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ABSTRACT: Cased pipe segments can suffer external corrosion when the carrier pipe holidays are exposed to electrolyte or humid air. Corrosion by electrolyte occurs when cathodic protection (CP) is shielded by, for instance, insulator spacers, the casing wall (particularly if coated), or mud/deposits accumulated in the annulus. When the casing and carrier are metallically shorted, any CP protection to the carrier pipe may be eliminated. Understanding mechanisms and severity of external corrosion of cased carrier pipe is a significant step toward developing strategies to prevent or mitigate the corrosion problem. The severity of carrier external corrosion can be assessed through a statistical analysis of corrosion anomalies identified and sized from In-Line Inspection (ILI) runs. The results of piggable cased pipe segments can be applied to non-piggable ones given their corrosion conditions are similar. The goal of this study was to investigate the significance of external corrosion damage to cased segments, including the preferential location of the peak anomaly in a cased segment, the effect on corrosion of metallic shorts relative to non-shorted conditions, historical failure incidents in casings, and the relative safety of cased segments to non-cased ones evaluated by the number of scheduled or immediate repair anomalies per mile. These results are expected to provide insight into developing risk methodologies for identification and prioritization of cased pipe segments as part of the external corrosion direct assessment (ECDA) program of cased crossings. INTRODUCTION: Cased pipe segments are generally believed to be safe since the time-independent threats, including third party excavation and outside force damage, are largely eliminated. Compromising this safety argument is, however, the possibly enhanced external corrosion of the carrier pipe due to the presence of the casing. No sound evidence is yet available that suggests that cased segments are safer than uncased ones, in terms of the number of leaks per mile or number of scheduled or immediate repair anomalies per mile. A survey of 1984 rather revealed that, of 14 countries surveyed, five reported corrosion damage on the carrier pipe when casings were used, but none reported corrosion damage on the carrier pipe at crossings where casings were not used[1]. The carrier external corrosion can become more severe than in uncased segments when the carrier pipe has access to electrolyte due to condensation from vent pipes open to air, or from direct intrusion of ground water into the casing-carrier annulus when the casing end seals are either lacking or do not properly seal. Figure 1 schematically shows the major elements of a typical casing, including vent pipes, end seals, and insulator spacers. When a thin layer of electrolyte is condensed at the carrier coating holidays, a high diffusion rate of oxygen can result in a high corrosion rate. For such atmospheric corrosion, lacking conductive electrolyte media in the annulus between the casing and the carrier pipe (Figure 2a and b), external CP is ineffective in protecting the carrier pipe. When the annulus is partially filled with electrolyte (Figure 2c and d).
- Transportation (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- (2 more...)
North Kuwait Oil Field Sea Water Flood Experience In Pipeline Integrity Management Program.
Carew, J. (Petroleum Production Department Petroleum Research& Studies Centre Kuwait Institute for Scientific Research) | Al-Hashem, A. (Petroleum Production Department Petroleum Research& Studies Centre Kuwait Institute for Scientific Research) | El-Mohemeed, E. (Petroleum Production Department Petroleum Research& Studies Centre Kuwait Institute for Scientific Research) | Al-Enezi, H. (Field Development North Kuwait, Kuwait Oil Company)
Introduction: Abstract: This paper will focus on methods of improving asset integrity by taking a holistic approach towards management and maintenance of the 48km sea water flood pipeline. This is carried out by a combination of a 36 inch carbon steel piping material, inhibitors, and monitoring systems to most effectively mitigate against corrosion. This presentation will focus on pigging the pipeline to control/mitigate microbiologically influence corrosion (MIC), and under deposit corrosion. The threat of MIC has surfaced as a concern to the pipeline operators in the last five years. Mitigation methods usually involve continuous injection of biocide, corrosion inhibitor and scale inhibitor treatments of the pipeline. There is some benefit in trying to control the problem of MIC and under deposit corrosion in the pipeline by running specifically designed cleaning pigs on a routine basis at set frequencies. Over a period of time, the scrapping estimated from the 36” carbon steel pipeline as amounted to over three tons of debris. Subsequently, intelligent or smart pigs were used to detect and measure the pipe wall defects, such as corrosion pits and weld defects. The use of intelligent pigs for inspection of pipelines has increase considerably. The most commonly used intelligent pigs make use of magnetic leakage (MFL) technique to detect corrosion pits. The seawater injection process has proven to be an effective mechanism for improving oil recovery through pressure maintenance. The success of the injection project depends on the quality of the injected seawater and its compatibility with the reservoir. The strategy used to minimize the risks associated with seawater injection process and to reach production targets under environmentally safe conditions, involves: establishment of the injection water quality requirements, standardization of the techniques for monitoring of the injection water quality and development of a data compilation system to assist the operational team in controlling the water quality and corrosion process. The 36” inch seawater pipeline, carbon steel API 5L grade B, was built and commissioned in the year 2000 to transport deaerated and treated seawater to the Central Injection Facilities (CIPF) 48 km North of the treatment plant. The water treatment regime includes the addition of scale inhibitor, corrosion inhibitors and biocides. It is difficult to remove sulphate reducing bacteria (SRB) once they have become established. Simply injecting biocide into the seawater will not work because the bacteria are located beneath the biomass products in order to get to the bacteria, the scale, corrosion biomass products need to be removed. Once the scale and the biomass are removed, the appropriate chemicals are injected through the pipeline to kill the bacteria. During the regular pigging operation (Carew et al., 2004 & 2006), huge amount of corrosion products were observed at the pig receiver end. Corrosion under organic growth is a major cause for concern because the local environment is inaccessible to corrosion inhibitor and biocide treatments and remediation often requires physical cleaning to be effective - often a costly and time consuming activity.
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.35)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- (2 more...)