Theory and Application of Formation Pressure in Fractured-Vuggy Oil and Gas Reservoirs Based on Concentrated Source Theory

Abstract

In this study, a rapid analytical framework is developed for reconstructing transient formation-pressure distributions in sparsely connected fractured-vuggy carbonate reservoirs using well-test-derived fracture–cave geometry and source allocation. Pressure–flow relationships are established for caves, fractured bodies, and finite line-source fractures; unit-source solutions are combined via spatial superposition and Duhamel convolution for variable-rate production; and the framework is evaluated by comparing Well EX-1 against a PEBI-grid simulation. Cave response is derived from mass conservation and effective compressibility, while point- and line-source Green’s functions describe pressure diffusion. For the 30-day EX-1 case, analytical and PEBI pressures at four locations show close internal agreement, with a mean absolute error of 0.070 MPa, a root-mean-square error of 0.083 MPa, and a maximum absolute error of 0.13 MPa. This method is applicable mainly to single-phase, slightly compressible, linear-flow conditions with a constrained fracture–cave topology. It provides a rapid screening tool for deep carbonate reservoirs with sparse well control, while multiphase, strongly nonlinear, reactive, or geomechanically coupled cases require conventional numerical simulation.