New Directions in RSS

8/10/2019 New Directions in RSS

1/12

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


2/12

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.


3/12

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.


4/12

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).


5/12

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.


6/12

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.


7/12

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.


8/12

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.

133/8-in.

N

2200

2000

1800

1600

1400

1200

1000

800

600

400

200

0

-500

-400

-300

-200

-100 0

100

200

300

400

500

600

700

800

900

1000

1100

1200

1300

1400

1500

2200

2000

1800

1600

1400

1200

1000

800

600

400

200

0

95/8in.

185/8-in.

-5

00

-40

0

-3

00

-2

00

-1

00 0

10

0

20

0

30

0

40

0

50

0

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


9/12

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.


10/12

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


11/12

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


12/12

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.

New Directions in RSS

Documents