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Marine Systems (Floating Production Storage Offtake - FPSOs) - Nov 1999
Marine

Marine Systems - the FPSO (FSO and Others)

FPSO (Floating Production Storage Offtake)

From this relatively humble beginning, the FPSO has evolved and progressed to where it now dominates the floating
production systems (FPS) landscape. Today, there are 66 FPSOs in service or under construction in almost every
major geographical oil producing region in the world, accounting for about 60% of the existing FPS fleet.

The evolution of the FPSO from 1977 to the present can be viewed in three waves:

•From 1977 to 1985 - the early years in which the FPSO was establishing and proving itself as a viable FPS option.

•From 1986 to 1994 - marked an era of rapid technological evolution and an expansion into a wider geographical
arena, larger production rates and deeper waters. A total of 20 FPSOs were deployed in this period, or an average of
about 2 per year.

•From 1995 to the present - witnessed explosive growth in the number of FPSOs deployed. In these four years,
about 44 FPSOs have been installed in every major offshore producing region of the world, except for the US Gulf of
Mexico, at an average rate of 8 per year. The UK sector was the most prolific with 12, including two in the very
hostile West of Shetlands region, followed by Brazil with 9.

Present fleet

A survey of the FPSO fleet conducted recently (see pullout poster following this article) divides the fleet into units
operating, laid-up, in the construction phase, or recently decommissioned. It does not include FPSOs that were
decommissioned prior to 1999.

There are a total of 71 FPSOs in the survey, of which 4 are idle and 1 (Tazerka) is listed as decommissioned. Ten of
the 71 are in construction with projected completion dates scheduled for 1999 and early 2000.

Areas with the highest concentration of FPSOs are the North Sea, South East Asia, and West Africa. The remainder of
the FPSO fleet is located off Brazil, in the South China Sea, Australia, and the Mediterranean Sea. The first FPSO in
Canadian waters (Terra Nova) is presently under construction and is scheduled to come onstream later this year.

Storage

The maximum storage capacity of the existing fleet ranges from 47,000 bbl (Crystal Sea) to 2,000,000 bbl
(Petrobras-P31, P32, P33 and P35). The storage capacity of an FPSO is partially a function of its production rate. It is
logical to infer that the trend toward large production rates over the last four years should lead to a corresponding
increase in FPSO size.

The largest storage capacities reported were for FPSOs installed within the last two years. As mentioned previously,
Petrobras' vessels in Brazil all have a storage capacity of 2,000,000 bbl, while the FPSO Girassol and the FPSO VI,
both currently under construction, have storage capacities of 1,981,000 and 1,750,000 bbl, respectively.

Production rate

The maximum production rate ranges from 11,000 b/d of oil (San Jacinto) to 220,000 b/d (Norne). The average
maximum production rate of the FPSOs prior to 1994 was 60,000 b/d of oil.

Since 1994, several FPSOs have achieved or exceeded maximum production rates of 200,000 b/d. The Norne FPSO
has achieved this status, while the Girassol now under construction, and Åsgard A both are designed to have a
maximum production rate of 200,000 b/d.

Water depth moored

The current fleet of FPSOs is moored in water depths ranging from 20 meters (Chang Qing Hao) to 1,853 meters
(Seillean). Fifty of the active FPSOs are in water depths less than 300 meters. The trend shows that the operating
water depth for active FPSOs was relatively constant at less than 200 meters until 1995.

Since 1995, there has been a dramatic increase in operating water depth. The FPSO Firenze was installed in 1995 at
a water depth of 850 meters. The FPSO Seillean established the highest operating water depth of 1,853 meters early
this year in the Roncador field offshore Brazil.

The oldest FPSO in the survey is the P34 (ex-P.P. Moraes) which has been in service for 20 years. If we exclude the
10 vessels under construction, the average age of the active FPSO fleet is 6 years.

Market prospects

The effect of the recent drop in the oil price has been more in the delaying rather than canceling of FPSO projects.
Some of the delays are also attributable to the complexities of the field developments and negotiations with foreign
partners.

There are many sources of FPSO projects planned or under study. While the number of estimated projects vary
widely, a good range is somewhere between 75 and 120.

Preliminary design activity in shipyards confirms this. The bulk of the inquiries are for hulls with capacities of 1.5-2.0
million bbl. Indications are that a substantial number of these may be sanctioned in the 1st or 2nd quarter of 2000.

A majority of the FPSOs is moving toward newbuilds. These newbuilds can largely be attributed to the major oil
companies getting into the FPSO market producing larger fields, which permit larger capital expenditures and require
longer service life.

The concern of an oil spill is driving companies to choose double hull or double sides over a single hull configuration.
The increasing number of newbuilds can also be attributed to the limited availability of existing double-hulled tankers.

Geographic distribution

The areas that show the most activity are West Africa and Brazil, with a combined 62.5% of likely projects. West
Africa accounts for 37.5% while Brazil accounts for 25%.

In general, FPSOs in the UK and Norwegian sectors and for large deepwater developments in West Africa will be
purpose-built. Early production FPSOs will be used in some cases to accelerate production and cash flow while
permitting better understanding of reservoir and choice of field development solutions.

Future prospects

Looking at the 5-10 year horizon, and assuming that oil prices remain in the $15-20/bbl range, FPSOs will continue to
hold market share since future, large developments will be either in remote or in deepwater areas or both. This
position will be secured as subsea and flow assurance technology inexorably marches onward while well intervention
frequency (a major hurdle for deepwater subsea developments) is reduced.

Tanker-based platforms will also be used for production-only oil or gas developments, as they may offer the lowest
capital cost platform option.

Technology trends

On the technology development front, the industry is working cooperatively on issues related to FPSO hull structural
strength and fatigue integrity, improved predictions of platform mooring and riser system response and loads.

Considerable effort is being focused on developing steel catenary and wave riser designs for FPSOs, including use of
titanium joints and prediction/mitigation of vortex induced vibration that could rapidly fail a riser in fatigue.

More emphasis is being placed on life cycle risk models that progress from design to planned maintenance and
inspection programs that will improve overall safety while reducing operating costs.

The industry continues to offer variations of FPSOs that increase functionality and overcome present barriers. The
biggest barrier is the ability to drill and/or workover wells. Emerging concepts that permit drilling on a turret moored
FPSO have been around for several years.

In West Africa, with its mild directional seas and winds that permit spread mooring, adding drilling capability to an
FPSO is readily achievable. Taking advantage of the low wave motions, FPSOs with drilling and surface trees are now
on the boards and appear very promising.

It is not inconceivable that as confidence in the reliability of dynamic positioning systems increases, that fully
dynamically-positioned FPSOs will eventually become available, resulting in major cost savings in ultra-deepwater
developments.

The future of FPSOs looks very promising. The recent oil price slump has delayed but not significantly slowed the
pace of FPSO-based developments. Its inherent versatility, advancing technologies, and improved project execution
will ensure that FPSOs will continue to be in demand in existing offshore arenas as well as new frontiers around the
world.

Ironically, this versatility may also be the biggest threat to its future growth, as existing FPSOs coming off contracts
will be available to compete for new field developments.

Pro and con of adding production to drillships  

Efficiency has long been the primary focus of the offshore industry. From the service side all the way to the
operator, the upstream industry has been in a continuous push for new ways of improving operating techniques and
exploit oil at the cheapest possible cost. One such avenue used to increase efficiency is to increase flexibility in
terms of equipment. Equipment that can provide multiple services, while in the short term adding significantly to
costs, could lower costs by increasing efficiency over the long term.

One such technique that has fast gained popularity in the past few years has been the idea of adding crude oil
storage and production capabilities to the fleet of newbuild drillships. Currently, twelve of the fourteen newbuild
deepwater drillships are being or have been built with crude oil storage capability. This addition has further extended
the capabilities of these new multi-million dollar vessels and has the potential of pushing the vessels into a new
operating realm.

During the last building cycle, drilling rig contractors were looking for ways to offer the operator the most equipment
for their money when they began bidding their rigs. This resulted in new drilling techniques such as the dual handling
and dual derrick. Another aspect arising out of this cycle was the addition of crude oil storage capabilities, to make
the vessel easily convertible for production activities. In doing so, contractors added crude oil storage tanks to hold
80,000-150,000 bbl to the vessel designs. Even so, the vessels are not being outfitted for actual production. The rigs
have the spaces built in for crude oil storage, but the equipment to handle the production has not been outfitted.

This, along with new drilling techniques and state-of-the-art equipment on these new rigs, offered the operator
almost the complete scenario for deepwater operations. In essence, the rig could drill and test in water depths up to
10,000 ft efficiently, in addition to actually producing, storing, and moving the oil to market.

Design theory

To add storage and production capability to a drilling vessel, major design factors have to be considered. The main
factor is the size of the vessel. The crude oil will be stored in the hull, and as a result the design had to be adapted.

The first alteration was the addition of a double hull. A double hull, while not required for a drillship, is required for
tankers in trade due to the OPA 90 legislation upheld by the Coast Guard in US waters and the International Maritime
Organization in international waters. As a result, in attempting to comply with future regulations if the vessels do
begin storing crude, most are being fabricated with double hulls, or being converted from tankers where double hulls
existed or have been added.

In addition to the double hull, the overall size of the vessel has to be increased for the addition of production
equipment. The reason is that equipment such as the tanks will be stored inside the hull and regulations require that
all crude oil piping be installed above the deck. This results in the movement of equipment normally stored in the
hull of a drillship to the topsides, resulting in a necessary increase in the deck space.

This also requires the implementation of safety features such as safe cabling, adding manways, slop tanks, transfer
equipment, and other additions. In effect, vessel safety is boosted to accommodate the increase in hazardous
conditions.

These factors result in a much larger vessel, but the addition requires additional generating capacity, thruster
capacity, and other items related to vessel size. In turn, construction costs increase, which some users feel cannot
be justified.

Cost impacts

There are differing opinions on the costs of adding crude oil storage and production capabilities to drillships. The
costs are definitely higher than a conventional drillship, due to the increased steel and equipment.

One example to illustrate this difference is in two of Gusto Engineering's drillship designs. The Gusto 10000 was used
as the design for the Pride Africa and Pride Angola drillships, and does not feature crude oil storage. The Gusto
P10000 design, almost identical to the 10000, has storage capabilities. The Glomar C.R. Luigs and Glomar Jack Ryan
vessels are very similar to the latter.

Bob Rietveldt, Marketing Manager of Exploration Vessels for Gusto said the P10000 design is closer to the Discoverer
Enterprise and the Deepwater Pathfinder because of the capability for crude oil storage. "This just makes the vessel
longer and bigger and lifts everything to the topsides on a modular basis. You basically end up with a virtually empty
hull."

"Compared to the drilling-only 10000 design, the enhanced capability design costs about $100 million more. The
increase is driven by an enormous increase in vessel size, in generating and thruster capacity, and also in steel
costs. When you examine it from an economic viewpoint, the enhancement is not easy to justify when it is not being
used."

Luxury or need?

The drilling units being built today for the addition of production do not have production equipment aboard. When
drilling contractors were receiving bids for the new drilling units, the idea of having crude oil storage was a key
selling point. But when construction began and the market turned around, the storage option became less important.
It became a luxury for operators and the installation of production equipment was never carried out.

Rietveldt explained: "Crude oil storage capability was what drilling contractors were asking for in those days. Most of
the oil companies would say today they don't need crude oil storage. Many ships are being outfitted empty with void
spaces instead of cargo tanks, piping, and processing."

With the crude oil prices on the rise again, the demand for this luxury good could return and the contractors with
enhanced drilling vessels will be ready. The vessels would need only minor upgrading and the addition of production
handling equipment. These costs should be minor.

Chuck Steube, Director of Production Operations for Conoco Shipping said, "If you have storage built into a vessel, it
is not that complicated an issue. All you need to do is rent a processing facility and place it on the deck. The oil
storage is ready. It is basically just the day rate cost of the facilities, plus transportation, to get them out there."

Mark Dreith, Global Marine's Senior Manager of Marine Projects and the Project Manager for Hull 456, said, "The 456
was designed originally with production facilities for extended well testing (EWT) in mind. We have the capability of
adding this production facility. The upgrade cost would be about $10 million. Certain items have to be added and we
can do most of the upgrading offshore. For final hull penetrations and tie-ins, we would have to stop operating for
about 30 days."

Usage time

The amount of time the production and storage capabilities would be used is also a major cost justification issue.
Without the storage tanks, the vessel is basically outfitted with an empty hull, which means a lot of wasted space.
Olivier de Bonnafos in Pride International's Department of Offshore Engineering said, "Oil storage is a high cost. With
production capacity, oil will be on board 2% of the time; 98% of the time, that storage is wasted space."

Dreith adds, "It sounded like everybody wanted crude oil storage when we started designing this drillship. Is it worth
$10 million to have that capability? How much is it going to be used? If for your financial model you assume a 30-
year life for such a vessel, and you only use the additional capability for a net 30 days, can you justify it?"

Location

Another key factor in the debate over adding crude oil storage and production to drillships is the location in which the
vessel will primarily operate. While one of the key advantages of a drillship is the ability to move from location to
location, the rig will primarily be used in one theater. One theater - the Gulf of Mexico - has not accepted the
principle of storing crude on a ship-shape vessel.

It is conceivable that these vessels could be used to obtain approval of placement of floating production, storage,
and offloading (FPSO) vessels in the Gulf of Mexico. The production capabilities and the mobility of both FPSOs and
drillships with production capability are closely comparable. However, this event is considered unlikely, but it brings
up the major misconception that many have in dealing with production on drilling vessels.

Maximum EWT

Crude oil production capabilities on drilling vessels are not designed to mimic the capabilities of an FPSO. The main
purpose of the crude oil storage and production capabilities is for EWT. To help reduce the overall well and
development costs, especially in the deepwater where costs are high, EWT offers time to gather production and
pressure data and help define reservoir parameters.

Steube explained: "Development costs are so extensive that, once you drill your well, you would like to have a
better feel for the flow characteristics of that well. EWT will drive development decisions for the field. But, it's not like
shelf production - you can't over-design your facilities. Over-design in deepwater costs a lot of money. Fit-for-
purpose development is critical."

There are key differences between an EWT vessel and an FPSO. Malcolm Sharples, Vice President of Offshore
Technology for ABS Americas, described it best: "An FPSO is an EWT extended on a permanent basis."

The EWT is the main driver behind crude oil storage. Due to flaring regulations in the Gulf of Mexico, the oil for the
test must be stored. Therefore, storage tanks are necessary.

Dreith said that added production capabilities would be more applicable in the Gulf of Mexico because of flaring
regulations. "Production capability onboard depends on what an oil company wants. The vessel is not an FPSO. If
you want to produce to a ship long-term, an FPSO is needed. A drillship is intended to be a drilling vessel, but we are
looking at an EWT classification. This doesn't fall under the FPSO rules, but incorporates some FPSO capabilities. We
have looked at what we would need from a classification point of view to allow us to temporarily store crude oil
onboard our drilling vessel. For example, an FPSO cannot trade in crude oil, and it cannot travel into port and offload
crude oil. With a drilling vessel, we would conduct EWT to prove the reserves. The vessel would have the ability to
store that crude produced during the EWT, instead of trying to flare it. This would bring us under the scope of
offshore regulators."

In terms of EWT capability and a comparison with FPSOs, specifically for the Gulf of Mexico, Chris Oynes, Regional
Director for the Minerals Management Service (MMS) said the regulatory body is considering moderate storage on
drillships. "But, there is a production limit to a drillship," he added, but declined to clarify the volume.

Classification

DNV offers the only EWT classification in the industry. ABS has been getting involved by assisting several companies
in making the vessels compliant if they do install the capabilities.

"We are looking at the design of the vessel in terms of its location and cargo to make sure that those systems would
be in compliance with what we would expect for an FPSO," explains Ken Richardson, ABS Vice President. "We are not
working for a formal certification at this point. It is a description. We have not been asked for it yet."

Bret Montaruli, ABS Chief Engineer, Engineering Services added that the vessel is a mobile offshore drilling unit
(MODU) and will remain classed as a MODU. "We are looking at the safety impact of that equipment on the rest of
the drillship."

"We are doing some work with R&B Falcon and Global Marine on their newbuilds to help streamline the conversion
possibilities in the future," said Todd Grove, ABS Manager of Offshore Engineering.

"In addition to our present scope of classification on these vessels, we are looking at getting them prepared for
doing this in the future. What they have asked us to do is review the expected configuration according to our Guide
for Building and Classing Floating Production, Storage, and Offloading Systems" and let them know where they do,
and do not, comply. It is more of an advisory than a formal notation because the vessel is not presently set up to
operate in that manner. Everyone is keeping their options open to provide maximum flexibility."

The future

What does the future hold for these vessels? If needed, the vessels could be converted to full FPSOs and could
provide fierce competition by offering an all-in-one solution for an operator's deepwater needs.

"There has been an increasing request from oil companies to have longer EWT to prove the reservoir before they
put in whatever facilities," ABS' Sharples pointed out. "I think FPSOs will be absolutely necessary for the long-term
because there will be no other reasonable way to produce these fields, particularly in deepwater areas where the
pipeline infrastructure is not there."

In the meantime, drilling-production vessels will operate as normal drillships and have a great deal of unused
capacity. But, when the time is right, they will have the ability to convert or upgrade to their full potential. At this
time, such a function does not appear to be necessary. These new drillships are built for the future, and when the
production capability is implemented, industry will have met another goal of increasing efficiency offshore.

FPSO's in the US Gulf by 2001?  

The Gulf of Mexico has taken another step towards joining the rest of the world in the use of floating production,
storage, and offloading (FPSO) vessels. The US Department of the Interior's Minerals Management Service (MMS)
has taken another step by issuing an environmental impact statement (EIS) on the possible use of FPSO's in the Gulf
of Mexico.

The EIS is expected to take about 18 months and will cost about $1 million funded entirely by the industry group -
Deepstar. According to the MMS, the EIS will assess the environmental effects of the use of FPSO's by examining a
hypothetical one million bbl storage FPSO that would receive hydrocarbon production and smaller shuttle tankers
would offload the production from the vessel for transport to port. The EIS will also examine a high-case scenario
with 2.3 million bbl storage.

On an industry panel at the Offshore Technology Conference in May, Chris Oynes, Regional Director for the Gulf of
Mexico OCS Region of the MMS, said, "The earliest anyone will be able to begin production from an FPSO will be in
2001. Once the EIS is complete, a specific location environmental review will also be performed before approval is
granted. We have been entertaining the use of mild storage on a drillship, but there is a production limit."

Another panel member, John Westwood, Principal of Douglas-Westwood of the UK, offered a European perspective
on the issue of the environmental impact of the vessels. Westwood pointed out that FPSO's are not an environmental
hazard. The problem lies in transportation of the oil. He said, "Oil gets into the water in one of two ways: seepage
and transportation. Oil production is not the polluter; transportation is the case."

The EIS will be released for public comment in March or April of next and public hearings will be held in April or May.
A final EIS will then be compiled based on all comments received in September or October. While the EIS does not
assure that FPSO's will be given the green light for the Gulf of Mexico, it does indicate a step in the right direction.

Economics still support FPSO fleet expansion  

Global fleet up to 90 vessels

A total of 90 floating production, storage, and offloading (FPSO) vessels are operating, idle, or under construction
world wide. Of the 90 vessels, 78 are operating in some area of the world. Three are idle. The United Kingdom holds
the highest number of operating FPSO units (13), followed by China (8), and Norway (8).

Several shipyards, including Samsung, Mitsui, and Hyundai, currently have nine FPSO units under construction. Four
of these vessels are newbuilds. The remainder are conversions. Most are destined for Brazil and Norway within the
coming years.

At present, there are 53 projects in some stage of development that are considering or planning to use FPSOs for
development. Of these 53, Australia holds the most opportunities with eight developments each under consideration.
These are followed closely by Norway, with six developments.

Construction, conversion

The FPSO fleet is continuing to grow, especially in the North Sea. On the new construction side, the most recent
FPSO newbuild to enter into operation was PGS' Ramform Banff. The Banff has a production capacity of 95,000 b/d
of oil, 89,000 b/d of water, and 72 MMcf/d of gas. The vessel is contracted to Conoco's Banff Field in the North Sea
for the life of the field.

The next major FPSO set to come onstream is Statoil's ?sgard A. The vessel came on location on the ?sgard Field in
the Norwegian Sector of the North Sea in February and is expected to go on-line shortly. The vessel will produce the
oil from the area, while other systems will be employed for gas production. The vessel has a production capacity of
175,000 b/d of oil and 950,000 bbl of storage capacity.

Other major newbuilds anticipated for delivery are:

• Woodside's Laminaria off Australia, due out this year
• Elf's Girassol Field off Angola, due out next year
• PetroCanada's Terra Nova Field offshore Canada, due out late next year.

On the conversion side, the Keppel Shipyard in Singapore completed a conversion of the Ruby Princess tanker to an
FPSO for Nortrans Offshore. The vessel is working for Petronas Carigali on the Ruby Field off Vietnam.

Contracts have also been recently awarded for an FPSO destined for BHP's Buffalo Field in the Timor Sea off
northwest Australia. The vessel is being converted from the M/T Spirit tanker into an FPSO capable of 40,000 -
60,000 b/d of oil production. Construction is expected to be completed by the end of the year.

Newbuild FPSOs: What can go wrong?  

Construction problems and solutions

To date, purpose-built floating production, storage, and offloading vessels (FPSOs) have been constructed in
traditional shipbuilding facilities with existing systems. The construction contracts were typically administered with
the pre-conceived contractual culture of a shipyard.

The 12 newbuild FPSO contracts for Northwest European waters have been made by the vessel's owner or
speculator, either directly with the respective shipyard or with the shipyard as a member of a contracting joint
venture. Four are owned by single operators - Gryphon 'A', Kerr McGee; Captain, Texaco; Anasuria, Shell; and
Schiehallion, B.P. - in the UK Sector, and five in the Norwegian Sector.

The first true monohull FPSO in the North Sea was the Petrojarl 1, delivered in 1986, and was intended to be a
production test vessel with a small crude oil storage capability. As the Seillean was designed and built as a single
well oil production system (SWOPS), it cannot really be called an FPSO. The title of second North Sea FPSO therefore
falls to Gryphon 'A', which started out life as a speculative build floating storage unit. The role changed during its
design development into an FPSO.

The Gryphon 'A' was delivered seven years after Petrojarl 1 and the next newbuild FPSO delivered for the North Sea
was the Captain in 1997, another four years later.

Of the 12 newbuild FPSOs now installed or under construction for the North Sea, 10 have been the product of the last
four years of FPSO history and designs are still evolving.

Market environment

Until the beginning of the 1960s, the principals in shipowning companies would order a new ship by making a
telephone call to a shipyard's managing director. The shipyard's managers would begin to develop the detailed
design and order steel materials without a contract being discussed - only the price would have been settled. In the
1950s, even the price would be open to some extent as it would often be "cost plus." The "cost plus," however,
would include a gentleman's "plus" based on similar, recent or sister ships, and quite easily calculated.

All that would change with the advent of intense worldwide competition from the developing nations and increased
inflation. Between these two factors, the numbers of countries still capable of major ship construction has dwindled
to a comparative handful mostly in the Far East.

In today's shipbuilding environment, the contracts for trading vessels have become a little more specific, but they
still convey some of the mutual goodwill that was fundamental to the old contracts.

The discussions that follow, although targeted at monohull FPSO's, are equally relevant to the construction of other
offshore sector floating structures built by a shipyard.

It involves a technical solution that solves a commercial problem and conversely, commercial effort that solves a
technical problem. This is singularly applicable to the design and construction activities for newbuild FPSO's due to
the early historical phase of their development and the ample opportunities for inspired innovation.

Contracting strategy

Although, in general terms, shipyards seem to prefer fixed, lump-sum contracts attached to a fully detailed
engineering package, this is usually not equitable with the current fast-track FPSO field development philosophy. Not
being equitable affects both contracting parties.

Delays can be caused by poor or incomplete engineering. This also leads to contractual confusion or dissension,
which may affect the quality of the engineered vessel. One of the best reasons for the beneficial inclusion of the
shipyard in an alliance partnership is a case where the workscope is not sufficiently defined at the time of contract.
At this time tolerance and help are needed from the shipyard and contractor, but instead there is often disruptive
and unproductive contractual wrangling.

If it is determined that all parties would benefit from the shipyard's inclusion in an alliance or joint venture then
further detailed analysis will be required before the final step is taken.

Contract structure

Eventually a construction contract will be offered to the shipyard for signature. It is therefore necessary to pre-
define the contract structure and its backing documentation. The Crine Network in the UK has recently published its
model "General Conditions of Contract for Construction" to provide an industry basis for major construction. The
model contract also has a set of guidance notes to complement its use. The complete presentation is the product of
years of work and formulation by the Crine Standards Contract Committee comprised of senior representatives from
major operators and the contracting industry.

The objective of the Model Standard Contract is to significantly reduce the inefficiencies associated with the repeated
drafting and reviewing of contracts. It is also intended to facilitate a greater sense of partnership between operators
and contractors and will reduce the need for a full contractual review for each tender.

The Crine Model should form a good basis for conventional contracting relationships. There may be some advantage
to be gained in the future by the identification of those clauses that would benefit from specific modification for
contracting for the construction of FPSOs and create a modified FPSO version of the model.

Bid invitations

Most shipyards under consideration for participation in a prospective project will be easily identified based on their
strong profile and capabilities. In some cases, these features are less apparent. They include, for example, when the
first choices are full to capacity, when they have changed their market sector interests, or for any reason they are
no longer interested in floating production construction.

The list of invitees should be as large as is sensibly possible within the project constraints. A typical prequalification
questionnaire will include expression of firm intention to bid request, shipyard facilities and manning levels, current
workload and schedules, relevant experience in the sector, ownership and corporate relationships, management
systems in existence, quality assurance qualification, safety and environmental records, industrial relations records,
financial information and accounts.

The prequalification documents will be vetted and evaluated in order to provide a final list of shipyards to be invited
to bid for recommendation for management approval.

The status of the front end engineering completion will determine the shape and extent of the formal bid invitation
documentation. This can range from just a collection of functional specifications, the design basis and the
environmental and geotechnical data or be a full-blown pre-engineering package.

The depth of this engineering will be measured against the speed the project schedule needs, but all floating
production projects will have some degree of grease applied to the schedule for early commercial returns. The FPSO
vessel design itself will always have the field development principal critical path straight through it and the front end
engineering activities are the first consideration. Any of this engineering pushed into the post-award construction
schedule will generally impact the schedule on at least a day-for-day basis.

The bid period will depend on the project schedule, tempered with the bid content and complexity, but will probably
be in the 3-6 weeks range, with 4 weeks being the likely median requirement. Miscalculating the bid period will only
cause dilution of the quality of the bid in terms of accuracy and technical content. It can also have a greater negative
impact on the project than almost anything else except the definition of the scope of work.

In order that supportive and qualitative pricing information responses are received from the shipyards they should
generally be instructed to complete a price breakdown matrix. This will allow interrogation of individual line items for
credibility and validity by comparison with each competitor's figures side by side. The value of this form of
evaluation by the comparison of line item breakdown cannot be overemphasised.

All omissions and deviations from the instructions to tenderers requirements will need to be identified, interrogated,
and closed out by the bid clarification process. If the shipyards under consideration are also being considered for
fabrication and HUC of the process plant, then this would also be incorporated into the matrix for comparison. Apart
from consideration of the price breakdown and total cost the overall evaluation will also consider the following
principal aspects of the individual offers; total lump sum price, towage cost and schedule impact, site supervision
team requirements, averaged rates for variation, payment schedule and methods, financing arrangements and
benefits, construction schedule, process plant capabilities, quality assurance assessment, safety record assessment,
financial health report, and simple ranking of all offers.

It is imperative that before any final commercial commitment is given to a short listed or recommended shipyard a
multitude of other relevant considerations should be evaluated and satisfied. Initially the following aspects of the
management systems should be considered; project management system, management culture, communication
abilities, business language, document control, QA/QC organisation, procurement and expediting, certification,
scheduling abilities, health and safety, cost control, and pre-outfitting experience. The following physical facilities and
resources should be evaluated; current and future workloads, building berths and dry-docks, steelwork
prefabrication, pipework prefabrication, berth craneage, outfitting quay logistics, undercover storage, engineering
manning levels and abilities, steelwork and outfitting trade levels and experience, electrical and instrumentation
resources and experience, and hook- up and commissioning resources and experience.

After consideration of all of the foregoing, the bid evaluation teamleader will conclude the evaluation with a formal
bid evaluation and recommendation report. This will include all records of the bid clarification negotiations, shipyard
assessment visits, and the normalization factors utilized in arriving at the recommended choice of shipyard.

Post-bid refinement

The recommendation to proceed with a shipyard and acceptance will provide an excellent opportunity to fully refine
the design, price, and construction schedule in readiness for final pre-award commitment:

The final pre-award discussions and negotiations include design/cost optimisation modifications, final agreed scope of
work, contract pricing structure and values, milestone payment values and schedule, rates and units for variation,
contract currency and exchange rates, master construction schedule, insurances, P.C. guarantee, and performance
bonds.

During this period of refinement and final contract negotiation it is imperative that any concurrent negotiations
between the shipyard and other potential clients are careful monitored. The opportunity at this stage for the shipyard
to "play-off" one client against another for a schedule slot in the yard is often too good to miss, particularly in a
strong market situation. The risk to both clients is obvious and probably schedule critical to all.

Contract payment methods

Until about 40 years ago, all of the world's major shipyards contracted for vessels on an almost cost-plus basis, but
then fixed, lump-sum contracts, with penalties, became the norm. The days of fixed, lump-sum contracts may now
be over as current contracting strategies reflect some form of alliancing arrangement with others and/or the
owner/operator.

Some of the FPSO developments recently contracted for consist of joint venture partnerships comprised of
contractors whom together will supply the total field development scope of work, from conception to first oil.

This form of contract can be based on the target price contracting mechanism which is founded on the principle of
shared risk and reward. Payment of a bonus for early production may also be provided.

The target price itself consists of three main elements; a management fee which includes fixed profit and overheads
for the joint venture, the estimated cost of the facilities, this would to be charged to the operator at cost. A
contingency provided to compensate the joint venture for those unforeseen events often experienced in an offshore
project.

The above costs will be declared at the pre-contract stage and have been clarified and agreed.

If the project is to be completed below the target price level then the joint venture partners and the owner would
share the savings on an equal basis and the joint venture would retain the fixed profit and overheads.

Should the final price exceed the target price then the excess costs would be shared on an equal basis between the
joint venture partners and the owner. This situation can be limited by a fixed amount, the total of which is termed
the cap price, after which the owner would pay 100% of the actual costs incurred without limitation.

The amount between the target price and the cap price is set such that all of the fixed profit and overheads element
could be lost by the joint venture partners. All members of the project, whether joint venture partners or owner will
have an incentive to minimise expenditure, thereby maximising the cost benefits to all parties. Each partner will also
be responsible for the rectification of his own defective work, at no cost to the joint venture or owner.

The estimated cost of the project would be based on contract scope of work, pre-award and intermediate
engineering deliverables, design basis and reports. No change to any of these documents, which diminish the
requirements of the design basis, would be permissible without the approval of the owner. Similarly, no changes to
the contract documentation which reduce the availability or quality of the facilities as agreed during the development
of the design would be permitted without approval.

Where such changes are approved, any cost increase associated with increased scope would be added to the target
price and similarly decreases in scope would be deducted from the target price.

Design development changes which will not effect the target price will be controlled and approved by the joint
venture and finally approved by the owner. Cost savings derived by efficient design development will enable the
joint venture to earn proportionally more profit under the target price mechanism, again subject to owner approval.

The fixed overheads and profit for the shipyard's scope within the overall project should be agreed between the
partners before contract award and built into the target price. The construction cost compensation for the shipyard
as a joint venture partner would be determined by breaking out the obvious components of the vessel and topsides
in a way that is fair, sensible and can easily be defined and measured.

An incentive related payment schedule should be developed and agreed and this should act as a motivation device
and reflect the shipyard's cashflow profile. A typical milestone-related payment schedule for a target price
mechanism construction contract is shown below.

Delivery liabilities

The philosophy for the imposition of liabilities and damages on the shipyard will be based on the commercial losses
that would by incurred by the owner, and his partners, in the event of delayed delivery. Although generally the
contract will include provisions for termination after a stipulated delay in the delivery date for provisional acceptance
they would only very rarely be activated.

Recovery of an owner's losses by the shipyard's payment of liquidated damages is generally of more interest and it
also acts as an incentive to the shipyard merely in its avoidance.

The delayed contract delivery considerations should be contract schedule inherent delay risks, contract price comfort
or risks, delay repercussions on installation windows, rights of termination clauses, liquidated damages free period
and activation, per diem liquidated damages value(s), and liquidated damages period and payment limit.

Both parties will have the right under the conditions of contract to raise a variation order request, which may or may
not eventually become an approved variation order depending on the particular circumstances.

The shipyard shall not implement a proposed variation order until the owner has approved the order by signature.
The only circumstances whereby a variation order may be implemented by a verbal instruction, would be in an
emergency endangering life or property or where in the owner's site representative's opinion the safety or integrity
of the project is at risk. Even under these circumstances the owner will be required to confirm the verbal instructions
in writing within, say, two days.

It is preferable that a very comprehensive list of rates for variation be incorporated into the contract to ease the
calculation and acceptance of variation costs. These will include for all likely labour, materials, plant and equipment
costs etc. and will aid in the avoidance of contractual confusion.

Depending on the final form of contract and the type of contracting relationship intended to operate with the
shipyard, the site team need for local supervision and inspection will vary. This can range from just a handful of
personnel on site to 50 or more as has been seen on some recent projects.

A likely initial site team build-up for a project with a comfortable status of engineering at the commencement of the
contract would include at least nine men. If it becomes obvious that further presence is required on site for
supervision and inspection then the team will be reinforced as necessary, but will increase in any case towards the
mechanical completion and pre-commissioning stages. The size of the team will also be dependant on the extent of
the process plant scope of work being carried out by the shipyard, if any.

The owner's site representative's role will also vary again depending on the type of contracting relationship and
existence or not of partnerships and alliance etc. However, it is usually intended that he will act as the sole point of
contract and authority on behalf of those contractually facing the shipyard or the joint venture on site as their
representative.

Contract schedule

The shipyard will be bound to produce within 30 days of contract award a master construction schedule consistent
with the overall contract schedule. This will be in bar chart format for the design, procurement, construction,
installation of equipment, testing and delivery of the vessel and shall identify all interdependencies of the variously
related activities.

Any delays in the early phases of engineering will inevitably delay the complete project schedule due to the critical
path weighting of these activities. Critical path delays can rarely be recovered due to the inherent incompressibility
of the activities and their subsequent approval cycles. This is often not recognised early enough, to the detriment of
the project.

Total project reporting will be produced on a weekly and monthly basis. The method of reporting will generally be by
narrative, activity progress bar chart mark up and globally by percentage progress completion figures against pre-
agreed S-curves.

Even if quite dramatic increases in performance were to create excellent steelwork and pipework prefabrication
progress, the subsequent activities - painting units, pre-outfitting, and erection of steelwork - are all sequential
activities without float. All of these activities are also sequential and on the critical path. This is when the real bottle-
necks begin to occur and these are generally irreversible as they deny the ability to complete and precommission
systems with obvious consequences.

In the demonstrated delay scenario shown above, in order to recover the schedule by the end of the third quartile in
order to meet the original delivery date, it would require that 55% of the work volume be carried out in six months
instead of the planned 35%.

One of the most remarkable facts about the average FPSO construction schedule is that the last 1% of schedule
progress volume can only be achieved in the last two months and which is 8% of the total schedule period.

The only way to achieve successful construction planning in a shipyard culture is to create a belief in planning at all
levels but this has to be bought by spending on effective planning systems or overspending on labour. It is important
that when the construction schedule states that "Unit 330 will move from the fabrication shop to the slipway on the
Friday of Week 22," that it does. This is not just to satisfy the schedule, but so the workforce, supervision and
management can depend on it happening.

Contract success should be relatively straightforward to achieve as it is only dependent on four main factors which
are well understood by conventional European offshore fabricators. If they weren't understood then they couldn't
even get into the business and they certainly couldn't stay in it without them - they are good engineering capabilities,
good fabrication quality systems, reliable schedule achievement, and effective hook-up and commissioning.

However, with a few exceptions, the construction activities of all of the Northwest European FPSOs have met with
schedule, quality and cost overrun problems of varying degrees and mixes, most of which we are all aware of. Some
have been absorbed and mitigated into the overall project development and some have not. Some have been
commercial and technical disasters of frightening proportions even to "well-padded" operators. The rumors and
estimated figures have even shown themselves to be well shy of reality when the facts finally leak out.

Topsides, marine systems planning upsetting FPSO delivery schedules  

Some solutions for cost, schedule management

The newbuild FPSO Triton recently arrived at England's River Tees for outfitting by Kvaerner Oil & Gas. Once
completed, it is due to be towed out this summer to its location in the Central North Sea, producing oil and gas from
the Bittern, Guillemot West and Guillemot North West fields.

A number of recent FPSOs, particularly on Europe's North West Continental Shelf, have taken longer to deliver than
planned. As a result, they have also ended up costing more. This has been a frustration to the industry, since one of
the benefits of the FPSO concept was supposed to be a cheaper and shorter schedule. Why have we lost this
perceived advantage?

In part, issues surrounding the integration of topside oil production and marine systems have been blamed, although
back-up for this belief is not always evident. Therefore, as part of a much wider investigation into FPSOs, BP
commissioned a study last summer by Genesis Oil & Gas Consultants to look specifically at these systems and how
their integration affects FPSO and design construction.

A review document was subsequently prepared, based partly on interviews with operators of seven FPSOs, two
contractors, and one shipyard. This examined what the industry had done to date, and to highlight the problems and
successes with the various approaches. It does not provide definitive solutions on how to integrate certain systems,
but rather presents data and guidance from which project engineers and managers can hopefully benefit in future.

18 systems considered

Eighteen systems were considered from both a design and construction point of view - some of the findings are
presented below.

  • Power generation/electrical distribution: A key problem of integrating power generation and electrical
    equipment is developing electrical load requirements early enough to suit shipyard schedules and
    opportunities. In cases where equipment is located in the engine room or other machinery spaces, the
    process of engineering definition and subsequent long lead time of certain items have caused problems with
    the hull schedule. One solution could be to site electrical switchgear on the main deck, which would allow it to
    be de-coupled from the hull construction schedule. Switchgear design is linked heavily to the process system
    design and as such is linked more logically to the topsides schedule. The same applies to power generation
    equipment.
    If main deck space is at a premium, it may still be prudent to site switchgear in the hull - but if this decision is
    taken, the switchgear design must be managed to prevent a schedule clash (significant FEED work must have
    been executed prior to award of the shipyard contract).

  • Control systems: A marine control system normally includes control for propulsion, position keeping, ballast
    control and offloading. Production plant control normally comprises production process control, fire and gas
    and emergency shutdown and subsea system controls. Integration of marine and topsides control is possible -
    however, the level of integration depends on propulsion philosophy and availability of technology. While a
    combined control system may suit an FPSO with no propulsion, or newbuild FPSOs, it also introduces extra
    interfaces, both physical and contractual, and can necessitate a large number of cables routed to a single
    point - creating a potential bottleneck during construction.
    Separate control systems may be more suited to converted vessels with propulsion, and also make vendor
    selection easier. Overall, a single system comes out more favorably, but the interfaces it introduces need to
    be identified early and managed in accordance with the level of risk that it poses to schedule and cost.

  • Seawater: Seawater pumps are employed to lift water from sea chests for distribution to seawater and deck
    water systems, the main user being the ballast water system. A typical offshore production system uses
    caisson-based pumps to supply cooling water to the process plant and for water injection. A number of FPSOs
    are benefiting from the decision to have separate topside seawater pumps in caissons set into or through
    ballast tanks. Firewater pumps are also on deck and in their own caissons. This approach was found to be
    cheap, effective and reliable. Caisson-style lift pumps are tried and tested offshore, and are easy to specify
    and install. Use of caissons in the hull allows pumps to be located near the process cooling or water injection
    plant end-users. This, in turn, reduces pipe runs and takes out a machinery space interface. Furthermore,
    pumps can then be specified much later in the design process. In addition, these pumps have a smaller
    footprint than traditional pumps, and also a lower operating cost.

  • Vents: On tankers, inert gas vents are sized normally for the maximum inert gas rate, which is, in turn, sized
    based on the maximum offloading rate. On FPSOs, however, offloading rates are defined by oil production
    rates, which are roughly one tenth of the offloading rate. As a result, vents are normally over-sized, leading
    to poor mixing and dispersion. This causes problems with maintaining certain hazardous area classifications
    on deck, and has even created unsafe gas clouds. The lesson is that two separate vents should be provided -
    one for offloading and one for loading - or alternatively, a single vent sized for loading conditions with a
    bypass for offloading.


  • Diesel: Diesel systems are easy to integrate on FPSOs, but the diesel treatment package must be specified
    for the most arduous duty, i.e. gas turbine fuel supply spec for solids and salts. Normal ship diesel treatment
    systems do not necessarily meet this requirement.

  • Hazardous areas: Some conversions and even some newbuilds have experienced problems with hazardous
    area classification. A common misapplication is to use the marine tanker code and consider locations above
    2.4 meters over the storage tank deck as non-hazardous. A significant lesson learned from the review was to
    not accept any concept of "safe areas" out on deck. All these areas should be treated as at least zone 2. This
    will ultimately simplify equipment specs and allow much more flexibility in regard to changes during the
    construction phase.

  • Structural: Two noteworthy lessons were identified.
  • Firstly, ships' cranes are not suited to offshore duty, since they are designed for calm jetty use, are
    slow and not dynamically rated - project teams should therefore insure that offshore specs are used
    for cranes.
  • Second, design for blast and fire-proofing can be a problem for shipyards, which do not normally
    analyse over-pressure and fire exposures of topside equipment. The answer may be to transfer this
    design aspect to the topside contractor, or to assign help to the shipyard.
    In certain FPSO projects, the review found, there is potential to combine the cargo tank blanketing system
    with the topsides production plant in order to recover VOCs, and also to integrate this with a flare recovery
    system (provided that there is a disposal route for gas, via export or reinjection).

Integration perspective

None of the systems covered in the review were identified per se as prime causes reasons of cost and schedule over-
runs. They were simply second order problems behind issues such as shipyard tender process and degree of front-
end loading, contractual strategies and construction planning. There are no rights and wrong ways to integrate
topside and marine systems on FPSOs -
the key lies in planning and management. Understanding some of the
specific issues, however, will aid that process.

Gains can be made from simplifying systems integration for newbuild FPSOs provided that sufficient engineering has
been undertaken prior to placing shipyard orders. Problems have arisen from the shipyard not comprehending (or
having been fully informed) of their requirements. If a project is heavily front-end loaded - allowing for significant
definition prior to placement of hull orders, every effort should be made to integrate systems where possible. If,
however, the schedule prevents significant FEED work, little or no integration should be attempted.

The review revealed significant support for outright avoidance of integration, to assure fulfilment of cost and
schedule performance. This means that the topside production plant, including utilities, should be designed and built
entirely by the topsides design contractor.

On existing ships, consider mothballing all marine equipment in the hull/engine room, and provide all production and
support utility equipment on the deck. With newbuilds, avoid putting anything in the engine room, to minimize
interfaces between the hull and the production systems and also to prevent access restrictions.

Early on in a project, the degree of integration is not likely to be viewed as a major cost driver. But historically,
integration has proven to be a risk to cost and schedule overruns.
To lessen this risk, integration of topside and
marine systems should either be minimized or alternatively maximized during the design phase, identified as a
potential threat to schedule and cost during the construction phase, and then managed accordingly.

Pitfalls in FPSO contracts  

Tanker owners, eager to meet the fast-growing demand for floating production, storage, and offloading (FPSO)
vessels, are struggling to accommodate the tougher commercial terms sought by field operators, who are
increasingly eager to pass on hydrocarbon development risks.

Marginal fields in South East Asia will require large numbers of floaters over the next decade. However, new players
in the market - including vessel owners with potential candidates for conversion - find it increasingly difficult to
assess the financial viability of complex terms proposed by field operators, who are attempting to reduce their risk
at the expense of the provider of the floater.

The field operators are seeking to reduce their risk by proposing shorter periods for fixed term utilization contracts.
Such attempts are commonplace even in cases where a high specification FPSO is required.

In the past, FPSO providers expected at least 10 years, but some terms negotiated are as short as 3-4 years. This
makes it virtually impossible for a FPSO provider to achieve an acceptable return, except in unusually favorable
circumstances.

Inexperience

Much of the development risk associated with marginal fields is now passing into hands that lack experience in the
complex world of offshore oil and gas production. Not surprisingly, the new players are looking to third parties to
provide the all-important expert evaluation of risk-sharing proposals put forward by field operators. This is why a
number of leading banks in the Asia-Pacific region have established teams of experts in reservoir assessment.

My firm recently assisted a client who had encountered problems during the conversion of his vessel into a
sophisticated floater. The conversion schedule slipped, and eventually, began to erode the fixed term charter
negotiated with the field operator.

Fortunately, the client successfully negotiated an extension and so maintained his potential for generating
satisfactory returns on a very considerable investment. Yet, this case did serve to highlight the lack of options
available when a conversion project is delayed.

There is little room for maneuvering, since demand for floaters exceeds supply and most requirements for floating
systems are highly field-specific. Project viability, of course, remains the key issue. The main objective of the
floating system provider should be to cover conversion costs at the mobilization/hookup phase. The aim is to obtain
payment of daily rate on a "ready, willing, and able to perform" basis.

Accounting for delays

Looking beyond that phase, however, the ability to generate attractive profits has been reduced by the field
operators' insistence on even shorter fixed term contract periods. In some cases, the floating systems provider's
position is aggravated by proposed contract provisions that would involve him in subsea works.

In many cases, deals of this type take the FPSO provider well beyond his "comfort zone." Yet this has positive
aspects, as it widens the FPSO provider's experience base.

Many Asia-Pacific shipping groups are eager to explore new opportunities offshore. The FPSO provider can reduce
commercial risk by establishing a clear set of commercial principles that are not negotiable. Certainly, one priority
should be to ensure that any "permissible" yard delays during conversion can be passed on, in order to preserve the
term of the utilization contract.

Other potential risks arise in connection with financial responsibility for "loss of function." Many floaters are designed
to perform various functions (storage, processing, pumping, and power generation).

Contracts should recognize that these functions have different levels of operational, commercial, and financial
significance. Lack of attention to this issue could result in an FPSO provider incurring unreasonably harsh damages,
out of proportion to the consequences of a temporary loss of a single function.

FPSO pump permanency requires low maintenance  

When planning pump facilities it is important to recognize that production ships are not the same as tankers. The
offshore pump can be ten times the size of the marine pump, which creates difficulties if installed in the machinery
space. And although a tanker comes to port for maintenance, the FPSO remains permanently on the field.

One solution for the installation problem is to use submersible pumps and a caisson. This solution has been adopted
on a number of FPSO projects, including Conoco's Banff, Amerada Hess's Bittern, Shell's Curlew and Woodside's
Laminaria. On Statoil's Norne vessel, the pumps and caisson were retrofitted at sea.

In the case of tankers being converted into FPSOs, it may be difficult to install a caisson. In this type of case, Frank
Mohn provides a submersible pump solution without the caisson. Instead, the pump hangs over the side of the vessel.

Latin America

Frank Mohn Flatoy has become a regular supplier of firewater and seawater lift pumps to Petrobras production
floaters. In just four years, the Bergen-based company has delivered 23 firewater pumps and seven seawater lift
pumps to 11 of the state oil company's production units, reports German Nilsen, sales manager, Americas. The latest
order, which was confirmed in July, is for two fire-water pumps, each of 2,000 cu meters capacity, for the P-40
production ship. These are due for delivery in April.

Last year, Frank Mohn delivered three seawater lift pumps for caisson installation to Amec for the P-36 (ex Spirit of
Columbus) semisubmersible production platform; two diesel-hydraulic firewater pumps and one diesel-direct
firewater pump to Modec for the P-37 production ship; and one diesel-hydraulic and one diesel-direct firewater pump
to AESA for the P-47 floating storage unit. The P-37 and P-47 pumps are all skid-mounted.

The company has opened a service office in Rio de Janeiro.

Also, Frank Mohn has a number of orders for emergency offloading packages from Pemex. The state oil company
has also purchased the supplier's cargo pumps for its products tankers, Nilsen says. Mexico does not represent a big
market where floaters are concerned - it has three floating storage and offloading units, but no production floaters.

Last year, the supplier sold water injection pumps to a BP operation in the Pedernales region of Venezuela, a
mangrove area where production takes place using barges. At 350 bar, these are the highest pressure pumps the
company has ever supplied, Nilsen says.

North Sea

The North Sea continues to be an important proving ground for Frank Mohn. In mid-1998, the company delivered
three fire-water pumps and three sea-water lift pumps for Elf's Elgin process platform. The pumps are installed in
three A-60 rated modules - in the case of fire, the modules will seal themselves off and the pumps will continue
operating for as long as the fuel supply lasts.

By employing its caisson-free concept, it was possible to save a total of 120 tons on a weight-sensitive project, says
oil and gas sales manager Frode Hjelmeland. The weight savings are achieved by Frank Mohn's concept using
integral power tubing, allowing the pumps to be installed without the large-diameter caissons normally used.

Each of the pumps is driven by a 2 MW driver. A time and labor-saving feature is that the condition monitoring of the
pumps is performed through the lube oil system.

Where required, the company also supplies systems packages. Last summer it delivered an 89-ton systems package
for Esso Norge's Jotun production ship, comprising two pumps for produced water injection with filtration systems. All
the equipment is mounted on a common skid with valving and instrumentation. A similar - but at 312 tons, much
heavier - systems package was supplied to Statoil's Norne production ship.

Global FPSO fleet growing at a 34% annual rate  

47 units under contract, 24 under construction

With no projection for future growth, the floating production, storage, and offloading (FPSO) vessel fleet will consist
of 71 vessels by the year 2001. According to Bluewater Offshore, 47 FPSOs are now in operation around the world.
An additional 24 units are on order or currently under construction.

Bluewater has released information tracking the existing and committed-for-construction FPSO fleet as of September
1998. Seventy-one vessels are listed as entering the FPSO fleet by 2001. Forty-seven are in operation, and 24 were
committed for construction, as of September 1998.

The Asia-Pacific region is by far the most active FPSO region with 26 vessels. Twenty-two FPSOs are in operation
and four are planned or under construction. The East China Sea area is the most active in the region, with 10 in
operation.

The North Sea follows closely, with 22 vessels. Thirteen of the FPSOs there are in operation and nine are planned or
under construction. West Africa holds third place, with 10 (six in operation and four planned), and Brazil follows with
eight (four in operation and four planned).

Fleet owners

Oil companies own a majority of the world's fleet. Forty-two vessels are owned by oil companies, with the remaining
29 contractor-owned. In a comparison between the North Sea and the rest of the world, North Sea contractors own
12 vessels, compared with 17 in the rest of the world. As far as oil companies are concerned, North Sea oil
companies own 10 vessels, compared to 32 in the rest of the world.

There is a tie between contractors who own the largest number of FPSO units. SBM and Bluewater each have a fleet
of four vessels. However, two of Bluewater's fleet are still under construction, whereas all four of SBM's FPSOs are in
operation.

On the oil company side, Petrobras leads the field with six company-owned vessels and an additional two on
contract. BHP follows with four vessels.

Fleet trends

Based on this information, the FPSO fleet is growing at an annual rate of 34%. As shown in the accompanying graph,
the FPSO fleet has been on the rise since 1992, and has climbed quickly in the period from 1996 to the present.

It is expected that the FPSO fleet will continue to grow with the expanding number of deepwater fields being
discovered and the need of an FPSO for production.

Another factor, not included in the information, is the number of deepwater drillships being built that can be easily
converted for FPSO usage. This will allow a quick shift in the market if needed.

A third factor that may also boost construction will be the growing pressure on the Gulf of Mexico for FPSO usage. If
FPSOs do enter US Gulf waters, a strong growth rate in the fleet is sure to follow.

New vessels, rigs & upgrades  

Will operators exit drilling contracts?

Speculation is growing that delivery delays and major cost overruns could be giving operators a convenient exit
from high dollar, long-term vessel contracts. Although no contracts have been officially terminated, as of this writing,
operators have begun asking for accountability with respect to these inefficiencies.

The most notable example of this problem was the cancellation of Smedvig/Navion's West Navion II drillship in
August due to major cost overruns. Cancellation cost Smedvig $90 million. Recently, more and more cancellation
problems have begun to materilize.

  • Saga Petroleum recently negotiated an $18.2 million settlement from Keppel FELS, Singapore due to late
    delivery of the Varg production ship. The Varg was delivered seven months late and licensees in the project
    will be credited a daily compensation by Keppel FELS. Keppel FELS will also be compensated for changes
    made during the construction period. However, this overrun only pushed the cost of the vessel up to $218
    million, less than 5% from the originally contracted price.
  • Esso Norway and Smedvig are going to court over the Balder FPU. Esso is attempting to terminate the sales
    and operations contracts for the vessel due to major cost increases. Smedvig filed a claim disputing Esso's
    claims, saying that Esso has no legal basis for termination of the contract. Esso submitted a counter-claim
    against Smedvig for $540 million to recover costs incurred by Esso in completion of the vessel as well as
    consequential damages from delayed production startup. The legal complaints are under the jurisdiction of
    Norwegian law and are expected to be heard in the first half of 2000.
  • On the drilling rig side, rumors have begun circulating that R&B Falcon may be negotiating with Texaco for the
    cancellation of a 3-5 year drilling contract off West Africa for the conversion of the Peregrine VIII drillship.
    Costs on the project have jumped $105 million and delivery has been pushed back from the second to the
    fourth quarter of 1999. R&B Falcon declined comment. Under the contract with Texaco, R&B Falcon will be
    subject to a $3,000/day late delivery penalty.
    On the positive side, R&B Falcon will receive the Deepwater Pathfinder on time, and the advancement of
    delivery dates on the Deepwater Frontier and Deepwater Millennium drillships by Samsung. R&B Falcon
    International President Andrew Bakonyi speaking as part of a panel at the IADC Annual Meeting in New
    Orleans, projected average industry cost and schedule overruns of 25-30%.

Ruby Princess converted

The 140,905-dwt tanker Ruby Princess has been successfully converted to an FPSO. Keppel Shipyard of Singapore
completed the conversion for Nortrans Offshore on time. The vessel is on its way to Petronas Carigali and
PetroVietnam's Ruby Field off Vietnam. The Ruby Princess will be operated by Nortrans and serve as a base for
processing and storage of crude oil and as a mooring and loading terminal for tankers for export.

This is the third tanker-FPSO conversion Keppel has performed for Nortrans. Keppel delivered the Endeavor FPSO in
April of last year and the Petroleo Nautipa in April of this year.

Gas-to-liquids FPSO studied for production processes  

  • Armstrong Technology's Producer FPSO vessel design continues to be developed for new applications.
    Three times the UK's total gas consumption is burned off from oil fields where there is no cost-effective way
    of getting the associated gas ashore. In response, Armstrong Technology is conducting a study to develop a
    floating gas production and storage platform, which is being sponsored by the UK Department of Trade and
    Industry through a partially funded SMART research project.
    According to sales and marketing manager Colin Baker, Armstrong wants to be the first British design
    company to develop this type of platform. "There are gas-to-liquid plants on shore already, but no such
    processing facilities currently exist on offshore floating platforms," explains Baker.
    The study, which currently is in the initial concept phase, combines Armstrong Tech nology's experience in
    FPSO design and costing with the expertise of specialist gas process engineers in consultancies and
    universities. The outcome of the study will include a cost model which will allow different processes for
    exploiting natural gas reserves to be evaluated.

    Gas production and export processes being considered include:
  • A cryogenic plant to produce liquid natural gas for which there is a growing world market
  • Trapping the gas in hydrates which can be shipped ashore for subsequent release of the gas
  • Translating the natural gas into a liquid which is stable at atmospheric temperatures and pressures.

    The cost model will include design algorithms for sizing a platform necessary to support the production plant
    and to store the LNG, hydrate or liquid products. Platform size considerations also take account of motion
    requirements for effective operation of the process plant.
    While designs for Armstrong's newbuild Producer FPSO series, which has been developed for modular
    construction, have already been included in three offshore tenders, Armstrong continues to develop the
    concept further.
    For instance, the company is currently evaluating a version of the Producer with the accommodation forward
    of the turret and dynamic positioning system to suit Norwegian practices. A larger, 2 million bbl version is also
    being designed to operate in areas such as West Africa.
    Away from the FPSO market, Armstrong is diversifying into designing barges for use with tension leg
    platforms, semisubmersibles and jackup rigs. According to Baker, the complex design would act as a barge
    for 1-2% of its life, and would then be lifted to act as a process deck. The barges, while generically similar,
    are designed to individual specifications as each one is supported differently when raised out of the water.
    "The advantage of using a barge structure is that it can be brought back to shore to change modules as
    required," says Baker. "The barge design also allows for rapid fabrication in parallel with the process and
    accommodation modules, to meet the often early production targets set by oil companies.

World FPSO fleet growing with deepwater, frontier discoveries  

1998 survey shows units operating, idle, under construction

Survey explanation
•Survey - Operating [16,584 bytes]
•Survey - Operating cont., Idle, Under Construction [18,033 bytes]
•Survey - Under Construction cont., Planned/Projected [19,801 bytes]

The survey on the following pages is separated into three major sections:
  1. operating and idle vessels,
  2. vessels under construction, and
  3. projects planned and projected.
The operating section lists the vessels separated by country, and provides detailed information on the operator, size,
depth capability, field/s, processing capabilities, storage capacity, mooring system used, and whether the vessel is a
newbuild or conversion.

The under construction section lists the field, operator, water depth, installation date, shipyard performing the
construction, and whether the vessel is being converted or a newbuild. The third section, planned or projected
projects, lists the location, operator, water depth, and installation date of each project.

A total of 79 floating production, storage, and offloading (FPSO) vessels are operating, idle, or under construction
worldwide. Of the 79 vessels, 56 are operating in some area of the world. Three are idle. The UK sector of the North
Sea holds the highest number of operating FPSO units (12), followed by China (8) and Australia (5).

Various shipyards, such as Samsung, Mitsui, and FELS, currently have 20 FPSO units under construction. Eight of
these vessels are newbuilds. The remainder are conversions. Most are destined for Brazil and Norway within the
coming years.

At the present, there are 57 projects in some stage of development that are considering or planning to use FPSO's
for development. Of these 57, Australia and Norway hold the most opportunities with nine developments each under
consideration. These are followed closely by the UK (6), Angola (4), Brazil (4), and Vietnam (4).

Future growth

The FPSO fleet is expected to grow quickly in the coming years. This is due to the increased need for fast-track
development, deepwater production, and the increasing number of large fields being discovered offshore with new
technology.

To keep up with demand, operators have begun building some of the largest FPSOs ever. This is evidinced with the
recent roll-out of BP's Schiehallion, the world's largest existing FPSO, and the even larger Laminaria for Woodside,
currently set for delivery next year. However, both vessels will be dwarfed by the massive FPSO currently planned
for Elf's Girassol discovery. Construction for this vessel is planned to begin next year. There has also been talk of
another FPSO for Elf's nearby Dalia Field.

There are also a number of highly prolific vessels currently under construction in the world's shipyards. Vessels
destined for Norway's Åsgard and Pierce developments are due in the next year, as well as the FPSO for Canada's
Terra Nova development. Petrobras is also continuing its stance as an industry leaded with four vessels currently
undergoing conversion for their Campos Basin area. Other companies such as Texaco, and Shell also have projects
currently on-line and many due to begin within the coming year.

Design of FPSO systems for re-use, decommissioning  

Multi-field use requires many up-front considerations

With the popularity of purpose built floating production, storage, and offloading (FPSO) vessels, the industry needs
  1. a standardized classification process to group these vessels into handy categories that would help owners
    place them on other fields when their purpose-built job is complete.
  2. Also, helpful would be the design of these vessels with the prospect that one day modifications would be
    necessary to market the vessel.

Though the process facilities of these vessels are generally custom made for a specific application, other major
components including pressure vessels, piping, and equipment that can be used on similar fields in future
applications.

If initially designed with an eye towards an extended life, and the potential for expansion, the equipment could more
easily be converted and moved to another field with similar fluid characteristics. FPSOs lend themselves readily to
such conversions and movements because of their ship shape.

This minimizes the need for offshore work, since the vessels can quickly travel to conversion yards under their own
power and then travel to the new field. By reducing offshore work, costs are also lowered.

Vessel categories

Although topsides are generally custom-built, FPSOs can be divided between those with conventional production
systems and those with enhanced production systems:
  • Conventional systems: This type of vessel contains a production manifold, several stages of two or three
    phase separators (including a test separator), a water treatment system, gas flare/disposal system, a heat
    exchanger, crude transfer pumps, and a control system.
  • Enhanced systems: This unit features a gas compression system for gas lift, gas injection, and gas export,
    water injection system, desalters, NGL recovery systems, in addition to the conventional production system.

    In general, enhanced production systems have a large processing capacity. This means they will have more
    chances to be used again with fewer modifications. To ease the redesign process for FPSOs, the following
    recommendations should be considered in the initial design:
  • Provide space for future expansion of additional equipment
  • Provide additional space in pipe racks and cable racks
  • Provide spare I/O ports for control panels
  • Provide spare branches on piping for future connections
  • Operator's policy and preference for operation, maintenance and safety.

Engineering documents of the equipment should be checked for compatibility with the new production fluid
composition and design conditions: manifolds, pressure vessels, valves, piping, pumps, heat exchangers, water
treatment facility, flare system, gas compression system, and E&I system.

This is followed by a thorough inspection survey of existing equipment and infrastructure. Once the existing and new
requirements are investigated for suitability, a revised PFD and P&ID is developed along with the appropriate
modification plan.

The FPSO vessel is
categorized by storage capacity.

Vessel categories follow classical groups for categorizing trading tankers.
  • The small vessel category includes tankers with a deadweight range less than 90,000 tons. Crude oil storage
    capacity is less than 700,000 bbl.
  • The medium vessel category includes mostly Suez Max tankers. Deadweight range is from 100,000 dwt to
    150,000 dwt. Crude oil storage capacity is between 700,000 bbl to 1 million bbl.
  • The large vessel category includes VLCC and ULCC size tankers. Deadweight range is from 160,000 dwt to
    400,000-dwt. Crude oil storage capacity is more than 1 million bbl. In almost every case, a large vessel has
    more versatility than a small vessel.

The following requirements are key factors to judge re-usability of an FPSO vessel for a new field:
  • Operation duration requirement at the new field
  • Crude storage capacity requirements
  • Double hull requirement.

If an FPSO is judged to be reusable for the next assignment, the following factors are studied and the conversion
plan will be developed accordingly:
  • Life extension and repair
  • Conversion of offloading system
  • Conversion of tank heating
  • Conversion of safety facility
  • Regulations
  • Site environment

FPSO mooring

FPSO tanker turret facilities can vary tremendously in type, size, and function. Turret facilities may be the external
or internal type, and may be either permanent or disconnectable.

External turrets are typically cantilevered off the bow or stern of a vessel. Internal turrets penetrate the body of the
vessel and may be located near the bow, near the stern, or near amidships. In general, these turrets perform the
same basic functions although additional functions may be served.

Turret design standardization further facilitates re-use in that plans for additional, or future risers may be well
thought out avoiding the complications due to structure or piping interference in a future modification.

Swivel and piping/manifold requirements are usually too field specific to employ much planning for reuse. However
space-control planning, similar to topsides space planning, will aid in future modifications. Standardization of swivel
mounting interfaces will aid swivel stack changes.

Turret re-utilization

Given that the most basic capabilities of a turret are governed by load capacity and riser space availability, turrets
may be categorized accordingly:
  • Load capacity: Turret load capacity may be categorized as either low load capacity or high load capacity for
    simplicity. Low load capacity may be considered when the total maximum resultant load due to off-vessel
    moorings plus risers is less than approximately 1,200 tons.
  • Riser capacity: Turret categories based on riser capacity are: few risers, less than 10; moderate number of
    risers, between 10 and 25; and many risers, greater than 25.

Realizing that the turret forms a plan of the flow path, a review of the new field key parameters to assess turret
system suitability will include most of the key parameters.

The turret system piping, manifold, swivels, and safety features must be evaluated for compatibility with the new
field requirements following a thorough inspection to determine the existing condition.

Evaluation of the swivels, piping, manifold, and other components must consider materials, corrosivity, pressure,
size, and pigging requirements.

Other factors involved in the process of decommissioning and re-use include the following:
  • Decommissioning: Prior to disconnection of the mooring and riser systems, the machinery related to anchor
    leg or riser installation/deinstallation is reconditioned.
  • Refurbishment, conversion: Turret system refurbishment is best carried out at a shipyard. Drydocking may
    be required depending on the modification plan.
  • FPSO mooring: Anchor leg patterns and component sizes, grades and lengths are generally specific to a
    certain site.

However, with proper consideration of corrosion, wear, fatigue and handling, modern anchor chain and wire
components may be considered for reuse. FPSO mooring systems may be categorized as all-chain system,
combination system, and polyester system.

The following are key parameters for judging the re-usability of the off-vessel mooring components:
  • Field life: Is residual life adequate for new field life?
  • Strength: Is size and grade of materials adequate?
  • Design temperature: Is the vessel and component material suitable?
  • Installation equipment: Can it be properly handled?

Anchoring components

Anchor chain may have been used many times, although this is seldom the case for an FPSO permanent mooring
system. However, inspection programs to re-certify anchor chain exist and should be adopted or modified to meet
the new field's functional requirements.

Careful planning for the recovery of the anchor legs must allow for handling operations, which will not damage the
components. Generally, these procedures may be a reversal of the original installation procedures. Any wire rope to
be considered for reuse must be very carefully handled especially when handling the spelter ends to avoid
overbending of the wire rope.

Risers

Typically risers are custom designed for a specific site. The design of the structure and the configuration is a
complicated function of fluid service, site, water depth, environment, and flowing vessel response characteristics.

However, careful design in the choice of riser configuration, size and interface between vessel and the wellheads can
allow the re-utilization of the FPSO without major modifications at the riser interface.

In the initial design, it is important to properly design the structure and configuration to enhance the potential for re-
use. Configurations like the lazy wave and free hanging cantenary risers are more readily adaptable to re-utilization
as the riser forms part of the flowline after touchdown; thus the length of the riser is not too dependent on water
depth.

The following are key parameters for judging the re-usability of the riser system:
  • Service life: Is the residual life adequate for the new field life?
  • Type of service: Is the product type similar, sweet or sour?
  • Design temperatures and pressures: Is the riser structure suitable?
  • Site particulars: water depth and metaocean environment?
  • Riser configuration: Does the riser configuration allow for use at another site?
  • Installation equipment: Can it be properly handled?

A thorough inspection plan must be carried out on the recovered riser. This includes the end fittings, external sheath
wear, external buoyancy modules, and possible NDE inspection of the inner carcass. Re-certification of the riser by
the riser manufacturer or the certifying authority may also be required.

A detailed inspection plan with specific reject/accept criteria must be developed with the riser manufacturer and/or
classification society for the new field. A detailed examination of the external sheath and the end fittings will be
required. Buoyancy modules will need to be removed, refurbished, and replaced during re-installation.

Subsea systems

Because subsea systems are a packaged system, they incorporate intricate machined hardware sized for the flow
rates, well shut-in pressures, installation vessel interfaces, and intra-field connections.

Suitability of subsea hardware for decommissioning and re-use is primarily a function of valve size, material class,
and its remaining useful design life. Another obstacle to re-use may be the tree's flowloop configuration and the
number of valves as it passes from one field's requirements to another.

Subsea trees can be broken down into
four major types and two sub-categories: water depth and trim. Water depth
is the primary category for describing the type and complexity of a subsea system:
  1. Mudline: <120 meters. mudline systems are simple designs, with stacked valve configurations, and rely
    heavily on human intervention to connect equipment together and play a key role in subsequent interventions
    and decommissioning.
  2. Diver assist: <200 meters. diver assist systems are rudimentary, but a little more complex and larger in size
    because they are usually placed on top of subsea, floating drilling, wellheads.
  3. Diverless: 200-800 meters. at around 200 meters, the economics of diver intervention verses remote
    operation give way to our third group of subsea trees, diverless systems. these trees, as their name implies
    uses rot's and rov exclusively to perform all installation and intervention tasks.
  4. Guidelineless: >100 meters, but usually >800 meters. This last group of subsea trees is the guidelineless
    tree. These trees are also diverless, but they do not require the four guidepost/guideline guidance from
    surface to the subsea well site, as the others.

Mudline trees are, by definition, smaller, minimal wall thickness design systems. Their designs are more susceptible
to metal loss and pitting corrosion because of the minimal wall thickness unless CRA's are used. They also are
limited in production capacity because of smaller bore configurations.

The other three subsea tree categories are typically designed with composite valve blocks, offering considerably
more metal which is available for metal loss without sacrificing pressure containment or pressure control for longer
design lives at the lower trim levels.

Diverless trees are probably the most versatile since remote intervention can be accomplished from many different
types of vessels in a wide variety of water depths.

Other equipment

There are three other subsea equipment areas that should be mentioned which could affect successful reuse:
wellheads, foundations, control systems, and flowline connection techniques.

Mudline wellhead systems are designed with below mudline abandonment in mind. They unscrew the landing string
from the casing hanger joints inside the well, and leave the rest behind. Subsea, floating drilling, wellheads have the
high pressure and low pressure housings recovered during abandonment work.

Reworked wellheads and housings are cost effective for drilling programs where a single wellhead may be used for
three or more successive drilling programs over a short period of time. Many subsea completions specify metal
sealing equipment. If so, seal bores in a wellhead only need to suffer minor corrosion or mechanical damage to
prohibit its reuse.

Mudline trees can fit on most mudline wellheads since the completion interface usually consists of casing joints
threaded together between the mudline wellhead's landing sub and the tree completion hardware. Therefore reused
mudline trees can be used on a number of different mudline wellhead systems so long as the casing program is the
same.

Subsea wellheads are a different matter. Subsea wellheads have an external profile in one of two categories, clamp
hub, or mandrel profile. The subsea tree has a special hydraulic connector that fits over and locks onto one of these
external profiles.

Subsea foundations are designed to structurally support subsea equipment on the seafloor for the life of the field.
Several systems are in use today, including drilled or hammer founded piles, flat mudmats and skirted mudmats,
auger bit anchors, caisson silos, and various suction anchor designs.

Subsea control systems are a wild card when considering decommissioning and re-use. There are three basic types
of subsea control systems: direct hydraulic, piloted hydraulic, and various forms of electro-hydraulic controls.

Flowline and umbilical decommissioning and reuse should address a fundamental question at the beginning of an
FPSO project, "Can, or should, the intra-field flowlines be abandoned in place, or should they be recovered for
economic and/or regulatory reasons?"

Removing a diver installed spool piece between the end of the flowline and the tree is the simplest method to
decouple and recover the two subsea components separately. If an operator wants to re-use existing equipment, he
either:
    1.Builds in all the "what ifs," paying a higher price for it at the front end of the project;
    2.Pays for an overhaul of the tree to change its configuration, trading off newbuild costs for refurbishment
    costs;
    3.Works hard to operate within the limits of what is given him and work around potential equipment
    limitations.

Subsea decommissioning

Subsea hardware decommissioning is accomplished during well abandonment. After the well is controlled and killed,
cement is usually circulated into the well through prepared perforations in the tubing string.

Once the well is dead, the flowlines and associated subsea hardware, such as subsea manifolds, flowline connection
hardware, and other components are circulated with water. By pumping from the FPSO to the tree and drilling vessel
or from the drilling vessel to the FPSO, all equipment is purged of hydrocarbons and allowed to flood to hydrostatic
pressure.

Then, flowline and control umbilical connections are disconnected and the subsea tree is recovered. Subsea
wellheads are then cut approximately 3 meters below the seafloor and pulled up as a single salvaged unit; wellhead,
guide bases, casing hangers, packoffs, and casing joint stubs. All remaining subsea hardware is either removed from
the seafloor, or abandoned in place, depending on local regulation requirements, water depth, proximity to shipping
lanes or anchorages, and abandonment costs.

NEW VESSELS, RIGS & UPGRADES  

•Ramform B380 FPSO destined for Conoco's Banff Field. [26,937 bytes]
•Geco-Prakla's SS2000 seismic vessel. [26,158 bytes]
•The Berge Hugin - to be converted to an FPSO. [17,297 bytes]

Ramform Banff FPSO ready

Hyundai Mipo Dockyard has delivered the first FPSO of Ramform design to PGS for use in Conoco's Banff Field in the
UK sector of the North Sea. The Ramform B380 measures 120 meters in length with a stern beam of 54 meters. This
allows for a large deck with a load capacity up to 16,000 tons. Excluding topsides modules, the light ship weight is
10,000 tons and is expected to produce 95,000 b/d of oil with a 120,000 bbl storage capacity.


The FPSO also features a unique hull design that allows the vessel to maintain bow to weather with minimal thruster
power. An aerodynamic flare tower equipped with a rudder augments the thruster to assist in trimming of the
vessel's heading. Work on the B380 began in the first quarter of last year and was completed in 13 months, ahead of
the planned schedule. The vessel has since been moved to the McNulty yard in the UK for hookup and installation of
the topside production modules and other deck fittings. Upon completion it will head to the Banff Field to begin
operations.

Pierce FPSO conversion

Work to convert the multipurpose shuttle tanker Berge Hugin to an FPSO for use on Enterprise Oil's Pierce
development in the UK North Sea has begun. The preliminary work is being carried out at the Blohm & Voss yard in
Hamburg, Germany where the processing facilities are being installed.

The work at the Hamburg yard is expected to be completed in 5-6 weeks, after which the vessel will be transferred
to the Aker McNulty yard in the UK for fitting of the processing equipment. The vessel is set to arrive on the field in
May at which time the submerged turret production buoy and its associated mooring system (supplied by Hitec
Marine) will be installed.

The Berge Hugin, owned 50% by Navion, a subsidiary of Statoil, and 50% by Bergesen shipping group, was the
world's first multipurpose shuttle tanker when it was delivered in February of last year. Enterprise has contracted the
vessel for five years plus the option for extensions following the conversion. Production on the Pierce Field is
expected to begin on the first of July.

North Sea constructors braced for new period of uncertainty  

Conflicting political messages temper optimism over development prospects

Esso's Balder floating production unit arriving last summer at UIE yard in Glasgow. UIE is one of several British
yards which has adapted its facilities in response to the growing demand for FPSOs in the North Sea.

Europe's fabrication yards are in an awkward situation. Even when order books are full, few emerge in real credit. In
northern Europe, the yards have raised profits through alliance or risk-reward arrangements, only to see them
diluted through cost-cutting crusades such as Crine (UK) or Norsok (Norway). As yards cut costs, producing
companies reap the benefits.

Despite the constant pressures, few of these facilities have folded in recent times. But there are awkward times
ahead, caused by a new set of threats:
  • Steep drilling rates in the North Sea, as elsewhere, are offsetting the gains derived from the cost-cutting
    initiatives. This may persuade some of the majors in particular to switch to other areas of the world where
    offshore development costs are less punitive
  • Norway's new coalition government has raised eyebrows by threatening to pull back Norwegian oilfield
    development in the next century.
  • For environmental reasons of its own in the UK, the Labor government reacted to an SOS from English coal
    mines by putting the brake on new gas-fired power stations.
  • Demand for gas platforms has been the salvation of certain UK yards in recent times. A review of the
    offshore taxation regime also is under way which could increase government revenue from oil and gas
    activity at the expense of oil industry commitment to Britain.

Whether these changes will come about is questionable. Labor is committed to reducing UK greenhouse emissions
20% by 2010, which seems hard to achieve through upping coal-fired power. In Norway, the nation's overwhelming
reliance on the oil and gas industry for its high standard of living may sweep aside the intentions of the minority
government.

A table in this report from London-based field analysts ScanBoss shows that most of the yards in Norway have solid
orders through 1999 or even 2000, due to the upsurge in large Norwegian field developments. UK North Sea activity
remains high too, but the average development is much smaller, leading to construction contracts of much shorter
duration. As a result, several UK yards face "house empty" signs from this summer onwards.

Downsizing

Until the industry finds a way to harness the stranded gas off western Britain, new giant-size platforms are not
expected. Several mid-range installations could go out to tender this year; however, for projects such as Texaco's
Captain Phase II, Amoco's planned Appleton/Halley area hub, British Gas' Moray Firth discoveries, and possibly BP's
Clair.

The bigger yards with higher overheads will hope to snap up this work, and also will compete with the mid-size yards
for the next wave of unmanned/compression platforms planned for the southern gas basin. Richer pickings will be
headed by British Gas' multi-platform Easington Catchment Area scheme.

A few facilities remain out-and-out jacket specialists, but the majority are now equipped to handle fast-track FPSO fit-
outs. The number of new FPSOs may be curtailed, however, especially with two older facilities approaching
availability as their fields wind down, such as Agip's Balmoral and Talisman's Blenheim. Talisman acquired this
declining field recently from Arco, but there are suggestions that its floater, the Petrojarl 1, may already be
earmarked for Fina's Otter development, due onstream in 1999.

Some of the better-placed yards in the scramble for FPSO topsides could be those sites acquired by Norwegian
companies. The most successful in volume terms has been Aker McNulty in South Shields, which has Kerr-McGee's
Janice, Conoco's Banff and Enterprise's Pierce all booked in the coming months. This heady period is causing the
company to almost quadruple its workforce from 400 in early 1997 to 1,500 this year.

Kvearner Oil and Gas on Teesside picked up the major fabrication job, for Amerada Hess/Shell's Bittern floater, but
also benefited from the work overload in Norway when it was awarded Esso Norge's Jotun drilling module.

The most far-thinking yard in Britain may be Harland and Wolff in Belfast, where the current workload includes
upgrading of two Dolphin semisubmersibles and the design of one or two deepwater DP drillships for Global Marine.
A full construction contract is expected by December. The yard is also promoting the Fobox, a new design for a
drilling, production and storage vessel able to work in waters down to 3,000 meters deep.

One of the positive trends for Britain's fabrication industry is the quickfire shuffling of acreage. Some of the majors
are trading blocks containing marginal oil discoveries in return for a position in more voluminous gas acreage. The
takers are often North American companies, anxious to speed up the development process. They prefer their oil out
of the ground.

Among the recent transactions which could galvanize slow-moving projects:
  • Bow Valley Energy and Morrison Middlefield Resources bought British Gas' 27.5% interest in Block 22/2a,
    containing the 1986 20 million bbl Chestnut discovery, and an identical stake in a similar size reserve just to
    the south. Although the fields lie just 5 km from Chevron's Alba Field, operator Premier is thought to favor a
    standalone FPSO.
  • Last October, Burlington Resources bought numerous British Gas interests in the Irish Sea for $157 million.
    These include seven undeveloped gas discoveries containing estimated reserves of over 700 bcf - the five-
    field ORivers' cluster, which are high in hydrogen sulfide, and the sweeter gas of the Dalton and Millon fields.
    Existing production complexes are handily nearby, such as Centrica's Morecambe North and BHP's Liverpool
    Bay. Millon could be tied back initially to Morecambe North this year, followed by a second phase involving a
    dedicated platform.
  • The Beryl Field consortium of Mobil, Amerada Hess, Enterprise, and OMV recently bought Conoco UK's entire
    assets in Quadrant 9. These include the Buckland, Sorby, and Maclure oil discoveries, the first two of which
    may be tied back subsea to the Beryl platform facilities. Maclure could be developed as a satellite of Gryphon
    Alpha, prolonging the life of that field's FPSO, but an alternate host could be BP's Harding platform 10 km
    away.

FPSO hulls, turnkey services preoccupy Norwegian yards  

No slowup in floating and development technology

Norway's offshore fabrication yards are working near capacity, but it is unclear at present how long the boom will
last, especially in the light of the new government's declared intention to slow the pace of development activity.

At present, there is no lack of potential future development projects, which suggests fabrication demand should
remain at a high level over the next couple of years. Floaters continue to make up the bulk of upcoming projects.

Saga shortly may award a contract for a large - around 23,000 tons - semisubmersible unit for Snorre North. This
installation, Saga promises, will be crammed with environmentally sound technology.

The same operator also is in the early stages of planning the complex Halten Bank South development, including a
large TLP on Kristin to which subsea completions on Lavrans, Tyrihans and Trestakk will be tied back.

Other possible floaters include dedicated oil FPSOs on Statoil's Midgard and Snoehvit fields, an FPSO on Norsk
Hydro's Gjoea Field and a semisub for the same operator's Fram.

Fabrication contracts for water injection platforms for Phillips' Eldfisk and Amoco's Valhall fields may have recently
been awarded.

Bids also have been submitted for Statoil's Huldra wellhead platform - the field is currently planned to start
production in 2000.

Amerada Hess is expected to invite bids soon for a small wellhead platform for Mjoelner

Other projects expected to be launched in the next year or so include Statoil's Sleipner Theta West and Glitne and
Hydro's Grane - each case, probably will require a process platform and a wellhead platform.

A large - 6,500 tons - gas processing/export module is under consideration for the Heidrun platform, and an
additional module likely will be needed on Statoil's Troll A platform.

Awards for all these outstanding items could come through by 2000 - unless the new Norwegian coalition
government decides to apply the brakes. However, the new government does not command the overall support of
the Storting (parliament), where most members are believed to back the previous administration's policy of letting
the industry dictate events at its own pace.

In contractor circles, the feeling is that any slowdown most likely will hit development activity in the longer term
through postponement of future licensing rounds.

Other factors also are having an effect: The gas supply committee has postponed the next allocation round by 7
months to September 1998, due to the more than ample flow of supplies from existing and planned fields. This
means authorization for new developments will slip into 1999, possibly hitting projects such as Halten Bank South.

Mid-Norway potential

Despite the high level of current yard occupation, fabricators - most of which belong to groups with integrated
contractor capabilities - are jockeying for position to bid on upcoming projects.

A relative newcomer is Reinertsen Vigor, a yard located at Orkanger in mid-Norway, and a member of the
Reinertsen group. This yard wants to play a major role in mid-Norway developments such as Halten Bank South and
any others that arise from the current deepwater exploration campaigns in these waters.

Though not of a size to take on the role of main contractor for a development project, Reinertsen is aiming for
turnkey responsibility for sub-projects. "Give us the functional specifications and we will come up with the most cost-
effective solution," says Geir Suul, managing director of the yard. He claims that fabricators' margins currently are
too small to make a purely sub-contract role worthwhile.

A combination of niche expertise and partnering is the direction Heerema Toensberg has chosen. This company has
a strong track record in wellhead and water injection platforms, including on a turnkey basis. It also is willing to work
as a partner alongside a main contractor, according to Marketing Manager Harald Svensen.

The big yards also are enhancing their turnkey capabilities - both Aker Maritime and Kværner have reorganized their
operations along more cost-efffective, "customer-friendly" lines. They also have joined forces to bid for the Snorre
North project, a move prompted primarily by lack of available engineering capacity.

Their sole rival for this contract is the Umoe group, which additionally intends to compete with the big guns on the
FPSO front. Currently it is looking for a yard in Europe in which to build hulls. This is the one major item missing
from Norway's system, but both Aker Maritime and Kværner own yards in Finland which can handle this task.

Presently, the Norwegian fabrication sector is so busy that in recent months a number of contracts have had to be
placed abroad. For instance, the 3,000-ton drilling module for Esso Norge's Jotun project was directed to Kværner's
Teesside yard in northern England, while the 4,000-ton separation module for Statoil's Åsgard B went to Italian joint
venture SaiRos.

Outsourced construction management enhances offshore projects  

Effective integration of a construction management team (CMT) can enhance an operator's ability to achieve on-
time, on-budget completion of an offshore project.

The Tantawan and Benchamas fields, offshore Thailand, are examples of two projects that benefited from the CMT
concept. In these projects, the CMT assumed a high level of authority and responsibility, while ensuring frequent and
productive communications among team members.

Outsourcing

The industry's increasing need for cost and time efficiency is encouraging exploration and production companies to
outsource construction management services from conceptual design through production start-up. Careful selection
of a CMT can enhance an operator's capabilities through successful integration of key expertise into the operator's
decision-making loop.

The CMT can develop an understanding of the operator's objectives, and the operator can then rely on the
integrated team to act in its best interest and make purposeful, proactive decisions on behalf of the project.
Importantly, the CMT can use front-end planning to define project requirements properly, initiate a competent
execution plan, and implement an effective contracting strategy.

Upon project completion, the operator has a successful project and access to a highly experienced, close-knit team
that is available for assignment to a new project anywhere in the world.

Pogo Producing Co., a Houston-based independent oil and gas company, relied on Paragon Engineering Services
Inc.'s construction management capability successfully to complete two Gulf of Thailand projects.

Pogo does not maintain a large, dedicated facilities-engineering staff because it prefers to focus on its core strengths
of reservoir and geophysical interpretation, drilling, and production. The operator contracts with qualified US Gulf
Coast service providers for facilities engineering and construction services.

Pogo relied on Paragon to create a construction-management team that would bring cohesiveness and accountability
to a diverse group of project participants. Key areas in which Paragon had significant impact through the
development of a CMT included:
  • Effective, competent, and timely decision-making from a small team with a high level of authority.
  • Good decisions resulting from open discussions and consideration of all project participants, including the
    operating company, process engineering, fabricators, installation contractor, and operating staff.
  • Effective management of the interfaces between the various contractors.

Pogo first contracted with Paragon to help it meet cost control and schedule objectives on its Tantawan field
development. This development included a floating production, storage, and offloading (FPSO) vessel with tie-ins
from two remote wellhead platforms.

Pogo became operator of Block B8/32 in 1995 and commenced gas and condensate production from the block's
Tantawan field in January 1997. The gas is consumed in Thailand.

Pogo and Paragon then immediately began work on the Gulf of Thailand Benchamas field development, also in Block
B8/32, through the creation of the Benchamas construction management team. The seamless integration of the CMT
into the full project infrastructure facilitated Pogo's June 1999 start-up of the Benchamas field (Fig. 1).

The associated facilities are the culmination of extensive planning, design, and construction efforts. The facilities are
designed to process 180 MMscfd, 35,000 bo/d, and 25,000 bw/d.

Development of the Benchamas field commenced in December 1996. The Benchamas field was designed as a gas
field with associated oil production.

Given the levels of responsibility and authority involved, team members committed to international travel on short
notice and working on the project through commissioning and start-up. This continuity of team members and their
willingness to travel played a key role in the successful completion of the Benchamas project.

The CMT approach thus eliminated transition problems as the project progressed from design through fabrication to
installation.

Paragon's CMT reported to Pogo's vice-president of operations and had considerable authority over technical
decisions; however, the team did not have financial authority.

The CMT worked closely with Pogo's Houston office and Thaipo Ltd., Pogo's 100%-owned subsidiary based in
Bangkok. The CMT supported Pogo in discussions and facility-related negotiations with working interest owners,
contractors, and vendors. The CMT was in effect an extension of Pogo, and its members acted in Pogo's best interest.

The project was divided into four sequential phases:
    1.Conceptual engineering.
    2.Bidding and contracting.
    3.Detailed engineering and fabrication.
    4.Installation, commissioning, and start-up.

Companies involved

The CMT dedicated 4 months to development of a conceptual design that accommodated the needs of Pogo's drilling
and reservoir staff, facilities process equipment, fabrication, and installation.

Pogo's significant investment provided a solid basis for bidding along with a preliminary design that could be
completed by the available engineering, procurement, and construction (EPC) contractors.

The team issued bid documents, evaluated proposals, and negotiated construction contracts for Pogo's approval.
Over the life of the contracts, the team resolved both technical and commercial issues with contractors.

It reviewed all invoices and negotiated change orders and made approval recommendations to Pogo as needed. It
also generated monthly cash call estimates and status reports for Pogo and its partners.

Pogo relied on numerous EPC contractors with extensive experience in Southeast Asia to construct the facilities for
the Benchamas field. The facilities were divided into several large, lump-sum EPC contracts, as follows:
  • Compression modules-Dresser-Rand.
  • Generation module-Solar Turbines.
  • Quarters module-Hyundai Heavy Industries/Southport.
  • Wellhead platforms-Nippon Steel.
  • Process and quarters platforms-Hyundai Heavy Industries.
  • Infield pipelines-Nippon Steel.
  • Floating storage and offloading vessel-Tanker Pacific
  • Sales gas pipeline-Nippon Steel.

Project interface

Each of the contractors selected and subcontracted detailed engineering to complete the design and create
construction drawings. CMT members were stationed on-site in the engineering companies' offices to expedite the
decision-making process. The team participated in the review process with the engineering subcontractors.

A key function of the CMT was effective management of the interfaces between contractors. Daily, direct
participation also ensured thorough review of construction drawings. These were normally studied two or three times
prior to issue for construction.

Importantly, the team handled drawing reviews in a timely manner, with turnarounds usually completed in less than
48 hr. It tracked progress of the overall project based on individual contract milestones, focusing on the contracts
that threatened to fall behind schedule. The team also maintained complete project records files with
correspondence and progress reports from all contractors.

The CMT created and issued a start-up, commissioning, and operating manual to integrate the operation of the
facilities throughout all contracts. Continuity of the team provided a high degree of insight regarding details of the
process and utility operations.

Close coordination among the CMT, Pogo, and Thaipo allowed direct participation in development plans of the
Benchamas field and surrounding fields.

Philosophy

The construction philosophy for the Benchamas facilities held personnel safety and care for the environment
paramount. To meet cost-control requirements and gas-delivery schedules, the construction philosophy for the
Benchamas field facilities hinged on off-the-shelf industry design standards.

Pogo's delivery date for designated contract gas quantities to Thailand was fixed, and well-test data were limited. In
addition, flexibility was key because platform locations were not finalized. The CMT proposed and obtained Pogo
approval of facilities to meet all requirements of the overall field development plans.

Along with flexibility, Pogo desired ease of operations. This requirement led to the extensive use of manufacturers'
standard packaged equipment, which was certified by an independent third party to meet project specifications and
industry standards.

While many utility packages had small programmable logic controllers (PLCs), local pneumatic control was used on
all process equipment except for the more sophisticated turbine-driven compressors and generators.

A number of elements led to the success of these projects. These are listed in the box.

Opportunities for improvement

While hindsight is 20/20, the CMT learned a number of lessons that could be applied in future projects.
  • To facilitate efficiency, future projects should ensure that contractors select subcontractors prior to contract
    execution.
  • Also, early in a project, all contractor and subcontractor electronic data systems should be reviewed to
    ensure compatibility.
  • Most importantly, electronic drawing file format conversion accuracy between engineering and fabrication
    contractors should be verified.

The CMT was initially hesitant to use overseas fabrication shops for vessels and major equipment. But because US
fabricators selected by overseas contractors experienced major delays, the CMT eventually allowed overseas
contractors to use their more familiar overseas fabricators.

Other good ideas worth considering on future projects include:
  • Indexed electronic files for all drawings and all available calculations on compact computer disks (CDs) for
    final documentation.
  • General specifications issued on CDs.
  • Digital cameras in fabrication yard.
  • Free, web-based e-mail accounts, such as Hotmail, for overseas team members.

Vibration suppression critical in FPSO design, offshore Thailand  

The Tantawan Explorer is a floating production offloading vessel recently installed in the Gulf of Thailand.

Alleviating potential vibration problems from seven 2,000-hp reciprocating gas compressors was critical in the design
of a floating production offloading vessel (FPSO)
for the Tantawan field, offshore Thailand. According to Alliance
Engineering Inc., which developed the design basis for the project, early recognition of the problem allowed the
project team to design the facility to prevent any such problems from occurring once the FPSO began operating in
about 400 ft of water.

Tantawan Service LLC, an affiliate of Pogo Producing Co., owns the FPSO. Thaipo Ltd., another unit of Pogo
Producing Co., operates the Tantawan field, which is in Block B8/32 of the Gulf of Thailand, 250 miles south of
Bangkok.

The
conversion of the 1 million bbl oil tanker into the FPSO, Tantawan Explorer, was part of a project that also
included four drilling/production platforms and associated subsea pipelines. The tanker was converted at the
Sembawang shipyard in Singapore.

Alliance says the project commenced in May 1995 and was completed in March 1997, ahead of schedule. Alliance
worked as a subcontractor for Intec Engineering Inc.

The facilities are designed for a production rate of 200 MMscfd and 50,000 bo/d.

Use of floating production systems escalates  

There are 107 floating production systems (FPSs) in operation worldwide-an increase of 67% over the number
operating 3 years ago. And this increased growth is expected to continue into the next decade.

The 3-year increase in the global FPS inventory was reached through the installation of 49 units: 22 floating
production, storage, and offloading (FPSO) vessels, 9 production semisubmersibles, 3 tension-leg platforms (TLPs), 2
mini-TLPs, and 2 production spars.

These are among the findings of a study by International Maritime Associates Inc. (IMA), Washington, DC.

"...We see no slowdown of growth in this sector," said IMA. "Our forecast calls for the inventory of operating units to
grow 48-66% between 2000 and 2005, requiring orders for 62-84 FPSO vessels, production semisubmersibles, TLPs,
or spars over the next 5 years."

"In March, we said the economic typhoon that triggered the downturn in the offshore sector was passing and oil
producers had reached a position where they could control output," said IMA. "We also said the combination of
increased demand and more tightly controlled production would lead to an increase in oil prices by mid-year."

Operators now have orders in for 21 additional FPSs and 5 FSOs. "This total is two fewer production units and one
less storage unit than reported in our March update, reflecting the slowdown in offshore activity over the past 18
months," says IMA.

The 26 production and storage vessels on order include: 13 FPSOs (7 new, 6 conversions or upgrades), 5 production
semis (3 new, 2 conversions), 1 large TLP, 1 mini-TLP, 1 production spar, and 5 FSOs (1 new, 4 conversions). The
delivery of the units on order would increase FPS inventories by 20%, and capital expenditures for these new
systems would total $17.3-23.8 billion, says IMA.

Long-term outlook

"The current list of projects being planned or under study is a substantial increase over the 188 projects identified in
our March update," said IMA, "which seems to indicate that interest in projects involving floating production continues
to be strong, despite the downturn in actual orders over the past several months.

"Proceeding with individual projects will hinge on the economics of the discovery, which in turn will be influenced by
the expected price of oil and project development cost. Not all will materialize, and in some cases another production
solution will be selected. And there are undoubtedly other projects in the planning and study phase where
information has not yet been publicly released."

Sakhalin Energy Becomes First Offshore Producer In Russia  

Sakhalin Energy Investment Co. Ltd. (Sakhalin Energy) expects to begin production this month in the Sea of
Okhotsk, becoming the first company to develop a Russian offshore field.

The company will also become the first foreign enterprise to develop oil and gas resources in Russia under the new
production-sharing agreement (PSA).

There are two Sakhalin II PSA License Areas, each covering a large field discovered in the 1980s.

Field development

With a net-to-gross ratio of 75%, this gives an average reservoir net pay of 1,000 ft. This thick structure, together
with high permeability, results in high delivery capacity, with individual production rates of 160 MMscfd. Sixteen
reservoir layers are hydrocarbon bearing, of which 15 have been proven to be productive by drill stem tests. Typical
pay thickness per layer is about 100 ft.

The reservoirs at Piltun-Astokhskoye include shallow-marine sands of the Upper Miocene Nutov formation.

Each sand layer is made up of interbedded sands and silts usually dominated by fine to medium-grained sandstone.
Ten sand layers contain oil with or without gas caps, while one layer is gas bearing. Typical pay thickness ranges
from 20 to 100 ft.

Altogether, hydrocarbon production could ultimately reach 200,000 b/d of liquids and 2 bcfd of gas, once both fields
are fully developed.

The development of these hydrocarbon resources will require a unique combination of engineering and multinational
teamwork. Work on this challenging project began with Phase I of the P-A (Piltun-Astokhskoye) field development,
as described in the following.

Vityaz production complex

The Sakhalinskaya Oblasts regional governor, Igor Farkhutdinov, helped Sakhalin Energy find an appropriate
identification for the new complex, naming it Vitgaz-the "Honorable Warrior." This name highlights Russia`s view of
this vital project.

The complex includes a:
    1.Production platform PA-A, located in the Astokh portion of the Piltun-Astokhskoye field, about 12 km
    northeast of Sakhalin Island
    2.Single-anchor leg-mooring (SALM) buoy
    3.Floating-storage offloading (FSO) tanker.

To provide additional accommodations and work space for the hook-up and commissioning of the process facilities
on the platform, the jack up drilling rig Sakhalinskaya has been temporarily positioned alongside, connected by a
gangway. The equipment, materials, and personnel required to "frac pac" the first group of producing wells will be
located aboard Sakhalinskaya, reducing interference with the hook-up and completion work on the production
platform.

The Molikpaq

Molikpaq, built in 1984, had been mothballed since 1990, but the Sakhalin Energy survey team found it in good
overall condition. Independent surveys performed by the Classification Society, American Bureau of Shipping (ABS),
and Russian experts also declared Molikpaq to be structurally sound and fit-for-purpose.

Nevertheless, Molikpaq`s new working environment necessitated redesign in some key areas. This included:
  • The addition of a substructure necessary to elevate Molikpaq above sea level in the deeper waters of the Sea
    of Okhotsk.
  • Structural improvements to support drilling up to 32 wells to measured depths of 6,000 m.
  • Extensions to the rig's wave deflectors.

Conversion of the mobile exploration drilling rig to a permanent drilling and production platform required the addition
of a 2,600 metic ton processing module to stabilize 90,000 bo/d for export and to treat and compress 70 MMcfd of
produced gas for reinjection into the reservoir, until gas export commences Seismic activity, wave loading, wave run-
up, and ice conditions represented the major metocean and environmental conditions that would affect Molikpaq`s
arctic platform design. These issues dictated the requirements for model testing to ensure its structural integrity in
its new environment.

The Sakhalin project team first applied physical hydraulic models to evaluate the feasibility of deploying Molikpaq in
this severe metocean setting. The models then assisted in adapting and optimizing the platform design.

Sand berms had been used to elevate Molikpaq on previous deployments in the Beaufort Sea; however, it was
questionable whether the large quantities of sand and rock required for a berm could be installed during the Sea of
Okhotsk`s short weather window. Sakhalin Energy also wanted to minimize the environmental impact of dredging.

Spacer

As a result of these considerations, the decision was made to construct a steel spacer between the sea floor and
Molikpaq (Fig. 5). Model tests proved that such a structure, engineered for the environmental conditions, would
provide better wave-loading characteristics than a sand berm.

The Rubin Central Design Bureau for Marine Engineering in St. Petersburg designed the spacer while the Amur
Shipbuilding Plant fabricated the 14,200 metric ton spacer. Prefabrication of the four block sections was carried out
in Komsomolsk and final welding of the spacer was completed after transportation down the Amur River to Bolshoi
Kamen.

The octagonal-shaped spacer measures 110 x 110 m and included three temporary stability towers and a
hydraulically operated valve system for gravity ballasting, removed after mating with Molikpaq.

Seven J-tubes were installed for oil and gas risers, water injection, pipeline, and umbilicals. The spacer design met
the Russian Maritime Register of Shipping (RMRS) requirements. Additionally, the American Bureau of Shipping
(ABS) reviewed the design with conformance calculations abiding by their Mobile Offshore Drilling Unit Classification
Rules.

Top side

In parallel with the spacer design and fabrication, the design and fabrication of the top-side modifications were also
undertaken. These essentially consisted of a new process module needed to accommodate oil-treatment equipment
for up to 90,000 bo/d, plus facilities for gas injection and oil export to the FSO vessel.

To further accommodate the required 32 well slots, extensions were made to the existing 8-slot arrangement. The
drilling unit was also raised 5 m to provide space for production wellheads that were not required for Molikpaq`s
previous service in Canada.

To withstand the high wave-slamming forces in the Sea of Okhotsk, the existing wave deflectors were also
redesigned and significantly enlarged. To overcome abrasion from ice flows for 6 months of the year, an 8-mm
carbon steel plate was added to the caisson structure`s ice-abrasion zone. Additional stiffening was also provided for
earthquake loading.

J. Ray McDermott Engineering LLC and Tri Ocean Engineering Ltd. performed the detailed design of these top-side
additions along with designing the refurbishment work in the drilling area. Sandwell Engineering Co. designed the
wave deflector modifications. The fabrication and refurbishment work was contracted to Daewoo Heavy Industries in
Okpo, South Korea, under separate competitive tenders.

Molikpaq`s outdated safety systems were also replaced and upgraded with newer technologies. These included
additional fire-fighting and emergency-escape capabilities and the addition of a temporary safe refuge. Similarly,
existing telecommunication systems were replaced with new equipment.

Generally, the drilling equipment was in good condition although it was necessary to replace or refurbish some
equipment. This included replacement of the shale shakers, diverter system, top drive, cementing unit, and the wire
line logging unit. The drawworks and rotary table were refurbished and the blow-out preventer was upgraded.

After review by Russian Institutes, the drilling rig and wellheads were further elevated to provide additional blast
relief as a risk-reduction measure. This required elevating two of Molikpaq`s three main pedestal cranes to maintain
structural clearance.

Narrow weather windows

Arctic conditions placed strict limitations on the project schedule. For example, the project had several narrow
weather windows for towing activities, that if missed, could have delayed the project by a full year.

First, Molikpaq itself had to be towed more than 4,000 nautical miles from the Canadian Beaufort Sea to the shipyard
in Okpo, South Korea. It was also necessary to tow the spacer sections down the Amur River to Bolshoi Kamen for
assembly before it froze over in the autumn of 1997.

In May 1998, the spacer was again towed to a carefully selected mating site and submerged by flooding the main
ballast tanks while maintaining trim and heel control with the corner tanks. Molikpaq was then towed to the mating
site and slowly winched into position over the spacer.

Once in position, the spacer was deballasted, raising Molikpaq out of the water and allowing workers to permanently
weld the sections together. The final footprint position of Molikpaq, in relation to the spacer, was well within the
specified 50-mm tolerance. Once mated, the Molikpaq and spacer weighed 51,600 metric tons.

Site preparation

In August 1998, the onshore refurbishment of Molikpaq was completed and it was towed 1,495 nautical miles through
the Sea of Japan to the Piltun-Astokhskoye platform location.

Before installation, the proposed location had to be dredged, back-filled, and leveled to form a satisfactory
foundation. Sand quality had to be maintained and monitored round the clock by specialists who made visual
assessments of the particle sizes and content.

In addition, laboratory testing was performed to confirm the visual assessments. A total volume of around 300,000
cu m of sand was used.

Despite high winds and stormy seas resulting from typhoon Rex, Molikpaq was installed Sept. 1, 1998, within 5 m of
its design location, beginning its new life as the PA-A platform.

To complete the installation of the PA-A platform, the center core of the caisson was filled with sand to provide
resistance against horizontal ice loads. A total volume of more than 200,000 cu m of sand was used to fill the caisson
core.

To ensure adequate stability of the core in dynamic loading events, explosive densification was carried out by
Foundex Explorations Ltd.

This method was successfully used when Molikpaq was originally deployed in the Beaufort Sea. Close attention to
detail became a critical issue, ensuring that no damage occurred to the top-side equipment and structure while
achieving sufficient explosive energy into the sand. A licensed Russian blasting contractor, OAO Transvzryvprom,
performed the handling of the explosives, requiring Russian approvals.

Scour protection

A scour-protection system was required to provide external structural resistance to currents and storm waves. A
stacked design using more than 20,000 metric tons of three different grades of rock was selected based on model
testing.

Sacrificial amounts of marine gravel were also placed at two locations some distance away from the eastern corners
of the PA-A platform, assessed to be the most severe location for seabed scour. All rock dumping was performed by
Van Oord ACZ`s dynamically positioned, flexible fall-pipe vessel, Rocky Giant.

SALM

In parallel with the core filling and scour protection activities, the hook-up and commissioning team commenced its
offshore scope of work to complete outstanding construction work and to commission the platform systems.

Also, in parallel, the remaining part of September 1998 was taken up with installation of the SALM, riser, and oil-
export pipeline. The lay barge Yamashiro was contracted by Van Oord to perform this work.

The SALM is provided by Sakhalin Marine Ltd. (SML). Prior to installation, a "glory hole," or sunken depression, had
to be excavated in the seabed to ensure that the top of the SALM buoy would remain below the maximum expected
ice-keel depths during winter storage.

Once the ice thawed at the start of the 1999 summer season, final commissioning of the SALM was completed.

FSO vessel

The final piece of equipment needed to complete the Vityaz Production Complex was the FSO vessel Okha. Okha `s
construction commenced in June 1998 at Daewoo`s Heavy Industries shipyard, Okpo, South Korea, and was
completed in March 1999.

The double-hulled Okha, with 12 storage tanks capable of holding 1 million bbl, includes a reinforced bow that allows
it to push through young or light ice. Tandem offloading can be performed from the stern.

Okha is one of the few vessels worldwide that can operate both as a floating storage unit and as a tanker.

Russian teamwork

Sakhalin Energy, consisting of Marathon Sakhalin Ltd., Mitsui Holdings B.V., Sakhalin Development Co. Ltd., Shell
Sakhalin Holdings B.V., and Diamond Gas Sakhalin B.V. (Mitsubishi), will become the first group to achieve
production under terms of a Russian production sharing agreement (PSA).

A requirement of the PSA is that Sakhalin Energy must use its best efforts to maximize Russian content to achieve
the target of 70% over the life of the entire Sakhalin II project. This is subject to Russian enterprises meeting
agreed qualifications, including price, quality and schedule.

Calculated over the life of the fields, Russian content applies across the whole spectrum of activities, including the
supply of material and equipment, labor, and construction operations, all of which are closely monitored by Sakhalin
Energy.

A significant contribution to the Phase I portion of the Russian content came from the fabrication of the spacer, which
was done entirely in Russia. This work was finished ahead of schedule while achieving excellent quality and
dimensional accuracy.

Committed to achieving a high Russian content ratio, the Sakhalin Energy engineering team will continue to study
ways to maintain a high level of Russian content for the subsequent phases of Sakhalin II`s development.

Approval procedures

In moving forward with this unique development, Sakhalin Energy overcame many challenges. In particular, the
Russian approvals process presented numerous complexities for the Sakhalin II team.

To succeed in developing the Piltun-Astokhskoye hydrocarbon resources, the project team needed to call on the
services and expertise of many talented Russian employees and contractors during the design stage, all working in
cooperation with many of the international oil industry`s best resources for upstream oil and gas field developments.

Sakhalin Energy worked with many Russian authorities and agencies to obtain approval of the Phase 1 development
plan for the Astokhskoye feature of the Piltun-Astokhskoye license area. Approvals had to be obtained from the
State Reserve Committee (SRC) and from the Central Development Committee (CDC) for the reservoir
development plan. Final approval for the development plan was received in July 1997.

The next important step was to obtain Russian approval of the Technical and Economic Substantiation (TEOC). This
unique Russian process was the least understood of all the approvals. With the assistance of the Russian authorities,
however, and good cooperation from all parties, the TEOC was approved by mid 1998.

Further approval activities took place in order to procure new equipment and refurbish older drilling and safety
equipment. This involved technical reviews by Societe Generale de Surveillance Energodiagnostika (SGS-ED) on
behalf of Gosgortechnadzor.

The design of the platform and pipeline facilities was reviewed by several of the premier design institutes of Russia
to ensure compliance with the requirements of Russian Codes and Norms.

Documentation

Following close liaison with SGS-ED, an agreement was reached to attach qualifications on certain permits to clear
any outstanding work offshore. In parallel, a team in Houston compiled the Technical Passports for various items of
critical equipment while issuing Certificates of Conformity on behalf of Gosstandart to clear Russian Customs.

The levels of technical certification documentation required to satisfy the needs of the Russian Federation Approvals
scheme is comparable to that of the U.K. and Norwegian sectors of the North Sea. Efficient document management
systems are required to manage and deliver the level of design and vendor data to satisfy the various Russian
regulatory agencies, facilitate timely approvals, and support ongoing operations.

Sakhalin Energy believes that the Russian Federation approvals process can be streamlined, particularly with regard
to the numerous government departments and agencies that are involved with the process. To achieve this goal, the
company will continue working closely with the PSA Commission and other Russian Federation authorities to
establish a single body with the authority to coordinate such approvals.

FSO fast-track conversion assisted by evaluation, classification  

Tough requirements set for Gulf of Mexico FSO

The Ta'Kuntah FSO, the first FSO installed in the Gulf of Mexico, performing simultaneous offloading on the Cantarell
Field off Mexico.

The first floating storage and offloading unit for Gulf of Mexico installation was recently classed by ABS Americas, a
division of the American Bureau of Shipping (ABS). The task came from Modec (USA), owner of Ta'Kuntah, a
converted tanker installed on Pemex's Cantarell Field offshore Mexico.

Within six months of first oil in August 1998, Ta'Kuntah had offloaded some 16 million bbl of oil. Permanently moored
in 267 ft of water, the vessel is designed to withstand 100-year hurricane conditions - a necessary requirement for
an FSO in the hurricane-prone Gulf of Mexico.

The Ta'Kuntah is ABS classed as an A1 FSO. The floating storage offshore (FSO) vessel notation includes
classification of the vessel (structure, stability, marine, utility, safety, and storage systems, and equipment) and the
mooring system. Previously known as Juno, the tanker was selected for conversion because of its very large storage
capacity, 357,600 dwt tons, a critical requirement for the prolific Cantarell Field. The field will have a production rate
of 1.4 million b/d of oil from 35 platforms, after completion of the field's short-term plan.

Capabilities

With a storage capacity of 2.342 million bbl of oil, the vessel is capable of receiving up to 800,000 b/d of crude. The
FSO also provides standby storage capacity in the event of inclement weather, as the field's three nearby single
point mooring terminals are unable to operate in winds exceeding 40 knots.

When the weather is stormy, or winds are high, crude is diverted by pipeline to Ta'Kuntah. The FSO can offload to
shuttle tankers both individually and simultaneously. Offloading to one tanker at a time, Ta'Kuntah can transfer up to
55,000 bbl/hour working in tandem, and up to 80,000 bbl/hour side-by-side. With two shuttle tankers working
simultaneously, Ta'Kuntah can offload at a rate of 40,000 bbl/hour in tandem or 80,000 bbl/hour side-by-side. This
special design capability is possible because crude is received through the turret and offloaded from the deck level.

Modec completed the conversion at Jurong Shipyard in Singapore within an aggressive nine-month schedule. A
conversion would normally require 12-15 months, depending on a shipyard's workload. ABS provided the manpower
and expertise to complete the engineering design approvals and surveyor monitoring of activities at the yard,
suppliers' plants, and the Cantarell site. The surveys included monitoring vessel conversion and installation surveys
of the piling, chain, and wire of the mooring system, and the flexible risers.

Fast-track conversion

ABS' involvement in the project began in the early stages, providing recommendations for how to complete the
conversion considering all ABS and applicable regulatory requirements, while helping Modec meet requirements for
the FSO's Cantarell Field operation in the Bay of Campeche. The most critical Pemex requirement is maximum usage
of Ta'Kuntah, with no downtime allowed, and pending heavy penalties to Modec for loss of operation.

The FSO design called for 2.3 million bbl of oil storage capacity at any one time, and will allow for up to three empty
tanks during any necessary ABS surveys. This capacity demand required a lot of built-in redundancy for on-site
maintenance and repairs. For example, the swivel and bearing of the external turret can be repaired on-site, and the
loading line can be isolated or diverted while in repair or during inspection, without interrupting operation. The cargo
holds also are coated to mitigate the need for steel renewals over the life of the vessel.

The 20-year old trading tanker required extensive strengthening and reinforcement to extend the vessel's life
another 15 years to meet project requirements. More than 1,200 metric tons of steel were added to strengthen the
hull, and an additional 1,000 metric tons of steel were necessary to modify the bow so it could support an 800-metric
ton external turret mooring system.

Design evaluation

ABS used SafeHull software program to evaluate the overall hull girder strength and remaining fatigue life on the
Juno prior to conversion. The program assessed hull structural strength in terms of yielding, buckling, and fatigue.
The application identified critical areas of the structure, providing a rational basis for planning the renewal program.
Improvements and modifications based on the analysis have given the vessel renewed strength and ensured fitness-
for-purpose.

Other technical issues related to design criteria for the turret mooring system, which keeps the vessel on location.
The key components of the turret are:
  • The bearing, which permits the structure to weathervane
  • The vessel's 10 mooring lines with structural capacity for handling all of the vessel and environmental loads
  • The chain table, which takes the two flexible risers
  • The turret head/swivel, which distributes the product.

Loads on the vessel are dynamic and significantly impact the size and placement of equipment and piping systems
and the effective interface of the turret and tanker. These hydrodynamics require design specifications for vertical
and longitudinal loads to ensure that the vessel complies with ABS requirements for site-specific installations.

ABS will monitor Ta'Kuntah yearly.

The monitoring program has been drawn from traditional ship surveys and has evolved to specific needs of the
offshore industry. For example, a continually operating installation, such as Ta'Kuntah, requires surveys that
minimally impact operations. ABS will plan surveys in conjunction with Modec's monitoring program.

FSO to feature simultaneous offloading to two tankers  

Permanently moored unit nearing completion

A floating storage and offloading vessel is being fabricated for installation in the Cantarell Field in the Mexico sector
of the Gulf of Mexico. Three FMC business units - Sofec, Loading Systems, and Smith Meter - have combined
capabilities and product lines to deliver the first permanently moored floating storage and offloading (FSO) vessel in
the Gulf of Mexico.

The business units supplied the external turret mooring system, ship-mounted marine loading arms, and metering
systems to Modec (USA), the prime contractor for Pemex, the Mexican national petroleum company. The project,
which called for the FSO to be completed on a fast-track basis, incorporates new technology developed especially for
the job.

The Cantarell Field in the Gulf of Mexico off the coast of the Yucatan Peninsula is one of the largest oil fields in the
world. Pemex is expanding its crude oil export systems to include a 350,000 dwt (deadweight ton) FSO that will be
permanently moored in 246 ft of water near the field facilities. The FSO will be constructed, owned, and operated by
Modec (USA) under a long-term charter contract arrangement with Pemex.

The FSO will provide 2.3 million bbl of crude oil storage capacity. It is designed to offload two shuttle tankers
simultaneously, one moored in tandem with the FSO and one moored side-by-side with the FSO.

Simultaneous offloading of two shuttle tankers has not been done anywhere else in the world. Side-by-side
offloading is made possible by three deck-mounted Chiksan marine loading arms supplied by FMC's Loading
Systems. A single receiving metering skid and two independent offloading metering skids provided by FMC's Smith
Meter will confirm oil import and export rates. The FSO is scheduled for installation in the summer of 1998.

FSO technology

The Pemex FSO is a unique vessel in many ways. Sofec provided design, procurement, fabrication, installation, and
commissioning of the turret mooring system to meet rigorous and exacting customer requirements.

Based on time constraints, environmental conditions, and production data, Sofec recommended to Modec (USA) the
selection of an external turret mooring system for the project.

State-of-the-art frequency and time-domain simulations were conducted by Sofec to accurately predict mooring
system motions and forces under 100-year storm conditions. Verification came through extensive model basin tests
including tandem and side-by-side offloading simulation.

Construction and installation of the turret system were performed in Singapore where Modec (USA) undertook the
tanker conversion. Many of the key elements for the project, including the fluid swivel were shipped from the US.
The main bearing was manufactured in Europe and shipped to Singapore for installation.

Loading systems

The FSO project called for a bank of three ship-mounted 16-in. loading arms capable of performing side-by-side
offloading operations in sustained winds to 25 mph and maximum wave heights to 13 ft. Additionally, the arms
required an emergency release system and a means for storage during vessel motion or hurricane conditions.

The vast majority of the world's marine loading systems are dock mounted. In the case of ship-mounted loading
arms, there is constant motion and forces at work between two moving bodies. To accommodate these demands,
the loading arms for this project utilized multiple swivels and an extra-long arm length of 93 ft. When necessary, the
arms can be stored horizontally on the ship deck.

Since a traditional emergency release system would make the loading arms too heavy for the FSO, FMC's Loading
Systems developed a new generation of fully powered piggable marine loading arms that minimized weight while
accomplishing the emergency disconnect requirements. The new arms feature a hydraulic coupler and automatic
pigging system for fast connection and disconnection on the shuttle tanker. A state-of-the-art position monitoring
system with a microprocessor and special sensors monitors the position of the arms at all times. If a shutdown is
required, the system shuts the pumps down and the automatic pigging system empties the arms prior to any
disconnection.

Custody metering

The PEMEX FSO called for three metering systems, one skid-mounted system for the measurement of incoming oil
and two skid-mounted systems for the simultaneous measurement of outgoing oil to separate shuttle tankers.

A total of twenty 16-in. PD (positive displacement) meters and 11 SyberTrol flow computers were required. To
deliver the equipment on schedule, normal lead times had to be reduced 75%. As a result of product simplification
by Smith Meter, the PD meter design had been changed to reduce both cost and lead time.

The PD meters, the largest and most advanced of their kind in the world, each weigh over 6,500 pounds and stand
over 5-ft tall, were shipped in batches of 3, 4, or 5 meters at a time. The outgoing metering skids each had eight PD
meters with a measurement capacity of 80,000 bbl of oil per hour. The incoming skid has four PD meters.

The completion of the Pemex project marks the first use of a permanently moored FSO in the Gulf of Mexico.

Propulsion system options for FSO vessel conversions  

Trade-offs in retaining or removing propulsion system

Crude oil is produced and processed from inland or subsea wellheads and loaded onto a moored floating storage and
offloading (FSO) vessel via a subsea pipeline, pipeline-end-manifold (PLEM) assembly, and underwater hoses.

The vessel, and those associated installations, constitute an offshore exporting facility for product crude. The vessel
can be moored through the bow or stern turret by a single-point mooring (SPM) system or other facilities. Cargo
stored in the vessel is exported through the offloading hoses at the stern (or bow) to a shuttle tanker berthed in-
tandem or another configuration.

The
facility presented here is one installed off the coast of West Africa, far from major world shipyards. The facility's
design life is presumed to be at least 20 years
. The FSO vessel, as studied, is a converted ultra-large crude carrier
(ULCC) built in the 1970's. During this era, ULCCs were equipped with a steam power plant with steam turbines for
propulsion.

The steam power plant, associated systems, and propulsion system were investigated for vessel conversion
engineering in this study. The converted ULCC presented here has the cargo-carrying capacity of 400,000+ DWT.
The methodology of the investigation can be applied to any similar vessel.

The study deals with the option of retaining or removing the existing propulsion system during the vessel conversion.
The propulsion system is not needed for the vessel's daily operation at the export facility. However, the retained
system fulfills certain functions such as propelling the vessel to and from the export facility. The removed system
simplifies certain operations, but requires that an alternate means be provided to transport the vessel to and from
the facility.

The final decision can be made during the conceptual study and is based on an overall economic assessment of the
propulsion system for the vessel design life as well as the field production life. There are industry examples of either
option. The purpose of the study was to lay out the planning philosophy and cost basis, and to support the later
design effort for the FSO vessel. Detailed engineering or examination of operations and maintenance were not
undertaken in the study.

For the propulsion system modification design, the study's objectives were to:
  • Analyze the option of retaining or removing the propulsion system
  • Estimate the number of crew, distance, number and cost of voyages for the vessel transporting between the
    West Africa coast and various shipyards under either option
  • Consider the possible operational, maintenance, and design implications on both options •Compare the cost
    of both options.

The FSO vessel inherits the propulsion system if it is converted from a ULCC. The propulsion steam power plant
includes the steam turbines, reduction gears, shafts, propeller, steering gears, rudder, associated piping systems,
and supporting machineries. Retaining or removing the system will be implemented during the vessel's conversion. A
different design, conversion work, operation, and maintenance will be required for the option adopted.

System conversion

Removal of the propulsion system does not imply that all system machinery, piping, and equipment must be
physically removed, but rather that they are disconnected. Some system modifications are required to fulfill the
classification requirements as well as the budgetary constraints.

For economic reasons, a minimal effort to disable the propulsion system is sufficient for this option. This includes
sealing off permanently all steam inlets to the turbines, stopping air leakage to main condensers, and dismantling
the shafts, propeller, and rudder. A consultation with the classification society can be made for the other tasks.
Shipyards can also be consulted for the detailed engineering and tasks. The removal tasks are permanent processes
which are intended to be irreversible.

Retaining the propulsion system also involves system modifications to fulfill the classification requirements as well as
the budgetary constraints. Blanking off steam inlets to the turbines and stopping air leakage to condensers are the
typical main tasks. The propeller shafts and rudder should be secured based on demands such as during severe
weather. The deactivation tasks are temporary processes and are required to be reversible to the original status of
the system. The deactivated propulsion system is required to be reactivated for propelling the vessel again with
minimum outside assistance at the facility.

Vessel voyages

The FSO vessel with the removed propulsion system needs to be towed by a tug(s) to the export facility, whereas
the one with the retained system can self-propel to the facility. The types of voyages which require the vessel to be
towed or self-propelled are summarized as follows:
  • The first voyage to the facility from a conversion yard is assumed to be 4,000 miles from southwestern
    Europe, 9,300 miles from Southeast Asia via the Cape of Good Hope, and 13,500 miles from east Asia.
  • The voyage for scheduled shipyard maintenance should be undertaken about every 10 years after the vessel
    is converted with repair and life extension. The distance to a shipyard is the same as above.
  • The voyage for unscheduled shipyard maintenance should be taken into account.
  • The voyage to a safe haven due to adverse weather rarely happens and depends on the weather at the
    facility.
  • The voyage to a new production site or a salvage yard may happen, but should not be included in this study
    and depends on the design life of the facility.

Considering the facility's operational life of more than 20 years and the vessel's age, the number of one-way trips
for the FSO vessel to be towed or to self-propel is estimated to be five voyages (first trip to the facility and four
possible one-way trips to and from shipyards for maintenance). The extent of repair and life extension on the vessel
during conversion plays the key role for determining scheduled or unscheduled shipyard maintenance. Another
factor such as the operational environment also affects this determination.

Requirements

The FSO vessel which has the propulsion system removed must be towed to the facility after the conversion. There
are no specific requirements or guidelines from the towing company, marine insurance company, and classification
society about the manning level aboard the vessel under towage and the number of tugs to tow the vessel. They can
accommodate the owner's towing specifications, which are based on safety and financial security reasons. Thus, the
manning level and the required number of tugs depend entirely on the owner and his construction contractor.

In this study, the FSO vessel is manned for safety, stability, and training reasons, with a crew of 20 persons aboard
during the towing voyage. The crew includes about 10 persons for engine and pump room operations and the
remainder for the on-deck operations. The crew can be used for such activities as adjusting the vessel's draft and
trim due to weather change, operating the power plant for ballast pumps and generators for the navigation lighting,
and becoming familiar with system operations.

Two tug boats are required for the ocean tow, simply for safeguarding the initial huge investment. One powerful tug
provides the main bollard pull for the vessel. The other tug provides backup force or emergency service.

The system-retained vessel is self-propelled to the facility. The manning level is estimated also to be a crew of 20
persons on board. There is no cargo aboard and a standard full marine crew is unnecessary. The operation of the
vessel during the voyage is less laborious as a trading voyage made by the ULCC.

Other considerations

Removal of the propulsion system of the FSO vessel will be completed during the vessel conversion. No additional
operation and routine maintenance on the system is required after the vessel leaves the conversion yard. The
system does not require any upkeep during the vessel's scheduled maintenance in a shipyard after a lengthy service
at the facility.

For the vessel retaining the propulsion system, the system deactivation is performed after the vessel has arrived at
the facility. The required equipment and parts for the deactivation are prefabricated at the conversion yard.
Deactivation work may require temporary and additional assistance from the yard.

The deactivated propulsion system requires routine maintenance to prepare the system to be functional if it is re-
activated. The system maintenance work, such as periodically rotating the propulsion turbines with the turning gears
and operating the lube oil pumps, are necessary. Auxiliary systems, such as the stern tube seal and the turbine shaft
gland seals, require constant operation. The stern tube seal system serves as the shaft lubrication and keeps the
engine room from flooding. The gland seal system helps maintain the vacuum in the main condenser. The steering
gears and the propeller shaft are required to be locked in adverse weather. Other operations and maintenance are
included in the vessel's detailed operating manuals. The system requires some upkeep during the vessel's scheduled
maintenance in a shipyard.

Cost comparisons

The conversion cost for removing the propulsion system is slightly higher than that of retaining the system for the
FSO vessel. The difference is small in contrast to the overall conversion cost. Higher cost is mainly due to the
dismantling and removal of shafts, propeller, and rudder, which totals about $30,000. The vessel with the removed
system could be stern-moored, which results in some cost saving to the SPM support structure at stern.

Operation and maintenance costs for the retained propulsion system are slightly higher than that of the system
removed for the vessel at the facility. The difference is small in contrast to the overall operation cost. Higher cost is
mainly due to the upkeep of turbines and auxiliary machinery as stated in the previous section. The retained system
incurs cost for maintenance during the vessel's scheduled maintenance in a drydock and shipyard. The maintenance
cost is for surface painting the rudder and polishing the propeller, and amounts to about $40,000.

For the system-retained vessel, the upkeep may actually amount to no extra labor cost since it is performed by the
crew during the routine watch hours in their daily shifts within the engine room. The cost of consumption of fuel oil
and lube oil for the deactivated propulsion system is very small. Re-activation of the system may result in no extra
cost for labor.

The engine room is assumed to be manned with a regular crew of operators for boilers and machines. This crew
should be adequate to maintain the deactivated propulsion system. However, one extra crew member may be
included for the cost estimate of the retained system. The extra cost is less than $50,000/year. The system is
capable of being reactivated within 24 hours with proper planning and execution. The operation cost estimate for the
vessel's entire steam power plant is out of the scope of this study.

For a conservative estimate, five one-way voyages are required for the FSO vessel to be towed or self-propelled
during its entire operating life of 20 years. The first voyage's cost from various conversion yards or shipyards
around the world to the coast of West Africa was determined.

The daily operating cost of the FSO vessel with crew aboard contributes significantly to the expense. The towed
vessel, manned with or without crew aboard, makes the major difference in cost comparisons. The vessel can be
towed by 1-2 tugs, providing their brake horsepower (BHP) is sufficient for that purpose. The first voyage costs using
various locations of conversion yards or shipyards were determined in constant dollars. The costs and shipyard
location for the 2nd to 5th voyages are assumed to be the same as the first. The five one-way voyage costs were
also determined.

The option of retaining or removing the vessel's propulsion system was based on economic merits. Other factors
were considered, such as vessel mobility in a politically uncertain region and the field production life.

Some options were clearly superior to others. The trade-offs and cost comparisons between the options were not
marginal. The decision of retaining or removing the system is subjective sometimes and should be determined case-
by-case. The approaches detailed in this study can provide the basis for decision-making about the propulsion
system of any future FSO vessel conversion engineering.

Cost Estimates for transporting an FSO vessel

Towing by tugs

A tugboat of 6,000 BHP is required to tow an FSO vessel ballasted to 30 ft draft (assumed) across the open sea. For
safety reasons, it is recommended to tow the vessel with two tugs. One main tug of 6,000 BHP and a second one of
3,000 BHP are proposed for towage from a conversion yard to the export facility off West Africa. An alternative, two
4,000 BHP tugs, will serve the same purpose.

The towing speed is about 6 knots in open water with modest weather. The main tug's daily rate is $5,500. Fuel
consumption is 200 gallons/hr. The secondary tug's daily rate is $3,000. Fuel consumption is 120 gallons/hr. The fuel
cost is $0.60/gallon FOB in the Gulf of Mexico. The fuel rate is $120/hr for the main tug, and $72/hr for the
secondary one.

The crew should stay with the FSO vessel during towage. Crew on board allows training, familiarization with the
vessel, changing vessel draft and trim due to the changing weather, and practicing fire drills. The daily vessel
operation cost is estimated to be $9,500/day. Wages and food for a crew of 20 persons amount to about $7,500/day.
The remainder is the fuel and lube oil consumption for the vessel's power plant being operated partially for the
accommodations. Marine insurance and contingency are excluded in this cost estimate. After conversion, the vessel
is towed to the West African coast from shipyards at various parts of world. The cost for towing of the FSO vessel is
itemized (Table 3).

Self-propelled vessel

The FSO vessel is ballasted to an assumed 30 ft draft and self-propels across the open sea to the facility on the
coast of West Africa. Vessel speed is about 10 knots in open water with modest weather. Fuel consumption for the
vessel is about 101 tons/day. Boiler heavy fuel oil cost is estimated to be $ 82/short ton bunkered at the Gulf of
Mexico.

Daily vessel operation cost is about $8,500/day. The cost is mainly for wages, overhead, and food for a crew of 20
persons. There is no need for a full marine crew. A 20-member crew is average operations in the engine/pump
rooms and on the deck of the FSO vessel. Marine insurance and contingency are excluded in this cost estimate. After
conversion, the vessel sails to the West African coast from shipyards at various parts of world. The cost for self-
propelling of the FSO vessel is itemized (Table 4).







                                      




              
Table 4 - Self-propelling costs (US$) for an FSO vessel              
 
Factor
SE Asia
SW Europe
NW Asia
Distance (miles)
9,300
4,000
13,500
Voyage time (days)
33.6
14.5
48.8
Fuel cost
$278,600
$119,800
$404,200
Operation cost
$285,900
$123.900
$414,800
Estimated Total Cost
$564,500
$242,800
$819,000
Days on Site ahead of towing decision
22.6
10.5
33.6
Cost-Benefit - "$ spent for days gained
???
???
???
Table 3 - Towing costs (US$) of an FSO vessel
 
Factor
SE Asia
SW Europe
NW Asia
Distance (miles)
9,300
4,000
13,500
Voyage time (days)
56.2
25
82
Towage cost (Main tug)
$309,100
$137,500
$451,0000
Fuel cost (Main tug)
$161,7600
$72,000
$236,160
Towage cost (2nd tug)
$168,600
$75,000
$246,000
Fuel cost (2nd tug)
$97,056
$43,200
$141,696
Vessel ops (crew of 20)
$533,900
$237,500
$779,000
Total cost - manned vessel, 2 tugs
$1,270,416
$556,200
$1853,856
Total cost - unmanned vessel, 2 tugs
$736,212
$327,700
$1,074,856
Total cost - unmanned vessel, 1 tug
$470,860
$209,500
$687,160
Table 2 - Cost estimates (US$) for five 1-way voyages to/from West Africa              
 
Alternatives
SE Asia
SW Europe
NW Asia
Self-propelled
$2,823,000
$1,214,000
$4.095,000
Towed - manned vessel, 2 tugs
$6,544,000
$2,826,000
$9,269,000
Towed - unmanned vessel, 2 tugs
$3,884,000
$1,639,000
$5,375,000
Towed - unmanned vessel, 1 tug
$2,556,000
$1,048,000
$3,436,000
Table 1 - Cost estimates (US$) for first one-way voyage to West Africa              
 
Alternatives
SE Asia
SW Europe
NW Asia
Self-propelled
$565,0000
$243,000
$819,000
Towed - manned vessel, 2 tugs
$1,271,000
$565,000
$1,854,000
Towed - unmanned vessel, 2 tugs
$737,000
$328,000
$1,075,000
Towed - unmanned vessel, 1 tug
$471,000
$210,000
$687,000
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