Decline curve analysis using a pseudo-pressure-based interporosity flow equation for naturally fractured gas reservoirs

Abstract

Significant amounts of oil and gas are trapped in naturally fractured reservoirs, a phenomenon which has attracted growing attention as production from unconventional reservoirs starts to outpace production from conventional sources. Traditionally, the dual-porosity model has been used in modeling naturally fractured reservoirs. In a dual-porosity model, fluid flows through the fracture system in the reservoir, while matrix blocks are segregated by the fractures and act as fluid sources for them. This model was originally developed for liquid flow in naturally fractured systems and it is therefore inadequate for capturing pressuredependent effects such as viscosity-compressibility changes in gas systems in its original form. This study presents a rigorous derivation of a gas interporosity flow equation that accounts for the effects of such pressure-sensitive properties. A numerical simulator using the gas interporosity flow equation is built and demonstrates a significant difference in system response from that of a simulator implementing a liquid-form interporosity flow equation. For this reason, rigorous modeling of interporosity flow is considered essential to decline curve analysis for naturally fractured gas reservoirs. In this study, we also show that the use of the proposed gas interporosity flow equation eliminates latetime decline discrepancies and enables rigorous decline curve analysis. The applicability of density-based approach in dual-porosity gas systems is investigated, and the approach reveals that gas production can be forecast in terms of a rescaled liquid solution that uses depletion-driven parameters, k and b. Application of this approach demonstrated that, at the second decline stage, gas production profile shifted from its liquid counterpart is identical to gas numerical responses with gas interporosity flow equation in effects. The production rates from the pseudo-function approach and those from simulations implementing the gas interporosity flow equation for the synthetic reservoirs are compared against each other, which demonstrated good matches during decline.

An artificial-intelligence-based petrophysical property predictor for compositional volatile oil reservoir using three-phase production data

“…In this study, our goal is to use production data to assess permeability, capillary pressure curves, and three-phase relative permeability properties. The evaluation of reserve and hydraulic fracture qualities has mostly relied on production data (Blasingame et al, 1991; Fetkovich, 1980; Wattenbarger et al, 1998; Zhang and Ayala H., 2016, 2017, 2018). Using proxies, Zhang and Ertekin (2021) evaluated the petrophysical characteristics of black oil reservoirs.…”

Proxy models for evaluation of permeability, three-phase relative permeability, and capillary pressure curves from rate-transient data

“…Production data have long been used for interpretation of reservoir properties such as permeability. 42–47 However, it has never been used to evaluate three-phase RP to the best of our knowledge. An ANN is an effective tool for simulating relationships.…”