Determination of In-Situ Reservoir Absolute Permeability Under Multiphase-Flow Conditions Using Transient Well Testing

Abstract

Summary A new method is presented that uses transient well testing to determine the in-situ absolute permeability of the formation when three phases of fluids are flowing simultaneously in the reservoir. The method was verified through simulation using synthetic data, and its applicability and practicality were confirmed through application to field data. Determining the absolute permeability over the reservoir scale using readily available transient testing data will have major benefits in accelerating history matching and improving reservoir-performance prediction. A recently developed method (Kamal and Pan 2010) to determine the in-situ absolute permeability under conditions of two-phase flow extended the applicability of transient well testing and has been adopted in commercial software. In this study, We extend the analysis method to determine the absolute permeability and fluid saturations when three phases are flowing in the reservoir. We show that an optimization procedure is needed to obtain the required results in this case. We show that the theoretical bases for the method presented to determine absolute permeability from transient tests under multiphase-flow conditions are the same as those used in obtaining relative permeability relations from core analysis and predicting reservoir performance in reservoir-simulation studies. The method presented in this study uses surface flow rates and the fluid properties of the three phases. It also uses the same relative permeability relations used in the simulation models, thus ensuring that the same permeability values calculated from field data are used in history matching and predicting the performance of the reservoir. It is assumed that the fluid saturations are relatively uniform in the region around the well at the time of the transient test. The method was verified by comparing the input values with the results obtained from analyzing several synthetic tests that were produced by numerical simulation. Data from a deepwater field were also used to test the practicality and validity of the method. For the field case, the method was verified by matching reservoir production and pressure using the calculated absolute permeability. Excellent agreements were obtained for both synthetic and field cases.

A Numerical Model for Pressure Analysis of a Well in Unconventional Fractured Reservoirs

“…After the numerical drawdown test, the reservoir permeability can be determined by analyzing the bottom-hole pressure and the production rate. If the interpreted permeability is equal to the input permeability in our model or their difference is less than 10% of the input value, the simulated results are accurate [46,47]. In log-log coordinates, based on the bottom-hole pressure difference and pressure derivative obtained by PANDAS, the radial flow regime can be identified, and then the reservoir permeability is calculated to be 48.1219 mD.…”

Numerical well test model of oil-water two-phase flow in fractured and vuggy carbonate reservoir

“…This approach provided valuable insights into the absolute permeability of the reservoir and the skin factor of the production well, with applicability to real reservoir systems featuring multiphase fluid flow within porous media. Kamal et al (2019) introduced an innovative method that leverages transient well testing to accurately estimate the in − situ absolute permeability of reservoir formations, even under the simultaneous flow of three fluid phases. The validity of this method was established through simulations using synthetic data.…”

A New Approach to Predicting Vertical Permeability for Carbonate Rocks in the Southern Mesopotamian Basin

“…Various studies have been performed to estimate the absolute permeability of different carbonate and sandstone reservoirs [15][16][17][18][19]. It is important to mention that predicting permeability and developing a straight equation for permeability as a function of petrophysical properties for carbonate reservoirs is a complicated task because of the availability of several uncertainties (e.g., anisotropy and heterogeneity) in these reservoirs.…”