No abstract

The mutual coupling effect between the fluid flow and the in situ stress fields cannot be ignored during the development of natural fractured reservoirs (NFRs), such as in the waterflooding process. In this study, a discrete fracture model is proposed to simulate the rock deformation and two-phase flow behaviors of oil and water in the NFR. The numerical solution of the model is achieved via the finite-element method and control-volume finite-element method. The numerical simulator is verified using commercial software, and a perfect agreement is obtained. Finally, sensitivity analysis is conducted on the key parameters in the model, such as fracture parameters, matrix permeability, and injection intensity. Results show that the fluid–solid coupling effect gradually weakens with production time. The degree of the fluid–solid coupling on cumulative oil production becomes smaller as the permeability of the matrix increases. Fracture connectivity controls the velocity and direction of the water flood front. Water injection intensity directly affects the natural fracture opening deformation and well productivity. The research and the numerical results obtained in this paper can provide theoretical guidance for the optimal design of water flooding operations in NFR.

In the past several decades, traditional decline curve analyses have been widely used as a quick and simple yet efficient method for reserve estimation and production forecasting. Several new models have been proposed since 2000s to address limitations of traditional decline models in shale and tight reservoirs especially multiple flow regimes and long-tail behavior of production profile which results in overestimating the reserve by the traditional models. Several of these newly proposed decline curve analysis (DCA) models are conservative and provide pessimistic reserve estimates. The main purpose of this work is to evaluate the application of six heavy-tailed probability density functions (PDFs) to approximate production in shale and tight reservoirs. A new class of DCA model suitable to capture the production decline trend in shale and tight reservoirs is examined using real and simulated production data. The proposed class of DCA has been demonstrated to predict production more accurately in tight and shale reservoirs especially when only limited data are available from wells with less than a few months of production history.