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51318-11541-Corrosion of Casing Vapor Recovery System in Steam Flooding Operation

Picture for Corrosion of Casing Vapor Recovery System in Steam Flooding Operation
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 Corrosion problems in casing vapor recovery system in a steam recovery processes to optimize corrosion management, considering maintenance, mitigation, inspections, material selection and cost-effective solutions.

Product Number: 51318-11541-SG
Author: Kehinde M. Ogun
Publication Date: 2018
Industry: Oil and Gas Production
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The objective of this paper was to evaluate corrosion problems in casing vapor recovery system from a production field utilizing steam recovery processes with a view of determining the optimum corrosion management approach considering routine maintenance, corrosion mitigation, inspections, material selection and cost-effective solutions. Aqueous corrosion issues in gas gathering and transmission lines are not new to Oil and Gas production and pipeline operators. Produced gas naturally contains carbon dioxide, CO2, hydrogen sulfide, H2S and oxygen as the principal corrosives with the composition of the corrosives varying throughout the life of the reservoir due to shifting formation chemistry and other souring mechanisms such as microbiological activities. Water vapor is produced with the formation fluid or introduced into the formation through enhanced recovery methods such as steam flooding.

Erosion-Corrosion effect resulting from corrosion by-products specifically ‘Black Iron Powder’ was also evaluated. Failure frequency impact on operation and high maintenance costs were the main consideration used to determine the appropriate corrosion mitigation and management strategy.  

Key words: Corrosion, Cost, Well casing, CO2, H2S, Black Iron Powder, Steam Flooding

The objective of this paper was to evaluate corrosion problems in casing vapor recovery system from a production field utilizing steam recovery processes with a view of determining the optimum corrosion management approach considering routine maintenance, corrosion mitigation, inspections, material selection and cost-effective solutions. Aqueous corrosion issues in gas gathering and transmission lines are not new to Oil and Gas production and pipeline operators. Produced gas naturally contains carbon dioxide, CO2, hydrogen sulfide, H2S and oxygen as the principal corrosives with the composition of the corrosives varying throughout the life of the reservoir due to shifting formation chemistry and other souring mechanisms such as microbiological activities. Water vapor is produced with the formation fluid or introduced into the formation through enhanced recovery methods such as steam flooding.

Erosion-Corrosion effect resulting from corrosion by-products specifically ‘Black Iron Powder’ was also evaluated. Failure frequency impact on operation and high maintenance costs were the main consideration used to determine the appropriate corrosion mitigation and management strategy.  

Key words: Corrosion, Cost, Well casing, CO2, H2S, Black Iron Powder, Steam Flooding

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