ASSESSING THE INFLUENCE OF EXTRACTED FLUID AND OPERATIONAL CONDITIONS ON CORROSION OF GAS FIELD EQUIPMENT

Abstract

Background The main intensifier of corrosion at the objects of the studied oil and gas condensate field is carbon dioxide corrosion (CDC). Aims and Objectives Based on the data from well surveys, analyze the factors affecting the corrosiveness of the media: CO2 partial pressure, temperature, reservoir pressure, pH, salinity, and water composition. After compiling the ion balance and recalculating it to the salts used in the manufacture of model solutions of the salts, make up three model waters corresponding to individual and mixed formations for further testing. Results The main danger in CO2 presence is not general, but local corrosion occurring in the fluid flow under conditions when FeCO3 films, although formed, but at low temperatures characteristic for the studied field, they are not stable enough. The appearance of a crack in the FeCO3 film initiates its cleavage, at this point the CDC begins, creating a carbonate film, which with a certain thickness cracks and chips. Some erosions are formed within the other of corrosive areas. Such local corrosion damages are developing, leading to deep (or through) pitting, to damages occupying the big area in interconnection of separate local corrosion defects on an internal surface of elements of a wellhead. Calculations of corrosion damages depth on a flange from a wellhead after removing the corrosion products testify that corrosion depth damages are from 1.0 to 2.5 mm. As the inspections show, the damages made by CDC are observed not only on a well head, but also in pump-compressor pipes of the wells. Operational tests of various grades of steel in the well media, characterized by high CO2 content (up to 1.7 %), showed that most of them are unstable to CDC, with except the alloy steel 12X18N10T. The rate of general (uniform) corrosion reaches several mm/year, including the low-alloy steel 09G2C used for most elements of the wellhead.