The completion strategy and hydraulic fracture stimulation are the keys to economic success in unconventional reservoirs. Therefore, reservoir engineering workflows in unconventional reservoirs need to focus on completion and stimulation optimization as much as they do well placement and spacing. This well-level focus requires the integration of hydraulic fracture modeling software and the ability to utilize measurements specific to unconventional reservoirs. This paper details a comprehensive integration of software, data, and specialized measurements specific to unconventional reservoirs that allows efficient full-cycle seismic-to-simulation evaluations.It is very important to properly model hydraulic fracture propagation and hydrocarbon production mechanisms in unconventional reservoirs, a significant departure from conventional reservoir simulation workflows. Seismic-to-simulation workflows in unconventional reservoirs require hydraulic fracture models that properly simulate complex fracture propagation which is common in many unconventional reservoirs, algorithms to automatically develop discrete reservoir simulation grids to rigorously model the hydrocarbon production from complex hydraulic fractures, and the ability to efficiently integrate microseismic measurements with geological and geophysical data. The introduction of complex hydraulic fracture propagation models now allows these work-flows to be implemented. This paper documents an efficient, yet rigorous, integration of geological and geophysical data with complex fracture models, single-well completion and stimulation focused reservoir simulation, and microseismic measurements. The implementation of a common software platform and the development of specialized gridding algorithms allow complex hydraulic fracture models to be calibrated using microseismic measurements in the context of local geology and structure. The complex hydraulic fracture geometry, including the distribution of proppant, is automatically gridded to a common Earth Model for single-well reservoir simulation. The software platform, newly developed complex hydraulic fracture models, and automated gridding algorithms are illustrated in a case history from the Barnett Shale unconventional gas play.

Abstract. Fractures are common features of many well-known reservoirs. Naturally Fracture Reservoirs (NFR) consist of fractures in igneous, matamorphic, and swedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones and are connected to numerous fractures with varying conductivities. In many NFRs, faults and fractures frequently have discrete distributions rather than connected fracture networks. Because fractures are often created by faulting, faults and fractures should be modeled together. Accurately modeling naturally fractured reservoir pressure transient behavior is important in hydrogeology, the earth sciences, and petroleum engineering, including ground-water contamination to shale gas and oil reservoirs. For more than 50 years, conventional dual-porosity type models, which do not include any fractures, have been used for modelling fluid flow in naturally fractured reservoirs and aquifers. They have been continuously modified to add unphysical matrix block properties such as the matrix skin factor. In general, fractured reservoirs are heterogeneous at different length scales. It is clear that even with millions of grid blocks, numerical models may not be capable of accurately stimulating the pressure transient behavior of continuously and discretely NFRs containing variable conductivity fractures. The conventional dual-porosity type models are obviously an oversimplification; their serious limitations and consequent implications for interpreting well test data from NFRs are discussed in detail. These models do not include wellbore-intersecting fractures, even though they dominate the pressure behavior of NFRs for a considerable length of testing time. Fracture conductivities of one to infinity dominate transient behavior of both continuously and discretely fractured reservoirs, but again dual-porosity models do not contain a single fracture. Our fractured reservoir model is capable of treating thousands of fractures that are perdiocially or arbitrarily distributed with finite- and/or infinite-conductivities, different lengths, densities, and orientations. Appropriate inner boundary conditions are used to account for wellbore-intersecting fractures and direct wellbore contributions to production. Wellbore storage and skin efffects in bounded and unbounded systems are included in the model. Three types of damaged skin factors that may exist in wellbore-intersecting fracture(s) are specified. With this highly accurate model, the pressure transient behavior of conventional dual-porosity type models are investigated, and their limitations and range of applicabilities are identified. The behavior of the triple-porosity models are also investigated. It is very unlikely that triple-porosity behaviorf is due to the local variability of matrix properties at the microscopic level. Rather, it is due to the spatial variability of conductivity, length, density, and orientation of the fracture distributions. Finally, we have presented an interpretation of a field buildup test example from an NFR using both conventional dual-porosity models and our fractured reservoir model.

Summary Fractures are common features of many well-known reservoirs. Naturally fractured reservoirs (NFRs) consist of fractures in igneous, metamorphic, and sedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones and are connected to numerous fractures with varying conductivities. In many NFRs, faults and fractures frequently have discrete distributions rather than connected-fracture networks. Because faulting often creates fractures, faults and fractures should be modeled together. Accurately modeling NFR pressure-transient behavior is important in hydrogeology, the earth sciences, and petroleum engineering, including groundwater contamination to shale gas and oil reservoirs. For more than 50 years, conventional dual-porosity-type models, which do not include any fractures, have been used for modeling fluid flow in NFRs and aquifers. They have been continuously modified to add unphysical matrix-block properties such as matrix skin factor. In general, fractured reservoirs are heterogeneous at different length scales. It is clear that even with millions of gridblocks, numerical models may not be capable of accurately simulating the pressure-transient behavior of continuously and discretely NFRs containing variable-conductivity fractures. The conventional dual-porosity-type models are obviously an oversimplification; their serious limitations for interpreting well-test data from NFRs are discussed in detail. These models do not include wellbore-intersecting fractures, even though they dominate the pressure behavior of NFRs for a considerable length of testing time. Fracture conductivities of unity to infinity dominate transient behavior of both continuously and discretely fractured reservoirs, but again, dual-porosity models do not contain any fractures. Our fractured-reservoir model is capable of treating thousands of fractures that are periodically or arbitrarily distributed with finite- and/or infinite conductivities, different lengths, densities, and orientations. Appropriate inner-boundary conditions are used to account for wellbore-intersecting fractures and direct wellbore contributions to production. Wellbore-storage and skin effects in bounded and unbounded systems are included in the model. Three types of damaged-skin factors that may exist in wellbore-intersecting fracture(s) are specified. With this highly accurate model, the pressure-transient behavior of conventional dual-porosity-type models are investigated, and their limitations and range of applicability are identified. The behavior of the triple-porosity models is also investigated. It is very unlikely that triple-porosity behavior is caused by the local variability of matrix properties at the microscopic level. Rather, it is caused by the spatial variability of conductivity, length, density, and orientation of the fracture distributions. Finally, we have presented an interpretation of a field-buildup-test example from an NFR by use of both conventional dual-porosity models and our fractured-reservoir model. A substantial part of this paper is a review and discussion of the earlier work on NFRs, including the authors’ work.

Forecasting production rates and reserves is important for reservoir management. Analysis of long-term production data has traditionally been performed using the empirical Arps (1945) decline curves to predict future production. Fetkovich (1980) combined Arps decline curves with constant-wellbore pressure solutions to offer a new method for decline-curve analysis. Furthermore, both rate-transient and declinecurve analyses for naturally fractured reservoirs were performed using Arps (1945) decline curves or Warren and Root (1963) dual-porosity-type models. These approaches have yielded unsatisfactory results for naturally fractured reservoirs. Recent studies show that the Warren and Root (1963) dual-porosity-type models, which do not contain fractures, cannot characterize highly diverse transient behaviors of continuously and discretely fractured reservoirs because they are inappropriate and incomplete for most naturally fractured reservoirs. Furthermore, no investigation has been performed on rate-transient behavior of discretely fractured reservoirs.We investigate rate-transient behavior of continuously (dual-porosity) and discretely naturally fractured reservoirs using semianalytical solutions. These fractured reservoirs can contain periodically or arbitrarily distributed finite-and/or infinite-conductivity fractures, of different lengths and orientations. Our results demonstrate that, in terms of rate transients, neither continuously nor discretely fractured reservoirs behave like the Warren and Root (1963) dual-porosity type model. There are many factors that dominate the rate-transient behavior of naturally fractured reservoirs, such as fracture conductivities, dip angles, lengths, and distributions, as well as whether or not fractures intersect the wellbore. Rate transients associated with these factors are shown for a few continuously and discretely fractured reservoirs with different well and fracture configurations.The inverse of the dimensionless pressure (p D ) is not a good approximation for the dimensionless rate (q D ), but for most cases, their derivatives behave similarly, and exhibit same or similar flow regimes. For some cases, they behave very differently. The similarities or variations are true for any type of reservoirs. For any reservoir, Arps' decline curves yield unreasonably high production rates and cumulative productions, except the exponential decline curve. The exponential decline curve should not be used without taking into account the change of the wellbore pressure as a function of time. Arps' decline curves analysis should not be used for both discretely and continuously fractured reservoirs. An integrated interpretation methodology is outlined for rate transient analysis in fractured reservoirs.A few examples for the rate transient behavior of the continuously and discretely fractured fractured reservoirs are presented. They exhibit different flow regimes depending on fracture distribution, intensity, and conductivity. We also compare the rate transient derivatives with pressure...

Naturally fractured reservoirs consist of fractures in igneous, metamorphic, and sedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones and are connected to numerous fractures with varying conductivities. In many naturally fractured reservoirs, faults and fractures can be discrete (rather than a connected network dual-porosity system). To accurately model pressure transient behavior of fractured reservoirs is important to gas and oil reservoirs.