Certain situations require advanced drilling tech-nology (next page). Local geology might dictate acomplicated well trajectory, such as drillingaround salt domes, salt tablets or salt sheets.1

Reservoir drainage or production from a particu-lar well might improve if a well penetrated mul-tiple fault blocks or was constructed horizontallyto intersect fractures or to maximize wellboresurface area within the reservoir. A multilateraltypically drains several reservoir compartments.Small compartments in mature fields can also beproduced economically if directional wells arelocated skillfully.

Operators drill extended-reach wells to reser-voirs that cannot be exploited otherwise withoutunacceptable cost or environmental risk, forinstance to drill from a surface location onshoreto a bottomhole location offshore rather thanconstructing an artificial island. Drilling multiplewells from one surface location has been stan-dard practice offshore for years and is now com-mon in restricted onshore locations, like rainforests, for environmental protection. There arealso instances in which the operator wants todrill a vertical wellbore, notably the deep well ofthe KTB Program (German Continental DeepDrilling Program), and uses a steering system tokeep the hole straight.2

18 Oilfield Review

New Directions in Rotary Steerable Drilling

Geoff DowntonStonehouse, England

Andy HendricksMount Pearl, Newfoundland, Canada

For help in preparation of this article, thanks to VinceAbbott, New Orleans, Louisiana, USA; Julian Coles,Kristiansund, Norway; Greg Conran, Barry Cross, IanFalconer, Jeff Hamer, Wade McCutcheon, Eric Olson,Charlie Pratten, Keith Rappold, Stuart Schaaf and DebSmith, Sugar Land, Texas, USA; Torjer Halle and Paul Wand,Stavanger, Norway; Randy Strong, Houston, Texas; MikeWilliams, Aberdeen, Scotland; and Miriam Woodfine,Mount Pearl, Newfoundland, Canada.ADN (Azimuthal Density Neutron), CDR (Compensated DualResistivity), InterACT Web Witness, PowerDrive, PowerPakand PowerPulse are marks of Schlumberger.

Initially developed to drill extended-reach wells, rotary steerable systems

are also cost-effective in conventional drilling applications because they

reduce drilling time significantly. Improvements in rate of penetration as

well as in reliability have prompted worldwide deployment of these tools.

Trond Skei KlausenNorsk HydroKristiansund, Norway

Demos PafitisSugar Land, Texas, USA

1. For an example of mastering subsalt directional drillingchallenges: Cromb JR, Pratten CG, Long M and Walters RA:“Deepwater Subsalt Development: Directional DrillingChallenges and Solutions,” paper IADC/SPE 59197, presented at the 2000 IADC/SPE Drilling Conference,New Orleans, Louisiana, USA, February 23-25, 2000.

2. Bram K, Draxler J, Hirschmann G, Zoth G, Hiron S andKühr M: “The KTB Borehole—Germany’s SuperdeepTelescope into the Earth’s Crust,” Oilfield Review 7, no. 1(January 1995): 4-22.

Spring 2000 19

In rare emergency situations, directional-drilling technology is essential, for example toconstruct relief wells for blowouts. Less diresituations, such as sidetracking around anobstruction in a wellbore, also benefit from theability to control the wellbore trajectory. Furtherdownstream, directional drilling is used to con-struct conduits for oil and gas pipelines thatprotect the environment.3

Like other drilling operations, there is also aneed for cost-effective performance in direc-tional drilling: Drilling expenses account for asmuch as 40% of the finding and developmentcosts reported by exploration and productioncompanies.4 Offshore, eliminating a day of rigtime can save $100,000 or more. Acceleratingproduction by a day generates similar returns.5

Clearly, without advanced directional drillingtechnology, it might not be physically possible todrill a given well, the well might be drilled in asuboptimal location or it might be more expen-sive or risky. Rotary steerable systems allow usto plan complex wellbore geometries, includinghorizontal and extended-reach wells. They allowcontinuous rotation of the drillstring while steer-ing the well and eliminate the troublesome sliding mode of conventional steerable motors.The results have been dramatic: The PowerDriverotary steerable system contributed to the drillingof the world’s longest oil and gas productionwell, the 37,001-ft [11,278-m] Wytch Farm M-16SPZ well, in 1999. This article reviews thedevelopment of directional drilling technology,explains how new rotary steerable tools operateand presents examples that demonstrate howthese new systems solve problems and reduceexpenses in the oil field.

3. Barbeauld RO: “Directional Drilling OvercomesObstacles, Protects Environment,” Pipeline & GasJournal 226, no. 6 (June 1999): 26-29.

4. “Drill into Drilling Costs,” Hart’s E&P 73, no. 3 (March 2000): 15.

5. For several examples of the economic value of advanceddrilling technology: Djerfi Z, Haugen J, Andreassen E andTjotta H: “Statoil Applies Rotary Steerable Technologyfor 3-D Reservoir Drilling,” Petroleum EngineerInternational 72, no. 2 (February 1999): 29, 32-34.

> Directional inclinations. Surface obstructions or subsurface geological anomalies might preclude drilling a straight hole. Reservoir drainage can be optimizedby drilling an inclined wellbore. In an emergency, such as a blowout, a directional relief well reduces subsurface pressure in a controlled manner.

Evolution of Directional Drilling TechnologyThere have been astonishing advances in drillingtechnology since the primitive cable-tool tech-niques used to drill for salt hundreds of yearsbefore the development of modern techniques.The advent of rotary drilling, whose timing andorigins are subject to debate but which occurredaround 1850, allowed drillers greater control inreaching a specified target.6 Further advancesdepended on the development of accurate sur-veying systems and other downhole devices.

Improvements in drilling safety have accom-panied the progress in drilling technology. Forexample, pipe handling has been increasinglyautomated by “iron roughnecks” to minimize thenumber of workers on the rig floor. Unsafe toolshave been removed, such as kelly spinners replac-ing spinning chains. Bigger and better drilling rigshandle loads more securely. Kick-detection soft-ware and use of devices that detect annular pres-sure changes help improve hole cleaning andretain well control.7 These and other advance-ments in modern drilling operations have reducedaccidents and injuries substantially.

The first patent for a turbodrill, a type of down-hole drilling motor, was awarded in 1873.8

Controlled directional drilling began in the late1920s when drillers attempted to keep verticalholes from becoming crooked, sidetrack aroundobstructions or drill relief wells to regain control ofblowouts. There were even cases of drilling acrossproperty boundaries to drain oil and gas reservesillegally. The development of the mud motor was apowerful complement to advances in surveyingtechnology. Since then, positive-displacementmotors (PDM), which are placed in the bottomholeassembly (BHA) to turn the bit, have drilled mostdirectional wellbores. Exotic well designs con-tinue to push the limits of directional-drilling tech-nology, resulting in the combination of rotary andsteerable drilling systems now available.

Determining the inclination of a wellbore was akey problem in directional drilling until accuratemeasuring devices were invented. Directional sur-veys provide at least three vital pieces of informa-tion: the measured depth, the inclination of thewellbore and the azimuth, or compass direction, ofthe wellbore. From these, the wellbore locationcan be calculated. Survey techniques range frommagnetic single-shot surveys to more sophisti-cated gyroscopic surveys. Magnetic surveys recordthe well inclination and direction at a given point(single shot) or many points (multishot) using aninclinometer and a compass, a timer and a camera.Gyroscopic surveys provide more accuracy using aspinning mass pointed in a known direction. Thegyroscope maintains its orientation to measureinclination and direction at specific survey stations.The industry is currently developing unintrusivegyroscopic surveying methods that can be usedwhile drilling.

Modern measurements-while-drilling (MWD)systems send directional survey information to sur-face by mud-pulse telemetry—survey measure-ments are transmitted as pressure pulses in thedrilling fluid and decoded at surface while drillingis in progress. In addition to direction and inclina-tion, the MWD system transmits information aboutthe orientation of the directional drilling tool.Survey tools indicate only where a well has beenplaced; it is the directional tools, from the simplewhipstock to advanced steerable systems, thatoffer the driller control over the wellbore trajectory.

Before the development of leading-edge steer-able systems, expedient placement of drill collarsand stabilizers in the BHA allowed drillers to buildor drop angle (above). These techniques allowedsome control over hole inclination, but little or nocontrol over the azimuth of the wellbore. In someregions, experienced drillers could take advantageof the natural tendency of the drill bit to achievelimited wellbore deviation in a somewhat pre-dictable manner.

20 Oilfield Review

6. For more on the likely origins of drilling techniques andoil and gas industry history: Yergin D: The Prize: The EpicQuest for Oil, Money & Power. New York, New York,USA: Simon & Schuster, 1991.

7. For more on measuring annular pressure while drilling:Aldred W, Cook J, Bern P, Carpenter B, Hutchinson M,Lovell J, Rezmer-Cooper I and Leder PC: “UsingDownhole Annular Pressure Measurements to ImproveDrilling Performance,” Oilfield Review 10, no. 4 (Winter1998): 40-55.For more on drilling risk: Aldred W, Plumb D, Bradford I,Cook J, Gholkar V, Cousins L, Minton R, Fuller J, Goraya Sand Tucker D: “Managing Drilling Risk,” Oilfield Review11, no. 2 (Summer 1999): 2-19.

8. Anadrill: PowerPak Steerable Motor Handbook. Sugar Land, Texas, USA: Anadrill (1997): 3.For more on the use of turbodrills in multilateral wellconstruction: Bosworth S, El-Sayed HS, Ismail G, Ohmer H,Stracke M, West C and Retnanto A: “Key Issues inMultilateral Technology,” Oilfield Review 10, no. 4(Winter 1998): 14-28.

9. McMillin K: “Rotary Steerable Systems Creating Niche inExtended Reach Drilling,” Offshore 59, no. 2 (February1999): 52, 124.

10. For several general articles about stuck pipe: Oilfield Review 3, no. 4 (October 1991).

11. Mims M: “Directional Drilling PerformanceImprovement,” World Oil 220, no. 5 (May 1999): 40-43.

Build assembly Pendulum or drop assembly

> Changing direction without a downhole motor. Careful placement of stabilizers and drill collarsallow the directional driller to build angle (left) or drop angle (right) without a steerable BHA.Generally, the placement and gauge of the stabilizer(s) and flexibility of the intermediatestructure determine whether the assembly will build or drop.

Spring 2000 21

Steerable motors, which use a downhole tur-bine or PDM to generate power and a BHA witha fixed bend of approximately 1⁄2°, were devel-oped in the early 1960s to allow simultaneouscontrol of wellbore azimuth and inclination.9

Today, a typical steerable motor assembly con-sists of a power-generating section, throughwhich drilling fluid is pumped to turn the drill bit,a bend section of 0 to 3°, a drive shaft and the bit(below left).

Directional drilling with a steerable motor isaccomplished in two modes: rotating and sliding.In the rotating mode, the entire drillstring turns inthe same manner as ordinary rotary drilling andtends to drill straight ahead.

To initiate a change in the wellbore direction,the rotation of the drillstring is halted in such aposition that the bend in the motor points in thedirection of the new trajectory. This mode, knownas the sliding mode, refers to the fact that thenonrotating portion of the drillstring slides alongbehind the steerable assembly. While this tech-nology has performed admirably, it requires greatfinesse to correctly orient the bend in the motorbecause of the torsional compliance of the drill-string, which behaves almost like a coiled spring,twisting to the point of being difficult to orient.Lithological variations and other parameters alsoinfluence the ability to achieve the planneddrilling trajectory.

Perhaps the greatest challenge in conventionalslide drilling is the tendency of the nonrotatingdrillstring to become stuck.10 During periods ofslide drilling, the drillpipe lies on the low side ofthe borehole. This leads to uneven fluid velocities

around the pipe. In addition, the lack of drillpiperotation diminishes the ability of the drilling fluidto remove cuttings, so a cuttings bed may form onthe low side of the hole. Hole cleaning is affectedby rotary speed, hole tortuosity and bottomholeassembly design, among other factors.11

Sliding-mode drilling decreases the horse-power available to turn the bit, which, combinedwith sliding friction, decreases the rate of pene-tration (ROP). Eventually, in extreme extended-reach drilling projects, frictional forces duringsliding build to the point that there is insufficientaxial weight to overcome the drag of thedrillpipe against the wellbore, and furtherdrilling is not possible.

Finally, slide drilling typically introduces sev-eral undesirable inefficiencies. Switching fromthe sliding mode to the rotating mode whiledrilling with steerable tools can result in a moretortuous path to the target (below right). The

Power section

Surface-adjustablebent housing

Bearing section andstabilizer

> Steerable BHA. This simple yet ruggedPowerPak steerable assembly consists of apower-generating section, a surface-adjustablebent housing, a stabilizer and the drill bit.

> Optimizing trajectory. Directional drilling in the sliding and rotating modes typically results ina more irregular and longer path than planned (red trajectory). Doglegs can affect the ability torun casing to total depth. The use of a rotary steerable system eliminates the sliding mode andproduces a smoother wellbore (black trajectory).

numerous undulations or doglegs in the wellboreincrease wellbore tortuosity, which in turnincreases apparent friction while drilling and run-ning casing. During production, gas may accumu-late in the high spots and water in the low spots,choking production (above). Despite these chal-lenges, directional drilling with a steerable motorremains cost-effective and is still the mostwidely used method of directional drilling.

The next advance in directional drilling tech-nology, still in its infancy, is the rotary steerablesystem (RSS). These systems allow continuousrotation of the drillstring while steering the bit. Currently, the industry classifies rotarysteerable systems into two groups, the moreprevalent “push-the-bit” systems, including thePowerDrive system, and the less mature “point-the-bit” systems (left).

How Does a Rotary Steerable System Work?The PowerDrive system is mechanically uncom-plicated and compact, comprising a bias unit anda control unit that add only 121⁄2 ft [3.8 m] to thelength of the BHA.12 The bias unit, locateddirectly behind the bit, applies force to the bit ina controlled direction while the entire drill-string rotates. The control unit, which residesbehind the bias unit, contains self-powered elec-tronics, sensors and a control mechanism toprovide the average magnitude and direction ofthe bit side loads required to achieve the desiredtrajectory (below).

The bias unit has three external, hinged padsthat are activated by controlled mud flow througha valve. The valve exploits the difference in mudpressure between the inside and outside of the

22 Oilfield Review

GasOil

Water

> Optimizing flow during production. The high and low spots in the undulating well-bore (top) tend to accumulate gas (red) and water (blue), impeding the flow of oil. A smoother profile (bottom) allows oil to flow to surface more readily.

Power generatingturbine

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Sensor packageand control system

Applied force> Rotary steerable system designs characterizedby their steady-state behavior. In point-the-bitsystems (left), the bit is tilted relative to the rest of the tool to achieve the desired trajectory.Push-the-bit rotary steerable systems (right)apply force against the borehole to achieve thedesired trajectory.

Control unit Bias unit

Control electronics TurbineTurbine Steering actuator pad

> The PowerDrive rotary steerable system.

Spring 2000 23

bias unit (right). The three-way rotary disk valveactuates the pads by sequentially diverting mudinto the piston chamber of each pad as it rotatesinto alignment with the desired push point—thepoint opposite the desired trajectory—in thewell. After a pad passes the push point, therotary valve cuts off its mud supply and the mudescapes through a specially designed leakageport. Each pad extends no more than approxi-mately 3⁄8 in. [1 cm] during each revolution of thebias unit. An input shaft connects the rotary valveto the control unit to regulate the position of thepush point. If the angle of the input shaft is geo-stationary with respect to the rock, the bit isconstantly pushed in one direction, the directionopposite the push point. If no change in directionis needed, the system is operated in a neutralmode, with each pad extended in turn, so that the pads push in all directions and effectively“cancel” each other.

The control unit maintains the proper angularposition of the input shaft relative to the forma-tion. The control unit is mounted on bearings thatallow it to rotate freely about the axis of the drill-string. Through its onboard actuation system, thecontrol unit can be commanded to hold a fixedroll angle, or toolface angle, with respect to therock formation. Three-axis accelerometer andmagnetometer sensors provide informationabout the inclination and azimuth of the bit aswell as the angular position of the input shaft.Within the control unit, counter-rotating turbineimpellers mounted at opposite ends of the con-trol unit develop the required stabilizing torqueby carrying high-strength permanent magnetsthat couple with torquer coils in the control unit.The torque transmission from the impellers to thecontrol unit is controlled by electrically switchingthe loop resistance of the torquer coils. The

upper impeller, or torquer, is used to torque theplatform in the same direction as drillstring rota-tion, while the lower impeller turns it in theopposite direction. Additional coils generatepower for the electronics.

The tool can be customized at surface andpreprogrammed according to the expectedranges of inclination and direction. If the instruc-tions need to be changed, a sequence of pulsesin the drilling fluid transmits new instructionsdownhole. The steering performance of thePowerDrive system can be monitored by MWDtools as well as the sensors in the control unit;this information is transmitted to surface by thePowerPulse communication system.

The datum used to set the geostationaryangle of the shaft is provided either by a three-axis accelerometer or by the magnetometer triadmounted in the control unit. For near-verticalholes, an estimate of magnetic North is used asthe reference for determining the direction ofdeviation. For holes that deviate more than a fewdegrees from vertical, the accelerometers pro-vide the steering reference.

One of the many benefits of using a roll-sta-bilized platform to determine the steering direc-tion is its insensitivity to drillstring stick-slipbehavior. Additional sensors in the control unitrecord the instantaneous speed of the drillstringwith respect to the formation, thereby providinguseful data about drillstring behavior. Shock and thermal sensors are also carried by the con-trol unit to record additional information aboutdownhole conditions. Information about drillingconditions is continuously sampled and logged bythe onboard computer for immediate transmis-sion to surface by the MWD system or for laterretrieval at surface. This information has helpeddiagnose drilling problems, and, coupled with theMWD, mud logging and formation records, isproving to be extremely valuable in optimizingfuture runs.

Control shaft Disk valve Actuator

Right turn

> Pushing the bit. Mud flow through a three-way disk valve actuates three external pads (top). The padspush against the borehole at the appropriate point in each rotation to achieve the desired trajectory—in this case, turning right (top right)—and extend outward up to 3⁄8 in. [1 cm]. The illustrations at thebottom show the tool with the pads retracted (left) and extended (right).

12. For additional details about the workings of thePowerDrive tool: Clegg JM and Downton GC: “TheRemote Control of a Rotary Steerable Drilling System,”presented at the British Nuclear Energy SocietyConference on Remote Techniques for HazardousEnvironments, London, England, April 19-20, 1999.For several case histories from Wytch Farm field:Colebrook MA, Peach SR, Allen FM and Conran G:“Application of Steerable Rotary Drilling Technology toDrill Extended Reach Wells,” paper IADC/SPE 39327,presented at the 1998 IADC/SPE Drilling Conference,Dallas, Texas, USA, March 3-6, 1998.

Getting from Here to ThereHaving the capability to control well trajectorydoes not guarantee a perfect well. Successfuldirectional drilling involves careful planning. Tooptimize well plans, the geologist, geophysicistand engineers must work together from the out-set, rather than working in sequence using anincomplete knowledge base. Given a certain sur-face location and a desired subsurface target,the directional planner must assess cost,required accuracy and geological and technicalfactors to determine the appropriate wellboreprofile—slant, S-shaped, horizontal or perhaps a more exotic shape. Drilling into another well-bore, known as a collision, is unacceptable, soanticollision software is typically used to plan a safe trajectory.13

It is also important to select the appropriateRSS for the job. For sticky situations, a tool withpad assemblies or other exterior components thatrotate with the collar, such as the PowerDrive sys-tem, minimizes the risk of stuck pipe and allowsbackreaming of the wellbore. The RSS also mustbe capable of achieving the desired build rate.

Real-time communication and formationevaluation capabilities are critical to success insome situations. The PowerDrive system links to the PowerPulse MWD system and the suite of Schlumberger logging-while-drilling (LWD)systems. A short hop, which is a short-distancetelemetry system that does not require hard

wiring, can be placed inside the PowerDrive toolto facilitate real-time upward communication(above). The short hop connects the PowerPulsetelemetry system interface with the MWD systemby sending magnetic pulses and confirms thatinstructions have been received from the surface.

Bit selection for rotary steerable systems isgreater than for steerable motor assembliesbecause toolface control is good even whenaggressive drill bits are used.14 Directional con-trol with a PDM and an aggressive bit can be dif-ficult because an aggressive bit may generatelarge fluctuations in torque. Variations in torquealter the toolface to the detriment of directionalcontrol. A short, polycrystalline diamond compact(PDC) bit, for example the Hycalog DS130,maximizes the performance of the PowerDriverotary steerable system. The versatility of thePowerDrive tool also permits the use of other bitdesigns, such as roller-cone bits.

Rotating the drillstring improves hole clean-ing dramatically, minimizes the risk of stuck pipe,and facilitates directional control. The power atthe bit is not compromised by the need to per-form slide drilling operations. Directional controlcan be maintained beyond the point wheretorque and drag make sliding with a motor inef-fective. The benefits of increased ROP comparedwith a traditional sliding assembly are realizedwhen using the PowerDrive system.

PowerDrive Systems in High GearSince its first commercial run in 1996, thePowerDrive tool has demonstrated that elim-ination of sliding while directionally drillingdramatically increases the overall rate of pene-tration. The elimination of the sliding mode alsomakes unusual well trajectories possible, as thefollowing case histories demonstrate.

There have been 230 PowerDrive tool runs todate, including thousands of hours of operationin more than 40 wells. The longest single rundrilled a 5255-ft [1602-m] section.

In the Njord field of the Haltenbanken area offwestern Norway, operator Norsk Hydro first usedthe PowerDrive system to drill the reservoir sec-tion of the A-17-H well, finishing 22 days aheadof schedule. This success set the stage for amuch more challenging multitarget well with asinusoidal profile to manage the dual challengesof geological uncertainty and poor reservoir con-nectivity. The A-13-H well was drilled with thePowerDrive system in April 1999. The unusual W-shaped trajectory was planned to penetratethe primary reservoir in multiple fault blocks(next page, top).

The well penetrated the heterogeneousJurassic Tilje formation, which is predominantlysandstone with minor occurrences of mudstoneand siltstone, in four fault blocks. The reservoir iscompartmentalized by steeply dipping, hydrocar-bon-sealing fault planes separated by as much as30 to 50 m [98 to 164 ft] of throw. An additionalcomplication is that horizontal permeability in theTilje reservoir is significantly better than verticalpermeability, so producing it from a horizontalwellbore is preferable.

24 Oilfield Review

13. For more on integrated well-planning software:Clouzeau F, Michel G, Neff D, Ritchie G, Hansen R,McCann D and Prouvost L: “Planning and Drilling Wellsin the Next Millennium,” Oilfield Review 10, no. 4 (Winter 1998): 2-13.

14. A full discussion of bit selection is beyond the scope ofthis article, but will be addressed in an upcomingOilfield Review article. For this discussion, an aggres-sive bit is one that has been designed to drill quicklyusing long cutters that produce large cuttings. Lessaggressive bits have shorter teeth that produce smallercuttings by grinding. Other issues that affect bit functioninclude rotary speed, weight on bit, torque, flow rateand the nature of the formation being drilled.

> BHA configurations. The PowerDrive system can be run without a real-time communications system(top), with real-time short-hop communications (middle) or with a short-hop extender that allows real-time communications using a flex collar when a higher build rate is required (bottom).

4°/100 ftno real-time communications

4°/100 ftreal-time communications

8°/100 ftreal-time communications

PPI-communications

interface subStabilizer Control unit

collarBias unit

Flexcollar

Short-hop probe

15. For more on data delivery, including the InterACT WebWitness system: Brown T, Burke T, Kletzky A, Haarstad I,Hensley J, Murchie S, Purdy C and Ramasamy A: “In-Time Data Delivery,” Oilfield Review 11, no. 4 (Winter 1999/2000): 34-55.

16. For more on extended-reach drilling and productionoperations in the Wytch Farm field: Algeroy J, MorrisAJ, Stracke M, Auzerais F, Bryant I, Raghuraman B,Rathnasingham R, Davies J, Gai H, Johannessen O,Malde O, Toekje J and Newberry P: “ControllingReservoirs from Afar,” Oilfield Review 11, no. 3 (Autumn 1999): 18-29.Allen F, Tooms P, Conran G, Lesso B and Van de Slijke P:“Extended-Reach Drilling: Breaking the 10-km Barrier,”Oilfield Review 9, no. 4 (Winter 1997): 32-47.

Spring 2000 25

Real-time porosity, resistivity and gamma raymeasurements from the ADN Azimuthal DensityNeutron and CDR Compensated Dual Resistivitysystems allowed the operations team to geologi-cally steer the well into the desired locationusing the RSS. Intentional departures from theplanned trajectory were decided on the basis ofreal-time formation evaluation measurements.The InterACT Web Witness system transmitteddata in real time from the Njord drilling platformto the operations offices in Kristiansund andBergen so that the drilling and geological opera-tions team could make timely drilling decisions.15

In the past, a fishhook-shaped well wouldhave been drilled to intersect the reservoir in justtwo fault blocks. The combination of the RSS andreal-time formation evaluation enabled a seek-and-find approach, rather than guesswork, in anarea in which seismic uncertainty is as much as100 m [328 ft], to optimize the trajectory andimprove reservoir drainage by drilling into fourfault blocks. The penetration of the additionalfault blocks saved the expense and risk of drillinganother well. The A-13-H well would have beenimpossible to drill with conventional directionaldrilling technology. Using the rotary steerable

system cost $1 million less than the previous wellin the field because it cut well construction timeby half. Use of PDC bits with the PowerDrive toolmore than doubled ROP.

Rotary steerable systems open up new hori-zons for well planning, reservoir management andeven field development. Rotary steerable systemsmean that fewer wells are drilled, but those thatare drilled penetrate more targets. By intersectingfour fault blocks rather than two, the A-13-H wellachieved the geological objectives of two wellsand improved reservoir drainage dramatically.Well placement can be optimized by real-timetrajectory adjustments based on measurementsby combining the newest real-time formationevaluation tools with the PowerDrive system.Smaller platforms with fewer slots requiresmaller investments while optimizing fielddrainage and reducing the cost per barrel.

The PowerDrive system extended the life ofthe Njord field as a whole because of the flexibil-ity of the system. It has allowed access to reservesthat would have been considered uneconomicwith standard technology.

PowerDrive tool performance in 1999 averageda mean time between failures of 522 hours in theUnited Kingdom. In 2000, UK activity has increasedto three or more runs per month. Typical drillingoperations include complicated designer wells withmultiple build and turn sections. In 1998, the WytchFarm M-17 well was drilled through the narrowSherwood sandstone reservoir and between twofaults using the PowerDrive tool.16 This well set thecurrent record for a bit run, drilling 1287 m [4222 ft]in 84 hours while achieving a 110° turn at high incli-nation (below).

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> Longest bit run at Wytch Farm. The PowerDrive tool was used in two runs on the M-17 well, the second of which established the field recordfor longest bit run, with 1287 m of 81⁄2-in. hole drilled in 84 hours. The plan view of the well trajectory (left) shows the 110° turn. The three-dimensional view (right) illustrates the high inclination that accompanied the turn. Use of the PowerDrive tool saved seven days of rig time.

< A-13-H well path. The W-shaped wellintersected the Tilje reservoir in four separate fault blocks (top). Other well configurations used in the area, such asfishhook-shaped wells, would have penetrated only two fault blocks (bottom).

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3100500 2700Vertical section, m at 227.26°

Proposal Actual

Maximizing the cost-effectiveness of expen-sive directional wells with complex trajectories is a major challenge facing drilling engineers.Success depends on drilling tools that offer inher-ent efficiency, reliability and capabilities thatsupersede conventional systems. In Malaysia, thePowerDrive rotary steerable system demonstratedits prowess in two wells, the Bekok A1 ST and A7 ST, for operator Petronas Carigali. In both wells,the system performed flawlessly, with no failuresand no restrictions to drilling operations, such as having to backream. Steering was excellent inboth cases despite the relatively soft formationsbeing drilled.

On Bekok A7 ST, 1389 m [4557 ft] were drilledat an average of 51 m/hr [167 ft/hr], with holeinclinations varying from 40 to 70 degrees. Buildsand turns averaged 3°/30 m [3°/100 ft] (left). Byoptimizing bit selection, weight-on-bit, mud flowrate and rpm, PowerDrive technology achieved a45% higher penetration rate than the best everrecorded with downhole motors: The PowerDrivetool drilled 513 m/day [1683 ft/day], saving fivedays of rig time, while the best motor per-formance, in the Bekok A5 well, was only 360 m/day [1181 ft/day]. Valuable rig time wasalso saved because wiper trips decreased from atraditional average of one per 300 m [980 ft] toone per 700 m [2300 ft]. The well reached totaldepth in only two-thirds the time specified in thedrilling plan, resulting in significant cost savings.

On Bekok A1 ST, the PowerDrive system was used to drill 1601 m [5253 ft] of the 81⁄2-in.[21.6-cm] landing section of the well, cuttingthree days from the scheduled drilling program(next page, top left). Rates of penetration were300% higher than those experienced withconventional assemblies in offset wells, withcorrespondingly fewer wiper trips. Minimal tortu-osity, no micro doglegs and a smooth wellboreface allowed rapid, trouble-free deployment of the 7-in. [17.8-cm] liner. Total savings throughuse of the PowerDrive system are estimated at US$200,000.

The second development well in a field in theViosca Knoll planning area was the first applica-tion of a rotary steerable tool by a major operatorin the Gulf of Mexico. The operator’s goal inselecting the PowerDrive system was to save rigtime by increasing ROP with improved hydraulicsand also improving hole cleaning above the levelsachievable with a steerable PDM configuration.These improvements would help mitigate or elim-inate expensive and time-consuming stuck-pipeproblems caused by expanding shales—a fre-quent occurrence in the area—and allow tightercontrol on the equivalent circulating density ofthe drilling mud. Use of the rotary system would

26 Oilfield Review

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1760-480 -320 -160 0 160 320 800 960 1120 1280 1440480 640

True

ver

tical

dep

th, m

Vertical section, m

KOP360 MD 358 TVD17.7° 347.43° az-19 departure

Build and turn 3.00° per 30 m

Bekok A7 ST

Bekok A7

Hold angle 69.35°7-in. liner 2190 MD 1692 TVD 69.2° 198.5° az 1369 departure

TD 8.5-in. section 2600 MD 1696 TVD 69.2° 198.5° az 1369 departure

ActualProposal

-1280

-720 -560 -400 -240 -80 80

-1120

-960

-800

-640

-480

-320

-160

0

160

320

480

Disp

lace

men

t (no

rth/s

outh

), m

Displacement (east/west), m

Bekok A7

KOP360 MD 358 TVD17.7° 347.43° az23N 7W

7-in. liner

Bekok A7 ST

Hold

azim

uth 19

8.93°

> Plan view (top) and section view (bottom) of theBekok A7 ST planned well trajectory, shown in blue,and the actual trajectory, shown in red.

Spring 2000 27

ensure that cuttings were held in suspension atall times, overcoming settling problems associ-ated with sliding during PDM operations.

The PowerDrive system was used to drill outfrom the 95⁄8-in. [24.4-cm] casing shoe at 11,660 ft[3554 m]. After a formation integrity test wasperformed, the fluid system was displaced with14.9 lbm/gal [1.79 g/cm3] diesel-base drillingmud. This was the first time the tool had beenused with diesel-base fluid, so the potential forproblems was anticipated. The tool successfullydrilled 2767 ft [843 m] at a turn and drop rate ofup to 1.6° per 100 ft [30 m] (right).

The planned directional profile includeddrilling a 1300-ft [396-m] tangent section before

dropping and turning left through two geometri-cally tight targets. The tangent, or hold, sectionallowed the team to evaluate the directionalperformance of the system before initiating theturn. Excellent penetration rates were achievedwhile steering with the PowerDrive tool. Thesmall pressure drop across the tool allowedbetter use of available hydraulic horsepowercompared to a steerable motor. Flow rates weresome 50 gal/min [0.2 m3/min] higher than previ-ous motor runs, promoting improved hole clean-ing and faster rates of penetration. Hole-cleaningefficiency was monitored using an annular pres-sure sensor in the MWD string so that the holecould be cleaned as quickly as it could be drilled.

> Plan view (top) and section view (bottom) ofthe Bekok A1 ST planned well trajectory, shownin blue, and the actual trajectory, shown in red.

-4000 -3750 -3500 -3250 -3000-3000

-3250

-3500

-3750

RIH with PowerDrive tool

POOH with PowerDrive tool

Drop and turn2° per 100 ft

-4000

-4250

-4500

-4750

-5000

Displacement (east/west), ft

Disp

lace

men

t (no

rth/s

outh

), ft

1050

1100

1150

1200

1250

1300

RIH with PowerDrive tool

1350

1400

Departure from vertical, ft4500 5000 5500 6000

Verti

cal d

ispl

acem

ent,

ft

ActualProposal

Drop and turn 2° per 100 ft 35.14° 13,448 ft MD

POOH with PowerDrive tool

> Rotary steerable drilling in the Gulf ofMexico. A development well in a field inthe Viosca Knoll area was drilled using a rotary steerable system to improve ROPand hole cleaning. The proposed trajec-tory is shown in blue. The PowerDrivetool achieved the desired trajectory, asshown in red in the vertical section view(top) and plan view (bottom). The rotarysteerable tool was removed after drilling2767 ft and a PDM drilled the remainder of the hole at a rate that was two andone-half times slower.

0

400

800

1200

1600

2000

0 400 800 1200 1600 2000 2400 2800

True

ver

tical

dep

th, m

Vertical section, m

Tie-in 8.5° 418 measured depth

Build and turn 3.00° per 30 m75.71° 1117 measured depth

Bekok A1

Bekok A1 STHold angle 75.71°

ActualProposal

-1800

-2400 -1800 -1200 -600 0

-1200

-600

0

Disp

lace

men

t (no

rth/s

outh

), m

Displacement (east/west), m

Tie-inBekok A1

Bekok A1 ST

Kickoffpoint

Overall, the PowerDrive assembly was used todrill 420 ft [128 m] of cement and the shoe trackand formation from 11,660 to 14,427 ft [3554 to4397 m]. This was achieved in 42 drilling hours atan average penetration rate of 66 ft/hr [20 m/hr].

At 14,427 ft measured depth, it becameapparent that the rotary steerable system was nolonger receiving commands from the surface. Thetool continued to drill according to the last

command received, a low-side orientation thatinduced a slight turn to the right. At this stage, itwas imperative to initiate a left-hand turn, and atrip was required to retrieve the tool. Becausethe nature of the failure was unknown initially,and because the wellbore temperature wasapproaching the temperature limits of the rotarysteerable assembly, a conventional steerablemotor was selected to finish drilling the interval.

Subsequent analysis confirmed that an elas-tomer bearing had failed, allowing the turbinepower assembly to rotate eccentrically in the toolcollar. Wear inside the collar indicated that theturbine fins were striking the inner collar wall,preventing the tool from receiving new com-mands. It was later determined that the mud haddegraded the bearing material. For future appli-cations, an upgraded, more durable elastomerhas been developed, proven effective and is now in use.

The results with a steerable motor on the fol-lowing run provided an interesting comparison ofthe efficiency of the two systems because thesame type of bit was run, the same formationwas drilled and similarly demanding directionalwork was performed. Penetration rates achievedwhile rotating with the conventional steerablemotor approached those of the PowerDrive sys-tem. However, the extra time necessary to orientthe toolface, along with lower penetration rateswhile sliding, greatly increased overall drillingtimes. The steerable motor drilled 1303 ft [397 m]in 48 hours at an average ROP of 27 ft/hr [8.2 m/hr], almost two and one-half times slowerthan the PowerDrive system.

This example clearly demonstrates thatincreased ROP offsets higher rig rates and morethan compensates for the additional expense ofthe rotary steerable tool, resulting in overall timeand cost savings (left). This well was drilled 10days ahead of plan. Nevertheless, furtherimprovement in rotary steerable drilling perfor-mance remains a key objective for Schlumberger.

28 Oilfield Review

> Drilling efficiency improvements.Use of the PowerDrive system contributed to drilling the VioscaKnoll development well 10 daysahead of plan.

17. Schaaf S, Pafitis D and Guichemerre E: “Application of aPoint the Bit Rotary Steerable System in DirectionalDrilling Prototype Well-bore Profiles,” paper SPE 62519,prepared for presentation at the 2000 SPE/AAPGWestern Regional Meeting, Long Beach, California,USA, June 19-23, 2000.

0

2000

4000

6000

8000

10,000

0 20 40 60 80

12,000

14,000

16,000

18,000

Mea

sure

d de

pth,

ft

Actual daysRisked plan days

Minimum plan days

Number of drilling days

Spring 2000 29

Driving into the FutureThe ability of the PowerDrive rotary steerable sys-tem to drill long sections quickly and reliably hasled to high demand for the 39 tools now available.The manufacturing of 16 additional PowerDrivetools during the first quarter of 2000 increasedworldwide access to these systems. The tools aremanufactured in the UK, but maintenance andrepairs are performed in several regional centers,close to where the tools are used.

The PowerDrive675 system, the 63⁄4-in. tooldescribed in this article, is now proven tech-nology (right). Schlumberger is working to setnew industry standards for rotary steerablesystems. The PowerDrive900, a 9-in. push-the-bit tool designed to drill 121⁄4-in. and largerholes, is undergoing field trials at present, with commercialization expected in the secondhalf of 2000.

A point-the-bit tool design, whose drilling tra-jectory is determined by the bit direction ratherthan the orientation of a longer section of theBHA, will fulfill demands for greater bit and sta-bilizer selection, including bicenter bits, andhigher build rates. Schlumberger has tested aprototype point-the-bit tool in various locationsworldwide and drilled upwards of 100 ft/hr [30 m/hr].17 This prototype tool extends the flowand temperature ranges of the push-the-bit

systems while maintaining a relatively compactsize. Survey data are gathered close to the bitand sent to the surface for real-time trajectoryfeedback and control. For each of these systems,the goal is cost-effective drilling in mainstreamoperations, rather than the current economicrestriction to only the most extreme applications.Operators certainly will continue to push the lim-its of reach and depth (left).

Further refinements in remote communicationlinks to operator offices will allow experts toreceive data, consult with rig personnel and sendback commands to the mud pumps, a criticalcapability when drilling complex wells.Eventually, the shape of wellbores will be limitedonly by economics and ingenuity. —GMG

Steady deviationcontrolled by downhole motor,

independent of bit torque. Problemsof controlling toolface throughelastic drillstring are avoided.

Cleaner holeeffect of high inclination is offset

by continuous pipe rotation

Continuous rotationwhile steering

Smooth holetortuosity of wellbore is reduced

by better steering

Less risk ofstuck pipe

Less dragimproves control of WOB

Lower cost per barrel

Time savingsdrill faster while steering and

reduce wiper trips

Longer extended reachwithout excessive drag

Completioncost is reduced

andworkover

is made easier

Longerhorizontal

rangein reservoir with

good steering

Fewer wellsto exploit areservoir

Lower cost per footFewer platformsto develop a field

> Benefits of the PowerDrive system. Continuous rotation of the drillstring improves manyaspects of well construction and ultimately translates into saving time and money.

35,000

30,000

25,000

20,000

15,000

10,000

5000

00 5000 10,000 15,000 20,000 25,000 30,000 35,000 40,000

5:1Ratio

2:1Ratio

1:1 Ratio

True

ver

tical

dep

th, f

t

Displacement, ft

Shell Auger

BP ClydeBP Gyda

Maersk, QatarAmoco Brintnell 2-10

Statoil Sleipner PhillipsZijiang

Total Austral

Total AustralCN-1

BP M-14

BP M-11BP Amoco

M-16Z

> Extending the envelope. Reach of 10 km [6.2 miles] or more is possible at relatively shallowdepths. Displacement becomes restricted with increasing depth, as shown by the purple envelope.