The goal of this compilation is to educate the reader through experiences and observations from real-world applications and to provide tools for the identification and remediation of pipeline corrosion issues before failure. Pipelines have been used to transport fuels since the 19th century. While there is no clear consensus of the total number of pipeline miles in use throughout the world, most agree that the U.S. has over 2.5 million mi of energy pipelines. This book provide tools for the identification and remediation of pipeline corrosion issues before failure.
2018 NACE e-book
According to a survey of corrosion releases in hazardous liquids pipelines, of the 52 internal corrosion releases reported in 2009-2012, 31 occurred in intermittently operated lines. Pigging operations cannot be performed in many of these pipelines for a number of reasons, such as limitations imposed by pipeline design features, pigging cost, risk of the pig getting stuck in solids or sludge accumulated in front of it. For unpiggable pipelines, direct assessment using the liquid petroleum internal corrosion direct assessment (LP-ICDA) method is a widespread industry practice that helps operators detect pipeline sections damaged by internal corrosion. The models and correlations referenced in the standard are for steady-state, oil-water flow or liquid-solids flow, however the flow of transported fluids is transient (unsteady) in intermittently-operated, crude-oil pipelines. Furthermore, the critical inclination angle defined in the standard is applicable to a pipeline having a piecewise elevation profile. Nevertheless, the local slope of the pipeline changes continuously along its entire length because the local slope of an elevation profile of the landscape or seabed changes continuously in most cases. In this paper, a pipeline diagnostic survey using transient, ultra-high definition simulations of three-phase oil-water-solids flow is performed to identify ICDA regions and develop solutions to extend the useful life of a 48-in. diameter pipeline transporting crude oil from an onshore tank farm to a Single Point Mooring/Pipeline End Manifold (SPM/PLEM) system. Transient free water and solids holdup profiles along the pipeline during loading operations and shutdown periods were predicted based on historical cargo data (including detailed loading plans and loading rates), basic sediments and water (BS&W) data, the rate of conversion of emulsified water into free water caused by the residual concentration of demulsifier in crude oil, solids properties, and tanker loading schedules. It was found that significant accumulations of free water and solids occurred only in a few sections of the offshore portion of the pipeline. This was attributed to the fact that in each loading operation the cargo officer requests the terminal to reduce the loading rate and adjust it until the final cargo transfer quantity is reached. As a result, during this time the pipeline is operated at a low flow condition at which free water ceases to enter PLEM, while it is still displaced from the onshore portion into the offshore portion of the pipeline. Two solutions were proposed to prevent microbiologically influenced corrosion (MIC) and extend the useful life of the pipeline. The first solution is based on the optimization of the loading plan to minimize the volume of free water accumulated in the offshore portion on completion of cargo transfer. In the second solution, a system generating batches of drained water taken from the storage tanks is connected to the pipeline inlet. A biocide is injected into the water batches. The concentration of the biocide and speed to kill are selected based on the water batch residence time determined using the transient flow simulations. The number of water batches to be launched depends on the volume and properties of solids that can enter the pipeline.
Upstream oil and gas companies operate oil gathering systems comprising a flowline network and process facilities that transport the flow of produced fluids from the wells to a main processing plant. The frequency of corrosion related leaks has increased recently despite a corrosion inhibitor is injected at the wellhead into all flowlines. A root-cause analysis conducted by several companies revealed that severe internal corrosion was caused by a low fluid flow velocity an increasing water cut and the presence of sulfate-reducing bacteria (SRB) in the production streams. Nevertheless it was not clear why some of the flowlines may leak while others do not leak despite the composition of produced fluids principal design parameters (diameter and length) dosage of corrosion inhibitor and environmental conditions of the flowlines are similar. A diagnostic analysis of different oil flowlines of was carried out to gain an understanding of why a first group of oil flowlines is developing leaks and why a second group of flowlines has not experienced leaks. The methodology used for the diagnostic analysis comprises 1) Ultra-High Definition simulation of 3-phase or 4-phase flow of gas oil water and solids; 2) 3D imaging of phase distributions inside critical sections of the oil flowlines as per NACE ICDA; 3) mapping adverse operational conditions; and 4) the determination of probability of failure in the critical sections based on criteria depending on the severity of operating conditions inside and outside the flowlines. It was found that multiple sections were exposed to stagnant water and/or had a fraction of internal surface area covered by a stationary bed of solids (formation solids produced from the well). The identified causes of potential leaks comprise the following failure mechanisms: a) metal loss caused by colonies of SRB b) composed load acting on the pipe wall and c) cyclic" thermal expansion/contraction of the flowlines due to seasonal ambient temperature variations. One of the surprising findings of this study was that a shorter flowline with a lower water cut may have multiple leaks while a longer flowline with a higher water may not leak at all approximately for the same period after commissioning. This result was explained with help of maps of adverse operational conditions constructed for the two groups of flowlines. Immediate corrective mitigation actions and preventive actions were implemented to reduce leak frequency including the installation of a novel automatic flushing system.
Offshore oil production facilities are subject to internal corrosion, potentially leading to human and environmental risk and significant economic losses. Microbiologically influenced corrosion (MIC) and reservoir souring are important factors for corrosion-related maintenance costs in the petroleum industry.1 MIC is caused by sulfate-reducing prokaryotes (SRP), which can be Bacteria (SRB) or Archaea (SRA), with the main focus in literature being on SRB.2–5 The microorganisms most frequently reported in literature to be responsible for MIC are the SRB; Desulfovibrio, Desulfobacter, Desulfomonas, Desulfotomaculum, Desulfobacterium, Desulfobotulus, and Desulfotignum, and methanogens.2,5
Uncontrolled growth of microorganisms in the oil field production systems have a major negative impact on the productivity and asset integrity in oil and gas industry. Sulphate-reducing bacteria (SRB) have been found as the most troublesome group of microorganisms among all organisms involved in MIC of carbon steel and other metals used in the oil industry (Abdullah et al 2014). The formation of SRB biofilm on steel surface can affect the kinetics of anodic and cathodic reactions, leading to an acceleration of steel corrosion (Beech and Sunner, 2004: Zuo,2007). In addition to that, SRB contributes to hydrogen sulfide-driven reservoir souring, increased suspended solids, reservoir plugging, etc., in oil field sites.
Pre-commissioning hydrostatic testing of pipelines and the resulting corrosion (MIC) issues are often linked to test water quality, as well as post-test cleaning operations. In a 1998 study, it was reported that localized corrosion (pitting/crevice corrosion) accounted for 20% of failures in the chemical process industry with an estimated one half of those being MIC failures. Identification of MIC failures is not straightforward. Common characteristic features such as pit clustering, “tunneling” of pits, tuberculation, high microbiological counts, presence of sulfides (in the case of sulfate reducing bacteria (SRB)) and preferential weld attack have been used to anecdotally pinpoint field failures towards MIC.
A leak suddenly occurred at the 24-inch common crude piping from the separators heading to the degassing boot inlets and the wet crude tanks in an oil gathering center. The initial observations showed the leak was due to a deep isolated pit and localized corrosion. Additional inspections by manual ultrasonic thickness (UT) and long range ultrasonic thickness (LRUT) measurements for the 24” common crude line showed similar deep isolated pits (up to 70% thickness reduction) scattered across the length of the 1100 meter piping.
Microbiologically influenced corrosion (MIC) is one of the leading causes of equipment and pipeline failure in oil and gas industries. Cost-effective MIC management requires routine monitoring of microbial activities, periodic assessment of microbial risks in various operational systems, and accurate diagnosis of MIC failure. Traditionally, MIC diagnosis has been dependent on cultivation-based methods by inoculating liquid samples containing live bacteria into selective growth media, followed by incubation at a certain temperature for a pre-determined period of time. The conventional culturing techniques have been reported to severely underestimate the size of the microbial populations related to metal corrosion, among many inherited weaknesses of these techniques. As a result, accurate diagnosis of MIC failure is challenging because the conventional techniques often fail to provide a critical piece of evidence required for a firm diagnosis, i.e., the presence of corrosion-causing microorganisms in the failed metal samples. In this paper, we described applications of molecular microbiology methods in diagnosing MIC in a crude oil pipeline and crude processing facility. Molecular microbial analyses have provided a solid piece of evidence to firmly diagnose the MIC in a crude oil flow line, a stagnant bypass spool, and a global valve bypass pipe. The presence of a high number of corrosion-related microorganisms in upstream pipelines poses a high risk to downstream crude processing facilities for microbial contamination and corrosion failure in these facilities. An effective MIC management program should include routine monitoring of microbial activities and risk assessment, and effective mitigation program, such as scraping and biocide treatments.