A 16 km. long, 18” Gas pipeline (HP055) was in service to transport High Pressure Gas from an oil gathering center in West Kuwait (WK) area since 2001. The Pipeline carried wet sour gas. It was inspected in 2008 using high resolution MFL-ILI tool. No significant corrosion was found. In late 2012, a leak developed in the pipeline. The leak was due to a crack along a spiral weld on the bottom. Inspection during repairs revealed severe internal pitting on the bottom. The pipeline continued to leak several times in the next year, eventually resulting in decommissioning of the pipeline. Another ILI could not be carried out due to operational constraints and frequent leaks. The Pipeline was critical in the operation of the oil gathering center, and the loss of it severally affected the gas/oil export target and the flaring reduction commitment. An internal failure investigation was inconclusive, though indicating possibility of sulfide stress cracking. The failure investigation work was then entrusted to TWI, UK. A failed section of the pipeline was sent to their facilities and various tests including Chemical analysis, tensile test, residual stress measurement, SSC/HIC test, microstructure analysis, and analysis of corrosion products were carried out. The outcome of the tests and conclusion was very surprising. This paper describes in detail the leaks, inspection of leak locations, and the failure investigation findings and conclusions.
Kuwait currently produces about 3 million barrels of crude oil per day and has a large pipeline network system for handling its oil and associated products (condensate, low pressure and high pressure gas, as well as produced and effluent waters). The total length of the pipeline network is about 4790 Km consisting of API 5L Grade-B carbon steel ranging in diameter from 100 mm to 1830 mm. The Kuwait Oil Company (KOC) is responsible for the corrosion and integrity management of the pipeline network system which involves: Internal Corrosion Monitoring to assess the internal corrosion status of the pipelines including the occurrence of microbial influenced corrosion; external corrosion protection with the help of coatings and cathodic protection, and periodic intelligent and cleaning pigging operations for internal corrosion assessment and cleaning. The present paper focuses on the internal corrosion management of the export crude segment of the pipeline network system which is very important for a healthy economy. The internal corrosion monitoring protocol includes, online corrosion monitoring, cleaning pigging and intelligent pigging. Bacteria counts’ trending is also included as part of protocol. Some anomalies between the results obtained from corrosion trends, cleaning pigging results and intelligent pigging are highlighted and a sound engineering explanation is attempted to explain these apparent anomalies.
A 41 km. (25.5 mile) long, 508 mm (20″) Fuel Gas pipeline (FG048) was in service to supply Fuel Gas to oil gathering centers (GC) in the West Kuwait area since 1968. It was required to convert the pipeline for reverse flow of HP Gas from a new gas gathering center in West Kuwait. During MFL-ILI survey prior to conversion, several undefined anomalies were detected along with other internal and external corrosion. Repair work was initiated based on ASME B31G criteria. During repair work, sections having unidentified anomalies were cut out and inspected internally. Internal blistering and HIC damage were observed. Further investigation revealed severe HIC damage and internal blistering at different areas throughout the pipeline length. Since the pipeline was crucial in commissioning gas collection and compressor facility operation, and was required to be in service for transporting gas within a short time, a program of failure investigation, inspection, data analysis and repair work was implemented. This paper demonstrates how a severely HIC damaged pipeline, crucial for gas transportation was put back into service using inspection, analysis, hydrotest and repair techniques through the collaborative efforts of different agencies.
More than half of the world’s oil and gas pipelines are classified as non-piggable. Pipeline operators are becoming aware there are increased business and legislative pressures to ensure that appropriate integrity management techniques are developed, implemented and monitored for the safe and reliable operation of their pipeline asset. The Kuwait Oil Company (KOC) has an ongoing “Total Pipeline Integrity Management System (TPIMS)” program encompassing their entire pipeline network. In the development of this program it became apparent that not all existing integrity management techniques could be utilized or applied to each pipeline within the system. KOC, upon the completion of a risk assessment analysis, simply separated the pipelines into two categories consisting of piggable and non-piggable lines. The risk analysis indicated KOC’s pipeline network contains more than 200 non-piggable pipelines, representing more than 60% of their entire pipeline system. These non-piggable pipelines were to be assessed by utilizing External Corrosion Direct Assessment (ECDA) for the threat of external corrosion. Following the risk analysis, a baseline external corrosion integrity assessment was completed for each pipeline. The four-step, iterative External Corrosion Direct Assessment (ECDA) process requires the integration of data from available line histories, multiple indirect field surveys, direct examination and the subsequent post assessment of the documented results. This case study will describe the available correlation results following the four steps of the DA process for specific non-piggable lines. The results of the DA program will assist KOC in the systematic evaluation of each individual non-piggable pipeline within their system.
This paper details the complete four-step Liquid Petroleum - Internal Corrosion Direct Assessment (LP-ICDA) for two operationally different liquid petroleum pipeline systems owned by Kuwait Oil Company. The internal corrosion pipeline wall metal losses were originally predicted using a uniform pitting factor and subsequently upgraded by a dynamic pitting factor. The first case evaluated three, 1959 vintage, non-piggable 40″/38″ telescopic export crude oil pipelines (CR102, CR103 and CR104) with individual corresponding parallel run lengths of 7.7km. All three pipelines run parallel to each other in a common corridor. They are gravity-fed from a storage tank farm resulting in a moderate fluid transit operating velocity. The second assessment was performed on a 6.5 year-old, piggable 36″ crude oil production pipeline (CR088) with an overall distance of 25 kilometers. During the Pre-assessment step, pipeline historical and operational data were collected. Limited historical data was available for the 3 non-piggable pipelines compared to the newer 36″ pipeline which was ultrasonically (UT) inspected via in-line inspection (ILI). In the Indirect Inspection step, the proprietary internal corrosion predictive model (ICPM), enpICDATM, was applied with a uniform pitting factor to predict the amount of degradation at those locations where liquid hold-up, solids accumulation, and in-turn the internal metal losses would be most pronounced. During the Detailed Examination step, “in-the-ditch” UT was utilized to measure and confirm the remaining wall thicknesses of the three gravity pipelines whereas a comparison of the ICPM to the ILI was executed for the newer 36″ × 25km pipeline. In the Post-Assessment step, a comparison between the predicted metal losses and the UT-ILI measured data were carried out. As a result of a gap analysis, dynamic pitting factors were proposed and developed to enhance and update the proprietary model for predicting the metal losses point-by-point within each subregion over the entire pipeline in terms of local pressure, temperature, water accumulation, and solids deposition. Validation of the in-house prediction was performed using the field measurements for gravity pipelines and ILI data for CR088, demonstrating that metal losses predicted by the proprietary model and measured through field tests and ILI data agree reasonably well for both extreme scenarios. Results showed that three gravity pipelines have minimal internal corrosion under a high flow velocity despite having a 51-year operating history whereas severe internal corrosion was identified after a 6.5-year operation for the CR088 pipeline. Hence, selection of a proper operating velocity is crucial for crude oil pipeline operations. Under a low speed condition, localized pitting corrosion dominates whereas uniform corrosion is predominant under a higher flow or “sweep” velocity. Since the pipeline operators were more interested in the worst-case scenarios, i.e. metal loss due to localized pitting corrosion, development of dynamic pitting factors was undoubtedly an innovative improvement of the overall Liquid Petroleum - Internal Corrosion Direct Assessment through capturing the fluctuation of metal losses along the entire pipeline, which can enhance the ICDA methodology toward a higher level of precision and accuracy.
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