GABON LINE CORROSION-1 COATING DISBANDMENT LEADS CAUSES OF EXTERNAL PIPELINE CORROSION

Marcel Roche
Societe Nationale
Elf Aquitaine
Pau, France

Internal corrosion has proved the most persistent corrosion problem on the approximately 670 miles of pipelines operated since 1959 by Elf Gabon.

Causes include the presence of CO2 in polyphasic lines, residual oxygen and sulfate-reducing bacteria (SRB) in water-injection lines, and bacterial corrosion in crude-oil lines.

External corrosion has been less troublesome, caused either by atmospheric marine exposure with frequent wetting or by disbonded coatings on buried lines.

These were the major conclusions of a review conducted by the company and presented here in two parts. This first article focuses on external corrosion; the conclusion looks at internal corrosion.

EXTERNAL RISKS

Elf Gabon is an oil-producing company which for 30 years has been operating more than 1,000 km (621 miles) of pipelines in a wide range of conditions.

Production of oil in the district of Port Gentil, Gabon, started in 1955. The producing company, which later became Elf Gabon, laid its first oil pipeline in 1959.

Development of offshore fields began in 1965 with Anguille, followed by Torpille and Grondin in 1973. Elf Gabon is now operating 1,080 km (671 miles) of pipelines larger than 4 in. (Fig. 1). Of these, 73.5% carry oil, 23.5% gas, and 3% water.

With respect to external environments, 51.2% of these pipelines are installed on land and 48.8% offshore. Some 175 risers are supported by 69 marine structures including 53 jackets.

This situation represents a very large range of conditions in terms of hazards which affect integrity, longevity, safety, and efficiency of the installations.

Externally, the lines must withstand aggressive attacks from various environments. The major external risks are as follows:

• Equatorial climate (hot and wet) for some old lines installed aboveground with more or less marine influence

• Marine atmosphere, for risers above sea level and horizontal piping on platforms

• Soil, generally sandy, for buried land pipelines

• Brackish waters at river crossings

• Seawater and seabottom for offshore pipelines.

With a few exceptions, pipelines are always coated. This generally ensures a high level of corrosion prevention. External corrosion cases are infrequent and always localized.

Cathodic protection is systematically applied to buried and submerged pipelines to compensate for the unavoidable coating defects. It is a particularly efficient method so long as the protective level is achieved at each place of the metal-electrolyte interface.

For pipelines exposed to air, coatings are the only way to prevent corrosion. They must be as perfect as possible and frequently inspected.

CORROSION OFFSHORE

The integrity of horizontal piping depends entirely on the epoxy-paint system. Some time ago, a low-pressure collector ruptured during a pressure rise caused by a shutdown (Fig. 2).

The damage survey showed that it was caused by a combination of a too low a schedule with localized thinning due to external corrosion spreading under the paint and frequent contact with seawater dropping from a leaking valve.

Corrosion cases have also been encountered under heat-insulated lines where the external sheath allowed water penetrations (Fig. 3).

The most severe conditions for external corrosion exist in the splash zones of offshore structures.

This hazard is especially critical for risers because they are often hot (which greatly increases corrosion rates, up to 10 mm/year) and because the consequences on safety are much more important than on the supporting structure.

The general survey of the risers, discussed later, revealed important wall thinnings on three risers, which necessitated cuttings and installation of spool pieces (Fig. 4).

Corrosion was initiated at coating defects which had made a trap for water.

Leaks due to external corrosion in buried offshore lines have been very occasional. Cathodic protection has been effective, except in the cases where disbanded coatings have constituted shields preventing the protective current to reach the exposed steel.

Leaks due to external corrosion are still less frequent on submerged lines because the selected coatings are more efficient and the conductivity of electrolyte is much higher, allowing a longer span of protection Under disbondments.

No leak has been experienced due to external corrosion of submerged coated and cathodically protected lines.

The first 4-in. lines laid on the Anguille field in 1965 to connect satellite platforms to the central platform were left without any protection during the first 10 years. Corrosion was not severe during this period because the lines were buried in the sandy sea bottom where SRB activity is probably low.

Differential aeration corrosion at the riser feet was prevented by the cathodic-protection system which protects the platforms. However, zinc anodes were progressively installed on frames every 500 m on the sea bottom.

These lines are still functioning and cathodically protected in spite of the absence of any coating.

Elf Aquitaine has always paid attention to the choice of pipe coatings, sometimes playing a leading role in adopting new solutions, as for polyethylene coatings at the end of the 1960s.

The company's field experience has previously been documented1 2 as well as syntheses of comparative test programs carried out in laboratories.3 4 Elf Gabon contributed actively to the progress and experience in this field.

COATINGS

The application over the ditch of bituminous enamels has never been used in Gabon.

The only in situ coatings, except for the girth-weld areas and repairs, have been tapes on 2-4 in. land flow lines. Their general performance has not been good, and their use is now restricted to a minimum of cases.

Tapes are selected on the basis of test results, primarily peeling strength and cathodic-disbonding resistance.

Wrapping must be done properly to prevent voids at overlaps and corrosion beneath disbondments. Use of a hand-held wrapping machine is recommended (OGJ, Mar. 18, p. 104).

The first 8-in. pipeline laid on land in 1959 was coated with bituminous enamel containing one layer of glass fabric. Exposed to sand, it suffered little mechanical damage and remains sound after 30 years. Significant corrosion has not yet been noticed.

This kind of coating was systematically applied on the lines installed on land until 1972 when the first use of a plant-applied polyethylene coating in Gabon was used for a 27-km, 16-in. pipe. It was a fusion-bonded polyethylene (FBP) coating which showed a very rapid degradation when stored outside.

Some excavation work in recent years has revealed areas where the coating has lost its flexibility and adherence. The use of polyethylene instead of a bituminous enamel was mainly aimed at avoiding mechanical damage during shipping and handling.

Extruded polyethylene was introduced in 1975 for a parallel 16-in. pipe and a 67-km, 12-in. pipe. Serious adherence problems, mainly related to low application temperatures, were experienced during pipeline installation. Later examinations confirmed this problem.

The first polyethylene-coated pipe laid offshore was a 10-km, 4-in. gas line in 1973.

Bituminous enamel with a double layer of glass fabric continued to be preferred for pipe with a concrete weight coating because the shear strength between a smooth polyethylene surface and concrete was considered too low to avoid any risk of slipping in the tensioners of the laying barge.

The oil trunk lines connecting the offshore fields to shore are thus coated. In 1983, a concrete weight coating was applied over the polyethylene coating on some sections of the 73-km, 10-in. oil pipe connecting Konzi field to Cape Lopez terminal.

The shear strength was increased by a rough finish provided by polyethylene powder during application.

An important progress in polyethylene coating performance was the introduction of an epoxy primer coat to improve adherence and cathodic-disbonding resistance.

The first use of a three-layer polyethylene coating by Elf concerned 13 km of 8-in. oil and 24 km of 6-in. gas pipelines laid for the 1980 development of Ayol offshore field.5

The 205-km (127 mile), 18-in. pipe laid in 1988 to carry oil incoming to the Elf Aquitaine Group and the Gabonese state from Rabi field to Port Gentil was coated with this kind of material.

Fusion-bonded epoxy (FBE) powder coatings are not widely used. The exception is the 10-km land section of a 6-in. gas line. This choice resulted from the high gas temperature (100 C.) considered for the design.

After a few years, this coating is in a very good condition, especially in the sections where channelings in the ground caused by rains have exposed the pipe to air. However, temperatures have been lower than anticipated.

Table 1 summarizes the present situation for plant-applied coatings.

RISER, GIRTH-WELD COATINGS

The vertical parts of the pipelines supported by platforms are generally coated with a system different from that of the pipeline itself in order to ensure a higher level of protection, especially in the tidal and splash zones.

The oldest risers were coated with bituminous enamels and introduced inside steel casings, the annular space being filled with concrete. Since 1973, all the risers have been coated with 8-mm, glass-fiber-reinforced epoxy.

The performance is generally excellent, as discussed later in a section on aerial pipes. This performance includes hot risers, where internal temperatures can reach 100 C.

When plant coatings are used, girth-weld areas must be coated in the field to ensure continuity of protection.

Raychem Corp. heat-shrinkable open sleeves have constituted the standard solution since 1973, for land as well as offshore lines, with or without concrete weight coating. In this last case, wooden slats are wrapped around for geometric continuity.

The heat-shrink sleeves are used with different kinds of plant coatings: bituminous enamels, polyethylene, FBE.

The general performance so far has been excellent. Cracking and disbandment has been observed only in one case on sections of a 12-in. pipe which had become uncovered in marshy areas. The sleeves had been installed over a polyethylene coating applied in the field by fusion bonding of powder.

This technique was used for the first polyethylene plant-coated pipes.

On risers, continuity of fiberglass-reinforced epoxy coating is achieved with a catalyzed epoxy composite curing at ambient temperature.

Raychem Corp. sleeves are also currently used to carry out localized coating repairs.

CATHODIC PROTECTION

Except for the first lines installed on Anguille field, all the pipelines which are exposed to soil or seabottom are cathodically protected, which is very reliable and cost effective.

All the buried lines laid on land have always been protected by impressed-current systems with either rectifiers or solar photovoltaic cells (since 1981) in remote areas.

The first pipelines laid offshore were protected by the impressed-current systems installed in the Port Gentil area because they were not too long. This is the case for lines connecting Anguille and Anguille North-East fields to shore. Their offshore lengths are 16 and 5 km, respectively.

They are coated with bituminous enamel and concrete and partly buried in the sea bottom.

Initially, the offshore end of the first one was fitted with magnesium anodes installed on the platform and insulated from it. When consumed, these anodes were not replaced, but the insulating joint was shunted to raise the protection level of the pipe by continuity with the platform protected by aluminum anodes.

Zinc-anode bracelets were used for the first time on a 4-in. gas line laid in Torpille field in 1970. This solution was generalized in 1973 and used for the main trunk lines.

Since that time, calculation methods and hypotheses have been more or less modified, but the technique has remained the same. Anode bracelets are installed every 12 joints. Design is based on a coating breakdown factor of 4% (which is roughly the percentage of girth-weld coating) and an expected lifetime of 20 years.

Inspection shows that this protection system is very effective. No retrofitting has been carried out so far. Installation of anodes by divers for the protection of offshore pipelines was only necessary in the case of initially unprotected lines.

Insulated flanges are installed on risers to follow up the protection level of the pipelines by measurements carried out on the supporting platforms.

INSPECTING AERIAL AND SUBMERGED LINES

The method for checking the soundness of lines exposed to air is visual inspection. Periodic visits of inspectors are organized on platforms at least once a year, but accessibility to some parts of flow lines, collectors, or risers is often a problem.

Corrosion spreading underneath paint systems or coating can be difficult to see in these conditions. Close visual examination, adherence tests, wall-thinning appraisal with profilometers or ultrasonic measurements are used when possible. Inspection reports give recommendations for the necessary coating repairs or even pipe replacements.

A general survey of all the risers was carried out in 1988. As a result, a number of coatings were removed for better inspection.

Corrosion was found in a few cases under defects at the upper extremity of composite coatings (Fig. 5). The major problems resulted from lack of tightness at the upper end of the older system with steel casing and concrete.

Except for three cases, coating repairs were the only actions taken. Table 2 summarizes the results of this survey.

A similar general survey was conducted in 1989 for the collectors (between manifolds and risers) consequent to the damage just described.

Potential measurements currently performed by someone taking the contact beneath the insulating joints on risers are a simple and inexpensive way to check protection at the ends of offshore pipelines. Cables connecting inaccessible risers to control panels were recently installed on platforms to generalize this type of survey, which is more valuable because the pipe is short and well protected.

Periodic underwater surveys are necessary, however, to check the precise location of the pipeline, its state of burial in sand or mud, possible free spans or presence of debris, the state of coating, and the level of cathodic protection.

These costly surveys are carried out systematically at least once on every pipeline. Initially, potential measurements have been made for several years by divers or with a submarine equipped with a moving arm capable of making an electrical contact with the pipe through the coating or with anodes.

The use of a submarine or an ROV gives more complete and reliable information, including a video recording with comments.

In 1988, it was decided to try some of the new methods aimed at giving a continuous evaluation of potential along the pipeline route and of anode presence and current output, despite whether the pipe is visible.6 7

One excellent method involved the continuous measurement of potential by a reference electrode carried above the pipeline by a submarine while maintaining a test connection to the riser by spooling out a small-gauge insulated wire.

Relative potential recordings using a remote electrode gave less valuable information. Electric-field gradient measurements with a pair of electrodes gave some interesting information, but the recording rate needed stops over the anodes to obtain the peaks (Fig. 6).

ACKNOWLEDGMENTS

The author thanks Elf Gabon and the Societe National Elf Aquitaine (Production) for permission to publish this article.

REFERENCES

1. Roche, M., and Samaran, J. P., "The Experience of Elf Aquitaine in Pipe Coatings," Fils, tubes, bandes et profiles, 81, February 1981, pp. 14-21.

2. Roche, M., and Samaran, J. P., "Pipeline Coating Performance-Field Experience of an Operating Petroleum Company," Corrosion/87, San Francisco, 1987, NACE, Paper No. 28; Materials Performance, November 1987, pp. 28-34.

3. Roche, M., Samaran, J. P., and Larcher, E., "Comparative Tests for the Selection of Pipeline Coatings," Corrosion/84, New Orleans, 1984, NACE, Paper No. 357.

4. Roche, M., Samaran, J. P., Larcher, E., and Meyer, M., "Comparative Tests of Various External Coatings for Buried Pipelines," Proc., 101st Gas Conference Association Technique de l'industrie du Gaz en France, Paris, 1984.

5. Tamara, T., Matsuda, K., Adachi, I., and Ikeda, U., "Production of Polyethylene Coated Line by Cross Head Die with Epoxy-polyethylene Base Adhesive," Paper B1, Proc., 4th International Conference on Internal and External Protection of Pipes, Noordwijkerhout, The Netherlands, 1981.

6. Roche, M., and Samaran, J. P., "Monitoring Methods for External Corrosion Prevention of Submarine Pipelines," Petrole et Techniques, Vol. 261, April 1979, pp. 55-58.

7. Roche. M., and Samaran, J. P., "New Monitoring Methods of Cathodic Protection of Offshore Petroleum Installations," Paper No. 211, Proc. Symposium International Corrosion and Protection Offshore, Paris, 1979.

Copyright 1991 Oil & Gas Journal. All Rights Reserved.