Produced fluids from many oil and gas wells carry sand, and solids from the geologic reservoir, which can be left behind as deposits on the interior of production equipment, particularly piping. These deposits become a diffusion barrier between the produced fluids and the interior pipe wall, which results in a water chemistry near the steel surface very different from that in the bulk fluids. This is a particular problem in a stratified flow regime where deposits of solids accumulate in the bottom of a pipeline.

A previous under deposit corrosion (UDC) study showed higher under deposit corrosion rates for API X-65 carbon steel when the deposit consisted of iron sulfide (FeS) than for sand in a 50%H2S/50%N2 environment. In addition to only H2S, when acid gases (H2S and CO2) are present in the system the corrosion mechanism becomes more aggressive due to lower pH of the environment.

The combined effect of H2S and CO2 on UDC and its morphology, corrosion rates and galvanic action is significant. The corrosion rate and coupon thickness loss of API X-65 carbon steel under FeS deposits are higher than under sand deposits tested at same conditions, i.e., 14-day exposure at 100°F (37.8°C).

Subject
Sand, Corrosion rate, Iron sulfides, Steel coupons, Under deposit corrosion, Thickness loss, Acidity, Corrosion scales, Fluids, Scale, Carbon steel, Corrosion coupons, Deposit corrosion
Keywords:
Under deposit corrosion, Iron sulfide (FeS), sand, mill scale, hydrogen sulfide, carbon dioxide
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2019
Association for Materials Protection and Performance (AMPP)
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