Jim McCaul - International Maritime Associates

Eric Smith - Saipem

While offshore field development in the Gulf of Mexico (particularly deepwater) gets most of the headlines, basins offshore West Africa, Brazil, Northern Europe, Western Australia and Southeast Asia are also alive with exploration and development activity.  Much of the undiscovered, economically recoverable oil and gas reserves are believed to lie in these deepwater basins - and operators, both majors and independents, are earmarking large capital expenditures and utilizing a multitude of techniques to tap their resources.  

Offshore activity is being driven by growth in demand for energy, the need for new sources of hydrocarbons and advances in technology that have dramatically lowered the cost of finding and developing offshore oil and gas.

Industry forecasts call for worldwide demand for oil to grow 2 to 2½ percent annually well into the next decade.  New sources of crude need to be found to accommodate this long-term growth.  When depletion is taken into account, it is estimated that more than half of the oil supply required in 2010 will be from reserves that have yet to be discovered, much less placed on production.  

Radical technology changes in the offshore sector have increased the success rate and reduced the cost of finding and developing oil by 40 percent since the early 1990s.  Driving these improvements are advances in seismic technology, use of directional drilling and multiple completions, improvements in subsea systems, improved production techniques, better coordination among field operators, etc.  Unocal estimates that, using Shell's Auger TLP installed in 1995 as a base, new technology and the learning curve have cut both capital intensity and construction/ installation time in half.

Both majors and large independents are increasingly focusing their finding and development budgets on new deepwater fields.  Advances in technology and compressed development cycles, both a function of floating production and subsea development, make this segment the most attractive on a life cycle basis.

Easily the deepest water around, with the highest number of imminent prospects, is the deepwater Gulf of Mexico.  This is followed by Brazil and offshore West Africa.  All three segments are in what we refer to as the South Atlantic region.  The resultant drilling and construction activity in all three areas helps explain the current migration of deepwater drilling and construction equipment into the region, primarily from the North Atlantic.  Shell, BP, Exxon and Chevron are particularly active in the U.S. Gulf.  Elf, with Girassol and Dalia, is especially active off West Africa.  Petrobras is aggressively pursuing deepwater activities off Brazil.  All of the majors are now concentrating their exploration and development activity on deepwater (exceeding 460 meters) and ultra deepwater (exceeding 910 meters).

A recent survey of more than 90 oil and gas companies indicates that capital spending will increase almost 10 percent in 1998 (after a 15 percent increase in 1997) and two-thirds of the majors said they plan to increase offshore expenditures this year.  In another industry survey, respondents said that the most attractive investment at this time is deepwater exploration and development in the Gulf of Mexico. This interest in deepwater is evident in Gulf of Mexico leasing activity, where almost 70 percent of the bids in the March auction were in water depths over 800 meters - one of which was in 3,225 meters.  Although there were fewer bids vs. the prior year, the total funds exposed were greater, with one lease garnering a bid of $28 million.  Significantly, this auction was held in an oil price environment that was less than supportive.

While recent oil price volatility has had a sobering influence on forecasts for capital spending for offshore E&D, most forecasts call for an increase in 1998 of approximately 10 percent over last year.  Where companies have announced cutbacks, it has been their onshore and shallow water regimes that have suffered, not the search for giant fields in deep or ultra deepwater.  These "crown jewels" of the operators' inventory will be the last to feel the pinch of shrinking E&D budgets, should they occur.  Also, generally missing in discussions about the impact of lower oil prices has been the apparent decoupling of oil and gas prices in this most recent cycle.  Fully 40 percent of all current development activity worldwide is based on gas, while 75 percent of the U.S. Gulf is so oriented - and gas prices are holding up well.

Jackups are suited to shallow water drilling to about 100 meters.  Semisubmersibles can generally operate in water depths to 2000 meters. Drilling in depths beyond 2000 meters is currently the domain of DP drillships.

There are about 150 semis available for offshore drilling.  This figure includes 31 rigs that can be considered candidates for drilling in water depths between 910 and 2000 meters (e.g., the Jack Bates and the Scarabeo 5).  This modest number represents a significant increase over the 14 deepwater rigs that were available before the recent wave of conversions, upgrades and newbuilds.  Another 11 deepwater rigs are under construction, including the Sedco Energy, which will be capable of drilling in water depths to 3000 meters when delivered in early 2000.

Worldwide, the drillship fleet is in the process of being almost doubled, with the universe of drillships growing from 25 to about 50 units over the next several years.  The new generation of units is typically dynamically positioned, with depth capabilities to 3000 meters.  Drillships are preferred in ultra deepwater for two major reasons.  First, their variable deck load far exceeds that of the most robust semisubmersibles, allowing them to support the added weight of ultra deepwater risers, drill strings, and mooring systems, including the attendant mud column.  Secondly, many possess onboard crude storage, which allows for early production (and cash flow) from the newly developed fields.  

While drillships are not as sensitive to variable deck load, they generally do not perform as well as semis in harsh environments, particularly in North Atlantic winters.  In this region, water depths are not as profound, so deck load limitations are not as important.  Therefore a number of new and upgraded semis are beginning the search for oil and gas in the ultra deepwater regions off Norway and the U.K.

Though several of the new ultra deepwater drillships will be limited by their riser capabilities, typically to 2000 meters, many will be capable of drilling in 3000 meters.  Among these are Saipem's recently announced deepwater drillship, the S10000, which will have 3000 meter drill capability on leaving the yard.  Other deepwater units on order include six drill ships for RB Falcon, three units for Transocean, two units for Global Marine, two units for Navion, two units for Pride and two for Navis/Pride.  The intended destination for most of these rigs is the deepwater U.S. Gulf, where the clock is ticking on a large number of undrilled leases.  The U.S. Minerals Management Service mandates a 10 year window in which newly leased deepwater fields must be drilled or the lessor forfeits the lease.  Use of these deepwater drillship units will also be popular offshore West Africa and South America and, to a limited extent, West of Shetlands, during the North Atlantic working season.  

There has been a significant increase in requirements for offshore construction that has impacted the type of equipment needed to install production facilities and transportation infrastructure.

Historically, offshore construction involved the fabrication and installation of large fixed platforms comprised of horizontally launched jackets, upon which were placed ever larger decks and modules.  Water depths were moderate, offshore conditions were not.  Large launch barges, semisubmersible heavy lift vessels and pipelayers were the basic requirement.  The equipment got larger as requirements increased to install the very large integrated, one-piece decks of the late 1980s and early 1990s.  The two largest derrick barges, both designed for the North Sea market, are the DB-102 and the Saipem 7000, launched in 1986 and 1988, respectively.  The DB-102 can lift up to 13,200 metric tons, while the Saipem 7000 is rated at 14,000 metric tons.  

The growing use of floating production and subsea completion has compromised the need for heavy lift capability.  Assembly of the production facility can now take place in a shipyard, rather than in the field.  This has impacted the demand for heavy lift specialists, as there are fewer requirements to lift and install massive fixed structures on offshore fields.  

Likewise, demand for installation of major trunklines in the North Sea is moderating and the need to lay pipe in ultra deepwater has impacted requirements for pipelay equipment.  Through the 1980s/mid-1990s, three semisubmersible S-lay pipelay vessels, the Castoro Sei, Semac I and LB200, were active in the North Sea market.  The lack of any large-scale discoveries, maturing of the region and the advent of remotely located production has impacted the economic driver for new trunklines in the region.  In addition, the traditional S-lay system is giving way to J-lay in ultra deepwater.

Owners are utilizing two approaches to extend the economic lives of traditional installation units.  One approach is to geographically diversify.  In the case of Saipem, the generally higher transit speed of its vessels has allowed the company to operate outside the North Sea, at least during the winter season.  The Castoro Sei recently completed a trunk line, Destin Dome, in the Gulf of Mexico while the Semac I is employed in Southeast Asia.  The Saipem 7000 spent the last few months in West Africa, is now working in the North Atlantic, and will visit the Gulf of Mexico during the fall and winter of 1999 to work for Exxon on the Hoover-Diana field development.

The second approach is to functionally diversify.  For example, the Saipem 7000 is being equipped with a large diameter, ultra deepwater J-lay pipe installation system to radically extend her capabilities.  McDermott's DB 50, a monohull heavy lift DP vessel, is also being equipped with a new J-lay system and will operate under a multi-year contract to Shell.  

Beyond these adjustments to existing vessels, new classes of construction vessels are emerging to deal with future offshore field development.  Particularly significant is the emergence of field development vessels.  These large (500 ft.) DP monohull vessels, with high deckload capabilities, are specifically designed to handle the installation of subsea/floating production systems in remote locations.  Saipem already operates the Maxita in this market and Saibos, a Saipem/Buoygues Offshore JV, has recently announced a newbuild specifically vessel designed for field development.  The unit will be capable of transporting and installing subsea manifolds, suction anchors and mooring systems, and installing rigid and flexible risers.  It will be fitted with a 600 ton crane and a J-lay system that can install pipelines and deck modules in a single mobilization.  

Another example of emergence of new concepts is DSND's deployment of the icebreakers Nordica and Fennica for pipelaying during the summer period.  The two activities naturally complement each other.  

Basically, fields developed with floating production systems are a subset of a larger set of fields utilizing subsea completions.  With the exception of certain deepwater fields in the U.S. Gulf using TLPs and Spars, both of which allow the use of dry trees, the bulk of deepwater development worldwide utilizes wet trees tied back to floating production monohulls, semis and to a lesser degree, to converted jackups. The choice between monohull and semi is a function of onboard storage.  In general, FPSOs are favored where there is a lack of pipeline and fixed platform infrastructure, while semis are preferred where infrastructure connections are convenient, or at least possible.  Jackups are limited by water depth.

In a significant number of cases, the tieback is not to a mobile floating unit, but rather to an existing fixed structure in shallower water. These latter units are concentrated on gas and oil production in regions where paraffin and hydrate problems can be minimized. Techniques include subsea separation, multi-phase pumping, pre-treatment, injection, pigging and various approaches to pipeline insulation, including deepwater burial.  Significant technical effort is going into extending the tieback range.

As of March 1998, there were 88 floating production systems in operation worldwide.  About 60 percent are FPSO vessels, 30 percent production semisubmersibles and the remaining 10 percent tension leg platforms or spars.  Another 35 systems were on order, representing capital expenditures of about $12 billion.  More than 20 shipyards are involved in building these systems.  Most importantly, almost 150 projects are under study that potentially involve use of a floating production solution.  

What will the new systems look like?  Because of the opportunities in ultra deepwater, the Gulf of Mexico will remain the domain of TLPs, both mini and full size, and Spars.  Storage will be a secondary issue and the challenge will be to develop fields, as well as their tiebacks to existing infrastructure, in a capital and time-efficient manner.  Significant funds will be spent on new installation technologies, particularly for new ultra deepwater pipelay capability, in order to make this possible.

Deepwater production offshore West Africa and Brazil will be largely limited to monohull and barge-based floating systems, reflecting the kinder weather environment and the absence of developed pipeline infrastructure in these regions.

Offshore Southeast Asia is a big place, with virtually every potential option for field development.  For the foreseeable future, most development will be in relatively shallow water with benign climatic conditions, in areas lacking infrastructure.  The result will be a number of fields developed with monohulls that incorporate onboard storage capability.  Shell is pursuing deepwater development of the Malampaya field in the Philippines and various groups are developing deepwater reservoirs, offshore New Zealand and Australia, with monohulls.  That said, the South China Sea has seen a recent hybrid development.  Amoco's Liuhua 11-1 field, in 300 meters of water, utilizes a semi for production from subsea wells, which then flows treated production back to a monohull storage vessel.  

In the North Atlantic, with its harsher weather and relatively "shallower" deepwater, we expect to see semisubmersible and monohull production units, perhaps an occasional TLP.  Our definition of North Atlantic includes fields off Canada's eastern provinces and north of Norway.  Terra Nova, offshore Eastern Canada, is utilizing a floater.  While water depths are not onerous, iceberg avoidance and subsea scouring are definite issues.

Eric Smith is President of Saipem Inc.  He has 13 years experience in the offshore construction business and is a graduate of Georgia Institute of Technology (B.ChE) and Tulane University (MBA).  

Jim McCaul is President of IMA, a management consulting firm in Washington, DC specializing in the maritime and offshore sectors.  He holds a Ph.D. in economics and was on the faculty of Webb Institute of Naval Architecture before establishing IMA in 1973.