Evaluating Stimulation Effectiveness in Unconventional Gas Reservoirs
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124843, ’Evaluating Stimulation Effectiveness in Unconventional Gas Reservoirs,’ by C.L. Cipolla, SPE, E.P. Lolon, SPE, and B. Dzubin, SPE, StrataGen Engineering, originally prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.

The full-length paper presents production-evaluation criteria that can be used to compare the overall stimulation effectiveness in unconventional gas reservoirs. Characterizing the “relative” conductivity of the fracture network and primary fracture is critical to evaluating stimulation performance. Because of the uncertainty in matrix permeability and network-fracture spacing (i.e., complexity), it is difficult to find unique solutions when modeling production data in unconventional gas reservoirs. However, it may be sufficient to identify qualitative behaviors that can distinguish between key production mechanisms.  

Introduction

The exploitation of unconventional gas reservoirs has become an ever-increasing component of North American gas supply. The economic viability of unconventional gas developments hinges on effective stimulation of extremely low-permeability rock by creating very complex fracture networks that connect a huge reservoir surface area to the wellbore. The widespread application of microseismic (MS) mapping has improved understanding of fracture growth in unconventional gas reservoirs significantly (primarily shales) and leads to better stimulation designs. However, the overall effectiveness of stimulation treatments is difficult to determine from MS mapping because the location of proppant and distribution of conductivity in the fracture network cannot be measured (and are critical parameters that control well performance).

Hydraulic-fracture growth in many unconventional reservoirs is very complex and unpredictable. Fig. 1 in the full-length paper shows a typical MS-event pattern for a Barnett shale crosslinked (XL) -gel fracture and a water-fracture refracture, illustrating the complex fracture networks that are typical when pumping water-fracture treatments in many unconventional gas reservoirs. The dots, or MS events, show the spatial locations where the rock has been “broken” or fractured. The water-fracture fracture network in Fig. 1 in the full-length paper is extremely large, covering approximately 140 acres and connecting millions of square feet of reservoir surface area to the wellbore, and it is much bigger than the XL-gel treatment. Without this “picture” of the fracture, the extreme complexity of fracture growth in the Barnett shale might never have been understood fully—instead constraining our view to the planar world reinforced by our current fracture models. In the Barnett shale, generally the larger and more complex the MS-event patterns are, the better the production. In this example, the stimulated reservoir volume (SRV) is 1,450 million ft3 of reservoir rock for the water-fracture and only 430 million ft3 for the XL-gel treatment. Gas production after the water-fracture treatment was more than twice that yielded by the XL-gel treatment because of the significantly larger water-fracture SRV.