NORTH SEA ESV PROGRAM IS FOCUS OF SUMMER WEATHER WINDOW

May 7, 1990
Warren R. True Pipeline/Gas Processing Editor Roger Vielvoye International Editor A major effort to improve the protection of workers and facilities in the North Sea will step into full swing this summer when many operators will install new or relocate existing emergency shutdown valves (ESV's). A Norwegian-sector installation is noteworthy because of its depth and the use of a check valve as an ESV. Most of the activity will occur in the U.K. sector and is prompted by findings after the
Warren R. True
Pipeline/Gas Processing Editor
Roger Vielvoye
International Editor

A major effort to improve the protection of workers and facilities in the North Sea will step into full swing this summer when many operators will install new or relocate existing emergency shutdown valves (ESV's).

A Norwegian-sector installation is noteworthy because of its depth and the use of a check valve as an ESV.

Most of the activity will occur in the U.K. sector and is prompted by findings after the July 1988 explosion on Occidental Petroleum's Piper Alpha platform.

U.K. Department of Energy (DOE) general regulations governing ESV's require that all U.K.-sector work be completed by Dec. 31, 1990. But complete and specific valve-design guidelines have not been officially released.

DOE officials are, however, working with operators, which has permitted work to proceed.

According to the regulations, valves must have two locations: above water level on platforms' pipeline risers and subsea at the bases of platforms.

U.K. Offshore Operators Association (Ukooa) estimates total cost for the topsides work for 1989 and 1990 at as much as 150 million ($247.5 million) and possibly as high as 200 million ($330 million). For the subsea work, Ukooa estimates the cost for this year and last at 162 million ($267.3 million), mostly for large-diameter pipeline risers.

The Norwegian project not withstanding, most valves being used employ conventional ball-valve technology.

WHAT'S HAPPENED

On July 6, 1988, explosions and fire destroyed Occidental Petroleum (Caledonia) Ltd.'s Piper Alpha production platform. The accident killed 167 men.

Set in Block 15/17, 120 miles northeast of Aberdeen, and standing in 470 ft of water, the platform was one of the largest of the first-generation production platforms in service off the U.K. (OGJ, July 11, 1988, p. 20).

Oil from Piper, and neighboring Claymore, Tartan, and the subsea satellites, moved by pipeline to a terminal at Flotta in the Orkney Islands. Piper gas moved to the Claymore platform where it was used for gas lift (OGJ, July 11, 1988, p. 20).

The preliminary technical investigation quickly concluded that much of the damage caused by the fire on Piper could have been prevented if the platform's ESV's had been located as close to the sea level as possible or if a second ESV system on the seabed had been in place (OGJ, Dec. 18. 1989, p. 28).

The study suggested that after the first explosion in Piper's gas-compression module, the disaster was made worse by a rush of gas from an incoming gas pipeline and a backsurge of gas from two outgoing gas lines.

In August 1988, after the explosion and in light of this initial evidence, U.K. DOE Director of Safety J.R. Petrie requested all operators to reevaluate pipeline ESV's then in use.

At the time of the accident, all U.K North Sea platforms had ESV'S, some on the seabed. Most were topsides on platforms, as was the case on Piper.

There, each of the four risers was equipped with an ESV. One handled oil exports and was set 83 ft above sea level. Three others, handling gas from Tartan and gas shipped to Claymore and through the Frigg pipeline, had their ESV's 68 ft above sea level (OGJ, Aug. 29, 1988, p. 16).

By midyear 1989, the DOE had issued several guidelines, the most important of which required operators to reposition, where necessary, platform ESV's to as near the splash zone as possible.

New guidelines on subsea ESV's had been expected by the end of 1989. But draft regulations are only now being circulated among operators with final guidelines not expected until the fall. By that time, the final report of the official inquiry into the accident is also expected.

Individual operators wishing to proceed with installing subsea valves, however, as some already have, are working with DOE personnel to ensure those installations will be acceptable under the new guidelines.

WHAT'S HAPPENING

Some operators moved quickly last year to comply with regulations governing platform-level ESV'S. During the summer maintenance shutdown, Marathon Oil U.K. Ltd. moved six ESV's on its Brae Platforms A and B.

On both structures, ESV's had originally been installed in the pig-trap areas close to wellheads. The new ESV's were installed under the platforms as near the top of the risers as possible, given maintenance and inspection requirements (OGJ, Oct. 9, 1989, p. 38).

By the end of last year and as a result of the new regulations governing placement of platform-level ESV'S, approximately 200 risers installed in the U.K. North Sea were being modified. About 130 of these are being relocated.

Oxy, however, began its ESV retrofit program less than 3 months after the Piper Alpha explosion and well before the U.K. DOE had issued its first set of guidelines on ESV'S, those for topsides installations.

Between September 1988 and April 1989, Oxy installed 15 new subsea ESV's ranging in size from 3 to 30 in. All are located in approximately 360-ft water depths (Figs. 1 and 2).

Between October and December, a 30-in. Robert Cort & Son Ltd. valve was installed 135 m from the base of the Claymore platform on the 112-mile main oil line to the Flotta terminal.

A 24-in. TK Valve Ltd. valve (Fig. 3) was installed at the same time on the 18-mile oil line from Texaco's Tartan platform back to Claymore. The valve is located 125 m from the base of Claymore.

On the 14-in., 25-mile line from Amerada Hess' Ivanhoe/Rob Roy to Claymore, another subsea ESV was fitted 150 m from the base of Claymore in March and April 1989.

For the gas-pipeline service, the 16-in., 21-mile line from the 18-in. Tartan-to-MCPOL line which is tied in at the Piper area was fitted with an ESV 450 m from the base of the platform between October and April.

Oxy also installed an 18-in. ESV on the gas line 500 m from the base of Total's MCPOL platform between October and March.

The subsea Scapa pipelines are in two bundles of a 10 in., 6 in., and three 3-in. lines each. The lines are designated "Scapa North Bundle" and "Scapa South Bundie."

Multiphase production flows to Claymore through the 1 0 and 6-in. lines in each bundle. The three 3-in. lines in each bundle flow gas back to the Scapa template for gas-lift operations.

The 10 ESV's (five per bundle) for the Scapa lines are enclosed in two protective cages, one for each bundle. The cages were located approximately 30 m from the base of Claymore. Installation occurred in January and February 1989.

As part of topsides installations, a new Cort valve was added to the 30-in. main oil line at the top of the riser on Claymore.

Part of Oxy's program for topsides valves was to ensure that these ESV's are located as close to the water line as possible but above the splash zone, following preliminary findings of the Piper Alpha accident.

On Claymore, an existing 24-in. topsides valve on the line from Tartan was replaced by a new TK valve and its location moved closer to the top of the riser.

A topsides valve for the pipeline from the Ivanhoe/Rob Roy field had been purchased but not installed at the time of the Piper Alpha accident. At that time, the Ivanhoe/Rob Roy field was still under development. Production commenced in July 1989.

When the valve was installed, its location was moved about 20 m along the pipe from the originally planned location to the top of the riser.

For Scapa production, existing topsides, 6 in. and 10-in. valves as well as the six new 3-in. valves were located at the tops of the risers of the platform.

Actuators for all subsea valves installed in the Oxy program are spring-return, fail-safe close types. All are hydraulically operated except for the 6 and 10-in. which are pneumatic.

Rating for the 30-in. main-oil-line valve is 900 lb. The 14, 16, 18, and 24-in. valves are all rated to 1,500 lb.

The valves for the Scapa lines' ESV's are rated at 900 lb.

Oxy's rules for subsea valves dictate that valves within 150 m of a structure be protected against dropped objects, hence, the cages for the Scapa ESV'S.

The ESV located at the edge of the 500-m exclusion zone around Claymore has an "over-trawlable" cover to protect against commercial fishing activities.

ADDITIONAL U.K. WORK

Texaco North Sea U.K. Co.'s plans for 1990 installations are indicated in Table 1 showing ESV's in place and planned for Tartan platform and subsea areas.

Shell U.K. Exploration & Production (Shell Expro), operator for the Shell/Esso group, says it will spend between 50 and 100 million ($82.5-165 million) on the installation and relocation of platform ESV'S. It is giving no details of the exact number of valves involved in the program.

It is also installing, ahead of DOE guidelines, six subsea ESV's at a cost of 60 million ($99 million). Three of the valves will be installed in the northern North Sea and three in the Southern Basin.

The Shell program will result in substantial production losses this summer. There will be a rolling shutdown of the four platforms on the Brent field, and the entire Brent pipeline system to Sullom Voe will close during October.

The Ninian-Sullom Voe pipeline will be shut down for a subsea ESV valve installation.

Other major field shutdowns this summer, not exclusively for ESV installations, will be seen on the Mobil and Texaco-operated oil fields.

BP will install a total of 26 ESV's this summer: two on Ula in the Norwegian sector, two each on the Thistle and Magnus fields, and 16 on Forties.

In addition, modifications will be made to the Buchan and Clyde oil fields and the Ravenspurn South and West Sole gas fields in the Southern Basin.

Forties will also be shut down for major ESV work. That program will cost up to 25 million ($41.25 million) and will involve valves ranging in size from 2 to 24 in.

Seven valves will be installed on Forties Charlie, five on Forties Alpha, two on Echo, and one each on Bravo and Delta.

And Chevron U.K. Ltd. has awarded a contract to Stena Offshore, Aberdeen, to install four skids containing eight subsea ESV's on all four infield pipelines on the Ninian oil field.

Work on the 8 and 24-in. pipelines will occur during a 3-week production shutdown in September. The eight valves will be manufactured by Cameron Ironworks, Livingston, Scotland; the skids by THC Fabricators, Hartlepool, England; and the control systems by GEC Avionics, Bristol, England.

SNORRE CHECK VALVE

A study by J.P. Kenny & Partners, U.K., of subsea ESV's installed in the North Sea through the end of 1989 found that the fully welded ball valve has been the most often used configuration for subsea ESV'S. The table showing work around Tartan would seem to confirm this.

These valves have been chosen mostly for their controllability. But a second choice, desirable for its simplicity and reliability, is the check-valve configuration.

Kenny & Partners note that, because of the functional principle of the check valve, its use is limited to export lines.

One such valve, modified to allow remote control, will be installed this summer in the Norwegian sector of the North Sea.

A 10-in., ANSI-900 Class check valve specially modified to function as an ESV was delivered Mar. 26 to SAGA Petroleum for installation in 308 m (1,010 ft) of water on the Snorre field development.

The valve has been modified to permit topsides control as well as diverless maintenance and repair.

These features are unique for check-valve designs, says the valve's manufacturer and supplier Tom Wheatley Valve Co., Houston.

The valve meets the requirements of NACE MR-01-75 and API 6D and is to be installed in a pipeline using API 5LX60 with a design life of 30 years. The valve will have an operating pressure of 2,284 psi and the test pressure of 4,570 psi.

SNORRE DEVELOPMENT

The Snorre field development program is scheduled to come on stream in late 1992. The field lies 150 km (93 miles) west of Floro, off the Norwegian coast, and extends across two of Norway's North Sea blocks, 34/4 and 34/7.

SAGA Petroleum will be operator with Esso Exploration & Production Norway A.S. supporting the project. To date 11 wells have been drilled in the field.

During Phase 1 of the field development, a tension-leg platform (TLP) and a subsea production facility will be installed on the field. After initial processing on the Snorre platform, final processing and export of the oil and gas will take place at the Statfjord field.

The pipeline running between the Snorre field and the Statfjord area will be laid at a depth of 1,100 ft beneath the TLP.

One of SAGA's main concerns in the development of this project was the ability to provide a subsea emergency-shutdown system to ensure the safety of the platform once the gas had been pumped into the line headed to Statfjord.

Complicating this problem was the fact it would be installed on the seabed in 1,010 ft of water but require the ability to be maintained if necessary.

SAGA decided to install a subsea ESV on the 10-in. line as part of the gas export system for the Snorre field. The additional decision was made to install a check valve of the clapper type.

The type of valve chosen has seen subsea service in the Gulf of Mexico for more than 25 years and in the North Sea for more than 12 years, according to Tom Wheatley Valve Co. to which SAGA awarded the contract for the valve.

OPERATOR STIPULATIONS

Saga requirements included:

  • 10-in. valve installed at 308 m (1,010 ft) water depth

  • 2,285 psig working pressure; 4,570 psig test

  • Weld end installed as anchor point in the expansion spool between the riser and pipeline connector on the TLP well template

  • Remote operated with mechanical override to lock-open to allow intelligent pigging or backflow under controlled conditions

  • Failsafe closing on pipeline pressure loss

  • Subsea operated and maintained without diver assist

  • Hydraulic power supplied by control-line umbilical or ROV.

    To meet the requirements, Tom Wheatley Valve designed, manufactured, and tested four major valve components (Fig. 4).

  • Baseplate. The baseplate is welded or bolted to the TLP well template and provides the mounting base for the valve. The baseplate also incorporates two ROV-removable and deployable guideposts with remote guideline deployment capabilities.

  • Barrier valve. The barrier-valve body mounts on the baseplate and is welded into the expansion spool. The barrier valve is a clapper type in which the clapper free swings in response to pipeline flow,

    Loss of flow causes the clapper to close by gravity and prevent back flow.

    A unique drive shaft and clutch arrangement allows the clapper to swing free during normal operation and turns the clapper to the full opening position when the shaft is rotated. The shaft does not rotate except when the valve is being locked-open or released.

    The clapper seal is metal-to-metal with a secondary Teflon seal. The body-to-cover seal is a pressure-energized metal-to-metal seal. The shaft is a backseat seal designed with a secondary Teflon V-packing set.

  • Barrier-valve actuator. The barrier-valve actuator is a remotely removable and installable single-acting, spring-return rotary design which can be operated by hydraulic or mechanical input (Fig. 5).

    Under normal operation, the hydraulic power to the actuator will be supplied by an acoustically controlled power pack installed by ROV on the seabed near the barrier-valve module.

    The mechanical override is ROV-operated and used to hold the valve in the locked-open position before commissioning of the pipeline or in emergency situations in the event of hydraulic failure.

    The hydraulic supply to the actuator can also be supplied by ROV via a hot-stab provided on the barrier-valve module.

  • Valve-intervention tool. The valve-intervention tool (VIT) is a dual-function hydraulically powered maintenance tool. The hydraulic power is provided by a surface-controlled umbilical or ROV hydraulic hot-stab and VIT-mounted control valves.

    The VIT is run on established guidewires by drillstring or wireline and soft lands on the barrier valve and baseplate. It is capable of retrieving or installing the barrier-valve actuator or all valve internal components without diver assistance. The body and baseplate remain on the well template.

H. O. Mohr Research & Engineering, Houston, assisted Tom Wheatley Valve in the design of the intervention tool and connector.

The barrier valve makes extensive use of carbon-steel forgings and nickel alloys and nickel-alloy overlays. Pressure-containing and structural parts were subjected to extensive NDT (nondestructive testing) evaluation including ultrasonic, magnetic particle, dye penetrant, and radiographic methods.

Tom Wheatley Valve says extensive testing verified component function, pressure-containing capability, and integration of the components. Customer surveillance was conducted on all phases of the project from material testing through final acceptance testing, coating, and preparation for shipment.

During normal operations the baseplate and valve will be located on a drilling template below the TLP.

Routine operations of the valve can include pigging in either direction through use of the remotely controlled actuator with the clapper placed in the locked-open position, allowing passage of most intelligent pigs.

Copyright 1990 Oil & Gas Journal. All Rights Reserved.