Predicting Shale Reservoir Response to Stimulation in the Upper Devonian of West Virginia

Abstract

A comprehensive site study carried out in an Upper Devonian shale gas reservoir at a site in southern West Virginia provided data to test a geomechanical model for stimulation of the Huron formation. Using a model in which natural fractures provide the primary conduits for production and are the major target for stimulation, and in which stimulation triggers shear slip on those pre-existing fractures, we were able to predict the shape of the reservoir volume stimulated by injection of high-quality foam and to match injection flow rates and pressures using a dual porosity dual permeability finite-difference flow simulator with anisotropic, pressure-sensitive reservoir properties. The resulting calibrated model matched both the relative contribution of the individual stages measured by production logging and the early-life well production. This suggests that similar models may in the future provide earlier and better production predictions, guidance for completion and stimulation design, and recommendations to minimize production decline and maximize well value.

Comment on Davies et al., 2012 – Hydraulic fractures: How far can they go?

“…In this case the frac fluid was N 2 gas, which is highly mobile. Some aspects of this study are described in Geiser et al (2012), Moos et al (2011), and Mulkern et al (2010. Here we provide additional description focused on the potential extent of frac fluid movement in natural fracture systems.…”

Estimation of Stimulated Reservoir Volume Using the Concept of Shale Capacity and its Validation with Microseismic and Well Performance: Application to the Marcellus and Haynesville

“…Kok et al (2010) used a production log to show the dramatic differences between similar frac stages, some stages contributing to 2.8% of the well's production while other stages provided 19% of the well's production. Moos et al (2011) illustrates the same variability in production along the wellbore with a Production Log (PLT) but this time provides also the distribution of the natural fractures and the microseismicity along the same wellbore. Moos et al (2011) shows that the well performance along the wellbore seems to correlate well with the natural fracture density, while the density of the microseismic events shows almost no correlation.…”

“…Moos et al (2011) illustrates the same variability in production along the wellbore with a Production Log (PLT) but this time provides also the distribution of the natural fractures and the microseismicity along the same wellbore. Moos et al (2011) shows that the well performance along the wellbore seems to correlate well with the natural fracture density, while the density of the microseismic events shows almost no correlation. Other authors have emphasized the need to intercept natural fractures which have a very high correlation with the production from the frac stages.…”

“…Here again, authors and companies are finally publishing case studies where both production logs are shown next to microseismic interpretation. An extensive study by Moos et al (2011) shows an absence of correlation between the production logs and the density of microseismic events. Dick et al (2013) published an interesting Marcellus case study where one of their laterals (4H in their Figure 5) shows the absence of microseismic events in about half the length of the lateral.…”

Evaluating the Effect of Natural Fractures on Production from Hydraulically Fractured Wells Using Discrete Fracture Network Models

“…The Mallory 145 well pad is one of these sites, and while the results should not be considered exemplary of unconventional reservoirs overall, they do provide significant insights into how an unconventional system may behave. Some aspects of the Mallory 145 experiment are described in Mulkern et al, 2010;Franquet et al, 2011;Moos et al, 2011;Geiser et al, 2012;Lacazette and Geiser, 2013; The Mallory 145 well site was developed by Pittsburgh-based EQT Corporation in Devonian shales and siltstones in southwestern West Virginia. The well pad has four vertically-stacked laterals from the Berea sandstone, Chagrin Shale, Lower Huron Siltstone and Lower Huron Shale.…”