Deepwater drilling market appears strong through 2000

The demand for semisubmersibles, such as the Sedco Forex unit, will be a function of technology and oil price stability. Deepwater's longevity as a commercially strong drilling market will depend on a continued balance between two forces - technological advances and oil price stability, comments Larry Hibbard, Sedco Forex's vice president of marketing.

The demand for semisubmersibles, such as the Sedco Forex unit, will be a function of technology and oil price stability.


Balance between technology, price stability will support active drilling

Deepwater's longevity as a commercially strong drilling market will depend on a continued balance between two forces - technological advances and oil price stability, comments Larry Hibbard, Sedco Forex's vice president of marketing.

The global drilling contracting company, based in Paris, is positive about the prospects for such a continued balance. In the following interview, Hibbard explains how his company and others view drilling opportunities, market forces, and where the industry will be in the year 2000.

OFFSHORE: Having been through over a decade of low utilization and dayrates, how would you describe the current state of the offshore drilling market?

HIBBARD: Offshore drilling contractors are experiencing one of the busiest, most interesting markets ever available to us, and the end to this market revival is not yet visible.

OFFSHORE: What factors play a role in this rebirth?

HIBBARD: Several economical and technological factors are playing a role. Among these are stable oil and gas prices. As long as oil prices remain above US$16/bbl, and there are no serious indications that this will change, operators will maintain fairly consistent drilling activity levels.

However, it must be noted that in the early 1990s, a historic decoupling of oil price and offshore rig activity levels took place. This is a direct result of oil companies' efforts to lower operating costs through such means as outsourcing, delayering, and returning to their core businesses by peeling off non-core holdings. Initiatives that started in 1985, after the oil price slump, were finally brought to fruition in about 1992. Since then, operators have been able to sustain robust exploration and appraisal activities with a softer oil price than they were able to previously.

Further, significant technological advances throughout the exploration, drilling , and production cycle have combined to reduce both finding and lifting costs, enabling oil companies to operate more efficiently. This too translates into a wider tolerance for oil price fluctuations and thus a more stable drilling market. In fact, the demand for deepwater rigs has been particularly keen. Deepwater rig demand is higher than it has ever been.

OFFSHORE: Why is that?

HIBBARD: Lower finding costs and the major operators' desire to concentrate on regions still holding potentially large reserves has focused offshore operations into deepwater regions. For example, the Texaco-led Deepstar project has estimated that 95% of presently unexplored offshore acreage lies in waters exceeding 2,990 ft (910m). And records show over 30 Gulf of Mexico discoveries in waters over 2,000 ft deep.

Recent tax incentives and investment guidelines also have spurred development drilling and deepwater programs worldwide. Tax incentives, for example, have helped keep the offshore fleet busy in the UK, and in the deepwater areas of Brazil and the US Gulf of Mexico. Most recently, certain West Africa countries have enacted legislation to spur deepwater exploration and production (E&P). And in Brazil, foreign investment rules have been modified to help Petrobras finance its development target of 1 million b/d by 1998. We expect a further opening of the Brazilian market to foreign oil companies in the coming years.

In the US, the Outer Continental Shelf Deepwater Relief Act was approved in late 1995 to provide incentives for oil/gas production in the central and western Gulf of Mexico. Naturally, this legislation positively impacted the subsequent 1996 lease sales for these areas. The first of two such sales received 32% more bids for deepwater acreage than the previous all-time high set in 1970.

In the latest sale, held in September, the number of bids and tracts offered exceeded any sale since 1983, and half of the bids were for blocks in water depths over 2,600 ft. The deepest block bid on was in 10,000 ft of water.

Clearly, operators are convinced they can produce economically from deepwater acreage in today's market, and many governments have followed suit by opening up new deepwater frontiers for them. In Northwestern Europe, for example, operators are taking on the opportunity to push out into the Northeast Atlantic Margin in water depths of 1,500-6,000 ft deep. Specifically, Norway has awarded the first deepwater acreage in its V ering Basin. The Faeroes have defined acreage for and subsequently started a 1st round for exploration, which should be awarded in the third quarter of 1998. The UK 17th round will be awarded in May 1997, and includes the West Hebrides and Rockall Bank. Activity in the Porcupine Basin west of Ireland will start in mid-1997 with two deepwater rigs fixed for work. Greenland has just awarded acreage to a consortium for exploration.

OFFSHORE: What type of technological advances have reduced finding costs and improved operations for the oil company, making the deepwater search commercial?

HIBBARD: Many advances and continuous improvements in traditional E&P technology, in deepwater technologies in particular, and in business practices, have significantly contributed to improvements in the offshore drilling business and resulted in lower production costs. Among these are 3D seismic, extended reach and horizontal drilling, multilateral drilling, subsea completions, slimhole and reentry techniques, rig upgrades, extended well testing, low-cost floating production systems (FPS), advanced drilling tools, and enhanced formation evaluation tools. In addition, service companies have restructured their scope of services to take a more proactive roll in the engineering and execution of wells through integrated wellsite solutions, new business partnerships, and alliances.

OFFSHORE: Can you site specific examples of technology-derived gains in the deepwater offshore?

HIBBARD: An excellent example comes from the Gulf of Mexico. The Mars platform, in 2,933 ft of water, was designed 8,000 tons lighter and for $200 million less than its neighboring platform Auger, which is in 2,860 ft of water. Mars is producing 100,000 b/d versus 50,000 b/d from Auger. The estimated production cost for Mars is an amazing $4/bbl.

Another advantage that technological gains bring is the significantly reduced time to first oil. A good example that comes to mind is BP's deepwater North Sea Foinaven project. It came on stream only 3.5 years after discovery, compared to an average 8.0 years for the area. Development costs have been estimated at $5/bbl.

Importantly, deepwater technology advances continue. Petrobras expects to push the limits of deepwater development beyond the current 3,000-ft mark. By the year 2000, it reportedly expects to be able to develop fields in 6,500 ft of water.

OFFSHORE: How does your company view the long-term potential of the deepwater market?

HIBBARD: During 1995-96, an extensive internal and independent study was conducted to better understand the deepwater market. Using a set of conservative assumptions, the data gathered pointed to another three to four years of continued growth in the deepwater drilling market. This translates into the current total fleet of 43 rigs that are suitable to drilling in mild environments, and in over 2,000 ft of water, growing to a fleet of 60-70 rigs by the year 2000.

OFFSHORE: And beyond 2000?

HIBBARD: After 2000, several variables will determine whether the market will grow further, level off or decline. These variables include whether or not technological advances continue to further improve deepwater drilling techniques and lower production costs. The Deepstar project was set up to address the challenges that face the industry in the quest for producing in water depths never imagined in the past. Petrobras remains confident that this is possible, and Shell is pursuing its Ursa development in 4,000 ft of water in the US Gulf of Mexico. These are all positive signs for continued deepwater technology advancement.

Oil price stability and continued deepwater tax incentives, as discussed earlier, also are variables.

Currently, there is no plausible reason to expect a drop in oil prices. However, Middle East conditions remain unpredictable and always threaten oil price stability. Oil consumption is another key factor that needs to be taken into account. Any economic downturn in Asia, Europe or North America would certainly have a negative impact on the demand for oil, thus affecting the price.

A sustained good return on investment also is key to continued growth in the deepwater market. The oil industry competes for investment dollars to finance E&P. If production costs remain competitive, then continued upstream investment can be expected.

The balancing of rig rates to performance is another related factor. Dayrates for existing units are already at an all-time high and there comes a point at which the economics for future E&P do not make sense. Offshore rig rates currently are US$100,000-140,000/day, based upon water depth capability. Newbuilds are expected to command $160,000-180,000 or more per day, but will be the most technically advanced rigs in the world and should deliver at least a 30% time savings per job through improved performance.

OFFSHORE: How are contractors meeting the escalating deepwater demand?

HIBBARD: On whole, contractors have found that upgrading and retrofitting existing rigs to meet deepwater demand is still more cost-effective than building new units. With lead time to retrofit a rig running about 3-12 months, it is fortunate that operators are announcing projects with sufficient advance notice to allow for upgrade. Thus, the supply and demand of deepwater rigs remain about equal.

Upgrading of existing rigs remains the preference, and will continue so until the cost of newbuilds comes down, or offshore drilling techniques change significantly, requiring new rig designs. Thus, not surprisingly, the continued migration of offshore rigs to deepwater service is causing a tight shallow-to-medium offshore rig market, as well.

Only two confirmed newbuild contracts for deepwater offshore rigs have been announced to date. Having over-built for the market once before, contractors remain hesitant to undertake even an upgrade on speculation. Firm work commitments and pricing terms typically are being required before any rig upgrading and certainly new building is launched.

OFFSHORE: What type of investment does a contractor make to upgrade a rig for deepwater?

HIBBARD: Upgrades of moored rigs come in a number of forms. Intended use of the rig, cost to upgrade and time to complete must be considered when choosing an upgrade option. Another important element to consider when upgrading is the amount of time it would remain idle when it could be earning a significant dayrate.

Low-cost upgrades can take from a few weeks to several months and can range from $5 million to $8 million. These typically are undertaken to meet the needs of a specific well. Full rig enhancements, which take 6 months to a year, range from $30 million to $110 million. This is true whether retrofitting for chain/wire mooring or upgrading to dynamic positioning (DP). And conversion of existing accommodation semisubmersibles to deepwater drillers can take more than a year and reportedly reach $155 million in cost. For comparison, newbuilds require 2.0-2.5 years to complete and cost in excess of $250 million.

So far, Sedco Forex appears to be only contractor undertaking the upgrading of an existing rig to include DP. There are a number of significant advantages and the cost to outfit for DP is comparable to upgrading to a deepwater chain/wire mooring system. Our experience with DP has shown it eliminates the time spent waiting on suitably equipped and powered anchor handling vessels a problem in both tight and remote markets and the cost of these vessels.

DP also is optimum when operating in an area with a lot of existing seafloor "jewelry." And, of course, DP is preferable in harsh environments that can require fast moves off location, or when frequently moving from one wellhead or seafloor template to another. We have found that the added fuel expense incurred operating a DP rig is typically more than offset by one or more of these benefits.

OFFSHORE: What makes up a rig conversion or upgrade for deepwater?

HIBBARD: More than 50% of the 143 semis available today are still eligible for upgrading to drill in waters greater than 2,000 ft deep. Such an upgrade involves more than replacing worn parts and outdated components. Careful evaluation of a rig's current capabilities and desired deepwater requirements must be conducted. Marine engineering is a key component in the rig upgrading business to ensure that the resulting drilling unit meets functional and economic goals.

Sedco Forex's rig upgrades to deepwater capability retain the ship shape of the rig, ensuring that it can make good time between locations. Seemingly minor considerations such as this can make the difference between an economic venture and a costly one. Many of the rigs being converted today will average only 1-2 knots. A 200-mile rig move could easily cost the operator over a million dollars before they even spud the well.

Depending upon the project targeted (water depth, topsides, and downhole environments) and the coinciding conversion budget, rig upgrades can include structural modifications to the deck columns and hull to meet added variable deck load requirements, mooring system enhancements for chain/wire or conversion to DP, drilling riser system expansion, subsea system modifications including BOP conversions and TV and acoustic positioning system upgrades, and drilling related augmentations such as additional mud pumps, engines, top drives, mud storage and shakers.

If harsh environments and water depths exceeding 3,000 ft are a possibility, then upgrades also can include tasks such as extending the rig's pontoons, generally adding more structural support, further modifying the riser and drilling systems, and adding an engine to allow drilling with thrusters running. If upgrading to DP, the same types of enhancements are required plus adding thrusters, motors, generator sets, a data management system, and fuel capacity.

OFFSHORE: What has been Sedco Forex's experience with upgrading?

HIBBARD: The Sedco 707, for example, was awarded a 5-year contract recently by Petrobras to work as a deepwater DP unit offshore Brazil. It will be undergoing extensive modifications, including a life enhancement, variable deck increase to 4000 metric tons, conversion to DP mode, and various other modifications for 6,500-ft water depths. With incentives, the 707 will bring in well in excess of US$100,000/day. The engineering of such an upgrade is paramount.

Upgrading our 700 series rigs to the equivalent of 4th generation semisubmersibles gives the operator the option of using either a DP or deepwater moored semi. In the moored condition, these semis are capable of operating in water depths to 5000 ft. The Sedco 700 is due to undergo conversion and was recently awarded a contract requiring it to be fitted with a chain/wire mooring system capable of operating in 3,500 ft of water.

OFFSHORE: Does Sedco Forex have plans for new generation rigs and further capitalizing on the deepwater market?

HIBBARD: Yes. While I can't give details at this time, we are keen on ushering in new technology to address the critical factors limiting deepwater drilling either technically or economically. For example, deck or storage space are critical factors due to the weight of added conventional riser systems. We are participating in a joint industry project on riserless drilling systems, sponsored by Conoco, Hydril and several other contractors, to address just this limitation.

In the lean year of 1994, Sedco Forex Engineering and Schlumberger companies, Anadrill, Dowell, and Wireline, took on a review of the entire drilling process with the intention of re-engineering it. The $15-million Simpler project, which was supported by the European Union through the Thermie project, came out of this review process and includes a new land rig that is now operating in Gabon for Shell. This new-generation rig incorporates safety and environmental improvements, increased mechanization, staff reductions via multi-skilling, state-of-the-art data management for drilling optimization and service integration, and optimized fluids management, among other features. The valuable knowledge and experience gained from the Simpler project is now being used to design the next generation of rigs for our eventual fleet replacement program.

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