A simultaneous application of rotary steerable and reaming-while-drilling (RWD) technology on an Ursa horizontal well eliminated a separate underreamer run and increased net rate of penetration (ROP) by 85% compared to the best offset drilled with bent-housing mud motors and bicenter PDC bits.

A key factor in improving the economics of deepwater developments is accelerating field production with high-rate wells. The development wells at the Ursa tension-leg platform (TLP) use 85/8-in. production casing with 5½-in. tubing to achieve the highest daily production rates in the Gulf of Mexico. The desire for large-diameter production casing and the small margin between mud weight and fracture gradient at Ursa combine to require drilling a larger-sized hole than the drift diameter of the previous casing string for all of the casing intervals. The last 1,000-ft (305-m) true vertical depth on the first two development wells - A-8 and A-7 - were drilled and then underreamed prior to running casing. For the third well, A-6, a rotary closed-loop system (RCLS), in combination with an RWD sub, was selected to eliminate the separate underreamer run (Figure 1).
Well design and objectives
The A-6 well was designed as a horizontal producer in the Yellow sand, the same reservoir targeted by the A-8 and A-7 wells (Figure 2). A pilot hole was to be drilled to confirm the depth of the Yellow sand reservoir and evaluate two secondary reservoirs below. The pilot hole then would be plugged back to the 11¾-in. shoe and sidetracked. The wellbore profile for the sidetrack required an 86° turn in azimuth and also building angle from 29° to 88°. The horizontal displacement along the wellbore at the 85/8-in. liner point would be about 6,500 ft (1,983 m). The sidetrack would intersect the top of the Yellow sand and also align the well for the proposed 3,000-ft (915-m) lateral section. The shoe of the 85/8-in. liner was to be set in the top of the Yellow sand and as near to bottom as practical. This would prevent exposing potentially unstable shales to the planned water-based horizontal drilling fluid.
BHA design
Previous attempts at simultaneous drilling with a rotary steerable system and opening the hole to a diameter larger than the drift diameter of the previous casing string had been unsuccessful. Baker Hughes Inteq and Hughes Christensen integrated the RCLS and RWD technology to design a bottomhole assembly (BHA) for optimum performance. Key concerns were stabilization of the RWD sub and the logging tool area and steering capability of the RCLS tool. Various scenarios were evaluated using Nonlinear Analysis of Drillstring Dynamics software to model the bending moments, dynamic and static side forces, wall contact points and lateral deflection points. The selected BHA showed excellent performance without any static or dynamic problems (Figure 3).
PDC bit and RWD sub design
The proposed bit, ATX536HA (IADC M323), was specifically designed for use with the RCLS. Application-specific PDC cutters and a new setting pattern in the gauge area, combining tungsten carbide inserts with natural and impregnated diamond technology, provided the optimum balance between abrasion and erosion resistance, bit stability, bit life and borehole quality. This anti-whirl bit is designed to suppress torsional and lateral vibrations that generally lead to poor drilling performance.
The RWD system consists of the bit and RWD sub. The RWD tool uses a pilot stabilization pad to balance the cutter forces generated from the reamer wing.
A-6 pilot hole
After discussions with the operator, a 6¾-in. RCLS system was selected with a 9½-in. pilot bit and 11.4-in. RWD sub to meet the requirement that the pilot hole be large enough for the 85/8-in. casing to be run to bottom. The 7,287-ft (2,223-m) TD was drilled during one trip in 82½ hours at an average ROP, including connections, of 88.3 ft/hr and average instantaneous ROP of 164 ft/hr. This was an increase of 95% and 36%, respectively, over the previous bests from the A-7 well. The cost per foot also decreased 50% compared to the best offset. No appreciable wear was seen on the bit or RWD sub, and both were judged able to be rerun on the planned sidetrack. However, both RWD sub nozzles were plugged when pulled. And high erosion in the tool's measurement-while-drilling (MWD) section was caused by overpumping due to plugged nozzles in the RWD sub.
The diameter of the hole in the shales was slightly greater than the gauge hole diameter of 11.4 in., while the sands showed undergauge values between 105/8 in. and 11.4 in. The wireline caliper data showed the RWD sub had successfully opened the hole in the shales, although there was no obvious reason why the sands were undergauge. No excessive vibration, torque or rotary steerable sleeve rotation were observed while drilling the sands. Subsequent laboratory tests suggested the undergauge hole was primarily due to filter-cake buildup and secondarily due to barite sag.
Drilling the A-6 S/T1 build to horizontal
The sidetrack to horizontal was drilled to 21,118 ft (6,441 m) MD and 88° inclination in four runs. The first run drilled 3,252 ft (992 m) in 38 hours at 85.6 ft/hr. A nozzle in the RWD sub was partially plugged with cement when the BHA was pulled. The second run drilled 1,329ft (405 m) in 14 hours at 94.9 ft/hr. This tool also had a plugged nozzle in the bit, and the RCLS sub filled with cement when pulled. When the third tool was run to bottom, it would not turn on and was pulled. The turbine area above the MWD tool was plugged with cement, which prevented the turbine from rotating and powering the tool.
At this point, the anti-whirl drill bit was thought to be contributing to the excessive rotation of the RCLS "nonrotating" sleeve, hindering the system's ability to steer. The bit was changed to a general-purpose, force-balanced, rotary steerable PDC bit, TX 445 (IADC M433). The fourth BHA had no problems steering once on bottom and drilled 2,129 ft (649 m) to total depth of the interval in 34 hours at 63.6 ft/hour.
The pieces of cement that plugged the nozzles and MWD turbine area were thought to be coming from a cement sheath that had formed inside the 5½-in. drill pipe. The sheath most likely formed during cementing operations earlier in the well without the use of drill pipe wiper plugs. Pieces of cement continued to break off and collect above the MWD tool or plug nozzles while drilling the pilot hole and first sidetrack.
The well had to be sidetracked since an 85/8-in. liner stuck about 1,000 ft (305 m) off bottom. A cement sidetrack plug was set from the top of the liner to above the 11¾-in. shoe. Drill pipe wiper balls were pumped behind the cement to prevent a cement sheath from forming inside the drill pipe.
Drilling the A-6 S/T2 build to horizontal
A bicenter bit driven by a bent housing mud motor was used to drill out the sidetrack cement plug. This change enabled drilling ahead after drilling out, making 963 ft (294 m) of hole to 15,387 ft (4,693 m) at 30.1 ft/hr. The 9½-in. by 11.4-in. RCLS/MWD BHA then was used to drill to 20,820 ft (6,350 m) MD, casing point at 88° inclination in one trip. The assembly drilled 5,433 ft (1,657 m) in 65½ hours at 82.9 ft/hr. No plugged nozzles or sleeve rotation problems occurred on this sidetrack. Based on real time and memory logs, this run was judged the best from the dynamic loading point of view. An optimized blend of experiences from previous runs, bit selection, RWD and bit compatibility, drilling practices and parameters contributed to the reduced dynamic loading.
The 9½-in. by 11.4-in. RCLS/RWD system successfully drilled and opened about 20,000 ft (6,100 m) of hole at inclinations from 30° to 88°. The directional targets of the 3-D profile well were intersected at the desired inclination and azimuth. This drilling experience aids in making the following assessments:
• RCLS/RWD usage decreased interval cost per foot 50%, increased net ROP including connections 85%, and increased instantaneous on-bottom ROP 30%, compared to the best offset drilled with bent-housing mud motors and bicenter PDC bits;
• no MWD detection problems occurred due to the use of RWD sub and nozzles above the MWD tool;
• wireline caliper logs showed that combined RCLS/RWD system opened the hole to the planned diameter;
• the RCLS tool is capable of drilling greater than 7,000 ft (2,135 m) in a single run and achieving build rates of 7°/100ft;
• combined use of RCLS and RWD tools does not cause additional vibration that affects tool reliability; and
• drill pipe wiper balls or plugs should be pumped behind all cement jobs to prevent a cement sheath from forming inside the drill pipe and affecting the performance of the RCLS/RWD sub.
Acknowledgments
This article is based on paper SPE/IADC 67760, "First Simultaneous Application of Rotary Steerable/Ream-While-Drill on Ursa Horizontal Well," originally presented at the SPE/IADC Drilling Conference held in Amsterdam, the Netherlands, Feb. 27 - March 1, 2001. The authors thank Ursa partners (Shell, BP Amoco, Conoco, ExxonMobil) for permission to publish the paper.