According to the 2011 Energy Information Agency (EIA) global assessment, Mexico ranks 4th in shale gas resources. The Eagle Ford shale is the formation with the greatest expectation in Mexico given the success it has had in the US and its liquids-rich zone. Accurate estimation of the resource size and future production, as well as the uncertainties associated with them, is critical for the decision-making process of developing shale oil and gas resources. The complexity of the shale reservoirs and high variability in its properties generate large uncertainties in the long-term production and recovery factors of these plays. Another source of uncertainty is the limited production history. Given all these uncertainties, a probabilistic decline-curve analysis approach was chosen for this study, given that it is relatively simple, it enables performing a play-wide assessment with available production data and, more importantly, it quantifies the uncertainty in the resource size. Analog areas in the US Eagle Ford shale were defined based on available geologic information in both the US and Mexico. The Duong model coupled with a Markov Chain Monte Carlo (MCMC) methodology was used to analyze and forecast production of wells located in the previously defined analog sectors in the US Eagle Ford shale. By combining the results of individual-well analyses, a type curve and estimated ultimate recovery (EUR) distribution for each of the defined analog sectors was obtained. These distributions were combined with well-spacing assumptions and sector areas to generate the prospective-resources estimates. Similar probabilistic decline-curve-analysis methodology was used to estimate the reserves and contingent resources of existing wells. As of March 2013, the total prospective resources (P90-P50-P10) for the Eagle Ford shale in Mexico (MX-EFS) are estimated to be 527-1,139-7,268 MMSTB of oil and 17- 37-217 TSCF of gas. To my knowledge, this is the first oil estimate published for this formation in Mexico. The most attractive sectors based on total estimated resources as well as individual-well type curves are located in the southeast of the Burgos Basin and east-west of the Sabinas basin. Because there has been very little development to date, estimates for reserves and contingent resources are much lower than those for prospective resources. Estimated reserves associated with existing wells and corresponding offset well locations are 18,375-34,722-59,667 MMSCF for gas and zero for oil. Estimated contingent resources are 14-64-228 MSTB of oil and 8,526-13,327- 25,983MMSCF of gas. The results of this work should provide a more reliable assessment of the size and uncertainties of the resources in the Mexican Eagle Ford shale than previous estimates obtained with less objective methodologies.

Organic shales have become one of the greatest sources of hydrocarbon thanks to novel production techniques such as hydraulic fracturing. A successful hydraulic fracturing job, however, is dependent on several rock properties such as mineralogy and elasticity. A reliable estimation of such properties is therefore necessary to determine ideal rocks for horizontal well placement. In this study, rock types within the Eagle Ford shale that would be suitable for hydraulic fracturing are identified through interpretations of available well logs and core data. A comparative study of petrophysical properties such as mineral content, kerogen type and maturity, porosity, and saturation in six wells is performed to characterize the Eagle Ford shale. Two of the wells studied are within the wet gas window of the shale while the remaining four are in the oil window. Based on the calculated petrophysical properties, rock typing was performed using k-means clustering. Two rock types (RT1 and RT2) were identified and their compositions compared in each well. Elastic properties for the various rock types identified were then estimated using the differential effective medium (DEM) theory and were validated through simulation of slowness logs. The final rock type assessment was then performed to identify ideal rocks for hydrofracturing. Results indicate that the Eagle Ford mineralogy varies greatly with depth and with geographic location relative to the San Marcos Arch, a geological arching prominence across the shale. Northeast of the arch, the Eagle Ford shale is clay-rich. Preferred rocks for hydrocarbon production, RT1, are characterized by volumetric concentrations of ~0.44 carbonate, ~0.09 kerogen, ~0.07 porosity, and ~0.42 clay; RT1 also exhibits high sonic velocities (> 3400 m/s and > 1500 m/s compressional and shear, respectively) and high apparent electrical resistivity (> 2 ohm-m). In the Southwest region, on the other hand, the Eagle Ford shale is mostly calcareous. Ideal rocks in the region, RT1, are rich in kerogen (~0.1) with carbonate content of ~0.56, ~0.1 porosity, ~0.19 clay content, and resistivity > 20 ohm-m. In both regions, porosity and pore aspect ratio displayed substantial effects on elastic properties. For example, over 80% decrease in Young’s modulus was quantified when pore aspect ratio approached zero; high pore aspect ratio is preferred for stiff rocks. Poisson’s ratio estimates were not always reliable therefore fracturability was assessed based on Young’s modulus estimates. The study shows that depth intervals exhibiting Young’s moduli above 18GPa and 21GPa in the Northeast and Southwest region, respectively, are suitable for hydrofracturing. / text