Deep Well Stimulation With Alcoholic Acid
Authors: McLeod H.O. , McGinty J.E. , Smith C.F. 
Published: December 2007

This paper was prepared for the 41st Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Dallas, Tex., Oct. 2–5, 1966. 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 OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Introduction

A hydrofluoric-hydrochloric acid mixture containing an alcohol has proven to be highly successful in stimulating production from "problem wells" in sandstone formation. The primary advantage of this acid is the better and more rapid "clean-up" properties provided by the added alcohol. It is particularly useful in gas producing formations, particularly those with a high clay content.

Many acid treatments in sandstone which would otherwise be quite successful are spoiled by a very slow spent acid clean-up. This cleanup problem is often the result of water block in the critical matrix surrounding the wellbore. The addition of alcohol to the acid can often prevent this water blocking problem and also can impart other desirable properties to the acid.

Water blocking is caused by the capillary forces present in porous rock and the high mobility ratio of gas and water. Water remains around the wellbore following a stimulation or workover treatment. When the well is put back on production, the gas forces some of the water out of the rock; but after the gas breaks through, a high water saturation is left around the wellbore. This high water saturation reduces the effective permeability of the sand to gas. As the water or spent acid is produced, the gas production rate may increase, but many hours or days will be required to establish optimum production following treatment. Some wells require as much as 3 months to a year to regain the initial gas production rate following liquid injection into the formation. The severity of water blocking increases in low permeability formations where the capillary forces are high or in gas producing formations where the reservoir pressure is low. Liquid saturation hurts the effective permeability of gas even more in formations with large variations in porosity and permeability. An extreme example of this is shown in Figure 1 from a study by Corey and Rathjens. In this case, tight sections are in series with very permeable sections. Here the gas permeability is low even at low average liquid saturations. This behavior may also result from aggregates of migrated clay particles contained in the pores of the rock. These types of reservoir rock can result from the geological conditions of sedimentation which are discussed below.