This paper examines the buildup pressure response of a well that penetrates an unconventional tight naturally fractured carbonate reservoir in Mexico. Four buildups in the same well over a period of 4 months, with intermediate flow periods, suggest partial closure of natural fractures. Radial flow is dominant in the four buildups. This is recognized in semilogarithmic and pressure derivative cross plots. However, the formulations require a consistent empirical component to match the buildup data.

The four buildup tests are evaluated with a semi-empirical dual-porosity model with restricted interporosity flow. The restricted flow between matrix and fractures is the result of partial secondary mineralization (cementation) within the fractures, which can be visualized as a natural positive skin that reduces the oil flow from the matrix to the fractures. The empirical part of the method is provided by a severity exponent (SE), which helps improving the match of the buildup semilog and derivative plots.

The buildup evaluations permit estimating several parameters of interest, including fracture capacity (k2.h), skin, storativity ratio (ω), and the extrapolated pressure (p*). The calculated k2.h is equal to 8.73 md-ft during the first and second buildups, 8.34 md-ft during the third buildup and 5.5 md-ft during the last buildup, which is also the longest (118 hours). Results suggest that although natural fractures are present, they tend to close once the well goes on production. Thus, the conclusion is reached that the carbonate reservoir is tight and likely stress dependent. The values of skin tend to increase going from −2.51 to −2.20 to −1.45 to +0.46 indicating that the reservoir goes from improved condition around the wellbore to slightly damaged conditions probably due to fracture closure. On the other hand, ω increases continuously going from 0.46 to 0.56 to 0.66 to 0.71 suggesting a tendency of the reservoir to move from dual to single porosity behavior. The reservoir is overpressured (0.87 psi/ft) and the extrapolated pressures (p*) decrease from 18,200 to 18,050 to 16,700 to 14,000 psi because of the tight characteristics of the reservoir. However, given the large size of the reservoir, the likelihood of depletion is unlikely.

The novelty of this study is the development of a new easy-to-use semi-empirical well testing model for matching the buildup pressure response of four tests performed in a well that penetrates an overpressured, unconventional, tight naturally fractured carbonate. The tests could not be matched with well-known commercial packages.

You can access this article if you purchase or spend a download.