Characterization of the Giant Chicontepec Tight Oil Paleochannel in Mexico and Integration with Actual Cumulative Oil Production

Abstract

Summary The Chicontepec paleochannel contains unconventional tight oil shaly sandstone reservoirs also characterized by natural fractures of tectonic origin. Chicontepec ranks as a giant reservoir with volumes of original oil in place (OOIP) ranging between 137,300 and 59,000 million STB (Guzman 2019). Although the cumulative oil is significant (440.38 million STB), it only represents 0.32 to 0.75% of the OOIP. The objective of this study is to develop a new characterization methodology with a view to increase oil recovery from Chicontepec. OOIP in Chicontepec paleochannels was estimated originally at 137,300 million STB. Despite several studies using state-of-the-art methodologies and contracting major oilfield services companies to test new technologies and significant investments, the OOIP was decreased recently to 59,000 million STB due to lack of any significant success on the implemented projects. This study shows that the key to success is understanding the contribution of natural fractures. This is demonstrated for the case of Chicontepec with a new dual-porosity petrophysical model for naturally fractured laminar shaly sandstone reservoirs developed in this study. The model assumes that matrix and fractures are in parallel. Laminar shaliness is handled with a parameter (Alam) that is a function of true and shale resistivities, and fractional shale volume (Vsh). The methodology integrates data from observations in outcrops, quantitative evaluation of cores, well logs, and actual production data. Past Chicontepec studies have assumed that the porosity exponent (m) in Archie and shaly sandstone equations is constant. However, core studies indicate that Chicontepec m values become smaller as porosity decreases. The proposed dual-porosity petrophysical model, when applied to actual Chicontepec wells, matches properly the laboratory values of m and generates results that generally compare well with actual production data (e.g., the larger the value of fracture partitioning, the larger is the cumulative oil production). Pattern recognition allows estimating fracture intensity with a partitioning coefficient, which is calculated as the ratio of fracture porosity to total porosity. The new contribution of this manuscript is the development of a petrophysical dual-porosity model for naturally fractured shaly sandstone reservoirs that integrates variable values of m from cores, fracture intensity, and cumulative production of individual Chicontepec wells. Our detailed review of the literature indicates that this methodology has not been published previously.