Corrosion Control - Deep Sour Gas Production

Abstract

Abstract Corrosion in deep high pressure sour gas wells can be successfully controlled. Many problems have been encountered in producing Shell's high pressure sour gas wells producing Shell's high pressure sour gas wells in the Thomasville, Piney Woods, and Southwest Piney Woods Fields. Corrosion was one of these Piney Woods Fields. Corrosion was one of these major problems. A hole developed in the tubing of one well approximately five months after production was started and a hole developed in a second well shortly thereafter in spite of continuous inhibition. This paper briefly describes both the successful inhibition program that has been developed since these initial failures and the potential for improved inhibition systems. The cost in workovers, lost wells, and operating expenses since the initiation of production of these wells has been $28 million production of these wells has been $28 million greater than it would have been if the current inhibition system would have been available when production was initiated. production was initiated Introduction The purpose of this paper is to review the characteristics of a successful corrosion prevention system used in Shell's deep, high pressure, high hydrogen sulfide gas production in Mississippi. However, some introductory material is in order before corrosion prevention technique and corrosion prevention results are reviewed. prevention results are reviewed. In 1969, Shell discovered the Thomasville Field about 15 miles Southwest of Jackson Mississippi. Currently, Shell produces approximately 100 millions cubic feet per day from the three adjacent fields Thomasville, Piney Woods, and Southwest Piney Woods to a sulfur recovery and gas dehydration plant. Further reference in this paper to "Thomasville" will refer to wells in these three in the Smackover formation between 19,700–22,250 feet and the initial bottom hole pressures range from 17,500 psi to 22,000 psi. The pressures range from 17,500 psi to 22,000 psi. The production at these fields in sour gas, and is production at these fields in sour gas, and is completely free of liquid hydrocarbons. The produced gas, in combination with produced water, is very corrosive; it contains between 28% and 46% hydrogen sulfide, between 3% and 8% carbon dioxide and between 51% and 65% methane; the gas contains trace amounts of ethane, nitrogen, and other sulfides. There are no hydrocarbon components heavier than ethane in the gas. Water production is about 6–8 barrels per million cubic feet of gas and salinity ranges from fresh to brackish. Each well is equipped with a circulating string (tubing) and does not have a packer (Figure 1). The casing is the pressure string. From the start of production, oil and inhibitor were circulated in production, oil and inhibitor were circulated in each well to prevent sulfur deposition and corrosion. In spite of continuous inhibition, severe corrosion caused two tubing strings to part and caused a hole in the third tubing string. The first hole in the tubing occurred in about five months after initiation of production. production. In an effort to explain the above failures and the current solution, 1) the corrosion mechanism, 2) Oil phase behavior, 3) Inhibition system, and 4) Inhibition results will be respectively discussed. The value of successful corrosion prevention and potential for improvements in sour gas inhibition potential for improvements in sour gas inhibition will also be reviewed. CORROSION MECHANISM The corrosion mechanism results in the forming of "scabs" of iron sulfide corrosion product. The formation of these "scabs" involves both the H2S and the chloride ion. The thin chloride film (see Figure 2) in an acid gas environment contains hydrochloric acid (HC1). The HC1 reacts with the tubular to form an iron chloride.