HURRICANE-DAMAGED GULF OF MEXICO PIPELINE REPAIRED WITH COLD FORGING

Gene Lewis
Texaco Pipeline Inc.
Houma, La.

Pierre DeGruy
Texaco Inc.
New Orleans

Lee Avery
BIG INCH Marine Systems Inc.
Lafayette, La.

Damage to Texaco Pipeline Inc.'s Eugene Island Pipeline System (EIPS) in last year's Hurricane Andrew prompted a complex repair project unique for the Gulf of Mexico.

On Aug. 22, 1992, one of this century's most destructive Atlantic hurricanes devastated South Florida and moved into the Gulf of Mexico towards producing offshore oil and natural gas fields.

Hurricane Andrew, with sustained winds of 165 mph, whipped seas to 70 ft as it moved across the gulf. Nevertheless, only 250 of the gulf's 3,800 offshore platforms experienced storm damage.

In some cases, damage was relatively minor, such as the loss of entire staircases or cracks to steel templates, according to the U.S. Department of Interior's Minerals Management Service (MMS). In other cases, platforms that survived the wrath of Hurricane Betsy in 1965, were easily toppled.

Damage, suffered when the anchor of a runaway semisubmersible drilling rig crashed into the 20-in. EIPS during the height of the storm, caused the pipeline to fail under pressure within 48 hr after start-up following the storm.

IMPORTANCE OF EIPS

Texaco Pipeline Inc. (TPLI), subsidiary of Texaco Inc., operates EIPS from its center in Houma, La. (Fig. 1). The system is jointly owned by TPLI, Exxon Pipeline Co., Marathon Pipeline Co., Chevron Pipeline Co., Conoco Pipeline Co., and Mobil Eugene Island Pipeline Co.

As a common carrier, EIPS transports much of the crude oil produced by operators in Outer Continental Shelf (OCS) blocks South Timbalier (ST), South Pelto (SP), Ship Shoal (SS), and Eugene Island (EI) to TPLI's Houma terminal. EIPS accounts for 22 million bbl/month, approximately 19% of the entire production in the Gulf of Mexico.

The 20-in., API 5LX-52 grade steel pipeline was laid in 1976, requiring about 5 1/2 months to complete. It was built to satisfy demands of producers who were interested in producing oil from nearby blocks but had no way to transport production ashore.

The line originates at the scraper sending trap on the Pennzoil South Marsh Island (SMI) 128 platform and terminates on the TPLI Caillou Island Station 5 platform in Terrebonne Bay, where it connects directly to the TPLI wholly owned 16-in. line which takes the crude oil to the Houma terminal.

From Houma, the crude moves to various destinations through TPLI's 22-in. pipeline to Gibson, La., Lake Charles, La., and Port Arthur, Tex. It can also move via TPLI's 18-in. pipeline to Capline and Exxon facilities in St. James Parish, La., or across TPLI's barge dock facilities at Houma.

The longest subsea pipeline system in the Gulf of Mexico, EIPS is made up of 112 miles of EIPS 20-in. line and 42 miles of TPLI 16-in. line from SMI 128 to Houma.

EIPS is also one of the largest lines and has the highest capacity of any of the crude oil fines that far offshore in the Gulf of Mexico.

The wall thickness of the pipeline varies with water depth, from 0.625 in. in the SMI 128 riser to 0.406 in. in shallow water.

The pipeline currently operates at an average pressure of about 1,100 psi at SMI 128. The maximum allowable operating pressure (MAOP) is 1,440 psi at SMI 128.

EIPS currently moves 140,000 b/d with a design capacity of 195,000 b/d. The Eugene Island-grade crude oil which runs in the system has a weighted average gravity of 33 API and sulfur content of 1.2%. There are 14 lateral connections to EIPS which deliver crude oil into the system from 39 platforms.

SYSTEM SAFETY

Each connected platform has a high pressure and low pressure shutdown device. Additionally, full-flow, pressure-actuated relief valves are installed around all block gates and at the Houma terminal in case of accidental valve closure.

There is also a rupture disk device installed at the Houma terminal as a fail-safe measure for the relief valve.

EIPS is operated from the Houma terminal via a computer which receives meter readings and pressure data from each of the connected platforms as well as meter readings at the Houma terminal.

The computer calculates differences between the volume in and volume out adjusted for pressure, temperature, and meter factors. This calculation can be performed as often as desired by TPLI personnel but normally is calculated on 2-hr intervals.

As operator, TPLI can manually enter data from platforms which may not be reporting to the computer. In these cases, the platform data are received by telephone.

Shutting in the pipeline is carried out by direct telephone contact with platform personnel by TPLI personnel at Houma. After the platform is shut in, platform personnel call the Houma terminal to confirm that the platform has shut in.

An alarm system to each platform which could be triggered by the Houma terminal is being considered. The operator, however, would have no sure way to know that the alarm had been received and acknowledged without telephone contact with platform personnel.

In addition, such an alarm could be triggered accidentally or erroneously, which would cause an unnecessary shut-in of the platforms.

The pipeline is buried with a minimum 3-5 ft of cover to a water depth of up to 200 ft. Beyond that point, in deeper water, the pipeline is unburied.

A 20 x 16-in. combination scrubber is nm every 10 days to remove paraffin and water and to sweep out spheres which drop into the main line from lateral connections.

In more than 17 years of continuous operation, only two other leaks have occurred from EIPS-owned facilities, and they were not from the 20-in. main line. One leak resulted from a faulty flange on a lateral connection; the other was caused by anchor damage to a lateral connection.

ANDREW'S DAMAGE

An anchor was in fact the chief suspect in the cause of the leak that shut in EIPS following Andrew's trek across the gulf.

During the storm, a massive semisubmersible drilling rig that had been stacked for several years in South Pelto Block 7 broke loose from its moorings. The rig, located less than 4 miles from where the EIPS traversed South Pelto Block 8, rode Andrew's waves, zigzagging from east to west and dragging its four anchors haphazardly along the bottom of the gulf.

It appears one of these giant anchors, weighing approximately 30,000 lb, struck the pipeline, which is coated with 2.23 in. of concrete. The pipeline suffered severe deformation at the point of impact but the 4-in. rupture along the longitudinal weld seam did not occur until 2 days after the line was restarted after Hurricane Andrew.

The leak in the pipeline occurred Aug. 31, after platforms had restarted production. As the pressure increased to approximately 700 psi, the pipeline failed at the deformation point.

At the Houma terminal, routine integrity checks signalled a shortage of crude oil in the system. But, because of the hurricane damage, data-communication circuits to several of the platforms were inoperable. Data, therefore, were being received by telephone which indicated some error.

Because the possible data inaccuracy rendered the integrity checks questionable, a helicopter inspected the pipeline and discovered not only oil in the vicinity of the line 10 miles out in the gulf from the closest barrier islands but also the rig, which was grounded in 35 ft of water about a mile west of the pipeline. TPLI personnel at the Houma terminal immediately began shutting in operations.

At the same time, Texaco's Gulf Coast Region Response Team, based in New Orleans, was activated. The team's mission was to prevent further environmental damage and to clean up crude oil discharged from the pipeline.

Once the pressure was reduced on the line, the discharge of crude oil was controlled and minimized. Cleaning up the spilled oil, estimated in the final analysis to be 2,000 bbl, required more than 150 workers.

Clean up personnel succeeded in preventing significant environmental damage to nearby sensitive barrier islands, and weather aided the natural dissipation of the crude oil.

LOCATING THE LEAK

TPLI immediately began to plan repair of the pipeline to bring it back into service for the producing platforms.

Before repairs could begin, the source of the leak had to be found. As operator of the EIPS, TPLI dispatched American Oilfield Divers (AOD) to the source location.

AOD and its wholly owned subsidiary, BIG INCH Marine Systems, a pipeline design, manufacturing, installation, and repair company headquartered in Houston, had already been mobilized to repair a 10-in. and 8-in. TPLI system damaged by Hurricane Andrew in nearby Terrebonne Bay.

The AOD divers were quickly mobilized from this less critical repair operation to inspect and repair the 20-in. EIPS main line (Fig. 2).

When the first diver went down to find and mark the damage, he began to lose visibility at 25 ft. Zero visibility set in at about 30 ft.

After several hours of searching, the diver was near what was considered to be the source of the leak in 35 ft of water, Slight internal pressure on the line enabled the diver to locate the damage by actually hearing the leak.

The damaged portion of the pipeline lay under a sandy bottom. Once the pipeline was uncovered and the work area scoured, the soft bottom repeatedly gave way and the pipeline had to be continually jetted.

REPAIR OPTIONS

TPLI engineers examined three options to repair the pipeline:

Option 1 involved repairing the line underwater by cutting out the damaged section and installing a new section using mechanical "gripper jaw" elastomeric sealed couplings.
This repair method was considered difficult because of the physical size and weight of such couplings. And TPLI engineers were concerned about the couplings providing the proper structural integrity.
The couplings also require use of elastomer sealing systems, adding to TPLI engineers' concerns about the permanence of the repair.
Option 2 focused on lifting the line out of the water, cutting out the damaged section, and welding in a replacement section, a repair method best suited for small-diameter pipelines in shallow water.
TPLI engineers calculated that two barges would be required safely to pick up the line and that extensive jetting would be necessary to remove the 5 ft of cover on more than a 0.25 mile of pipe.
Two barges were not readily available. But even if they had been, TPLI engineers anticipated other problems.
The process is weather-sensitive and could only be attempted in calm seas. At the time, swells in the aftermath of the hurricane approached 7 ft. Once lifts have been made and a damaged section replaced, the line is returned to the bottom where it must be reburied because a line seldom returns into the original trench.
For large diameter pipe, such as the EIPS 20-in. main line, the method would prove time-consuming and thus lengthen the period of lost production.
Option 3 centered on repairing the pipeline on the bottom using the BIG INCH Flexiforge system, with its end connectors and BaR Flanges. The system is more fully explained presently and in the accompanying box.
TPLI engineers ultimately selected this method because the system was readily available and had proven to be rapid and dependable in past TPLI projects in shallower water.
One of the main advantages of this process is that the metal-to-metal seal of the system provides the permanent reliability demanded for such a critical line.

CHOSEN SYSTEM

Repairing the line on the bottom offered a faster, less weather-sensitive repair. The divers needed to jet out only the local area to be repaired-in this case, a length of line about 90 ft was jetted for the repair. Instead of using two barges to lift a heavy 20-in. pipeline, only one barge was required.

The 295-ft work barge was sufficient to handle the 50-ft replacement section of 20-in. pipeline. Although deployment of this "spoolpiece" of pipe, the BIG INCH fittings, and forging tool was weather-sensitive, the divers nonetheless accomplished the repair in 6-8 ft seas.

AOD's divers were familiar with the BIG INCH system, having installed approximately 90% of all such systems during the past 6 years.

The BIG INCH Flexiforge system has been used more than 250 times worldwide since 1977. The first two connectors, installed at an offshore gas compressor station in Louisiana in 1977, are still in service.

To reduce the potential of further oil spillage, it was necessary to displace the oil inside the pipeline. This displacement process was initially attempted from a nearby platform, but subsea elevations prevented the water from moving into the repair area.

The repair section was then filled with salt water through a 4-in. subsea hot tap made near the damaged area. This procedure displaced the oil in the pipeline for 3 miles from the damaged section that was to be removed.

The repair process actually began with a diver using an hydraulic chipper carefully to strip the concrete coating from the pipeline.

Safety dictated that only a single diver could work on the pipeline. Divers were rotated approximately every hour, each time undergoing a decompression routine.

Once the pipeline was stripped of its coating, it was cut in two locations with an hydraulic guillotine hacksaw. The saw, which can cut pipe sizes from 6 to 24 in., was strapped onto the pipeline by the diver. The surface hydraulic power supply drove a reciprocating saw blade.

The diver used a hand crank to advance the saw blade slowly through the pipeline. The advancement of the saw blade through the pipe resembles the cutting action of a guillotine, hence its name.

The damaged section of pipeline was carefully lifted out of the water and placed on the work barge, where the 4 in. fracture along the seam of the pipe was easily visible (Fig. 3).

MECHANICAL BONDING

Cold-forging refers to the process whereby the Flexiforge end connectors (Fig. 4) are mechanically bonded to the pipeline in a process of plastic deformation of steel (in this case, the pipe wall) at ambient temperatures without applied heat.

Specifically, the Flexiforge process uses a special hydraulically driven rotary tool which expands the pipe outward using a tapered cone surrounded by similarly tapered rollers. As forging is initiated, the cone is retracted under the rollers, forcing them radially outward and in contact with the pipe.

As forging progresses, the rollers force the pipe into intimate contact with the end connector sleeve's inner wall.

Based on the specific pipe grade and wall thickness, BIG INCH's computer program calculates how much force is required plastically to yield and mold (cold-forge) the pipe into the machined ridges of the end connector body.

This force is correlated to the radial expansion of the rollers, which is correlated to the length of travel of the tapered cone under the rollers. A mechanical stop inside the forging tool stops the cone to prevent excessive deformation.

Since the end connector is high-strength material of a greater wall thickness, the connector only undergoes elastic displacement which enhances the surface contact and sealing stresses between the pipe OD and the end connector.

Only the Flexiforge system derives its sealing and gripping functions from such a single action. The tool is operated by technicians from the surface vessel where remote monitoring indicates full completion of the process.

The speed of the cold-forging system reduces on site repair time. In this case, the entire project, from start to finish, took 11 days, with work continuing around the dock.

As a general rule, the mechanical forging process requires 1 min/pipe diameter inch to complete. A 6-in. forging takes about 6 min, a 20-in. forging takes about 20 min.

Other systems rely on a time-consuming process that requires the diver to tighten and torque a series of studs in the body of the coupling. For this repair, the diver need only stab the forging assembly into the pipe and retrieve it after the forging is completed.

The Flexiforge system is a means of joining pipe subsea and represents an improvement over pipeline connector technology previously used by TPLI engineers. The system is an alternative to hyperbaric welding, one of the reasons TPLI engineers selected it. Other reasons included:

A 100% metal-to-metal seal-no elastomeric seals subject to deterioration.
Effective resource utilization-reduced pipe preparation time, fast hydraulic operation, and decreased diver time.
Design integrity-tested and proven to be stronger than the pipeline it joins.

END CONNECTORS; BALL FLANGES

Originally designed in 1975, the end connectors have since undergone only design refinement. The significance of this is that connectors manufactured in 1975 can still be installed with today's installation equipment.

This is important to companies seeking to purchase and maintain their own repair systems.

The connector is manufactured of ASTM A668, Class M (other classes are used for special requirements), using AISI 8630 modified chemistry.

The material's strength is significantly higher (2-4 times) than that of API 5L grade pipes.

It is manufactured of a single piece, upset forging; no welding fabrication is allowed or required.

Exacting computer numerical control (CNC) machining processes are used to ensure quality.

Replacing the damaged section of pipeline, TPLI used an articulating spoolpiece with three ball joints.

The two Ball Flanges (Fig. 5) on the ends of the new section accommodate pipe misalignment up to 10. The articulating ball joint in the center of the new section provides end-gap adjustment.

The section is lowered with the spool articulated at its greatest angle, thereby shortening its overall length.

Once the diver has inserted the RTJ ring gasket in the groove of the end connector flange, the articulation angle of the section is decreased. In a direct geometric relationship, the length of the spoolpiece extends as the articulation is reduced.

The diver can then easily bolt the Ball Flange connectors to the mating end connectors.

Usually, the new section, including Ball Flanges, is fabricated onshore to a predetermined length based upon the inspection diver's measurements of the damage. In this case, the new section of pipeline was manufactured on the work barge. Typical replacement sections are 40-80 ft long.

The fabricated assembly is hydrostatically tested and all welds are X-rayed before subsea assembly. Once on location, the length of the new section can be shortened or it can be lengthened by use of a piece of pretested pipe.

Any resulting welds on the modified spool piece are fully X rayed.

The Ball Flange connector is also unique in being the only misalignment connector which mates directly to a standard RTJ flange (Fig. 6). Older style misalignment connectors require additional flanges as well as significantly more diver effort for bolting operations.

A patented "captured ball" design creates a barricade around the internal metal sealed area to prevent the intrusion of silt and other foreign matter.

And, like the Flexiforge end connectors, all Ball Flanges are fully machined with the CNC process for maximum quality control.

Following installation of the new section of pipeline, divers coated all bare metal (approximately 15% of the total repair section) with a two-part epoxy called Splash Zone which hardens into a permanent coating. Except for weld areas and the fittings, the repair section was yard-coated with cold tar enamel.

DIVE OPERATION

Wave action and lack of visibility make this operation extremely delicate for divers. Special precautions must be taken in the operation of high-pressure water blasters used to remove the concrete coating.

Likewise, divers must stay clear of the blade of the guillotine saw as they normally would in clear water.

The most difficult aspect of this operation in zero visibility was the connection of the two subsea flanges. The diver took special care to keep his fingers clear of the two mating flanges.

The use of the misalignment Ball Flanges greatly reduced the risk to the diver because he adjusted the flange angle quickly.

Without misalignment Ball Flanges, the diver would have had to rely upon the surface crane to make trial and error attempts to force the flange faces into alignment.

The crane line, of course, transmits the heave of the surface wave action to the subsea assembly.

A sudden surge at the wrong time would have injured the diver trying to make such a "hard flange" connection.

Since the repair project was completed in early September, TPLI has experienced no problems with the EIPS.