Hydraulic fracturing is currently the completion method of choice in most tight reservoirs; however, the ultimate performance of fractured wells is severely affected by the interfering effects inside the fracture and interfractures. Previous simulation studies investigated the effects of well spacing and fracture length on well productivity in low-permeability oil and gas reservoirs. It was shown that the most important parameters for determining the optimum fracture length are the formation permeability and the stimulated reservoir volume (SRV). Although a number of studies have examined the performance of horizontal fractured wells and the fracture geometry effect, fracture spacing and intersecting angles in vertical and horizontal wells should be further investigated. This study presents the results of a tight oil reservoir analogy. Reservoir parameters considered include local rock stresses, rock compressibility, absolute and relative permeability, and porosity. The well-completion parameters included fracture length, height, width, conductivity, number and spacing between fractures, fracture intersecting angle, and cased- vs. openhole completion. Fracture modeling considered rigorous description of the hydraulic fracture properties and finite difference reservoir modeling. Economically attractive reserves recovery was modeled through multiple fracture placements in a 10,000-ft horizontal well. Numerical simulation showed that oil recovery increased between 8 to 15%, while net present value (NPV) increased 8 to 24%, as the number of fractures increased. Based on the critical assumptions in the study (permeability, natural fracture distribution, and stress orientation), an optimum number of fractures was identified. Openhole completions provided better performance in most cases, and recovery was greater for a higher number of contributing perpendicular vs. longitudinal fractures. The results of the study hopefully can be used to improve the understanding of the role of fracture geometry, spacing, and open/cased-hole completion strategy to enhance an operator's optimum completion design.

Summary In this study we estimated the initial effective fracture pore volume (Vfi) and fracture volume loss (dVef) for 21 wells completed in the Montney and Eagle Ford formations. We also evaluated the relationship between dVef and choke size. First, we applied rate-decline analysis to water-flowback data of candidate wells to estimate the ultimate water recovery volume, approximated as Vfi. Second, we estimated dVef using a fracture compressibility relationship to evaluate the fracture volume loss of the Eagle Ford wells. Third, we investigated the effect of choke size on dVef for the Eagle Ford fastback and slowback wells. Semilog plots of flowback water rate vs. cumulative water volume show straight-line trends, representing a harmonic decline. The estimated Vfi accounts for approximately 84 and 26% of the total injected water volume (TIV) of the Montney and Eagle Ford wells, respectively. The results show that approximately 10% of the fracture volume is lost during flowback. This loss in fracture volume predominantly happens during the early flowback and becomes minimal during the late flowback period. The results show a relatively higher dVef for fastback (a flowback process with a relatively large choke size) wells compared with that for slowback (a flowback process with a relatively small choke size) wells. In this study we proposed a method to estimate the initial fracture volume and investigated the loss in fracture volume during the flowback process. Analyses of the field data led to an improved understanding of the factors that control water flowback and the effective fracture volume.

Hydraulic fracture design and performance optimization has been studied extensively. Lean manufacturing strategies for the intensive fracturing operations requires completion optimization by careful understanding of marginal benefits that additional fracture stages will bring to the bottom line.This study presents the results of a tight oil reservoir analogy of the Bakken shale using a fully coupled reservoir and surface-network multiphase simulation orchestrated by an automated workflow to run multiple technical scenarios to understand the incremental economic value of adding additional fractures to the standard 20-fracture well design. Our effort included the use of assisted generation of grid refinements to estimate oil recovery in a multiple-fracture horizontal well.This study demonstrates that an increasing number of fractures will not always improve the short-term economics. Comparing 30-vs 60-fracture cases to low-permeability cases (k=0.005 and 0.05 md) indicates that NPV can be increased by USD 0.8 to 2.2 million-97 to 110%), whereas return on capital invested (ROCE) was improved by 3-4%. The methodology and the results of this study can confidently be used to advance the understanding of the role of fracture geometry and spacing to enhance an operator's optimum completion design.

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