Rotary steerable tools have vastly improved drilling performance and hole quality in directional, extended-reach and designer profile wells.

Recent advances in geosteering have made it possible to drill and complete a smooth horizontal section exactly where desired. In just a few short years, rotary steerable tools have progressed from high-tech novelties to essential elements in the horizontal drilling toolbox. The reason for this transformation is that they provide "value for (the) money," said Craig MacGregor, drilling superintendent at Amerada Hess.
"Steerability while drilling in rotary mode represents, in my opinion, one of the biggest steps forward for directional drilling technology," said Laurent Parra, head of drilling engineering at Total. "This type of tool will allow us to access new reserves with much lower drilling costs. We are now systematically assessing the use of this device when planning all our deviated wells."
These devices steer the drill bit in any desired direction while the drillstring rotates, increasing rate of penetration (ROP) while reducing torque, drag, casing wear and wellbore tortuosity. Tortuosity not only contributes to excessive torque and drag, it also can lead to problems while running casing, liners and completion equipment. In some cases, excessive tortuosity or doglegs in horizontal wells can even impair productivity.
Before rotary steerable tools were invented, well direction was usually adjusted by sliding, which contributed to problems such as stick-slip, bit whirl and differential sticking. Because the new systems rotate rather than slide, these problems are minimized.
Given these benefits, all the major service companies - and several smaller ones - have developed their own rotary steerable tools and accompanying services.
Directional control
The AutoTrak Rotary Closed Loop System (RCLS) is an integrated drilling and measurement-while-drilling (MWD) system that provides precise directional control. It includes multiple propagation resistivity, dual azimuthal gamma-ray, directional and near-bit inclination measurements. The downhole guidance system automatically keeps the bit on the programmed course, and well trajectory changes are communicated to the tool from surface using mud-pulse telemetry. This process, also called downlinking, assures accurate well positioning while optimizing overall drilling performance.
A new application for the AutoTrak was tested at Shell's Ursa tension-leg platform in the Gulf of Mexico.1 Large-diameter wells at Ursa have achieved the highest daily production rates in the Gulf of Mexico (50,150 boe/d). Bicenter bits were used to enlarge the wellbore while drilling all but the last 1,000-ft (305-m) section, which was underreamed in the first two wells prior to running casing. The directional plan for the third Ursa well included an 86° turn in azimuth, building hole angle to 90° by 18,300 ft (5,582 m) TVD. A 91/2-in. bit was used below a 63/4-in. AutoTrak RCLS in combination with an 11.4-in. ream-while-drilling sub, eliminating the separate underreamer run for the third well. ROP of the third well was 30% faster than the first well and 85% faster than the second well, both of which had been drilled with steerable mud motors and bicenter bits.
Baker Hughes Inteq has combined the AutoTrak with 3-D visualization and logging-while-drilling (LWD) sensors into its integrated Reservoir Navigation Service, focusing on maximizing the value recovered from geosteered wells. "Standard geosteering techniques based on layer-cake resistivity response modeling have proved to be inadequate for the complex geology of the North Sea," said James Coghill, technical support engineer with Baker Hughes Inteq in Aberdeen, Scotland.2
Typically, the geoscientists select drilling targets based on 3-D visualization, then the drilling team attempts to construct a well plan to tap them, taking into account such engineering limitations such as torque and drag, dogleg severity (DLS), practical limitations on proposed drilling tools and completion requirements. This, in effect, is a reality check on the geoscientists' dreams, and sometimes several iterations are required until a practical plan is negotiated. This process is streamlined by integrating the well planning process with the 3-D earth model.
Using the integrated Reservoir Navigation Service, four horizontal wells were successfully placed in a thin - 3 ft to 10 ft (1 m to 3 m) - zone using effective porosity as the geosteering parameter. "Integration of the earth model into the well planning and wellsite geosteering process significantly reduced the time and cost involved," Coghill said.
Perfectly horizontal sections
Landing a horizontal section in a thin layer of oil between a rising water contact and an expanding gas cap can be challenging. Because reservoirs are heterogeneous, it is important to minimize drawdown along the entire horizontal section to prevent water or gas coning. To minimize the amount of produced water that has to be treated and disposed or produced gas that must be flared, controlling the pressure differential between the heel and toe of the well is critical. This requires a well that is truly horizontal, as vertical deviations can cause pressure loss along the horizontal section, water holdup in sumps and gas slugging at small uphill inclinations.3
Drilling with conventional motors that steer by alternately rotating and sliding the bottomhole assembly (BHA) may cause a tortuous well path with significant vertical deviations. But with closed-loop controlled rotary steerable systems, these deviations are reduced from several meters to only fractions of a meter. The AutoTrak system has two-way communication with confirmation of receipt of the downlink command. Some competitive systems drill crooked holes because they lack two-way communication or have no real-time, near-bit (within 3 ft or 0.9 m) sensors. Such systems have to stop drilling to send the downlink commands, and spend up to 20 minutes off bottom while circulating for downlink transmission. After drilling is resumed, it can take up to 66 ft (20 m) for the MWD tool to reach the depth where the downlink was performed to see if the tool actually received the signal and reacted properly.
And operators are happy with the cost savings. One well west of the Shetland Islands was drilled 28 days ahead of schedule, saving the operator US $8 million.
John Bartges, drilling superintendent for Chevron's North Sea Alba field, said using rotary steerable equipment to drill the
12 1/4-in. horizontal section of the A29 well saved his company a lot of time and money. "AutoTrak saved us 4 days on this hole section, realizing a savings of around £400,000 ($578,000) on our operating costs. Subsequent casing and cementing operations indicated that AutoTrak also delivered a higher quality wellbore than previously seen on Alba."
Peter Sharpe, head of well engineering at Brunei Shell Petroleum, used AutoTrak to kill two birds with one stone while drilling the Iron Duke well ID19. "AutoTrak has allowed us to combine this well with an appraisal well, reducing exploration costs." This represents about $3 million in cost savings for a conventional appraisal well.
The magic number for this tool seems to be 75. On average, the AutoTrak RCLS is drilling ahead for 75% of the total circulation time, according to company literature. Baker Hughes Inteq is continuously improving AutoTrak RCLS reliability; about 75% of AutoTrak jobs have reached total depth or surpassed 75 circulating hours without a downhole tool failure.
The Phoenix rises
Phoenix Technology Services calls its rotary steerable tool the Well Director. This system incorporates drilling navigation capabilities and makes adjustments as necessary without operator intervention. The patented closed-loop system can be reprogrammed from the surface whenever new objectives are required. The tool consists of a rotating drive shaft and a nonrotating sleeve, which contains the downhole computer, the electronic sensor module and the hydraulic steering unit with control valves and piston-driven steering ribs. The Well Director is equipped with a positive-pulse mud transmitter to continuously send directional borehole parameters and the tool's functional data to the surface monitor. Phoenix has 61/2-in. and 91/2-in. tool sizes to drill directional or horizontal wells, and plans are on the drawing board for more.
"We hope to save operators 20% of the directional/horizontal drilling time," said Reid Hansen, vice president of sales and marketing. Studies have found that traditional steerable motor assemblies are in sliding mode at least 35% of the time, resulting in a 50% slower ROP.4
The Well Director also can drill extended-reach and horizontal wells more effectively than steerable motors because the continual rotation of the drillstring eliminates transition ledges that allow cuttings buildup to occur, Hansen said. Conventional steerable motors find it increasingly difficult to hold a tool face, partly due to the large amount of drag in the drillstring as it lies on the bottom of the wellbore in the horizontal section.
Because there are no steerable motor or MWD components to the Well Director, it is possible to put the directional sensors only 3 ft (1 m) behind the bit, compared to the 50 ft (15 m) for conventional mud motors. "It eliminates the need for personnel on the surface to guess or forecast where the bit is," Hansen said. "We know where it is within 1 m, and there's not much change in 3 ft."
An onboard generator, driven by pipe rotation, supplies the required electrical power. The downhole computer continually analyzes the navigation data in the closed-loop system, comparing it to preprogrammed values. If a correction is needed, a hydraulic control process is initiated automatically. Downhole parameters can be changed from the surface by the directional driller.
2-D rotary steering
As far back as 1986, long before rotary steerable systems became fashionable, Andergauge was doing 2-D rotary steering with adjustable stabilizers in conventional rotary assemblies. Operators could control wellbore inclination over tangent and drop-off sections without the need to trip for BHA modifications. In response to changes in formation conditions, the directional driller uses a simple setting procedure to adjust the BHA downhole, thereby controlling inclination and enabling him to drill to total depth in a single run. And fewer trips mean big savings, especially offshore.
In 1991 adjustable stabilizers in a near-bit rotary configuration were applied to horizontal drilling, providing rapid responses that enabled precise inclination control within tight true-vertical-depth target corridors. Research conducted by independent drilling personnel has consistently shown that in tangent sections, more than 90% of slide drilling operations are for inclination control and not azimuth, making 2-D rotary steering with adjustable stabilizers a cost-effective option. In the few cases where azimuth corrections are anticipated, an adjustable stabilizer can be placed above the motor to eliminate sliding for inclination control and maximize ROP. As a rule of thumb, if there is sufficient weight to drill ahead, then there is sufficient weight to cycle an adjustable stabilizer.
Nearly 500 horizontal sections have been drilled using the Andergauge 2-D rotary steerable system. In many of these wells, the rotary BHA has consistently placed the wellbore within a tight target corridor of ± 20 ft (6 m) (Table 1). One factor that was critical in achieving this kind of success was predicting BHA behavior by examining data from offset wells about bit walk tendencies, formation changes, bedding and dip angles. By analyzing the extensive database of 2-D rotary steerable runs, optimum BHAs can be selected, and DLS for various tool settings can be predicted to maintain better inclination control.
Andergauge's 2-D rotary steerable system has been used in the UK North Sea to drill horizontal sections within tight tolerances. The predictable full-gauge build (1.1°/100 m) and undergauge drop (-2°/100 m) can keep the wellbore horizontal for distances up to 2,740 ft (836 m).
The hidden costs of sliding
Horizontal wells drilled using conventional steerable assemblies have certain hidden costs and limitations, including:
• difficulty in setting and maintaining tool face because of weight stacking and reactive torque;
• poor hole cleaning and formation of cuttings beds caused by nonrotation; and
• an increase in overall drilling time because of lower ROP when sliding to control inclination (Figure 1).
Even so-called good sections with high ROP and minimal sliding often hide significant - and preventable - costs. Well path corrections made by sliding create instantaneous doglegs and result in tortuous wellbores, which may necessitate the use of torque-reduction devices such as time-consuming, nonrotating drill pipe protectors or expensive drilling fluids. In some cases, increased output top-drive systems may be required. High doglegs cause poor casing centralization, which leads to poor cementing. Doglegs also may induce premature casing wear. In the long run, lifting costs may increase due to increased workover operations and interrupted production. Drilling with a 2-D adjustable rotary steering assembly will minimize these costs by creating a smoother wellbore. This is because rotary build and drop trends take time to break, and thus doglegs are smoothed out over long sections. Consequently, cuttings are agitated and circulated out, the hole is cleaned out better, casing can be set more easily, and there is reduced potential for workovers and interrupted production. The cost-effectiveness and reliability of the adjustable stabilizer make it a valuable 2-D rotary steering tool that fits nicely in the directional driller's toolbox next to the latest rotary closed-loop steerable systems.
Point the bit
In February 2000, Halliburton Sperry-Sun introduced its Geo-Pilot second-generation rotary steerable system, designed in collaboration with Japan National Oil Corp. The system includes the Geo-Pilot rotary steerable tool and LWD and Insite data acquisition and management systems, as well as specially designed extended-gauge bits from Halliburton Security DBS.
First-generation rotary steerable tools have a pad device to push the short gauge bit away from the formation in the direction it needs to go. This side-cutting action can result in bit whirl and spiraling. Geo-Pilot is the first true point-the-bit rotary steerable tool with an internal rotating driveshaft that is deflected off center using two eccentric rings that cause the driveshaft to flex between the upper cantilever bearing and the lower focal bearing (Figure 2). Rotation of the eccentric rings is controlled by a downlink system with clutch control activators. The majority of the internal electronics boards are the same as the ones used in Halliburton's formation evaluation tool. A lithium battery provides 200 hours of rotary steering control, and all moving inner components are lubricated and isolated from wellbore fluids. The tool can be run in manual or automated mode with the tool self-guided along a programmed trajectory.
After undergoing field trials at the Gas Technology Institute's research facility near Catoosa, Okla., Geo-Pilot was launched commercially in October 2000 and has been used in 71 runs for operators in Norway, Canada, Alaska and the Gulf of Mexico. One challenging run for Spirit Energy in the Gulf of Mexico called for:
• a shallow kickoff;
• build to 33° inclination at a rate of 2.5°/100 ft;
• hold angle for 1,200 ft;
• drop to near vertical;
• kick off and build to 55°; and
• turn 182° to complete the section.
With the Geo-Pilot system, this difficult well path was followed with great precision and displayed significantly less torque and drag compared to similar wells. In addition, no extra circulation time was required for hole cleaning. The extra stabilization provided by the extended-gauge bit kept it centered, reducing side-cutting action and downhole vibration levels, which led to longer bit life and increased LWD reliability.
"We see the Geo-Pilot rotary steerable system as having a profound impact on drilling, even more than other rotary steerable systems," said Edgar Ortiz, president and chief executive officer of Halliburton's Energy Services Group. "Straighter, smoother wellbores will dramatically affect a host of problems that have plagued our industry for years. By minimizing borehole spiraling, we reduce our time spent circulating for hole cleaning, improve our logging and LWD tool response, improve the quality of our cement jobs, and reduce stuck pipe and casing incidents. We will also push the limits of extended-reach drilling even beyond where we have already gone."
Field trials have begun for an 8-in. Geo-Pilot tool for 121/4-in. holes, said Jerry Keen, technology leader at Halliburton Sperry-Sun. Plans also are being made to transition to near-bit and at-bit sensor technology. At-bit inclination is 3 ft (1 m) from the bit face; gamma-ray is expected at the same location in the next few months, and resistivity at about 15 ft (5 m) is planned later in 2002. Today, gamma-ray and resistivity are in the LWD tool about 30 ft (9 m) behind the bit, Keen said.
Improved power
Schlumberger developed the first prototype of its point-the-bit system in 1998 from MWD components. Improvements were made to the software, electronics and mechanical components to make a better
6 3/4-in. tool. In 1999, Schlumberger integrated Camco's Drilling & Service Engineering, Manufacturing into its Anadrill subsidiary to focus on this PowerDrive rotary steerable system, which has three subassemblies:
• the steering section, with a universal joint that transmits torque and weight on bit, but keeps the bit axis offset from the tool axis (a mandrel, which is kept geostationary by using a counter-rotating motor, points the bit);
• the electronics and sensor section, which monitors rotation of the collar and counter motor and measures direction and inclination 12 ft (4 m) behind the bit; and
• the power-generation section with alternator and high-power turbine.
The responsive inclination and azimuthal control of the PowerDrive system kept a record-setting Wytch Farm wellbore in the pay zone at inclinations from 84° to 98°.
Schlumberger claims a mean time between failure of 1,000 hours, with single-run capabilities of 250 hours or more. Build rates up to 8°/100 ft are recommended, but doglegs up to 11°/100 ft are achievable. It is also the only rotary steerable tool that can operate with bicenter bits. Communication with the tool is achieved by varying the flow rate, so drilling can proceed without pulling the tool to change configuration.
Schlumberger's second-generation tool is called PowerDrive Xtra, and it has numerous design improvements, including state-of-the-art downhole electronics, wear-resistant hardfacing, real-time communications and an integrated surface control system. The control unit and its housing are certified to withstand high levels of downhole impact and vibration, and the electronics can withstand higher temperatures.
PowerDrive Xtra replaced the stand-alone PC with a control interface for Schlumberger's Toolscope Ideal surface system. The communications system has been totally redesigned. A real-time link provides continuous telemetry to the MWD tool via an electromagnetic noncontacting link. This channel transmits azimuth and inclination data 7.9 ft (2.4 m) behind the bit.
This system has a couple of unique capabilities, including the ability to back-ream and kick off from vertical.
'Simple is good'
George Sutherland, vice president of Houston-based Rotary Steerable Tools (RST), said his company has a different approach to rotary steerable drilling. "The others are complicated with up to 4,000 components, whereas our tool only has 67 components, so it can function reliably and economically in a broader range of wells," he said. His company's system rotates the drillstring 100% of the time, and the bit can be controlled in three dimensions, all at about one-third the cost of the big, closed-loop systems. "Our system is so simple, it's field-repairable. And you can transport a standard package of two tools and a surface kit around the world for only about $10,000. A Volkswagen bug will get you where you're going a lot cheaper than a Ferrari. Simple is good."
The tool is essentially an eccentric cam driven by a battery-powered electric motor for 3-D rotary steering. It is an instrumented, nonrotating, near-bit stabilizer with a mandrel, an eccentric inner sleeve and a weighted outer sleeve, which seeks the low side of the hole (Figure 3). Once the mud motor has been used for the initial kickoff, the rotary steerable tool replaces the motor and controls the angle and direction for drilling the remainder of the well. The tool can be set within 1° to any of 360 toolface positions by a series of rotational frequency commands lasting 3.5 minutes. Inclination should be kept higher than 25° to ensure the weighted housing is kept to the low side of the hole. Inclination, cam position and outer housing orientation are recorded in downhole memory, and plans are to include a simple MWD tool to transmit these measurements in real time. The RST tool is compatible with all MWD and LWD systems, as well as underbalanced drilling with air or foam. A brushless DC motor powered by lithium C-cell batteries rotates the pinion gear, and the electronics are in the nonrotating housing for a smoother ride.
RST's first tool in July 1999 was for a
12 1/4-in. hole size, and this tool was run offshore California. In November 2000, the company released its SmartSleeve tools, which had 22 major design changes from the prototype. Tools for 8 1/2-in. and 6-in. hole sizes are planned for the future. The RST tools have been used with mill-tooth, insert and PDC bits in water- and oil-based muds. "With this tool, directional drillers can use the optimum bit for the formation, rather than the optimum bit for the motor," Sutherland said. Communication with the tool has been effective at more than 21,000 ft (6,405 m) of depth. The short tool length minimizes the pressure drop across the tool and enables survey instruments to be positioned closer to the bit (11 ft, 3.3 m).
One recent study showed that only 15% of the North Sea offshore rigs could afford to run a closed-loop rotary steerable system. For operators seeking a less expensive 3-D rotary steering tool, the simpler SmartSleeve tool may be the way to go.
Smaller is better
On the drawing board is a 4 3/4-in. OD rotary steerable tool from Precision Drilling, a company that is changing its business model from being a drilling contractor to being an integrated service company with its own rigs. As yet unnamed, the new tool, to be released by year-end 2001, will only be 6 ft (2 m) long, not 30 ft (9 m) long like some of the rotary steerable systems on the market. The small diameter will make it suitable for re-entry wells and other applications that are not accessible by 6 3/4-in. and 8-in. tools, said marketing manager Kevin Brady.
References
1. Eaton, L.F.; McDonald, Scott; and Rodriguez, Edgar M.: "First Simultaneous Application of Rotary Steerable/Ream-While-Drill on Ursa Horizontal Well," Paper No. SPE/IADC 67760, presented at the 2001 SPE/IADC Drilling Conference, Amsterdam, the Netherlands, Feb. 27-March 1, 2001.
2. Coghill, J.; Benefield, M.; Poppitt, A.; and Skillings, J.: "Innovations in Reservoir Navigation," Paper No. SPE 67756, presented at the SPE/IADC Drilling Conference, Amsterdam, the Netherlands, Feb. 27-March 1, 2001.
3. Georgi, D.; Wang, J.; and Krüger, V.: "The Benefits of Truly Horizontal Wells," Paper No. SPE/CIM 65526, presented at the 2000 SPE/Petroleum Society of CIM International Conference on Horizontal Well Technology, Calgary, Alberta, Nov. 6-8, 2000.
4. Paper No. SPE/CIM, presented at the 2000 SPE/Petroleum Society of CIM International Conference on Horizontal Well Technology, Calgary, Alberta, Nov. 6-8, 2000.