American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. 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. Abstract In certain producing fields in the United States, Canada and other countries with severe corrosive conditions, special downhole equipment installations have been developed to meet the requirements of production and stimulation. This paper classifies corrosive well conditions and associated theoretical considerations, and describes packer and tubing equipment being successfully used for these conditions. Certain guide lines are established for designing completions for a wide range of corrosive conditions in producing wells. Introduction Throughout the producing areas of the world, a variety of special equipment is employed to combat corrosive well conditions. The design of special packers and tubing strings is dictated by the nature and severity of the corrosive environment in addition to the normal requirements of production or injection. Corrosive environments consist primarily of produced fluids containing varying amounts of H2S produced fluids containing varying amounts of H2S and CO2 at a wide range of pressures and temperatures. Even so, there Is enough similarity of downhole conditions, such that, classification of successful equipment installations has been very helpful in designing equipment for other corrosive areas. So many corrosive producing formations require stimulation by acidizing or fracturing to improve production. Rig time can be saved by equipping the well to stimulate after initial completion. Special equipment has been developed to permit tubing expansion during stimulation and accommodate inhibitor injection while on production. production. TYPES OF CORROSIVE WELL CONDITIONS Corrosive conditions in producing wells can usually be described as sour or sweet corrosion. Sour corrosion is due to hydrogen sulfide in production, while sweet corrosion is primarily a production, while sweet corrosion is primarily a result of carbon dioxide in produced fluids. H2S Conditions In the presence of moisture, H2S in production can result in iron sulfide corrosion and hydrogen stress cracking. Iron sulfide is a general corrosion which appears as a black powder or scale on exposed steel surfaces. Hydrogen stress cracking is a failure of high strength steels due to hydrogen embrittlement which can occur without visible corrosion damage. It has been found that only a trace of hydrogen sulfide is necessary to cause hydrogen stress cracking. CO2 Conditions When CO2 and water are present in production, a resulting acid condition may cause iron carbonate corrosion. Damage to well equipment normally takes the form of deep pitting where corrosion-erosion occurs.