Stimulation of the Deep Ellenburger in the Delaware Basin
Authors: Crenshaw P.L. , Flippen F.F. 
Published: December 2007

Certain problems are inherent in stimulating deep, hot wells. Experience with wells in the Delaware Basin has led to this paper, which explains how such problems as the following have been dealt with:inability to confine the treatment within the desired interval;lack of fracture- fluid-loss control;lack of definite knowledge regarding acid reaction and flow mechanism at high temperatures and pressures; andlimitations that are dictated by dry gas reservoirs and that are not present in oil wells.

Since some standard techniques and most standard chemicals were not usable, new methods and materials have been developed and are described here.

Introduction

The early high-temperature and high-pressure Delaware Basin gas wells did not require extensive stimulation. The only special items required were high-pressure pumping equipment and high-temperature inhibitors for the acid. The small acid treatments used to clean up the limestone and dolomite pay zones did not impose severe limitations of the acid formulations so that standard mixtures of hydrochloric and acetic acids were used. Arsenic inhibiters were in use and provided excellent protection against attack in ordinary tubular goods. High pressure pumping equipment was obtained to allow treating at pressures up to 15,000 psi. Later, several wells were completed with alloy metal psi. Later, several wells were completed with alloy metal and with high-strength tubular goods, wellhead connections and down-hole producing assemblies. Arsenic inhibitors were suspected of being able to contribute to stress corrosion cracking and hydrogen embrittlement of high strength alloys. These inhibitors were also deemed undesirable because the presence of arsenic in produced gas and oil could present problems to some catalysts used in refineries. present problems to some catalysts used in refineries. Therefore, a good high-temperature organic inhibitor for acid was desirable, but none was available for use in hydrochloric acid for these special metals under these conditions

The need to re-treat some wells with larger volumes of acid pointed up the fact that hydrochloric acid could not be retarded for these temperatures without first being emulsified in a hydrocarbon. This resulted in very high friction pressure and lower injection rates. The low injection rates pressure and lower injection rates. The low injection rates cancelled part of the benefit of retarding the reaction rate of the acid. Also, many people felt it was undesirable to inject liquid hydrocarbon into the gas reservoir. The results of treating wells with this type of viscous acid showed that it was an effective method of getting deep penetration into the reservoir with live acid. So the desirability of a viscous acid with low friction characteristics became apparent. This prompted an intensive research effort into the reaction parameters of acid on these formations at downhole conditions to learn what acid characteristics and injection techniques were most desirable.

In many cases, the wells had been damaged by drilling fluids, cement slurry, and kill fluids. This damage could not be removed because the acid took the path of least resistance into the formation and tended to break through and bypass the damage. This formation damage, coupled with mass perforating and open-hole completion, made it impossible to place treating fluids into all the potentially productive zones. An effective high-temperature/high- productive zones. An effective high-temperature/high- pressure diverting agent needed to be developed to permit pressure diverting agent needed to be developed to permit vertical distribution of the treating fluids throughout the entire open formation interval.

Most of the deeper wells encountered much thicker gross pay sections than the previous wells. This increased the volume of treatments so that the size of a small initial clean-up job became as large as the prior large restimulation treatment had been. The added depth and thicker intervals caused the jobs to last longer, and fatigue began to take its toll in high-pressure pumping equipment. Whereas the mechanical components could stand many repeated high-pressure treatments of short duration, they could not last through very many of the same treatments of long duration. Newer equipment had to be developed.

Those problems that have been satisfactorily solved include:the need for diverting agents, friction reducers, and dependable pumping equipment;treatment design of acid type and fluid volumes; andcorrosion of tubular goods.

Research will continue in the development of (1) viscosity builders for acid; (2) better organic inhibitors; and (3) a high-pressure, high-temperature fluid-loss additive.

The greatest problem at the present time is the lack of mechanical control over the flow of treating fluids in the formation.

Hydraulic Theory

The formations being treated in these deep wells of the Delaware Basin are limestone, dolomite, and chert, an of which have very low porosity and essentially no matrix permeability. They have varying amounts of natural permeability. They have varying amounts of natural fractures and vugs. The few cores that have been retrieved from the deep Ellenburger show both vertical and horizontal intersecting fractures with varying degrees of secondary deposition. However, the higher pressures required to open and extend horizontal fractures have not been encountered in treatments, and it is believed that injection is into the vertically oriented fractures.

JPT

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