Economic Analysis Of Foam Fracturing In The Devonian Shales: Preliminary Report
Authors: Liebenthal Andres M. , Komar Charles , Rieke Herman H. , Skillern Charles R. 
Published: December 2007

The Department of Energy's Morgantown Energy Technology Center (DOE-METC) has, since 1975, been sponsoring a number of foam fracturing stimulation treatments in the Devonian Shale. Wells stimulated with foam appear to have better potential than hydraulically stimulated wells. This is indicated by a mean initial open flow rate of 329 Mcf/D obtained from nine conventional size pilot treatments in the periphery of the Big Sandy region. In addition, the periphery of the Big Sandy region. In addition, the mean initial open flow rates of three wells that received multiple massive foam treatments has been 394 Mcf/D, even though they were in an old producing area that was partially depleted. The costs of foam-stimulation are however definitely higher than those of gelled water fracturing.

This paper presents a preliminary economic analysis of foam treatments. It uses a discounted cash flow method and generalized production decline curves based on actual production data from 25 hydraulically fractured wells in the Devonian Shale (Big Sandy region) of Eastern Kentucky. The results of the study show that gas production from foam fraced wells is economically viable if the resulting production decline curve is similar to that of production decline curve is similar to that of hydraulically fractured wells with the same initial open flow rates.

Introduction

It has been established geologically that a potentially significant source of natural gas lies potentially significant source of natural gas lies in the Devonian Shales of the Appalachian, Illinois and Michigan Basins of the eastern United States. The shales underlie an area of approximately 250,000 square miles and are distributed in discrete units ranging in thickness from a few feet to about 400 feet. Organic content ranges from 5 to 25 percent by volume and caloric content ranges up to 7 million Btu (MMBtu) per ton of shale. A recent industry study has estimated that the total gas-in-place in the Devonian Shales ranges from 225 to 2,023 trillion cubic feet (Tcf).

The technological challenge is to find practical and economic ways to produce this resource. Industry and the Department of Energy (DOE) are presently involved in developing, improving, and evaluating different well stimulation technologies proposed for the exploitation of the Devonian Shales. One of the technologies under consideration is the use of foam as a low-residual fracturing fluid. Foam has been used quite widely in the oil and gas industry for the past five years. The use of foam fracturing in the Devonian Shale evolved from research at DOE's Morgantown Energy Technology Center (METC) that started in 1975 and was directed at improving gas productivity from new shale wells. Together with productivity from new shale wells. Together with independent gas producers and in cost sharing contracts with Kentucky West Virginia Gas Co., Consolidated Gas Co., and Columbia Gas System, DOE-METC has conducted a number of both conventional-size (~1000 bbls) and massive-size (3000–6000 bbls) foam treatments in stimulating gas production from different stratigraphic units within the Devonian Shale formation. Although the number of tests involved and the length of their production history do not yet warrant a statistically-based analysis of the economic viability of foam fracturing, sufficient data has been accumulated to allow for a preliminary evaluation of its economic potential. This paper presents a parametric approach that was used to obtain preliminary insights on the economics of foam fracturing in the Devonian Shales.

Foam Fracturing Results

Field data from both conventional size and massive size foam treatments in the Devonian Shales have been accumulated by the DOE-METC in cooperative projects with various gas producers. The location projects with various gas producers. The location of the foam treatment test wells is shown in Figure 1. Treated intervals include both the Upper and Middle Brown Shale sections of the Appalachian Basin, the New Albany Shale in the Illinois Basin, and the Antrim Shale of the Michigan Basin. Treatment data on these wells, summarized on Tables 1 and 2 are extremely limited and can only be used to obtain preliminary insights.