This paper examines the pressure response of a horizontal well that penetrates an unconventional, naturally fractured reservoir. The response is quite surprising. The expectation of linear flow is shattered, and only radial flow is observed. The radial flow two parallel straight lines in a semilogarithmic crossplot of flow pressure vs. time are present but they are reversed, with the last straight line showing smaller pressures as compared with the extrapolated first straight line.
Two different methods are used; the first one is a conventional approach for analyzing the first semilog straight line with a view to calculating flow capacity and permeability well as skin. The second approach involves a novel dual porosity model that permits calculating several fracture parameters of interest, and to the best of our knowledge has not been published previously in the petroleum engineering literature. In this paper, new equations with a semi-empirical component, are presented that allow matching the reversed real pressure drawdown data as well as the corresponding pressure derivatives.
The new model shows that fluid flow is dominated initially by the fractures as in the case of dual porosity conventional models. In the conventional model, flow pressure data deviate from the first straight line toward the right due to pressure support stemming from fluids that move from the matrix toward the fractures. Eventually, a pressure equilibrium is reached and a second straight line, parallel to the first one, is developed. However, in the case of the model presented in this paper the data deviates, not to the right of the first straight line, but down and below the first straight line. This pressure drop is interpreted to be the result of boundary-dominated flow. Next, a pressure equilibrium is reached between matrix and fractures, and the last line becomes parallel to the first straight line. It is shown that correct pressure and derivative matches permit estimating various parameter of interest such as size of the matrix blocks, number of fractures that intercept the well bore, storativity ratio omega, partitioning coefficient (the ratio between fracture and matrix porosity), matrix permeability, and the ratio of fracture to matrix hydraulic diffusivity.
The novelty of this study is the development of a new easy-to-use well testing model for matching an unconventional pressure response during drawdown of a horizontal well that penetrates an unconventional tight dual porosity reservoir. The new method is explained with a step-by-step example that uses real data from the giant unconventional Chicontepec paleochannel in Mexico and can be reproduced readily by the reader.