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This paper reviews the corrosion management for a critical sour gas pipeline operated by Saudi Aramco. The 38-inch diameter pipeline transports untreated sour gas from Crude Processing Facility (CPF) to downstream Gas Plant and spans a total distance of 145 km. To prevent internal corrosion inside the pipeline, the wet sour gas is dehydrated using Tri-Ethylene Glycol (TEG) unit.
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At present, there were ten common crossing modes in long-distance oil and gas pipelines[1,2]. There were six ways of tunneling, such as large excavation, horizontal directional drilling, shield tunnel, drilling and blasting tunnel, ramming pipe and pipe jacking. There were four ways of spanning methods, such as truss crossing, arch bridge crossing, suspension cable crossing and cable-stayed bridge crossing. Crossing by shield tunneling, as a pipeline laying method with high mechanization and automation, extensive applicable strata and high safety, has been widely used in recent years.
Effects of initial crack aspect ratio, pipeline diameter, wall thickness, and loading conditions on the crack shape development were investigated. A new methodology for fatigue crack growth assessment is demonstrated. The study provides a refinement for more accurate prediction of remaining service life for pipelines.
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.
Corrosion control of buried assets usually involves a double shield: a coating system as a physical insulation barrier, and a cathodic protection system as an additional ad hoc defense. Detection of a corrosion spot at the coating defect stage is the only way to identify the threat before significant metal loss occurs. Furthermore, detection of defects in the coatings of such assets is especially important, since large defects, if left unrepaired, will not only leave the asset locally prone to corrosion, but also drain and weaken the cathodic protection effectiveness for the entire structure. Therefore, identification and characterization of coating anomalies is critical for the integrity of buried assets.
To maintain production levels, oil fields in the Middle East increasingly require water injection to maintain pressure in hydrocarbon reservoirs. The injected water increases the water cut of the produced fluids, resulting in a very corrosive mixture for metallic piping. Therefore, nonmetallic pipe systems have become more widely accepted as alternative pipe materials for transporting produced fluids and injection water.
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.
While dedicated hydrogen pipelines have been present on the Gulf Coast of the US for decades, new application opportunities are opening up for transportation of hydrogen as a greener fuel. Some opportunities may be for newly built transportation lines while others may use existing natural gas pipelines that are converted to wholly or partially carry hydrogen. A normal part of operating a pipeline system is reconfiguring the system to add new pipes by making tie-in welds joining the new pipe to the wall of the existing pipe.
Hydrogen sulfide (H2S) is one of the most common gases in the oil and gas industry. Once dissolved in aqueous environments, H2S can induce corrosion damage to carbon steel. It has been proposed that the severity of the damage is related to parameters such as temperature, partial pressure, microstructure of steel, etc.
Pipeline leak detection is emerging as a prime focus of PHMSA and other regulatory agencies in the United States as well as jurisdictions all over the world. The immense volume of buried pipelines and the fact that much of this buried infrastructure is over forty years old1 combine to present increasing risk of leaks with potentially catastrophic results. During the twenty-year timespan from 2002 through 2021, in the United States alone, the Pipeline and Hazardous Materials Safety Administration (PHMSA) recorded 42 hazardous liquids incidents resulting in 35 fatalities, 80 injuries, and over 147,000 barrels spilled. In many cases the environmental and human health and safety costs could have been reduced if the leaks were detected much earlier.
Pipeline leak detection is emerging as a prime focus of Pipeline and Hazardous Materials Safety Administration (PHMSA) and other regulatory agencies in the United States as well as jurisdictions all over the world. The immense volume of buried pipelines and the fact that much of this buried infrastructure is over forty years old1 combine to present increasing risk of leaks with potentially catastrophic results. During the twenty-year timespan from 2002 through 2021, in the United States alone, the Pipeline and Hazardous Materials Safety Administration (PHMSA) recorded 42 hazardous liquids incidents resulting in 35 fatalities, 80 injuries, and over 147,000 barrels spilled (Figure 1).
During the construction of a 56km long 16 in. carbon steel sour gas pipeline, repetitive surfacepreparation failures were detected during visual inspection of pipeline girth weld internal surface prior tocoating application. Such failures represented 67% of the total pipeline girth welds and were manifestedby excessive sharp-edges at the root pass. To identify the failure causes, an investigation wasperformed through reviewing the pipeline, fabrication and coating application specifications andprocedures, quality control records and performing an extensive visual inspection through an advancedvideo robotic crawler on all pipeline girth welds made. Upon investigation analysis, the failures werecaused by sharp-edges in the root pass which were attributed to improper practices duringmanufacturing, field fabrication and pre-coating quality control. The failure analysis indicated that themechanized Gas Metal Arc Welding process, with the parameters used, was not suitable for internalgirth weld coating application. In addition, a more stringent requirement should be applied to theacceptable pipe-end diameter tolerance and pre-coating quality control to ensure absence of similarpremature surface preparation failures. The pre-coating quality control can be improved throughutilization of robotic laser contour mapping crawler for precise detection and sizing of unsatisfactorysurface weldment defects, including sharp edges.