Achieving first production is the end goal for the entire drilling process. The gap between spud and total depth (TD) is a defining success factor for operations onshore and offshore. As operators continue to push the envelope of viable production targets, technology companies continue to set the pace for how deep and soon a well can be drilled.

As tools become better defined and new parameters are set, the cycle time for most drilling projects continually decreases. And, in many cases, many tools and processes become standard operating procedures once they are proven in the field to be a viable way of reaching production safer, faster, and with fewer costs related to nonproductive time (NPT).

In North America and abroad, several record-setting applications have shown how operators are investing more in advanced technology to save on overall project costs.

Hybrid technology

The benefits of combining multiple qualities into one component or machine can create improved performance without necessarily reinventing the wheel. Although the concept was not new, Baker Hughes recently commercialized its old idea of manufacturing a hybrid drillbit to combine roller cone and PDC technology to produce a hybrid bit with maximum durability and cutting efficiency in tough and challenging applications compared to conventional bit technology.

An operator in Norway contacted the company for assistance with a planned exploration well containing a demanding basalt interval.

The Kymera, a hybrid drill bit using both roller cone and PDC technology, drilled more than twice as fast as premium roller-cone bits in a basalt formation in an Icelandic geothermal application. (Image courtesy of Baker Hughes Inc.)

While basalt drilling is uncommon in conventional wells, Baker Hughes saw the Kymera hybrid drill bit as ideal for this application. To validate the bit's ROP and its durability in igneous rock, the company identified a potential geothermal application for a field test.

Baker Hughes drilled two different sections in the geothermal test, 17½-in. and 123/4-in., for a total of two runs using the hybrid drill bit technology. Historically, the bits used in the offset geothermal offset wells would drill to TD but with reduced ROP. The driller achieved an average ROP of 10.8 m/hr (35.4 ft/hr) in the 173-m (567.6-ft) 17?-in. section to TD of 270 m (885.8 ft), which was almost three times faster than runs in offset wells.

The company had proven that PDC bits were a viable option in an Icelandic basalt application in a previous 123/4-in. run. However, controlling downhole vibration was a challenge that resulted in severe cutter breakage and overall reduced the cost saving potential compared to conventional roller cone technology. The team used the Kymera hybrid bit on a steerable motor and was able to control ROP by reducing weight on bit (WOB). The team drilled the 12?-in. section 487 m (1,597 ft) to TD with an average ROP of 21.3 m/hr (69.9 ft/hr). With the resulting reduction in vibration, both Kymera bits experienced minimal wear, proving the value of the PDC and roller cone concept in basalt-like formations.

The 123/4-in. interval achieved its directional objectives, including build inclination from 0 degrees to 35 degrees. Drilling parameters were held back for both sections to manage well integrity, yet the Kymera hybrid bit drilled more than twice as fast as premium roller-cone bits compared to offsets.

Shale development, proving ground

The vast amount of growth experienced in North American shale plays has provided ample room for a number of record-setting achievements. Extended-reach drilling, multilateral well bores, and building curve from vertical to horizontal are not as challenging as they once were. However, continuous improvement is required to maintain low costs while drilling. Reducing cycle times brings on the completion stage sooner, which can account for around 50% of a well cost in most unconventional shale plays.

Bits are big news in the unconventional market. Ulterra recently set a footage record for Roger Mills County in Western Oklahoma with its new 123/4-in. U616M six-blade matrix PDC bit using 16-mm cutters. The bit drilled 2,153 m (7,065 ft) from surface casing down to a depth of 2,474 m (8,115 ft) for an estimated cost savings of US $44,500 versus the closest offset. This savings increased to $88,500 when compared to the average of five offset wells. The company's latest generation U616M is the result of extensive bit design and cutter testing in the Granite Wash play and has continued to set records in the area.

In January, the company's U616M 8?-in. bit drilled from surface casing to TD at a record pace of 28 m/hr (93 ft/hr) in the Eagle Ford. The vertical, curve, and lateral all were drilled with the same bottomhole assembly, which reached TD without a trip out of the well. In all, it took only 107 hours to drill 3,035 m (9,953 ft), representing a time savings of 37.5 hours over the fastest offset of 144.5 hours. Cost savings were estimated at $77,566 versus the direct offset and $133,024 compared to the average of five competitor offsets.

The bit was designed to increase slide efficiency and reduce unnecessarily high slide percentages. It maintains sharpness throughout all three drilling intervals, thereby minimizing torque fluctuations and resulting in better toolface control, minimized bit-induced stick-slip, and reduced impact damage.

In the Bakken, Halliburton raised the bar for lateral drilling. On a Williams County, North Dakota well, the company's 6-in. FX64 drilled the entire 3,055 m (10,019 ft) of the lateral section on a high-speed motor to a TD of 6,316 m (20,709 ft) measured depth (MD) in only 95 hours. This proved to be the fastest lateral among the offsets with an average ROP of 32.1 m/hr (105.4 ft/hr). This bit was the first to drill the entire lateral section, and its performance provided the lowest cost-per-foot among similar offset runs.

Longest running deepwater MPD

Drilling technology also is advancing offshore. In the Makassar Straits of Indonesia, Weatherford in conjunction with Transocean's GSF Explorer has mounted what is now the world's longest running deepwater managed pressure drilling (MPD) project.

Installation of the first MPD system integrated into a marine riser below sea level provided a flexible solution that enhanced drilling capabilities across multiple sections throughout the drilling campaign. The MPD system improved safety and efficiency through early kick detection and control, riser gas handling, and two variants of MPD: constant bottomhole pressure and pressurized mud cap drilling. Constant bottomhole pressure is used in narrow margin drilling scenarios, and pressurized mud cap drilling is used in total lost circulation conditions.

The company's deepwater MPD system is installed above the intermediate flex joint in the riser and below a standard slip joint. As a result of this configuration, the riser can be used in a conventional manner with full-bore access to the well. The entire system is installed through the rotary table when the riser and BOP are deployed.

Managed pressure drilling is enabling drilling operations in otherwise undrillable conditions while improving safety and efficiency. (Images courtesy of Weatherford International)

The 12-m (40-ft) MPD system provides riser gas handling and early kick detection/control in drilling sections when the BOP is connected to the well. The riser MPD assembly used on the GSF Explorer comprises three main components: the flow spool, operational annular preventer, and rotating control device (RCD). The flow spool provides the connection for the flowlines from the top of the riser to the MPD manifold. Two 6-in. flowlines are connected at the moonpool to allow returns to flow through the MPD manifold to the shale shakers and mud pits. A 21?-in. subsea annular BOP is installed above the flow spool. The annular BOP allows riser gas handling. If a kick is detected in the riser, the annulus can be closed to provide controlled handling of a riser influx through the flow spool and back to the surface. The Weatherford Model 7875 Below Tension Ring Seashield RCD is installed on top of the annular BOP in the MPD riser joint. This RCD enables pressure control for annulus gas containment and drilling operations. Its principle use is to provide an annular seal around the drillpipe during drilling and tripping operations. The inside profile of the RCD includes a hydraulic latch assembly to receive, retain, and release the bearing seal assembly. With the bearing seal assembly removed, the 2,000-psi RCD system is capable of handling the full-size 18?-in. BOP tools.

This RCD currently is the only one in the world that can be installed in a deepwater marine riser and support the riser tension requirements while conforming to API 16 RCD drillthrough specifications. The ability to put the RCD in tension with the riser allows it to become a standard component of the riser and enables installation below the conventional slip joint.

Weatherford commissioned its MPD package in March 2010. As the project is nearing its two-year mark, the company is currently drilling the fifth well for the consortium.

"Deepwater MPD using this configuration will soon be deployed in Brazil as well as the West Coast of Africa," said David Pavel, director business development, Drilling Optimization Services, Weatherford. "The diversity of E&P operators using and requesting this technology in deep water is evidence that there is a need for this key enabler."

At its onset, only one operator in the consortium agreed to use Weatherford's system. "The others were in a 'wait and see' mode," Pavel said. "Upon initial success, the majority of the consortium contracted the technology and the project has continued for two years with additional wells to come."

Weatherford's project has confirmed the viability of key technologies that comprise this system. "Operators in the consortium are evaluating other deepwater basins in which to deploy this technology," Pavel said.

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