Studies reveal best installation, coatings for desert gathering lines

Kamal M. Morsi
Abu Dhabi National Oil Co.
U.A.E.

• Magnetic induction coils preheat the field joint to 240° C. in a process required for the powder-spray application of a primer coat of FBE and an adhesive layer. [10,534 bytes]

• The circumferential seam between the factory-applied polypropylene pipe coating and the field-joint polypropylene wrapping is plastic-welded with a mechanical assembly to rotate the hot-air welding head around the pipe. [6,959 bytes]

• The flame-spray technique involves spraying the FBE-coated field joint with small molten drops of polypropylene. This sprayed powdered polypropylene passes through a well-controlled propane flame. For greater productivity (as here), two applicators can be positioned on either side of the joint to be coated. [9,968 bytes]

Intensive study of corrosion problems for pipelines buried in highly saline desert areas, known as "Sabkha" in Abu Dhabi, led to replacement of lines aboveground, rather than buried, and to a change in their external coatings.

The investigations by Abu Dhabi National Oil Co. (Adnoc), U.A.E., examined the factors affecting the choice of aboveground or underground installation of pipelines. The factors were pipeline operating temperature, soil conditions, environment, installation method, and aesthetics.

Among the study's findings were that the required cathodic protection (CP) is fundamentally different: Aboveground pipelines only require small-scale CP systems at buried road crossings, whereas buried pipelines need protection over their entire lengths.

The study also compared the risks of coating deterioration and external corrosion on buried pipelines with the simplicity of external inspection and maintenance on aboveground pipelines.

Thamama C system

The project involved Adnoc's original underground Thamama C gas-gathering system and subsequent trunklines replacement and gas-gathering expansion for this system.

The Thamama C gas-gathering system was initially commissioned in 1984 and consisted of 19 gas producers connected to a central gas plant via four trunklines (Fig. 1 [59,266 bytes]). The flow lines and trunklines were fusion-bonded-epoxy (FBE) coated and buried in dry desert, or Sabkha, with the field joints protected by heat-shrink sleeves.

The operating temperatures of some flow lines exceeded 90° C. Leaks, caused by external corrosion in areas of coating breakdown, occurred within 7 years of commissioning.

Following these failures, extensive studies were carried out during 1991 to investigate various coating types. Information was gathered from other operators regarding the service histories of various coatings.

The objective of these investigations was to establish the optimum pipeline and field-joint coating systems required for high-temperature service in Sabkha conditions. The investigations revealed considerable uncertainty over the long-term resistance of even the best coating systems in hot saline Sabkha conditions.

The subsequent trunkline replacements (1992-1993) were therefore installed aboveground on continuous elevated bunds to ensure complete clearance of the Sabkha. An additional five wells were connected to the replaced system (Fig. 2 [60,375 bytes]).

At the end of 1993, expansion of Thamama C system was initiated.

After careful consideration, it was decided that a three-layer polypropylene coating was capable of enduring Sabkha conditions even at temperatures greater than 90° C. Accordingly the underground option was considered. A new trunkline connecting six wells was added (Fig. 3 [62,410 bytes]), and the system was commissioned in 1996.

A further major expansion planned for the Thamama C gas-gathering system envisions the drilling of an additional 18 wells and installation of three additional trunk lines (Fig. 4 [63,206 bytes]). The coating type and installation method for the previous expansion will also be used on the planned expansion.

Original system

In 1982, Abu Dhabi National Oil Co. (Adnoc) initiated a project for the gathering and processing of gas produced from the Thamama C reservoir. The gathering system consisted of 19 wells which produce natural gas and associated condensate.

It was decided that the optimum gas-transmission system to the plant would be four buried trunklines each connected to four or five wells. The four trunklines terminate at the main processing plant in four gas separators provided with the necessary relief valves to protect against overpressure.

Thamama Zone C gas is produced from limestone. H₂S and CO₂ contents in existing wells range 0.7-8.0 mole % and 4-8 mole %, respectively. The original pressure of the Thamama C reservoir is 4,300 psig at 8,500 ft subsea with a bottomhole temperature of 260° F.

The prevailing soil condition defines what is meant by "Sabkha": very corrosive with high water salinity and high water table.

Corrosion problems

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

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

The line pipe material, as well as the other carbon-steel materials for pressure-containing equipment and pig launcher and receiver barrels, were selected to meet the relevant requirements of NACE standard MR-01-75 for sour service.

The line 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.

Internal-corrosion protection against attack by sour wet gas is provided through a combination of corrosion inhibition and periodic pigging. A continuous downhole open chemical-injection system is provided; it utilizes the casing/tubing annulus as the injection conduit.

The annulus between the tubing and casing 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.

The pipeline size was selected to maintain the velocity in the range of 10-40 fps for effective distribution of the corrosion inhibitor. Cleaning and pigging of the trunklines are carried out at regular intervals to remove water and gas condensate. Cleaning is done every 45 days.

The four trunklines are buried. The soil conditions are of two general types, wet highly saline soil (Sabkha) and loose dry desert sand.

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

• A factory-applied FBE coating of 300 ?m dry-film thickness (dft)
• Heat-shrink sleeves for wrapping the field welded girth joints
• An impressed-current cathodic-protection system consisting of one transformer-rectifier of 30 amp/48 v and silicon-iron ground bed.

At the time, the factory- applied FBE was considered to be suitable for a high gas temperature service (90° C. maximum at the wellhead).

Operating problems

In 1985, surveys on the pipelines indicated significant decreases in CP potentials along all the trunklines to less than minimum protective levels. Remedial action was taken by installing extra current capacity to upgrade the cathodic-protection system.

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

Subsequently, external corrosion problems have 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 disbondment especially in saline-soil areas.

External corrosion beneath disbonded and blistered coating was mostly found in the bottom half of the pipe. The corrosion resulted in a number of 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. In dry desert sand areas, the coating was found in a better condition than that in saline-soil areas.

Intelligent-pig surveys carried out in 1989 and verified by subsequent local excavation revealed widespread coating disbondment and external corrosion especially in hostile saline areas.

A detailed soil-resistivity survey carried out in early 1989 identified areas of low resistivity. It has been 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.

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

Causes of coating failure were investigated by a recognized corrosion center. The scope of its investigation covered assessment of FBE as a 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, options for coating onshore pipelines operating at 90° C. and subject to aggressive soil conditions were FBE, coal-tar enamel, or two-layer polyethylene with bituminous adhesive.
• FBE was the logical selection; the other two systems were at the limits of their capabilities at the specified temperature, particularly in hostile environments.
• FBE is a thermosetting resin and will not soften on heating. But on prolonged exposure to high temperature, it will become brittle. When subjected to wet/dry cycling, it will further degrade and disbond.

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

• Adhesion, to ASTM D 3359 A, was found low in general, and microscopic examination showed evidence of lack of flow in the coating (that is, the film was not fully consolidated)
• Surface preparation was adequate to Swedish Standards SA 2.5
• The aggressive soil conditions in Sabkha areas coupled with wetting and drying of thin FBE coating caused loss of weight and disbonding
• In Sabkha, ionic continuity between line pipe and anodic ground beds was subject to disruption as a result of shrinkage of the moist clay type of soil away from the lower quadrant of the warm pipe commonly known as "cocooning."

Analysis of the unused pipe sample indicated the following:

• Appearance: The coating has a slight "orange peel" appearance indicating lack of flow.
• Film thickness: acceptable (260-320 µ)
• Holiday detection: adequate
• Adhesion: satisfactory
• Film continuity: Microscopic examination indicated poor flow, lack of consolidation of epoxy powder on curing

Installation options

It was decided to implement a new project entitled "Thamama C Trunklines Replacement." Scope of engineering services included the optimization of installation options, coating system, and line pipe material.

In dry-sand areas, the line should be buried and coated, as described presently. In saline hostile areas, the following options were evaluated:

• Aboveground

–Bermed option (that is, installing the pipeline above grade on a pad of clean sand with an isolation layer to stop the capillary action of salt water). The isolation layer consists of stone and membrane. Then the line is covered with sweet sand (Fig. 5 [41,253 bytes]).
–On continuous elevated bund and concrete sleepers to ensure complete clearance above the Sabkha (Fig. 6 [56,979 bytes]).

• Underground option
• At grade level and mounding over with local material.

The studies showed the aboveground options minimize corrosion risk; buried options minimize pipe congestion.

The following aspects were considered in the selection of installation method:

• Aboveground option

–Exposed lines cool the gas; increase the risk of hydrates and increase pigging frequency (Fig. 7 [44,923 bytes]).
–Piping congestion and road crossing
–Risk of damage by vehicles or sabotage

• Underground option

–Corrosion risk in wet Sabkha
–Beneficial thermal insulation
–No piping congestion and no problems with road crossing
–No risk of damage by vehicles or sabotage.

The second aboveground option (on continuous elevated bund and concrete sleepers) was selected for the Thamama C trunklines-replacement project.

The criteria for the support system selection included noncorrodible in Sabkha, minimum foundation works (cost and time), lightweight and small size, easy to install, and not affected by sunlight in hot desert conditions.

Coating; pipe material

After a study of the coating options, the following systems were proposed for the lines:

• For underground lines (in dry sand areas). A three-layer system consisting of a 70 µm primer FBE coating and a polymeric adhesive layer (350 µm) to provide a sound adhesive bond for the outer polypropylene layer (2.5 mm). Total thickness for the three-layer system ranges between 2.4 and 3.4 mm (approximately 90-140 mils).
• For aboveground lines (in Sabkha areas). An exposed paint system with 260 ?m total dft, consisting of primer, first coat high-build micaceous iron oxide, second coat high build, and a polyurethane coat finish.

The pipe material for the original system was API 5L grade X-60 ERW. The pipes were specified for resistance to HIC. During the optimization study, alternative materials were investigated.

High operating temperature limited the choice of material to titanium and titanium alloys, duplex and super stainless steels, cladded material, nickel-chromium-molybdenum (Inconel, Hastelloy, and others).

Carbon-steel pipeline material with a precisely specified chemistry was found to be the most favorable option, being the most cost effective and having the least technical and logistical limitations.

API 5L Grade X-60 ERW was found to be the optimum. 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 (0.08-0.12%), carbon equivalent (CE) 0.35%, and lower content of all other elements.

The aboveground trunklines were laid on epoxy-coated concrete sleepers placed at intervals of 12 m allowing a clearance of 0.3 m in order to be clear of any sand accumulation under the pipe. The flow lines also incorporated expansion loops at every 1 km.

This system was commissioned in 1994 and is now operating without problems.

The Thamama C trunklines-replacement project overcame the previous problems by using innovative pipeline installation methods, advanced pipeline coating technologies, and sour-service linepipe steels manufactured to strict specifications.

Expansion project

At the end of 1993, an expansion of the Thamama C system was planned which envisioned the drilling of an additional six wells and installation of a new trunkline.

Comprehensive studies looked at various options for flow line and trunkline coatings and installation methods. The experience of other operators was investigated.

Studies involved a full technical and logistical review of shop and field-applied coatings, experienced coating contractors, operational experience, and installation requirements.

Over recent years, the greatest development has been in multilayer coating systems which have incorporated FBE primers with extruded-polyolefin outer coatings. The most impressive track record to date has been gained by three-layer polyethylene systems. Polyethylene has a temperature limitation of 80° C., however, which made it unsuitable for this project.

A similar but higher-rated coating system which utilizes polypropylene rather than polyethylene is also available. (The accompanying box summarizes other operators' experiences in pipelines coating.)

The data gathering led to the conclusion that a below-grade installation could be implemented successfully.

Because of the high design temperature, however, together with the aggressive Sabkha soil, the choice of available coatings is severely restricted.

This problem is further compounded by the requirement for a comparable and effective field-joint coating and repair system, which is essential if the integrity of the overall coating system is to be maintained and the pipeline system adequately protected throughout the 30 years' design life.

A review of all proven available coating systems led Adnoc to conclude that the two and three-layer polypropylene and polymers derived from ethylene propylene diene monomers (EPDM) are suitable for the service conditions involved. Of these, the EPDM system appears to be the most expensive.

A cost comparison shows that the selected three layer is less expensive than the Duval (Dupont Canada and Valspar Inc.) two-layer polypropylene system. This fact, combined with the stringent shop-coating requirement for two-layer polypropylene systems, has led to the conclusion that the three-layer polypropylene system (Fig. 8 [36,243 bytes]) is the preferred option.

As a result, this has been adopted for the Thamama C expansion project.

It was also concluded that, in order to provide buried lines with maximum protection, we should connect temporary anodes to the system during construction until the permanent impressed-current CP system is brought into operation.

Coating selection

It was essential that the same considerations given to the selection of the line-pipe coating should also be given to the field-joint coating, with the added complication of application in a desert environment.

The following coating systems were examined during the field-joint coating selection process:

• Sintered field joint. In this coating system, a mixture of powdered FBE and polypropylene is sprayed onto heated pipe, where it melts and fuses with the pipe coating.
• "Smart" field joint. In this coating system, a mixture of FBE and adhesive is sprayed onto heated pipe, which is then wrapped with a sheet of polypropylene. This is encapsulated within a heated compression clamp which softens the polypropylene and fuses it with the line-pipe coating.
• Flame-sprayed field joint. In this coating system, chemically modified polypropylene powder is sprayed through a flame onto an FBE-coated field joint. The polypropylene powder melts as it passes through the flame where it solidifies and bonds directly onto the FBE when it strikes the pipe.
• Heat-shrink sleeves. Of the heat-shrink sleeves available at that time, none would form a totally effective bond with a polypropylene pipe coating. Actual tests in a laboratory produced failures at 55° C.
• Co-extruded sheet system (wrap, glue, and weld). This new method was developed specifically for the Thamama C expansion project and involves the wrapping, gluing, and plastic welding of a special co-extruded sheet material around the joint.

This sheet material consists of chemically modified polypropylene on one side and normal polypropylene on the other (Fig. 9 [43,766 bytes] and Fig. 10 [34,876 bytes]).

The modified inner surface will bond strongly to an adhesive-coated FBE primer, and the normal outer layer can be plastic welded to the factory-applied, three-layer polypropylene on the parent pipe. The co-extruded polypropylene sheet was applied on all the field joints on the Thamama C gas-expansion project.

Design implications

Adnoc's experience with these projects suggests the following design points:

• No single installation method is ideal.
• For underground pipelines in Sabkha areas, the highest quality of external coating is required.
• The selection of pipe coating should also take account of the ease of application and reliability of available field joint coatings.
• Risk of hydrates must be determined in all parts of the system.
• Thermal insulation cancels out the inspection advantages of aboveground pipelines.

The front-end engineering design (FEED) for the Thamama C major expansion project has been completed and the tender for engineering, procurement, and construction has been issued. This project envisions the drilling of an additional 18 wells and the installation of three additional trunklines.

The coating type and installation methods applied on the previous expansion project will also be applied on the planned future expansion project (that is, three-layer polypropylene coating and co-extruded polypropylene sheet field joint coating).

Commissioning of this project is planned for the middle of 2000.

The Author