08122-48

Primary Performer
Texas A&M University

Additional Participants
TerraTek a Schlumberger Company
Devon Energy Corporation
EnCana Oil & Gas USA
Pennsylvania General Energy Co.

Abstract
It is well known that achieving economic production in nano-Darcy permeability gas-shale reservoirs requires creating a large surface area by hydraulic fracturing. Less well publicized are the many factors that contribute to the loss of productive fracture area and reduction of fracture conductivity, both immediate and over time. These lead to low flow rates, low recovery, and often marginal or uneconomical production. Current operational experience in gas shale reservoirs indicates that retention of productive fracture area and conductivity are major economic issues in these plays; literally “a billion dollar problem that needs resolution for deep plays to be economically viable” .

The objective of this theoretical and experimental project is to understand the multiple causes of loss of fracture area and fracture conductivity, and define solutions to mitigate the resulting loss of production. To accomplish this we must understand both the simpler and the often very complex hydraulic fracture networks and determine the critical parameters to maintain productive fracture area and fracture conductivity—including optimal proppants, fracture fluids, and pumping schedules, all as they are related to the heterogeneous rock formations that are to be produced. The end product deliverable would be an improved methodology for production of tight gas shales. The problem is difficult, but the potential for greatly improved production is real.

The project tasks include an evaluation of reservoir geology, mechanical properties, in-situ stress, and rock-fluid interactions. This is required to predict how sparsely propped or self-propped fractures can have and maintain conductivity and to understand the rock fluid sensitivity which could adversely affect the movement of gas from the matrix into the fracture and the conductivity of the fracture. And, we must understand and be better able to predict the fracture connectivity—fracture conductivity alone is not enough; fractures must be connected.

The participants bring critical, essential technology, unique laboratory and field experience, access to reservoir core, logs, completions information (including micro-seismic measurements), and production history, as well as cash and in-kind financial contributions. This is a strong team.

The management of the project will be led by Co-Principal Investigators, Dr. Ghassemi, Petroleum Engr. Dept. at Texas A&M University, and Dr. Suarez-Rivera, Schlumberger Advisor at TerraTek in Salt Lake City. Other team members encompass geologists and engineers, and most importantly, support from producing companies. The project is expected to include measurements on characteristic reservoir mudstones from the Marcellus, Barnett and Haynesville gas shale plays, including 1) long-time, creep effects, 2) un-propped and propped fracture conductivities considering critical proppant concentration required for conductivity, 3) an evaluation of connectivity in generic situations, and 4) a methodology for reservoir typing and selection of fracture stimulations for preventing loss of productive fracture area and loss of fracture conductivity.

Co-Principal Investigators: Dr. Ghassemi, Petroleum Engr. Dept. at Texas A&M University, and Dr. Suarez-Rivera, Schlumberger Advisor at TerraTek in Salt Lake City