GABON LINE CORROSION-CONCLUSION SYSTEMATIC PROGRAM AND INTERNAL INSPECTION KEYS TO CORROSION CONTROL

Marcel Roche
Societe Nationale
Elf Aquitaine
Pau, France

A review of corrosion problems on the 670-mile land and offshore system operated by Elf Gabon indicated that internal corrosion has been the most persistent problem.

The company has operated the system since 1959.

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, discussed in the first of this two-part series (OGJ, Apr. 1, p. 49), has been less troublesome, caused either by atmospheric marine exposure with frequent wetting or by disbanded coatings on buried pipes.

INTERNAL CORROSION, CONTROL

Although problems from internal corrosion have been infrequent, they are more difficult to control. When they appear, they are generally more widespread along the line than those related to external corrosion.

The major internal risks are the following:

• Polyphasic flow (oil containing separated gas, salt water and carrying more or less wax, sand, and other sediments)

• Oil containing various amounts of salt water and sediments, above or under commercial specified limits (bs&w < 1%; salinity

• Raw gas (containing water)

• Dehydrated gas (for gas lift use or commercial supply to Port Gentil area)

• Seawater treated for waterflooding

• Brackish water treated for waterflooding.

The first precaution for avoiding corrosion problems is efficiently to treat water used for hydrotesting of lines. This treatment prevents trouble during the first operating years. But problems can arise later when field water appears in the lines.

CO2 corrosion and bacterial corrosion caused by SRB growth are the main risks experienced by Elf Gabon. H2S is not present in the reservoirs and has not yet appeared as a result of water flooding.

Effluents are potentially corrosive when CO2 partial pressure is high.1 2 This happens before gas separation, in the wells, flow-lines, collectors, and polyphasic lines connecting satellites to central stations.

Most of the fields operated by Elf Gabon contain high levels of CO2 partial pressure (up to 3 bar) and are hot (up to 125 C.). Significant corrosion damage was experienced on many well tubings at the end of the 1970s which led to general use of 13% chromium stainless steel.3

Flow lines are subject to CO2 corrosion associated with erosion and abrasion by sand, more especially in the bends. This problem has been reduced by installation of sand traps.

On offshore platforms, leaks have been avoided as a result of periodic and systematic inspections.

The most severe cases concerned submerged polyphasic pipelines:

• A 10-in, line from Girelle to Pageau (see map, OGJ, Apr. 1, p. 49) leaked after 3 years' operation. Replacement of the first 3 km occurred 2 years later. Inhibition treatment introduced at that time has prevented new leaks.

• A 16-in. line connecting Grondin satellite to Grondin central complex was abandoned 8 years after installation.

OIL, GAS, WATER

The main risk of damage in oil lines is related to bacterial corrosion because of low CO2 partial pressure. The high temperature of most of the reservoirs prevents SRB contamination of the wells.

SRB comes from the introduction of water into the surface installations. The frequency of these events has been high enough to lead to an almost permanent contamination of the trunk lines, despite the various biocide injections.

Fortunately, this contamination generally does not cause bacterial corrosion because the content of sulfate ions in the separated water is not continuously maintained sufficiently high enough to allow the bacterial growth.

The ingress of an effluent containing a low amount of water but highly loaded with sulfate ions, however, explains severe internal pits discovered in the 11-km section of the 16-in. No. 2 Tchengue-Cape Lopez line downstream of a tee introducing this effluent (Figs. 1 and 2).

Such damage was detected neither in the upstream section of this pipe nor in the entire length of No. 1, a parallel 16-in. line fed with the same effluent.

Inside gas lines, prevention methods have precluded corrosion damage. Trouble related to the formation of hydrates in nondehydrated gas lines are also generally solved without major problems by methanol injections.

Waterflooding with seawater was introduced on Anguille field in 1968 and on Anguille North-East and Port Gentil Ocean in 1972.

The 8-in. line feeding this last field leaked after 2 years and was replaced twice during 10 years. The other 8-in. line feeding Anguille NorthEast leaked in 1978 and was replaced by Coflexip S.A. flexible pipe in 1979.

These severe failures were due to a poor deaeration of water (between 0.5 and 1 ppm residual oxygen) aggravated by bacterial growth (inefficient biocide). Anguille water pipes were not damaged because gas lifting of seawater ensured a good deaeration.

Newer waterflooding systems installed on Anguille, Anguille North-East, Torpille, and Breme fields have suffered no corrosion to date.

CORROSION ALLOWANCE, ADDITIVES

A classical method for reducing leak hazards resulting from internal as well as external corrosion of pipelines is to add a corrosion allowance (generally 3 mm) to the calculated wall thickness. This routine preventive method can be questioned, however.

Corrosion patterns encountered are most often localized: CO2 corrosion or SRB corrosion does not lead to generalized uniform attack but to pits, craters, or grooves. External corrosion is also localized to some coating defects.

Consequently, the increase of lifetime due to corrosion allowance is generally less significant and the decision to maintain a corroded pipe in service is not directly based on residual wall thickness but often estimated from the shape of the defect (through ANSI/ASME B31G-1984, for instance).

Using a corrosion allowance should be decided only after a thorough risk analysis.

For the Rabi North pipeline laid in 1988, the nominal wall thickness (7.67 mm) was determined to be exactly equal to the theoretical value calculated for the maximum allowable operating pressure (MAOP, 100 bar). For this 205-km (127 miles), 18-in. line laid on land but crossing a lagoon inlet and the Ogooue estuary, the cost savings have been all the more significant because X60 steel was used.

This decision was taken because corrosion risks were considered negligible:

• Water content less than 0.5%

• Frequent pigging necessary for wax cleaning

• Very low partial pressure

• No sulfate ions

• Improbable SRB contamination

• Heavy-duty external coating

• Presence of a cathodic-protection system.

Moreover, corrosion monitoring will be completed by frequent inspections, including intelligent pigs.

Comparative laboratory tests are carried out to select efficient additives and to check their compatibility before they are tried in the field.

The general policy adopted is to use inhibitors which have a good capacity to go into the water phase. This capacity depends highly on the composition of the organic phase. The first experiences with corrosion inhibitors failed because they were too oleophilic. General use of long-chain amines as inhibitors in oil pipelines began in 1979, first with Solamine 108S (Seppic), then with Norust 720E (CECA) since 1985.

These products are injected at the farthest upstream point into the flow line which contains the higher water content on a given platform. The amount used is calculated on the basis of the theoretical surface wetted by the water phase and roughly corresponds to 20 ppm. Performance of inhibition has been good. Before the systematic dehydration of gas, inhibition of wet-gas systems was carried out with the same inhibitors dissolved in methanol.

Concerning waterflooding, the pipelines carrying water deaerated by gas stripping are continuously treated by chemicals having biocidal and inhibiting functions (to prevent the corrosive effect of CO2 contained in the gas). Such chemicals include D3036 (Nalco), Sofrabac (Sofraser), or Bactiram 3084 (CECA).

When vacuum columns are used for deaeration, corrosion inhibitor is unnecessary. In all cases, however, oxygen scavengers, such as K490 (Petrolite) or SC45 (CECA), are used. They are ammonium and sodium bisulfites.

Preventive injection of biocides is systematically performed in oil systems: 10 1. are put into the slop tanks every week and 25 1. after each water-jetting operation to remove sand from the separators. Curative biocidal treatments calculated on 200 ppm related to water content are periodically carried out in the trunk lines. Their efficiency is improved by coordination of pigging operations with these injections.

Glutaraldehyde types of biocides have been used but are being replaced by more complex formulations (aldehydes and quaternary ammonium compounds), such as Bactiram 3084 (CECA), which have a better residual efficiency.

Weekly batch treatments are performed in the waterflooding systems with vacuum columns for deaeration.

OTHER METHODS

Water removal on the fields contributes to reducing the hazards related to corrosion and mineral scales and assists metering and flow capacity of pipelines.

Gas dehydration with ethylene glycols has been generalized for gas-lift networks and commercial delivery, allowing cancellation of chemical treatments. Physical deaeration of injection sea or brackish waters completed by oxygen scavenging leads to a very low concentration of residual oxygen (10 ppb) which prevents any risk of oxygen corrosion.

Use of internal coatings has not as yet been tried because the results were considered problematic. Protection continuity at girth welds is also difficult to ensure.

Developments of newer coatings, such as Novolac FBE, should encourage use of this solution for different cases. Example uses are prevention of corrosion or wax deposition in oil pipes and prevention of plugging of low-permeability reservoirs by residual corrosion products in injection waters.

Intensive comparative laboratory tests have been carried out to test the effect of temperature and pressure drops in petroleum fluids.

Flexible pipes, first installed in 1978, constitute another solution to problems listed previously for offshore lines. Smooth-bore types (Rilsan internal sheath) prevent corrosion and organic deposits; rough-bore type (stainless steel internal carcass inside Rilsan sheath) prevents only corrosion.

Early last year, 24 km of flexible lines were installed to carry oil (14 km), gas (1.5 km), and water (8.5 km).

Composite-material lines can be selected for the same objectives as far as aerial or buried lines are concerned. Except for short pipings in seawater-treatment units, composite material is not yet used in Gabon but is considered for the near future for land flow lines.

The frequent use of efficient cleaning pigs constitutes an essential way for removal of separated water and deposits, which reduces electrochemical and bacterial corrosion risks and facilitates the flow. Recent experience showed that the new bidirectional pigs built with polyurethane discs are much more efficient than traditional pigs using cups. Moreover, the use of jetting nozzles on the nose cap helps wax scraping by creating a turbulent flow in front of the pig.

MONITORING, INSPECTION

Because full knowledge of the corrosion status of the pipelines is essential, monitoring aims at giving a warning before any serious damage occurs, and inspection is used periodically to check the validity of monitoring and to complete it.

For monitoring corrosivity, a wide range of techniques is used, such as direct corrosivity measurements (coupons, electrical resistance, and electrochemical probes), chemical analysis of sampled waters (iron counts, sulfate and sulfide ions, pH, dissolved gases), and SRB detections.

Coupons can also give indications on the formation of deposits and help in the detection of the sessile types of bacteria (bioprobes). Flushmounted types of coupons must be used as far as pipelines are concerned.

Although this monitoring system has been generally satisfactory, it failed to reveal the severe bacterial corrosion observed on the 16-in. Tchengue-Cape Lopez line discussed previously. Comparison of data collected on this pipe and on the parallel 16 in. does not allow a differentiation between them.

Improvements must be made to the system, especially for the quality of water sampling. This should be done as much as possible when cleaning pigs are received at the traps.

Periodic wall-thickness measurements at defined places are carried out on the flow lines by ultrasonics and gamma rays. Corroded sections are replaced when the remaining thickness is less than 4.5 mm.

The same measurements are also carried out to check the validity of information given by internal inspection with intelligent pigs. Insulated joints are also checked annually by these methods for internal corrosion. Gamma-rays are used to follow up the growth of mineral-scale deposits.

Intelligent pigs were first used for internal inspection in 1988 as a result of corrosion damage discovered on the 16-in. Tchengue-Cape Lopez line. After a general survey of the market, H. Rosen Engineering was chosen because of the flexibility of its tools to adapt to our installations: 1.5 diameter (D), 45, 16-in. bends. The electronic geometry pig (EGP) is based on a touchless sensoring device. Data are recorded in an onboard computer with C-MOS memory. This vehicle detects unknown geometrical features such as short-radius bends, not fully opened valves, and dents (Figs. 3 and 4).

A corrosion-detection pig (CDP) uses the magnetic flux-leakage principle with sophisticated digital signal-processing computers. It is equipped with two rows of sensors which allow differentiation between internal and external metal losses (Fig. 5).

Internal pitting was precisely detected. Some external pits and internal general corrosion were also detected in some parts of the surveyed pipelines. General corrosion appraisal had to be adjusted by external checks. The inspection of an offshore 10-in. line necessitated replacement of 1.5D bends at the receiving trap and a slight modification of the tool to pass two dents detected by the EGP.

Inspection of 16-in. and 20-in. offshore lines fitted with 1.5D 90 bends will need a complete redesign of the tool. Differentiation between internal and external corrosions will be tried with two runs, the second being carried out after modification of the magnetization system.

The use of intelligent pigs is of course easier in the newer pipelines designed for that purpose. The Rabi North pipeline was inspected last year for a reference status, 2 years after installation.

EXPERIENCE

The experience acquired by Elf Gabon over 30 years of pipeline operations leads to some conclusions concerning protection and inspection:

• Corroded lines have been replaced with 20 km of new lines, which can be compared with the total present length of lines (1,080 km).

• Internal corrosion was the cause of most of the trouble. It was due to CO2 in polyphasic pipes, residual oxygen and SRB in injection water pipes, and bacterial corrosion in oil pipelines.

• External corrosion (OGJ, Apr. 1, p. 49) was limited to a few cases caused either by atmospheric marine exposure with frequent wetting or by disbanded coatings on buried pipe.

• Performance of internal-inspection monitoring programs was generally satisfying. However, improvements are necessary for bacterial corrosion appraisal.

• Internal inspection with intelligent vehicles is the only way to define exactly the corrosion status of pipelines.

REFERENCES

1. Crolet, J. L., "Acid corrosion in wells (CO,, H2S), Metallurgical aspects," Journal of Petroleum Technology, August 1983, pp. 1553-1558.

2. Bonis, M. R., and Crolet, J. L., "The nature of the CO2 corrosion of steels in oil and gas wells, and the corresponding mechanisms," Materiaux et Techniques, February-March 1985, pp. 55-64.

3. Bonis, M. R.. and Crolet, J. L., "Experience in the use of 13% Cr tubing in corrosive CO2 fields," Proc. International Symposium on Oilfield and Geothermal Chemistry (Phoenix, 1985), SPE paper 13552, pp. 37-44.

4. Roche. M., Samaran, J. P., and Larcher, E., "The influence of operating conditions on the behavior of coatings exposed to petroleum fluids," Proc. 10th International Congress on Metallic Corrosion (Madras, India, 1987).

Copyright 1991 Oil & Gas Journal. All Rights Reserved.