Drilling with casing (DwC) typically eliminates 20% to 30% of rig time by removing the need for a pilot hole. It virtually guarantees getting to the planned casing depth, minimizes hole stability problems associated with fluid loss while drilling.

DwC mitigates fluid loss problems because of the “smear effect” — as the rotating casing rubs against the formation, it plasticizes the cuttings and creates an artificial filter cake that prevents fluid from getting into the formation. And because the annulus is smaller, fluid flows faster, cleaning the hole more effectively and allowing reduced pump rates.

DwC also solves another problem. Some formations are so time-sensitive that if the hole is

Figure 1. Weatherford’s Drillshoe III drillable casing shoe — a PDC bit capable of drilling formations with unconfined compressive strength of 20,000 psi — eliminates the need for a special drill-out run or BHA retrieval after drilling to total depth. (Photos courtesy of Weatherford International)
left open too long, the formations become unmanageable. Drilling with casing minimizes the time between drilling and casing off the well bore, reducing formation exposure and the possibility of hole loss. The idea for drilling with casing is not new, but much of the technology making it possible is innovative. New top-drive systems allow casing to be circulated, rotated and even reciprocated during run-in. Such systems can replace power tongs, elevators, fill-up and circulation tools and weight compensators, while requiring only a driller, a tool operator and one or two rig hands to operate.

Drillable casing bit

The most important technology for DwC and drilling with liner (DwL) for the industry today involves having the mechanical and hydraulic ability to get the casing or liner string to its planned depth, isolate the problem zone, and be able to drill out with conventional means.
A key component of the DwC system is Weatherford’s DrillShoe III drillable casing bit, which performs as a polycrystalline diamond compact (PDC) bit until total depth (TD) is reached, at which time a ball dropped into the string falls into a receptacle in the bit where it blocks fluid flow from the drilling nozzles.

Pressuring the casing string up to approximately 2,000 psi shears the DSIII pins and forces the tool’s inner piston downward. This action displaces the PDC cutting structure into the annulus of the hole exposing the cementing ports, allowing fluid to circulate again. The entire cutting structure is eventually cemented in place in the annulus. The aluminum inner piston of this bit is fully drillable with conventional mill tooth and PDC bits — a special bit or mill run is not required. Because the tool is a true PDC bit, it can drill through formations with unconfined compressive strengths of up to 20,000 psi.

When this bit is used to drill with liner using a high-torque liner drilling system, the same pressure event that displaces the bit can also set the liner hanger and release the liner from the running tool. For DwL operations subject to high differential pressures (e.g., packoff problems), liner drilling tools are available that are not sensitive to differential pressures while drilling but require a ball dropped from the surface coupled with a pressure event to enable the setting tool to release. New stage tools also make it possible to combine DwC and stage-tool cementing, as problem wells in Colorado have proven.

Solving problems in Colorado

The gas fields of the western Piceance Basin in northwestern Colorado include dipping formation beds that lead to “crooked hole” drilling, plus fractured shale formations that steal circulation and can make it impossible to return cement to surface during primary cement jobs. Sometimes casing cannot be run to total drilled depth. One Piceance Basin operator decided to approach these problems by combining DwC with stage-tool cementing.

Seven wells have been successfully drilled by this operator using the DwC technology to date allowing casing to be drilled to planned TD, reducing open-hole exposure time as well as non-productive rig time. In all of these wells, it was possible to keep the annulus nearly full during drilling, which minimized problems with sloughing shales. The rigid DwC bottomhole assembly (BHA) successfully mitigated deviation problems as seen with the previously used mud motor BHAs.

Figure 2. In the Piceance gas fields of Colorado, the pipe-handling arm of a singles-type rig lifts this 9 5/8-in. Drillshoe III with an integral centralizer. Drilling with casing using this technology requires no rig modifications.
Low weight-on-bit with the DwC system prevented major hole deviation problems. And finally, the use of a multiple-stage cementing tool in the DwC BHA enabled cement to be circulated to surface, the key requirement necessary to satisfy the Bureau of Land Management regulatory authority.

The technology used included the DrillShoe III, an internal casing drive tool (a high-strength spear that requires no rig modifications), a double-flapper-valve float collar (to allow passage of the ball required to displace the cutting blades of the drillable casing bit), and a mechanical two-stage cementing tool. The system, which also included the first use of combined DwC and multistage cementing, achieved an average 47% reduction in nonproductive time and reduced fluid losses substantially. It also cut hole deviation by an average of 44%. All wells reached or exceeded their depth goals.

Liner drilling offshore Mexico

Production in the Carpa field offshore Veracruz, Mexico, comes from the El Abra zone, naturally fractured limestone prone to lost circulation. The formation lies underneath the Brecha formation, a calcareous shale zone with sandstone stringers. Hole stability problems in the Brecha combined with lost circulation in the El Abra (both are hard formations) often lead to stuck pipe and poor cement jobs that require extensive remediation work. A typical well would require 95¼8-in. casing above the El Abra plus an expensive sacrificial 7-in. liner through the producing horizon.

One major operator decided to use DwL for one of their development wells to reduce openhole exposure time, eliminate the surge and swab forces of conventional tripping, minimize lost circulation, and increase hole stability. The well would be nearly horizontal (75°), so directional control would also be an issue.

The plan was to set and cement

13 3/8-in. surface casing and then drill 12 1/4-in. hole conventionally to a point above the Brecha formation. After hole conditioning, the DwL BHA (including the drillable casing bit) would be run into the hole and used to drill onwards through the Brecha formation and into the El Abra. At this point the displacing ball would be dropped and a single pressure event would displace the PDC cutting blades of the drillable casing bit into the annulus, set the 95¼8-in. liner hanger set, and release the liner hanger running tool. The liner would then be cemented in place and the liner hanger packer set and tested in the 133¼8-in. casing.

Following cleanout, the 9 5/8-in. tieback string would be run, the liner tieback tested and
then cemented. The DwL operation drilled 266 ft (81 m) of 12 1/4-in. hole in 45 hours in a hard-rock drilling environment while maintaining 75° inclination and azimuth. No fluid losses or hole stability problems occurred, validating the beneficial smear effect of DwL. The single pressure event saved valuable rig time and simplified operations.

The operator confirmed that DwL saved a total of 39.5 days compared to previous conventional operations. This saving, plus not having to install a 7-in. sacrificial liner, was worth a total of about US $4.5 million.