Previous studies have shown that transmission-quality heavy crude oil carries water-wetted solid particles, that these particles can accumulate on the pipe floor and cause under-deposit corrosion, and that the incidence of accumulation is strongly correlated to locations downstream of over-bends. This paper describes a computational fluid dynamics (CFD) analysis of light and heavy oil flow in a representative segment of a real transmission pipeline in which corrosion has been observed. The purpose was to gain insight into the key processes affecting deposition in heavy oil that do not occur for light oil and to offer suggestions for mitigation. The analysis suggests that the key effect in determining whether particles become trapped is the near-wall velocity of the flow, which is found to be significantly lower for heavy oil compared to light oil, especially downstream of over-bends. This causes particles near the pipe floor to move slowly and makes them susceptible to becoming trapped. It is interesting that the key process affecting deposition is not the tendency of particles to fall to the pipe floor, which occurs more readily in light oil than heavy oil, but, rather, the ability of the flow to keep particles moving along the pipe floor.

Transmission heavy crude oil carries water-wetted solid particles. Studies have shown that these particles can accumulate on the pipe floor and cause under-deposit corrosion and that the incidence of accumulation is strongly correlated to locations downstream of overbends. Computational fluid dynamics (CFD) analysis of light and heavy crude oil flows in a representative segment of a real transmission pipeline suggested that the deposition patterns in heavy oil flow are a result of low near-wall velocity, especially downstream of overbends, which prevents the flow from sweeping particles along the pipe floor, not the tendency of particles to fall to the pipe floor. The objective of the present study was to provide information that would help establish mitigation strategies. The present parametric study used the CFD model to predict the decrease in near-wall velocity at the pipe floor downstream of overbends for different pipe diameters and oil flow rates and properties. This information provided the basis for mapping the transition from light oil behavior to heavy oil behavior. The results were condensed to a chart that provides the reduction in near-wall velocity downstream of overbends as a function of the Reynolds number. It indicated a sharp overbend effect as the Reynolds number decreased below 30,000.

This paper is an exploration of factors affecting internal corrosion of transmission pipeline systems (<0.5% S&W), as well as a progress report on research aimed at improving chemical mitigation of this threat in heavy oil product streams. Typical pipeline corrodents and corrodent transport mechanisms are explored. Transmission quality hydrocarbon products are shown to carry micro-emulsified water, various solid particles, solid particles with micro-attached water, and bacteria. While micro-emulsified water can be considered benign owing its ability to be transported harmlessly without accumulation; water-wetted solid particles have sufficient density to reach the pipe floor. Patterns of internal corrosion on a transmission pipeline are used to demonstrate the significance of solids accumulation leading to under-deposit corrosion. Analysis of pipeline sludge reveals significant populations of different bacterial species indicating the existence of a robust biomass capable of creating or sustaining a corrosive environment. Corrosivity testing of pipeline sludges was performed using two static autoclave coupon methods. One test method demonstrated that the addition of chemical inhibitor directly to the pipeline sludge could reduce corrosion rates as effectively as batch treatment of a clean coupon. A rotating mechanical contactor was designed and built to facilitate the blending of corrosion inhibitor with pipeline sludge under ‘like-pipe’ flow conditions, but results of sludge corrosivity testing using this device are not yet available.

Hydrocarbons transported in transmission pipelines contain solid particles with micro-attached water. Subjected to flow conditions, these particles may have sufficient density to reach the pipe floor and enable bacteria growth and local Under-Deposit Corrosion (UDC), with this form of corrosion being one of the principal threats to the integrity of oil and gas transmission pipelines. NACE International has published a variety of UDC related standard practices to manage corrosion in the oil industry such NACE 61114, but few of them are representative of, or applicable to, low water cut hydrocarbon transmission pipelines. Further, there are presently no industry recognized key performance indicators (KPIs) suitable for managing UDC in low water cut hydrocarbon transmission pipelines. Enbridge (the “Company”) operates North America’s largest interconnected liquid hydrocarbon transmission pipeline network. For the purposes of this paper, when the word ‘transmission’ is used to modify ‘crude oil’, ‘hydrocarbons’, or ‘pipelines’, it implies medium to long distance transport (100’s to 1000’s of km) as well as clean, “refinery-ready” crude oil (oil containing less than 0.5% sediment and water). This quality of oil renders it generally non-corrosive at pipeline operating conditions. However, if water wet particulates accumulate on the pipe floor, it can lead to UDC. The Company collects sludge samples produced during pigging operations on a regular basis to establish the composition of these materials and quantify bacterial population/activity. These solids represent an amalgamation of material removed from the pipe floor, and thus can be used as an indicator of the UDC threat in the pipeline. This paper builds upon previous work of the Company [1] by considering a larger data set in order to generate a more meaningful assessment of bacteria population/activity and provide better correlations with crystalline compounds, water content and elements found in the sludge. This paper presents these data and associated statistical analysis, and proposes KPIs for evaluating the UDC threat based on numerous variables, including in-line inspection Magnetic Flux Leak (MFL) data (through signal to signal corrosion growth rates), sludge analysis, flow conditions and pipeline operation; this paper also suggests mitigation activities and intervals relative to these KPIs. Personnel involved in pipeline integrity management (e.g. field operations, technical and management staff) may find the concepts, strategies and correlations presented herein to be useful in developing their own UDC management programs.

Strength and leak testing (AKA ‘hydrotesting’, and ‘pressure testing’) of pipeline projects remains a primary method of providing quality assurance on new pipeline construction, and for validating structural integrity of the as-built pipeline [1][2][3]. A myriad of regulations surround these activities to ensure soundness of the pipeline, security of the environment during and after the pressure testing operation, as well as personnel safety during these activities. CAN/CSA Z662-11 now includes important clauses to ensure that the pipeline designer/builder/operator consider the potential corrosive impacts of the pressure test media [4]. This paper briefly discusses some of the standard approaches used in the pipeline industry to address internal corrosion caused by pressure test mediums — which often vary according to the scope of the pipeline project (small versus large diameter, short versus very long pipelines) — as well as the rationale behind these different approaches. Case studies are presented to highlight the importance of considering pressure test medium corrosiveness. A practical strategy addressing the needs of long-distance transmission pipeline operators, involving a post-hydrotest inhibitor rinse, is presented.