Installing pipelines offshore California for the Exxon-Santa Ynez project earlier this year called for several novel techniques, according to the installation contractor Allseas Marine Services N.V., Essen, Belgium.
From December 1991 until February, Allseas installed 12, 14, and 20-in. pipelines off the coast of Santa Barbara in water depths of up to 1,200 ft.
Allseas says that three diverless connections were made in 350 m (1,155 ft) water depth using the deflect-to-connect (DTC) method. A single-point lift was made to allow connection of a flexible pipeline, a novel 1-tube was installed, and extensive testing was conducted to prove the methods of installation.
FIELD, PREPARATIONS
Fig. 1 shows a layout of the field. A 20-in., concrete-coated oil emulsion line was installed between the Heritage and Harmony platforms located in 1,080 ft and 1,150 ft of water, respectively. Another 20-in. oil emulsion line was installed from the Harmony platform to shore.
Three subsea connections were made between the 20-in. lines and the platforms using connectors mounted on pull-in sleds at the end of the pipeline.
Once the end of a 20-in. line had been installed on the seabed, cables were attached to the sled, and the pipe was pulled into a bend towards a receiver on the platform.
A 14-in. oil emulsion line and a 12-in. gas line were pulled into J-tubes on the Harmony platform and laid down for later connection at the foot of the Hondo platform.
A 12-in. treated-water line was started up near the Harmony platform and laid towards shore. Later a flexible pipeline was attached to this line and pulled into an I-tube. This I-tube was not originally part of the platform but was designed and installed by Allseas using a new technique, the company says.
An I-tube is used for the pull-in of flexibles and has a small guide at the bottom (bellmouth) instead of a large radius "J."
Table 1 summarizes the pipeline parameters for all lines in the field.
At the time of installation of the pipelines, only the jackets of the Harmony and Heritage platforms had been installed. To facilitate the various pull-in and construction activities, Allseas designed and fabricated three deck structures for placement on the jackets (Fig. 2).
A deck was designed which housed a linear winch, a spooling winch, power pack, and other facilities for the J tube pull of the 12 and 14-in. lines at the Harmony jacket.
Another deck was built to support the DTC activities and housed winches, hydraulic systems, power generators, and control cabins.
The third deck, including what Allseas says is a unique line-up mechanism for the I-tube for the installation of the flexible end of the 12-in. treated water line, was designed and built for location on the Harmony platform.
All decks were transported to California and installed on the jackets by the Allseas vessel Lorelay.
CONCRETE COATING, TESTS
As part of the scope of work, Allseas was responsible for the procurement of the concrete weight coating of the 20-in. line pipe. This pipe was supplied by Exxon complete with a layer of fusion-bonded epoxy (FBE) anticorrosion coating.
The provision of a layer of concrete weight coating of the correct thickness and density was of critical importance to the success of the laying operation, says Allseas.
The concrete thickness of 1.25 in. was determined by the minimum submerged weight required by Exxon in areas where the water was 1,150 ft or deeper. The resulting calculated static tensions were between 70 and 90 tons.
Relatively small tolerances in thickness, density, and water absorption capacity had a significant effect on the laying tension.
In view of the critical nature of the laying operation, Allseas says it was necessary to establish a program of material tests in combination with a quality-control program.
A study was carried out to determine the practical limitations to weight coating for the purpose of laying the pipe.
In the study, the thickness and density of the concrete were varied and an envelope of acceptable values defined.
The upper limit of the envelope was defined by the maximum density variation allowed by the Exxon specifications and the maximum lay tension for the Lorelay. The lower limit was defined by the minimum submerged weight and minimum density variation allowed.
During actual concrete coating, each joint was weighed and color coded according to calculated submerged weight and density so that the lightest pipe could be used for the deepest water.
The concrete was to be applied over a layer of FBE. To ensure a proper bonding between the FBE and the concrete, an adhesive was applied to the FBE.
Several preliminary patterns of application of the adhesive were tested by application of compressive and axial force to the coated pipe until shear failure occurred between coatings.
As a result of these tests, adhesive was applied over the complete length of coated pipe in rings of 4-in. width, spirally wound at a pitch of 6 in.
Further tests were performed aboard the Lorelay, says Allseas. There it was concluded that the spirally wound adhesive pattern was sufficient to transfer the maximum tension as occurs in practice in the Lorelay's tensioners.
TENSIONER, ADSORPTION TESTS
The layer of concrete on some of the deepwater sections was relatively thin. In general, a minimum thickness of 1.575 in. is maintained as a practical value for the application of weight coating to pipelines.
For the Exxon pipes, however, this thickness would have resulted in too large a submerged weight. In order to ascertain the structural integrity of the coating after passing through the tensioners, tests were conducted which used full-scale coated pipes.
The tests indicated that the coating (supplied by Compression Coat, Houston) suffered no significant damage during these tests and that a thickness of 1.25 in. could be used without problems.
The results of these tests were later borne out during the installation, when the coating system proved to have good structural integrity, as no significant damage occurred, not even at high strain levels.
In deep water, it may take 18-24 hr for a joint of pipe to reach the seabed from the moment it enters the water at the stern of a laying vessel, says Allseas. During this time, water is absorbed into the concrete, adding to the submerged weight and thus the laying tension.
This process is also affected by the hydrostatic pressure, which becomes a significant factor for pipelaying in deep water.
To establish the upper limit to the weight of the concrete-coated pipe in the coating study just described, a theoretical water-absorption factor was taken into account.
To prevent excessive lay tensions, however, the actual percentage of water absorption was to be established by tests simulating the actual conditions of time and pressure.
Samples of 6 x 6 in. and of a thickness of 1.25 in. were taken from the coated pipe joints. The sides not normally exposed to water were provided with a water-resistant coating.
After weighing, each sample was placed in a pressure tank. The pressure was then built up at a rate similar to that experienced during laying conditions to a maximum value of 570 psi in 18 hr. Every 6 hr the samples were weighed.
This testing program yielded the following conclusions:
- The average water absorption of the samples was 4.87%.
- The larger part of the absorption took place during the first 6 hr of the test. After this time, a pressure of 13.8 bar (200 psi) had been reached and an absorption of 77% of the maximum value. This latter was reached at 570 psi.
INTERNAL COATING
The 12-in. treated water line received external as well as internal FBE corrosion coating.
During the laying of this line, a field joint coating had to be applied to the outside as well as to the inside of the weld areas. Allseas says this was the first time an internal field-joint coating has been applied offshore in a pipe this small.
With several internal tools (line up clamp, X-ray crawler, X-ray stop cart, buckle detector) already inside a pipe during normal laying operations, providing the field joint with internal coating was too complicated for efficient application on a laying vessel.
Therefore, significant precautions were taken.
Allseas subcontracted the coating work to Commercial Resins, Tulsa, which provided the specialized personnel and equipment for the internal and external FBE coating of the field joints.
An extensive testing program was set up to prove the tools developed for this project, to ensure the quality of the joints, and to ensure no lost time offshore as a result of mechanical problems.
The following were tools additionally required for this operation:
- A wire-brushing and vacuum cleaning tool attached to the line-up clamp. This tool cleaned the weld area after the first weld.
- A crawler provided with an internal coating machine which remained in the pipe during the welding of about 20 joints. After this period, it was retrieved and its store of coating powder replenished.
- An internal inspection crawler provided with cameras for visual inspection of the coating.
One major problem associated with internal coating is the difficulty in inspecting the coating after application. To ensure a constant quality, the following measurements were taken:
- The coating unit was extensively tested ashore.
- After each 20 joints, the coating machine was pulled from the pipeline and the interior visually inspected by the video crawler. If the quality had not been satisfactory, then the pipe could have been cut back.
- During every shift, a qualification test verified that the machine was applying the correct coating thickness.
Once the operation had begun, the internal coating process did not significantly affect the lay rate. The time lost was caused by the video inspections (every 20 welds), each taking about 1 hr.
Apart from some minor mechanical problems, Allseas says, the tools performed satisfactorily, and an acceptable quality of internal field-joint coating was achieved.
JACKETS' PREPARATION
When the pipeline was installed, only the jackets of the Harmony and Heritage platforms had been installed. To facilitate the various pull-in and construction activities, Allseas says it designed and fabricated three deck structures for placement on the jackets (Fig. 2).
A deck was designed which housed a linear winch, a spooling winch, power pack, and other facilities for the J-tube pull of the 12-in. and 14-in. lines at the Harmony jacket.
Another deck was built to support the DTC operations, housing winches, hydraulic systems, power generators, and control cabins.
The third deck included a unique line-up mechanism for the I-tube for the installation of the flexible end of the 12 in. treated-water line. It was designed and built for location on the Harmony platform.
The Lorelay transported all decks to California and installed them on the jackets using her 300-ton crane.
SLEDS AND ROVS
The subsea connections were made with the DTC method.
The principle is shown in Fig. 3: A pipeline is installed on the seabed carrying at its end a sled which can be pulled into a receiver, preinstalled at the bottom of the platform structure, says Allseas.
Once the sled is pulled into this receiver, an hydraulic system makes a pressure-tight connection between the pipeline and the platform piping.
To move the sled from its laydown position towards the receiver, cables are run from the platform and attached to the sleds by a remotely operated vehicle (ROV). The hydraulic system and cables are connected to the control system and winches on the work deck on top of the jacket by piping and cables preinstalled on the jackets.
The Lorelay picked up the sleds for welding onto the pipelines. Fig. 4 shows the sled aboard Lorelay as a large buoyancy tank is attached to the sled just before being lowered to the seabed.
Several ROV tools and working procedures were developed specifically for this project, says Allseas.
After fabrication of the tools, all operations were tested under dry conditions and later in a wet tank to simulate the actual working environment. The operations tested varied from the cutting through of a cable by ROV to the complete mating operations of the sleds and receiver.
All three DTC procedures were successfully completed.
On the first operation some problems were experienced with part of the hydraulic system of the receiver. Contingency procedures, however, allowed local intervention by ROV.
On the two remaining DTC operations, the hydraulic systems were found to be fully operational, and the entire deflection and connection operation, including the testing of the connection, was completed within 48 hr.
I-TUBE INSTALLATION
For the pull-in of the flexible end of the 12-in. treated water line, no J-tube was available on the Harmony platform. To overcome this problem, Allseas designed and fabricated an I-tube which was installed in sections through the pile guides on one of the jacket legs.
Fig. 5 shows the lowest section of the I-tube.
The bellmouth section is of particular interest, says Allseas, because it was designed for two functions:
- Being the lowest end of the I-tube, it had to be shaped to allow smooth entrance into the pile guides; and,
- As the flexible pipe was pulled into the bellmouth, it had to be provided with curved surfaces so that its minimum allowable bending radius was not exceeded.
Tubular spacers were welded to the I-tube to make up the difference between the inside diameter of the pile guides and the outside diameter of the I-tube. Quick connectors were installed on the sections to allow a quick connection without any welding.
Fig. 6 shows the installation of the first section as well as the completed I-tube.
Each section was lifted by the Lorelay crane and lowered through a purpose-built line-up structure. The lineup structure was designed to perform the following functions:
- Provide a guide for the rough alignment of the individual I-tube sections before connection
- Provide an accurate alignment tool for the quick connector
- Provide a hang-off support for the I-tube.
Each section was clamped in the structure while the following section was picked up by the Lorelay crane. The new section was attached to the previous one by the quick connector and the whole assembly was lowered again.
In this way an I-tube was installed down to a depth of 960 ft quickly and cost effectively, without the help of divers. Approximately 30 min were required for the make up of a quick connector, a considerable improvement over the time required for welding and nondestructive testing of an equivalent welded connection.
Total time for the installation of a single section between pick up of the section from the barge until pick up of the next section was 2-3 hr.
Allseas says that the successful installation of the I tube proves a new method of installing I-tubes on existing platforms. The method can be used for the pull-in of cables, umbilicals, or flexible pipelines.
INSTALLING FLEXIBLE LINE
The I-tube just described was installed to allow pull-in of a length of flexible pipeline to be attached to the 12-in. treated-water line. This line had been laid down on the seabed near Harmony during a previous phase of the operation.
To facilitate the installation of the flexible fine, the 12-in. steel line had to be recovered by the Lorelay. This was done with a single-point lift method which allowed recovery of the line to the side of Lorelay.
Once it was recovered, a flexible pipe was attached to the 12-in. line. This pipe had been stored on a large reel placed on deck of the Lorelay. Rigid pipeline and flexible line were then laid down in a loop on the seabed (Fig. 7).
Upon completion of the laydown, the pipeline had to be pulled into the I-tube up to the work deck on the jacket. To allow this operation to proceed, it was critically important, says Allseas, that the flexible line be installed in the correct configuration on the seabed to prevent coiling or sharp bends in the line during pull-in.
Allseas says that because of its capability to lay pipe using dynamic positioning, Lorelay smoothly completed the complicated maneuvering necessary to pick up the steel pipe, lay it down again with the flexible line attached, then lay it into a loop.
After laydown, the flexible line was pulled into the I tube and successfully pressure tested.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
