MAINTENANCE & REPAIR Stingray Pipeline replaces protection on gas risers in splash zone

John Miley Natural Gas Pipeline Company of America Stingray Pipeline Compressor Platform at West Cameron 509A, located 98 miles offshore in the Gulf of Mexico, was experiencing coatings loss on the natural gas risers in the splash zone. (Photos courtesy of Mid-Atlantic Diving Contractors). A 30-in. riser shown in the splash zone with most of the neoprene and mastic covering swept away by wave action.


Platform operator makes use of FRPand epoxy technologies
for critical areas of platform

John Miley
Natural Gas Pipeline
Company of America
Stingray Pipeline Compressor Platform at West Cameron 509A, located 98 miles offshore in the Gulf of Mexico, was experiencing coatings loss on the natural gas risers in the splash zone. (Photos courtesy of Mid-Atlantic Diving Contractors).

A 30-in. riser shown in the splash zone with most of the neoprene and mastic covering swept away by wave action.

While there are many factors that lead to the deterioration of marine pipeline risers, the principal cause is exterior corrosion. Operators have found ways to minimize or at least delay corrosion, by applying exterior coatings of various types at the time of construction, but many of these coatings have proven to be vulnerable in the splash zone.

When repairs to risers become necessary, it has often been difficult to accomplish them effectively in the splash zone. The success rate for field-applied coatings has been very low; however, the recent introduction of a special all-polymer encapsulation technology promises to change those percentages.

Stingray Pipeline Company, operated by Natural Gas Pipeline Company of America, has a large gas gathering network in the West Cameron, East Cameron, Vermilion, and Garden Banks Areas off southwest Louisiana. Several risers on the main compressor platform at West Cameron 509A were in need of corrosion protection.

Neoprene, mastic failure

The original concrete and mastic coatings applied to the risers prior to construction had failed in the splash zone. Subsequent field-applied neoprene and mastic encasements were also in distress. To maintain the platform in the safest, most reliable condition, with pipeline pressures that could exceed 1,300 psi, it was imperative that an effective method for protecting the risers be found.

Stingray Pipeline Company examined a number of repair methods before locating a technology that had been used successfully on inland and coastal structures, but had not yet been introduced offshore. The A-P-E Process, supplied by Master Builders of Cleveland, Ohio (US) was selected to repair four suction risers of varying diameters and one 36-in. line at a manifold platform in West Cameron 148. Stingray contracted with Mid Atlantic Diving Contractors of Ellicott City, Maryland, to remove the remains of the old coatings and install the new riser protection.

The bottom right photo shows a typical suction riser at the compressor platform, prior to the recent repair work. Wave forces had torn off most of the neoprene outer cover in the splash zone. The mastic layer beneath the outer cover was spotty and discontinuous. The original concrete encasement was intact up to a level just below the waterline, but had also failed in the splash zone.595of67

This close-up of the 30-in. riser at the waterline shows part of the original concrete and mastic encasement.

The tops of completed encapsulations on two suction risers are shown. The encapsulations are only 1-3/8-in. larger in diameter than the riser.

Application process

The A-P-E Process began with surface preparation. The length of the riser to be encapsulated extended from elevation +10 ft to elevation -5 ft. Powered rotary abraders were used to remove the remnants of the previous coatings, including some of the original concrete encasement that

extended from the waterline to the -5 ft elevation.

Final cleaning to bare metal was accomplished by grit blasting. After the surface had been prepared, a translucent fiberglass-reinforced plastic (FRP) outer jacket was placed around the riser. The jacket was fitted with polymer stand-offs that maintained a 1/2-in. annulus between the riser and the jacket.

Grout injection ports were positioned at strategic points along the length of the jacket. A seal gasket was placed in the lower end of the jacket and the aggregate-filled epoxy grout was pumped into the annulus from the bottom up.

Because of the translucent jacket, the progression of grout could be easily monitored by the diver from outside the jacket. If any defects had been detected, corrective action could have been taken. This ensured that the grout column inside the encapsulation was continuous and free of water pockets or other discontinuities. Pumping the aggregate filled grout into the jacket from the bottom up also created a scouring effect that ensured a tight bond between the encapsulation materials and the riser.

Another unique feature of the process is the air-operated batcher/mixer/pump unit that handles the aggregate-filled epoxy grout by the plural component method. With this method, the reactive components of the epoxy grout are kept separate throughout the process and are blended together just prior to entering the FRP jacket.

By keeping the reactive components separate, the contractor was free to start and stop the work at any time, without concern for the set time of the grout. Cleanup is also simplified, because the mixers, hoppers, pumps and hoses contain only un-catalyzed materials and the use of solvents is kept to an absolute minimum.


View of completed encapsulation on the 30-in. suction riser. The FRP jacket is tightly bonded to the riser with high strength epoxy grout.

Grout filler

According to the developers of the process, the ability to add significant amounts of inert filler to epoxy grouts has several additional advantages:

(1) The heavier filler adds to the unit weight of the grout, causing it to displace the water more readily and to self-level inside the jacket.

(2) Durability of the completed encapsulation is enhanced because the aggregate filled grout has a much lower coefficient of thermal expansion than does the pure epoxy alone. Seasonal temperature changes should have little or no effect on the bond between the polymer encapsulation materials and the steel substratum.

(3) The addition of filler also has the added effect of reducing cost. On this project, the ratio of aggregate to liquid epoxy components was 3.38 to 1 by weight, yet the grout was very flowable and self-leveled in the jackets. The A-P-E grout is 100% solids epoxy and contains no solvents to evaporate into the environment.

The bottom left photo on this page, photographed recently, shows two completed encapsulations after weathering their first winter 98 miles offshore. Close inspection revealed that the encapsulations were still tightly bonded and completely sound. The encapsulations are only 1-3/8 in. larger in diameter than the risers, minimizing the area for wave forces to act against.

The bottom right photo, also taken recently, gives a closer view of one of the repaired risers. The tightly bonded jacket seam and fillet of epoxy paste at the top of the encapsulation contribute to exceptional durability in the splash zone.

Stingray selected the A-P-E Process because it provided an economical means to perform the encapsulation work on site, without interruption to operations. All materials, special equipment and technical assistance were available from a single source, and contractors, experienced with the process, were available.

While new to the offshore scene, the process had been used successfully for over ten years on piers, bridges and other coastal structures. It also appeared that the research leading to its development had been extensive.

The work was completed during the summer of 1994 and the encapsulations have weathered a winter of rough seas without evidence of distress.

Copyright 1995 Offshore. All Rights Reserved.

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