Downhole systems & tools revolutionize incrementally

Today's drilling market is driven by an expansive array of technological options. While certain systems like rotary steerables can be attributed to a revolutionary beginning, the majority of advanced technology has risen from small, incremental improvements on existing technology.

While faster than geologic time, the downhole tool market advances slower than is often attributed. Small changes such as components made more robust, changes in chemical makeup, and the sometimes hybrid confluence of competing technologies impact the way operators drill and complete their wells. Field trials, breakage, and coordinated R&D between operators and service providers each share a place in the field of innovation.

Conventional plays and offshore operations are each represented as beneficiaries of technological innovation. However, the shale revolution within the last few years best represents technological growth as an incremental process rather than one expanded through revolution.

Speaking at Hart Energy's Developing Unconventional Gas (DUG) conference in Fort Worth, Texas, April 24, James Wicklund, consultant at Carlson Capital LLC, said, "There are two return drivers for technology advancement: to lower costs and improve recovery."

A new paradigm

The struggle between E&P and service companies is a constant. "The E&P company provides the geoscience and the operations, and of course they own the resources," Wicklund said. "With oilfield service companies providing the technology and equipment, it is always an issue of who is generating returns."

The circular refinement process for new technology drives the need and requirement to improve returns on investment. "Whether we get giant relative improvements or absolute improvements from here is almost a moot point," Wicklund said.

Long-term, consistent returns paid in by diligent cost control and efficiencies bring attention to the current shale boom. "It changed the paradigm," Wicklund said. When conventional E&P companies traditionally relied on wildcatting, it was a gamble. Shale plays are now produced and developed as manufacturing exercises. This industrialization has provided an environment featuring repetitive operations with more predicatable results.

"These projects are predictable, and they have high capital costs, so you have a whole block of people looking to put money into these plays and then get their money back," Wicklund said. "Returns actually can be calculated and improved on. Investors can judge which company is generating the best returns."

Opening the curtain on technology

Horizontal drilling, PDC bits, pressure pumping, and proppants combined have drastically optimized the

factory approach to developing shale plays around the world. The important point here is that the shale revolution is considered to have begun in 2007. Baker Hughes started counting horizontal rigs in 1989. Pressure pumping has been around for almost 60 years. "All of these technologies have been around for a while," Wicklund said. There was no instantaneous revolution in technology. More importantly, the combination of these technologies and their continual refinement contributed to the shale barrier finally being broken. "The whole point of this was to improve returns," Wicklund said.

Once again, the argument becomes whether technology and innovation drive returns or whether returns drive technology and innovation.

Wicklund cited Schlumberger's introduction of its HiWAY frac system. "This technology improved production in the Haynesville and the Eagle Ford significantly," he said. "With all of the equipment seen during the HiWAY frac in the Eagle Ford, the only difference was the chemistry and the blending technology – nothing else." Rather than seeing brand new, dramatic technologies coming into the market, the shale plays have primarily been enhanced by continued refinements.

Prime objectives include the maximized recovery of hydrocarbons in place. "The prime objective for the oilfield service industry and its highest returns is to provide the technology to do this," Wicklund said. "The oilfield industry will continue to refine the technology; the E&P companies will continue to manage the operations. They will reward the companies that make that possible," he added.

Bottom line

Where the bottom line is concerned, advanced tools and systems are refined through trial and error. Both operators and service companies have a vested interest in identifying weak spots in the technological landscape and working together to engineer a solution.

Robert Banks, executive vice president and chief operating officer, Swift Energy Co., also said at DUG Fort Worth, "This is what drives the bottom line: continuous improvement, embracing technology, and successfully managing all parts of the business – this will help you deliver economic results for your company and its shareholders."

New RSS system drills faster
Unconventional operations benefit from smooth, fast runs.

Operators can drastically reduce cycle times by landing a well sooner. Eliminating slides and delivering consistent steering and high ROP, even in high stick-slip environments, are prime objectives in directional drilling applications. Smooth curves and straight tangents with better hole qualities can result in more effective fracturing operations and higher production rates. Baker Hughes' AutoTrak Curve rotary steerable system (RSS) has been achieving these goals in one run. It also provides continuous string rotation, which maximizes overall efficiency by reducing torque and drag to provide a high-quality well bore, better hole cleaning, and less cleanup time.

The technology is proving better drilling economics, exact wellbore placement, and faster drilling in unconventional plays. It reduces the time on the well with reliable performance, less risk, and an improved bottom line.

The unit is designed as an all-in-one solution that features real-time azimuthal gamma ray for precise steering with accurate near-bit measurements. Expandable pads on a slow-rotating sleeve maintain precise trajectory and proper circulation for carrying cuttings out of the hole. Surface control of the directional capability maintains drilling plans and allows on-the-fly target changes when needed. The company's PDC bit technology allows for better weight-on-bit, improved hydraulic efficiency, and longer life in tough formations.

The Autotrak Curve RSS system is a fully equipped, ready-to-use directional drilling package that provides full surface control with full rotation for smoother well bores, often in one run. (Image courtesy of Baker Hughes)

Utica success

A client operating in the Utica formation of the Appalachian basin contacted Baker Hughes to drill an 8°/30.5-m (8°/100-ft) dogleg severity curve section. The client's drilling plan included a hard line avoidance at total depth, and the client wanted to significantly improve ROP.

The client chose to drill the section using the Baker Hughes AutoTrak Curve rotary steerable system along with an 8?-in. Baker Hughes drill bit. The system allowed the client to significantly reduce total days of drilling exposure by completing a one-run curve and lateral on a three-dimensional profile with a 658-m (2,159-ft) curve and 2,274-m (7,462-ft) lateral.

The company's drilling system eliminated two rig days compared to average offset wells.

New running tool ensures successful landing of completion string
Peace of mind is a good thing when investing in a costly completion application.

Proper placement of the completion string can be challenging for some reservoirs. Not getting it right the first time can lead to sunk cost and extensive nonproductive time (NPT). Managing this risk has become more accessible as running tools improve.

The Shalerunner provides the ability to wash and ream and to reestablish the borehole during completion string running. This allows for the completion to be landed without a need for rotation and without the risk of prematurely setting the liner hanger. (Image courtesy of Deep Casing Tools)

One example, the Deep Casing Tools (DCT) Shalerunner, was designed as a cost-effective method for running completion strings in shale wells. The tool adds a balanced high-speed rotating reamer shoe to the completion, allowing the operator to essentially drill the completion in. The tool can reduce wiper trips since the completion itself has the ability to wash, ream, and reestablish the borehole.This allows for the completion to be landed without a need for rotation and without any risk of prematurely setting the liner hanger.

According to DCT CEO Lance Davis, "This technology provides a simple plug-and-play solution in risk management."

The tool is specifically designed to integrate with all completions to achieve placement. It can eliminate unnecessary cleanout trips, complement the best practice of proper circulation, and provide an added insurance to achieve success. The intrinsic value of the technology increases with cost of the completion and the risk of wellbore instability. It is suited for applications where the imperative is to land the completion in the right place.

Bakken landing

The Shalerunner was used to ensure landing the 4½-in. open-hole completion with more than 25 hydraulic openhole packers and frac sleeves. The well trajectories were similar – 3,048 m (10,000 ft) total vertical depth (TVD) and 6,096 m (20,000 ft) measured depth (MD) with 10,000 feet open hole – with the casing shoe in the horizontal section. Whereas offset wells had required wiper trips, the operator had moved to eliminate the wiper trip, lubricate the borehole, and slide in the completion.The insurance for this plan was provided by the Shalerunner.This client is now moving to increase the step-out to 3,962 m (13,000 ft).

Insurance in Niobrara

The technology was applied to land a 4½-in. liner in 6-in. open hole where the operator had predicted running problems based on the drilling record.The well trajectory was 3,048 m TVD and 4,572 m (15,000 ft) MD with 1,524 m (5,000 ft) open hole, but here the casing shoe was in the vertical section. The liner was conventional with cementing floats above the turbine.The liner hung up in two sections and could not progress through the

open hole; circulation started rotating the downhole reamer shoe, and the blocked passages were both reamed through until the liner was able to pass.

These initial runs allow future wells to be planned with more complex trajectories, longer step-outs, and less wiper trips."Clearly the technology provided benefit, and we are excited about running it again," said Vic Estes, drilling engineering manager, Anadarko.

Field-tested

DCT's Shalerunner has proven a successful risk management device. As operators step out further with more complex completion programs, ensuring a successful landing becomes a necessity. Avoiding NPT and decreasing the overall cycle time is helping to achieve more production with lower overall investments.

New tool displays full view of borehole
Avoiding trouble spots when placing a horizontal well is made simpler through a new LWD service.

MicroScope images showed approximately 349 open fractures and 867 healed natural fractures that strike northwest to southeast and dip steeply to the northeast and southwest. The open fractures were responsible for significant mud losses during drilling. (Image courtesy of Schlumberger)

Horizontal wells require optimal placement. Identifying problems such as fractures and faults also can assist in designing completions application. A new resistivity and imaging-while-drilling service is now providing high-resolution electrical imaging and microresistivity measurements around the full circumference of the borehole in conductive mud environments. Schlumberger's MicroScope LWD tool also provides enhanced formation evaluation, including thin-bed identification and invasion profile analysis.

The service uses a 4 3/4-in. tool in 5 7/8- in. to 6½-in. hole sizes that measures azimuthally focused laterolog resistivity at multiple depths of investigation. Azimuthal gamma ray (GR) and mud resistivity are also measured. Formation resistivity measurements, high-resolution borehole images, and azimuthal GR data are transmitted uphole in real time using a high-speed telemetry platform that employs advanced compression algorithms to maximize data rates. The high resolution resistivity and imaging-while-drilling service is suitable for use in diverse and challenging environments, including unconventional shale plays, carbonates, and clastic reservoirs.

An operator in Wyoming planned to develop the Niobrara formation in the Denver-Julesburg basin by combining horizontal drilling with multistage hydraulic fracturing.This formation consists of up to four laterally continuous chalk benches with intervening marls. Both permeability and porosity in the Niobrara chalk are relatively low, and production is expected to be enhanced by natural fractures.

From historical drilling data in the area, it was known that a 10-m (33-ft) bench layer was the most attractive interval. This was reconfirmed and refined by openhole logs run in a pilot hole, where the operator identified a 3-m (10-ft) window as the final lateral zone target. Keeping the well bore within the highly fractured layer identified in the pilot hole would require accurate real-time information to guide steering decisions. The operator achieved the well placement objective needed to optimize recovery by using the MicroScope service to provide real-time electrical borehole images, azimuthal GR measurements, and multidepth measurement of formation resistivity.

The well was drilled using the PowerDrive RSS, engineered for accurate directional control, high ROP, wellbore smoothness, and low tortuosity, thus simplifying the installation of completions equipment. Analysis of the LWD information in real time allowed proactive well placement decisions to be made by comparing the apparent dip of the formation to the borehole trajectory.The service enabled the operator to keep the 914-m (3,000-ft) lateral within the 10-ft target of best quality pay within the desired chalk bench. In addition, post-drill analysis of the high-resolution MicroScope images facilitated fracture identification, fault estimation, and structural analysis to optimize stage designs for hydraulic fracturing. The packers were staged to complete similar zones together and away from large open fractures. Sleeve ports were positioned close to open natural fracture swarms.

RFID enhances casing running
Multiple activation capability can improve hole enlargement operations.

Hole enlargement operations are common for Alaska's North Slope. Achieving successful results requires an operator to reach the planned total depth (TD) in one run without restrictions or delay.

The RipTide RFID reamer has the ability to activate and deactivate on demand multiple times. RFID technology allows the reamer to electronically lock and unlock (activate and deactivate) down hole keeping the drilling BHA down hole and providing unparrelled flexibility. (Image courtesy of Weatherford International Ltd.)

When drilling long tangent sections, proper hole cleaning is very important. Having the ability to activate and deactivate the under-reamer provides more flexibility for pumping and rotating at high rates to sweep the hole clean, especially when short-tripping to the shoe.

One major benefit is the ability to surface-test the underreamer. Most other major bottomhole assembly (BHA) components are surface-tested prior to tripping in the hole. Because conventional under-reamers are mechanically "pinned" closed, surface testing is not an option. The RipTide RFID reamer can open and close at surface, confirming that the system is working properly and reducing the risk of malfunction once at drilling depth.

An operator set out to successfully drill and enlarge a 10 5/8 in. borehole to a diameter of 11? in. to provide additional annular space to ensure the 9 5/8-in. liner could reach TD without restriction.

Weatherford's RipTide RFID 10625 series was deployed with rotary steerable system (RSS) BHA. The tool successfully enlarged the intermediate section from 984 m (3,228 ft) to 3,325 m (10,910 ft). This included a 2,341-m (7,682-ft) section of shale with claystone and sandstone stringers. Keeping the hole clean is the major challenge in these formations. The ability to deactivate the reamer and pump sweeps or pump and rotate in cased hole is required.

The operation required multiple activations including surface test, below the 11?-in. shoe, at TD, and a second surface test.The operator successfully ran the 9 5/8-in. casing to TD.

The client was able to reach TD in the 2,341-m (7,682-ft) section, deactivate the RipTide RFID reamer, and circulate the hole clean. If additional reaming was required, the reamer could have been activated again, saving a trip.

The RipTide RFID reamer has the ability to activate and deactivate on demand multiple times. RFID technology allows the reamer to electronically lock and unlock (activate and deactivate) down hole, keeping the drilling BHA down hole and providing unparrelled flexibility. Other benefits include a fullbore inside diameter (ID) (all other underreamers require a ball to activate, therefore creating a restriction and pressure drop in the ID).