Use Of Liquified Gases As Fracture Fluids For Dry Gas Reservoirs
Authors: Hurst R.E. 
Published: December 2007

This paper was prepared for the 47th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in San, Antonio, Tex., Oct. 8–11, 1972 Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A new fracturing treatment has been developed which has proved very successful in gas reservoirs. The treatment uses a unique fluid system which is liquefied petroleum gas and liquid carbon dioxide combined with a methyl alcohol based gelling system. Components are mixed in such a ratio that they remain a liquid and behave as other liquids as long as they are under adequate pressure and below their critical temperature. After the fluid is heated to this critical temperature in the reservoir and pressure reduced, the liquid reverts to a gas. This pressure reduced, the liquid reverts to a gas. This results in extremely rapid clean-up and no residual liquids are left in the formation. The new technique, therefore, is primarily designed for gas well stimulation and will have limited application in oil reservoirs.

This paper discusses the technique, materials and equipment used in the new treatment. A tabulation of stimulation results is included.

Introduction

Many gas-bearing reservoirs have resisted stimulation by conventional methods of liquid injection. Frequently, failure of the reservoir to respond was credited to water sensitivity when water, brine, or acid was used as the treating fluid. When oils were used as the treating fluids, the problem of poor stimulation was related to the creation of a third phase. While it is recognized that water sensitivity is a real problem and frequently adds to complications of other types of damage, it is believed that expected stimulation results are often partially or even totally offset because of liquid retention by the reservoir. Core testing of many reservoir rocks, especially those with pore structures displaying a high surface area (pinpoint porosity), verifies this type of damage. In 1964, Kublitz and Shearin, presented data (Table I) from the Canyon Sand presented data (Table I) from the Canyon Sand in the Ozona area of West Texas which dramatically illustrates the effect of liquid retention on permeability to gas. For example, sample number 3 shows a permeability to air (or gas) of 0.104 md at 0.0 per cent brine saturation. This permeability is retained at a saturation up to permeability is retained at a saturation up to 45.9 per cent. However, at a saturation of 49.6 per cent, an increase of only 3.7 per cent, per cent, an increase of only 3.7 per cent, permeability is reduced to 0.067. This represents permeability is reduced to 0.067. This represents a reduction in permeability to gas of nearly 36 per cent. At a brine saturation of 56.0 per per cent. At a brine saturation of 56.0 per cent, an increase of only 10.1 per cent, permeability to gas is reduced to 0.022, a loss of permeability to gas is reduced to 0.022, a loss of nearly 80 per cent of the original permeability.