Fluid flow effects on CO₂ corrosion: a review of applications of rotating cage methodology

Abstract

Purpose Among the many influencing effects that the medium has on the CO2 corrosion of carbon steel, flow is one of the most important because it can determine the formation of corrosion product scales and its stabilisation, thus influencing the attack morphology and corrosion rate. This paper aims to summarise some factors affecting aqueous CO2 corrosion and the laboratory methodologies to evaluate one of the most important, the flow, with an emphasis on less costly rotating cage (RC) laboratory methodology. Design/methodology/approach Regarding the key factors affecting CO2 corrosion, both well-established factors and some not well addressed in current corrosion prediction models are presented. The wall shear stress (WSS) values that can be obtained by laboratory flow simulation methodologies in pipelines and its effects over iron carbonate (FeCO3) scales or inhibition films are discussed. In addition, promising applications of electrochemical techniques coupled to RC methodology under mild or harsh conditions are presented. Findings More studies could be addressed that also consider both the salting-out effects and the presence of oxygen in CO2 corrosion. The RC methodology may be appropriate to simulate a WSS close to that obtained by laboratory flow loops, especially when using only water as the corrosive medium. Originality/value The WSS generated by the RC methodology might not be able to cause destruction of protective FeCO3 scales or inhibition films. However, this may be an issue even when using methodologies that allow high-magnitude hydrodynamic stresses.

Impact of Flow on the Development of Iron Sulfide and Iron Carbonate Layers

“…Even though the condition under the dynamic regime did present a relatively low corrosion rate after 24 h (Figure 2), the corrosion product layer formed on the surface could not promote a greater capacitive character as observed under the quiescent regime. This assumption agrees with previous works that have found the same characteristics for mixed and porous coverage played by corrosion products 13,23 .…”

“…Under the quiescent condition, the corrosion rate measured by using LPR started at 0.05 mm/y and gradually decreased to 0.028 mm/y after 24 hours of the test. This reduction in the corrosion rate is associated in the literature with the precipitation of corrosion products 13,23,30 . The formation of iron carbonate during the test was confirmed by comparing the corrosion rate values obtained by weight loss of 3.23 mm/y with the values obtained by the LPR measurements.…”

“…Another flow effect discussed in the literature is the mechanical action of the hydrodynamic shear stress on the wall 11,12 . However, commonly observed wall shear stresses in multiphase pipelines (1 Pa-1kPa) are several orders of magnitude lower than the adhesion strength values of corrosion product layers (1 -100 MPa) [13][14][15] . Thus, it is doubtful that multiphase flow can mechanically remove a dense and compact corrosion product layer.…”

“…In conditions where the formation of corrosion products with protective characteristics is not thermodynamically stable (generally at low temperatures and pH), the effect of increasing fluid velocity is very evident 13 . Under these conditions, higher speeds mean an increase in the mass transfer of electroactive species to the steel surface, thus accelerating the corrosive process.…”

Carbon Capture and Storage in Depleted Oil and Gas Reservoirs: The Viewpoint of Wellbore Injectivity

“…The majority of studies on carbon capture, and storage (CCS) focused on assessing the storage potential of deep saline aquifers; however, oil and gas reservoirs, despite their relatively smaller storage potential, are ideal for CCS owing to their high capacity, containment, reservoir structure, and surface facilities that can be adapted for CO 2 storage operations [3,4,27,38]. However, it should be noted that oil is considered as a hydrophobic fluid and has no harmful effect on pipeline walls, but CO 2 is a moisture content that in contact with water causes sweet corrosion in pipelines [39][40][41][42][43][44]. The facilities already existing are designed for hydrocarbons so it makes the CO 2 corrosion a significant problem in oil and gas production and transportation facilities that the cost of remediation can be higher than replacing the facilities [41,42,[45][46][47].…”