ELASTOMER FOR LINE INSULATION COATING PASSES NORTH SEA TEST
Gunnar Eriksen
Norsk Hydro A.S.
Lysaker, Norway
E. R. Christiansen
Viking Mjondalen A.S.
Lysaker, Norway
Elastomeric deep sea thermal insulation proved highly damage resistant during handling and pipelay for a North Sea project.
The coating was chosen by Norsk Hydro for 11.5 km of 8 in. flow lines at its Oseberg field development. The Oseberg field is situated 130 km west of Bergen in Norway in 110 m of water.
Norsk Hydro picked elastomeric insulation for lines connecting its two subsea satellite wells to the Oseberg B platform.
The J-tube pull-in operation of the coated line was conducted in stages as the lengths of pipe were field jointed, laid, and back-pulled into the bell-mouthed J-tube.
The pull-in went smoothly with the maximum pull-in force being 50 tons. No damage to the pipe or the coating was experienced.
WHY INSULATE
The composition of a hydrocarbon mixture varies as it flows up through the wellhead into flow lines for transportation in the subsea pipe to a platform.
The oil and gas mixture may be of highly viscous crudes, waxy crudes, or emulsions and wax hydrates, all of which may cause difficulties in the flow rate.
Multiphase-flow analysis for the hydrocarbon mixture and the conditions along the pipeline will determine the need for thermal insulation and the degree of insulation needed.
An analysis will consider the oil-gas-water content, the temperature and pressure of the mixture, the flow rate, length of flow line, and the nature of the sea bottom.
Current materials used or tested for thermal insulation coating of subsea pipelines include polyurethane foams, polypropylene foam, poured polyurethane, syntactic foam, molded polyurethane, neoprene elastomer, PVC foam, and insulation elastomer.
The foams are very good insulators, but their ability to withstand hydrodynamic pressure is limited by their cellular structure.
The molded polyurethane resists high hydrodynamic pressure but is not as good an insulator as the foams and is prone to hydrolyses by hot water.
Being compact, the neoprene elastomer resists very high hydrodynamic pressure, is a fairly good insulator, and is not influenced by sea water.
The insulation elastomer also resists very high hydrodynamic pressure, is a very much better thermal insulator than neoprene, and is also not influenced by sea water.
Burial of the pipe is also a means of insulating if the soil is stable and allows burial.
The best material for a given field must be chosen according to the flowing medium, the design life, and total cost.
At Norsk Hydro's Oseberg field, two 8-in. flow lines connect two subsea wells to one of the platforms approximately 6 km from the wells. Analysis determined that the lines had to be thermally insulated.
The design life was stipulated as 24 years, and the production fluid to be transported through the 8-in. lines was a mixture of gas, oil, and water.
It was determined that the fluid temperature must be maintained greater than 25 C. during flowing conditions. Additionally, the temperature must be kept greater than 25
C. for a minimum of 4 hr after a shutdown.
The design basis for the 8-in. production line is shown in Table 1.
After careful technical and economic evaluation and prequalification testing of various possible coatings, the coating configuration chosen for the Oseberg project was a three layer, sandwich-type composition of rubber, Vikotherm, and rubber to give the specified "U" values of 15.2 w/m2-K. and 9.5 w/m2-K. for the various stretches of the pipe.
Norsk Hydro engaged Vallourec Industries in France for the production of the steel pipe. These were delivered to Mjondalen in December 1987. The pipe was subsequently coated, delivered in June 1988, and successfully laid during two weeks in July 1988 by the Dutch lay vessel Lorelay.
PREQUALIFICATION, FABRICATION
More than a year in advance of the actual coating start up, the prequalification process for the coating material was initiated by Norsk Hydro.
Prequalification consisted of a series of tests specified by Norsk Hydro and by the insulation coater. These were performed partly by independent institutes, by the insulation coater's own laboratory, and by Norsk Hydro's own research laboratory.
The independent institutes used were Sintef, Norway; Battelle, Switzerland; Veritec, Norway; Marintec, Norway; Capcis Umist, England; and Development Engineering, Scotland.
Tests conducted included long-term, water-absorption; high-temperature, high-pressure, water absorption; water uptake, bond strength system on duplex steel; hydrostatic water pressure, static indentation; and rolling, impact, and adhesion.
Additionally, other tests were scanning test in sea water; water absorption, heat conductivity; thermal conductivity, water absorption; creep, shape distortion; compressive strength; destructive compression; and thermal conductivity.
Tests were also performed for cathodic disbanding; compressive strength uniaxial at elevated temperature and pressure; hot bonding and tear strength (duplex); bending and bonding; impact; bending of coated steel pipe; and field-joint impact.
The insulation coating system is a rubber elastomeric composition, chemically bonded to the steel pipe by a vulcanization process at high temperature and pressure (Fig. 1).
The coating process consisted of the following:
- Acclimatization and inspection of pipes
- Shot blasting in an automatic blasting machine
- Coating of the shot-blasted area with a chemical primer
- Coating with the insulation system to the correct thickness in an automatic coating-wrapping machine
- Vulcanizing of the coated pipe in an autoclave at elevated temperature and pressure
- Inspection and testing of the finished coating
- Load-out to storage area.
The result of this fabrication process is a tough flexible coating giving corrosion protection, thermal insulation, and mechanical protection all in one coating system.
The physical properties of the thermal-insulation system are shown in Table 2.
If a greater negative buoyancy is required, the density of the anti-corrosion coating can be increased to 2,500 kg/cu m. In an appropriate thickness, this will then act as weight coating.
As the coating system is made of elastomeric materials with extreme elongation properties, it is ideally suited for all kinds of laying methods including the reel method.
FIELD JOINTING
The Oseberg field is in 110 m water depth. The field center lies 50 km west of the Troll field with Statfjord and Gullfaks to the north and Frigg and Heimdal to the south.
Norsk Hydro, whose partners are Statoil, Elf, Saga, Mobil, and Total, is operator of the Oseberg field.
The Oseberg field center consists of the A platform, a concrete gravity-base structure with accommodation and control facilities, and the steel-jacketed B platform which houses production and drilling facilities. The two platforms are connected by a bridge.
The subsea development from the Oseberg field includes two wells, 30/9 B49H and 30/9 B50H, located about 6 km north of the field center and approximately 2 km from each other. The subsea wells are connected to the B platform by thermally insulated 8-in. production lines and 2-in., fusion-bonded epoxy (FBE) coated service lines.
Norsk Hydro accepted all the coated pipes from Mjondalen at the port of Drammen in Norway at the beginning of June 1988 (Fig. 2).
The appointed flow line installation contractor transported the pipe from Drammen to CCB near Bergen, Norway (Fig. 3), where it was transferred onto a gondola barge to await the arrival of the lay vessel Lorelay.
The dynamically positioned vessel arrived at the Oseberg field on July 4. Pipelaying commenced early on July 5, with the J-tube pull-in of the B49H 8-in. insulated flow line.
A lubricating agent was liberally applied by paint brush to the first 14 pipe joints in each flow line before they left the stern of the barge. This was to reduce the friction factor against steel in water and therefore reduce even further the required pull-in force from the linear winch mounted on the B platform.
The 2-in. risers had been preinstalled in their own J tubes on the B jacket during onshore jacket fabrication. The 2-in. services line were simultaneously laid with the 8-in. production lines and then clamped piggyback style on top of the 8-in. lines just aft of the field-joint stations.
The 2-in. lines were positioned so as to start after the 8-in. line had been completely pulled into the J-tubes. The 2-in. lines were later connected to their risers by flexible jumpers.
The flow line insulation design and specifications required that the field joint provide a heat-transfer coefficient equal to or better than the applied factory coating while maintaining the same overall thickness.
Also, the field-joint materials and application procedure would both need to be successfully prequalified onshore in advance of pipelaying.
In addition to the insulated 8-in. field joints, the field-joint contractor was also responsible for the following activities:
- Two-in. pipe FBE field joints
- Eight-in. anode installation and electrical connection to the steel pipe
- Application of electrical continuity cables between 8 in. and 2-in. flow lines to provide cathodic protection to the latter from the anodes on the 8-in. line.
MOLDING PROCESS
At the first 8-in. field-joint station, the bare steel was shot blasted with closed-circuit shot blasters, the bare steel was raised to 80 C. by induction heating, and finally a primer was applied to the bare steel and the cut-backs of the factory coating.
At the second 8-in. station, sealing strips were applied around the factory coating on both sides of the field joint. A single-piece removable steel mold was wrapped around the field joint, and a two-part polyurethane filler was introduced from an inlet port at the bottom of the mold.
The prequalification trials showed that the mold had to remain in position for a minimum of 5 min before it could be removed. The laybarge was permitted to move forward only when the field joint had reached a hardness of 65 IRHD. This was always accomplished within seconds of mold removal.
Because of the slope of the pipeline at the field-joint station, the filler had to flow to the highest point in the mold resulting in a shark-fin shape of surplus material on top of the joint. This was removed easily by a sharp knife as soon as the mold was removed.
The color selected for the polyurethane filler was a vivid yellow. This provided a sharp contrast with the black factory-applied coating and stood out prominently on later ROV surveys of the as-laid flow lines.
The first line laid was the one to B49H subsea satellite well. This was completed on July 9 and was laid in a single operation from J-tube pull-in to lay-down at the subsea well.
The J-tube pull-in of the line to B50H was commenced on July 10. This line was completed on July 15.
This particular installation was interrupted by bad weather on two occasions, and the piggyback 8-in. and 2-in. lines had to be abandoned and recovered both times.
Recovery of the lines provided the opportunity for a visual inspection of both the factory coating and field joints after they had been on the seabed. No defects or damages were observed on either occasion, and the bond between the factory coating and the field joints was still completely intact.
The maximum lay rate was achieved during the B50H flow lines installation when one 12-hr shift laid 78 joints, equivalent to slightly greater than 9 min per joint.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.