SUBSEA DEVELOPMENTS-1 TECHNOLOGY, NEEDS FAVOR MORE ACTIVITY

Knut S. Skattum
Norsk Hydro A.S.
Oslo

Given the large amount of information available on subsea production facilities and experience with them,' ' the time is ripe to analyze subsea development and consider the technical and economic challenges for this technology.

Today, almost 30 years after the first underwater well completion, there is more interest in subsea development than ever before. This interest has been spurred by deepwater development, marginal fields near established fields, satellite wells to more efficiently produce reservoirs, safety, increased equipment reliability, and increased knowledge of multi-phase flow.

The latter two points open the door to maximizing control and processing units at onshore facilities.

SUBSEA FACILITIES

The first well completed subsea in 1961 by Shell was a single satellite in 17 m water depth. Since then there has been a gradual increase until the present where the North Sea and Brazil represent the two major areas of subsea development (Table 1 and Fig. 1).

At present approximately 570 wells have been completed subsea of which 450 are still active. There are approximately 300 oil producers, 80 gas producers, and 70 injectors.

Completions have gradually moved into deeper waters as experience has grown and the search for hydrocarbons has been extended. The first well beyond 300 m was completed in 1984. Fig. 2 shows the developments beyond 300 m after that time.

NORTH SEA

The first field discovered in the North sea, Ekofisk, initially was produced by subsea wells tied back to the drilling rig Gulftide.

This was in 1971 in the Norwegian sector. The first permanent subsea production was in 1975 in the Argyll field in the U.K. sector.

Fig. 3 depicts North Sea subsea completions to date. Table 2 gives some important data relating to subsea facilities and projects in fields in the Norwegian sector in production or under planning. Some comments on these follow:

North East Frigg is the first subsea development in the Norwegian sector. The gas is manifolded and sent 18 km through a 16-in. pipeline to the Frigg field. A special control station was installed 150 m away from the subsea template. This station has been manned only during special maintenance and servicing work.3
East Frigg is a complete diverless system designed after the Skuld project principles. Five production wells are controlled from the Frigg field about 18 km away. It has had an excellent production record since start of production.4
Gullfaks has five diverless satellite wells that made it possible to start production from Gullfaks at an early stage. Production started in 1986. Experience has been good.5
Tommeliten had a short development period with the production starting about 28 months after the decision to go ahead. Tommeliten employs divers for installation of lines but could with minor adjustments be made completely diverless.4
Oseberg has two oil production wells, of which one was initially (in 1986-87) used as an early producer into the production ship Petrojarl. Averaging about 20,000 b/d over an 18 month period, the early production systems proved to be very reliable. One of the two early production wells was tied back to Oseberg and started regular production by late in 1988.
The "7/11" is a one-well, single satellite tied back to the platform in the Ekofisk complex.
Cost has been reduced to a minimum by employing simple and standard equipment and maintaining a pure hydraulic control from the mother platform.
Troll Oil has a test-well in 330 m water depth with the objective of evaluating the potential of extracting the thin layer of oil situated underneath the gas zone at the Troll West location. The well has been drilled and completed horizontally. Production tests began early in 1990 with rates reaching 30,000 bo/d.
TOGI (Troll Oseberg gas injection) has a complete diverless subsea station installed in 305 m to collect and produce from five gas wells on Troll East location. The gas is transported to the Oseberg field where it is injected into the reservoir for pressure maintenance and increased 7 oil recovery.
Snorre is an ambitious large-scale deepwater (330 m) oil development planned to be in production in 1993. It consists in Phase 1 of a tension leg platform, from which 44 wells may be drilled, and a subsea station located 6 km away. It will utilize advanced subsea technology.8

TERMINOLOGY

Fig. 4 illustrates simply and schematically the elements that may be involved in subsea facilities and the corresponding terminology.

The production facilities can be broken down into three types:

Satellite wells-These are wells tied back directly without use of manifold systems to established production and process facilities on fixed or floating platforms. Examples of these are the wells tied back to the Gullfaks and Oseberg facilities.
Floating production systems (FPS)-These are production facilities for subsea wells only utilizing ships (e.g. early production ships like Petrojarl), converted drilling rigs (e.g., Argyll), or specially built floating units.
Stand-alone subsea development-This is usually associated with multiwell development where the oil/gas fluid is manifolded and transported to processing facilities some distance away. Examples of this are Central Cormorant, East Frigg, Highlander, etc.

SUBSEA CHALLENGES

The ultimate goals during offshore projects are safety during development and production, and total economy.

The recent increase in subsea developments is a clear indication that they can compete with platform completions in terms of safety and economy.

Each offshore discovery of hydrocarbon reserves will set definite and unique boundary conditions and requirements for a development scenario. Each potential development has to be evaluated on its own merit. The major determining conditions that will have to be considered in order to select a development scheme are: Production data, including fluid characteristics, production quantity, and reservoir characteristics; and location data, including water depth and distance to possible processing facilities.

It is therefore difficult to standardize and propose solutions. Nevertheless, there are major options involved in a subsea development. The major questions, along with some comments, are:

Subsea or surface-completed wells?
The choice depends on the number of wells required at a set location and the water depth involved. The dividing line in the North Sea has been roughly 10-15 wells in 100-200 m water depth, respectively. With well requirements less than those given, subsea completions have in general been selected.
With the increased capabilities of extended reach drilling, some potential satellite wells may be replaced by topside wells. Horizontal distances from the platform of up to 5 km may be of interest for extended reach wells.
Single or multiwell system?
The distance from the processing and control facilities and the number of wells required are the main parameters to consider. Within an area of 5 km radius from a production field's center, single satellite wells have been mostly used.
Multiwell systems increase the complexity of the control system because of manifolding, underwater choking, and monitoring requirements to each well. Economics will decide which system is best.
Wet or dry subsea facilities ?
A number of research projects and prototype developments have been directed towards a one-atmosphere dry chamber around the subsea Christmas trees and/or manifold system.
So far, however, few dry trees have been put into a production mode. And there is not much talk about utilizing such systems in the future. The main reasons for this clear tendency are that the wet trees have proven to be reliable and also that the dry system needs personnel (divers) in the waters for maintenance and servicing.
Diver or diverless?
In Norway, diving is in general accepted down to 180 m but certain activities have been qualified down to 360 m (e.g., pipeline repair). However, because of costs, safety, and the well-being of divers, the general consensus is that below 300 m, subsea systems should be completely diverless. Diving offshore Brazil is not allowed in more than 300 m water depth.
In the Norwegian sector of the North Sea, a number of the subsea developments have been designed for diverless installations and operation/maintenance (Table 1). Good experience has been gained both at East Frigg 4 and Gullfaks in diverless operations. These are needed stepping stones before developing oil and gas fields at greater water depths.
However, cost considerations especially have led Shell' to announce its strong commitment to diver-assisted subsea development schemes (e.g., Osprey and Gannet) in water depths between 100 and 200 m).
In the future it is likely that traditional diver-assisted operations in 100-200 m water depth can be done both more economically and safely using diveriess systems.
Multiplex or pure hydraulic control?
This question is essentially only valid for single satellite well developments because the multiwell system will need electrical cables for monitoring purposes, creating the basis for multiplex electro hydraulic systems. Pure hydraulic control systems are much simpler because electrical connections and signal transfers are eliminated. However, response time is increased considerably with increasing distance, and wellhead pressure has to be monitored by other means, if needed.
TFL servicing?
Depending to a certain degree on the reservoir characteristics and need for frequent well servicing, the TFL (through flow line) system can be an interesting option as has been demonstrated by Shell in its Central Cormorant development and now by Saga's selection for the Snorre development.
However, the TFL servicing system is complex and usually not a serious option for most subsea developments including the new subsea schemes announced by Shell.'
Possible future workover systems which do not require expensive rigs will also further eliminate the advantage of TFL. In very deep waters (e.g., 1,000 m) TFL may again be an economical option.
Insert or modular replacement?
Subsea equipment (e.g., accumulators, chokes, gate valves, control pods) may fail, and replacement/repairs are normal operations in all subsea developments. For single-well systems, most critical equipment is part of the Christmas trees which are usually retrieved in case of malfunctions (exception is the control pod which may be retrieved separately). For multiwell systems, equipment retrieval will be utilized for future diver-assisted Shell developments, while a complex mechanical system was used in the UMC at Central Cormorant.
Most recent developments have, however, been designed for complete modular replacement, such as in NE Frigg, Tommeliten, and TOGI. This is also the basic idea in the BP's Disps project.10
Guideline installation?
Water depth is the main parameter in this question because the running and handling of guidewires becomes increasingly more complex and time-consuming with increasing water depths.
Petrobras says that guidelines will be used down to 600 m, while Saga has selected a guidelineless system for Snorre. This has mainly been done because of the hazard in lowering heavy equipment directly above subsea templates. The BP research project, Disps, has also selected a guidelineless system as target for its case study of 400 m.10
TOGI uses guidelines.
Multiphase transport or subsea separation?
Hydrocarbons can be transported in the production line to the processing facilities by:
- Utilizing the energy (i.e., pressure) available in the reservoir. In most cases this will mean some form of multiphase transport, gas, oil, water.
- Injecting energy into the well stream downhole by gas lift methods, at wellhead by multiphase pumping facilities, at wellhead by separation and pumping systems, at riser base by injection of gas or use of pumps.
Both multiphase pumping and subsea separation are still mainly in a prototype development stage, although a separation unit has been installed in the Hamilton Bros. Argyll field.
Multiphase pumping has attracted much interest lately with prototypes being built and tested out, such as Poseidon, (Total/Statoil),11 Smubs (Shell), S.B.S. project (Agip).13
Multiphase flow without separation and pumping has been used in the North Sea on, among others, Cod-Ekofisk, Highlander, and Tommeliten. It has also been designed for TOGI, which will be covered in the second part of this article. Except for TOGI the transport distances are fairly short.
Which conditions to monitor?
State regulations and operating requirements have to be considered in determining what conditions or functions to be monitored on a regular or irregular basis.
Possibilities are wellhead pressures, fluid temperature, valve status, hydrocarbon leakage, sand production, and chemical injection rate.
Wells with pure hydraulic control have very limited regular monitoring possibilities (only wellhead pressure by direct flow/pressure interpretations).
For most multiwell systems and when monitoring becomes important, electrical cable is used to transfer signals from the subsea installation to the mother platform. This is a fairly standard method for pressure and fluid temperature monitoring, less used for valve status, and only very recently being developed for gas leak and sand production monitoring (i.e., TOGI). These monitoring functions complicate the production control system considerably and may be cost-driving.
Sealine connectors?
There are several methods to connect production lines and service lines. Divers have to a large extent been employed in order to support the underwater connections (e.g., Tommeliten, Oseberg).
Large diameter production lines have mostly been connected by diver-assisted hyperbaric welding. One exception is TOGI. Here, direct underwater pull-in was utilized for the 20-in. gas line and will also be used for the service line bundle.
Use remotely operated vehicle (ROV)?
This is one of the most challenging future aspects because ROV's are increasingly being designed for extensive use in most new diverless subsea projects. Areas of utilization are, among others:
- Valve operations, direct and override
- Guideline establishment
- Replacement of equipment (sensors, chokes, valves)
- Installation of modules in guidelineless systems.
TOGI has designed special tools for extensive use of ROV'S.14 And there is in the industry a lot of attention and serious work directed towards extending the use of ROV's for diverless operations.15 10

REFERENCES

Overli, J.M., "Subsea Production, Past, Present and Future," Deep Offshore Technology Conference, 1989, Mirabella, Spain,
Sasanow, S., "Subsea Systems in the North Sea," Petroleum Management, May 1988, and "Subsea Special: Current Projects," Petroleum Review, October 1989.
Brand, R., "Experience from Operation, Maintenance and Repair of the Subsea Installation on the North East Frigg Field," NPF Conference 1987.
Vollaire, E.J., "East Frigg Operation, One Year After," Deep Offshore Technology Conference, 1989, Mirabella, Spain.
Indreberg, O., and Knudsen, T.W., "Gullfaks A Subsea Wells System Development, Completion and Production Start-up," Offshore Technology Conference Paper 5402, 1987.
Ferdinansen, J.R., and Solheim, A., "The Tommeliten A Subsea Development Project, Design, Development and Experience," Deep Offshore Technology Conference, 1989, Mirabella, Spain.
Skattum, K.S., "Troll Oseberg Gas Injection-A Status Report," Deep Offshore Technology Conference, 1989, Mirabella, Spain.
Overgaard, I., Allum, K., and Clusters, R., "Snorre: Third Generation Subsea Production Systems," Subsea '88 International Conference, London, December 1988.
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Rodda, N., "BP's DISPS Project Key Findings to Date," Deep Offshore Technology Conference, 1989, Mirabella, Spain.
de Donno, S., et al., "The S. B.S. Project-Development of a Subsea Booster System for the Exploration of Deep Water Oil Fields," Deep Offshore Technology Conference, 1989, Mirabella, Spain.
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Lafaille, A., and Cessou, M., "Poseidon: the Multiphase Pumping Production System, on the Way toward Industrial Applications," Deep Offshore Technology Conference, 1989, Mirabella, Spain.
Hovland, E., "TOGI ROY Interventions," Intervention 89, San Diego.
Scott, P., "Design of Subsea Trees to Permit Remote Interventions," Deep Offshore Technology Conference, 1989, Mirabella, Spain.