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Certain situations require advanced drilling tech-
nology (next page). Local geology might dictate a
complicated well trajectory, such as drilling
around 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 horizontally
to intersect fractures or to maximize wellbore
surface area within the reservoir. A multilateral
typically drains several reservoir compartments.
Small compartments in mature fields can also beproduced economically if directional wells are
located skillfully.
Operators drill extended-reach wells to reser-
voirs that cannot be exploited otherwise without
unacceptable cost or environmental risk, for
instance to drill from a surface location onshore
to a bottomhole location offshore rather than
constructing an artificial island. Drilling multiple
wells from one surface location has been stan-
dard practice offshore for years and is now com-
mon in restricted onshore locations, like rain
forests, for environmental protection. There are
also instances in which the operator wants todrill a vertical wellbore, notably the deep well of
the KTB Program (German Continental Deep
Drilling Program), and uses a steering system to
keep the hole straight.2
18 Oilfield Review
New Directions in Rotary Steerable Drilling
Geoff Downton
Stonehouse, England
Andy Hendricks
Mount 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 Klausen
Norsk Hydro
Kristiansund, Norway
Demos Pafitis
Sugar Land, Texas, USA
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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 andKhr M: The KTB BoreholeGermanys SuperdeepTelescope into the Earths Crust, Oilfield Review7, no. 1(January 1995): 4-22.
Spring 2000 19
In rare emergency situations, directional-
drilling technology is essential, for example to
construct relief wells for blowouts. Less dire
situations, such as sidetracking around an
obstruction in a wellbore, also benefit from the
ability to control the wellbore trajectory. Further
downstream, directional drilling is used to con-
struct conduits for oil and gas pipelines that
protect the environment.3
Like other drilling operations, there is also a
need for cost-effective performance in direc-
tional drilling: Drilling expenses account for as
much as 40% of the finding and development
costs reported by exploration and production
companies.4 Offshore, eliminating a day of rig
time can save $100,000 or more. Accelerating
production by a day generates similar returns.5
Clearly, without advanced directional drilling
technology, it might not be physically possible to
drill a given well, the well might be drilled in a
suboptimal location or it might be more expen
sive or risky. Rotary steerable systems allow us
to plan complex wellbore geometries, including
horizontal and extended-reach wells. They allow
continuous 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 drilling
of the worlds longest oil and gas production
well, the 37,001-ft [11,278-m] Wytch Farm
M-16SPZ well, in 1999. This article reviews the
development of directional drilling technology
explains how new rotary steerable tools operate
and presents examples that demonstrate how
these new systems solve problems and reduce
expenses in the oil field.
3. Barbeauld RO: Directional Drilling OvercomesObstacles, Protects Environment, Pipeline & GasJournal226, no. 6 (June 1999): 26-29.
4. Drill into Drilling Costs, Harts E&P73, 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 EngineerInternational72, 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.
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Evolution of Directional Drilling Technology
There have been astonishing advances in drilling
technology since the primitive cable-tool tech-
niques used to drill for salt hundreds of years
before the development of modern techniques.
The advent of rotary drilling, whose timing and
origins are subject to debate but which occurred
around 1850, allowed drillers greater control in
reaching a specified target.6 Further advances
depended on the development of accurate sur-
veying systems and other downhole devices.
Improvements in drilling safety have accom-
panied the progress in drilling technology. For
example, pipe handling has been increasingly
automated by iron roughnecks to minimize the
number of workers on the rig floor. Unsafe tools
have been removed, such as kelly spinners replac-
ing spinning chains. Bigger and better drilling rigs
handle loads more securely. Kick-detection soft-ware and use of devices that detect annular pres-
sure changes help improve hole cleaning and
retain well control.7 These and other advance-
ments in modern drilling operations have reduced
accidents 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 late
1920s when drillers attempted to keep vertical
holes from becoming crooked, sidetrack around
obstructions or drill relief wells to regain control of
blowouts. There were even cases of drilling across
property boundaries to drain oil and gas reservesillegally. The development of the mud motor was a
powerful complement to advances in surveying
technology. Since then, positive-displacement
motors (PDM), which are placed in the bottomhole
assembly (BHA) to turn the bit, have drilled most
directional wellbores. Exotic well designs con-
tinue to push the limits of directional-drilling tech-
nology, resulting in the combination of rotary and
steerable drilling systems now available.
Determining the inclination of a wellbore was a
key problem in directional drilling until accurate
measuring devices were invented. Directional sur-
veys provide at least three vital pieces of informa-
tion: the measured depth, the inclination of the
wellbore and the azimuth, or compass direction, of
the wellbore. From these, the wellbore location
can be calculated. Survey techniques range from
magnetic single-shot surveys to more sophisti-
cated gyroscopic surveys. Magnetic surveys record
the well inclination and direction at a given point(single shot) or many points (multishot) using an
inclinometer and a compass, a timer and a camera.
Gyroscopic surveys provide more accuracy using a
spinning mass pointed in a known direction. The
gyroscope maintains its orientation to measure
inclination and direction at specific survey stations.
The industry is currently developing unintrusive
gyroscopic surveying methods that can be used
while drilling.
Modern measurements-while-drilling (MWD)
systems send directional survey information to sur-
face by mud-pulse telemetrysurvey measure-
ments are transmitted as pressure pulses in the
drilling fluid and decoded at surface while drilling
is in progress. In addition to direction and inclina-
tion, the MWD system transmits information about
the orientation of the directional drilling tool.
Survey tools indicate only where a well has been
placed; it is the directional tools, from the simple
whipstock 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 collars
and stabilizers in the BHA allowed drillers to build
or drop angle (above). These techniques allowed
some control over hole inclination, but little or no
control over the azimuth of the wellbore. In some
regions, experienced drillers could take advantage
of the natural tendency of the drill bit to achieve
limited 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 Review10, 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 well
construction: 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, Offshore59, no. 2 (February1999): 52, 124.
10. For several general articles about stuck pipe:Oilfield Review3, no. 4 (October 1991).
11. Mims M: Directional Drilling PerformanceImprovement, World Oil220, 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.
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Spring 2000 2
Steerable motors, which use a downhole tur-
bine or PDM to generate power and a BHA with
a fixed bend of approximately 12, were devel-
oped in the early 1960s to allow simultaneous
control of wellbore azimuth and inclination.9
Today, a typical steerable motor assembly con-
sists of a power-generating section, through
which 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 is
accomplished in two modes: rotating and sliding.
In the rotating mode, the entire drillstring turns in
the same manner as ordinary rotary drilling and
tends to drill straight ahead.
To initiate a change in the wellbore direction,
the rotation of the drillstring is halted in such a
position that the bend in the motor points in the
direction of the new trajectory. This mode, known
as the sliding mode, refers to the fact that the
nonrotating portion of the drillstring slides along
behind the steerable assembly. While this tech-
nology has performed admirably, it requires great
finesse to correctly orient the bend in the motor
because 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 also
influence the ability to achieve the planned
drilling trajectory.
Perhaps the greatest challenge in conventional
slide drilling is the tendency of the nonrotating
drillstring to become stuck.10 During periods of
slide drilling, the drillpipe lies on the low side of
the borehole. This leads to uneven fluid velocities
around the pipe. In addition, the lack of drillpipe
rotation diminishes the ability of the drilling fluid
to remove cuttings, so a cuttings bed may form on
the low side of the hole. Hole cleaning is affected
by rotary speed, hole tortuosity and bottomhole
assembly design, among other factors.11
Sliding-mode drilling decreases the horse
power available to turn the bit, which, combined
with sliding friction, decreases the rate of pene
tration (ROP). Eventually, in extreme extended
reach drilling projects, frictional forces during
sliding build to the point that there is insufficien
axial weight to overcome the drag of the
drillpipe against the wellbore, and furthe
drilling is not possible.
Finally, slide drilling typically introduces sev
eral undesirable inefficiencies. Switching from
the sliding mode to the rotating mode while
drilling with steerable tools can result in a more
tortuous 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).
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numerous undulations or doglegs in the wellbore
increase wellbore tortuosity, which in turn
increases 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 motor
remains cost-effective and is still the most
widely used method of directional drilling.
The next advance in directional drilling tech-nology, still in its infancy, is the rotary steerable
system (RSS). These systems allow continuous
rotation of the drillstring while steering the
bit. Currently, the industry classifies rotary
steerable systems into two groups, the more
prevalent push-the-bitsystems, including the
PowerDrive system, and the less mature point-
the-bitsystems (left).
How Does a Rotary Steerable System Work?
The PowerDrive system is mechanically uncom-
plicated and compact, comprising a bias unit and
a control unit that add only 1212 ft [3.8 m] to the
length of the BHA.12 The bias unit, located
directly behind the bit, applies force to the bit in
a controlled direction while the entire drill-
string rotates. The control unit, which resides
behind the bias unit, contains self-powered elec-
tronics, sensors and a control mechanism toprovide the average magnitude and direction of
the bit side loads required to achieve the desired
trajectory (below).
The bias unit has three external, hinged pads
that are activated by controlled mud flow through
a valve. The valve exploits the difference in mud
pressure 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
Collar rotation
Motor rotation
Motor
Drilling tendency
Sensor packageand control system
Appliedforce
> Rotary steerable system designs characterizedby their steady-state behavior. In point-the-bitsystems (left), the bit is tilted relative to the restof 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.
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Spring 2000 23
bias unit (right). The three-way rotary disk valve
actuates the pads by sequentially diverting mud
into the piston chamber of each pad as it rotates
into alignment with the desired push pointthe
point opposite the desired trajectoryin the
well. After a pad passes the push point, the
rotary valve cuts off its mud supply and the mud
escapes through a specially designed leakage
port. Each pad extends no more than approxi-
mately 38 in. [1 cm] during each revolution of the
bias unit. An input shaft connects the rotary valve
to the control unit to regulate the position of the
push point. If the angle of the input shaft is geo-
stationary with respect to the rock, the bit is
constantly pushed in one direction, the direction
opposite the push point. If no change in direction
is needed, the system is operated in a neutral
mode, with each pad extended in turn, so thatthe pads push in all directions and effectively
canceleach other.
The control unit maintains the proper angular
position of the input shaft relative to the forma-
tion. The control unit is mounted on bearings that
allow it to rotate freely about the axis of the drill-
string. Through its onboard actuation system, the
control unit can be commanded to hold a fixed
roll angle, or toolface angle, with respect to the
rock formation. Three-axis accelerometer and
magnetometer sensors provide information
about the inclination and azimuth of the bit as
well as the angular position of the input shaft.Within the control unit, counter-rotating turbine
impellers mounted at opposite ends of the con-
trol unit develop the required stabilizing torque
by carrying high-strength permanent magnets
that couple with torquer coils in the control unit.
The torque transmission from the impellers to the
control unit is controlled by electrically switching
the loop resistance of the torquer coils. The
upper impeller, or torquer, is used to torque the
platform in the same direction as drillstring rota-
tion, while the lower impeller turns it in the
opposite direction. Additional coils generate
power for the electronics.The tool can be customized at surface and
preprogrammed according to the expected
ranges of inclination and direction. If the instruc-
tions need to be changed, a sequence of pulses
in the drilling fluid transmits new instructions
downhole. The steering performance of the
PowerDrive system can be monitored by MWD
tools as well as the sensors in the control unit;
this information is transmitted to surface by the
PowerPulse communication system.
The datum used to set the geostationary
angle of the shaft is provided either by a three-
axis accelerometer or by the magnetometer triadmounted in the control unit. For near-vertical
holes, an estimate of magnetic North is used as
the reference for determining the direction of
deviation. For holes that deviate more than a few
degrees 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-slip
behavior. Additional sensors in the control uni
record the instantaneous speed of the drillstringwith respect to the formation, thereby providing
useful data about drillstring behavior. Shock
and thermal sensors are also carried by the con
trol unit to record additional information abou
downhole conditions. Information about drilling
conditions is continuously sampled and logged by
the onboard computer for immediate transmis
sion to surface by the MWD system or for late
retrieval at surface. This information has helped
diagnose drilling problems, and, coupled with the
MWD, mud logging and formation records, is
proving to be extremely valuable in optimizing
future 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 padpush against the borehole at the appropriate point in each rotation to achieve the desired trajectoryin this case, turning right (top right)and extend outward up to 38 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 Society
Conference 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.
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Getting from Here to There
Having the capability to control well trajectory
does not guarantee a perfect well. Successful
directional drilling involves careful planning. To
optimize well plans, the geologist, geophysicist
and engineers must work together from the out-
set, rather than working in sequence using an
incomplete knowledge base. Given a certain sur-
face location and a desired subsurface target,the directional planner must assess cost,
required accuracy and geological and technical
factors to determine the appropriate wellbore
profileslant, S-shaped, horizontal or perhaps
a more exotic shape. Drilling into another well-
bore, known as a collision, is unacceptable, so
anticollision software is typically used to plan a
safe trajectory.13
It is also important to select the appropriate
RSS for the job. For sticky situations, a tool with
pad assemblies or other exterior components that
rotate with the collar, such as the PowerDrive sys-
tem, minimizes the risk of stuck pipe and allowsbackreaming of the wellbore. The RSS also must
be capable of achieving the desired build rate.
Real-time communication and formation
evaluation capabilities are critical to success in
some 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-distance
telemetry system that does not require hard
wiring, can be placed inside the PowerDrive tool
to facilitate real-time upward communication
(above). The short hop connects the PowerPulse
telemetry system interface with the MWD system
by sending magnetic pulses and confirms that
instructions have been received from the surface.
Bit selection for rotary steerable systems is
greater than for steerable motor assemblies
because 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 generate
large fluctuations in torque. Variations in torque
alter the toolface to the detriment of directional
control. A short, polycrystalline diamond compact
(PDC) bit, for example the Hycalog DS130,
maximizes the performance of the PowerDrive
rotary steerable system. The versatility of the
PowerDrive tool also permits the use of other bit
designs, 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 at
the bit is not compromised by the need to per-
form slide drilling operations. Directional control
can be maintained beyond the point where
torque and drag make sliding with a motor inef-
fective. The benefits of increased ROP compared
with a traditional sliding assembly are realized
when using the PowerDrive system.
PowerDrive Systems in High Gear
Since its first commercial run in 1996, the
PowerDrive tool has demonstrated that elim-
ination of sliding while directionally drilling
dramatically increases the overall rate of pene-
tration. The elimination of the sliding mode also
makes unusual well trajectories possible, as the
following case histories demonstrate.
There have been 230 PowerDrive tool runs to
date, including thousands of hours of operation
in more than 40 wells. The longest single run
drilled a 5255-ft [1602-m] section.In the Njord field of the Haltenbanken area off
western Norway, operator Norsk Hydro first used
the PowerDrive system to drill the reservoir sec-
tion of the A-17-H well, finishing 22 days ahead
of schedule. This success set the stage for a
much more challenging multitarget well with a
sinusoidal profile to manage the dual challenges
of geological uncertainty and poor reservoir con-
nectivity. The A-13-H well was drilled with the
PowerDrive system in April 1999. The unusual
W-shaped trajectory was planned to penetrate
the primary reservoir in multiple fault blocks
(next page, top).The well penetrated the heterogeneous
Jurassic Tilje formation, which is predominantly
sandstone with minor occurrences of mudstone
and siltstone, in four fault blocks. The reservoir is
compartmentalized by steeply dipping, hydrocar-
bon-sealing fault planes separated by as much as
30 to 50 m [98 to 164 ft] of throw. An additional
complication is that horizontal permeability in the
Tilje reservoir is significantly better than vertical
permeability, so producing it from a horizontal
wellbore 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 Review10, 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 Reviewarticle. 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 Review11, 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 Review11, 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 Review9, no. 4 (Winter 1997): 32-47.
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Spring 2000 25
Real-time porosity, resistivity and gamma ray
measurements from the ADN Azimuthal Density
Neutron and CDR Compensated Dual Resistivity
systems allowed the operations team to geologi-
cally steer the well into the desired location
using the RSS. Intentional departures from the
planned trajectory were decided on the basis of
real-time formation evaluation measurements.
The InterACT Web Witness system transmitted
data in real time from the Njord drilling platform
to the operations offices in Kristiansund and
Bergen so that the drilling and geological opera-
tions team could make timely drilling decisions.15
In the past, a fishhook-shaped well would
have been drilled to intersect the reservoir in just
two fault blocks. The combination of the RSS and
real-time formation evaluation enabled a seek-
and-find approach, rather than guesswork, in an
area in which seismic uncertainty is as much as
100 m [328 ft], to optimize the trajectory and
improve reservoir drainage by drilling into four
fault blocks. The penetration of the additional
fault blocks saved the expense and risk of drilling
another well. The A-13-H well would have been
impossible to drill with conventional directional
drilling technology. Using the rotary steerable
system cost $1 million less than the previous wel
in the field because it cut well construction time
by half. Use of PDC bits with the PowerDrive too
more than doubled ROP.
Rotary steerable systems open up new hori
zons for well planning, reservoir management and
even field development. Rotary steerable systems
mean that fewer wells are drilled, but those tha
are drilled penetrate more targets. By intersecting
four fault blocks rather than two, the A-13-H wel
achieved the geological objectives of two wells
and improved reservoir drainage dramatically
Well placement can be optimized by real-time
trajectory adjustments based on measurements
by combining the newest real-time formation
evaluation tools with the PowerDrive system
Smaller platforms with fewer slots require
smaller investments while optimizing field
drainage and reducing the cost per barrel.
The PowerDrive system extended the life o
the Njord field as a whole because of the flexibil
ity of the system. It has allowed access to reserves
that would have been considered uneconomicwith standard technology.
PowerDrive tool performance in 1999 averaged
a mean time between failures of 522 hours in the
United Kingdom. In 2000, UK activity has increased
to three or more runs per month. Typical drilling
operations include complicated designer wells with
multiple build and turn sections. In 1998, the Wytch
Farm M-17 well was drilled through the narrow
Sherwood sandstone reservoir and between two
faults using the PowerDrive tool.16 This well set the
current record for a bit run, drilling 1287 m [4222 ft
in 84 hours while achieving a 110 turn at high incli
nation (below).
9 5/8-in.
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60
0
70
0
80
0
90
0
10
00
11
00
12
00
13
00
140
0
15
00
N
Distance,
m
Distance, m
> 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 812-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 fourseparate fault blocks (top). Other wellconfigurations used in the area, such asfishhook-shaped wells, would havepenetrated only two fault blocks (bottom).
Verticaldepth,
m
2100
3100
500 2700Vertical section, m at 227.26
Proposal Actual
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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 that
supersede conventional systems. In Malaysia, the
PowerDrive rotary steerable system demonstrated
its prowess in two wells, the Bekok A1 ST and
A7 ST, for operator Petronas Carigali. In both wells,
the system performed flawlessly, with no failures
and no restrictions to drilling operations, such
as having to backream. Steering was excellent in
both cases despite the relatively soft formations
being drilled.
On Bekok A7 ST, 1389 m [4557 ft] were drilled
at an average of 51 m/hr [167 ft/hr], with hole
inclinations varying from 40 to 70 degrees. Builds
and turns averaged 3/30 m [3/100 ft] (left). By
optimizing bit selection, weight-on-bit, mud flow
rate and rpm, PowerDrive technology achieved a
45% higher penetration rate than the best ever
recorded with downhole motors: The PowerDrive
tool 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 was
also saved because wiper trips decreased from a
traditional average of one per 300 m [980 ft] to
one per 700 m [2300 ft]. The well reached total
depth in only two-thirds the time specified in the
drilling plan, resulting in significant cost savings.
On Bekok A1 ST, the PowerDrive system
was used to drill 1601 m [5253 ft] of the 812-in.
[21.6-cm] landing section of the well, cutting
three days from the scheduled drilling program
(next page, top left). Rates of penetration were300% higher than those experienced with
conventional assemblies in offset wells, with
correspondingly fewer wiper trips. Minimal tortu-
osity, no micro doglegs and a smooth wellbore
face allowed rapid, trouble-free deployment
of the 7-in. [17.8-cm] liner. Total savings through
use of the PowerDrive system are estimated
at US$200,000.
The second development well in a field in the
Viosca Knoll planning area was the first applica-
tion of a rotary steerable tool by a major operator
in the Gulf of Mexico. The operators goal in
selecting the PowerDrive system was to save rigtime by increasing ROP with improved hydraulics
and also improving hole cleaning above the levels
achievable with a steerable PDM configuration.
These improvements would help mitigate or elim-
inate expensive and time-consuming stuck-pipe
problems caused by expanding shalesa fre-
quent occurrence in the areaand allow tighter
control on the equivalent circulating density of
the drilling mud. Use of the rotary system would
26 Oilfield Review
0
160
320
480
640
800
960
1120
1280
1440
1600
1760-480 -320 -160 0 160 320 800 960 1120 1280 1440480 640
Trueverticaldepth,
m
Vertical section, m
KOP360 MD 358 TVD17.7 347.43az-19 departure
Build and turn 3.00per 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 69.2 198.5az 1369 departure
Actual
Proposal
-1280
-720 -560 -400 -240 -80 80
-1120
-960
-800
-640
-480
-320
-160
0
160
320
480
Displaceme
nt(north/south),m
Displacement (east/west), m
Bekok A7
KOP
360 MD 358 TVD
17.7 347.43az
23N 7W
7-in. liner
Bekok A7 ST
Hold
azimu
th198
.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.
8/10/2019 New Directions in RSS
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Spring 2000 27
ensure that cuttings were held in suspension at
all times, overcoming settling problems associ-
ated with sliding during PDM operations.
The PowerDrive system was used to drill out
from the 958-in. [24.4-cm] casing shoe at 11,660 ft
[3554 m]. After a formation integrity test wasperformed, the fluid system was displaced with
14.9 lbm/gal [1.79 g/cm3] diesel-base drilling
mud. This was the first time the tool had been
used with diesel-base fluid, so the potential for
problems was anticipated. The tool successfully
drilled 2767 ft [843 m] at a turn and drop rate of
up to 1.6 per 100 ft [30 m] (right).
The planned directional profile included
drilling a 1300-ft [396-m] tangent section before
dropping and turning left through two geometri-
cally tight targets. The tangent, or hold, section
allowed the team to evaluate the directional
performance of the system before initiating the
turn. Excellent penetration rates were achieved
while steering with the PowerDrive tool. Thesmall pressure drop across the tool allowed
better use of available hydraulic horsepower
compared to a steerable motor. Flow rates were
some 50 gal/min [0.2 m3/min] higher than previ-
ous motor runs, promoting improved hole clean-
ing and faster rates of penetration. Hole-cleaning
efficiency was monitored using an annular pres-
sure sensor in the MWD string so that the hole
could 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 turn2per 100 ft
-4000
-4250
-4500
-4750
-5000
Displacement (east/west), ft
Displacement(north/south),ft
1050
1100
1150
1200
1250
1300
RIH with PowerDrive tool
1350
1400
Departure from vertical, ft4500 5000 5500 6000
Verticaldisplacement,ft
Actual
Proposal
Drop and turn 2per 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 usinga rotary steerable system to improve RO
and 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 remainderof 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
Trueverticaldepth,
m
Vertical section, m
Tie-in 8.5 418 measured depth
Build and turn 3.00per 30 m
75.71 1117 measured depth
Bekok A1
Bekok A1 ST
Hold angle 75.71
ActualProposal
-1800
-2400 -1800 -1200 -600 0
-1200
-600
0
Displacement(north/south),m
Displacement (east/west), m
Tie-inBekok A1
Bekok A1 ST
Kickoffpoint
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Overall, the PowerDrive assembly was used to
drill 420 ft [128 m] of cement and the shoe track
and formation from 11,660 to 14,427 ft [3554 to
4397 m]. This was achieved in 42 drilling hours at
an average penetration rate of 66 ft/hr [20 m/hr].
At 14,427 ft measured depth, it became
apparent that the rotary steerable system was no
longer receiving commands from the surface. The
tool continued to drill according to the last
command received, a low-side orientation that
induced a slight turn to the right. At this stage, it
was imperative to initiate a left-hand turn, and a
trip was required to retrieve the tool. Because
the nature of the failure was unknown initially,
and because the wellbore temperature was
approaching the temperature limits of the rotary
steerable assembly, a conventional steerable
motor was selected to finish drilling the interval.
Subsequent analysis confirmed that an elas-
tomer bearing had failed, allowing the turbine
power assembly to rotate eccentrically in the tool
collar. Wear inside the collar indicated that the
turbine fins were striking the inner collar wall,
preventing the tool from receiving new com-
mands. It was later determined that the mud had
degraded the bearing material. For future appli-
cations, an upgraded, more durable elastomer
has been developed, proven effective and is
now in use.
The results with a steerable motor on the fol-
lowing run provided an interesting comparison of
the efficiency of the two systems because the
same type of bit was run, the same formation
was drilled and similarly demanding directional
work was performed. Penetration rates achieved
while rotating with the conventional steerable
motor approached those of the PowerDrive sys-
tem. However, the extra time necessary to orient
the toolface, along with lower penetration rateswhile sliding, greatly increased overall drilling
times. 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 slower
than the PowerDrive system.
This example clearly demonstrates that
increased ROP offsets higher rig rates and more
than compensates for the additional expense of
the rotary steerable tool, resulting in overall time
and cost savings (left). This well was drilled 10
days ahead of plan. Nevertheless, further
improvement in rotary steerable drilling perfor-
mance remains a key objective for Schlumberger.
28 Oilfield Review
> Drilling efficiency improvements.Use of the PowerDrive systemcontributed 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
Measu
reddepth,
ft
Actual days
Risked plan days
Minimum plan days
Number of drilling days
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S i 2000 29
Driving into the Future
The ability of the PowerDrive rotary steerable sys-
tem to drill long sections quickly and reliably has
led to high demand for the 39 tools now available.
The manufacturing of 16 additional PowerDrive
tools during the first quarter of 2000 increased
worldwide access to these systems. The tools are
manufactured in the UK, but maintenance and
repairs are performed in several regional centers,
close to where the tools are used.
The PowerDrive675 system, the 634-in. tool
described in this article, is now proven tech-
nology (right). Schlumberger is working to set
new industry standards for rotary steerable
systems. The PowerDrive900, a 9-in. push-
the-bit tool designed to drill 1214-in. and larger
holes, is undergoing field trials at present,
with commercialization expected in the second
half 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 the
BHA, will fulfill demands for greater bit and sta-
bilizer selection, including bicenter bits, and
higher build rates. Schlumberger has tested a
prototype point-the-bit tool in various locations
worldwide and drilled upwards of 100 ft/hr
[30 m/hr].17 This prototype tool extends the flow
and temperature ranges of the push-the-bit
systems while maintaining a relatively compac
size. Survey data are gathered close to the bi
and sent to the surface for real-time trajectory
feedback and control. For each of these systemsthe goal is cost-effective drilling in mainstream
operations, rather than the current economic
restriction to only the most extreme applications
Operators certainly will continue to push the lim
its of reach and depth (left).
Further refinements in remote communication
links to operator offices will allow experts to
receive data, consult with rig personnel and send
back commands to the mud pumps, a critica
capability when drilling complex wells
Eventually, the shape of wellbores will be limited
only 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 reducedby 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
Trueverticaldepth,
ft
Displacement, ft
Shell Auger
BP Clyde
BP 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.
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