Copyright 2003, Offshore Technology Conference This paper was prepared for presentation at the 2003 Offshore Technology Conference held in Houston, Texas, U.S.A., 5–8 May 2003. This paper was selected for presentation by an OTC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference or its officers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.

Abstract

The BP Bombax Pipeline Project in Trinidad involved the design and installation of a 48-inch diameter subsea gas trunk line. This line is the largest subsea pipeline operated by BP in the world. The immense scale of this pipeline and associated appurtenances provided many design and construction challenges, among these was the selection and application of the anti-corrosion and concrete weight coating systems. Compounding this challenge was the requirement that the system have a design life of 50 years.

Coatings are the primary method of protecting the external surface of metallic structures from the corrosive effects of seawater and sediment. Typically the coating system is supplemented by a cathodic protection system.

Concrete weight coating is commonly employed on large diameter pipelines to increase on-bottom stability. A number of concrete coating application methods were evaluated and two such methods were employed. Wire reinforcement is required within the concrete to minimize spalling. Due to the unprecedented size of the main trunkline, common re-enforcement practices were analyzed to ensure success.

Bonding between the concrete weight coating and the corrosion coatings is of paramount concern on large subsea pipelines to prevent slippage due to the high lay-tensions imposed on the pipeline during installation. In order to select the optimal system, several bonding methods were tested for use on the project. Introduction

In response to the increasing demand for energy in the form of natural gas, BP Trinidad and Tobago has started expanding its offshore fields and gas transportation system to supply new LNG trains at Point Fortin on the West side of Trinidad as well as the increased local domestic market. There are two projects currently underway to expand production and transportation of gas from 1.5 bscfd to 3.0

bscfd, the Kapok Project and the Bombax Project. The Kapok Project comprises a new 2.6 BCFPD production platform, Cassia ‘B’ that is bridge connected to the existing Cassia ‘A’ platform and a new drilling platform Kapok. The Bombax Pipeline Project includes 63 km of 48-inch offshore pipeline from Cassia ‘B’ to landfall at Rustville, on the East Coast of Trinidad. From the landfall, the pipeline extends 1.8 km onshore to the existing Beachfield slug catcher and production facility for onward transportation of gas to the various industries on the island including the LNG facilities on the West Coast. The offshore end of the 48-inch pipeline is connected to the existing 40-inch pipeline via a 20-inch subsea jumper. This jumper facilitates looping of approximately 2/3’s of the existing 40-inch pipeline thereby expanding the transportation system capacity.

Additional gas production to meet the growing industrial demand will be supported by a new wellhead platform located at the Kapok field along with continued development of existing fields. The Kapok platform is linked to the Cassia ‘B’ production hub by a 26-inch multi-phase pipeline installed as part of the Bombax Pipeline Project. Due to the development schedule, the Kapok platform will be ready for production before the Cassia ‘B’ hub topsides are available. To allow Kapok to produce early gas, it is intended to carry out separation on Kapok with the test separator and transport liquids via a new 6-inch line to the existing 12-inch liquids line. The 12-inch liquid line transports liquids to shore from BP’s existing platforms originating from the Mahogany platform. Tie-in to the existing 12-inch liquid line is via a pre-existing subsea hot-tap tee. The Kapok separated gas is then transported via the 26-inch line to the subsea manifold and into the 48-inch pipeline for transportation to the Beachfield facility via an early gas jumper on the manifold. Figure 1 provides a layout of the new Bombax development and the existing pipelines.

To satisfy the requirements for the Cassia B platform safety, a check valve for the 48-inch export pipeline, and an SSIV for the incoming 26-inch line from Kapok are required. Additionally, the project required the installation of an actuated valve in the 20-inch line looping the 40 and 48-inch pipeline to enable isolation of the large gas inventories in these lines if needed. In light of the complexity required to meet the project requirements, it was decided to accommodate the valving and piping within a single manifold structure. Also in line with the project’s objective to maximize the use of local content, the manifold was constructed in Trinidad. Add

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Bombax Pipeline Project: Anti-Corrosion and Concrete Weight Coating of Large Diameter Subsea Pipelines John. La Fontaine - Champlain Group, Inc.; Derek Smith - JP Kenny Inc; Gary Deason - Bredero Price; Gary Adams - BP

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to this individual 48-inch, 26-inch and 20-inch tie-in spools of up to 300 feet long and 270 tons, collectively Bombax presented an interesting and challenging project.

Figure 1 Bombax Field Layout

Anti-Corrosion Coating

Requirements. The project team selected the pipeline anti-corrosion coating system based on several criteria. First among all requirements was that any system utilized for this project, coating or other, must meet the highest standards from a health, safety, and environmental (HSE) standpoint. The system must also be capable of providing high levels of corrosion protection for the life of the field. This requirement was of particular concern given the 50-year design life required for the pipeline. The system must also be compatible with the concrete weight coating.

Options. Pipelines in general rely on a system of coatings as the primary defense against external corrosion. These coating systems are coal tar enamel (CTE), asphalt enamel (AE) and fusion bonded epoxy (FBE). The type of coating available varies between the different geographical regions of the world. For example, FBE is more commonly used in North America and AE is used in the UK. CTE is still offered in Asia. Each of these systems was considered for use as the primary coating system for the Bombax pipelines. The evaluation was based on HSE, performance, economics, and availability criteria.

Comparison. Due to the surface profile and adhesion characteristics with respect to concrete, both CTE and AE require little, if any, modifications to achieve a high strength bond with the concrete weight coating (CWC). Both CTE and AE are more flexible than FBE and have a greater impact resistance. AE and CTE also provide a secondary thermal insulation capability resulting from the greatly increased coating thickness of these systems compared to FBE. CTE and AE cost approximately 10 to 20% less, respectively, than FBE on a surface area basis. However, FBE has superior adhesion characteristics in comparison to both CTE and AE, which is a crucial factor in light of the long design life requirement. CTE and AE plants were not available in the USA or Trinidad at the time of the evaluation. As a result of the evaluation, FBE was selected for the Bombax pipelines.

A summary of the comparison is shown in Table 1.

Coating System Fusion Bonded Epoxy

Coal Tar

Epoxy

Asphalt Enamel

Thickness (minimum) 0.012” 0.200” 0.200” Rough Coat Thickness (minimum) 0.003” Not

Required Not Required

Service Temperature Maximum 90-C 80-C 65-C

Cathodic Disbondment Resistance Excellent Good Good

Flexibility Good Good Good Impact Resistance Good Excellent Excellent

Availability Worldwide Asia Asia & Europe

HSE Good Fair Fair Table 1

Comparison of Anti-Corrosion Coatings

The Bombax Coating System. Coating systems for large diameter subsea pipelines in general must be thick enough to provide a diffusion barrier to oxidants, tough enough to withstand pipe movement and handling, and withstand the rigors of the CWC application process. Industry practice has shown that FBE applied to a 0.014-inch (± 0.002-inch) thickness will provide a sound anti-corrosion barrier. However, this thickness is not sufficient to withstand application of CWC by the impingement method. When concrete is impinged, it impacts the anti-corrosion coating at high velocity. In order to achieve the toughness required to withstand this process, FBE must be applied to a minimum thickness of 0.026-inches. This requirement was confirmed by stripping the CWC from several pipe-joints which had been coated with 0.026-inches of FBE. Once stripped, the FBE coating was inspected for holidays both visually and by voltage indication (jeeping)(1), to ensure that the coating had satisfactorily withstood the CWC application. It was found that there was no damage to the FBE coating. CWC applied using the wrap method does not require additional FBE thickness beyond that required to achieve an anti-corrosion barrier.

In addition, it was determined that the FBE anti-corrosion coating must be augmented with a rough overcoat in order to achieve the required shear strength between the CWC and FBE. Rough coat powder is a modification of the FBE anti-corrosion coating powder. The rough coat FBE powder contains larger particulates, which provide an anchor profile upon fusing to the anti-corrosion layer. A rough coat thickness of 0.003-inches (minimum) was utilized for the Bombax pipelines.

Typically pipe coatings are terminated a short distance from the pipe bevel, this is commonly referred to as the “cut-back”. Industry practice usually requires a minimum cutback of 2-inches. However, certain CWC plants manipulate pipe on rollers on each end of the joint. In the case of the Bombax impingement plants these rollers had a width of 8-inches. Coated pipe with a 2-inch cutback would suffer end damage and require repair when contacted by these rollers. As a result, it was determined that the FBE coating should be cut back a minimum of 8.5-inches to avoid such damage.

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Production. FBE application of line pipe is a highly automated process. Bombax pipe coating requirements were based on industry standards including NACE RP 394(2). The coating process begins by load-in of the pipe into the plant. At the load-in rack, a coupling is inserted and secured in the I.D. bore of the lead end of each pipe prior to being indexed onto the cleaning line conveyor. The coupling serves two purposes: 1) Protects the pipe ends from potential mechanical damage that may be caused during the process of the pipe being conveyed down the cleaning line. 2) Prevents the pipe ends from sagging while the pipe travels through the cleaning process (Shot Blasters). The pipe surface is also inspected for salt contamination and other defects such as end and body wall damage. The pipe is then conveyed down the cleaning line where a system of solid rubber tires, positioned with a slight pitch so as the pipe rotates it travels in a forward motion. Here the pipe is pre-heated to remove surface moisture, blast cleaned, acid washed, rinsed then blasted again to SSPC 10 / ISO 2.5 surface profile (0.002 to 0.004-inch). After the final blast the pipe is indexed into a mid-rack station where the surface of the pipe can be checked for defects (Figure 2).

Figure 2

Mid-Rack area of FBE Plant If significant defects are found the pipe can be indexed

back to the load-in stage for re-blasting. After the mid-rack inspection, the pipe is then indexed onto the coating line, which begins with a series of induction coils (Figure 3).

Figure 3

Induction Coils The induction coils raise the surface of the steel to between

450 and 500°F. It is critical that proper controls are instituted to ensure the pipe surface is not over heated. Temperatures of greater than 525°F can adversely affect the mechanical

properties of the pipe. Bombax utilized a combination of heat sticks and infrared cameras to monitor surface temperature. After passing through the induction coils the pipe travels immediately into the coating booth. The coating booth contains the application nozzles for both the anti-corrosion coating and rough coat. The FBE powder is applied within this booth utilizing an electrostatic spray (Figure 4).

Figure 4

Electrostatic Spray

After coating the pipe continues into a quench line where the pipe is inundated with water. The pipe is then indexed to the out-bound rack where it receives a final inspection, prior to transport to the concrete coating plants (Figure 5).

Figure 5

FBE Out-Bound Rack Inspection

Special considerations should be made when FBE coating large diameter heavy wall pipe. The Bombax 48-inch diameter by 1-inch wall thickness pipe weighed 18,000lbs, without concrete. Pipe of this size is an order of magnitude heavier than most pipe that is coated in automated coating mills. In the case of Bombax, the FBE plant set up time took several days longer than usual. Among the items that require change over are the cleaning line and coating line conveyors, the induction coils, and the FBE booth, which requires many more application nozzles to coat large diameter than smaller diameter pipe. Change over times should be considered for large diameter pipe if schedule is an issue, particularly if the mill must be changed several times to coat other size pipe. Large diameter DSAW pipe have large crowns on the longitudinal seams, which can “shadow” the adjacent pipe

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when passing through the blast booth. Bombax pipe suffered slightly from this phenomenon, however the problem was quickly remedied by making adjustments to the blasting booth. Concrete Weight Coating

Background. A significant step in the engineering process of subsea pipelines is to ensure the line will have sufficient on-bottom stability. The stability of the pipeline is a function of several factors including the magnitude of the ocean waves and currents and the negative buoyancy of the pipeline. Large diameter lines displace a large volume of water, which results in increased buoyancy and their large surface area creates inherent stability problems. There are several ways to remedy this problem. One option is to increase weight by increasing the wall thickness of the pipe. However, this is often not an attractive option from a commercial perspective. The optimal solution involves having enough steel wall thickness for pressure containment, internal corrosion allowance, and installation stresses, then coating the pipe with concrete to provide the additional mass that is required for stability.

Application Methods. Concrete weight coating can be applied by casting, wrapping or impingement. The casting method involves placing the wire reinforcement and a mould around the pipe, then pouring the concrete into the annulus. Vibrating the assembly ensures the mix is distributed properly. The mold is removed after the concrete has cured sufficiently. The curing process is then progressed using a wrap membrane, or by periodically applying water, until the threshold compressive strength is achieved. Casting of CWC is most frequently used for short spans, such as river crossings; however for large quantities of pipe this method is impractical. The wrap method is used extensively for subsea pipelines. Wrapping or "compression" plants are semi-automated. The pipe joint travels through the plant on a conveyer that comprises of a system of gearboxes and solid rubber tire, positioned with a slight pitch so as the pipe rotates it travels in a forward motion through the plant and past the concrete coating applicator. As the pipe rotates and travels past the concrete applicator, the cement, aggregate and water is being continuously mixed inside a pugmill mixer and fed onto a conveyor feed belt into the applicator hopper onto an applicator belt. Between the concrete mix and the applicator belt is the wire mesh reinforcement and outer plastic wrap that will act as the curing membrane. The mix, wire mesh reinforcement and membrane are wrapped around the pipe simultaneously as it travels past the coating applicator (Figure 6).

Figure 6

Wrapping Concrete Weight Coating

After the pipe is coated it is indexed to the final inspection rack where the concrete is cut back from the ends, O.D. measurements are taken and the pipe joint is weighed. The information is then documented per unique pipe number and entered into a computerized program where the negative buoyancy of each pipe is verified. Pipe joints requiring anode installation are then moved to the cut out saw, where the concrete coating is cut away in preparation for anodes.

Impingement application of concrete is also a semi-automated process. Unlike the wrap method, end rings are installed onto the pipe ends on the inbound rack. The purpose of the endrings is to establish the concrete coating cutback at the pipe ends as well as a means of anchoring the wire reinforcement to the pipe in order to commence the application process. The pipe is then placed onto a rotation buggy, where it is supported on an eight inch surface at the pipe ends. The rotation buggy is utilized for roating the pipe while traveling past the throwing unit applicator. Once the pipe has been placed on to the rotation buggy it is maneuvered infront on the throwing unit. The wire is secured and the pipe then begins to rotate while moving past the throwing unit applicator (Figure 7).

Figure 7

Impingement Method of Applying Concrete

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Concrete coating applied by the impinged method is thrown onto the pipe surface by a set of turning vulcanized rollers. Cement, aggregate and water are continuously mixed inside a pugmill mixer and fed onto a conveyor feed belt. The conveyor feed belt supplies the throwing unit with a continuous supply of concrete mix the mix impinges upon the surfaces of the pipe at high velocity (approximately 40 m/sec). After the pipe is coated and weighed, it is placed into a curing area where water is introduced onto the coating until the specified compressive strengths of the concrete coating have been achieved. The endrings are removed, and wire is trimmed from the edges and anodes. Anodes are installed prior to applying the CWC (during the coating process a shield is placed between the throwing unit and anode to prevent coating the anode).

Both impinged and wrap concrete often requires touch up repair, and infill in the gaps surrounding the anodes. This is accomplished using gunnite. Gunnite is a mortar type compound, which is pneumatically blown out of the end of a pump hose onto the substrate. While the concrete is wet, it can be trimmed with a trowel or shovel. A summary comparison between the Wrap and Impingement methods is shown in Table 2.

Method Wrap / Compression Impingement

FBE thickness Required (min.)

0.012-Inches 0.026-Inch

Method of Curing Membrane Water Pipe Sizes Up to 48-Inch All Sizes Availability Common in N.

America Worldwide

Wire Reinforcement Per BS 8010 Per BS 8010 Anode Attachment After CWC Before CWC

Table 2 Comparison of Concrete Weight Coating Methods

Shear Tests. In order to achieve the required shear strength between the CWC and the FBE coating, several bonding systems were evaluated. The systems were, rough coat alone bonding the concrete to the FBE coat, and rough coat with a bonding adhesive applied in 3-inch bands covering 50% of the pipe surface. The purpose of the test was to ensure the shear strength of the bond between the CWC and FBE would withstand the large tensions that the 48-inch pipe would endure during installation. The test was performed by pushing the CWC coat utilizing four 100 metric ton hydraulic jacks.

A magnetic dial gauge is attached to the pipe and the probe touches the area under the CWC such that any movement of the concrete can be detected. The results of the test were dramatic. Slippage of the concrete on the pipe without adhesive initiated at a force of 25 metric tonnes. The pipe with adhesive withstood a force 150 metric tonnes without slippage. This force exceeds the highest single tensioner available on modern lay vessels. As a result of this test adhesive was applied to the rough coat FBE during the CWC application process.

Bombax Requirments. The on-bottom stability analysis of the Bombax 48-Inch trunkline revealed it would require a range of CWC thickness of between 3.75-inch on the majority

of the pipeline mid-depth to 5-inches on the shore approach sections. The 26-inch diameter pipe would require 3-Inches of CWC and 4-inches on the spoolpieces. Due to diameter restrictions of wrap/compression plants, all of the 48-inch CWC pipe except for the thin wall pipe with 3.75-inch CWC was coated utilizing the impingement method. The remainder, including all of the 26-inch diameter pipe was coated using the wrap method. Cores were taken from the CWC to verify the strength and quality throughout production. Compressive strength minimums are required to ensure integrity of the weight coat not just during installation, but also for handling within the coating yard. The concrete was required to reach a compressive strength of 3500psi after 7-days and 5300psi after 28-Days. The quality of the concrete was very good and as a result it easily achieved these minimums (Figure 8).

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

0 4 8 12 16 20 24 28

Days

Com

pres

sive

Stre

ngth

(P

SI)

Figure 8

Bombax concrete weight coating compressive strength increase vs. time

Wire reinforcement within the CWC is required to increase

strength in tension. The term “reinforcement” is perhaps a misnomer. It is technically not possible to reinforce the concrete, as any true reinforcement would have to be stronger than the pipe. The true purpose of the wire is in fact to keep the CWC on the pipe. The CWC will crack when the pipe traverses the stinger and is laid on-bottom. The wire mesh allows the cracking to occur cicumferentially in an acceptable manner, while securing the CWC on the pipe. The Bombax wire reinforcement requirements were based on BS 8010 Part 3 Section 9(3). This requirement specifies that the wire reinforcement cover 0.08% (minimum) and 0.4% (minimum) of both the longitudinal and transverse surface areas of the CWC, respectively. In addition, a second layer of wire was utilized for coating thicknesses of over 80mm as required by this standard. The wire reinforcement utilized for the Bombax coating was a welded, galvanized, wire mesh. The wire mesh was crimped in the longitudinal direction. This feature allows the mesh to flex when the pipe undergoes bending.

Anodes. The anti-corrosion coatings of subsea and onshore pipelines are supplemented by cathodic protection (CP). Subsea pipeline CP is most commonly provided by sacrificial anode bracelet systems. Bombax utilized the largest Aluminum-Zinc-Indium anode bracelets in the world, the largest of which weighed approximately 950lbs (Figure 9).

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Figure 9

48-Inch Diameter Al-Zn-In anode bracelet on fit-up jig in foundry

Field Joints Background. Offshore pipelines are typically installed in

coastal waters by reeling or by conventional S-lay methods. Reeling of pipe has many advantages due mainly to the speed of the lay process, which results from the pipeline being welded and reeled up onshore. However, this method is limited to smaller diameter pipe that meets certain yield-to-tensile strength ratio and diameter-to-wall thickness ratio criteria. Most large diameter pipe and all CWC pipe must be assembled offshore. As such, the majority of the girth welds must be made on the lay vessel. Such was the case with the Bombax Pipelines. Pipe installed in this manner requires that the field joints be coated on the lay vessel after welding of the joints.

Options. Field joints of FBE coated pipe can be coated offshore using heat-shrink sleeves, liquid epoxy or FBE. Heat-shrink sleeves can be installed with relative speed and with a minimum of labor. However, it is difficult to apply heat in a uniform manner to sleeves on large diameter pipe. This often results in sags and voids beneath the sleeve. Liquid epoxies can be installed using a roller or spray method. From a quality and performance perspective, FBE is the best coating for these field joints. FBE is compatible with the parent coating, and has superior adhesion and abrasion resistance. For these reasons FBE was selected as the coating for the Bombax Field Joints.

Field Joint Infill. As the pipe exits the lay vessel onto the stinger, it is supported on rollers. In order to smoothly traverse the rollers, the field joint cavity on CWC pipe must be modified to match the outer diameter of the CWC. Until recently, the most common method involved strapping a steel sleeve around the field joint using steel banding and clips, then filling the annulus with a hot mastic. Two decades ago, polyurethane (PU) foam compounds were introduced as an alternative to hot mastic. Most recently, PU foam system was improved by the introduction of polyethylene (PE) sleeves to replace the use of banded steel sheets. The sleeve is secured around the pipe by electric fusion welding. Once the sleeve is inplace the high-density PU (HDPU) foam is injected into the annulus where it quickly cures. This was the system used for the Bombax Field Joints. The combination PE sleeve with

HDPU foam provides a flush transition between CWC surfaces. HDPU foam can achieve adequate compressive strength (300psi minimum) in only a few seconds. The combination PE sleeve/HDPU infill system has several advantages. First, the cycle time on the system even on large diameter pipe is only a few minutes, quicker even than mastic systems. Second, this system eliminates steel sleeves and banding which unless handled properly can cause cuts and other such wounds to laborers.

Performance Results. The critical stage for the concrete weight coating and field joint system is installation. The movement of the pipe over the stinger and on to the seafloor is the most mechanically demanding. The concrete weight coating system performed exceptionally well during installation, suffering virtually no mechanical damage. The same can be said for the field joint infill system, which provided the strength to smoothly traverse the rollers in all cases. Conclusions

The Bombax pipeline system, which included one of the largest subsea gas pipelines in the world, successfully employed a system of coatings that provided both corrosion protection and on-bottom stability. The system included up to 5-inches of concrete weight coating over a coating of FBE. A bonding system of rough coat FBE and adhesive ensured that the concrete did not slip from the pipe while the pipe was in tension. The field joints were successfully coated with FBE overwhich high-density polyurethane foam was injected to allow the pipe to smoothly traverse the lay vessel rollers. The entire system was successfully applied while upholding the highest health, safety and environmental standards of the operator and society. References

1. NACE Recommended Practice 490 2. NACE Recommended Practice 394 3. BS 8010 Part III Section 9

Tables

Table 1. Anti-Corrosion Coating Systems Table 2. Concrete Weight Coating Application Methods

Figures

Figure 1. Bombax Field Layout Figure 2. Mid-Rack of FBE Plant Figure 3. Induction Coils Figure 4. Electrostatic Spray Figure 5. FBE Outbound Rack Inspection Figure 6. Wrapping Concrete Weight Coating Figure 7. Impingement of Concrete Figure 8. Compressive Strength of Concrete Weight

Coating vs. Time Figure 9. Al-Zn-In anode bracelet on fit-up jig in

foundry