Abdul Wahab Al-Mithin

Risk Based Inspection (RBI) of Aboveground Storage Tanks to Improve Asset Integrity

Kuwait Oil Company (KOC) has 85 crude oil aboveground storage tanks in its Tankfarms for the storage of crude oil prior to export. These tanks have storage capacities ranging from 162,000 to 597,500 bbl. (US). Hydrocarbons leaks / spillages resulting from tank failures, if any, could be very expensive and could pose serious fire hazards apart from major environmental issues. Therefore, in order to carry out a comprehensive assessment of the tanks to prevent any impending failure, KOC decided to adopt Risk Based Inspection (RBI) approach to evaluate the risks associated.

Life Extension of Hydrocarbon Equipment in Sour Environment

Reliability of equipment is indispensable for the uninterrupted operation of any oil & gas producing facility. Over a period of time, some oil wells producing sour crude were also added to the incoming feed of Gathering centres, which were originally designed for processing sweet crude. Most of the facilities were designed and installed prior to the publication of NACE MR 0175 and NACE TM 0284. As these facilities are still in operation under sour condition, it is prudent to take necessary measures in time for continuing safe operation of these facilities.In this paper, the authors share their experience in initial detection & online monitoring of service-induced damages to the equipments due to sour service using NDT techniques like Wet Fluorescent Magnetic Particle Inspection, manual ultrasonic testing and time of flight diffraction & Phased Array. The experience gathered during internal coating of the vessels has also been described. Several items of equipment continued in operation to maintain production even after the detection of Hydrogen induced cracking. Periodic monitoring and critical analysis of inspection data provided confidence to continue operation of equipment. This enabled the operating company to extract maximum life of the equipment without compromising on safety.This Paper focuses on two items of equipment, HP Gas Scrubber from Oil/Gas separation plant and HP Gas Discharge Cooler from CRU. Fitness for Service (FFS) evaluations were carried out for HP Scrubber and the Channel head component of HP Gas Discharge cooler. The analysis was based upon the latest UT scan results and guidelines prescribed in API 579-1/ASME FFS-1. These items of equipment were found not fit for further service. In the interim period, the company procured new scrubber and channel head of the cooler for replacement thus minimizing the shutdown period.Copyright

Living With HIC Damaged Pipeline

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.© 2012 ASME

Two Contrasting Internal Corrosion Scenarios Assessed by Liquid Petroleum–Internal Corrosion Direct Assessment (LP-ICDA) for the Innovative Development of a Dynamic Pitting Factor

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.Copyright

Integrity Management of Aged Equipment in Sour Oil and Gas Service: Kuwait Oil Company Approach

The professionals across the Oil & Gas industry have strived to combat the adverse effects of Hydrogen Sulphide and maintain the integrity of vital facilities. The detrimental effects of Hydrogen Sulphide on process equipment has remained as one of the prime subject of research in Oil & Gas Industry, fostering the advancement of inspection philosophies and necessitating adoption of appropriate mitigating measures. The challenge of Integrity Management increases with the ageing of equipment and increased influx of sour media. This paper discusses: • The change in operating environment — from non sour to sour. • The actions taken to protect the equipment in the changed operating environment. • Consequent changes in the inspection strategies and techniques to detect material degradation. • Material protection methodologies deployed to manage the age old facilities for safe operation. This paper gives an insight into the various methodologies adopted in KOC to address asset/plant life extension issues of an operating company to tackle the challenges caused by the changed composition of fluids handled. The paper illustrates adoption of appropriate inspection strategies, application of effective internal coating systems, periodic online monitoring of the pressure vessels to improve confidence level with respect to integrity of the vessels without necessitating major changes in the facilities.© 2010 ASME

Integrity Assessment of Pressure Vessels Subjected to Hydrogen Induced Damages

Hydrogen damage to pressure vessels in a Crude Oil Production facility is not uncommon. The intriguing question is about the decision to continue affected vessels in safe operation if such decision is supported by an accurate engineering assessment of the damage and the impending risk. Engineering assessments of the vessels instill confidence for safe operation and help in minimizing production loss & capital expenditure. This paper presents the integrity assessment undertaken during the years 2004–2005 for pressure vessels of an upstream oil production facility (Gathering Centre) of Kuwait Oil Company (KOC), where high H2 S (hydrogen Sulfide) levels in the process streams have made the pressure vessels susceptible to hydrogen induced damages. These carbon steel pressure vessels were manufactured to ASME Section VIII Div 1 during the years 1961–1968. As part of elaborate Inspection Program of the pressure vessels in the Gathering Centre, ultrasonic testing was conducted on all the hydrocarbon pressure vessels. Several vessels were found with significant embedded flaws including hydrogen induced crack-like defects & blisters. These defects were further evaluated by Automated Ultrasonic Testing (AUT) which comprised of C-Scan and Time-of-Flight Diffraction (ToFD) techniques. AUT was used for the precise detection & sizing of the embedded flaws which is important for Fitness-For-Service (FFS) Evaluation. Subsequently, the affected vessels with critical flaws were evaluated by FFS assessment as per API-579. While some vessels were found unfit for further safe operation, others were retained in operation with periodic monitoring.Copyright

KOC’s Integrity Management Program for Non-Piggable Pipelines: A Case Study

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.Copyright