Shell Exploration and Production stages a successful campaign to lower drilling costs.

Drilling, particularly offshore, is a producer's most expensive operation. Shell Exploration & Production Co. watched returns climb dramatically as it lowered that component of offshore activity.
For Shell, that effort comes from exploitation of useful new technology and its Drilling the Limit (DTL) program. The concept is simple. Instead of trying to cut existing costs to the bone, Shell creates a perfect, trouble-free well on paper and tries to match it in the field.
The result is striking. In deepwater subsea completions in the Gulf of Mexico, using one rig with no rig move, Shell took 75 days to complete an average well - including 18.3 trouble days - at a cost of US $21.4 million in 1997 and 1998.
In the following 2 years, it cut average completion time to 45.9 days, trouble days to 17.8 and costs to $17.2 million. A lot of additional opportunities look good when a company can save $4.2 million on an average well.
The program continues, said Don Jacobsen, Shell's drilling and completions manager. Through the first 10 months of 2001, average time to complete a subsea well dipped to 26.5 days, trouble days dropped to 5.7, and the average well cost plunged to $13.2 million.
Plug that savings and similar savings into 19 new wells, 17 re-entry sidetracks, 26 completions (nine subsea), 14 recompletions and workovers and 16 plugging and abandonments and before long the savings mount up to a few more wells, more reserves, more production and lower finding costs under the same budget.
Back to the field
Following the restrictions of technology and economic limits, Shell and other operators in the Gulf of Mexico drilled shallower reservoirs first and are returning to drill to lower formations, but trying to push a drillstring through depleted reservoirs causes drilling problems. To fight problems of stuck pipe and hole collapse, Shell, working principally with M-I, has developed special fluids and formation strengthening and drilling technology to drill through those zones. That technology allowed the company to drill its Ursa A-11 well through a 6,000-psi depleted sand without affecting the nearby Ursa A-6 horizontal well that was producing
30,000 b/d.
Among accomplishments at its Gulf of Mexico Ursa platform, Shell has:
• three wells longer than 5 miles (8 km) MD;
• the longest Gulf of Mexico platform well at 30,100 ft (9,181 m);
• the single-well production record at 49,700 boe/d;
• 23 million bbl of oil produced in 2 years from a single well; and
• a six-well average production per well of 36,600 boe/d.
Bigger holes, lighter rigs
Think about the best well for the Gulf of Mexico, or any other deepwater application, and then consider the restrictions.
Deep and ultradeepwater wells, particularly wells that go through the seafloor into high-pressure formations, require several strings of casing, each smaller than the one above it.
The number of casing strings, the hole size and completion requirements set the size of the blowout preventer (BOP) and the wellhead. Some of the wells run out of casing diameter before they reach the target formation. Still others are so small by the time they reach the producing formation that they restrict the flow of hydrocarbons.
For example, an average well at Shell's Picaroon field produced 32 MMcf/d of gas through 2 7/8-in. by 2 3/8-in. tubing, while Alex will produce 130 MMcf/d through 4-in. tubing and Crossbones is expected to produce more than 130 MMcf/d, also through 4-in. tubing.
At the same time, big pipe means big offshore rigs, heavy-duty mooring systems and a host of equipment and techniques designed to handle the sheer size of the job. Riser, mooring and deck loads set requirements for the drilling vessel, said Paul Goodfellow, floating rigs operations manager for Shell.
The whole system would be a lot easier to deal with, and a lot cheaper, if an operator could reduce the scale but keep the larger diameter production pipe. Daily rig costs and time on the well determine most of the cost of the well. In addition, the deeper wells and higher temperatures and pressures make wells more difficult to drill.
Goodfellow offered his list of technology opportunities to keep operations simple and drilling inexpensive:
• set up the well to keep production casing diameter large for high-rate completions;
• use casing expansion to maintain hole diameter;
• dual-gradient drilling allows drilling with fewer casing strings and keeps riser use only to guide tubulars;
• smaller BOPs are required because there are fewer casing strings and less maintenance of hole diameter;
• the riser in a dual-gradient well can be lighter and smaller because fluids return to the surface by an attached conduit;
• suction anchors and lightweight synthetic lines can be used to moor drilling vessels in deeper water; and
• the BOP can be maintained at the
surface.
The effect of these changes, he said, means an operator can use a compact rig because riser loads and sizes are smaller, because it handles smaller tubulars, because drilling fluid volumes are lower and because the mooring system is lighter.
Shell will take a step forward this year by starting with a monobore well to identify and solve potential problems with the technology, he said. If everything works out, it will bring monobore wells offshore later in the year.
Shell is also constructing a subsea pumping (dual-gradient) system to be installed on the Transocean Sedco Forex Nautilus in the fourth quarter of this year. Shell will then have the capability and opportunity to use as few as two casing strings instead of six by using dual-gradient drilling.
The next step in that evolution will be the monobore well.
Preinstalled mooring systems are limited to about 8,000 ft (2,440 m) of water because of the weight of the steel in the wire, Goodfellow said. Shell has used a system with synthetic rope installed and recovered by a single boat in 9,100-ft (2,776-m)waters at Alaminos Canyon Block 867 in the Gulf of Mexico. That lighter weight extends the drilling rig's capability.
The preinstalled system allows moored vessels to safely moor over such existing seafloor infrastructure as pipelines.
Shell has used a surface BOP on a floating rig for normally pressured wells in Southeast Asia. It is developing a similar surface BOP for use on the geopressured wells of the Gulf of Mexico.
Goodfellow estimated use of a completion or intervention vessel to do some of the work done by a conventional drilling rig could save 25%. Dual-gradient drilling has the potential to save 40% compared with conventional drilling. A compact rig would cost 25% less than a full-size rig, he said. A dual-derrick rig in use on some drilling vessels can save 25% on drilling costs. Eventually, using a combination of these technologies, an ultraslim rig used to drill monobore wells will save in excess of 50% over conventional drilling and rig combinations.
To handle all those applications, Shell has completed design work with key contractors for the ultraslim rig.
In real-life, dig-down-in-your-pocket terms, assuming the technology is successful, a second- or third-generation drilling rig capable of working in 2,000-ft (610-m) waters and drilling to 20,000 ft (6,100 m) will be able to work in 7,500-ft (2,288-m) waters and drill to 30,000 ft (9,150 m), Goodfellow said, and it will do that work without substantial structural changes.
Expandable tubulars
A key part of that smaller, better rig depends on the use of expandable tubulars. The large number of casing strings and small diameters at the bottom of the hole represent inefficiency in producing, said Ken Dupal, senior drilling engineer.
Those inefficiencies led Shell experts to take a good, close look at its technology options in 1997 and 1998. They saw that increased BOP, riser and wellhead sizes required larger rigs, larger equipment and bigger risers. They saw that dual-gradient drilling was the best technical solution, but it would take time. They saw that expandable tubulars had a high value, if they could be made to work.
The team had to decide on an expansion process, pipe material, connections, mandrel design and cementing techniques to make the expandable tubing rig-friendly.
Shell experts worked with Halliburton on the expansion system and decided on Lone Star LSX 80 material for the tubulars. The material had to expand at typical downhole temperatures, and the expansion process had to control the stress on the pipe so that it didn't fail during the process.
After a series of tests, problems, learning experiences and solutions, Shell is ready to make expandable tubing a standard item in its well design arsenal.
The value of expandables, Dupal said, is in ultradeepwater wells with low drilling margins. It can be used for contingency liners in deep wells and subsalt for low-margin conditions of borehole stability, and it allows a step change in wellbore and rig design.
Now that the industry is starting to get comfortable with expandables, the next step will be the compact rig using a 135/8-in. BOP and tubulars with the same diameter from top to bottom. Shell likes the 95/8-in. tubular size for that monobore operation.
Surface BOPs
Surface BOPs aren't exactly new technology, at least for Shell. Shell Indonesia worked with Unocal on a two-well project with surface BOPs using the Sedco 601. Shell then used the same rig in a Shell-operated three-well project off Brunei. It also adapted the systems for a two-well program offshore Malaysia on the Stena Clyde.
The technology has the potential to lower well costs by 20% to 50%, said Graham Brander, senior well engineer. For example, if an operator doesn't have to run an 183/4-in. BOP to the sea floor and attach a 21-in. riser, it saves rig time at a rate of $145,000 to $200,000 a day. By running smaller rigs with a 135/8-in. BOP in the moon pool and 133/8-in. casing to the ocean floor, the operator saves on rig costs. Those smaller rigs may cost only $60,000 to $85,000 a day.
As side benefits, a third-generation rig can work in deeper water, and that benefit potentially extends the number of rigs available for deepwater drilling. The faster times potentially increase the number of wells that can be drilled while the rig is under contract.
Shell used a fixed BOP system in the Brunei operation, but it is moving to a BOP in the moonpool that can move laterally with minor pipe movements. That lowers bending loads on the riser and makes the surface BOP installation less dependent on the type of rig.
The company plans to use the new type of system without lateral constraints in the Gulf of Mexico. It also will include a subsea shutoff and disconnect valve to allow the rig to get away from hurricanes.
Shell also is looking at a 16-in. casing riser, the minimum size it can use for the constraints imposed by pore pressures and fracture pressures in the Gulf of Mexico's subsurface formations,
Brander said.
If everything goes according to plan and is accepted by the US Minerals Management Service, Shell should drill its first well in the Gulf of Mexico with the new system at the end of this year. That will include the whole package - a surface BOP, smaller risers, preinstalled mooring and big savings.

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