DANISH SOUR-GAS PIPELINE HAS SUBSEA SAFETY SYSTEM

June 4, 1990
J. E. Thygesen Dansk Olie & Gas Produktion A/S Hoersholm, Denmark Dansk Olie og Gasproduktion A/S has gained valuable experience installing a subsea safety system on a 30-in., 215-km (134-mile) subsea sour-gas pipeline. The system is designed to reduce the risk of explosion or suffocation of personnel aboard a nearby platform. It consists of a subsea check valve and a fullbore ball valve.
J. E. Thygesen
Dansk Olie & Gas Produktion A/S
Hoersholm, Denmark

Dansk Olie og Gasproduktion A/S has gained valuable experience installing a subsea safety system on a 30-in., 215-km (134-mile) subsea sour-gas pipeline.

The system is designed to reduce the risk of explosion or suffocation of personnel aboard a nearby platform. It consists of a subsea check valve and a fullbore ball valve.

Experience from operation of the system has been gained in pigging through the check valve, scour around the installation, repairs, and function tests. This is the basis for recommendations for operators intending to install subsea safety systems of the same or similar type.

DANISH OFFSHORE GAS

The supply of gas for the domestic market in Denmark comes from the Danish sector of the North Sea.

The gas is produced as associated gas from the oil production as well as from gas reservoirs. The present oil and gas production systems are shown in Fig. 1.

The gas streams are joined together at the Tyra East platform complex and transported through the 30-in. gas transmission line to shore, a distance of 215 km (135 miles). The oil and condensate streams are joined together at the Gorm field and pumped through the 20-in. oil-transmission line to the onshore terminal at the east coast of Denmark, a distance of 330 km (205 miles).

The gas covers total Danish gas consumption as well as exports to Sweden and West Germany.

In 1979 the Danish parliament decided that the gas discoveries were to be produced for the Danish market. The first sample of gas showed an H2S content of 0.08 mol % (800 ppm). This is high enough to endanger the lives of people aboard the Tyra East platform in case of a rupture of the pipeline in the vicinity of the platform complex.

With this risk in mind, and the fact there was only one transmission line for supplying the Danish gas market, great emphasis was put into the design, safety, and supply security analysis of the total system.

HIGH RISK

In 1980 a safety analysis by Det Norske Veritas showed a high-risk area close to the platform.

The risk of a rupture was calculated to be 1 X 102 events/km/year for the first km/year for the first kilometer downstream from the platform. In other words, the probability of a rupture of the pipeline in the platform approach area during the course of the 30-year design life of the system is 30%; 100% for a period of 100 years.

The risk is mainly due to damage from falling objects and offshore activities such as fouling by anchors from construction and repair vessels.

With this high risk, sour gas, and supply security in mind, several possibilities were studied to minimize the risk level.

The Tyra East platform complex is illustrated in Fig. 2. The central platform (TCP-A) contains the process and compression facilities and living quarters.

The product in and outflow to the platform complex takes place via the separate unmanned riser platform (Platform TE-E) connected with TCP-A via a 50 m (167 ft) long bridge. Besides TCP-A and TE-E, the complex consists of two well head platforms, B and C.

As can be seen from Fig. 2, the system layout has given personnel and system safety high priority by separating the various potential risk areas of production.

The 30-in. gas line originates from the riser of TE-E. The riser is located in the center of the platform, i.e., out of risk of being damaged by vessels. The pipeline runs at a water depth of 37 m away from the platform through a pipeline expansion loop installed on the seabed.

The expansion loop section is without concrete. It serves as an absorber of longitudinal expansion from the pipeline and thereby reduces the expansion transferred to the riser.

As can be seen from Fig. 3, this horizontal part of the line is at high risk of being damaged by construction vessels working close to the platform. Means of protection were studied intensively.

Trenching was not considered feasible or 100% reliable due to the unstable seabed level and the depth of anchor penetration.

Concrete cover slabs were found to be too risky during installation as well as operation.

A more practical approach was therefore selected involving strict control of all vessel movements and anchoring and of all crane activities on the platform to keep objects from falling on the pipeline.

The nature of outflow of gas from a ruptured subsea gas line was studied intensively. Laboratory investigations were carried out on a model in scale 1:100.

PUFF-CLOUD INDICATOR

The first discharge of gas takes place as a very cold puff-cloud, lasting approximately 20 sec. The puff-cloud will be followed by a high-velocity jetstream with gas exit speed close to the sonic speed for the period of pressure reduction.

The installation of a subsea safety installation, to reduce the amount of gas escaping close to the platform in connection with a pipeline rupture, was therefore chosen to be the best design approach. The total amount of gas in the pipeline is a 10 X 106 Newton cu m (Nm 3) (333 million normal cu ft).

The location of the subsea safety installation was chosen to be 1,500 m downstream from the platform in order to be outside the high-risk area.

The position of the safety installation was evaluated based on the prevailing wind directions in the area and with the intention to minimize the amount of escaping gas and thereby the blowdown time for the damaged pipeline section.

The calculated hazards for the pipeline with and without a subsea safety installation are listed in Tables 1 and 2.

Adverse weather conditions in the context of Tables 1 and 2 are conditions of high atmospheric stability (inversion) and very low wind speed.

These conditions are extremely rare at Tyra East platform, and the probability of a pipeline rupture coinciding with such conditions is tangential to zero.

In practice, therefore, the range of the migrant-gas ignition risk is seldom more than 500 to 1,500 m, while the maximum range of radiation risk is of the order of 500 m.

Table 2 indicates the extent of the risk when the blowdown length is 1.5 km instead of 215.

It can be seen that the geographic extent of the risk has been only slightly improved in this scenario.

What is far more important, however, is that the blowdown time for a 1.5-km length of a 30-in. pipeline at 138 bar (2,001 psi) is some 70 sec, compared with a period of 22 hr for a 215-km length.

This means that the probability of serious consequences is very much reduced, not least because the wind is likely to have a virtually constant direction during a 70-sec blowdown. The chance of that direction being towards the Tyra East flare is limited.

On the other hand, the wind veer during a 22-hr blowdown will stand a good chance of bringing the gas within ignition range at some stage.

SAFETY SYSTEM

The risk of pipeline rupture downstream from the subsea safety installation caused by construction activity in the vicinity of the platform is considered minor and risk level acceptable.

The total pipeline safety system is illustrated in Fig. 4 showing an abovewater emergency shutdown valve (ESV) and a subsea safety installation.

The safety installation chosen is a combination of a check valve followed by a fullbore ball valve further downstream.

The installation was to be protected against damage from fishing activities. The protection chosen was a totally enclosed cover.

The check valve secures immediately, in case of a pipeline rupture close to the platform, the separation of the downstream 215-km (135-mile) pipeline section from the ruptured section.

The total amount of gas escaping is thereby reduced to approximately 0.05 x 106 Nm3 or 0.5% of total gas volume of 10 x 106 Nm3 (333 million normal cu ft) accumulated in the pipeline. As mentioned, the blowdown time of the small section will last approximately 70 sec, in the case of a full rupture, vs. 22 hr without the subsea check valve.

With the subsea safety valve installed in the pipeline, the risk of H2S poisoning of personnel onboard the platform was investigated and found highly unlikely because a part of the H2S would be scrubbed out of the gas during its passage through the 40 m (131 ft) of water to the atmosphere.

The subsea safety installation was made as simple as possible to minimize operation upsets and expensive maintenance (Fig. 5). A simple check valve was chosen and fitted with a retarding mechanism to avoid unnecessary wear on the clapper bearing (Fig. 6) due to oscillation of the clapper caused by the gas stream.

The fullbore ball valve was selected as backup for blocking off the downstream gas pressure in case of a rupture.

Between the two main valves, a 4-in. offtake was installed allowing safe work on the check valve and accommodating the dewatering of the damaged pipeline section after it has been repaired.

The valves are all manually operated by divers.

The installation, especially the check valve, could not be guaranteed maintenance-free throughout the pipeline's design life of 30 years. Furthermore, the installation incorporated the possibility of exchanging the check valve should this be necessary.

Despite this disadvantage, many advantages were found.

The installation gave the platform and personnel a high level of security from gas explosions from a subsea-pipeline rupture in the area.

The amount of gas escaping would be reduced considerably, and the rest of the pipeline containing approximately 10 x 106 NM3 (333 million normal cu ft) of gas, would be saved as a good supply supplement in case of a critical interruption of the gas supply.

The valve installation allows the flooding and dewatering of the damaged pipeline section, thereby reducing the repair time of the pipeline from 60 days to less than 30 days.

INSTALLATION SYSTEM

Installation of a subsea safety valve system in shallow water, i.e., water depth of 40-50 m (131-164 ft) is associated with several problems.

The system has to be protected against impact from fishing gear, such as trawls of various designs. A study was therefore performed to develop a concept which would safeguard the valve system and be stable on the seabed.

The concept was analyzed and tested by means of a model before final selection. A total enclosure covering the valve installation was chosen.

The model test showed that keeping the edges of the cover embedded into the seabed was vital.

Sand-filled textile mattresses were installed to seal the structure into the seabed along the edges and protect against scour. Nature, how ever, proved to be stronger than expected.

After one-half year in operation, the mattresses were found totally disintegrated, the covering structure underscoured with the lower edges 1-2 m (3-7 ft) above the seabed, and the pipeline section underneath free spanning below the original seabed.

The covering structure had during installation been piled into the seabed and was now supported by these 4 piles above the pipeline. The piles were designed to carry the weight and the structure.

Free spanning of the pipeline was corrected by installation of two supports under the pipeline using the piles carrying the structure. In order to minimize the scour underneath the structure, the seabed area was reinforced by dumping 20-cm size rocks.

The rocks have in operation proven to be unstable, however, and are causing backfilling on top of the valves due to the seabed bottom current of 2 m/sec in a 5 years' storm situation. The size of the rock could have been increased to stabilize the backfill. But larger rocks would hamper possible repair work.

OPERATION

The access to the subsea safety system has proven to be hampered by backfilling of rocks, gravel, etc. The edges of the structure are approximately 0.5-1 m (2-4 ft) above the seabed.

The near seabed current is thereby increased, enabling the transport of heavy rocks into the covered structure. The rocks partially covering the valve systems hamper proper inspection and maintenance without excessive cost of air lifting (Fig. 7).

Concepts for controlling the backfill under the structure are under development. A recommendation to operators intending to install subsea systems at similar water depth is to reinforce the seabed with rocks before the installation of the valve system on top of it.

They thereby avoid the scour and sinking of the system below the normal seabed causing backfill and poor access during operation.

The check valve was designed for free passage of pigs. Before the start of pigging operations, a test was executed on an onshore spare valve to evaluate the proper design of the pig.

The only acceptable pig was a specially manufactured cup-pig able to bridge-over the check valve (Fig. 8).

The maintenance and regular check of the ball valve was limited to external inspection. Based on contact with other operators it was recommended that the valve should only be operated in emergency situations and in case of repair of the check valve.

PIGGING RUNS

In Spring 1988 the pipeline was prepared for intelligent pigging. The clapper in the check valve was lifted and blocked in open position. The first dummy pig run, however, showed an obstruction in the pipeline. Through a specially designed pig, the location of the obstruction was identified as the check valve.

A later diving inspection showed that the opening and blocking mechanism on the valve was not connected to the clapper shaft itself. The location of the disintegration was not visible.

As a matter of safety it was decided to isolate and blowdown the pipeline section between the platform and the valve installation by closing the 30-in. ball valve. This would allow a safe disconnection of the blocking and retarder mechanism and hopefully locate the break.

The ball valve was closed and the gas blowdown initiated. But, the ball valve was unable to close and thereby did not permit a blowdown of the pressure in the check valve. It was later found that the seat-rings of the ball valve had settled in a fixed position and did not allow sealing off the pressure.

The rings were reactivated by flushing them with diesel oil and turning them by opening and closing the valve several times.

The procedure allowed the blowdown of the pressure and the inspection of the check valve.

Dismantling of the blocking and retarder mechanism showed a break in the outer connection. A new and modified mechanism could be installed.

The preanalysis of possible causes of failure proved to be correct. The retarder installed by the supplier was shown to be working in the opening as well as in the closing direction and not dimensioned for such.

The retarder working against the pig trying to lift the clapper had caused the retarder mechanism to break.

Based on recommendations by the manufacturer, the retarder force was eliminated in the new one installed in order to avoid overstressing.

A final solution for pigging through the clapper has not yet been selected. Until that time, the clapper is manually lifted to open position by divers and after pig passage released.

Since repair of the check valve, a program has been initiated for development of a new concept for pigging through the check valve without having to block the clapper in open position before every pigging operation, which involves extra costs and restricts the free selection of the time of pigging.

The impact between pig and clapper has been calculated based on registered pig velocities through the valve. The calculations have been verified by laboratory tests.

For the time being we are working on a modification of the pig to ease the impact between pig and clapper. Several tests and other possible routes of modification, however, will have to be investigated before a final selection. The greatest uncertainty is found to be the pig speed when approaching the check valve.

BLOWDOWN TEST

During the repair operations, the subsea valve system (Fig. 5) has proven acceptable, allowing the blowdown of the section towards the platform in a controlled manner through the flare and the 4-in. branch.

Extreme care, however, had to be taken to guide the blowdown gas to the surface at a safe distance from the diving support vessel. A heavy bunker hose was used for this purpose.

Because of the low pressure in the hose, however, as a result of the suction of the gas outlet after closing the 4-in. valve, the hose collapsed under the surrounding water pressure. A new system is therefore under development.

The subsea check valve has been repaired and is undergoing regular function tests.

A test is to check the valve's capability to seal off the back-flow of gas. The valve is passing this test.

Seal-off test, however, will not be representative for a full pipeline rupture situation.

In this case the valve will close very abruptly and be exposed to high forces.

IMPLICATIONS

Installation of a subsea safety valve involves some major operational problems. But they can be minimized by a proper design of the valve system which allows for the change out of the weaker part of the system, normally the check valve.

A safety system consisting of a check valve followed by a block valve is a reliable safety system. It gives high level of protection to the platform and its personnel against hazardous gas escape and explosion in case of a pipeline break in the area.

Such a safety system reduces the repair time of the damaged pipeline section and saves most of the gas in the line from being released and lost in situations where gas supply is critical.

Operators who intend to install such type of safety valves should request extensive function tests representative of operations and emergency situations including a pipeline rupture simulation.

The manufacturer despite normal practice should supply all design calculations of the various parts of the valve, not only the stress calculations dealing with overpressure. This allows the customer to recheck and inspect the delivered product before installation.

Pigging through an activated check valve must be analyzed very carefully and the impact between pig and clapper lowered as much as possible.

Subsea mainline block valves should be operationally tested regularly and greased despite the fact that they only serve as block-off valves in emergency situations.

Valve manufacturers should be required to deliver detailed calculations of dimensions of all parts in the delivered product for proper check by the operator before final acceptance of the design.

Copyright 1990 Oil & Gas Journal. All Rights Reserved.