04 hybrid rotary

8/12/2019 04 Hybrid Rotary

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36 Oilfield Review

The Best of Both WorldsA Hybrid RotarySteerable System

The transition from vertical to horizontal drilling has been spurred by evolving

technology that led the industry away from a dependency on conventional bottomhole

assemblies and whipstocks and toward mud motors and rotary steerable systems.

The latest innovation is a hybrid design that combines the performance capabilities of

a rotary steerable system with the high build rates of a positive displacement motor.

Edwin Felczak

Ariel Torre

Oklahoma City, Oklahoma, USA

Neil D. Godwin

Kate MantleSivaraman Naganathan

Stonehouse, England

Richard Hawkins

Ke Li

Sugar Land, Texas, USA

Stephen Jones

Katy, Texas

Fred Slayden

Houston, Texas

Oilfield ReviewWinter 2011/2012: 23, no. 4.Copyright 2012 Schlumberger.

For help in preparation of this article, thanks t o ElizabethHutton and Emmanuelle Regrain, Houston; and EdwardParkin, Stonehouse, England.

DOX, Drilling Office, IDEAS, PERFORM Toolkit, PowerDriveArcher, PowerDrive X5 and PowerPak are marks ofSchlumberger.

The shortest distance between two points is a

straight line. However, it may not be the fastest,

or most economical, when it comes to directional

drilling. E&P companies increasingly turn to

complex well trajectories to hit distant targets,

intersect fractures, penetrate multiple fault

blocks or reach deep into a reservoir. Although

more difficult to drill than other profiles, these

well paths often improve drainage efficiency by

increasing wellbore exposure to the pay zone.

Kickoffpoint

TD

PowerDriveArcherrotarysteerablesystemPositivedisplacementmotorConventionalrotarysteerablesystem

Landingpoint

Landingpoint TD

Kickoffpoint


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Winter 2011/2012 3737

Complex horizontal and extended-reach tra-

jectories are just the current apex in the evolu-

tion of directional drilling. The first nonvertical

wells were not intentionally drilled that way, but

by the late 1920s, drillers began to figure out how

to point a wellbore in a particular direction.

Since then, directional drilling technology has

progressed beyond a reliance on basic bottom-

hole assemblies for influencing the course a bit

might take, to using surface-controlled rotarysteerable systems that precisely guide the bit to

its ultimate destination. During the past decade,

the development of new drilling technologies has

continued to gain momentum.

This article describes advances that led to the

development of rotary steerable systems and

focuses on one of the latest steps in their evolution:

the PowerDrive Archer rotary steerable system.

This hybrid system produces the high build rate of a

positive displacement motor with the rapid rate of

penetration of a rotary steerable system.

A Brief History

The intentional deviation of wellbores came into

practice during the late 1920s as operators sought

to sidetrack around obstructions, drill relief wells

and avoid surface cultural features; directional

drilling techniques were even employed to keep

vertical holes from turning crooked.

In part, the ability to drill deviated wells

arose from the development of rotary drilling and

roller cone bits. The design of these bits causes

them to drift laterally, or walk, in response to

various formation and drilling parameters such

as formation dip and hardness, rotary speed,

weight on bit and cone design. In some regions,

experienced drillers recognized the natural ten-

dency of a bit to walk in a somewhat predictable

manner. They would frequently try to build a cer-tain amount of lead angle to compensate for

anticipated drift between the surface location

and bottomhole target (below left).

Drillers also found that modifications to the

rotary bottomhole assembly (BHA) could change

a drillstrings angle of inclination. By varying

stabilizer placement, drillers could affect the

balance of the BHA, prompting it to increase

maintain or decrease wellbore inclination from

vertical, commonly referred to as building, hold

ing or dropping angle, respectively. The rate a

which a rotary BHA builds or drops angle i

affected by variables such as distance between

stabilizers, drill collar diameter and stiffness, for

mation dip, rotary speed, weight on bit, formation

hardness and bit type. The ability to balance the

BHA against these factors can be crucial forreaching a planned target.

A BHA configured with a near-bit stabilize

beneath several drill collars will tend to build

angle when weight is applied to the bit (below)

In this configuration, the collars above the stabi

lizer will bend, while the near-bit stabilizer acts

as a fulcrum, pushing the bit toward the high side

>Lead angle, plan view. Rotary cone bits tend towalk to the right. Knowing this, drillers sometimesused a lead angle to orient the wellbore to the leftof the target azimuth.

Target azimuth

Surface location

S20E Lead line

Lead angle

Target

N

>Using a BHA to change inclination. By strategic placement of drill collarsand stabilizers in the BHA, directional drillers can increase or decreaseflexibility, or bowing, of the BHA. They use this flexibility to their advantage asthey seek to build, drop or hold angle. A fulcrum assembly (upper frame, top)uses a full gauge near-bit stabilizer and sometimes a string stabilizer. Bowingof the drill collars above the near-bit stabilizer tilts the bit upward to buildangle (lower frame, left). A pendulum assembly (upper frame, middle) hasone or more string stabilizers. The first string stabilizer acts as a pivot pointthat lets the BHA bow beneath it, thus dropping angle (lower frame, right). Apacked assembly uses one or two near-bit stabilizers and string stabilizers tostiffen the BHA (upper frame, bottom). By reducing the tendency to bow, thepacked assembly is used to hold angle.

Fulcrum assembly Pendulum assembly

Stabilizer

Near-bit stabilizer Bu

ilding

angle

Droppin

g

angle

Near-bit stabilizersFirst string stabilizerSecond string stabilizer

Near-bit stabilizerDrill collarFirst string stabilizer

Fulcrum (Angle-Building) Assembly

Packed (Angle-Holding) Assembly

Second string stabilizer

Bit

Pendulum (Angle-Dropping) Assembly

First string stabilizer


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38 Oilfield Review

of the borehole. Another type of BHA is used to

drop angle. This variation uses one or more stabi-

lizers; the collars below the lowest stabilizer in

the BHA act as a pendulum, which allows gravity

to pull the bit toward the low side of the bore-

hole. Upon reaching the desired angle, the driller

may use a different BHA to hold angle. The

packed BHA utilizes multiple stabilizers, spaced

along its length, to increase stiffness.

Drillers employ other mechanical means to

help divert a well from its vertical path, most

notably the whipstock. Simple in principle, this

long steel ramp is concave on one side to hold

and guide the drilling assembly. Used in either

open or cased holes, the whipstock is positioned

at the desired depth, oriented to the desired azi-

muth, then anchored in place to provide a guide

to initiate, or kick off, a new well path (above).

While early techniques allowed some degree ofcontrol over wellbore inclination, they provided little

azimuthal control. They were also inefficient, requir-

ing multiple trips in and out of the hole to install a

whipstock or to change BHA configurations.

The early 1960s witnessed a significant change

in directional drilling when a BHA with a fixed

bend of approximately 0.5 was paired with a

downhole motor to power the drill bit.1Drilling

mud supplied hydraulic power to a motor that

turned the bit.2The motor and bent sub offered

much greater directional control than was possi-

ble with earlier BHAs, while significantly increas-

ing the angle of curvature that a driller was able

to build. Early assemblies had fixed tilt angles

and required a trip out of the hole to adjust the

angle of inclination.

These steerable motors operate on the tilt-

angle principle. The bent sub provides the bit

offset needed to initiate and maintain changes incourse direction. Three geometric contact

pointsthe bit, a near-bit stabilizer on the motor

and a stabilizer above the motorapproximate

an arc that the well path will follow.3

Some motors use a downhole turbine; others

use a helical rotor and stator combination to

form a positive displacement motor (PDM). The

basic PDM with bent sub has evolved, leading to

the development of a steerable motor. Modern

steerable motor assemblies still use PDMs, but

include surface-adjustable bent housings (below

right). A typical steerable motor has a power-

generating section, through which drilling fluid is

pumped to turn a rotor that turns a drive shaft

and bit. The surface-adjustable bend can be set

between 0 and 4 to point the bit at an angle

that differs only slightly from the axis of the well-

bore; this seemingly minor deflection is critical

to the rate at which the driller can build angle.

The amount of wellbore curvature imparted by

the bent section depends, in part, on its angle,

the OD and length of the motor, stabilizer place-

ment and the size of drill collars relative to the

diameter of the hole.

Steerable motors drill in either of two modes:

rotary mode and oriented, or sliding, mode. In

rotary mode, the drilling rigs rotary table or its

topdrive rotates the entire drillstring to transmit

power to the bit. During sliding mode, the drill-

string does not rotate; instead, mud flow is

diverted to the downhole motor to power the bit.

Only the bit rotates in sliding modethe nonro-

tating portion of the drillstring simply follows

along behind the steering assembly.

Different motors may be selected on the basis

of their ability to build, hold or drop angle during

rotary mode drilling. Conventional practice is to

drill in rotary mode at a low number of revolu-tions per minute (RPM), rotating the drillstring

from the surface and causing the bend to point

equally in all directions, thereby drilling a

straight path. Inclination and azimuth measure-

ments can be obtained in real time by measure-

ment-while-drilling (MWD) tools to alert the

driller to any deviations from the intended

course. To correct for those deviations, the driller

must switch from rotary to sliding mode to

change wellbore trajectory.

The sliding mode is initiated by halting rota-

tion of the drillstring so the directional driller can

orient the bend in the downhole motor to point in

the direction, or toolface angle, of the desired tra-

jectory. This is no small task, given the torsional

forces that can cause the drillstring to behave like

a coiled spring.4 After accounting for bit torque,

drillstring windup and contact friction, the driller

must rotate the drillstring in small increments

from the surface while using MWD measurementsas a reference for toolface direction. Because a

drillstring can absorb torque over long intervals,

this process may require several rotations at the

surface to turn the tool just once downhole. When

the proper toolface orientation is confirmed, the

driller activates the downhole motor to com-

mence drilling in the prescribed direction. This

process may need to be repeated several times

during the course of drilling because reactive

torque that is generated as the bit cuts into the

rock may force reorientation of the toolface.

>Cased hole whipstock. This cylindrical steelramp (green) is run in the hole to a predeterminedkickoff depth and oriented azimuthally. A windowmill opens a hole in the casing, which is dressedby the watermelon mill. This assembly is thenpulled and replaced by a drilling BHA.

Casing

Cement

New borehole

Watermelonmill

Window mill

Cement plug

Whipstock

>Positive displacement motor. Downholemotors, such as this PowerPak steerable motor,provide much more directional control thanconventional BHAs.

Power section

Surface-adjustable

bent housing

Stabilizer

Bit


4/9

Winter 2011/2012 39

Each mode brings distinct challenges. In

rotating mode, the bend in the drilling assembly

causes the bit to rotate off-center from the BHA

axis, resulting in a slightly enlarged and spiral-

shaped borehole. This gives the wellbore rough

sides that increase torque and drag and may

cause problems while running in the hole with

completion equipmentespecially through long

lateral sections. Spiral boreholes may also affect

logging tool response.In sliding mode, the lack of rotation intro-

duces other difficulties. Where the drillstring

lies on the low side of the borehole, drilling fluid

flows unevenly around the pipe and impairs the

muds capacity to remove cuttings. This, in turn,

may result in the formation of a cuttings bed, or

a buildup of cuttings on the low side of the hole,

which increases the risk of stuck pipe. Sliding

also decreases the horsepower available to turn

the bit, which, combined with sliding friction,

decreases the rate of penetration (ROP) and

increases the likelihood of differential sticking.

In extended-reach trajectories, frictional

forces may build until there is insufficient axial

weight to overcome the drag imposed by drill-

pipe against the wellbore. This makes further

drilling impossible and leaves some targets out of

reach. Additionally, switching between sliding

and rotating modes can create undulations or

doglegs that increase wellbore tortuosity, thus

increasing friction while drilling and running

casing or completion equipment.5These undula-

tions may also create low spots, or sumps, where

fluid and debris collect, impeding flow after the

well is completed.

A number of these problems were addressed

in the late 1990s with the development of a rotary

steerable system (RSS). The single most impor-

tant aspect of the RSS is that it allows for

continuous rotation of the drillstring, thereby

eliminating the need to slide while drilling direc-

tionally. RSS tools provide a nearly instantaneous

response to commands from the surface when

the driller needs to change downhole trajectory.

Early on, these systems were utilized primarily to

drill extended-reach trajectories, in which the

ability to slide steerable motors had been limited

by hole drag. These jobs often resulted in

improved ROPs and hole quality over previous

systems (above). Today, the RSS is widely used for

its performance drilling, hole cleaning and accu-

rate geosteering capabilities.

Revolutionary Steerables

Rotary steerable systems have evolved consider-

ably since their introduction. Early versions uti-

lized mud-actuated pads or stabilizers to cause

changes in directiona design concept that con-

tinues to enjoy success to this day. With a depen-

dence on contact with the borehole wall for

directional control, the performance of these

tools can sometimes be affected by borehole

washouts and rugosity. Later versions included

designs that relied once again on a bend to pro

duce changes in toolface angle, thereby reducing

borehole environmental influences on tool per

formance.6 Thus, two steering concepts were

born: push-the-bit and point-the-bit.

The push-the-bit system pushes against the

borehole wall to steer the drillstring in the

desired direction. One version of this RSS uses a

bias unit with three actuator pads placed near

the bit to apply lateral force against the forma

tion (below). To build angle, each mud-actuated

pad pushes against the low side of the hole as i

1. McMillin K: Rotary Steerable Systems Creating Niche inExtended Reach Drilling, Offshore59, no. 2 (February1999): 52, 124.

2. Unlike conventional rotary drilling techniques, in whichrotation of the entire drillstring is required to drive the bit,the drillstring does not rotate when a mud motor isemployed. Instead, the mud motor relies on hydraulicpower supplied through the circulation of drilling mud toturn a shaft that drives the bit.

3. 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): 3247.

4. Downton G, Hendricks A, Klausen TS and Pafitis D:New Directions in Rotary Steerable Drilling,Oilfield Review12, no. 1 (Spring 2000): 1829.

5. A dogleg is an abrupt turn, bend or change of directionin a wellbore.

6. Schaaf S, Pafitis D and Guichemerre E: Application ofa Point the Bit Rotary Steerable System in DirectionalDrilling Prototype Wellbore Profiles, paper SPE 62519,presented at the SPE/AAPG Western Regional Meeting,Long Beach, California, USA, June 1923, 2000.

>Comparison of borehole quality. Caliper displays show how a positivedisplacement motor created a spiralled borehole (top), while the rotarysteerable system drilled a much smoother bore (bottom).

>Push-the-bit RSS. Pads extend dynamically from a rotating housing to create a side force directedagainst the formation, which in turn, causes a change in the drilling direction.

Stabilizer

Control unit Bias unit

Bit

Extended pad

When pads push againstthe high side, the bit

cuts toward the low side.

Extended pad


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40 Oilfield Review

rotates into position; to drop angle, each pad

pushes against the high side. Driller commands

sent downhole by mud pulse telemetry direct the

timing and magnitude of pad actuation. A control

unit positioned above the bias unit drives a

rotary valve that opens and closes the mud sup-

ply to the pads in concert with the drillstring

rotation. The system synchronously modulates

the extension and contact pressure of the actua-

tor pads as each pad passes a certain orientation

point. By applying hydraulic pressure each time

a pad passes a specific point, the pad forces the

drillstring away from that direction, thus moving

it in the desired direction.

A point-the-bit system uses an internal bendto offset the alignment between tool axis and

borehole axis to produce a directional response.7

In a point-the-bit system, the bend is contained

within the collar of the tool, immediately above

the bit (left). Point-the-bit systems change well

trajectory by changing the toolface angle. The

trajectory changes in the direction of the bend.

This bend orientation is controlled by a servomo-

tor that rotates at the same rate as the drillstring,

but counter to the drillstring rotation. This allows

the toolface orientation to remain geostationary,

or nonrotating, while the collar rotates.8

The latest development in the evolution of

these rotary steerablesthe PowerDrive Archer

high-build-rate RSSis a hybrid that combines

performance features of both push-the-bit and

point-the-bit systems (below).

The Hybrid RSS

Until recently, RSS assemblies were unable

to deliver well profiles as complex as those

drilled by steerable motor systems. However, the

PowerDrive Archer rotary steerable system dem-

onstrated its capability to attain high dogleg

severities (DLSs) while achieving ROPs typical of

rotary steerable systems.9Just as important, it is

a fully rotating systemall external tool compo-

nents rotate with the drillstring, enabling better

hole cleaning while reducing the risk of sticking.

Unlike some rotary steerables, the PowerDrive

Archer RSS does not rely on external moving

pads to push against the formation. Instead, four

actuator pistons within the drill collar push

against the inside of an articulated cylindrical

steering sleeve, which pivots on a universal joint

to point the bit in the desired direction. In addi-

tion, four stabilizer blades on the outer sleeve

above the universal joint provide side force to the

drill bit when they contact the borehole wall,enabling this RSS to perform like a push-the-bit

system. Because its moving components are

internalthus protected from interaction with

harsh drilling environmentsthis RSS has a

lower risk of tool malfunction or damage. This

design also helps extend RSS run life.

An internal valve, held geostationary with

respect to toolface, diverts a small percentage of

mud to the pistons. The mud actuates the pistons

that push against the steering sleeve. In neutral

mode, the mud valve rotates continuously, so bit

force is uniformly distributed along the borehole

wall, enabling the RSS to hold its course.10

Near-bit measurements, such as gamma ray,

inclination and azimuth, allow the operator to

closely monitor drilling progress. Current orien-

tation and other operating parameters are

relayed to the operator through a control unit,

which sends this information uphole via continu-

ous mud pulse telemetry. From the surface, the

directional driller sends commands downhole to

the control unit located above the steering unit.

These commands are translated into fluctuations

in mud flow rates. Each command has a unique

pattern of fluctuations that relate to discrete

points on a preset steering map, which has been

programmed into the tool prior to drilling.

Operators have been quick to capitalize on

the capabilities of the PowerDrive Archer steer-

>Point-the-bit RSS. A bit shaft is oriented at anoffset angle to the axis of the tool. This offsetis held geostationary by a counter-rotatingservomotor.

Power-generating

turbine

Motor

Sensor package

and control system

Bit

Mud flow

Bit shaft

>PowerDrive Archer rotary steerable system. This hybrid system combines actuator pads with an offset steering shaftall located inside the drill collar forprotection from the downhole environment.

Steering unit

Bias unit

Control unit

Internal geostationaryrotary valveStabilizer

blades

Internal universal joint Internal actuator pistonsStabilizer blades


6/9

Winter 2011/2012 41

ing system. Because it can drill the vertical,

curved and horizontal sections, it can attain com-

plex 3D trajectories and drill from one casing

shoe to the next in just one run.

Putting It to the Test

Until recently, steerable PDMs tended to domi-

nate the realm of high-dogleg drilling projects.

Despite their directional capabilities, drilling

with PDMs may consume a lot of rig time. Withthis approach, a conventional rotary BHA is typi-

cally used to drill the vertical section of the well.

Upon reaching the kickoff point (KOP), the

driller trips out of the hole to change the BHA. A

PDM is then installed, with a bent housing set to

the angle needed to drill the curve. After landing

the bit in the target formation, the driller again

trips out to dial down the angle of the adjustable

bent housing to a less aggressive build rate, then

trips back into the hole to drill the lateral sec-

tion. This process results in a good deal of flat

time, in which the bit is not on bottom and not

actively drilling.

Using the PowerDrive Archer RSS, an opera-

tor can drill the vertical, curved and lateral sec-

tions with a single BHA, thereby increasing

drilling efficiency, ROP and borehole quality.

And by circumventing the practice of alternating

between sliding and rotating modes, drilling

with the RSS achieves lower borehole tortuosity,

drag and friction caused by poor hole quality.

This permits drilling of longer lateral sections

that reach farther into the reservoir.

The PowerDrive Archer RSS has been used in

a wide range of environments, onshore and off,

from the US to the Middle East and Australia. The

high-build-rate capabilities first demonstrated in

shale plays are now used to help drillers maintain

trajectories through problematic unconsolidated

formations. Throughout a variety of plays, opera-

tors are beginning to appreciate the flexibility in

designing and revising well trajectories that this

hybrid RSS affords.

One such play, the Marcellus Shale in the

Appalachian basin of North America, spans an

area estimated to be approximately 3.5 times

larger than that of the Barnett Shale, which has

proved to be one of the most prolific sources ofunconventional gas in the US. The Devonian-age

Marcellus Shale contains an estimated 363 Tcf

[10.3 trillion m3] of recoverable gas. Ultra

Petroleum Corporation is engaged in exploration

and development of this play.11

In the past, operators completed Marcellus

wells using vertical boreholes, which provided

comparatively little exposure of the source

rock to the wellbore. However, horizontal drilling

technology has significantly changed the eco-

nomics of gas production in the Marcellus play,

with horizontal wells drilled from multiwell pads

and completed with multistage fracture stimula-

tion of the lateral section. Operators frequently

used air to drill the vertical section, then

switched to mud drilling upon reaching the KOP.

After setting 95/8-in. casing, they kicked off an

83/4-in. hole, building angle with a PDM before

landing the well within the Marcellus interval. To

drill the curved and lateral sections, a PDM

might drill for 90% or more of the interval in slid-

ing mode. This approach has several drawbacks,

including lower ROP, poor hole cleaning and tor-

tuous well pathsand often required trips out of

the hole to adjust the bent housing when geologic

uncertainties forced well path corrections.

Drilling in this play can involve complex 3Dwell profiles, high curvature rates and direction-

ally challenging formation dips that affect DLS.

Ultra Petroleum recognized the potential for

such problems in a recent project and selected

the PowerDrive Archer RSS to meet these chal-

lenges, drill the wells quickly and place them in

the productive zones of the formation. In 2010,

Ultra began an aggressive drilling campaign,

having identified numerous targets within this

play. The company drilled the first Marcellus

well using a steerable PDM to establish a bench

mark. The next 10 wells were drilled using the

PowerDrive Archer RSS. Some of these wells

were kicked off from vertical with a long turn in

azimuth of 90 or more to line up with the target

while simultaneously building angle at rates up

to 8/100 ft [8/30 m]. Geologic uncertainties

near the landing point sometimes called for cor

rective action, often requiring higher build

rates (above).

7. Bryan S, Cox J, Blackwell D, Slayden F andNaganathan S: High Dogleg Rotary Steerable System:A Step Change in Drilling Process, paper SPE 124498,presented at the SPE Annual Technical Conference andExhibition, New Orleans, October 47, 2009.

8. Al-Yami HE, Kubaisi AA, Nawaz K, Awan A, Verma J andGanda S: Powered Rotary Steerable Systems Offera Step Change in Drilling Performance, paperSPE 115491, presented at the SPE Asia Pacific Oil andGas Conference and Exhibition, Perth, WesternAustralia, Australia, October 2022, 2008.

9. A dogleg is typically quantified in terms of doglegseverity, which is measured in degrees per unit ofdistance.

10. Bryan et al, reference 7.

11. Auflick R, Slayden F and Naganathan S: NewTechnology Delivers Results in Unconventional ShalePlay, presented at the Mediterranean OffshoreConference and Exhibition, Alexandria, Egypt,May 1820, 2010.

>Three-dimensional trajectory. In this Marcellus Shale well, the operator used the PowerDrive ArcherRSS to kick off from vertical, drill a 3D curve with more than 100 change in azimuth, then hold thetangent section. Uncertainty in the geologic model forced the operator to change the landing point bymore than 70 ft [21 m]. Once the geologic marker was identified, the RSS quickly built angle to 16/100 ft[16/30 m] to reach the target, then the operator switched to a 2 build rate to a create a soft landingwithin the reservoir section.

Reservoirsection

Kickoffpoint

TD

Landingpoint

Tangentsection

Chan

geinazimuth


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42 Oilfield Review

With one exception, the wells drilled subse-

quent to the benchmark PDM well realized sig-

nificant savings in rig time. In addition, all

completion strings were run without incident.

The hybrid RSS was also able to reach farther

into the target section, resulting in more than a

twofold increase in production rates.

A different resource play has been receiving

attention in central Oklahoma, USA, where

Cimarex Energy Company has been drilling the

Woodford Shale. Cimarex selected PathFinder, a

Schlumberger company, to utilize the PowerDrive

Archer RSS in drilling the curve section of the

companys Kappus 1-22H well. Using this RSS to

drill the 83/4-in. hole with an 8/100 ft build rate,

the operator achieved an 80% increase in ROP

over that of previous wells drilled with PDMs.

Having attained a smooth wellbore through the

curve, the operator was able to switch to a

PowerDrive X5 RSS, which drilled a 4,545-ft[1,385-m] lateral section to TD in just one run. A

fast ROP through the curve, combined with high

build rate and smooth drilling operations in the

lateral section resulted in a savings of 10 drilling

days (left).

The high-build-rate capability of this hybrid

RSS makes for a shorter curved section, enabling

operators to design trajectories with deeper

KOPs. A deep KOP lets the operator expand the

length of the vertical section, which typically

drills faster than the curved section. An operator

in the Middle East used the PowerDrive Archer

RSS to drill an 8 1/2-in. curve section for 846 ft

[258 m] at a build rate of 7.6/100 ft [7.6/30 m].

After meeting the objectives for this well, the

operator selected the same system to drill a sec-

ond well.

The second well required a more aggressive

build rate, but in carrying out this plan, the oper-

ator was able to boost overall ROP by drilling

through a longer vertical section before kicking

off, which enabled a rapid ROP through the verti-

cal section. After drilling the 12 1/4-in. section, the

operator set casing and kicked off the 81/2-in. sec-

tion. The hybrid RSS consistently maintained an

11/100-ft [11/30-m] DLS and drilled the 742-ft

[226-m] interval in a single run of 15 hours (left).

The well was landed within 1 ft [0.3 m] vertically

and 3.8 ft [1.2 m] laterally of its intended target.

Because the 81/2-in. section was shortened, the

operator also saved nearly 700 ft [210 m] of liner.

Pushing the kickoff point deeper sharpened the

curve, which reduced the amount of drilled foot-

age needed to reach the reservoir and allowed

drilling engineers to consider downsizing the cas-

ing strings to achieve further savings.12

In northwest Arkansas, USA, SEECO, a

wholly owned subsidiary of SouthwesternEnergy Company, tested the performance of the

PowerDrive Archer system as it drilled the verti-

cal, curved and lateral sections of an Atoka

Formation well. The vertical section was drilled,

>Time versus depth curve. To drill the Kappus 1-22H well in the WoodfordShale, Cimarex used the PowerDrive Archer system. The operator was able

to drill to TD in 49 days instead of 59, saving 10 days of drilling time against theprojected time frame.

5,000

0

15,000

20,000

10,000

604020

Time, days

0

Depth,

ft

Plan

As drilled

>Shortened curve. The PowerDrive Archer RSS achieved an 11/100 ft build rate that allowed theoperator to extend the vertical section of the trajectory while shortening the curve to reduce drilling

time and the amount of liner required.

Conventionalkickoffpoint

Conventionaltrajectory

PowerDriveArcher

kickoffpoint

PowerDriveArcher

trajectory

12. Eltayeb M, Heydari MR, Nasrumminallah M, Bugni M,Edwards JE, Frigui M, Nadjeh I and Al Habsy H: DrillingOptimization Using New Directional Drilling Technology,paper SPE/IADC 148462, presented at the SPE/IADCMiddle East Drilling Technology Conference andExhibition, Muscat, Oman, October 2426, 2011.


8/9

Winter 2011/2012 43

then the well was kicked off along the planned

azimuth. The driller built angle at 10/100 ft

[10/30 m] DLS before making a soft landing at

the desired target point with an 88.2 inclina-

tion. Using an automated inclination hold fea-

ture, the RSS drilled ahead, with inclination

maintained within 0.5 of the planned trajec-

tory. After drilling for about 1,000 ft [305 m], the

directional driller nudged the well path upward

to follow the general dip of the reservoir, withthe RSS building inclination up to 92 before an

unexpected fault created an abrupt lateral ter-

mination of the reservoir (right).

Planning for Success

The success of PowerDrive Archer steering tech-

nology can be attributed largely to extensive

planning, modeling and testing. BHA design and

modeling of bit and BHA response go into each

PowerDrive Archer job.

As a first step, Schlumberger drilling engi-

neers obtain offset well information from the

operator and focus on drilling issues and bit per-

formance data. Engineers use DOX Drilling Office

integrated software to design a trajectory to land

within the designated target zone while optimiz-

ing drilling efficiency. This software package

integrates trajectory design with drillstring spec-

ifications and BHA design, hydraulics, torque and

drag. The DOX software lets drilling engineers

quickly run multiple scenarios to optimize the

well path. A well plan and equipment plan are

then formulated to reach the given target, taking

into account known drilling issues. Anticollision

modeling ensures that the proposed trajectory

will avoid nearby wells.

Hole quality is a critical issue in high DLS or

extended-reach wells; poor hole quality may

impact the success of a well by hampering

efforts to deploy drilling and completion equip-

ment through tight curves and may limit the

footage that can be drilled through the lateral

section. Extensive testing has played an impor-

tant role in developing capabilities to deliver

high-quality boreholes. One such test involved a

series of blocks, each with a different compres-

sive strength. These test blocks were arranged

side by side to form a rectangle nearly 45 m[150 ft] long. The PowerDrive Archer RSS

drilled through the blocks using various combi-

nations of bits and power settings to simulate

downhole drilling conditions. Once the holes

were drilled, a laser caliper measured the bore-

hole gauge in each block and consistently found

no borehole rugosity (right).

>Two-dimensional curve and lateral section. SEECO developed two drilling scenarios to accommodateuncertainties in Atoka Formation dip. The actual well path (red) differs from the two plannedtrajectories. Geosteering LWD sensors proved the dip to lie between those assumed in the two plans.Faulting terminated the reservoir and shortened the lateral section considerably. (Adapted from Bryanet al, reference 7.)

2,500

2,000

3,000

0 500 1,000 1,500

Lateral section, ft

Original plan

As drilled

Pilot hole

Revised plan

2,000 2,500 3,000

True

verticaldep

th,

ft

>Smooth drilling through test blocks. Laser calipers revealed no borehole rugosity in the borehole drilledby the PowerDrive Archer RSS (bottom). (Photographs courtesy of Edward Parkin, Stonehouse, England.


9/9

44 Oilfield Review

Although modeling of BHA and bit response

has been notoriously difficult, recent advances

make it possible to analyze dynamic downhole

drilling conditions and compute drillstring

stresses. The forces generated by the bit and

their effects on BHA steering performance canalso be predicted. This is followed by laboratory

testing and, finally, field testing to deliver opti-

mized BHA and bit designs.

Schlumberger performed finite element anal-

ysis and bending moment modeling and analysis

on components of the PowerDrive Archer BHA

(left). Field testing validated BHA behavior to

ensure steerability at high build rates. After the

BHA design was finalized, engineers conducted

shock and vibration analysis to identify critical

resonance frequencies and RPMs to be avoided

while drilling. Torque and drag simulations for

drilling and tripping operations were run toensure BHA integrity. Hydraulics modeling was

also conducted across various mud weight and

flow ranges.

Drillbit technology is another factor that is

vital to the success of any well. The bit affects

drilling efficiency, or the ability to achieve and

maintain a high average ROP. Bit design also

impacts steerability, or the ability to place the

well in the right part of the reservoir. Push-the-

bit systems generally require an aggressive side-

cutting bit for delivering doglegs, while

point-the-bit systems tend to rely on stabiliza-

tion from a less aggressive bit with a longer side

gauge. With a hybrid system, using the right bit is

especially critical. For this RSS, engineers con-

ducted extensive testing to characterize interac-

tions between the bit, tools and formation to

best match the bit profile to the tools and maxi-

mize performance.

Bits for the PowerDrive Archer system can be

tailored to enhance steerability and deliver

improved ROP for a particular field. The IDEAS

integrated drillbit design platform lets drilling

engineers optimize bit selection based on model-

ing the drilling system overall.13The IDEAS soft-

ware accounts for a wide range of variables in its

bit design and BHA optimization packages:

rock type and formation characteristics

interaction between bit cutter surface and

rock face

contact between drillstring and wellbore

detailed bottomhole assembly design

casing program

well trajectory

drilling parameters.

Modeling data were also used as input to a

fatigue management system that predicts fatigue

life for each component of the BHA. When sub-jected to rotation through high doglegs, BHAs

will experience large bending moments. Fatigue

life decreases exponentially with increasing

build rate and can reduce the life of standard

BHA components to a matter of hours. Fatigue

modeling and tracking is helping drillers avoid

twist offs and other catastrophic failures.

Schlumberger tracks fatigue life automati-

cally to ensure integrity of BHA components.

With the aid of PERFORM Toolkit data optimiza-

tion and analysis software, the wellsite engineer

can record RPM, ROP, DLS and other contribu-

tors to fatigue, providing real-time fatigue man-

agement information and predictions of fatigue

life. Monitoring fatigue life is not a trivial task:

The position of each component along the well

path must be tracked and the bending momentcaused by DLSalong with RPM and time

needs to be quantified. Tracking fatigue in real

time, including time off-bottom rotating, can sig-

nificantly improve the accuracy of the fatigue life

estimates. These fatigue data may be monitored

remotely at operations support centers, where

the data can be reviewed by drilling experts who

can advise operators when critical components

need to be replaced.

Advances in directional drilling technology

are helping operators access hydrocarbons that

could not otherwise be produced. The latest gen-

eration of rotary steerables is achieving well tra-

jectories and step-outs that were previously

unimaginable, while delivering lower cost and

lower risk wells and improving production. These

increasingly complex well trajectories are spur-

ring the industry to reach further in the search

for new reserves. MV>Tool joint stress contours. Drillstring tool jointconnections are subjected to a variety of loadsthat affect the fatigue life of a tool. In particular,tool joints are subjected to torque as they aremade up on the drill floor, when the pin is screwedinto the box (inset). This is followed later bybending moments as the curve section is drilled.

Finite element analysis can be used to predictstress along a threaded connection by accountingfor the torque and bending moments expected oneach job. This plot indicates higher von Misesstress in the pin than in the box when thethreaded connection is made up and subjected toa bending moment. This information is useful inpredicting the fatigue life of the connection.

1.184 105

1.036 105

8.880 104

7.400 104

5.920 104

4.440 104

2.960 104

1.480 104

1.257 104

von Mises stress,

psi

Pin Box

Pin

Box

13. The IDEAS program was developed in the 1990s bySmith Bits, which was later acquired by Schlumberger.For more on bit design using the IDEAS system:Centala P, Challa V, Durairajan B, Meehan R, Paez L,Partin U, Segal S, Wu S, Garrett I, Teggart B andTetley N: Bit DesignTop to Bottom,Oilfield Review23, no. 2 (Summer 2011): 417.

04 hybrid rotary

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