Modeling of Viscous Displacement in Dual-Porosity Naturally Fractured Reservoirs: Application to Surfactant Enhanced Oil Recovery

Abstract

Surfactant-enhanced oil recovery (EOR) in fracture-dominated naturally fractured reservoirs (NFR) and very low-permeability Bakken type reservoirs is less known. Therefore, to predict its performance, improvement of the reservoir simulation tools is necessary to account for the surfactant flow mechanisms as much as possible. We present an improved dual-porosity (DP) numerical simulation model and algorithm in which matrix-fracture fluid transfer function was enhanced by implementing a proper viscous displacement mechanism. This mechanism was added to the existed fluid expansion, gravity drainage, and capillary pressure mechanisms. Current DP reservoir simulators generally do not account for the viscous displacement mechanism. To validate both the accuracy and efficacy of the improved model, results were compared with the results from a variable permeability-porosity, single-continuum, fine-grid model. Simulation results of improved model were in agreement with the results of the fine-grid model as the reference case. In a one-dimensional numerical model, water flood cumulative oil production increased about 5% compared to the conventional DP model. Also, incremental oil production increased over 5% for 1 to 2 wt% surfactant concentrations. Similar results were obtained in multi-dimensional numerical models. In a representative matrix block, the water flood oil production rate started at 0.25 bbl/day in improved model compared to 0.053 bbl/day in conventional DP model. This rate was 0.124 bbl/day versus 0.03 bbl/day at the start of chemical injection. The improved model is computationally very efficient and is much faster than the fine-grid model. For a practical application, the improved model was used to design and assess the viability of an EOR pilot-test using a single-well, multiple-completion protocol in a fractured carbonate reservoir. This reservoir has a matrix permeability of 10 md and matrix porosity of 0.05, and fracture permeability of 10,000 md. Similar result was obtained using improved and fine-grid models. Also sensitivity analysis was performed on fracture spacing of 5 to 20 ft. We found that smaller matrix blocks are affected more by viscous displacement.

Performance Quantification of Enhanced Oil Recovery Methods in Fractured Reservoirs

“…They might result in more oil recovery and a delay in breakthroughs [21,22]. The viscous drive mechanisms can assist the oil displacement from the matrix due to substantial pressure gradients of fracture flow, particularly for chemical injection [23]. Water-alternating gas (WAG) injection, as a mobility control process, can improve sweep efficiency and oil recovery.…”