Acid Corrosion in Wells (CO2, H2S): Metallurgical Aspects
- Jean-Louis Crolet (SNEA (P))
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- August 1983
- Document Type
- Journal Paper
- 1,553 - 1,558
- 1983. Society of Petroleum Engineers
- 4.6 Natural Gas, 5.4.10 Microbial Methods, 4.2.3 Materials and Corrosion, 3.2.4 Acidising, 4.3.4 Scale
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Crolet, Jean-Louis; SNEA (P)
The problems of acid corrosion in the wells are in a perpetual evolution. For CO2 corrosion, the solution of using 13% Cr production tubings seems to have rapidly expanded, production tubings seems to have rapidly expanded, and a quick summary of our own experience is given. The difficulty lies essentially in accurately forecasting when stainless steel will be necessary and when the CO2 corrosion of standard tubings will remain acceptable. For H2S corrosion, the differences between the traditional SSC problems and the new SCC ones are emphasized.
In the oil and gas industry the increasing cost of energy since 1973 has basically modified the terms and the solutions of corrosion problems. In particular, it is now very unlikely for a well to be closed merely because of the effluent corrosivity. Indeed practically all the available means to fight internal corrosion have reached their threshold of economic profitability. The only remaining question is to choose the most suitable one and to ensure that it is a technological success. Furthermore, the increasing cost of energy has also resulted in a spectacular development of offshore production. Thus, increased safety requirements and the enormity of investments lead to an ever growing need for prevision, as accurately as possible, of the corrosion behavior of the plants. Simultaneously, the trend towards the reduction of offshore personnel, and then of the monitoring, which is inherent in techniques of inhibition, strongly supports the production engineers in their wish to solve corrosion problems in wells by using corrosion resistant materials alone. Naturally, the choice of materials for tubings and casings is the most important aspect of this evolution. The aim of this paper is thus to take stock of the present technology and of expected evolution concerning the two main corrosion problems in the wells, namely: - CO2 corrosion, that is the problems of metal dissolution and of tubing break through in H2S free, CO2 fields. - H2S corrosion, that is the problem of sudden cracking of the tubings and casings in H2S fields.
2. CO2 CORROSION
CO2 corrosion in the wells was first reported in the 1940's, in Louisiana and Texas. At the present time it is also encountered in the Netherlands present time it is also encountered in the Netherlands and Germany, in the North Sea, in the Gulf of Guinea, and in California. CO2 corrosion concerns both gas wells and oil wells. Its extent depends indeed upon the action of a very large body of parameters (temperature, pressure, CO2 content, BSW, water analysis, flow conditions etc). In this respect, the best published studies still remain the ones carried out in the United States by the NACE around 1950. Beyond the diversity of facies and of environmental conditions, the CO2 corrosion of steels is basically a very localised corrosion which appears in the form of pits, gutters or attacked areas of various sizes. Where the localised attack occurs, the penetration rate of the corrosion is quite high, reaching very commonly several mm/year. Normally, apart from these affected areas, the dissolution rate remains rather limited. The transition from an affected to an unaffected area is most often very abrupt. It is very difficult to gauge the amount of CO2 corrosion in advance, since there are numerous exceptions to the usual rule: "No noticeable corrosion for CO2 partial pressure up to 0.05 MPa, severe corrosion over 0.2 MPa". So, to summarize, the two main concerns at this time are actually the forecasting of the corrosion of standard tubings and the use of stainless steel tubings.
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