Abstract

Cyclic gas injection in hydraulically-fractured wells has been successfully applied as an enhanced oil recovery (EOR) method in tight unconventional basins such as the Permian and Eagle Ford. However, displacement processes (continuous gas, solvent or water injection) such as those piloted in the relatively more permeable Bakken formation have not been considered in tighter basins. In this work, we present a novel displacement process that uses alternating injecting and producing hydraulic fractures to flood the inter-fracture region around a horizontal well. We demonstrate that the method is feasible as long as suitable fracture geometries can be generated.

A reservoir geomodel of a typical Montney gas condensate reservoir was constructed using publicly available data. Rock mechanics parameters were integrated into the model alongside completion and pumping schedule information to predict hydraulic fracture propagation and geometries representative of the typical stimulated volumes in Montney. A compositional numerical reservoir simulator was then used to test the proposed EOR process in a gas condensate reservoir where we forecast liquid recovery under different frac-to-frac continuous gas injection flooding scenarios. Sensitivities to study the effect of fracture spacing and complexity, solvent composition, starting time of gas injection, and matrix permeability were performed.

With simultaneous injection and production from alternating hydraulic fractures, it is possible to flood the volumes between them and consequently avoid the drawbacks of huff ’n’ puff processes. By using a more rigorous fracture description, we can reproduce the interactions between fractures and determine how they affect the conformance of the displacement front.

Modeling results showed that frac-to-frac displacement process can significantly improve the condensate recovery compared to primary or even huff n puff EOR process. They also showed that the frac-to-frac EOR process is feasible only if the formation mechanical properties and in-situ stresses are such that the resulting hydraulic fractures exhibit aligned planar geometries. If high-intensity natural fracture networks are present, the hydraulic fractures tend to form complex geometries that negatively affect the conformance of the flooding front. The study also showed that there is an optimal spacing between the injecting and producing fractures that would allow for the efficient utilization of the EOR agent; this spacing was shown to have a strong dependence on matrix permeability. Composition of injected solvent and starting time of gas injection doesn’t seem to have considerable impact on incremental recovery due to frac-to-frac displacement.

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