Total circulation losses and gas kicks can make wells seemingly undrillable. After one operator spent 60 days trying to drill a well in South Sumatra, Indonesia, these problems actually made drilling impossible. Two years later, the operator tried again, using the pressurized mud cap drilling variant of managed pressure drilling — and reached target depth in just 19 hours, with no non-productive time (NPT).

In the Cuu Long basin of southern Vietnam, a constant bottomhole pressure system allowed the successful completion of the longest well ever (21,411 ft or 6,530 m) in a pressurized, fractured-basement reservoir where losses and kicks are common. Controlled annular backpressure made it possible to drill with a reduced-weight brine, which also increased hole cleaning and rate of penetration (ROP).

Since 2005, managed-pressure drilling (MPD) techniques like these have been successful in more than 150 onshore and offshore wells of many types in the Asia Pacific region. MPD delivers significant cost savings by cutting NPT associated with kicks, losses, and well-control events, increasing ROP and making previously “undrillable” wells drillable. Operators find that using MPD cuts their NPT and costs from 20 to 100%. MPD typically requires only minor modifications to the rig, and it permits all drilling, logging, and completion operations to be executed safely and efficiently.

Pressurized mud cap drilling operations. Here a flow spool installed below the RCD allows fluid to be pumped into the annulus.(Images courtesy of Weatherford International)

The main application of MPD in Asia Pacific has been in fractured carbonates such as the Baturaja and Kujung formations in Indonesia. In every case where MPD equipment has been rigged up, the well has been drilled successfully without significant NPT. Today the industry is witnessing the expansion of MPD techniques into high-pressure, high-temperature (HP/HT) wells, where it helps eliminate problems of wellbore breathing and influx control.

MPD techniques

All MPD systems use a rotating control device (RCD) to enclose the mud return system; today there are many MPD technologies to suit specific conditions.

Returns flow control is simply a safety measure to divert gases away from the rig floor. By diverting gases, the RCD avoids having to close the blowout preventer (BOP), and it allows pipe movement while circulating out gas influx.

Constant bottomhole pressure applications require a choke in the return flowline to apply back pressure during the drilling process.

Pressurized mud cap drilling (PMCD) is widely used in Asia Pacific and is ideal for fractured and vuggy carbonate reservoirs where total fluid loss is common; in fact, it can only be used where there is total loss (Figure 1). A mud “cap” is pumped down the annulus, where it remains in place and forces cuttings and the sacrificial drilling fluid (usually seawater) into the loss zone. Seawater is cheap, and it increases ROP. Floating mud cap drilling (FMCD) is a variant in which reservoir pressure is lower than hydrostatic pressure; here, the top of the fluid drops to a balance point down in the well.

Constant bottomhole pressure (CBHP) is effective when there is a narrow window between pore pressure and fracture gradient (Figure 2). By eliminating pressure fluctuations during connection make-up, CBHP eliminates kicks and losses. There are various approaches: annular backpressure applied through a choke and pumps (the simplest), continuous circulation while connections are made up using special subs in the drillstring (which prevents cuttings from settling and eliminates stuck pipe), continuous annular circulation (to prevent temperature and pressure fluctuations in HP/HT wells), and annular pumping (to reduce annular pressure and help extended-reach wells reach total depth).

Riser cap installation. The slip joint on the riser is collapsed and locked; the RCD is installed using a riser adaptor to the top of the slip joint.

Finally, dual-gradient MPD is used in deepwater applications where the marine riser is displaced with seawater, eliminating the mud column between the rotary table and the seabed.

Switching to MPD

It is rare for MPD to require significant rig modifications. Some land rigs require additional space between annulus and the rotary table for the RCD, but offshore rigs normally only require welding tie-in points for the main flowline to ensure that returns can be taken back to the shakers.

While MPD is simple to employ, it is important to plan and rig up for before drilling starts. The well can be drilled conventionally until the need arises to manage well pressure. Then it takes only minutes to switch to MPD operations: the RCD bearing assembly is installed, the flowline to the shale shakers is closed, and the well is diverted to the choke manifold for CBHP operations or to the annular fluid injection system for PMCD operations.

Fixed installations

Many land rigs lack sufficient space under the rig floor for MPD; pony subs are the best way to raise the rig. Removing a ram or the annular BOP to make space can seriously impact well control and is not recommended.

RCD docking station installation for floating and deepwater rigs. The slip joint is removed and a crossover and spool are rigged on top of the riser.

Rig alignment is an issue: for an RCD rubber packer to perform optimally, the rig must be aligned with the BOP to within 0.5 in. — anything larger seriously shortens the life of the rubbers. For safety and efficiency, flowlines to the BOP stack should be equipped with hydraulically controlled valves so operations can be conducted from the rig floor.

Floating installations

Offshore rigup must consider riser pressure ratings, slip joints, heave, emergency disconnects, flexible return flowlines, moonpool operations, and conventional drilling operations when switching over to MPD. Typically, the RCD is rigged on top of a collapsed and locked slip joint on the marine riser while the BOP remains on the seabed (Figure 3).

Heave does not appear to have a significant impact on the life of RCD rubbers, although drillpipe condition is important, as grooves, hard banding, etc., are affected when the pipe is stripped.

Rigging up MPD for deepwater operations requires significant forward planning and a novel RCD “docking station” design. The drilling riser and conventional flowline remain in position while the RCD bearing assembly is installed through the rotary table and riser. With this rigup, the well can be drilled conventionally with all of the MPD equipment in place (Figure 4).

To switch to MPD operations, the bearing assembly is installed, the valves are opened, and drilling resumes in MPD mode with returns taken up the flexible flowline. For PMCD, the cap fluid can be injected through the flexible flowline. This system greatly enhances safety since no one needs to access the top of the marine riser during MPD operations.

Gaining efficiency

In Asia Pacific, MPD has proven that it can eliminate non-productive time related to kicks, losses, and well control. Rig modifications for most MPD operations are minimal, and for a small investment, operators gain significant efficiency benefits. They can drill ahead undisturbed in previously undrillable formations, they can drill ahead while circulating out large amounts of gas, and they can drill a hole cleaner and faster without worrying about differential sticking. MPD makes it possible to efficiently drill deeper than ever before.

The critical decision in Asia Pacific should not be whether to use MPD, but what kind of MPD to use.