| dc.description.abstract | Formation evaluation and production design are often challenging in organic-rich mudrocks due to complexities in petrophysical and compositional properties as well as post-depositional hydrocarbon generating mechanisms such as thermal maturation over time. Petrophysical parameters such as porosity, permeability and fluid saturations are important but not sufficient to fully characterize organic-rich mudrocks. Thus, integration of geomechanical, geological, geochemical, and petrophysical characterization is critical to enhance production from these formations. This paper focuses on an integrated rock classification applied in two wells in the oil-window of the Eagle Ford Shale play in South Texas. The lower Eagle Ford interval is an organic-rich fossiliferous marine shale deposited in Late Cretaceous.
Initially, we classified the rocks based on geological texture and geochemical properties measured at the lower Eagle Ford (LEF) in a well where conventional core was available. Then, I performed a joint inversion of triple-combo, spectral gamma ray, and elemental capture spectroscopy (ECS) logs in both wells to estimate depth-by-depth volumetric concentrations of minerals, porosity, and fluid saturations. The rocks were separated into five petrophysical classes using these results. In the absence of acoustic measurements in Well 1, I used concentrations and shape (i.e., aspect ratio) of minerals as inputs to the Self-consistent Approximation (SCA) model to estimate depth-by-depth effective elastic properties such as Young's Modulus (YM), Poisson’s Ratio (PR), and minimum horizontal stress (MHS) gradient. Finally, I conducted a geomechanical iii classification, and divided the rocks in the LEF into three categories: low-stress, medium-stress and high-stress, based on the MHS gradient.
The introduced well-log-based petrophysical and geomechanical rock classification was applied to the pilot section of two oil-producing wells located approximately 20 miles apart. Both wells were drilled horizontally with lateral lengths greater than 5,000 ft, and were hydraulically fractured. Petrophysical evaluation showed similar organic content (4.5- 5.0 wt%), porosity (7.0%), and total volumetric concentration of clays (10-15 vol%) in the target intervals of both wells. However, in comparison of well productivity, Well 1 produced an additional 11,000 barrels of oil equivalent (BOE) with a total hydrocarbon production of 54,000 BOE in the first 90 days after completions, approximately 25% more than Well 2 (43,000 BOE total). Geomechanical rock classification results showed lower MHS average values in Well 1, than in Well 2 (0.58 psi/ft vs. 0.62 psi/ft, respectively), and a higher proportion of completion-quality (low-stress) rock types in Well 1 relative to Well 2 (55% vs. 34% respective).
Results suggest that the well-by-well difference in production cannot be explained by only relying on the estimated petrophysical properties of the formation. Higher productivity of Well 1 may result from greater hydraulic fracture extent, and thus increased total stimulated reservoir volume (SRV). Moreover, geomechanical properties such as in-situ stresses and presence of natural fractures play important roles towards well productivity and must be taken into account in rock classification for completion decisions. | en |
