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Picture for Detecting and Preventing Internal Corrosion Damage in Unpiggable, Intermittently-Operated, Crude-Oil Pipelines
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Detecting and Preventing Internal Corrosion Damage in Unpiggable, Intermittently-Operated, Crude-Oil Pipelines

Product Number: 51320-14673-SG
Author: Yuri Fairuzov, Victor Fairuzov
Publication Date: 2020
$20.00

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.   

Picture for Diagnosis of Internal Corrosion in Pipelines Based on Mapping Adverse Operational Conditions
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Diagnosis of Internal Corrosion in Pipelines Based on Mapping Adverse Operational Conditions

Product Number: 51319-13250-SG
Author: Yuri Fairuzov, Victor Fairuzov
Publication Date: 2019
$20.00

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.

Picture for Failure Investigation of Internal Girth Weld Coating Surface Preparation: A Case Study
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Failure Investigation of Internal Girth Weld Coating Surface Preparation: A Case Study

Product Number: MPWT19-14360
Author: Rashed Alhajri, Yousef Alrayes, Fahad Alhindas, Ghassan Bahamden
Publication Date: 2019
$0.00

Field Guide for Managing Iron Sulfide (Black Powder) within Pipelines or Processing Equipment”

Product Number: 37642-POD
ISBN: 978-1-57590-383-5
Author: Daniel E. Powell, Robert H. Winters, Mark A. Mercer
$190.00
Picture for Impact of O2 Content on Corrosion Behavior of X65 Mild Steel in Gaseous, Liquid and Supercritical CO2 environments
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Impact of O2 Content on Corrosion Behavior of X65 Mild Steel in Gaseous, Liquid and Supercritical CO2 environments

Product Number: 51320-14433-SG
Author: Xiu Jiang, Dingrong Qu , Xiaoliang Song
Publication Date: 2020
$20.00

CO2 stream in CCS system usually contains impurities, such as water, O2, SO2, NO2, H2S, and other trace substances, which could pose a threat to internal corrosion and integrity of CO2 transportation pipelines. The general and localized corrosion behavior of API 5L X65 mild steel were evaluated using an autoclave both in water-saturated CO2 and CO2-saturated water environments in the presence of varying concentrations of O2. Experiments were performed at 25 °C and 35 °C, 8 MPa and 35 °C, 4 MPa to simulate the conditions encountered during dense, supercritical and gaseous CO2 transport. General corrosion rates were obtained by weight-loss method. The surface morphology of the coupons was examined by scanning electron microscopy (SEM). Results indicated that general corrosion rates at each O2 concentration in CO2-saturated water environment were much higher than those in water-saturated CO2 environment. The corrosion rates did not increase with increasing O2 concentration from 0 to 2000 ppm; instead the corrosion rate reached a maximum with 1000 ppm O2 at 25 °C, 8 MPa and 50 ppm O2 at 35 °C, 8 MPa in water-saturated CO2 environment and 50 ppm at 25 °C, 8 MPa and 100 ppm at 35 °C, 8 MPa in CO2-saturated water environment. However, the change trend of general corrosion rate with O2 content at 35 °C, 4 MPa was different from that in 25 °C and 35 °C, 8 MPa both in water-saturated CO2 and CO2-saturated water environments. Localized corrosion or general corrosion rate of over 0.1 mm/y was identified at each test condition both in a water-saturated CO2 and CO2-saturated water environments. When O2 was added, coupon surfaces were covered by a more porous corrosion product scale. A final series of tests conducted with the addition of 100 ppm and 2000 ppm O2 in CO2 environment with 60% relative humidity (RH) and 80% RH revealed that no localized corrosion was observed and the general corrosion rates were lower than 0.1 mm/y at 25 °C and 35 °C, 8