Asset owners spend significant monies each year on the construction of new and the maintenance of existing infrastructure. More than ever, these funds can be difficult to procure and budget. The owners include, both municipal and industrial entities and funds are limited in most cases, therefore, asset service life is very important to all parties.
In the mid-1990s, the US Navy’s technical community, led by Naval Sea Systems Command (NAVSEA), recognized existing coatings used to protect the inside of ships’ tanks were failing on average 5-8 years after application. The high cost to blast and recoat over 11,000 tanks every 5-8 years, not counting submarines and aircraft carriers, was prohibitive. To address this issue, the Navy conducted a study to analyze the problem and decided to replace these legacy coatings with high solid epoxy coatings.1
Canada's oil sands are the third largest deposit of crude oil in the world, and consist of a mixture of sand, water, and bitumen. Due to an aggressive operating environment that includes abrasive sands and corrosive chemicals, oil sands equipment and process piping often experience severe wear and erosion-corrosion, which can lead to the risk of equipment failures, plant downtime or, even worse, environmental leaks . For more than half a century, oil sands producers have collaborated with materials suppliers, equipment fabricators, and technology providers to develop wear technologies to reduce downtime and improve operational reliability.
Various aspects of the mechanism of C02 corrosion are reviewed, together with a discussion about the validity of a number of simplifications which can be used with models for predicting the corrosion rate. A "worst case" rate can often be predicted. To this end a number of parameters has been identified, the
influence of which has to be accounted for. The effects of protective corrosion product layers and of dissolved corrosion product on pH needs to be included in the prediction. More quantitative information about the effect of flowpattern and flowrate is needed. For wet gas pipelines, the prediction of the effect of injection of glycol as a measure against corrosion is of special interest. Predictive models consisting of a system of rules and equations can be conveniently developed in computer spreadsheets.
Oil field operating company’s (1) flowline network in North and West Kuwait (NWK) has over 3000 wells connected through 6” carbon steel pipelines flowing from wellhead to the nearest Gathering Center (GC). Untreated wet crude is transported through the flowlines to GC’s directly or passing through the Remote Headers and Manifold (RHM) to GCs. In RHM, mixing of the wet crude takes place before it is sent to GC’s via transfer lines for further separation. The flowlines are laid aboveground except at road crossings where they are buried.
Caustic corrosion is sometimes referred to as “caustic attack or “caustic gouging.” Corrosion of this type may result from internally fouled heat transfer surfaces and the presence of sodium hydroxide in the boiler water; and concentrated solutions of alkali where the normal washing of the tube metal ID is restricted after Departure from Nucleate Boiling (DNB), i.e., when the steam bubble release exceeds the rinsing rate.
The pitting corrosion and crevice corrosion of oilfield production alloys (e.g., 13Cr/UNS S41000, 17-4PH/UNS S17400, 25Cr/UNS S32750, A286/UNS S66286, 718/UNS N07718) and proprietary austenitic stainless steels for directional drilling (PREN between ~20 to ~45) has been investigated. Specifically, series of electrochemical tests have been conducted to rank the alloys, establish simple correlations between electrochemical parameters, PRENmod, and 3-to-60-day immersion tests in 3.5% NaCl at ambient temperature. For all but one alloy, pitting was absent in stark contrast to crevices. Upon tracking populations and dimensional characteristics of crevices over time, trendlines comparing the susceptibility of the alloys towards crevice corrosion were established. Practical conclusions were reached, including the following: (1) 13Cr consistently developed crevices within days, (2) 17-4PH as well as all traditional directional drilling stainless steels developed crevices within one to five weeks, and, (3) neither 718, 25Cr, nor newer directional drilling alloys with both high nickel and high PRENmod showed any sign of crevices upon being tested up to 60 days. Through a variety of comparisons, this investigation also reveals useful technical directions for the development of new, economical, and fit-for-service Oil & Gas alloys for both production and drilling.