New Directions in Rotary Steerable Drilling
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.
Geoff Downton
Stonehouse, England
Trond Skei Klausen
Norsk Hydro
Kristiansund, Norway
Andy Hendricks
Mount Pearl, Newfoundland, Canada
Demos Pafitis
Sugar Land, Texas, USA
For help in preparation of this article, thanks to Vince
Abbott, New Orleans, Louisiana, USA; Julian Coles,
Kristiansund, Norway; Greg Conran, Barry Cross, Ian
Falconer, Jeff Hamer, Wade McCutcheon, Eric Olson,
Charlie Pratten, Keith Rappold, Stuart Schaaf and Deb
Smith, Sugar Land, Texas, USA; Torjer Halle and Paul Wand,
Stavanger, Norway; Randy Strong, Houston, Texas; Mike
Williams, Aberdeen, Scotland; and Miriam Woodfine,
Mount Pearl, Newfoundland, Canada.
ADN (Azimuthal Density Neutron), CDR (Compensated Dual
Resistivity), InterACT Web Witness, PowerDrive, PowerPak
and PowerPulse are marks of Schlumberger.
18
Certain situations require advanced drilling technology (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 particular well might improve if a well penetrated multiple 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 be
produced economically if directional wells are
located skillfully.
Operators drill extended-reach wells to reservoirs 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 standard practice offshore for years and is now common in restricted onshore locations, like rain
forests, for environmental protection. There are
also instances in which the operator wants to
drill 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
Oilfield Review
> Directional inclinations. Surface obstructions or subsurface geological anomalies might preclude drilling a straight hole. Reservoir drainage can be optimized
by drilling an inclined wellbore. In an emergency, such as a blowout, a directional relief well reduces subsurface pressure in a controlled manner.
In rare emergency situations, directionaldrilling 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 construct 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 directional 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
1. For an example of mastering subsalt directional drilling
challenges: Cromb JR, Pratten CG, Long M and Walters RA:
“Deepwater Subsalt Development: Directional Drilling
Challenges 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 and
Kühr M: “The KTB Borehole—Germany’s Superdeep
Telescope into the Earth’s Crust,” Oilfield Review 7, no. 1
(January 1995): 4-22.
3. Barbeauld RO: “Directional Drilling Overcomes
Obstacles, Protects Environment,” Pipeline & Gas
Journal 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 advanced
drilling technology: Djerfi Z, Haugen J, Andreassen E and
Tjotta H: “Statoil Applies Rotary Steerable Technology
for 3-D Reservoir Drilling,” Petroleum Engineer
International 72, no. 2 (February 1999): 29, 32-34.
Spring 2000
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 expensive 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 steering the well and eliminate the troublesome
sliding mode of conventional steerable motors.
The results have been dramatic: The PowerDrive
rotary steerable system contributed to the drilling
of the world’s 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.
19
Build assembly
Evolution of Directional Drilling Technology
There have been astonishing advances in drilling
technology since the primitive cable-tool techniques 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 surveying systems and other downhole devices.
Improvements in drilling safety have accompanied 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 replacing spinning chains. Bigger and better drilling rigs
handle loads more securely. Kick-detection software and use of devices that detect annular pressure changes help improve hole cleaning and
retain well control.7 These and other advancements in modern drilling operations have reduced
accidents and injuries substantially.
The first patent for a turbodrill, a type of downhole 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 reserves
illegally. 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 continue to push the limits of directional-drilling technology, resulting in the combination of rotary and
steerable drilling systems now available.
6. For more on the likely origins of drilling techniques and
oil and gas industry history: Yergin D: The Prize: The Epic
Quest 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: “Using
Downhole Annular Pressure Measurements to Improve
Drilling Performance,” Oilfield Review 10, no. 4 (Winter
1998): 40-55.
For more on drilling risk: Aldred W, Plumb D, Bradford I,
Cook J, Gholkar V, Cousins L, Minton R, Fuller J, Goraya S
and Tucker D: “Managing Drilling Risk,” Oilfield Review
11, no. 2 (Summer 1999): 2-19.
20
Pendulum or drop assembly
> Changing direction without a downhole motor. Careful placement of stabilizers and drill collars
allow 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 intermediate
structure determine whether the assembly will build or drop.
Determining the inclination of a wellbore was a
key problem in directional drilling until accurate
measuring devices were invented. Directional surveys provide at least three vital pieces of information: 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 sophisticated 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.
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 in
Multilateral Technology,” Oilfield Review 10, no. 4
(Winter 1998): 14-28.
9. McMillin K: “Rotary Steerable Systems Creating Niche in
Extended Reach Drilling,” Offshore 59, no. 2 (February
1999): 52, 124.
10. For several general articles about stuck pipe:
Oilfield Review 3, no. 4 (October 1991).
11. Mims M: “Directional Drilling Performance
Improvement,” World Oil 220, no. 5 (May 1999): 40-43.
Modern measurements-while-drilling (MWD)
systems send directional survey information to surface by mud-pulse telemetry—survey measurements are transmitted as pressure pulses in the
drilling fluid and decoded at surface while drilling
is in progress. In addition to direction and inclination, 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, that
offer the driller control over the wellbore trajectory.
Before the development of leading-edge steerable 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 predictable manner.
Oilfield Review
Steerable motors, which use a downhole turbine or PDM to generate power and a BHA with
a fixed bend of approximately 1⁄ 2°, were developed in the early 1960s to allow simultaneous
control of wellbore azimuth and inclination.9
Today, a typical steerable motor assembly consists 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 technology has performed admirably, it requires great
finesse to correctly orient the bend in the motor
because of the torsional compliance of the drillstring, 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 horsepower available to turn the bit, which, combined
with sliding friction, decreases the rate of penetration (ROP). Eventually, in extreme extendedreach drilling projects, frictional forces during
sliding build to the point that there is insufficient
axial weight to overcome the drag of the
drillpipe against the wellbore, and further
drilling is not possible.
Finally, slide drilling typically introduces several 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-adjustable
bent housing
Bearing section and
stabilizer
> Steerable BHA. This simple yet rugged
PowerPak steerable assembly consists of a
power-generating section, a surface-adjustable
bent housing, a stabilizer and the drill bit.
Spring 2000
> Optimizing trajectory. Directional drilling in the sliding and rotating modes typically results in
a more irregular and longer path than planned (red trajectory). Doglegs can affect the ability to
run casing to total depth. The use of a rotary steerable system eliminates the sliding mode and
produces a smoother wellbore (black trajectory).
21
Gas
Oil
Power generating
turbine
Water
Collar rotation
Sensor package
and control system
> Optimizing flow during production. The high and low spots in the undulating wellbore (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.
Motor rotation
Motor
Applied force
Drilling tendency
> Rotary steerable system designs characterized
by their steady-state behavior. In point-the-bit
systems (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 the
desired trajectory.
Turbine
numerous undulations or doglegs in the wellbore
increase wellbore tortuosity, which in turn
increases apparent friction while drilling and running casing. During production, gas may accumulate in the high spots and water in the low spots,
choking production (above). Despite these challenges, 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 technology, 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-bit” systems, including the
PowerDrive system, and the less mature “pointthe-bit” systems (left).
Control electronics
Control unit
How Does a Rotary Steerable System Work?
The PowerDrive system is mechanically uncomplicated and compact, comprising a bias unit and
a control unit that add only 121⁄2 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 drillstring rotates. The control unit, which resides
behind the bias unit, contains self-powered electronics, sensors and a control mechanism to
provide 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
Turbine
Steering actuator pad
Bias unit
> The PowerDrive rotary steerable system.
22
Oilfield Review
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 point—the
point opposite the desired trajectory—in 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 approximately 3⁄8 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 geostationary 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 that
the pads push in all directions and effectively
“cancel” each other.
The control unit maintains the proper angular
position of the input shaft relative to the formation. The control unit is mounted on bearings that
allow it to rotate freely about the axis of the drillstring. 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 control 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
12. For additional details about the workings of the
PowerDrive tool: Clegg JM and Downton GC: “The
Remote Control of a Rotary Steerable Drilling System,”
presented at the British Nuclear Energy Society
Conference on Remote Techniques for Hazardous
Environments, 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 to
Drill Extended Reach Wells,” paper IADC/SPE 39327,
presented at the 1998 IADC/SPE Drilling Conference,
Dallas, Texas, USA, March 3-6, 1998.
Spring 2000
Control shaft
Disk valve
Actuator
Right turn
> Pushing the bit. Mud flow through a three-way disk valve actuates three external pads (top). The pads
push 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 the
bottom show the tool with the pads retracted (left) and extended (right).
upper impeller, or torquer, is used to torque the
platform in the same direction as drillstring rotation, 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 instructions 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 threeaxis accelerometer or by the magnetometer triad
mounted 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 provide the steering reference.
One of the many benefits of using a roll-stabilized platform to determine the steering direction is its insensitivity to drillstring stick-slip
behavior. Additional sensors in the control unit
record the instantaneous speed of the drillstring
with respect to the formation, thereby providing
useful data about drillstring behavior. Shock
and thermal sensors are also carried by the control unit to record additional information about
downhole conditions. Information about drilling
conditions is continuously sampled and logged by
the onboard computer for immediate transmission to surface by the MWD system or for later
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.
23
Rotating the drillstring improves hole cleaning dramatically, minimizes the risk of stuck pipe,
and facilitates directional control. The power at
the bit is not compromised by the need to perform slide drilling operations. Directional control
can be maintained beyond the point where
torque and drag make sliding with a motor ineffective. The benefits of increased ROP compared
with a traditional sliding assembly are realized
when using the PowerDrive system.
4°/100 ft
no real-time communications
4°/100 ft
real-time communications
Short-hop probe
PPIcommunications
interface sub
Flex
collar
Stabilizer
8°/100 ft
real-time communications
Control unit
collar
Bias unit
> 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 realtime communications using a flex collar when a higher build rate is required (bottom).
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 outset, rather than working in sequence using an
incomplete knowledge base. Given a certain surface location and a desired subsurface target,
the directional planner must assess cost,
required accuracy and geological and technical
factors to determine the appropriate wellbore
profile—slant, S-shaped, horizontal or perhaps
a more exotic shape. Drilling into another wellbore, 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 system, minimizes the risk of stuck pipe and allows
backreaming 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
24
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 when
aggressive drill bits are used.14 Directional control with a PDM and an aggressive bit can be difficult 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.
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 Wells
in the Next Millennium,” Oilfield Review 10, no. 4
(Winter 1998): 2-13.
14. A full discussion of bit selection is beyond the scope of
this article, but will be addressed in an upcoming
Oilfield Review article. For this discussion, an aggressive bit is one that has been designed to drill quickly
using long cutters that produce large cuttings. Less
aggressive bits have shorter teeth that produce smaller
cuttings by grinding. Other issues that affect bit function
include rotary speed, weight on bit, torque, flow rate
and the nature of the formation being drilled.
PowerDrive Systems in High Gear
Since its first commercial run in 1996, the
PowerDrive tool has demonstrated that elimination of sliding while directionally drilling
dramatically increases the overall rate of penetration. 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 section 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 connectivity. 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, hydrocarbon-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.
15. For more on data delivery, including the InterACT Web
Witness 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 production
operations in the Wytch Farm field: Algeroy J, Morris
AJ, Stracke M, Auzerais F, Bryant I, Raghuraman B,
Rathnasingham R, Davies J, Gai H, Johannessen O,
Malde O, Toekje J and Newberry P: “Controlling
Reservoirs 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.
Oilfield Review
2100
Actual
Vertical depth, m
Proposal
3100
Vertical section, m at 227.26°
500
2700
< A-13-H well path. The W-shaped well
intersected the Tilje reservoir in four
separate fault blocks (top). Other well
configurations used in the area, such as
fishhook-shaped wells, would have
penetrated only two fault blocks (bottom).
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 geologically 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 operations 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 seekand-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
2200
2200
2000
system cost $1 million less than the previous well
in the field because it cut well construction time
by half. Use of PDC bits with the PowerDrive tool
more than doubled ROP.
Rotary steerable systems open up new horizons for well planning, reservoir management and
even field development. Rotary steerable systems
mean that fewer wells are drilled, but those that
are drilled penetrate more targets. By intersecting
four fault blocks rather than two, the A-13-H well
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 of
the Njord field as a whole because of the flexibility of the system. It has allowed access to reserves
that would have been considered uneconomic
with 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 inclination (below).
9 5/8 in.
2000
9 5/8-in.
1800
1800
1600
1600
5
18 /8-in.
Distance, m
1400
1400
1200
1200
1000
1000
800
800
600
133/8-in.
600
400
400
200
N
200
N
-500
-400
-300
-200
-100
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
-500
-400
-300
-200
-100
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
0
0
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 record
for 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 threedimensional view (right) illustrates the high inclination that accompanied the turn. Use of the PowerDrive tool saved seven days of rig time.
Spring 2000
25
Bekok A7
480
320
160
KOP
360 MD 358 TVD
17.7° 347.43° az
23N 7W
-160
-320
Ho
ld a
zim
uth
198
.93
°
Displacement (north/south), m
0
-480
Bekok A7 ST
-640
-800
-960
-1120
7-in. liner
-1280
-720
-560
-400
-240
Displacement (east/west), m
-80
80
0
160
320
KOP
360 MD 358 TVD
17.7° 347.43° az
-19 departure
True vertical depth, m
480
640
800
Build and turn 3.00° per 30 m
960
Bekok A7
1120
1280
Bekok A7 ST
1440
1600
1760
7-in. liner 2190 MD 1692 TVD 69.2° 198.5° az 1369 departure
Hold angle 69.35°
TD 8.5-in. section 2600 MD 1696 TVD 69.2° 198.5° az 1369 departure
-480 -320 -160
0
160
320
480
640
800
960
1120 1280 1440
Vertical section, m
Proposal
Actual
26
> Plan view (top) and section view (bottom) of the
Bekok A7 ST planned well trajectory, shown in blue,
and the actual trajectory, shown in red.
Maximizing the cost-effectiveness of expensive directional wells with complex trajectories
is a major challenge facing drilling engineers.
Success depends on drilling tools that offer inherent 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 five
days of rig time, while the best motor performance, 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 81⁄2-in.
[21.6-cm] landing section of the well, cutting
three days from the scheduled drilling program
(next page, top left). Rates of penetration were
300% higher than those experienced with
conventional assemblies in offset wells, with
correspondingly fewer wiper trips. Minimal tortuosity, 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 application of a rotary steerable tool by a major operator
in the Gulf of Mexico. The operator’s goal in
selecting the PowerDrive system was to save rig
time 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 eliminate expensive and time-consuming stuck-pipe
problems caused by expanding shales—a frequent occurrence in the area—and allow tighter
control on the equivalent circulating density of
the drilling mud. Use of the rotary system would
Oilfield Review
RIH with PowerDrive tool
Bekok A1
1050
Kickoff
point
1100
Vertical displacement, ft
Displacement (north/south), m
0
Tie-in
Bekok A1 ST
-600
-1200
Drop and turn 2° per 100 ft
35.14° 13,448 ft MD
1150
1200
POOH with
PowerDrive
tool
1250
1300
1350
-1800
-2400
-1800
-1200
-600
Displacement (east/west), m
1400
0
4500
5000
5500
6000
Departure from vertical, ft
0
-4000
800
-3750
-3500
-3250
-3000
-3000
Build and turn 3.00° per 30 m
75.71° 1117 measured depth
RIH with PowerDrive tool
-3250
Hold angle 75.71°
1200
Bekok A1 ST
1600
Bekok A1
2000
0
400
800
1200
1600
2000
2400
2800
Vertical section, m
Proposal
Actual
> Plan view (top) and section view (bottom) of
the Bekok A1 ST planned well trajectory, shown
in blue, and the actual trajectory, shown in red.
Displacement (north/south), ft
True vertical depth, m
Displacement (east/west), ft
Tie-in 8.5° 418 measured depth
400
-3500
-3750
-4000
Drop and turn
2° per 100 ft
-4250
POOH with PowerDrive tool
-4500
-4750
-5000
ensure that cuttings were held in suspension at
all times, overcoming settling problems associated with sliding during PDM operations.
The PowerDrive system was used to drill out
from the 9 5⁄8-in. [24.4-cm] casing shoe at 11,660 ft
[3554 m]. After a formation integrity test was
performed, 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
Spring 2000
dropping and turning left through two geometrically 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. The
small 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 previous motor runs, promoting improved hole cleaning and faster rates of penetration. Hole-cleaning
efficiency was monitored using an annular pressure sensor in the MWD string so that the hole
could be cleaned as quickly as it could be drilled.
Proposal
Actual
> Rotary steerable drilling in the Gulf of
Mexico. A development well in a field in
the Viosca Knoll area was drilled using
a rotary steerable system to improve ROP
and hole cleaning. The proposed trajectory is shown in blue. The PowerDrive
tool achieved the desired trajectory, as
shown in red in the vertical section view
(top) and plan view (bottom). The rotary
steerable tool was removed after drilling
2767 ft and a PDM drilled the remainder
of the hole at a rate that was two and
one-half times slower.
27
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.
0
2000
4000
Measured depth, ft
6000
8000
10,000
Subsequent analysis confirmed that an elastomer 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 commands. It was later determined that the mud had
degraded the bearing material. For future applications, an upgraded, more durable elastomer
has been developed, proven effective and is
now in use.
The results with a steerable motor on the following 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 system. However, the extra time necessary to orient
the toolface, along with lower penetration rates
while 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 performance remains a key objective for Schlumberger.
17. Schaaf S, Pafitis D and Guichemerre E: “Application of a
Point the Bit Rotary Steerable System in Directional
Drilling Prototype Well-bore Profiles,” paper SPE 62519,
prepared for presentation at the 2000 SPE/AAPG
Western Regional Meeting, Long Beach, California,
USA, June 19-23, 2000.
12,000
14,000
16,000
18,000
0
20
40
60
80
Number of drilling days
Risked plan days
Actual days
Minimum plan days
28
> Drilling efficiency improvements.
Use of the PowerDrive system
contributed to drilling the Viosca
Knoll development well 10 days
ahead of plan.
Oilfield Review
Driving into the Future
The ability of the PowerDrive rotary steerable system 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 63⁄4-in. tool
described in this article, is now proven technology (right). Schlumberger is working to set
new industry standards for rotary steerable
systems. The PowerDrive900, a 9-in. pushthe-bit tool designed to drill 121⁄4-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 trajectory is determined by the bit direction rather
than the orientation of a longer section of the
BHA, will fulfill demands for greater bit and stabilizer 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
Steady deviation
controlled by downhole motor,
independent of bit torque. Problems
of controlling toolface through
elastic drillstring are avoided.
Continuous rotation
while steering
Cleaner hole
effect of high inclination is offset
by continuous pipe rotation
Smooth hole
tortuosity of wellbore is reduced
by better steering
Less drag
improves control of WOB
Less risk of
stuck pipe
Longer
horizontal
range
in reservoir with
good steering
Longer extended reach
without excessive drag
Time savings
drill faster while steering and
reduce wiper trips
Fewer wells
to exploit a
reservoir
Fewer platforms
to develop a field
Lower cost per foot
Completion
cost is reduced
and
workover
is made easier
Lower cost per barrel
> Benefits of the PowerDrive system. Continuous rotation of the drillstring improves many
aspects of well construction and ultimately translates into saving time and money.
Displacement, ft
0
0
5000
10,000
15,000
20,000
25,000
30,000
Total Austral
5000
BP M-14
10,000
True vertical depth, ft
35,000
Amoco Brintnell 2-10
Maersk, Qatar
BP Clyde
BP M-11
40,000
BP Amoco
M-16Z
Total Austral
CN-1
Statoil Sleipner Phillips
Zijiang
BP Gyda
15,000
2:1
Ratio
20,000
Shell Auger
25,000
30,000
35,000
5:1
Ratio
systems while maintaining a relatively compact
size. Survey data are gathered close to the bit
and sent to the surface for real-time trajectory
feedback and control. For each of these systems,
the 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 limits 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 critical
capability when drilling complex wells.
Eventually, the shape of wellbores will be limited
only by economics and ingenuity.
—GMG
1:1 Ratio
> Extending the envelope. Reach of 10 km [6.2 miles] or more is possible at relatively shallow
depths. Displacement becomes restricted with increasing depth, as shown by the purple envelope.
Spring 2000
29