During hydraulic-fracturing operations in low-permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix is believed to have a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may affect the post-fracturing productivity of the well. However, there is lack of direct experimental and visual evidence of the extent of fluid retention, evolution of the resulting imbibing-fluid front, and how they relate to potential productivity hindrance. In this paper, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leakoff is monitored as a function of space and time by use of X-ray computed tomography (CT). The X-ray CT imaging technique allows us to map saturations at controlled time intervals to monitor the migration of fracturing fluid into the reservoir formation. It is generally expected for low-permeability formations (5 to 10 md) to show strong capillary forces because of their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in low-permeability sands. The relevance of capillarity as a driver of fluid migration and retention in a low-permeability sand sample is interpreted visually and quantified and compared with high-permeability Berea sandstone in our experiments. It is seen that although low-permeability sands are subject to strong capillary forces, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. Nevertheless, saturation values attained as a result of spontaneous imbibition are comparable with those obtained for high-permeability samples. Leakoff of fracturing fluids during the shut-in period of a well can result in delayed gas flowback and can hinder gas production. Results from this investigation are expected to provide fundamental insight regarding critical variables affecting the retention and migration of water-based fracturing fluids in the neighborhood of hydraulic fractures, and consequently affecting the post-fracturing productivity of the well.

During hydraulic fracturing operations in low permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix may be responsible for having a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may consequently affect the post-frac productivity of the well. However, there is lack of direct quantitative and visual evidence of the extent of retention, evolution of the resulting imbibing fluid front, and how they relate to potential productivity hindrance. In this paper, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leak-off is monitored as a function of space and time using X-ray computed tomography (CT). The X-ray CT imaging technique allows us to map saturations at controlled time intervals to monitor the migration of fracturing fluid into the reservoir formation. It is generally expected for low permeability formations to show strong capillary forces due to their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in tight gas sands. The relevance of capillarity as a driver of fluid migration and retention in a tight gas sand sample is interpreted visually, quantified and compared with high permeability Berea sandstone in our experiments. It is seen that although these formations demonstrate strong capillarity, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. However, saturation values attained during imbibition experiments are comparable to those previously obtained for high permeability samples, which can have significant implications in terms of phase mobilities in the neighborhood of induced fractures. Results from this investigation are expected to provide fundamental insight regarding critical variables affecting the retention and migration of water-based fracturing fluids in the neighborhood of hydraulic fractures, and consequently on the post-frac productivity of the well.

Unconventional plays have moved to the forefront of the energy industry in the U.S. over the last five years due to advancements in technology and the overall abundance of producible hydrocarbons discovered near existing infrastructure. In the present economic climate, there is an increased interest in liquid rich plays, and because of the relatively limited historical production data available for these resources, there is a lot of industry discussion regarding future decline performance and estimated ultimate recovery (EUR) per well. The objective of this paper is to discuss the uncertainty associated with estimating reserves in U.S. unconventional plays using common decline curve analysis (DCA) methods in comparison to analytical modeling. Broadly speaking, there are five common methods for estimating: use of analogs, volumetric analysis combined with an estimate of recovery efficiency, decline curve analysis (DCA), analytical models and numerical simulation. Among theaforementioneds, DCA is the simplest and often fastest way to estimate volumes. However, the theoretical basis for most DCA approaches does not apply to unconventional reservoirs, which introduces some uncertainty into estimation of volumes. Nevertheless, it is commonly applied because of its perceived simplicity. Different unconventional DCA methods were compared with results of an analytical model generated using commercial software: the power law model (PLE), the logistic growth model (LGM), and Duong's method. The analysis was performed on various unconventional plays based on reservoir type and well geometry. All historical production data is gathered from public documents. The application of the DCA methods was also extended to various fluid types to determine their suitability for application in oil as well as gas reservoirs. The results of the study show that comparing multiple DCA methods with an analytical model aids in the understanding of the range of uncertainty associated with the EUR of unconventional wells. The study also helps establish the most appropriate DCA methods for various reservoir types, well geometry, and fluid types. The results also suggest approaches for avoiding violating the SEC's guidelines for categorizing proven reserves.

During hydraulic fracturing operations in low permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix may be responsible for having a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may consequently affect the post-frac productivity of the well. However, there is lack of direct quantitative and visual evidence of the extent of retention, evolution of the resulting imbibing fluid front, and how they relate to potential productivity hindrance. In this paper, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leak-off is monitored as a function of space and time using X-ray computed tomography (CT). The X-ray CT imaging technique allows us to map saturations at controlled time intervals to monitor the migration of fracturing fluid into the reservoir formation. It is generally expected for low permeability formations to show strong capillary forces due to their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in tight gas sands. The relevance of capillarity as a driver of fluid migration and retention in a tight gas sand sample is interpreted visually, quantified and compared with high permeability Berea sandstone in our experiments. It is seen that although these formations demonstrate strong capillarity, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. However, saturation values attained during imbibition experiments are comparable to those previously obtained for high permeability samples, which can have significant implications in terms of phase mobilities in the neighborhood of induced fractures. Results from this investigation are expected to provide fundamental insight regarding critical variables affecting the retention and migration of water-based fracturing fluids in the neighborhood of hydraulic fractures, and consequently on the post-frac productivity of the well.

The prediction of Estimated Ultimate Recovery (EUR) for a well or group of wells in a development project is critical to accurate reserves estimation. A number of techniques, many of which can be used deterministically or probabilistically, are employed in EUR prediction in mature and maturing unconventional gas and oil plays in North America. These include the use of geological and production data from analogous reservoirs, the use of volumetric methods and recovery factors, analytical models, numerical reservoir simulation and production decline curve analysis (DCA). Decline curve analysis is arguably the most commonly used method for forecasting reserves in unconventional reservoirs. This paper discusses its basic theory and application, together with the potential pitfalls of using simple empirical production forecasting methods in complex reservoirs. We analyse production data from several US unconventional oil and gas plays and carry out production forecasting using the traditional Arps' methods as a basis for comparison, and newer empirical solutions including the Power Law, Stretched Exponential Decline Model, Duong (and variations thereof). The range of production forecasts provided by these methods is examined, together with methodologies for developing statistically valid type wells in unconventional plays, and how best to determine valid input parameters for the various empirical solutions. The effect of the variable length of production history available in the various plays, and how it impacts the accuracy of the forecasts is also examined. The results of the analyses are compared with analytical models developed for each play to determine the suitability of each decline curve analysis method: in which plays and under which circumstances they can be applied, and suggest reasonable input parameters and data requirements for each method. Finally, the potential future use of the methods in emerging plays outside of North America is presented.