A Novel Methodology to Capture Anisotropy in Unconventional Reservoirs: A Case Study with Stress Anisotropy

Abstract

ABSTRACT The article presents the results of a case study obtained through the application of theory and methodology explained in the accompanying article submitted to this conference. Stress anisotropy determination requires material properties anisotropy as input, and the acquisition of these properties isn’t common practice. The current results clearly demonstrate how stress anisotropy could be captured in an unconventional reservoir with a simple and novel methodology. The results eventually enable efficient lateral placements and optimized hydraulic fracture design. Rock mechanical properties were determined by compression and shear velocities; later, a 1D geomechanical model (1DGM) was built based on the poro-elasticity and effective stress principles. Subsequently, 1DGM was calibrated based on any available core, DFIT/LOT/FIT/minifrac data, and observations from DDR (daily drilling reports). The 1DGM built and the rock's mechanical properties calculated are isotropic. A regional tectonic strain value was determined based on multiple well correlations in the region. Following the theory and methodology proposed in the accompanying article in this conference, two new horizontal stresses, Shmin_tect and SHmax_tect, were determined, capturing stress anisotropy as input to hydraulic fracture design. The play has three distinctive pay zones or shale formations: upper, middle, and lower, confined by much harder formations above and below. The area of study did not have any data for a full anisotropic characterization; however, there was production data suggesting connectivity in the staggered laterals. Thus, the objective was to determine as accurately as possible the stress anisotropy that would affect the vertical fracture growth and containment. Data from four (four) lateral/pilot wells was used to build four 1DGM in two different acreages. Results from one such well are shown in Figure 1. The results shown in Figure 1 clearly demarcate five zones with different stress gradients. In the three pay zones and shale formations, it is evident that the middle formation would potentially act as fracture containment for laterals placed in the upper and lower formations. Also, the much harder above and below formations show a higher stress gradient, as expected. Further analysis comparing microseismic and production data to substantiate the results obtained is ongoing. The results clearly show the effectiveness of the methodology, thus adding a simple but novel workflow to capture stress anisotropy that is cost-effective and has a quick turnaround.