CORROSION PROMPTS REPLACEMENT OF ABU DHABI GAS-GATHERING SYSTEM

Kamal M. Morsi
Abu Dhabi National Oil Co.

Adel Al Key
Abu Dhabi Co. for Onshore Oil Operations

Persistent corrosion problems in a newly in stalled gas-gathering system in Abu Dhabi's Bab field have led Abu Dhabi National Oil Co. (Adnoc) to replace the system.

The project called for a different corrosion coating, line-pipe material, and installation method.

EXISTING DESIGN

In 1982, Adnoc initiated a project for gathering and processing natural gas produced from the Thamama Zone C reservoir in the Bab field.

The gathering system comprises a total of 19 wells which produce natural gas and associated condensate. The optimized gas-transmission system to the plant consists of four buried trunklines connecting four to five wells each (Fig. 1).

Each trunkline was divided into an upstream section (8 in.) connecting two wells and a downstream section (12 in.) connecting the other two or three wells. Each section is provided with its own pig launching and receiving facilities.

The four trunklines terminate at the main processing plant in four gas separators provided with a necessary relief valve to protect against over pressure.

Sweet gas from the process plant's gas header is supplied to all wellheads and pig-launching stations via a 3-in. distribution system which follows the same routing as the trunklines. This gas is used for purging and provides instrument supply gas to the corrosion-inhibitor injection pump and wellhead control panel.

Thamama Zone C gas is produced from a limestone formation. H2S and CO2 contents in the existing wells range from 0.7 to 8.0 mole % and 4.0 to 8.0 mole %, respectively.

The prevailing soil condition is very corrosive with high water salinity. The water table is also high. These soils are referred to as Sabkha.

The original pressure of Thamama C reservoir is 4,300 psig at 8,500 ft with a bottomhole temperature of 260 F.

The Thamama C gas-gathering lines were originally designed in accordance with ANSI B31.8 Class 1 location to a maximum design pressure of 110 bara (approximately 1,600 psia) with 0.203 and 0.312-in. W.T. for the 8 and 12-in. pipe, respectively. A small corrosion allowance of 0.05 in. was added.

The 12-in. pipe material was electric-resistance welded (ERW) pipe in accordance with API 5L Grade X-60.

The pipe as well as the other carbon steel pressure-containing equipment, including launcher and receiver barrels, were selected to meet the relevant requirements of NACE (National Association of Corrosion Engineers) Standard MR-01-75 for sour service.

The 8 and 12-in. pipe was also specified for resistance to hydrogen-induced cracking (HIC) through low sulfur content, copper addition, calcium shape control, ultrasonic testing, and HIC testing.

PROTECTION SYSTEMS

Internal corrosion protection against attack by the sour wet gas was provided through a combination of corrosion inhibition and periodic pigging.

A continuous downhole open-chemical injection system utilizes the casing-tubing annulus as the injection conduit. The annulus is filled with corrosion inhibitor mixed with diesel oil.

The injection chemical enters the side pocket mandrel directly from the casing annulus, then flows into the mandrel pocket. The chemical is regulated at the surface by a chemical-injection pump and associated control equipment.

Three of the Thamama Zone C wells have different downhole completions of duplex stainless steel tubing with no downhole chemical inhibition.

The pipeline sizes of 8 and 12 in. were selected to maintain the velocity of 10-40 fps for effective distribution of the corrosion inhibitor.

Cleaning and pigging of all 8 and 12-in. trunklines are being carried out at regular intervals to remove water and gas condensate. Cleaning is done once every 45 days.

The soils in which the four trunklines are buried are of two general types, the hostile, wet, highly saline soil (Sabkha) and loose dry desert sand.

External corrosion protection for the trunklines and sweet-gas supply line was designed on the basis of a combined protective coating and cathodic-protection system consisting of the following:

• A fusion-bonded epoxy (FBE) coating of 300 u dry film thickness (dft; Eurokote 711.97) factory applied and chosen to meet the high gas temperature (100 C. maximum at wellhead). Heat shrinkage sleeves were used for wrapping the field girth weld joints.

• An impressed current cathodic-protection system consisting of one transformer-rectifier of 30 amp/48 v and silicon iron groundbed.

Scraper launching and receiving facilities were designed for regular pigging and cleaning of all trunklines (8 and 12-in. sections) and are sufficiently long to accommodate intelligent pipeline tools (Fig. 2).

Periodic examination of changes in pipe-wall thickness by ultrasonic method at exposed sections located along the route of the pipelines is currently being implemented.

Corrosion is also monitored through strategically placed corrosion coupons, probes, and corrosion spools.

Downhole corrosion inhibitor injection consists of 1-2 pints/MMscf of gas of neat inhibitor, diluted in diesel (10% solution).

Residual inhibitor levels are measured regularly. The inhibitor suppliers suggest that residual levels of 60-70 ppm in water are evidence of adequate protection.

Originally the frequency of pigging was once every 36 months.

Since the intelligent pig survey in 1986, however, the frequency was increased to once every 45 days. Each trunkline is pigged twice, making the total number of runs 16 for the four trunklines.

An estimated 400-500 bbl of liquids have been removed from each trunkline (water and condensate) per pigging operation.

INITIAL PROBLEMS

Thamama Zone C system was commissioned in 1984.

During early operation, some problems of excessive corrosion that created safety hazards prompted several studies and audits.

The recommendations from these studies were combined and implemented in one project called Thamama C gas-gathering remedial project. This involved several modifications in flow lines, wellhead, and pig-launching areas summarized as follows:

• Constructing double block-and-bleed valves including spectacle blinds on all interconnecting lines, pig launchers and receivers, and all instruments.

• Providing adequate protection on flow lines against over pressure by installing a second independent high-pressure trip with associated logic.

• Installing local alarms and additional H2S detectors.

• Replacing small-bore screwed connections by socket-yielded connections.

• Replacing thermo-electric generators by solar power system.

• Replacing control valve plugs with Inconel ones.

• Installing crash barriers and fencing around all ground piping and valving stations.

FURTHER OPERATING PROBLEMS

In 1985, potential surveys on the cathodic-protection (CP) system indicated significant drops to below minimum protective levels along all the trunklines. Remedial action was taken by installing extra current capacity to upgrade the CP system.

Review of readings during this period showed continuing decline in potential levels, notwithstanding the increased current input.

Subsequently, external corrosion problems led to severe gas leaks from the trunklines. Physical excavation for inspection in critical areas demonstrated substantial deterioration in the epoxy coating by embrittlement and disbandment especially in saline soil areas.

External corrosion beneath disbanded and blistered coating was mostly found in the bottom half of the pipe and resulted in several in-service leaks.

Corrosion was also noted beneath poorly adhered shrink sleeves.

The epoxy coating was found covered with a layer of crystalline salt-sand mixture. The coating in dry desert sand areas was found to be in a better condition than that in saline soil areas.

Findings of intelligent pigging surveys conducted in 1989 and verified by subsequent local excavation confirmed widespread coating disbanding and external corrosion especially in hostile saline areas.

A detailed soil-resistivity survey carried out in early 1989 identified areas of low-resistivity soil. It was concluded that under prevailing conditions of high gas temperature and exposure to wet saline soil, the applied FBE coating failed in service.

No effective cathodic protection was achieved under this progressively deteriorating coating condition which incurred a risk of carbonate-bicarbonate stress-corrosion cracking.

STUDY RESULTS

A task force reviewed these problems together with the results obtained from extensive line inspection and intelligent-pigging operations.

Reasons of coating failure were investigated by a recognized corrosion center. The investigation's scope covered assessment of FBE as coating system, adhesion and curing, cathodic disbonding, and analysis of corrosion on a sample of in-service pipe which had failed and on a sample of unused stored pipe.

Following are the report's principal findings:

• In 1982, the evaluation options for coating on an onshore line operating at 80 C. and subject to aggressive soil stressing were FBE, coal-tar enamel, and polyethylene two-layer with bituminous adhesive.

• FBE was the logical selection because the other two systems were at the limits of their capabilities at the specified temperature particularly in hostile environment.

• FBE is a thermosetting resin and will not soften on heating.

  But on prolonged exposure to high temperature, it will become brittle and, when subjected to wet-dry cycling, will further degrade and disbond.

  Analysis of the in-service pipe sample indicated the following characteristics:

• Adhesion, assessed to ASTM D3359-A, was found low in general, and microscopy showed evidence of lack of flow of coating. The film was not fully consolidated. Surface preparation was adequate (Swedish standard SA 2.5).

The aggressive soil stressing in Sabkha areas coupled with wetting and drying of thin FBE coating had caused loss of weight and disbonding.

In Sabkha, electrical continuity between line pipe and anodic ground beds was subject to disruption because of shrinkage of the moist clay soil off the lower quadrant of the warm pipe commonly known as "cocooning."

Analysis of the unused pipe sample indicated that, in appearance, the coating has a slight "orange peel" appearance indicating lack of flow.

The film thickness was acceptable (260-320 u), holiday detection adequate, and adhesion satisfactory.

The microscopy indicated poor flow and lack of consolidation of epoxy powder on curing.

The short-term recommendations of the task force were to repair all anomalies and hydrotest the line, upgrade the existing CP system, and conduct an intelligent-pigging survey annually and carry out repairs as necessary.

For the long-term, the task force recommended replacement of the four trunklines with new ones.

The short-term remedy of the Thamama C gas-gathering system was implemented successfully.

Eight bonding facilities were connected with the newly installed cathodic-protection solar units. An average of 8 amp was drained at each bonding facility.

REPLACEMENT PROJECT

The long-term solution was also selected.

The terms of reference were prepared and an EPCM (engineering, procurement, construction management) contract was awarded in May 1991.

The scope of engineering services included optimization of installation options, pipeline configuration, gas leak detection, line-pipe sizing, coating system, and line-pipe material.

The optimization studies dealt with each of the following:

• Installation options. In dry sand areas, the line should be buried and coated as indicated presently. In saline hostile areas, several options appeared.

  For the bermed option, the pipeline would be installed on the grade on a pad of clean sand and an isolation layer to stop the capillary action of salt water.

  The isolation layer would consist of stone and membrane. Then the line would be surrounded by sweet sand.

  The other three options included routing the line aboveground on supports, burying it, or laving it on the surface and then mounding it over with local material.

• Pipeline configuration. A four-trunkline system with unified diameter for each trunkline was indicated as the optimum for simplifying pigging operations and reducing safety risks without jeopardizing the flow regime in the front section of each trunkline.

  This was achieved by extending the 6-in. flow line from the first well of each of the four legs to the second well where each 12-in. trunkline starts.

• Gas-leak detection. The gas composition indicated that the most sensitive component to be detected is H2S. Therefore, gas on wellhead site is detected by means of H2S detectors located around the wells, flow lines, pig launchers, and receivers.

  In the case of gas detection, an alarm is triggered in the control room, and a siren or beacon is activated. Wells are shut down manually or through the supervisory control and data acquisition (scada) system.

• Line-pipe sizing. A unified size of 12 in. was selected.

  Wall thickness of pipeline was increased to 10.3 mm (0.406 in.) to accommodate B31.8 Class H design, instead of Class 1.

• Coating system. During inquiry, the following systems were proposed for coating:
  • For buried lines, a three-layer FBE as a primer of 70 u and polymeric adhesive (350 u) to provide a sound adhesive bond to the outer polypropylene layer (2.5 mm).

    The total three-layer thickness ranges between 2.4 and 3.4 mm (approximately 95-105 mils).

  • For over-the-ground lines, an exposed paint system with 260 u dft total, consisting of primer, first coat high-build (HB) micaceous iron oxide, second coat HB, and a polyurethane coat finish.

• Line pipe material. The pipe material for the existing system is API Grade 5 X-60 ERW. The pipe was specified for resistance to HIC.

During the optimization study, alternative materials were investigated. High operating temperatures limited the choices to the following:

1. Titanium and titanium alloys which depend on a protective titanium dioxide (TiO2) film for corrosion resistance. To avoid brittleness, processes for heating, melting, and welding must be conducted in inert environments.

   This condition constitutes a limitation during installation. Additionally, it is not proven for sour-gas application and is very costly.

2. Duplex and super stain-less steels which are very costly and could be subjected to localized attack from chlorides at saturation point which could result in stress-corrosion cracking.

3. Cladded materials. External cladding is impractical and imposes limitations in cost, time, and field welding.

4. Nickel-chromium-molybdenum (Inconel, Hastelloy, and others). Inconel 625 and Hastelloy G-50 are metallurgically sound alternatives to carbon steel but very costly, on the order of 9-12 times compared to the cost of carbon steel.

MATERIAL SELECTED

To achieve an extended design life of 30 years, exhaustive studies were carried out to yield a method for strictly controlling corrosive mechanisms in the exceptionally aggressive environment.

These studies resulted in the optimized selection of line pipe material of limited-chemistry carbon steel pipeline material.

It was believed to be the most cost effective and offered fewest technical and logistical limitations.

API grade X-60 ERW was found to be the best choice.

Specifications were set to provide resistance to HIC through an improved chemical composition steel of high copper content (0.3-0.35%), low carbon content (0.080.12%), carbon equivalent (CE) 0.35%, and lower content of all other elements.

The studies also indicated the optimum installation option. The following three methods of installation were considered:

• Buried. In the very hostile Sabkha and at high operating temperatures, burial was not deemed suitable for different reasons, particularly limited cooling and CP effectiveness.

• On-ground and mounding over with local material. Limitations for this installation method were felt to be identical with those of the burial option.

• Aboveground. The pipeline would be exposed, either laid on separate supports or continually buried on ground in an engineered berm containing an isolation barrier to prevent the pipeline's surroundings from becoming contaminated by capillary action.

Installation was finally carried out as an overground pipeline on a continuous elevated (1.5 m) bund which also acts as a barrier against vehicle crash.

Bund material is a well compacted gatch (92% min.) with selective sieve and chemical analysis. Based on chemical analysis, the gatch consists of no more than 10% gypsum and soluble salts, with the maximum content of gypsum limited to 5%.

The 12-in. pipeline lies on epoxy-coated concrete sleepers, placed at an equidistance of 12 m, with a clearance of 0.3 m to prevent sand accumulation and with expansion loops every 1 km. The line's paint system is epoxy with 260 u dft.

Non-destructive testing was also strictly specified with 100% X-ray crawler type for the 12-in. line with high-sensitivity film.

The four trunklines have now been completed. Three lines have already been commissioned and are in steady operation. Commissioning of the fourth line is imminent.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.