SUBSEA PRODUCTION DEVELOPMENTS-CONCLUSION NORTH SEA DIFFICULT BUT PRIME AREA FOR APPLICATIONS

Knut S. Skattum
Norsk Hydro A.S.
Oslo

The Norwegian North Sea sector has been considered a very expensive area for subsea developments compared to the Gulf of Mexico and Brazil, where, the cost of a completed subsea well is several times less. 16 An analysis of these large differences, though difficult, may show how the costs for North Sea projects can be reduced. Nevertheless, numerous projects are planned or underway in the Norwegian sector. The Troll/Oseberg gas injection (TOGI) project will be a major test of important innovations.

The first article in this two-part series appeared in OGJ, Mar. 12.

COSTS

The main reasons for the differences in cost between Norwegian sector and U.S./Brazil can be traced to the following:

Deepwater technologies--A number of subsea developments in the North Sea have utilized new technologies in order to save on maintenance and servicing work and to prepare for deeper waters and more hostile environments. Prototype equipment has been utilized, sometimes resulting in extensive engineering, testing, and reworking/redesign. However, these developments are believed to have a long term cost benefit.
Rules and regulations--The regulations which Norwegian offshore developments must meet are different from other areas. They cover protection for fishing equipment (e.g., over-trawlability and burying of sealines); monitoring and frequent servicing and functional checks (e.g. barrier testing); and working conditions.
Quality assurance--This has resulted in increased manpower to administer quality activities and to write, check, and administer the necessary documentation.
Quality requirements--These are in general considerably higher in the North Sea compared to Brazil and Gulf of Mexico (e.g., welding requirements) where established practices are allowed to continue if experience is satisfactory,
Safety measures--The large reservoirs and extreme consequences in case of accidents (e.g., blowout) have made it necessary for North Sea operators to enforce strong safety criteria, i.e., for dropped object protection.
High reliability--Because of high production potential of North Sea wells, an increase in reliability from 75% to 95% may easily result in a doubling in rate of return. This leads to use of redundant systems and increased emphasis on the equipment design creating a need for robust design and on extensive testing programs.

The main economic challenges are therefore to minimize cost under the given regulations and conditions using the knowledge now available. It is believed that the areas where potential savings can be made are in:

Standardized equipment and tools for installation and servicing.
More use of divers in shallower waters where field-proven diverless systems do not exist.
Reduce documentation requirements and optimized QA/QC activities.
Reduced overall management manpower and site follow-up partly as a result of more standardized designs.

TOGI CHALLENGES

The TOGI Project is the result of a decision to maintain the Oseberg reservoir pressure by injection of gas from the Troll field. This is the largest offshore natural gas reservoir so far discovered in Europe and it is some 50 km (30 miles) west of Oseberg.

The gas injection will enable Oseberg to recover an additional 12 million cu m (75 million bbl) of crude oil. The subsea station with six-well slot template structure, five Christmas trees, a manifold module, and pig launching facilities will be placed on Troll, East 48 km from production control facilities at the Oseberg Field Center platform.

Also part of the system are a 20-in. gas production line, a service line bundle, including two hydraulic lines, one methanol line, and one cable. Fig. 1 depicts the situation, including the existing crude to the Sture terminal.

Because of the station's location in 1,000 ft of water, Norsk Hydro decided to design the station for diverless installation and servicing. Fig. 2 shows the template being lowered on location in August 1989.

The long distance to the Oseberg Field Center and need for extensive monitoring have made it necessary to look at advanced technological solutions. The following four areas are considered to be the four most challenging technical areas of the project.

MULTIPHASE FLOW

Transport of unprocessed well fluid over long distances without the use of pigging to remove liquids has not been used extensively prior to TOGI. In particular the limited slug catcher volume that could be fitted on the already designed platform at Oseberg posed demanding challenges to the TOGI design team. Detailed knowledge on liquid multiphase flow dynamics, hydrate prevention, and corrosion protection was required for the design.

The pipeline route will start at a depth of around 300 m at Troll and ascend to a depth of around 110 m at Oseberg as indicated by the contour lines in Fig. 1. The major part of the climb will take place in the western slope of the Norwegian trench. In this slope the average inclination will be around 1. Locally there will be depressions causing inclinations as high as 5. Ability to calculate precisely the amount of liquid accumulations in the surface depressions have been one of the key parameters for understanding the behavior of the multiphase flow.

The TOGI pipeline will have continuous methanol injection to prevent hydrate formation. Approximately 30 to 35 cu m of methanol will be injected each day during full production.

The TOGI project has extensively used the high quality measurements obtained in the Sintef multiphase flow laboratories in Trondheim and the computer models for dynamic two phase flow simulations developed by the Institute for Energy Technology (IFE) at Kjeller, Norway.

POWER AND SIGNAL

The supply of electrical power and transfer of electrical signals over a 50 km distance to subsea wells is only possible in the TOGI project because of an extension of available technology. This distance is more than twice the distance ever attempted in subsea production control systems. In the TOGI system, signals and power will be transferred in one cable and distributed within the subsea station on Troll to the Christmas trees.

The subsea electrical distribution necessitates electrical connections that have to be made up on the sea bottom during the installation of the cable and the Christmas trees. Through long term testing, two types of conductive connectors have been selected to reduce risk of common fault failure.

The TOGI control system is dual redundant and the transmission voltage is 450 v ac. At the subsea station this voltage is transferred down to 35 v ac. The signal transmission is superimposed on the power transmission using the same conductor pair for both purposes. The digital signals phase modulated on a 1800 hz carrier. The TOGI production system is delivered by Aker Vetco with Hughes Aircraft and STK as main subcontractors for the transmission system.

LEAKAGES AND SAND

Early in the TOGI project the design team decided that special systems that could monitor gas leakages and sand particles produced with the gas were desirable. No such systems were commercially available at that time. After a development and test program with Simrad Subsea, Norsk Hydro decided to include these systems as elements in the production control system.

The sand detection system mounted on well stream pipe on each tree utilizes the noise generated by particles in the well stream, impinging on a flow bend. This noise contains frequency components significantly higher up in the frequency spectrum than other noise generated by the gas flow. Thus, by frequency analysis of the noise spectrum it is possible to identify that part of the noise generated by the sand particles. The practical implementation incorporates an acoustic transducer and a microprocessor located in a subsea pod.

The gas leak detection system is also based on acoustics. Gas bubbles are detected by transmitting a number of acoustic pulses from a transducer located close to each well and receiving the echoes of the pulses. By means of signal processing and calculations, the position of the leakage relative to the transducer position and the approximate leakage rate will be decided and this information will be transferred to Oseberg through the subsea cable.

PIPELINE

Due to the water depth at Troll and the TOGI requirement of diverless operations, complete and universal diverless pull-in and connection systems had to be developed."

The systems have been designed by Kvaerner Subsea Contracting. In August 1989 the actual pull-in was successfully performed at the Troll location. Here the drilling rig and pipeline laying barge worked closely together (Fig. 3).

The tension in the suspended pipeline was controlled by the draw work off the drilling rig and the pipeline tensioners on the laybarge. For the last meters of pull-in, a linear winch installed on the pull-in tool was engaged, and finally the pipeline head was locked down. The mechanical connection was performed using a universal connection tool.

The system has been designed to perform a number of tasks and it may also be competitive in shallow water applications where diver made up mechanical or hyperbaric welding connections have been used so far.

THE FUTURE

The North Sea and Brazil will most probably dominate subsea development into the 1990s with the North Sea as the major area. It has been estimated that by the end of this century about 400 subsea wells will be in production in the North Sea compared to about 140 today. 9

This means that from today's rate of about 10% of all hydrocarbons being produced from subsea wells, production from the new developments may raise the subsea ratio by more than 50%.

In the Norwegian sector, large subsea developments under way or being evaluated are: Gullfaks, 4 single wells (1990); TOGI, 5 wells (1991); Snorre, 20 slot well cluster (1993); Draugen, 9 wells (1993); Statfjord satellites, more than 20 wells (1 994?); Midgard, 4 wells (1995?); and others, Gullfaks South, Troll, Balder, etc.

This could lead to about 100 subsea wells during the 1990s.

In the U.K. sector, there are indications that some 1 00 fields with recoverable reserves each in the range of 80-100 million bbl of oil equivalent remain to be developed. The majority of these are within 20 km of process facilities.

However, while future U.K. developments will focus on smaller fields and satellites in shallower waters, the Norwegians must to a larger degree enter the deeper Norwegian trench and the deeper areas outside northern Norway. But also it is believed that there will be very few large scale developments; most will be smaller fields and satellites. It should also be noted that some of these fields in the Norwegian trench will be located less than 60-70 km away from the mainland.

With the potential solutions to production control over long distances and subsea multiphase pumping, future offshore development may be limited to on-bottom subsea facilities.

ACKNOWLEDGMENTS

The author wishes to acknowledge the support received during the preparation of this article from B. Ringvold and Ian Ball of Norsk Hydro, and S. Sasanow of Subsea Engineering News.

REFERENCES

Sletten, S., "Standardization and simplicity priorities for oil companies," Noroil, June/July 1989.
Varvin, K., Pedersen, K., "Diverless pipeline pull-in and connection system for the TOGI project," Deep Offshore Technology Conference, 1989, Mirabella, Spain.