Abstract
The Time-Stepped Linear Superposition Method (TLSM) has been used previously to model and analyze the propagation of multiple competitive hydraulic fractures with constant internal pressure loads. This paper extends the TLSM methodology, by including a time-dependent injection schedule using pressure data from a typical diagnostic fracture injection test (DFIT). In addition, the effect of poro-elasticity in reservoir rocks is accounted for in the TLSM models presented here. The propagation of multiple hydraulic fractures using TLSM-based codes preserves infinite resolution by side-stepping grid refinement. First, the TLSM methodology is briefly outlined, together with the modifications required to account for variable time-dependent pressure and poro-elasticity in reservoir rock. Next, real world DFIT data are used in TLSM to model the propagation of multiple dynamic fractures and study the effect of time-dependent pressure and poro-elasticity on the development of hydraulic fracture networks. TLSM-based codes can quantify and visualize the effects of time-dependent pressure, and poro-elasticity can be effectively analyzed, using DFIT data, supported by dynamic visualizations of the changes in spatial stress concentrations during the fracture propagation process. The results from this study may help develop fracture treatment solutions with improved control of the fracture network created while avoiding the occurrence of fracture hits.
Highlights
Attempts to engineer the creation of fracture networks and their hydraulic conductivity are key for successful hydrocarbon field development strategies
Pore pressure changes have a direct relationship with principal stress magnitudes—as pore pressure increases, the principal stress magnitudes will increase (Figure 4a)
The dynamic propagation of two hydraulic fractures is modeled with a regional pore pressure gradient with and without a near-field stress superposition due to a pre-existing natural fracture
Summary
Attempts to engineer the creation of fracture networks and their hydraulic conductivity are key for successful hydrocarbon field development strategies. A vast body of modeling attempts have focused on investigating how the various parameters affect the development of complex fracture networks during hydraulic fracturing [1,2]. Fracture characterization efforts in dedicated field experiments have revealed the existence of complex fracture networks in the vicinity of horizontal wells completed with multi-stage fracture treatment operations [3,4,5,6,7]. Modeling work has shown that the fanning of hydraulic fractures occurs due to stress shadowing between the individual fractures as they propagate away from the perforation clusters during the fracture treatment operation. The interaction with the pre-existing natural fractures and parent well hydraulic fractures greatly affects the development of the final fracture network from which the reservoir fluids are produced
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