New designs advance spar technology into deeper water

L.C. Skaug
Spars International Inc.
Houston

• Platform Options [134,802 bytes]

ABOUT THIS REPORT
Operators and service companies are rising to meet the challenge of deepwater development. In some cases, current technologies-including spar configurations and pipeline-end manifolds-are readily adaptable. In other cases, entirely new technologies, such as concentric risers, are needed to overcome operational difficulties. This report provides details on the current status of the deepwater offshore industry as it moves towards developing hydrocarbon resources in excess of 5,000 ft.

The vast hydrocarbon reserves found in deepwater have increased the oil industry's interest in the spar platform and led to a vigorous development of spar technology, particularly as applied to ultradeepwater.

Recent design studies conducted by Spars International Inc. (SII) and Deep Oil Technology Inc. (DOT) indicate that because of its inherent characteristics, the spar configuration is economically competitive in water depths of 10,000 ft or more without significant modifications.

Current advances in spar technology include a spar designed specifically for drilling in waters over 8,000 ft and a split-tree production riser system for spars in ultradeepwater.

Deepwater

Finding economic ways to access deepwater oil deposits has been one challenge driving technological innovation in the oil and gas industry in recent years. Among the chief factors contributing to this increase in global deepwater activity are the depletion of shallow reserves, greater potential for large finds in deepwater, future growth in hydrocarbon demand, and favorable fiscal policies of host governments towards deepwater development.

Of the 66 significant discoveries (greater than 100 million bbl) worldwide between 1996 and 1998, 49 were offshore.

It is believed that 90% of the world's undiscovered hydrocarbon reserves offshore are in water deeper than 3,000 ft.

While the deepwater prospects abound, so do the challenges oil companies face developing these fields. As water depth increases so does the investment and, even under optimal sea conditions, water depth significantly influences the cost and risk associated with some drilling and production systems.

Increased water depth may intensify the damage potential of rough sea conditions upon risers, moorings, and seafloor support structures. In severe storm conditions, potential damage due to FPSO (floating production, storage, and offloading) vessel motion, for example, can limit the economic feasibility of developing deepwater fields in certain waters.

When the distance from the seafloor to surface begins to approach 2 miles, many development options such as TLPs (tension leg platforms) may become impractical because of the forces on structures that span such distances and by the sheer quantity of material required.

Spar history

Spar technology has been used in offshore environments for over 30 years in such applications as a research vessel, a large communication relay station, and storage and offloading buoys.

In 1987, Edward E. Horton patented a special form of spar technology for deepwater drilling and production platforms. This patent describes a vessel with a circular cross-section that sits vertically in the water and is supported by buoyancy chambers ("hard tanks") at the top and stabilized by a structure ("midsection") hanging from the hard tanks.

If necessary, stability may be supplemented by solid ballast placed in compartments at the keel. The vessel is held in place by a taut catenary mooring system, providing lateral station keeping.

In 1984, Horton founded Deep Oil Technology Inc. (DOT) to develop spar and other deepwater drilling and production technology. DOT has since been combined with the joint venture company, Spars International Inc. (owned by Aker Maritime and J. Ray McDermott).

In 1996, the first spar, Oryx Energy Co.'s operated Neptune workover and production platform, was installed in 1,930 ft of water in the Gulf of Mexico. The 1998 installation of Chevron U.S.A. Production Co.-operated "Genesis" drilling and production spar in 2,590 ft of water and Exxon Corp.'s selection of a "deep-draft caisson vessel" for its Hoover/Diana project in 4,800 ft of water demonstrate the extension of the spar concept to progressively deeper waters.

Neptune, Genesis, and Diana are all of the original "classic" hull design (Fig. 2 [169,593 bytes]). This full cylinder form can be used for drilling, production and, with suitable design modifications, oil storage.

On Sept. 1, 1998, the detailed engineering phase was begun for a newer design, the "truss" spar (Fig. 2), to be used in 5,550 ft of water (see box).

When the storage capabilities of the classic spar are not required, the truss spar provides a lighter and, therefore, more cost-effective alternative that still exhibits the same motion characteristics of the original spar.

Expanding versatility

Although all the spars presently in place or under construction are in the Gulf of Mexico, the interest in this technology has led to studies for adapting the spar concept to a wide range of deepwater locations and oceanographic conditions.

Over the last few years, Amoco Corp., British Petroleum Co. plc, Texaco Inc., and other major oil companies have commissioned studies of spar designs for areas such as West of Shetland, Norwegian North Sea, and offshore Angola, and Brazil. These studies indicate that the spar concept can be adapted well to different environments.

Oil company interest in the spar derives primarily from the intrinsic properties of the design that make it well suited to deepwater. Some of the key advantages of spar technology are as follows:

• Stability and low motions (Table 1 [90,591 bytes])
• Protected center well
• Active mooring system
• Ability to accommodate surface ("dry") trees.

Another feature that many find attractive is the inherent versatility of the spar design. Using the basic ideas for the spar hull, mooring system, topsides, production risers, and export risers, a spar platform can be configured in various ways from production only to any combination of production, workover, drilling, and, in the case of the classic spar, storage.

Furthermore, because the installation process is reversible and only a few of the spar's systems are affected by differences in water depth, relocating a spar platform is economically feasible. Relocation is an important consideration when the spar is configured as a drilling rig in the exploration stage of field development, and can be advantageous when working in areas of political unrest.

The ability to relocate and reuse the spar makes it an attractive option for developing marginal fields.

One recent development is a spar designed for drilling in water depths up to 8,000 ft (or up to 10,000 ft with minor upgrades). While designed primarily for delineation and development wells, the deepwater drilling spar is a highly versatile vessel that can also drill exploration wells. It also has provisions for adding limited production facilities-features that are particularly important in deepwater where cost is high.

When used for production, the drilling spar can substantially reduce the financial risk of field development. For example, the drilling spar can be used to begin production before committing to full field development, or the modular drilling rig can be removed to convert the vessel to production operations with workover capability.

Thus, if drilling is successful, it is possible to begin production immediately and continue production until the required number of wells are completed or, if extremely large reserves are discovered, until the drilling spar is replaced by a production spar, or some other production vessel.

Water depth considerations

A major aspect of the flexibility of the spar concept is that the basic configuration changes little as water depth increases. In many circumstances, the same spar can be used in a wide range of water depths, anywhere from 1,500 to 10,000 ft.

With the exception of the well systems (subsea wellheads, riser assemblies, buoyancy modules, and trees), only the mooring lines change as the water depth increases. Increased mooring line length has only a minor effect upon payload capacity.

The spar's hull dimensions, topsides, and motions are not directly affected by water depth.

Motion

The motion and the stability of a spar are largely unaffected by water depth.

The spar derives its stability from its long cylindrical shape, from its mooring system, and from the fact that its center of buoyancy is always above its center of gravity. Vertical motion (heave) is small because the keel is well below the wave-affected zone and the spar's natural period in heave is beyond the range of wave energy.

Angular motion (pitch) is governed by wave forces and by the relationship of the spar's center of buoyancy to the center of gravity. Because its center of buoyancy is above the center of gravity, the spar is inherently stable and will maintain an upright position even if allowed to float free without mooring lines.

Lateral motion (surge) is governed by the configuration of the taut catenary mooring system.

The limited motion of the spar leads to a number of practical advantages for both drilling and production in ultra-deepwater.

Because of the spar's low heave response to waves, production risers can extend vertically from the seafloor to trees at the surface. The spar's surface ("dry") trees are more reliable and less costly as compared to the subsurface trees that must be used with FPSOs and semisubmersibles, because of the relatively high motions of these vessels.

When the water depth exceeds the practical limits of a TLP, which can also accommodate dry trees, the spar platform becomes the only proven vessel with this capability.

Hull size

The same hull size can be used in varying water depths. As water depth increases, however, other factors come into play that can affect the hull dimensions. In this regard, the most important factor is payload.

As water depth increases, larger reserves and higher production rates are required to provide an economic return on the investment for drilling, production equipment, and pipelines. These requirements translate into a need for topsides of greater area and weight than might be expected in shallower water.

When the payload demands increase, either the depth of the hard tanks or the hull diameter, or both, may be increased at the design phase to sustain the payload. There is no theoretical limit to the payload weight that can be supported by a spar hull. The only limitations are the capabilities of fabrication yards to build very large hulls and the ability of transport companies to haul the large hull to the field.

Spars with hull diameters up to 150 ft with corresponding topsides payloads of 40,000 tons have been designed. These designs can be constructed without significantly changing the methods previously used to construct smaller spar hulls.

Hulls with dimensions much greater than 150 ft are routinely encountered in shipyard tanker construction; therefore, there are no apparent reasons why even larger hulls could not be built.

Mooring systems

Increased mooring system weight as water depth increases is not a significant factor in design of a spar. Because vertical loads from the mooring systems are relatively small compared to the overall loads on the spar, typically less than 5% of the displacement, even a doubling of water depth causes only a minor increase in hull loads.

The largest challenge in very deep water is to maintain a suitably stiff mooring system that will limit maximum offsets to 8% of water depth, or less, as typically required by top-tensioned riser systems.

The weight of steel mooring lines makes them less efficient in ultra-deepwater, although polyester and other synthetic materials appear to be an attractive solution to this problem.

Risers

Because spar motions are generally independent of water depth, with relatively minor adaptations, the same riser system concepts (whether for drilling or production) suitable for shallow water are also suitable for ultra-deepwater.

The risers are installed through the center well of the spar hull, which protects them from wave and current forces. Because of the spar's protected center well, buoyancy modules can support the riser weight (Fig. 2).

Buoyancy modules are one of the most important and unique features of spar technology. They can significantly increase capacity and reduce risk and cost, particularly in very deep water where riser weight and length present many challenges.

Installed concentrically around the outer riser string, these buoyancy modules provide constant tension and effectively isolate the risers from the effects of heave motions, even in 100-year storm events. This is especially advantageous for drilling risers because they can then remain connected during large storm events, even in the deepest water.

Buoyancy modules also contribute to the overall flexibility of the spar concept. As the riser weight increases with water depth, more buoyancy modules can be added to accommodate the increased load.

The shape of the spar hull and the taut mooring system keep the spar motions low enough that flex joints are not needed in the riser string. Even the combined effects of lateral offset (surge) and heel angle (pitch) of the spar during extreme weather conditions do not overstress the riser.

A strengthened riser joint or restraining sleeve is installed at the keel to limit the bending stresses at that point. Similarly, a strengthened joint, a "stress joint," is installed in the riser string at the seafloor connection to the subsea wellhead to resist the bending forces encountered there.

A cost-effective steel stress joint can accommodate these forces as long as maximum spar offsets are less than about 8% of water depth.

Drilling risers

The low motions of the spar in extreme environmental conditions permit drilling risers with surface BOP stacks. This is analogous to the surface trees with production risers in that well control safety devices are "dry" and may be operated and maintained without the need for underwater control systems, divers or remote-operated vehicles (ROVs).

The drilling riser assembly consists of an inner high-pressure riser and an outer low-pressure riser. The outer riser includes reinforced joints where it passes through the spar keel and at the subsea wellhead. This design absorbs the bending loads induced at those locations.

The drilling riser assembly may be supported by buoyancy modules at the top of the riser or by hydraulic tensioners. While drilling the upper portions of the well, only the outer low-pressure riser is used. This outer riser (typically 21-in. diameter) must be designed to withstand the pressures that might be encountered at surface or intermediate casing depths as well as the mud weight overpressure at the seafloor.

Once the top portion of a well has been drilled and surface casing strings cemented in place, the inner high-pressure drilling riser is run inside the outer riser for drilling the remainder of the well. The inner riser is designed to withstand the maximum pressures anticipated in the well.

Buoyancy modules can be installed as an alternative, or supplement, to tensioners for supporting the riser. This has various advantages for drilling.

The spar's use of a surface BOP allows the use of bare steel, high-pressure drilling risers. These are smaller in diameter than risers with syntactic foam buoyancy and do not require mud boost lines and kill and choke lines to a subsurface BOP stack.

The bare riser presents a much smaller profile to ocean currents and hangs nearly vertical, even in the very high subsurface currents often encountered in deepwater. The reduced current loading and improved verticality reduces run-in times as well as drilling downtime.

As water depth increases beyond about 6,000 ft, however, the riser assembly weight may cause the tension in the upper portion of the riser to become so high that the riser could be overstressed.

Derrick and drawworks capacity also limit the maximum riser weight that can be lowered. Under these conditions, the outer riser design would include syntactic foam to reduce the riser assembly weight in water.

Syntactic foam and hydraulic tensioners are routinely used with deepwater exploration drilling rigs and present no technological challenges not already encountered.

Production risers

Production risers join the seafloor wellhead to the surface tree. A flexible flow line connects the surface tree to the deck-mounted production manifold. The casing string outside the tubing is normally designed to withstand the well's shut-in tubing pressure.

Because the production tree is at surface, it is accessible for all normal operating activities, just as on a fixed platform. Instrumentation, shut-in valves, manual valves, and chokes are the same as those routinely used in the oil industry.

Well maintenance activities such as wire line work and coiled tubing operations are also the same as for wells on a fixed platform.

Several different configurations of the production riser string may incorporate the operator's preferences, the characteristics of the well, or the requirements of regulatory authorities.

Fig. 3 [74,327 bytes] illustrates several production riser systems.

• Single-casing riser-A single-casing riser assembly consists of a production tubing string installed inside a casing string. The casing string is suitably reinforced at the spar keel and at the seafloor wellhead to resist bending forces.

For an oil well, the annular space may be utilized for gas-lift gas. Alternatively, a packer may be located below the subsea wellhead, in which case lift gas could be carried to the seafloor via a separate lift-gas tubing string installed in the annulus between the production tubing and the casing.

• Dual-casing Riser-A dual-casing riser assembly is essentially the same as a single-casing riser with the addition of an outer casing string. The outer casing string provides added mechanical strength to support the tubing and inner casing string. It also resists bending loads induced by the environment and may also serve as a secondary barrier against the accidental release of hydrocarbons. It provides a mechanism for reducing heat losses in the well stream if an insulating fluid fills the annulus.

• Tubing Riser-The tubing riser concept is analogous to a flow line from a remote subsea well in that shut-in capability is at the subsea wellhead and only a single pipe carries the well stream fluids to the vessel.

For the tubing riser, a control umbilical is strapped to the production tubing and gas-lift gas, if required, is carried to the subsea wellhead by an additional line, also strapped to the production tubing.

One or more subsea valves can be provided at the wellhead for shutting in the well in the event of an incident requiring seafloor isolation.

• Split-tree riser-The split-tree riser is an adaptation of current riser technology that taps some of the best features of existing riser systems at a reduced cost without compromising system integrity. This configuration retains the benefits of dry surface trees while providing seafloor shut-off along with a dual barrier. But it still has top tension requirements that are about 25% of current dual-casing designs.

The split-tree riser configuration incorporates a single-valve tree at the seafloor, thus providing a subsea shutoff capability. In other respects, it is similar to the single-casing riser in that the production tubing is installed inside of an outer casing. The annulus space however, carries a control umbilical for operating the subsea tree valve, the Scssv (surface-controlled subsurface safety valve), and an annulus valve, as well as lines for chemical injection fluids.

The outer casing protects the tubing and umbilical during installation and operation and is designed for structural loads and for gas lift pressures if annular gas lift is planned.

Monitoring of annulus pressure aids in early detection of production tubing leaks that may then be isolated by closing the seafloor tree valve. The split-tree riser, with its seafloor shutoff capability, provides protection against the accidental release of hydrocarbons comparable to the dual-casing riser in very deep water but at a much lower cost.

As spars are installed in deeper water, the production riser weight increases proportionally. Because the risers are top-tensioned, supported by buoyancy modules at the surface, the upper portion of the risers must carry ever-greater loads. This requires higher-strength materials or greater wall thickness and higher weights. The impact is greatest for the dual-casing riser systems.

An increase in riser weight requires that the buoyancy modules be increased either in length or diameter to provide the necessary buoyant support. Increasing the diameter of the buoyancy modules may also require enlarging the spar center well, thereby reducing the buoyant volume of the hull and necessitating a larger hull diameter to compensate.

Lighter weight riser systems such as the split-tree riser however, permit the extension to deeper water without significant changes in the spar hull size or cost.

The Author