On the Local Inner Corrosion of Oil and Gas Pipelines in the West-Siberian Fields and Its Prevention

Abstract

In the course of running of oil-collecting pipelines in West Siberia (the Samotlor field, etc.) in early 1970s, numerous breakdowns of the pipelines were caused by corrosion. At 1995, the total number of the breakdowns resulted in the pipe seal failures came to a few thousands. This gave rise to significant oil losses and was harmful to the environment (vast areas appeared covered with black oil).Quite unexpected for experts and hard in repair were the pipe ruptures occurring mainly in the lower parts of the pipelines, where local corrosion damage occurred as deep and extended grooves in the metal. The grooves were uniformly deepened canals in the lower parts of pipe walls, 40-60 mm wide, 10-15 mm deep, and 800-10000 (or more) mm long. They appeared like manmade grooves cut in a purely mechanical way.According to the pipeline operators, this inner damage mainly occurred in ascending segments of pipelines that transported oil-gas-water emulsion mixtures in a stratified stream mode at a velocity of 0.9 to 1.5 m/s. The water content in the oil emulsions first was 20-22%, then gradually increased up to 50-95%. The concentration of mechanical admixtures in water (iron sulfides, sand) came to more than 100 mg/l. The CO 2 content in the oil-gas-water mixtures was as high as 150-250 mg/l; the hydrogen sulfide content was relatively low (10-20 mg/l). The mineralization of water phase was as high as 10-20 g/l; yet, the technological stability of the oil emulsion from the West-Siberian fields was relatively low, which further resulted in easy water removal during the dehydration process.The surprising feature was that the stratal water extracted from oil wells appeared being low-corrosive: the mean corrosion rate in this water was as low as 0.3 to 0.5 g/(m 2 h) [1-3]. Obviously, this weakly corrosive medium cannot yield pronounced local pipe corrosion for such a short period (1-2 years). Indeed, as a rule, the stratal water from the West-Siberian fields shows low mineralization. These waters are classified as chlorinecalcium type, they contain CO 2 and small amount of hydrogen sulfide of biogenic origin because the stratal media are infected with sulfate-reducing bacteria which gradually (very slowly) saturate the stratal liquid with hydrogen sulfide. However, in the initial stratal media the bacteria activity is low; therefore, they do not produce hydrogen sulfide inside the oil strata. The operating experience suggests that the sulfate-reducing bacteria become active only in the waste-waters recovery system where fresh water containing atmospheric oxygen used to be added with chemicals (de-emulsifiers) and from other sources. It is these conditions under which the active bacteria begin producing hydrogen sulfide from sulfates.Casing-head gas contains CO 2 (up to 6 wt %), which is the product of the bacteria biogenic reduction, and hydrogen sulfide (up to 1.5 mg/m 3 ).One may believe that the oil-gas-water mixture cannot cause any serious corrosion of metal pipes because the content of corrosive components is low. However,...

Evaluation of pipeline corrosion in sour‐gas environment

“…The simulated conditions are akin to what obtains in practice in gas pipelines with additional parameters such as temperature and pressure differentials contributing to the detrimental flow conditions that result in pipeline failure. This situation has proved to be a daunting challenge for experts and especially hard in repair were the pipe ruptures occurring mainly in the lower parts of the pipelines where local corrosion damage occur as deep and extended grooves in the metal (Gonik, 2005). Furthermore, in the presence of even traces of liquid water, CO 2 can lead to severe corrosion-erosion attack when velocities are high (Juan et al, 1993).…”