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Zav'yalov, V. V.

doi:10.1023/a:1023975422504

Cited by 10 publications

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“…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][2][3]. Obviously, this weakly corrosive medium cannot yield pronounced local pipe corrosion for such a short period (1-2 years).…”

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“…However, when even a small spot of this protective film was deteriorated in the lower part of pipe, it converted to an intensely dissolving anode. It was shown [1,3] that the potential difference in such a galvanic macropair may be as high as 200 mV and more; this explains, to a first approximation, the rapid corrosion in the pipes' lower parts. However, it was unclear, what process can remove the protective film from some areas and why the film cannot recover or why it was steadily removed from the lower parts of pipes.…”

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“…It was assumed in 1980s (and relied upon in [3]) that the formation of deep grooves in pipes is related to a near-bottom motion of abrasive species (e.g., quartz sand) along the pipes' lower generatrix. However, to match the real situation, the author had to raise one more hypothesis: the wearing effect of sand particles is weaker in horizontal and descending segments of pipelines where the particles move down the stream, than in ascending segments where they move back and forth.…”

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“…It is known [1][2][3] that water-enriched emulsion containing CO 2 and small admixture of hydrogen sulfide and transported via the West-Siberian oil and gas pipelines, as well as the water proper in the oil-water-gas medium, are not highly corrosive (the corrosion rate comes to only 0.4 to 0.5 g/(m 2 h)). Actual pipe corrosion rate is still lower because the surface is covered with the iron-carbonatesulfide film that is relatively weakly permeable for the medium and, hence, somewhat protects the base metal of tubes.…”

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“…The entire surface with undistorted film (that is, 90-95% of the surface) serves as the cathode, while the naked lower part of the pipe (5-10% of the cathode surface area) becomes the anode; it corrodes at a rate of 5-10 and more g/(m 2 h), because the potential difference in the pair may reach 200 mV [1][2][3].…”

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

Gonik¹

2005

Prot Met

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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,...

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