Development of High-Pressure Sour Gas Technology
Authors: Hamby Tyler W. 
Published: December 2007

High-pressure sour gas has been produced continuously and safely since 1972 from three fields about 15 miles southeast of Jackson, MS. The wells in these fields are completed in the Smackover formation between 19,700 and 22,250 ft, and the initial bottomhole pressures (BHP's) ranged from 17,500 to more than 22,000 psi. Bottomhole temperatures (BHT's) range from 365 to 385°F. The well fluids consist of 28 to 46% H2S, 3 to 8% CO2, 51 to 69% methane, and no condensate. Water production is about 6 to 8 bbl/Mcf of gas.

The bottomhole conditions and fluid composition of these wells from a hostile environment that has required development of new technology at great cost to safely produce these reserves. This paper reviews the major problem areas encountered and discusses the solutions used during the past 10 years since high-pressure sour gas was discovered. Metallurgical problems, well design, corrosion control, quality control, and safety are discussed.

Introduction

Before the late 1960's, drilling and production experience with high-pressure (&gt;15,000-psi BHP) sour gas was very limited. Probably the most notable experience in the U.S. before that time was the Phillips-Josephine A-1 well in southeast Mississippi. That well was drilled to 20,138 ft, where it encountered a BHP of 13,830 psi and a BHT of 385°F.1

In 1969, Shell Oil Co. discovered higher-pressured (17,500-psi) sour gas near Thomasville, about 15 miles southeast of Jackson, MS. Since that time, Shell has continued to drill in this area and now has three fields (Thomasville, Piney Woods, and Southwest Piney Woods) that produce to a 100-MMscf/D sulfur recovery and gas-processing plant.

The CO2 and H2S content of the produced fluids, coupled with high pressure and high temperature, constitute a very corrosive environment that few materials can withstand. Further, because of toxicity of the H2S and the danger of metal failure as a result of stress corrosion cracking, extreme caution must be taken in selecting materials to drill and produce this type of reserve safely.

A temporary completion was made in the Thomasville discovery well to permit production testing (Fig. 1). The well tested at rates up to 10 MMcf/D of sour gas before completion-equipment failures resulted in temporary abandonment. Analysis of the failures indicated many technical problems in wellhead and well design, selection of materials, elastomer seals, quality control, and other design considerations.

As a result, a task force was established to develop the necessary technology to produce high-pressure sour gas safely. The task force consisted of a group of engineers from production operations, closely backed by a counterpart research and development staff. The group's initial efforts were directed toward (1) designing a well completion that would overcome the deficiencies noted in the discovery well test and (2) development of contingency plans in the event of a sour gas release.

Over the years, problems were resolved and new problems were identified as producing operations began. In general, for purposes of discussion, they can be grouped in general problem areas of (1) metallurgy, (2) well design, (3) corrosion control, (4) quality control, and (5) safety and contingency planning.