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June 11, 2001 Oil and Gas Journal
Floating Production Systems Provide a Capability to
Produce Deepwater and Remote Fields
James R. McCaul
International Maritime Associates, Inc.
Washington, DC

Use of floating production systems in deepwater and remote locations has proven to be a major breakthrough in offshore oil and gas production.  This production technology has provided a solution to develop fields that otherwise would have been economically off limits to fixed platforms.  Floating production, which dates from the mid-1970s, is now being used on more than 120 offshore fields.  About one-quarter of the units are operating off Northern Europe, another quarter off Brazil and the remainder are mostly in the Gulf of Mexico, offshore China/Southeast Asia, West Africa and Australia (see chart 1).  

Comparing the floater options - There are four basic platform options for a floating production facility: ship shape FPSO vessel, tension leg platform, production semisubmersible and spar.  Each of these platform options has unique advantages and disadvantages that drive their popularity and there are also differences in regional preferences (see box 1).

FPSO vessels probably have the greatest flexibility of all production systems for utilization in deepwater.  They have no weight constraints and can accommodate large processing capability on deck.  Units equipped with internal turrets can operate in severe weather and sea conditions.  Storage capability is built into the design of the vessel.  The disadvantage of turret-fitted FPSO vessels is the limitation on number of risers that can be accommodated through the turret, which in turn restricts the number of wells that can be produced by the unit.  FPSO vessels are the most popular platform for floating production systems.  Almost 60 percent of the floating production systems now on order utilize ship shape hulls as a platform.

Full size TLPs are particularly useful on large complex fields with high production throughput.  They have the advantage of being able to utilize surface wellheads, which reduces the cost of well maintenance over the life of the field.  TLPs have been popular in the Gulf of Mexico, where 11 units are in operation or on order.  Included in this figure are 7 full size TLPs, 4 mini-TLPs. A major disadvantage of TLPs is tendon weight, which on a full size unit more than doubles from 4,000 to 6,000 ft. and quadruples between 6,000 and 10,000 ft. water depth.  

Production semis have no inherent water depth restriction, good motion characteristics and are able to accommodate a large number of risers. Weight limitations ultimately constrain processing capability that can be placed on the unit.  Production semis had been the unit of choice in Brazil for many years, utilizing secondhand drill rigs as platforms for conversion to production facilities.  There are now 19 production semis operating offshore Brazil (20 before the Roncador unit sank).  Recently, two large purpose-built production semis have been ordered for fields in the Gulf of Mexico.

Production spars have the advantage of being able to place production trees on the platform deck, a very important advantage in areas where there is high paraffin oil that requires frequent intervention.  Spars can accommodate storage, though none of the units now in operation do so.  They also have good motion characteristics.  This type of production unit has become extremely popular in the Gulf of Mexico, where there are 10 spars in operation or on order.  

Recent orders for floaters - There has been a burst of orders for new floating production systems over the past half year, reflecting upbeat conditions in the oil and gas sector.  Between September 2000 and April 2001, 12 floating production units have been ordered: 6 FPSO vessels, 4 production spars and 2 production semis. Among the orders is the Crazy Horse production semi, which will be the largest steel production semi built to date.  With these new orders, 31 floating production systems are now being fabricated, which when installed will add 26 percent to the inventory of floaters in operation (see chart 2).  

A noticeable shift has taken place in the type production system now being built vs. five years ago.  In 1996, about one-quarter of the production units on order utilized semisubmersible hulls.  Now spars comprise about one-quarter of the production units being built and only 10 percent of the 31 units currently on order are semisubmersibles. Accounting for this shift in platform is the growing popularity of spars as dry completion units and the lack of suitable semisubmersible hulls available for conversion to production facilities.  

There has also been a noticeable shift in locations where floating production systems are to be used.  Almost half of the units under construction in 1996 were being built for fields in the North Sea and another 30 percent of the units were being built for use offshore Brazil.  Now the major destination is the Gulf of Mexico, which accounts for almost 40 percent of the systems currently on order.  Equally significant is the increased presence of West Africa as a destination for floating production systems.  There are now more systems on order for use on fields offshore West Africa than for use in the North Sea (see chart 3).  

New floaters planned or under study - IMA has identified 155 offshore projects in the bidding, design or planning stage where a floating production and/or storage system is being considered as a development solution.  Projects off West Africa account for 26 percent of these planned projects and the Gulf of Mexico accounts for another 22 percent.  There has been a significant drop in number of projects planned in the North Sea vs. five years ago, reflecting the downturn in new activity offshore Northern Europe (see chart 4).

Particularly interesting is the large number of projects that have moved from the planning to final design and bidding stage since the second half of last year.  There are now close to 20 projects where final design or bidding is underway, indicating a significant flow of orders for new floating production systems can be expected over the next 6 to 12 months.  

Declining cost of floating production - Tremendous gains have been made in reducing the cost of floating production systems.  According to Shell, the unit cost of newly designed floating production systems has declined significantly since the Auger TLP was installed in the early 1990s.  The most recent unit being built by Shell, the Na Kika production semi, is expected to have a unit cost 50 percent that of Auger - and by 2003 Shell expects new floating production systems to have a unit cost half that of Na Kika (see chart 5).  

It's worth looking at the cost of Na Kika, as it provides a good cost benchmark for fields in ultra-deepwater.  Na Kika, located in 6,000 ft. water depth, is estimated to have gross ultimate recovery of over 300 million boe.  A production semisubmersible is being constructed for use on this field that will have capability to process and export 100,000 b/d oil, 325 MMcf/d gas.  Ultimately, oil and gas will be produced from ten satellite subsea wells.  Assuming recoverable reserves are as now estimated, Na Kika will have a field life of about eight years.

Total capex to develop Na Kika is projected to be $1.26 billion, excluding lease cost.  Approximately 50 percent of the capex is associated with fabricating and installing the host facility and pipeline, 25 percent with fabricating and installing subsea components and 25 percent with drilling and completion of wells.  

Annual operating costs on Na Kika are estimated to be about $25 million. Discounted back at 10 percent, present value of this cost flow would total $135 million. Adding this to the capex, total life-of-field cost to develop and produce Na Kika is about $1.4 billion in net present value.  Dividing this cost by 300 million boe results in a finding, lifting and processing NPV cost of just under $4.80 per boe.

Cost Structure of the Na Kika
Ultra-Deepwater Field

Fabrication and installation of host     $650
facility and pipeline                                 
(millions of $)

Fabrication and installation                 $325
of subsea components
(millions of $)

Drilling and completion of                   $325        
wells                    (millions of $)

Present value of annual                      $135
operating cost    (millions of $)            

Total life-of-field cost                          $1,435
(millions of $)

Recoverable reserves                          300
(millions of boe)

NPV cost per boe                               $4.80

Transport challenge of ultra-deepwater - Until now, pipeline has been the sole means of transporting oil produced on fields in the Gulf of Mexico and field operators in the Gulf have gotten very comfortable using pipeline for transport.  But a number of fields in the ultra-deepwater sector of the Gulf of Mexico are remote from existing pipeline infrastructure, driving a requirement to look at shuttle tankers as a transport solution.  In a recent study, IMA has identified 165 potential development sites in the Gulf of Mexico in water depth beyond 5,000 ft.  These are high priority sites that are likely to be explored and potentially developed with floating production systems over the next ten years.  But there are flow assurance challenges in ultra-deepwater that will likely require expensive technical solutions and more than half of the sites are situated in very rugged seabed conditions that make pipeline installation difficult (see chart 6). This translates to higher pipeline capex and opex.  

The decision between installing a pipeline from the floating production unit on the field vs. utilizing shuttle tanker for export will ultimately come down to the economics of the two options.  Pipeline cost will be influenced by the distance to nearest infrastructure where pipeline connection can be made, the seabed conditions in the surrounding area and the volume discount on the connecting pipeline tariff that can be negotiated.  Shuttle tanker cost will be influenced by construction capex (which will likely be in the area of $100 to 120 million), operating costs and the need for excess capacity to ensure off-take capability under any conditions.  While conditions unique to each field will determine the outcome of this comparison, we have found 25 to 30 miles to be the approximate breakeven distance from infrastructure where shuttle tanker becomes the low cost option.  But introducing shuttle tanker transport into the Gulf of Mexico will meet lots of resistance, given the level of comfort everyone has with pipeline transport and the domestic sourcing requirements that mandate shuttle tankers in the Gulf of Mexico be built in the U.S.

The author - James R. McCaul is President of International Maritime Associates, Inc., a management consulting firm based in the U.S. that specializes in strategic planning and market analysis in the offshore and maritime sectors.  He established IMA in 1973 and the firm has since completed more than 220 business planning assignments for clients in 30 countries.  He holds a Ph.D. in economics from the University of Maryland, M.S. in business administration from Pennsylvania State University and B.S. in marine science from the State University of New York.  Prior to forming IMA, he was member of the faculty of Webb Institute of Naval Architecture.  He is a member of NOIA, the American Economic Association and Society of Naval Architects and Marine Engineers.

Chart 1

120 Floating Production Systems
are in Operation or Available
     Source:  IMA, Floating Production Study

Chart 2

     Source:  IMA, Floating Production Study

Chart 3

     Source:  IMA, Floating Production Study

Chart 4
West Africa and the Gulf of Mexico Account for Almost
Half of the Floating Production Systems Planned or Under Study
     Source:  IMA, Floating Production Study

Chart 5

Declining Unit Cost of Floating Production
     Source:  Shell

Chart 6

Distance from Infrastructure and Seabed Characteristics
of Ultra-Deepwater Development Sites in the Gulf of Mexico
     Source:  IMA, Gulf of Mexico Shuttle Tanker Requirements study

Box 1
What Type of Floater Will Be Used?

Offshore West Africa the most likely solution will be use of non-weathervaning FPSOs tied to subsea wells.  Purpose-built units will be ordered for big fields such as Rosa, converted hulls for smaller fields.  On very large fields, a spar or TLP will be considered for use as a production hub, but the local partner will likely push for the least cost up front solution, which leans toward selecting FPSOs with subsea completion.

In the Gulf of Mexico, spars, mini-TLPs or production semis will be the likely production solution on fields where they can be tied to the existing pipeline infrastructure.  Operators in the Gulf like to minimize operational cost by utilizing surface trees, a capability of spars, making this production option attractive.  Weathervaning FPSO vessels will be a potential solution in the ultra-deepwater central and western areas distant from pipeline infrastructure, with shuttle tankers used to deliver crude to the refineries along the Gulf Coast.  

Offshore Brazil, Petrobras will undoubtedly lean toward FPSOs (based on converted hulls) tied to subsea wellhead facilities in order to minimize capex.  Existing production semis will be moved around as fields close, but there will probably be no additional semis acquired, unless a semi hull of opportunity emerges.  Oil majors operating offshore Brazil may be willing to incur the added capex of spars or TLPs to enable use of surface trees in order to minimize well maintenance cost.  

FPSO vessels (mostly weathervaning) will be the likely solution offshore China, Southeast Asia and Australia.  Purpose built units will be selected for large fields with long life expectancy, particularly off China and Australia.  Hulls for offshore China will likely be local built.  Converted hulls will be more likely to be used off Southeast Asia.

North Sea production units will be mostly weathervaning FPSO vessels (some purpose-built, some based on converted hulls), with a possible TLP or spar on larger fields.  Units now on station will be moved around.