Deepwater Rig Requirements
From a broad business perspective, the challenges of deepwater drilling are similar to those encountered in other oilfield projects: namely, to deliver the desired result on time and on budget while avoiding accidents and environmental incidents. The main difference is one of scale. Deepwater drilling is a high-stakes game involving very large expenditures for the opportunity to find and produce large volumes of hydrocarbons. Everything costs more in deepwater, beginning with the drilling rig itself. Therefore, there is great emphasis on the efficient use of the rig and all associated equipment.
Load-bearing Capacity
The extreme demands of deepwater drilling require high load-bearing capacities. A rig must be able to support long, heavy strings of drill pipe and casing and a marine drilling riser, as well as a subsea blowout preventer and wellhead assembly that may have a working pressure rating of 15,000 psi. This requirement affects the design of the vessel’s hull, drilling systems and marine systems.
- Deck load is less an issue for drillships than it is for semisubmersibles. Early semisubmersibles had deck loads of about 2,000 tons or less. This increased to 4,000 – 5,000 tons for semis built during the 1980s. The leading deepwater drilling unit of that time (a drillship) boasted a variable load of 9,100 tons. New semis built in the late 1990s and 2000s vary in deck load from 5,000 to 10,000 tons, depending on their water-depth and drilling-depth ratings. The lower range of deck load for semis rated for 10,000-ft water depth and 30,000-ft total well depth is about 7,700 tons, and the upper range exceeds 10,000 tons. The deck-load capacities of large drillships are now in the range of 20,000 to 25,000 tons.
- The derrick and associated equipment that supports the drillstring, riser, and casing must be made stronger and more powerful for deepwater operations. Deepwater rigs are typically equipped with greater mud pumping and power generation capacities than are found on shallow-water units.
- Station keeping requires either a deepwater mooring system with longer lengths of chain and wire or a thruster-powered dynamic-positioning system (DP). Rigs drilling in deepwater are always equipped with a dedicated remotely operated vehicle (ROV) system. Each of these elements adds deck-load weight.
Supporting this extra weight requires additional buoyancy, which can only be achieved by increasing the size of the hull so that it displaces a larger volume of water. The extra weight, carried at or above deck level, also creates stability problems that must be addressed by the hull design. The additional structural steel and steel plating increase the weight of the hull, which in turn places greater demands on the station-keeping system. The additional size and capacities raise the cost to build deepwater rigs. The cost, in turn, is reflected in higher day rates for deepwater units and, thus, in the cost of deepwater wells. This all finally means that the oil and gas prospects targeted for deepwater drilling must be of sufficient size to allow these costs to be recovered.
Efficient Use of Rig Time
The need for greater load-bearing capacity adds significantly to the overall cost of drilling wells in deep and ultra-deep water depths. The high costs challenge drillers to optimize all aspects of the drilling process so that these expensive rigs can operate with the greatest possible efficiency.
The offshore industry in general places a premium on saving rig time by operating as efficiently as possible. At present, this goal is handicapped by a shortage of qualified personnel, an issue that is beyond the scope of this discussion. This section provides a brief overview of several aspects of deepwater operations where companies seek to improve efficiencies.
Mobilization and Moving onto Location
Deepwater MODUs are typically on full day rate when moving from one drilling location the next. These moves, or mobilizations (“mobs”), can involve cross-ocean voyages between such locations as the North Sea, Gulf of Mexico, Brazil, and West Africa. Drill ships make these mobs under their own power. For semis, these long-distance mobs can be hastened by loading the rig aboard a heavy-lift vessel for a “dry tow” rather than using tugboats to wet-tow the rig with its hull in the water (Figure 12. Source: Charles Townsend)
More often, the distance involved will be short—from one block to another within the same region or between two drilling locations within the same block or the same field. The opportunities for optimization are greater during a series of short moves, particularly when a rig is drilling and completing a set of subsea development wells within a single field. Dynamic positioning offers the greatest efficiency, since there are no anchors and mooring lines to deploy. But even with conventionally moored MODUs, careful planning can minimize the number of moves and reduce the time each one requires.
In development drilling projects, subsea wells can be located in several groups around the field so that each well in a group can be drilled by simply repositioning the rig using its mooring winches to take in and pay out line, rather than retrieving and deploying the entire mooring system. In this manner, it may be possible to drill 12 to 15 wells with only three to five rig moves.
Spudding the Well
The first set of tasks involved in spudding, or getting a Deepwater well started, require round-tripping the drillstring several times. In water depths of 5,000 to 10,000 feet, this takes considerable time, during which nothing else is happening to actually advance the drilling operation. If any of these tasks can be combined, thereby eliminating one or more round trips, it will improve the overall efficiency of the operation.
The uppermost sections of a Deepwater well are typically drilled without the BOP or drilling riser in place. Before drilling can proceed to more than 1000 to 1500 ft or so below the sea floor (mudline), however, the BOP and marine drilling riser must be deployed (Figure 13 –Subsea BOP stack in place at the end of drilling riser. CAD computer model for deep sea scientific drilling vessel D/V Chikyu. Image provided courtesy of JAMSTEC. All rights reserved). The drilling riser is a tubular column that extends the well with full pressure containment from the BOP to the drilling rig, providing an annulus around the drillstring for drilling fluid to return to the surface. Installing the BOP can involve two roundtrips of the drillstring, with the riser being run between the two. Because of their design, the requirement for pressure integrity, and the need for buoyancy along their length, running and retrieving a drilling riser is more time-consuming than tripping the drillstring or running a string of casing.
It is possible to move from one well to another without retrieving the riser and BOP to the surface if the wells are close enough to each other. The BOP is released from the finished well, raised above the seafloor, and hung off beneath the drilling rig while it shifts to the next well. This can be performed with little risk when the two wells are very close together, as is the case with much deepwater development drilling.
To enable this kind of time-saving operation while also having the ability to spud a well with riserless drilling, some newly built or upgraded Deepwater rigs are equipped with dual drilling systems, so they can perform certain operations simultaneously (referred to as dual-activity (Figure 14, Deepwater dual activity semisubmersible West Venture). While the primary drilling rig suspends the BOP and riser above the seafloor, the second derrick is moved over the new well and performs the riserless operations to get the well started. When these are finished, the primary derrick is moved over the new well to attach the BOP, and drilling can then proceed without the delay of round tripping. The dual-activity capability removes the installation of the BOP and drilling riser from the well schedule critical path.
This may seem to be an extreme measure, but it does indicate the lengths to which drillers and oil companies will go to save rig time with Deepwater MODUs that carry $500,000 day rates. If two days can be saved when initiating a new well, the cost of a second derrick will be well worth it. Oil companies monitor drilling operations closely for “unproductive time,” a category covering just about all the time that the well is not making progress toward its target, i.e., drilling, running casing, cementing casing, and so forth. Their goal is to reduce the unproductive time to an absolute minimum.
Marine Drilling Riser Design and Operation
No piece of equipment is more important to the success of deepwater drilling than the marine drilling riser. As the extension of the well between the BOP and the drilling rig, the riser is a primary device for pressure containment and well control. It is also the conduit for drilling fluid to return to the surface and the guide for the drillstring and casing down to the wellhead. Riser failure has very serious consequences for drilling operations, safety, and environmental protection.
The riser is made up of a series of 20-21-inch ID tubular joints coupled together with highly engineered connectors – threaded, flanged, or mechanical.
Kill and choke lines used to re-establish well control when a gas kick occurs are attached to the outside of the riser and terminate at the BOP stack. A 20-in. steel tube with several much smaller tubes attached to it and extending up to 10,000 feet between the surface and seafloor has little structural integrity and is obviously very vulnerable. Tensioning at the top allows it to resist environmental forces. To perform reliably it must be designed with the utmost care.
The design and specification of the riser must take into account the loads and stresses that it will experience over the entire range of the rig’s drilling capabilities. These include hydrostatic pressures; the MODU’s motions in response to maximum environmental conditions for drilling operations; bending stresses imposed by the MODU’s lateral motions, particularly if the motions exceed the limit of the pre-defined watch circle; and fatigue from repeated motions and vibrations that may be caused by currents. There is also the special case of riser hang-off in the event that the rig must rapidly disconnect from the well in an emergency.
The lower end of the riser is firmly attached to the BOP at the seafloor, while the upper end is attached to the moving drilling rig. Although the rig’s motions are limited by the mooring or DP system and the riser is suspended from the rig by a set of tensioners so that it will never go into compression, the riser still responds to rig motions. Its behavior in service is thus dynamic instead of static and many of the loadings are nonlinear. Analysis of a specific riser design can be as complex and exhaustive as the available budget allows and includes static, quasi-static and dynamic methods, as well as finite element analysis of local components, such as joint connections. API Recommended Practice 16Q (1993) covers marine drilling riser analysis in detail.
