This issue of SPE Reservoir Evaluation and Engineering brings you 14 papers covering topics of current interest in the industry. Four papers focus on topics related to reservoir simulation, reserve estimation, and reservoir management. Five papers deal with various aspects of shale reservoirs, including controls on fluid flow, imbibition, and elastic anisotropy. Another three papers deal with topics related to reservoir characterization and natural fractures. The final two papers are related to hydraulic fracture stimulation and flowback.
The Use of Reservoir Simulation in Deterministic Proved-Reserves Estimation proposes an approach for assessing a reservoir-simulation model for use in estimating reserves. A simulation model can integrate complex static data, the physical description of displacement processes, production constraints, and schedules. Hence, it can provide important information for business decisions and reserves estimation. Confidence in simulation predictions depends on the strength of evidence for the input data, quality control of the model, robustness of the history match, and whether there is independent evidence supporting predictions. The approach can be used with different available data and at different stages of field life. It is illustrated through a case study that shows how the principles may be applied.
Geostatistical simulation is performed for reservoir characterization to depict local variability in the modeled properties. Conventional simulation methods are implemented in a grid-dependent manner that makes regridding of realizations, refinement of existing grids, and the simulation on irregular grids challenging. A new grid-free geostatistical simulation (GFS) method was developed recently that can be used in petroleum reservoir characterization for construction of models of various node configurations and densities. Application of Grid-Free Geostatistical Simulation to a Large Oil-Sands Reservoir demonstrates the practical application of GFS to a large oil-sands reservoir in northern Alberta, Canada, and shows that the GFS method has significant potential to be applied extensively in the practice of petroleum reservoir characterization.
A Novel Enhanced-Oil-Recovery Screening Approach Based on Bayesian Clustering and Principal-Component Analysis presents and tests a new screening methodology to discriminate among alternative and competing enhanced-oil-recovery (EOR) techniques to be considered for a given reservoir. The approach relies on grouping of fields into clusters through Bayesian hierarchical clustering and computation of suitable Euclidean distances between fields belonging to the same cluster. These approaches are highly compatible and conducive to an effective screening.
Time-Lapse Seismic for Reservoir Management: Case Studies From Offshore Niger Delta, Nigeria presents case studies focused on the interpretation and integration of seismic reservoir monitoring from several fields in conventional offshore and deepwater Niger Delta fields. Case studies integrate reservoir elastic models, seismic forward modeling, and inversion-based seismic warping to interpret 4D responses and demonstrate the use of seismic monitoring to address model uncertainties and to optimize reservoir-development strategies.
A geological challenge in the Eagle Ford shale is the understanding of fluids distribution over geologic time. By constructing a conceptual cross-sectional compositional simulation model, the history of fluid migration, fluid distribution, and fluid contacts throughout 1 million years were investigated in Factors Controlling Fluid Migration and Distribution in the Eagle Ford Shale. The controlling parameters studied were porosity, permeability, pore-throat aperture, and spacing between natural fractures. Results show that fluids in the matrix remained with approximately the same dry-gas/condensate contact and approximately the same condensate/oil contact, but with some gas migration through natural fractures to the top of the structure. This migration is interpreted to be responsible for higher initial gas production in some oil wells.
Nanopore Compositional Modeling in Unconventional Shale Reservoirs shows an association of flow units and different scales of pore apertures for improving recovery of liquids from shale reservoirs. Using data from the Niobrara and Eagle Ford shales, the study demonstrates how the smaller pores and their associated dry gas can be recognized with the use of process speed (flow units) and modified Pickett plots. A positive aspect of smaller pores is that, under favorable conditions, they can lead to larger economic benefits from organic-rich shale reservoirs. This occurs in the case of condensate fluids that behave as dry gas in the smaller pores of organic-rich shale reservoirs. Flow of this dry gas diminishes the amount of liquids that are released and lost permanently in a shale reservoir. Conversely, this dry gas can lead to larger recovery of liquids in the surface from a given shale reservoir and consequently more-attractive economics. A result is that there is significant practical potential in the use of process speed as part of the flow-unit characterization of shale condensate reservoirs. This, in turn, can help in locating sweet spots for improved liquid production.
Characterization of Elastic Anisotropy in Eagle Ford Shale: Impact of Heterogeneity and Measurement Scale reports measurements of the elastic properties of the Eagle Ford shale at various measurement scales. The paper also discusses the role of heterogeneity in laboratory testing of shale reservoirs.
Scaling Laboratory-Data Surfactant-Imbibition Rates to the Field in Fractured-Shale Formations investigates the use of surfactant imbibition to enhance oil recovery from oil shale or other tight rocks. By use of existing methods, typical oil-recovery factors from the Bakken and other shale formations are low, typically less than 5% of original oil in place (OOIP). This paper uses analytical models to scale laboratory surfactant-imbibition rates to the field. Calculations of available fracture area, assuming typical horizontal well lengths and transverse-induced-fracture spacing in typical Bakken wells, coupled with imbibition, to estimate oil-recovery rates in a field setting suggest that surfactant imbibition will generally not proceed more than a few meters into the low-permeability rock; insufficient fracture area is available to provide a viable imbibition process if only the induced-fracture area is considered. However, recent results suggest considerably greater area associated with natural microfractures in these target formations. When the increased area suggested by the presence of natural microfractures is included in the analyses, the surfactant-imbibition process appears quite promising.
Recent work has shown that flow units characterized by process or delivery speed—the ratio of permeability to porosity—provide a continuum between conventional, tight-gas, shale-gas, tight-oil, and shale-oil reservoirs. Flow Units in Shale Condensate Reservoirs uses flow units to recognize characteristic phase envelopes associated with pores of different sizes in shale condensate reservoirs.
Risk of uneconomical wells in unconventional reservoirs is high, partly because of uncertainty about rock properties (e.g., permeability, porosity, pore-throat aperture, fracture intensity, and characteristics of those fractures). Using the Monteith formation, an important tight-gas reservoir in Alberta, as an example, Integrated Reservoir Characterization and 3D Modeling of the Monteith Formation: A Case Study of Tight Gas Sandstones in the Western Canada Sedimentary Basin, Alberta, Canada shows how a multiscale description and characterization with cores and drill cuttings can be used to help construct a numerical 3D model to history match gas production and forecast performance of new wells in those areas where the geologic model indicates potential for gas production.
Prediction of extremely low permeability in tight reservoirs poses major challenges with traditional methods. A New Approach for Permeability Prediction With NMR Measurements in Tight Formations describes a new nuclear-magnetic-resonance (NMR) well-log interpretation method, which decomposes the log10(T2) spectrum from the NMR well log into at most three Gaussian components. A pore-size related model with these parameters helps to relate permeability measurements that have different scales and resolutions. Furthermore, one can use these parameters to modify the Timur-Coates equation model and greatly increase its accuracy in tight formations to predict permeability.
Estimation of effective fracture-network permeability is an essential part of modeling transport processes in naturally fractured reservoirs. A practical method is to use correlations that consider fracture network statistical and physical characteristics. A Critical Analysis of the Relationship Between Statistical- and Fractal-Fracture-Network Characteristics and Effective Fracture-Network Permeability explores fractal-based correlations to clarify the physical relationship among network properties and the correlation parameters. It was shown that the connectivity index is a more-powerful parameter to rely on in permeability estimation, especially at percolation ranges far from the threshold.
Water leakoff into the shale matrix during the hydraulic-fracture treatment has been a critical issue in determining fracture geometry. It also affects mechanical properties of the surrounding rock matrix which, in turn, affects fracture propagation. Here, factors controlling leakoff are considered in a physics-based model. Investigation of Water Leakoff Considering the Component Variation and Gas Entrapment in Shale During Hydraulic-Fracturing Stimulation emphasizes the significance of osmotic and capillary effects as well as gas entrapment on hydraulic-fracturing treatment of shale-gas reservoirs.
Less than half the fracturing fluid is typically recovered during the flowback operation. Numerical Investigation of Coupling Multiphase Flow and Geomechanical Effects on Water Loss During Hydraulic-Fracturing Flowback Operation models the effects of capillarity and geomechanics on water loss in the fracture/matrix system, and investigates the circumstances under which this phenomenon might be beneficial or detrimental to subsequent tight-oil production. Results highlight the crucial interplay between imbibition and geomechanics in short- and long-term production performances.
Stephen E. Laubach
Co-Executive Editor, SPE REE