In recent years, new fracturing designs and techniques have been developed to enhance production of trapped hydrocarbons. The new techniques focus on reducing stress contrast during fracture propagation while enhancing far field complexity and maximizing the stimulated reservoir volume. Zipper frac is one of these techniques, which involves simultaneous stimulation of two parallel horizontal wells from toe to heel. In this technique, created fractures in each cluster propagate toward each other so that the induced stresses near the tips force fracture propagation to a direction perpendicular to the main fracture. The effectiveness of zipper frac has been approved by the industry; however, the treatment's optimization is still under discussion. In this paper, we present a new design to optimize fracturing of two laterals from both rock mechanic and fluid production aspects. The new design is a modification to zipper frac, where fractures are initiated in a staggered pattern. The effect of well spacing on the changes in normal stress has been evaluated analytically to optimize the design. Results demonstrate that the modified zipper frac improves the performance of fracturing treatment when compared to the original zipper frac by means of increasing contact area and eventually enhancing fluid production.
The role of geomechanics in design and evaluation of hydraulic fracture stimulations in unconventional reservoirs has become more important than ever. Microcosmic mapping provides a good estimation of fracture geometry and stimulated reservoir volume (SRV); however, without geomechanical considerations, the predictions may not be completely accurate. By understanding reservoir rock mechanics and those parameters that have a major impact on the performance of fracture treatments, more reliable decisions in fracturing design and optimization can be made. This paper presents the results of an analytical model that predicts the changes in stress anisotropy in the neighborhood of the fractures of different designs in an elastic-static medium. Also, a numerical model has been used to investigate the effect of different geomechanical parameters on the geometry of the fractures. Results show that the spacing between fractures has a major impact on the changes in stresses. The effect of well spacing on fracture geometry in modified zipper frac design has been investigated. The results of this study give valuable insight into optimization of fracture placement in newly developed designs of hydraulic fractures in horizontal wellbores.
The previous efforts toward single period inventory problem with price-dependent demand only investigate the optimal order quantity to minimize the total inventory costs; however, there is no method in the literature to avoid unwanted costs due to the deviation between the actual demand and the previously estimated demand. To fill this gap, the present paper supposes that stochastic demand rate with normal distribution is sensitive to the selling price; this means that increasing the selling price would decrease the demand rate and vice versa. After monitoring the consumption trend within a section of the period, a new selling price is implemented to change the demand rate and reduce the shortage or salvage costs at the end of the period. Three functions were suggested to represent the demand rate as a function of selling price, and the numerical analysis was implemented to solve the proposed problem. Finally, an illustrative numerical example was solved for different configurations in order to show the advantages of the proposed model. The results revealed that there is a significant improvement in the system costs when price revision is considered.
With the development of unconventional shale and tight reservoirs, stimulation treatments that place multiple transverse fractures have received a greater attention in recent years. The post-frac productivity of such low-permeability reservoirs is largely determined by the matrix-fracture contact area with appropriate fracture conductivity. Although it is often anticipated that the fractures are infinitely conductive, the general belief is that the production increases with the proppant amount injected. This paper presents an approach to assess the optimum proppant amount injected by determining the post-frac conductivity. First, using three-dimensional finite difference reservoir simulations in a naturally fractured reservoir, which has both the hydraulic fracture and natural fractures modeled explicitly as discrete grid blocks, we find cumulative production as a function of fracture conductivity. For a fixed propped length and production time, we observe a critical conductivity beyond which the production is insensitive to the conductivity. The critical conductivity is then obtained as a function of the propped length and production time. The numerical results show that the critical conductivity increases with propped length and decreases with production time. The effect of stimulated natural fracture properties (intensity and permeability) on the critical conductivity is then investigated. For reservoirs with matrix permeability in the range 20-1000 nD, natural fractures increase the short-term critical conductivity but decrease the medium to long-term ones. The paper also evaluates the influence of water production, cluster spacing, and BHP flowing pressure on the critical conductivity. This study demonstrates that Agarwal type curves based on linear flow are not appropriate for naturally fractured reservoirs and lead to errors in estimation of critical conductivity. The results of this study can be useful for selecting the type and amount of proppant for stimulation of unconventional reservoirs.
Summary With the development of unconventional shale and tight reservoirs, stimulation treatments that place multiple transverse fractures have received greater attention in recent years. The post-fracture productivity of such low-permeability reservoirs is largely determined by the matrix/fracture contact area with appropriate fracture conductivity. Although it is often anticipated that the fractures are infinitely conductive, the general belief is that production increases with the proppant amount injected. This paper presents an approach to assess the proppant amount injected by determining the optimum post-fracture conductivity. First, through use of 3D finite-difference reservoir simulations in a naturally fractured reservoir, which has both the hydraulic fracture and natural fractures modeled explicitly as discrete gridblocks, we find cumulative production as a function of fracture conductivity. For a fixed propped length and production time, we observe a critical conductivity beyond which the production is insensitive to the conductivity. The critical conductivity is then obtained as a function of the propped length and production time. The numerical results show that the critical conductivity increases with propped length and decreases with production time. The effect of stimulated natural-fracture properties (spacing and permeability) on the critical conductivity is then investigated. For reservoirs with matrix permeability in the range of 20 to 1,000 nd, natural fractures increase the short-term critical conductivity, but decrease the medium- to long-term conductivity. The paper also evaluates the influence of water production, cluster spacing, and flowing bottomhole pressure (BHP) on the critical conductivity. This study demonstrates that fracture designs that are based on pseudosteady-state solutions are not appropriate for naturally fractured shale reservoirs and can lead to significantly lower initial production. Considering conductivity degradation over time, fracture designs that target achieving 1-year critical conductivity are recommended. A simple, yet robust workflow that is based on knowledge of 1-year critical conductivity is also presented for systematically selecting the type and amount of proppant for stimulation treatment. Such a workflow can mitigate trial-and-error-based and data-driven approaches in the industry. An example is demonstrated for the Marcellus play.
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