Casing While Drilling

Casing while drilling and stage-tool
cementing combined to mitigate downhole conditions

Two technologies cut drilling NPT by 21% in this Piceance basin case history.

Steve Rosenberg, Brent Lirette and Al Odell, Weatherford and Ryan Robinson, SandRidge Energy

The gas fields of the western Piceance basin in northwestern Colorado present significant challenges to drilling and casing operations. The area has complex geology, with dipping formation beds that lead to �crooked-hole� drilling. Fractured formations cause problems, including lost circulation while drilling and failure to return cement to surface during primary cement jobs of the 9 5/8-in. casing. Sometimes casing cannot be run to total drilled depth.

Operator SandRidge Energy in the region selected Weatherford's DwC (Drilling with Casing) service, combined with stage cementing of the surface casing, as an alternative that was expected to yield a significantly more effective surface-hole drilling and casing operation, reducing Non-Productive Time (NPT) and associated costs.

BACKGROUND

SandRidge Energy has been drilling in the gas fields of the Piceance basin since 2003, Fig. 1. The operator has experienced difficulty drilling and casing the surface hole, which is typically targeted to about 3,100 ft MD. Problems are caused by dipping formation beds, rock stresses and lost-circulation intervals.

Fig. 1. Operator SandRidge has been drilling in the gas fields of the Piceance basin since 2003.

Conventional drilling in the area uses mud motors and low weight on bit to drill a 12 ¼-in. surface hole, because high WOB with conventional drilling assemblies often results in severe inclination increases, sometimes in excess of 7°, Table 1.

TABLE 1. Comparison of maximum inclinations in the surface hole sections

The surface-hole geology predominantly consists of sandstone, siltstone and limestone stringers with interbedded shales. The naturally fractured formations often cause lost circulation, which in turn results in sloughing shales with subsequent pack-off and sticking.

After drilling, hole conditions make running the 9 5/8-in. surface casing to the planned depth problematic, even when the casing is washed down. Many times in the conventionally drilled holes, the operator unable to get the 9 5/8-in. casing to its planned setting depth. On two of the wells, the casing was set 300 ft and 427 ft short of TD.

Unplanned hole-conditioning trips have caused many incidents of NPT, the longest being 15 days. In the worst cases, stuck pipe from long openhole exposure time necessitated fishing operations.

Hole conditions also often have led to poor-quality primary cement jobs and difficulty satisfying the requirements of the local regulatory authority, the Bureau of Land Management (BLM). Failure to circulate cement to surface has required running a cement bond log to evaluate the cement job's integrity and, in many cases, remedial cementing and wireline operations to reach an acceptable quality of cementation. This remedial work often has resulted in 3�4 days of NPT.

An NPT analysis revealed about 32 days of NPT documented in the 12 ¼-in. surface interval from the five wells reviewed, Table 2. Most of this NPT was related to hole instability encountered while drilling and then running the 9 5/8-in. casing.

TABLE 2. Surface interval drilling and NPT comparison

METHOD SELECTION

With knowledge of the surface-hole difficulties, the operator investigated alternative methods to fulfill the following objectives:

� Ensure surface casing could be set at the planned depth

� Efficiently drill the surface hole while mitigating lost circulation and hole instability

� Minimize hole deviation caused by dipping formation beds

� Provide an effective cementing system that would lead to cement at surface, eliminate remedial work and satisfy the BLM

� Minimize or eliminate NPT.

After a review of available offset well data, including drilling data, mud logs, geological and bit records, and an NPT analysis, the operator chose Casing While Drilling (CWD) combined with a stage-cementing system as the best chance of achieving these goals, based on the following evaluations:

� Getting casing on bottom. CWD enables casing to be drilled to its planned TD, thus minimizing open-hole exposure time.

� Minimizing problems associated with fluid losses while drilling. CWD allows the annulus to be kept nearly full during drilling to minimize problems associated with sloughing shales.

� Minimizing hole deviation. Replacing the mud motor with a CWD BHA and eliminating low WOB would minimize the angle-build tendency.

� Improving cement job quality. A multiple-stage cementing tool in the CWD BHA enables cement to be circulated to surface, the BLM's key cementing requirement.

EQUIPMENT SELECTION

The federal 399-1-5 well was selected to implement the CwD project. The choice of equipment for this job was critical to the project's success. The following were selected:

Casing connection. The operator had previously selected 95/8-in., 36-lb/ft J-55 buttress casing for the surface casing in the drilling program. The operator was concerned about the fatigue resistance of the standard buttress connection, which is subjected to several hundred thousand revolutions during the CWD operation. In addition, buttress connections are known for inconsistent makeup torque values because the makeup torque is dependent on the final location of the field end pin with respect to its alignment in the coupling to the �triangle� stamp. There was also concern that buttress connections would over-makeup during rotation while drilling.

To improve makeup consistency and fatigue capability, a modified buttress design was implemented with a coupling that incorporates internal torque shoulders in the center. In this connection, the pin noses engage torque shoulders, providing a positive makeup stop and enhanced torque resistance. The modified buttress design also provides a triple taper in the coupling to reduce localized radial bearing stresses in mating thread elements, thereby enhancing fatigue resistance. Secondary benefits of the modified buttress design include significantly reduced galling potential during thread makeup and excellent make/break repeatability under field conditions.

For CWD, the operator used casing strings with conventional buttress pin members. The casing couplings used the integral shoulder and triple-taper box. The heavy cross-section at the center reinforces the coupling body, producing smoother hoop stress distribution, higher thread-interface contact pressure and enhanced leak resistance.

Drillbit. As a cutting structure, the operator chose the DrillShoe3 (DS3), essentially a five-bladed PDC) bit that can be converted to a cementing shoe to allow drillout with conventional drillbits. ¹ The bit has 16-mm PDC cutters and tungsten carbide gauge-protection inserts. The gauge section is designed to allow back-reaming capability. The tool performs as a PDC bit until TD is reached, at which time a ball dropped into the string falls to the ball funnel inside the bit, blocking the drilling nozzles from fluid flow. The casing string is then pressured to about 2,000 psi, and the pins are sheared, forcing the tool's inner piston downward. This action displaces the steel blades and PDC cutting structure into the casing-openhole annulus. Simultaneously, cementing ports are exposed, and fluid circulation is reestablished through these ports as the tool's inner sleeve slides down with a latching mechanism engaging at full stroke. The full stroke of the tool is engineered to displace the entire cutting structure into the annulus, which eventually is cemented in place. The center piston exposed is fully drillable with conventional mill tooth and PDC bits, Fig. 2.

Fig. 2. The pipe-handling arm is shown picking up the operation drill tool with integral centralizer.

The cutting structure is designed for formations with Unconfined Compressive Strength (UCS) up to about 15,000 psi and can drill up to 18,000-psi-UCS formations for limited intervals. Based on the operator's offset well lithology and bit records, this design was adequate to drill the required footage for the Piceance basin operation.

Internal casing drive tool. The 95/8-in. casing was hoisted and rotated using an Internal Casing Drive Tool (ICDT), Fig. 3. The 9 5/8-in., 36-lb/ft tool has a tensile rating of 1.38 million lb, a torque rating of 50,000 ft-lb and packoff-cup pressure rating of 2,500 psi. The tool is a high-strength spear that engages the casing with a quarter-turn to the right and releases by pushing down and a quarter-turn to the left. The ICDT has a 6 5/8-in. regular box connection on top and is made up to the rig's top drive. It serves three functions:

1. A casing elevator

2. A fillup tool

3. A casing drive tool.

Fig. 3. Casing was hoisted and rotated using an internal casing drive tool, a high-strength spear with a tensile rating of 1.38 million lb, a torque rating of 50,000 ft-lb and packoff-cup pressure rating of 2,500 psi.

After each joint of casing is raised to a vertical position over the rotary using the rig's pipe-handling boom arm, the ICDT engages the casing joint and then lowers it to the box end of the casing joint already in the slips. About four to five turns of the ICDT-engaged casing are made, and the remainder of the casing makeup is completed with casing power tongs.

Float collar. The operator selected a double-flapper-valve float collar to allow passage of the drillbit's 3-in.-OD blade-conversion ball, Fig. 4. This float collar serves three functions:

1. A mechanical well-control barrier (same function as a drillpipe float)

2. A landing collar for the first-stage top wiper plug

3. A one-way check valve to prevent U-tubing of the first-stage cement slurries.

Fig. 4. A double-flapper-valve float collar was used for cementing the hole.

The basic design is that of a conventional auto-fill float collar with the auto-fill tube removed, allowing the flappers to be run in the closed position. This float collar also houses a 3.875-in.-ID insert baffle plate for landing the first-stage top wiper plug. The float collar is bucked on and thread-locked to the pin end of a joint of 9 5/8-in. casing before shipment to the rig.

Cementing tool. A mechanical two-stage cementing tool was selected, Fig. 5. It requires a mechanical event combined with a pressure event to open. The stage-tool ID had to be large enough to allow the first-stage top wiper plug (4-in. OD nose) and the drillbit's 3-in.-OD conversion ball to pass through. The minimum ID of the stage tool is 7.25 in. Its mechanical strength properties are superior to those of the 9 5/8-in., 36-lb/ft J-55 casing on which it would be run. The tool has 90 durometer, peroxide-cured nitrile O-ring seals, rated for -20 to +275°F, and six 11/8-in.-OD cementing ports.

Fig. 5. The mechanical two-stage cementing tool selected requires a mechanical event combined with a pressure event to open.

From an operational standpoint, the stage tool's designed opening and closing pressures (700�1,000 psi to open and >1,200 psi to close) were within the casing's mechanical strength limits.

The rig. The operator chose a singles rig equipped with split traveling and crown blocks rated to 250 tons and a drawworks rated to 630 hp, Fig. 6. The rig has a pipe-handling boom arm capable of transferring pipe from the pipe racks to a position vertically above the hole, thus minimizing human contact. The boom arm was considered a significant safety feature. The top drive has a torque capacity of 24,000 ft-lb at a maximum of 150 rpm.

Fig. 6. The singles rig uses a pipe-handling boom arm to transfer pipe from the pipe racks to a position vertically above the hole.

Thorough examination of the rig facility by the operator and the contractor established that the ICDT combined with the maximum top-drive height would only allow a 40-ft casing joint. This length would also be the maximum for any pre-assembled BHA.

DRILLING AND CEMENTING

The procedure called for setting a 14-in. conductor at about 120 ft MD and then drilling a 12¾-in. hole to about 1,500 ft MD, using a pendulum mud-motor BHA. This depth was thought to be below hard formations that could damage the drillbit. At that point, the conventional BHA would be pulled and the CWD operations commenced, to drill a 12¼in. hole to about 3,100 ft MD. Casing was to be set and cemented in two stages.

After conductor was set, a 12¾-in. hole was drilled conventionally as planned to 1,540 ft MD. A 12¾-in. insert roller cone bit and freshwater fluid system were used. A wireline survey observed a 3.75° inclination at 1,470 ft. The BHA was then pulled. The 12¾-in. bit was used instead of a conventional 12¼-in. bit to minimize reaming time when tripping in the hole with the 12¼-in. CWD BHA. The 9 5/8 × 12¼-in. DS3 drillbit�made up and thread-locked to the first joint of casing�was picked up using conventional casing side-door elevators. A non-rotating CWD centralizer, straddled by two stop rings, was placed in the middle of the second casing joint with the double-flapper-valve float collar. This centralizer was positioned 86 ft above the drillbit.

The side-door elevators were used to run the first four joints of 9 5/8-in., 36-lb/ft J-55 casing with CWD-enhanced casing connections to establish sufficient axial loading for the ICDT slips to engage the casing string. Six non-rotating casing centralizers were run, one on each side of the stage tool. Using the rig's pipe-handling arm and the ICDT, the 12¼-in. BHA was run in the 12¾-in. hole to 1,057 ft MD, and the casing was washed and reamed through intermittent tight spots to bottom. The mechanical stage tool was positioned in the casing string to be set at 1,404 ft MD. Drilling with casing commenced, and the 9 5/8-in. casing was drilled to 2,068 ft MD without incident.

Before connections were made, each joint was backreamed, and two high-viscosity sweeps were pumped before drilling ahead. At 2,068 ft MD, total circulation was lost. The rig's pumps were lined up on the annulus, and 120 bbl of water was pumped to fill the 9 5/8 × 12¼-in. annulus. Air compressors were put on line, air was pumped with water at approximately 600 standard ft ³/min, and returns were obtained. Drilling continued to 2,473 ft MD, and the air discontinued with nearly full returns obtained and instantaneous ROP of 30�40 ft/hr. The operator observed 8,000�15,000 lb WOB and 6,000�10,000 ft-lb surface torque, with 60�80 rpm.

Drilling with casing continued to the planned TD of 3,075 ft MD without incident. A 30-bbl viscous sweep was pumped and circulated out of the hole, and the drillbit was picked up 3 ft off bottom to provide enough clearance to displace the five blades to the annulus.

The ICDT was released, and the 3-in. phenolic conversion ball (3.45 specific gravity) was dropped. The ICDT was re-engaged into the casing, and the rig's pumps were used to circulate the ball to the drillbit's ball-seat funnel. After pressuring to 2,700 psi, the blades were successfully displaced, as observed on the rig's stand-pipe pressure gauge with a sudden pressure drop. The ICDT was rigged down, and the cement head was installed in preparation for cementing.

The first-stage cement slurry consisted of 310 sacks of a 12.0-ppg Class �G� blend, followed by a tail slurry of 190 sacks of a Class �G� blend mixed at 15.8 ppg. The cement slurries were displaced with 231 bbl of water, and the first-stage top plug bumped with 1,500 psi and float valves holding. The stage-tool opening cone was manually dropped down the casing, and the stage tool opened with 900 psi.

Circulation with water was established through the stage tool at 5.5 bbl/min with the rig pumps. After 4 hr of circulation, the second-stage cement slurries were pumped. The second-stage lead slurry consisted of 215 sacks of a 12.0-ppg Class �G� blend, followed by a tail slurry of 80 sacks of a 15.8-ppg Class �G� blend. About 17 bbl of cement was circulated to surface. The closing plug was dropped, and the stage tool was successfully closed with 1,774 psi at 6.4 bbl/min. A BLM representative was on location to witness the cementing job, and no remedial cementing was required.

CONCLUSIONS

The casing drilling operation combined with multiple-stage cementing technology was superior to previous practices in the area. An average time savings of 2.72 days per well (21%) was achieved. The fastest surface interval drilled and cemented using CWD with stage tool was 5.75 days compared with 7.38 days for the conventional surface holes.

This technology enabled the operator to minimize the time required to set casing at the planned depth, greatly reducing time-related hole stability problems. Another advantage was a more competent cement job. The combined approach reduced surface-hole NPT in the area by an average of 3 days per well (47%). On two wells, NPT was reduced to 0 and 0.35 days.

Fluid loss from the CWD operations was significantly lower than from conventionally drilled surface holes, with documented savings of $40,000 in water-hauling costs for one of the wells drilled with casing.

Conventionally drilled wells had two jobs where casing was set 300 ft and 427 ft short of well depth, whereas each CWD well allowed surface casing to be set at planned depth. Also, all CWD stage-tool cementing jobs achieved cement returns to surface.

CWD also reduced average hole deviation by 44% compared with the previous conventional wells.

All seven CWD drillbits used to date have displaced the PDC cutting blades to the annulus without incident. All of these bits were drilled out using conventional roller-cone drillbits.  

ACKNOWLEDGEMENTS

This article was prepared from IADC/SPE 105457 presented at the IADC/SPE Drilling Conference held in Amsterdam, Feb. 20�22, 2007. The authors thank SandRidge Energy (formerly Riata Energy) for permission to publish this paper. Also, thanks to Gary Thompson of Weatherford for preparing the illustrations.

LITERATURE CITED

¹   McKay, D., Galloway, G. and K. Dalrymple, �New developments in the technology of drilling with casing: Utilizing a displaceable DrillShoe tool,� WOCD-0306-05, presented at the World Oil Casing While Drilling Conference, Houston, March 6, 2003.

THE AUTHORS
	Steve Rosenberg is a senior drilling engineer at Weatherford. He has been with the company for four years and is project manager for the company's drilling-with-casing and drilling-with-liner operations. He holds BS degrees in petroleum engineering from Mississippi State University and in biology from St. Lawrence University. He can be contacted at steve.rosenberg@weatherford.com
	Brent Lirette is the product-line engineering manager of cementing products for Weatherford. He has 22 years' experience in the design and development of cementing products. Mr. Lirette earned a BS degree in engineering science and MBA degrees at Nicholls State University.
	Al Odell is the product-line engineering manager for drilling tools and drilling with casing at Weatherford. He has 20 years' experience in product development. Mr. Odell earned a BS degree in mechanical engineering at LSU and is a registered PE in Texas. He is the inventor and/or co-inventor of 18 drilling-related patents.
	Ryan Robinson is a senior drilling engineer for SandRidge Energy, formerly Riata Energy, which he joined in 2003. He earned BS and MS degrees in petroleum engineering at New Mexico Institute of Mining and Technology.