Deepwater prospects offer huge reserves, and technology offers the means to reach those reserves at lower costs.

Deepwater drilling is proliferating worldwide, spurred by advances in seismic acquisition and analysis. The application of seismic imaging and advanced processing has had a major effect on reducing drilling risk. As a result, exploration success has been dramatically improved, particularly in three key areas: West Africa, the Mediterranean Sea and Brazil.
Deepwater discoveries total 57 billion boe. For natural gas, this calculation uses the conversion factor of 10 Tcf equals 1 billion boe to reflect value, rather than the caloric equivalent of 6:1 since in deep water, gas is not as valuable. It is worthwhile to examine the migration of deepwater activity by comparing the geographic mix of deepwater reserves reported in 1999 with today's data. Whereas Brazil had the early leadership, the tables have turned, and the playing field has become quite level (Figure 1).
This is not to take away from the invaluable contribution of Brazil in leading the way with applications of deepwater technology. The combination of a benign political environment coupled with unusually astute corporate vision on the part of Petrobrás provided a climate for attacking the deepwater frontier that may not have been available elsewhere - at least not at the time. Of course, it is a well-recognized fact that Brazil has powerful incentives for developing its petroleum reserves. With a huge anticipated demand from the power-generation sector as well as the largest techno-industrial complex in the Southern Hemisphere, Brazil is quite literally in a "sink-or-swim" situation. It has chosen to swim.
Looking at the global scoreboard, more than 1,000 exploratory wells have been drilled in deep water worldwide, with almost half of these in the Gulf of Mexico. Nearly 200 have been drilled in Brazil, 120 in West Africa, 85 in northwest Europe and 81 in Southeast Asia. Brazil and West Africa have accounted for 70% of the ultradeep wildcats - generally in waters more than 4,922 ft (1,500 m) deep.
Deepwater drilling started in the 1970s but took off in the mid-1980s, averaging about seven wells per year until 1994. There has been an explosion since then, with more than 115 wells in 1998 and 140 and 145 in 1999 and 2000, respectively. The surge was due to advances in geological knowledge and seismic technology, especially 3-D, which improved the success rate and reduced drilling risk. Deepwater production system design and construction lowered the cost of bringing the reserves into production.
Between 1994 and 1998, the deepwater success rate averaged 36%, comparable to the current average success rate of 40% in all the offshore (except North America and 1994 to 1998). Prior to 1994, the average was 28%. So deepwater drilling bears a risk comparable to shallowwater drilling in finding reserves. The success rates show considerable variation among regions (Table 1).
Deepwater demand
In forecasting rig demand in a region, an analyst must review results on a country-by-country basis. Since the market driver with the greatest influence on demand for rigs is, by far, geologic success, it makes sense to point out the high, central and low success cases. A regional forecast considers differing operational realities in each geographic region. Those realities affect the model parameters: time to first appraisal well, average number of appraisal wells, appraisal well success rate and percentage of finds sanctioned for development.
Comparing visible effective rig supply with regional rig demand through 2010, an overall rig shortage appears around 2004 if new building doesn't begin soon. But a common rule of thumb regarding new-builds states that 10 times the average day rate should equal the new-build cost. With new-builds costing as much as US $350 million and with the highest day rates in the $200,000 range, a spurt of building is not expected anytime soon (Figure 2).
Looking at deepwater rig shortage and surplus by water depth, all rig categories except the ultradeepwater fleet will be in short supply by mid-2005. Of course, it could be argued that the ultradeepwater fleet can offset shortages in shallow waters, except that according to the model, the ultradeepwater fleet is fully utilized and no excess capacity exists through 2010 (Figure 3).
How deep is deep?
Forecasting deepwater activity is not without controversy. Although fundamental, the very definition of deep water has been the subject of a continuing debate. To the average person, anything over 6 ft (2 m) is deep enough to qualify. But deep water is defined differently in just about every offshore business environment. In the oil and gas drilling business, the definition evolved as drilling and production methods changed to accommodate greater water depths. A threshold was reached when the practical water depth limit of a platform was determined to be about 2,000 ft (610 m). Passing this threshold forced the use of a floating production facility or a subsea scheme - enough to warrant a threshold. Even so, North Sea drillers preferred to use 1,600 ft (500 m), a significant difference.
A case can be made for the North Sea. There, harsh metocean conditions can downgrade a rig's deepwater capability. Safety concerns limit variable deck load to less than calm sea conditions. Thus a Gulf of Mexico or West Africa deepwater-rated floater might find itself out of the running for a North Sea contract.
While folks were arguing about which threshold to use, drilling technology improvements enabled routine probing beyond 2,000 ft (610 m), and before long, operators began staking prospects in 5,000-ft (1,525-m) waters. This called for another threshold, because the requirement to support 5,000 ft (1,525 m) of marine riser, associated tubulars, drilling fluid and equipment necessitated a new-generation floating rig. Moreover, wells in water this deep were necessarily far from coastal support bases (except in rare instances), and the rigs had to accommodate more crew, supplies, tubulars and spare parts. Thus, the industry defined the ultradeepwater threshold as greater than 5,000 ft (1,525 m) of water. At the time, even experienced drillers shook their heads and opined it was a moot point. Few viable wells would ever be drilled at those depths. However, as many as eight floaters claim water depth capability to 10,000 ft (3,303 m).
Technology to the rescue
A seeming counter-trend is emerging. Technology improvements allow second- and third-generation floaters to drill in deep and ultradeep waters. This means the market metrics that justified $350 million new-builds might be tossed, and owners of these behemoths could find themselves competing with 1970s vintage rigs.
The problems with deep water are geological and technological, and together they justify terming the resource nonconventional. But deepwater problems have solutions. The incredible growth of enabling technology has permitted worldwide deepwater development to accelerate, limited only by rig availability and access to drilling and development capital.
Back to the future
Attempting to drill in waters 5,000 ft (1,525 m) deep or greater using rigs rated to 2,000 ft (610 m) seems like sending David out to slay Goliath. But in certain benign metocean environments, the practice has been technically successful and, most importantly, cost-effective.
Several major oil companies are pioneering the idea of drilling exploration wells from a floater in deep water, using a high-pressure riser and a dry land blowout preventer (BOP). By suspending the BOP in the moonpool and employing moderate environment heave compensation, the floater is used much the same way as a jackup. Introduced by Unocal, the technique is called saturation exploration (SX) drilling and has been successful in up to 6,730 ft (2053 m) of water in Southeast Asia. The company has proved the reliability of the technique drilling more than 130 wells in this manner.
With conventionally drilled subsea wells in the region costing $15 million to $30 million, the incentives to economize are compelling. Unocal reports well costs of only $4 million to $6 million when the SX technique is used. A large measure of the savings comes from elimination of the subsea BOP and large-diameter marine riser. That, plus the ability to use a floater with low to moderate variable deckload capacity has enabled the company to contract more economical rigs.
When using a dry BOP, the operator must conduct extensive modeling of the historic metocean environment in the region to be explored. It then models each task of the drilling sequence, taking into account the physical characteristics of the rig proposed to do the work. Before giving the green light, the operator and contractor must agree that there is no increased risk to the rig or personnel. Some increased well risk may be acceptable, because even if 10% of the wellbores are lost, the cost to redrill them is more than compensated by the savings offered by the program.
A certain amount of customization may be required to adapt the BOP stack to the particular moonpool of the intended rig, but with attention to detail and a little engineering, the modifications can be implemented with a reasonably modest investment of time and money. Other players using or considering the technique include Shell, Chevron, Woodside Energy, TotalFinaElf, Petrobrás and Conoco.
Getting rid of the shakes
Destructive vibration of tubulars caused by deep ocean currents is a major cause of concern in deepwater drilling and production operations. Vortex-induced vibration (VIV) is caused when vortices of water spin off or shed from a structure. The result of unmitigated vibration in risers, casings and subsea structural members is often a catastrophic failure. As drilling ventured into deeper waters, the risk multiplied as longer unsupported sections of cylindrical material were exposed to undersea currents. The problem was exacerbated by the fact that at different depths, subsea currents travel at different velocities and in different directions, thus setting up extremely complex VIV modes.
Extensive research and development has been conducted in the area of VIV, resulting in numerous VIV mitigation tools, such as fairings, gap spars and helical strakes. All of these proved expensive and of marginal effectiveness.
Recently, Shell engineers investigated the effect of the roughness of cylindrical surfaces on the buildup of marine current vibration. Using the facilities of the US Naval Warfare Center in Maryland, they examined the drag of flexible cylinders at critical and supercritical Reynolds numbers in the ranges normally encountered in offshore drilling and production. They observed a direct relationship between surface roughness and VIV.
The conclusion was that VIV can be virtually eliminated by the use of sufficiently smooth cylindrical members in the subsea environment. Subsequent testing showed that acceptable degrees of smoothness can be achieved either by using smooth cylinders to begin with, or by installing smooth sleeves over rough or irregular surfaces to suppress VIV. The technology was successfully tested offshore Trinidad when the semisubmersible Stena Tay was equipped with smooth sleeves to keep it stabilized in extremely harsh currents. Shell reckons it saved millions of dollars by avoiding VIV-related downtime.
Atlantis rediscovered
Not willing to wait for the discovery of the mythical lost civilization, one Norwegian company has proposed development of an artificial seabed called Atlantis from which to conduct drilling and production operations. The effect on the supply of deepwater drilling units could be profound.
The plan involves installing a large buoy some 400 ft (122 m) below the ocean surface, held in place by tendons that form the risers of the wells to be drilled on the structure. These are tethered to a seabed template and serve to anchor the buoy in a stable state. The buoy supports the BOPs and subsea connections normally found on the seabed template. The result is a stable artificial seabed in relatively shallow water.
Wells can be drilled using a floating rig with shallow water-depth capability, because as far as the rig is concerned, the water is only 400 ft (122 m) deep. A capacity-limiting factor of deepwater drilling units is variable deck load. In conventional drilling, much of a rig's deckload capacity is taken up supporting thousands of feet of heavy marine riser. By using the artificial seabed approach, only 400 ft (122 m) of riser is required. Thus companies could use less costly floaters to develop their discoveries. This also would free fourth- and fifth-generation floaters to do more exploration drilling, alleviating potential supply problems.
Wells could be batch-drilled. Then the rig could be released and a floating production, storage and offloading vessel positioned above Atlantis to take the production. Alternatively, a combination drilling and production floater could be used so wells could be drilled, completed and brought onstream sequentially. Atlantis is an idea waiting to be tested, but its successful introduction could have major implications on deepwater supply and demand scenarios.
Other technological developments can extend deepwater capabilities. These include dual-gradient drilling, riserless drilling, expandable tubulars, composite tubulars and mooring lines. Some of these are available today. Once a technique seems to work and is proven reasonably reliable, it can be implemented fairly quickly, much faster than an extensive rig-building program.
But with global energy demand continuing unabated, it is unlikely that technology will be able to solve all the supply problems. A balanced approach is required.

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