This paper presents new applications of Volatile Corrosion Inhibitors (VCI) inside new and/or existing out-of-service pipelines. The system utilizes a combination of soluble and volatile corrosion inhibitors that are directly applied into the pipeline. In some cases, the decrease in the corrosiveness of environment is done by increasing the pH. Different approaches are discussed depending on pipeline design and operating considerations of the owner. A recurring issue during the construction and commissioning, and sometimes operation, of facility pipe (pump station and terminal) assets is the creation of internal corrosion threats due to leftover hydrotest water or product. Available methods for removing the water or product entirely, or applying inhibitor chemicals to the hydrotest medium or product, are time-consuming and expensive. In 2015, 2016, and 2017 VCI chemicals were applied to various facility piping systems in lieu of other methods which would mitigate internal corrosion threats. This method, while not a best-practice in the oil and gas industry at the time, was shown through laboratory testing to be effective at mitigating both biological and generalized internal corrosion. The application of VCI was also proven to be safe for the personnel involved, which was one of the original objections of the operator, and the application process resulted in significant cost savings at the time of commissioning. This paper details a single preservation project as an example.
Internal corrosion in metal pipelines is one of the greatest time-dependent threats affecting newly constructed, deactivated, or idled assets. New construction presents additional variables, such as leftover uninhibited hydrotest water, that increase the risks associated with internal corrosion. In mainline pipe that can be cleaned, inhibited, and inspected with inline tools and devices launched from traps, there are a multitude of ways to mitigate the risks presented by internal corrosion. However, with facility pipe, internal corrosion threats - especially from leftover hydrotest water where the pipe was not internally lined - are compounded by configurations that make owners unable to clean, inhibit, or inspect with inline tools (in most cases). In the case of buried facility pipe, external direct inspection is not possible to prevent leaks or ruptures, the consequence of which could be worsened by an inability for local staff to inspect visually, and the lack of leak detection equipment that would otherwise be present for a mainline system and thoroughfare facility pipe.
A proposed method for Liquid Petroleum Pipeline Internal Corrosion Direct Assessment (LP-ICDA) has been developed that is consistent with the general principles of other Direct Assessment (DA) methods. The scope of LP-ICDA complements those of dry gas ICDA (DG-ICDA) and wet gas ICDA (WGICDA).
LP-ICDA (as with other DA methods) is intended to serve as an integrity verification tool, playing the same role within pipeline integrity management as in-line inspection (ILI) and hydrotesting (either as a replacement or as a complement). The method relies on 1) identifying a mechanism for corrosion susceptibility, 2) detecting a property associated with this mechanism through an indirect measurement, 3) performing a direct observation of the pipe (e.g., by excavation), and 4) correcting for any discrepancies between the predictions and observations.
The underlying basis of the proposed approach is simple; corrosion in liquid petroleum pipelines is most likely where water and/or solids accumulate. Secondary factors affecting the distribution of corrosion between locations of water and solids accumulation are also considered.
Liquid product transmission pipelines are defined as pipelines that are fully packed with a liquid phase (i.e., no significant gas phase). Water content in crude oil is typically specified by "basic (or bottom) sediment and water" (BS&W) of less than 1% (sometimes 0.5 or 0.35%), and refined product or hydrocarbon condensate specifications are typically more stringent.
Direct assessment methodology (DA) has been developed for the purpose of performing pipeline integrity verifications, especially for pipelines that are not able to accept inline-inspection (ILI) tools. DA development was initially driven by a need to meet pending changes to U.S. natural gas transmission pipeline regulations. DA also has applicability to the pipelines carrying other products. External corrosion DA (ECDA) and Stress corrosion cracking DA (SCCDA) have been developed for the buried pipelines. The prediction applicability of ECDA and SCCDA does not depend upon the product being transported, except that pressure fluctuations can differ between liquid and gas systems, and SCC susceptibility can be affected.
The basis of DA is that 1) a mechanism for susceptibility is identified (i.e., preassessment), 2) a property associated with this mechanism is used as a basis for detecting susceptibility (indirect inspections), 3) direct observations are made to verify the correlation between the property and mechanism (direct examinations), and 4) corrections are made for any discrepancies (i.e., postassessment).
Internal Corrosion Direct Assessment (ICDA) is a process that can be used to assess pipeline integrity, based on identifying areas along the pipeline where internal corrosion is most likely to exist. The process identifies the potential for internal corrosion caused by microorganisms, fluid with CO2, O2, H2S or other contaminants present in the carrying fluid. The ICDA methodology is a four-step process requiring integration of pre-assessment and indirect inspection data, with detailed examinations of the internal pipeline surface.
A method to assess internal corrosion in normally dry natural gas systems has been developed and termed Dry Gas Internal Corrosion Direct Assessment (DG-ICDA).
Bachman, Susie (Intergen) | Chmilar, Bill (TransCanada Pipeline Ltd) | Ellul, Ivor (Knowledge Reservoir Inc.) | Goodman, Mike (El Paso Corporation) | Goodreau, Mary (Stoner Associates Inc.) | Nicholas, Ed (Nicholas Simulation Services) | Pietsch, Ulli (Enbridge Pipelines)