic feet of undiscovered natural gas resources. To evaluate and model the potential connectivity of hydraulically induced fractures to natural fractures in the subsurface, the natural fracture network was examined using scanline sampling, image and well logs, core and microstructural analyses. Regional fracture sets include subvertical fractures with dominant orientations of: north–south (006–015°), NE (045–059°), NNW (326–342°) and a WNW (271–286°). Sedimentologic and diagenetic characteristics of seven sandstone lithofacies control the fracture development and distribution in the group. Key sedimentologic and diagenetic influences on fracture distribution include bed thickness, stratigraphic architecture, the degree of cementation and the type of cement. From these sedimentologic controls on the character of natural fractures, lithofacies can potentially predict fracture distribution within the Mesaverde Group based on environments of deposition. The presence of NW-trending discontinuous sandstone reservoirs deposited in meandering fluvial environments that are highly fractured by a pervasive WNW-striking fracture set helps to explain fairways of prolific natural gas production within the basin.

Abstract In this study, fracture systems developed within faulted, high-porosity sandstones in the decommissioned mines of Alderley Edge, Cheshire, UK are characterized using lidar (Light Detection And Ranging)-based analysis. The geometry of the mine workings prove to be conducive to the extraction of fracture attributes, whilst providing a degree of exposure of a notable Triassic-aged reservoir outcrop analogue (Helsby Sandstone Formation) not afforded at the surface. To test the fidelity of the approach, fracture statistics generated from lidar-derived digital outcrop models are compared to an equivalent dataset collected using conventional manual surveys, with digital outcrop and manually acquired fracture attributes used to populate discrete fracture network models. These are upscaled to provide equivalent porous medium properties, enabling the impact of uncertainties introduced into fracture modelling workflows by lidar-based techniques to be assessed. Whilst broadly comparable to fracture attributes obtained using manual surveys, the systematic underrepresentation of fracture properties is observed within lidar-derived dataset, resulting in the underestimation of fracture network flow capacity. The study results suggest that, whilst enhancing data acquisition rates and coverage of exposure surfaces, the use of digital discontinuity analysis may introduce additional biases into fracture datasets, increasing the level of uncertainty within resultant modelled networks.

Abstract A field study focusing on fracture systems in a fault linkage zone from the Suez Rift, Egypt, is presented to elucidate the role of fault linkage zones in the permeability structure of segmented normal faults in tight carbonate rocks. Fracture systems in the linking damage zone show significantly increased structural complexity compared to that typical of isolated faults. The linkage zone is characterized by high fracture frequencies and multiple fracture sets of different orientations. Notably, pervasive fracture corridors strike at high angles to the fault trend and are interpreted to have formed during the latest evolutionary stages of what is interpreted as a breached relay. The structural observations indicate that along segmented normal faults in carbonate rocks, fault linkage zones represents locations of progressively increased cross- and along-fault permeability through the stages of relay growth and breaching. Our findings, in combination with previously published work, indicate that fault linkage zones represent localized conduits not only for increased fluid flow across faults, but also (vertically) within fault zones. Appreciating this has wide-ranging implications for understanding fluid transport in carbonate rocks and other naturally fractured lithologies.

Abstract Fractured carbonate reservoirs, characterized by high structural porosity/permeability, are of great economic importance because in such systems a single well can access large volumes of easily migrating hydrocarbons. Therefore, the accurate quantification of fracture density and connectivity values within a reservoir can be an important input for reservoir models and field development plans. However, a large number of the fractures that are present in a field are smaller than the resolution of most industry standards methods. In this paper we use two independent methods to quantify small-scale fracture density and connectivity, such as two-dimensional image analysis of slabbed cores and rubble-size measurements.

Abstract This paper reviews aspects of the procedures for characterizing rock masses from outcrop mapping and core logging. It is argued that current definitions of discontinuities and joints are too simple and too coarse to deal adequately with the range of geological features that are found in the field and that range from open fractures through to incipient joint traces. A generic approach is proposed that differentiates between discontinuities on the basis of relative tensile strength compared to the intact parent rock. Examples are provided of how fracture frequency and extent vary with degree of weathering and erosion, and it is suggested that the concept of dynamic development of geological discontinuities needs to be appreciated by geotechnical engineers and structural geologists when analysing fracture networks. This concept has major implications for the use of rock mass classifications to zone the rock mass into engineering units.

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 Flow responses in fractured reservoirs are difficult to predict. Apparent success in predicting flow has been achieved by developing simple rules of thumb based on (i) alterations of effective stress associated with pore pressure changes or (ii) concepts about fracture aperture alterations due to stress changes. Here it is argued that the assumptions underlying these explanations of flow are flawed, as they are based on ideas about stress that are physically wrong. It may be that these simple ideas can be fitted to some observations, but their use in this fashion is highly risky. The role of geomechanics in fractured reservoirs is more complex than suggested by the simple rules of thumb, as illustrated by numerical simulations that demonstrate the occurrence of strong non-linear interactions between the fluids, the geomechanics of blocky systems, and thermal changes. The resulting movements within fractured rock masses can cause major alterations of the upscaled flow properties. Flow performance discrepancies that are often associated with the operation of fractured reservoirs can, and often should, be seen as a consequence of motions occurring within the fractured rock mass. The explanations developed here are phenomenologically correct, and are more holistic than existing simple rules of thumb, improving the reliability of predictions.

Abstract The hydraulic conductivities of faults and fractures in reservoirs can be influenced by geomechanical perturbations due to production operations. It is anticipated that such dynamic permeabilities will be manifest as changes in flowrates at production and injection wells. Statistical correlations in flowrate fluctuations between wells from fields in the North Sea appear to bear out this expectation; they are characterized by high correlations over very large separation distances between wells, and appear to be stress-related and fault-related. This paper discusses possible geomechanical mechanisms that might explain orientational characteristics of correlations relative to stress state: (1) creation of new Andersonian, bimodal faults; (2) shear slip on pre-existing structural features according to slip tendencies; (3) polymodal faulting more consistent with three-dimensional strain; and (4) dilatation or compaction of aligned compliant (micro-)fractures at near-critical densities arranged in en echelon patterns. Mechanism 4 is currently preferred in that it is consistent with: (a) established theory of the nucleation of shear failure; (b) interpretations of widespread microfractures in the lithosphere from observations of shear-wave splitting; (c) (as shown in this paper) the observed frequencies of directionalities in oilfield flooding schemes, an independent empirical feature of production data.

Abstract It is well established that compaction bands (CBs), joints and faults are often present in the same rock volume in the Jurassic aeolian Aztec Sandstone, exposed in the Valley of Fire State Park, Nevada, USA. Because the permeability of CBs can be one or more orders of magnitude less than the matrix permeability, and joint permeability, depending on its aperture, can be several orders of magnitude greater than matrix permeability, the combined effect of these structures on subsurface flow can be complex and substantial. In this study, we investigate the effects of a variety of intersecting geological structures on fluid flow. This is accomplished by performing two- (2D) and three-dimensional (3D) permeability upscaling and waterflood simulations over areas/volumes populated by hydraulically interacting geological features. The regions considered are approximately the size of typical grid blocks used for reservoir or aquifer flow simulations, so the results are of practical interest. The systems studied include models with two sets of vertical CBs intersecting at various angles, an inclined CB set intersecting a vertical CB set, a joint set intersecting a CB set at various angles, and a small fault and its damage zone overprinting a CB set. Our numerical results quantify the impact of these composite structures on subsurface flow and show, for example, that the intersection angle of two sets of structures can have a considerable effect on the upscaled directional permeability. In addition, waterflood simulations demonstrate that the efficiency of oil recovery can be significantly impacted by the direction of flow relative to the orientation of intersecting geological structures.

Abstract Natural fractures control primary fluid flow in low-matrix-permeability carbonate hydrocarbon reservoirs, making it important to understand the factors that affect natural fracture distributions and networks. Away from the influence of folds and faults, stratigraphic controls are accepted to be the major control on fracture networks. The influence of carbonate nodular chert rhythmite successions on natural fracture networks is investigated here using a Discrete Element Modelling (DEM) technique that draws on outcrop observations of naturally fractured carbonates in the Eocene Thebes Formation, exposed in the west central Sinai of Egypt, that also form reservoir rocks in the subsurface. Stratally-bound chert nodules below bedding surfaces create lateral heterogeneities that vary over short distances. The resulting distribution of physical properties (differing stiffnesses) caused by chert rhythmites is shown to generate extra complexity in natural fracture networks in addition to that caused by bed thickness and lithological physical properties. Chert rhythmite successions need to be considered as a distinct type of carbonate fractured reservoir. Stratigraphic rules for predicting the distribution, lengths and spacing of natural fractures, and quantitative fracture indices ( P 11 , P 21 , P 22 and fractal dimension) are generated from the DEM outcomes. In a less-stiff carbonate medium, the presence of chert nodules reduces fracture intensity at chert horizons, and fractures per unit area are higher in chert-free vertical corridors. In a stiff carbonate medium, chert has little influence on fracture development. In a peritidal cyclic succession with constant layer thicknesses, the presence of chert in less-stiff carbonate horizons results in a reduction in fracture intensity. When chert is introduced in a subtidal cyclic sequence with constant layer thicknesses, it has little effect on fracture distribution. The study has widespread significance for characterizing naturally fractured reservoirs containing carbonate nodular chert rhythmites.

Abstract Sills are common in sedimentary basins and, through thermal effects, may contribute significantly to the transformation of organic material into oil and gas. In addition, many sills act as hydrocarbon reservoirs, either as seals or as fractured reservoirs themselves. The seals are related to glassy margins and/or low permeable metamorphosed host rocks at the contacts between the sills and their host rocks. Reservoir formation may then be encouraged at sill-fault or sill-dyke contacts, provided the dykes/faults have low permeabilities. If the seal at the lower margin of a sill is ruptured (because of changes in tectonic loading) while the seal at the upper margin is maintained, the sill may itself act as a fractured hydrocarbon reservoir. Major sills in sedimentary basins are mostly c. 15–150 m thick and are mostly fed by (much thinner) dykes. Deflection of dykes into sills is primarily due to three related factors: (1) opening of contacts ahead of the feeder dyke (the ‘Cook–Gordon debonding’); (2) dykes meeting layers with local stresses unfavourable to dykes but favourable to sills (‘stress barriers’); and (3) abrupt increase in Young’s modulus (‘elastic mismatch’) across a contact. Theoretical models predict common lateral dimension/maximum thickness (aspect) ratios of sills between 150 and 500, in agreement with actual measurements of sill dimensions. Many thick sills worldwide are currently exploited as hydrocarbon reservoirs.

Abstract In the oil industry, complex workflow is used to match or predict fluid production. The large uncertainty of the data can lead to large variability of the simulation results, notably because of the strongly heterogeneous nature of fluid flows. The particular case of naturally fractured reservoirs is well known to be especially difficult to match. This paper presents a method to improve an initial geological analysis, carried out in 2008, through the integration of hydrodynamic data in the fractured reservoir model. Dynamic data such as production information, production logging tools and well tests are used to determine fractures properties by calibrating the fluid flow or reservoir pressure measured at wells. The approach, applied to a real field case, respects both the statistical geological analysis and the dynamic analysis of the production history. Using this methodology the geological structural model based on static characterization are preserved and available. In the study we analysed uncertainties and, in respecting the initial geological model, we prove the presence of compartmentalization in the reservoir by matching 1 year of production and three well tests. Both analytical and numerical flow simulations were used at different scales for time and space: near the well and on the whole reservoir.

Abstract This case study of ten oil wells drilled into highly fractured and heterogeneous crystalline basement rocks of the Bayoot Field, Say’un Masila Basin, Yemen, brings together the findings from a wealth of oil field data and shows that a multidisciplinary approach is required for full characterization. An improved method for targeting hydrocarbons has been established for the study area. This has been achieved by drilling highly deviated wellbores into the upper basement reaches and optimally orienting them to intersect a maximum number of stress-sensitive fractures together with major seismic-scale fault damage zones that are not in direct connection to the local Bayoot Fault.

Abstract Three exploration wells drilled in the West of Shetlands targeted crystalline Lewisian Basement as the primary reservoir. The objective of these wells was to demonstrate the presence of movable oil in basement and the viability of fault zones within the Lewisian Basement as an exploration target. Lewisian Basement reservoir properties were defined pre-drill through a combination of fieldwork, offset well data, global basement analogues and detailed 3D seismic interpretation. Dip, azimuth and similarity attributes were analysed within the 3D seismic volume in order to delineate the fault network, complimenting manual fault interpretation. Once the fault network had been defined, two fault zones were chosen as a reservoir target for an inclined basement well, based on their length and location within the reservoir. After drilling over a kilometre of basement across three wells, significant understanding has been gained of the basement reservoir. The comprehensive suites of log data obtained from the wells have allowed some leading edge techniques to be used to bridge the gap between wellbore data and seismic data, with fault zones identified from log data tying to fault zones that had been interpreted using seismic data. The well results have been used to feed back into the predicted fault model to increase the number of mapped faults and to constrain rock properties including lithology and fracture frequency. This paper summarizes the above process and provides specific details regarding the seismic characterization of the fault network.

Abstract The East Ras Budran Concession is located in the eastern rift shoulder of the Gulf of Suez. Syn- and pre-rift rocks are exposed in the north and east of the concession, and the Markha alluvial plain covers the SW. The Markha plain occupies the hanging wall of a large extensional fault which preserves most of the pre-rift stratigraphic sequence and >3500 m of syn-rift strata. Vertical wells drilled in 1999 indicated the presence of a >200 m oil column in low-porosity naturally fractured limestone beds of the Eocene Darat and Thebes formations. Outcrop, borehole image and core data define NW, WNW, N, NE, and ENE steeply dipping fracture sets. Borehole breakouts and drilling-induced fractures show that the minimum horizontal stress is aligned NNE to NE, so the NW and WNW fractures should be open in the subsurface. Using this structural picture, a near-horizontal well of 300 m length was drilled into the Darat in a NE direction. During testing, the well flowed at a rate of 1900 barrels of oil per day with no water. Future development of the field includes drilling similarly oriented wells with longer horizontal sections.

Abstract The Machar Field in the UK Central North Sea is a fractured Cretaceous chalk and Palaeocene sandstone oil reservoir, developed around a tall salt diapir. Machar was discovered in 1976 and, after a lengthy appraisal including extended flow tests starting in 1994, has been developed in a phased manner from 1998 through a multi-well subsea development. The steeper eastern flank has historically lacked coherent reflectivity on seismic data and has remained undrilled. The geological possibility of a reservoir on the east flank provided motivation for extensive seismic reprocessing between 2005 and 2007, and the seismic interpretation showed both a chalk and a sand presence in this area of the field. Simulation modelling suggested that a well here would deliver substantial incremental field volumes. Confidence in the new seismic interpretation reduced the subsurface risk associated with the area, and a new subsea drill-centre reduced the drilling risks and costs sufficiently to allow a Machar East well to be sanctioned. Successful well results in 2008 changed the entire perception of the field and acted as a springboard for further development including a sidetrack in the northern area and a third injection well to support the east, which was drilled and completed in the summer of 2010.