Carbon Dioxide Corrosion at Low Partial Pressures in Major Submarine Gas Pipelines

Abstract

SUMMARY OF PAPER This paper describes Shell's approach to the problem of possible corrosion in large diameter pipelines transporting possible corrosion in large diameter pipelines transporting sweet wet gas from offshore fields in the North Sea and elsewhere It is considered unrealistic to attempt to predict such corrosion as may occur by using the rough-and-ready criteria often found adequate, for example in the case of gas condensate wells. To obtain more suitable criteria, several series of laboratory tests have been carried out which have enabled the effect of the main variables to be evaluated. The laboratory results obtained have been compared where possible with cases of corrosion in the field. These tests and their interpretation are discussed. Broadly speaking, it is concluded that corrosion is likely to occur at an unacceptable rate in a wet major submarine pipeline at partial pressures of carbon dioxide lower than those which partial pressures of carbon dioxide lower than those which would be considered acceptable for other facilities. The practical consequence of this, is that the gas has to be dried practical consequence of this, is that the gas has to be dried offshore, and the operational and financial implications are described for the North Sea case. Some remarks are made on the possible use of inhibitors as an alternative to drying and reasons for the rejections of this course are explained. Introduction a) Sweet corrosion in ps-condensate wells, and in associated gathering systems, Ls a well-known phenomenon. While the mechanism of the attack is not fully understood, the factors which influence the rate of the corrosion can be evaluated in a roughly quantitative manner. Inspection methods for wells and gathering systems are available which in many cases enable a check to be made on corrosion intensity and location, and there are more or less effective remedial measures that can be applied. If a failure occurs, it may be serious but it is unlikely to be disastrous. It follows therefore that if some corrosion goes undetected, or if remedial measures prove less effective than hoped, there are not matters for major concern. b) The position with a major submarine pipeline is, however. quite different. The capital investment is very large, and serious corrosion would mean at best a very expensive repair, and at worst loss of the line. In either case there might be heavy contractual penalties for non-delivery of gas. For large submarine pipelines the rough-and-ready criteria (e.g. the often quoted 7 and 30 p.s.i. carbon dioxide partial pressures) sometimes used to predict corrosion in partial pressures) sometimes used to predict corrosion in gas condensate wells should not be applied. Effective inspection is impracticable and monitoring the rate of attack would be of doubtful validity. Furthermore remedial measures applicable to wells and gathering systems do not have sufficient reliability. For the joint Indefatigable to Bacton, 30" by 62.5 mile submarine line. Shell/Esso considered it necessary to obtain, by means of laboratory experiments, data which could be used with a greater degree of confidence than the criteria just mentioned, data which would facilitate taking the decision as to whether or not to go to the considerable expense of drying the gas offshore in order to eliminate the possibility corrosion. (Refer Appendices I and II). possibility corrosion. (Refer Appendices I and II).