Abstract

For the past several years, foam has been used in many treatments as a fracturing fluid. Although many different types of reservoirs have been stimulated with foam, the primary zones of interest in Eastern Kentucky and Southern West Virginia have been the Berea Sandstone and the Devonian Shales. Due to the nature of these formations, i.e. low permeability, low bottom-hole pressure and water sensitivity, foam pressure and water sensitivity, foam fracturing has been a successful technique.

This paper presents the basic background theory of foam and presents several basic treatment designs which have been used successfully in the Devonian Shales and Berea Sandstone. Production histories for up to two years on a number of wells fractured with foam are compared to production histories of offset wells which were conventionally fractured with gelled water. In all the side -by-side comparisons, foam fracturing was found to give production results either as good as, or better than, conventional fracturing with gelled water.

Introduction

In the decade of the 1970's, foam fracturing was established as a tool for stimulating the production of hydrocarbons from low pressure, low permeability wells. In the past several years, foam fracturing has also been applied to the Devonian Shales of West Virginia and Berea Sandstone of Eastern Kentucky for stimulating production of natural gas.

The Devonian Shales typically have low natural reservoir pressure, with low permeability, natural fracturing, and tendencies permeability, natural fracturing, and tendencies toward fluid sensitivity and frac fluid retention. Foam, as a fracturing fluid, has inherent advantages for use in the initial stimulation of such formations. But the real value of foam stimulation must be reflected in the hydrocarbon produced. This paper presents the results for foam fracturing presents the results for foam fracturing treatments, as indicated by production histories up to two years, in comparison with the results of conventional gelled water fracturing treatments.

THEORY

A fracturing fluid often is a high viscosity fluid which is utilized to create a fracture and to transport propping agent and place it in the fracture. Efficient fracture place it in the fracture. Efficient fracture extension requires good fluid loss control. For greatest production benefit, the frac fluid must cause minimal damage to the formation and then return to the surface with maximum efficiency.

Conventional aqueous fracturing fluid systems use gelling agents, such as polysaccharide gums, to yield fluids with polysaccharide gums, to yield fluids with high viscosity. The ability of the fluid to support proppant is partially dependent upon the concentration of the gelling agent in the fluid. High gelling agent concentrations also aid in fluid loss control; however, additional particulate fluid loss additives are often particulate fluid loss additives are often needed for full fracture extension. Return of the broken gelled water to the surface depends on various fluid properties as well as pressure within the reservoir. If the reservoir pressure is low, the return of fluid must be assisted by swabbing the well before the benefits of the frac treatment can be realized.

Foams, which are mixtures of a gas phase a liquid phase and a surfactant, meet all the basic requirements for a good fracturing fluid; however, the fluid properties of foam are derived from a structure different from that found in gelled water.

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