Tailoring drilling-production units for West Africa fields

The Multi Function Barge. Wake effect for drilling and production risers (Multi Function Barge) [32,826 bytes]. Internal view of the FPSO concrete hull with the membrane containment system. [22,977 bytes] Computer-generated view of the LNG FPSO offloading to an LNG tanker [28,566 bytes]. Following the giant strides in deepwater production in the US Gulf of Mexico, the industry is itching to get started on West Africa. Elf may already have lit the fuse by initiating development of Girassol off


Reservoir shape, spacing, stranded gas, wax impact production design

Jeremy Beckman
Editor, Europe
The Multi Function Barge.

Following the giant strides in deepwater production in the US Gulf of Mexico, the industry is itching to get started on West Africa. Elf may already have lit the fuse by initiating development of Girassol off Angola in up to 1,400 meters of water.

It may be a while, though, before Elf and other operators master the conditions. Spars and tension-leg platforms (TLP) suit the prevailing environment in the Gulf of Mexico. West Africa's deep offshore, however, may prove less straitjacketed in concept terms due to the shape and spacing of the reservoirs and the known tendency for unwanted by-products such as waxes and hydrates.

Various French engineering and construction consortia close to Elf have been working on a range of solutions which are more likely to be applied post-Girassol. The production systems range from mammoth integrated drilling and production semis to miniaturized TLPs. One group may also have found the answer to West Africa's stranded gas dilemma - an FPSO for liquified natural gas (LNG).

Deepwater DPSS

Doris' Engineering's latest idea is mindful of rising drilling costs in an era of falling oil prices. The drilling-production submerged storage floating unit (DPSS) is designed for mid to large-size fields from 200 million bbl upwards in water depths of 400 meters to 1,400 meters - the current bracket for the deepwater discoveries off Angola.

Like any conventional floating production unit, it is suited for pre-fabrication and towing to the production site, as well as relocation when the field expires. But the on-site installation technique is more flexible:

  • As is usually the case for deck mating of a GBS, the DPSS' topsides, mounted on a barge, can be floated over the columns' supports, the hull being submerged via controlled ballasting
  • Alternately, the topsides can be shipped over on a self-elevating deck barge to the mating site. Once there, the barge is floated over the pontoon slab between the columns. The hull is then submerged under a controlled ballast operation while the barge is guided up along the columns (Doris-patented technique). Once the topsides are locked in position, the hull is de-ballasted to its operating/transport draft.
Use of heavy transportation or lift equipment can thus be avoided, says Pierrick Sauvage, Doris' tender manager, business development. "In addition, the hull's overall size and multiple supports combine to provide a large working area, allowing the use of modular decks which can be installed in stages as field development progresses.

"Drilling and simplified production equipment can first be mounted for early phases. The DPSS can be used in lieu of semisubmersible drilling rigs, thereby optimizing initial expenditure significantly. Subsequently, the DPSS can either be relocated elsewhere for complementary drilling, or remain at its central location, fully equipped and installed, for final drilling and long-term production/development duty."

Another strong feature is its storage capacity - anything up to 2 million bbl is attainable from a highly productive field, according to Doris' president Dominique Michel. But that capability could also serve to allow longer periods between tanker offloading.

Storage is the main limitation of conventional semisubmersibles. In the DPSS' case, storage is situated in its submerged pontoons. This offers advantages over FPSOs, namely:

  • Reduced motions, especially in terms of heave - within acceptable operating limits. That in turn allows the use of surface wellheads with minimum equipment/maintenance.
  • Wave impact on the hull is minimized, permitting optimal use of materials for the hull area in the splash zone (and consequent cost reductions).
Storage tanks are designed according to the principle of water/oil displacement, the aim being to keep the tanks in equi-pressure with external seawater, to simplify hull design and to maintain a constant operating draft with minimum active ballast compensation.

Buoyancy and stability provided by the columns supporting the pontoons serve to:

  • Minimize wave and still water longitudinal bending moments, thereby optimizing the hull scantling
  • Support and elevate topsides equipment
  • Allow easy erection of the topsides on the hull at any time, even when the platform is on site.
The hull's predominantly rectangular shape is designed to suit Gulf of Guinea-type operating conditions. But the geometry can be varied according to storage or local environment needs. Mooring systems deployed on barges or semisubmersibles are also suitable for the DPSS. However, a taut leg system with synthetic ropes might be more practical for reducing maximum displacements. And costs overall would be lessened through minimized use of tensioning systems for surface wellhead drilling/completion equipment.

Steel or concrete are both viable options for the hull. Geometry can be tailored according to anticipated displacement characteristics and the yard's layout. According to Doris, most existing shipyards are more suited to the slender hull, light draft steel version, whereas drydocks might be more appropriate for deep draft, wider hulls in either steel or concrete.


Two years ago, Doris Engineering and Foramer unveiled at OTC their Mini-TLP concept for marginal deepwater fields. The centerpiece is a small, normally unmanned wellhead platform supporting dry trees and minimum topsides. On West African fields in waters up to 1,500 meters deep, this would be combined with a tender-assist rig for drilling and workover operations.

It was one of the concepts under review for the Moho Field nine miles offshore Congo. Elf then decided to appraise numerous other prospects in the Haute Mer licence, the results of which might invalidate the earlier development analysis.

However, the Mini-TLP remains in contention for the deep waters off Angola. Here, reservoir geometries are thinner and bigger, and therefore more suited to a combination of production facilities rather than a centralized FPSO with limited subsea well reach.

Clusters of up to 20 wells can be drilled from the Mini-TLP using the tender-assist barge. Foramer Pride has calculated drilling costs of just $40,000/day, roughly one-fifth of the rate for a semisubmersible drilling rig. Use of surface wellheads as part of the concept also limits the cost of workovers.

For drilling, the Mini-TLP supports a full-size derrick set with a surface BOP mounted on a high pressure drilling riser. When switching to completion mode, the BOP is removed. The riser remains suspended from the tensioners in the center of the well bay with its bottom end connected to the wellhead of the next well lined up for drilling.

The derrick set can then be skidded over the appropriate slot on the outside of the well bay to tieback the production riser and complete the well. Then the derrick is returned to the central position where the drilling riser is ready to begin drilling the next well.

Use of locked-off production risers (at the main deck surface entry point) without motion compensation is made possible by the Gulf of Guinea's mild environment, allied to the TLP's minimal motions.

Late last year, Doris undertook a study for a client in Brazil, but the reservoir in question turned out to need only six wells. This led Doris to propose a Micro-TLP, featuring three legs instead of the Mini-TLP's four, with two tethers per corner. This looked to be the only way of reducing the platform's cost. However, if this concept is to go forward, more work needs to be done to appraise and then solve potential problems relating to riser interaction and fatigue.

Wax and hydrates

Analysis of Moho's production needs identified concerns with wax and hydrate formation in flowlines brought on by the low seabed temperatures (around 4°C). This is an issue expected to impact many deepwater developments off West Africa.

Little confidence has been generated in the idea of 1,500-meter-long flexible risers bringing product from the wellhead to the floating production unit. One possibility is to tailor the riser to the field's pressure and insulation requirements. However, a riser tower might prove less risky.

This is the approach Doris, Stolt Comex Seaway, ETPM, and Bouygues Offshore are proposing, using bundles to insulate the risers. A confident ETPM is already setting aside a 1.5 km strip of land for a bundle construction site at its new yard in Lobito, Angola.

The riser tower works as follows: Steel pipe forms the core of the tower, itself wrapped with two half-shells made of syntactic foam. Four or five flowlines and other service lines are housed within the foam which provides high thermal insulation to stave off wax/hydrate formation. It also adds buoyancy to the pipe, thereby improving the tower's hydrodynamic behavior.

In case of prolonged shutdown of any well, some of the service lines can also be used to circulate hot water to recover ensuing hydrate blockages occurring in the flowlines.

The tower is assembled onshore through welding of the sections together, then towed out to the offshore location. There, it is up-ended and self-installs. Once in position, it is fixed to the seabed by means of a suction anchor. The interface between the anchor and tower is ensured either by standard TLP tendon connectors or drilling connectors.

At the tower's top end (around 50 meters below the surface), a buoyancy element in which all the risers and service lines are grouped together provides the tower with its necessary uplift, and also ensures its dynamic behavior. The risers are further connected to the FPU via a 150-meter-long flexible line. Installation of the tower demands use of anchor handling tugs, plus another vessel for the riser-FPU connection.

The riser tower is, in effect, a compliant tower with behavior comparable to a TLP. It can sway 40-50 meters or more yet still provide the FPU with a good safety margin. The system can also be designed for quick release of the FPU, simply by disconnecting the short flexible riser section. The tower itself can be dismantled easily and re-used elsewhere, as proven by Placid in the Gulf of Mexico.

As operator of the Grand Canyon Field development, Placid installed a riser tower in 600 meters of water. Production proved to be uneconomic, so the tower was taken down and brought back to the mainland, where it was lengthened by 300 meters prior to being re-installed on an Enserch Field in 900 meters of water. It is still in service there today.

Maintenance is said to be minimal, and the number of risers should not limit the effectiveness of insulation. But lines could be added to the riser tower as the field development evolves. Doris is considering basin trials this year to fully qualify the system. The tower can be installed prior to the arrival of the FPU on site, and would work with any supporting system, including Mini-TLPs.

Barge concept

Vertical riser bundles could also be applied to the Multi-Function Barge (MFB) as a means of tying back dispersed deepwater subsea wells in the Gulf of Guinea. The concept of the MFB, formulated by Bouygues Offshore, Sedco Forex and IFP, was outlined in the May 1997 edition of Offshore (page 72). Certain changes have been implemented since, included in a paper at this year's OTC.

Like the DPSS, the concrete-hulled MFB combines the capabilities of an FPSO with the ability to drill and complete development wells, and it can also handle workovers. But it is targeted at compact, prolific reservoirs rather than elongated reservoirs. The aim is to achieve more economic centralization of wells at a single location. Use of surface tree and rigid risers eases intervention, further limiting capex and opex over the field's life.

There has been criticism that the MFB might be too restricted in its configuration, hence the incorporation of the riser tower into the equation. If there are additional accumulations beyond the reach of vertical or directional wells, they could be tied back as subsea satellites via flowlines. These would be connected to a seabed template positioned close to the MFB, then grouped together in a vertical steel riser bundle originating from the barge's moonpool.

The bundle could contain gas lift and hot water heating lines, in addition to production lines. From the moonpool, it would descend in parallel with other single production risers, while at its upper end, it would link into the MFB via jumper-type flexibles connected at the top end of a vertical carrier pipe, the latter tensioned by sub-surface buoyancy aids.

The MFB's well bay houses 20 risers in two longitudinal rows, with fluid transfer from the production risers being effected via jumper hoses between the surface trees and the barge. The drilling rig can move back and forth across the skid base to perform drilling, tie-back, completion or workover at any designated slot.

Hydro-pneumatic tensioners were chosen early on to handle anticipated riser stroke extremes (up to 15 meters), but the designers have since developed an alternate, totally passive system based on the use of individual buoyancy cans. The key challenges here were to limit exposure of the buoyancy units to wave and current action, and to avoid clashing of the drilling and production risers during simultaneous drilling and production operations.

For analysis of the risers under varying environmental loads, IFP's Deeplines software was used. This is a large displacement, finite element and time domain program. The team analyzed factors such as riser top and bottom tensions, top angular movements, von Mises stresses, maximum relative motions between risers and hull, as well as the possible interaction between adjacent drilling and production risers.

Among the findings, the riser top is under maximum bending stress in no offset or negative offset position, whereas the bottom end is at its maximum stress for the maximum offset. Also, angles of production risers in relation to the barge's vertical axis remain small, even in 100-year wave conditions, varying from -5.5 to +3.8°C. The results were used to optimize riser design in terms of spacing and structural strength.

The MFB is aimed currently at mild conditions in water depth limits of around 2,000 meters, but it could be adapted to 3,000 meters as new technologies continue to emerge, such as the use of synthetic ropes and other materials for taut leg spread moorings. BP, Elf, Shell and Statoil have participated in the development to date and another major may come onboard shortly.


Finally, Bouygues Offshore has developed another FPSO concept, applicable for instance in the Gulf of Guinea where it would be dedicated to LNG. Onboard liquefaction followed by offloading to LNG carriers may prove the most practical solution yet to extracting West Africa's stranded or associated offshore gas.

The concept was described at DOT '97 in The Hague. Also, the unit can be adapted for more rigorous environments such as South East Asia, and that was the setting adopted by Bouygues Offshore and SN Technigaz in their joint paper, for an FPSO with liquefaction capacity of 1.5 million tons/yr and storage capacity of 140,000 cu meters. However, a 100% increase in both cases is also feasible.

Currently, a portion of associated gas is produced and stored as LPG on the N'kossa production barge off Congo and the Escravos FSO off Nigeria, as well as by another concrete FSO in Ardjuna, South East Asia. LNG transactions, however, have been restricted hitherto to shore-based terminals interacting with LNG carriers. SN Technigaz has designed several technical facilities since 1967. The firm's membrane technology is incorporated in the LNG FPSO's containment system.

The LNG FPSO as outlined at DOT'97 is 286 meters long, 51.5 meters broad, and 29 meters deep, with a 292,000 ton (laden) displacement. This is a concrete-hulled barge structure similar in build to an LNG tanker, with cargo storage protected by double sides, a double bottom, and a double deck. The vessel, designed for a 50-year service life, would receive and process high pressure gas from subsea wells or a wellhead platform, depending on water depth. Resultant processed LNG, LPG and condensates would be stored until offloading occurs - LPG and condensates would be offloaded using low pressure hoses designed for tandem tanker offtake.

For LNG offloading, a side-by-side cargo transfer system is feasible in mild operating environments, using three 16-in. diameter loading arms to provide an offtake flow rate of 10,000 cu meters/hr. The FPSO is moored on an external turret.

Total liquefied gas storage capacity in the South East Asia version is 167,500 cu meters through five LNG and two LPG cargo tanks, all housed in the hull along with a 32,000 bbl condensate tank. Maximum pitch and roll motions in this environment are forecast to be less than 2° for more than 98% of the time. According to Bouygues Offshore, the concrete hull design offers good motion behavior for cargo loading even in extreme conditions, due to its intrinsically high mass and the low density of LNG.

Stability appears to hold up even when the hull is damaged, due to its overall dimensions and low center of gravity. However, the combination of a floating support, the confined storage and liquefaction space plus the need to offload periodically to large LNG tankers alongside does introduce potential hazards.

With safety being a key issue for this concept's viability, a risk analysis was recently mounted, in cooperation with Gaz de France, to determine safe design and operational criteria. Identification of possible hazards was computed using formal and systematic methods, taking into account the layout of equipment, environmental and operational data.

Once the critical items were identified, the impact of heat radiation and over-pressures on the FPSO's various sub-systems were modeled. For some especially critical hazards, computational fluid dynamics codes were used to predict the consequences. For those consequences that might impair safety unacceptably, recommendations have since been made in order to eliminate or lessen the source/consequences of the hazard. These are design (layout, equipment, sizing, extra protection measures) or operations related.

However, the study also highlights that inherent properties of concrete (good cryogenic behavior, better fire resistance compared to steel structures, stiffness) will help the hull maintain its integrity following an LNG spill on deck, pool fires, over-pressure caused by gas cloud ignition, supply boat collisions and so on. This limits the need for further safety measures which would be mandatory with a steel hull.

Bouygues Offshore/SN Technigaz concluded that there were no unacceptable risks to their concept.

Copyright 1998 Oil & Gas Journal. All Rights Reserved.

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