CASING Torque & Drag

At the end of this module you will be able to:

Explain and define Side Forces

Explain and define Friction Factor

Objectives

Understand causes of Torque and Drag

Build a Broomstick Plot

Understand the mechanisms to reduce Torque and Drag

Torque and Drag Uses Define rig equipment requirements Determine drillability of the well Optimize the trajectory and BHA / drill string /bit design Simulate drilling and completion (casing) runs Identify problem areas Identify problem areas Determine circumstances for sticking events Establish mud program needs Evaluate the effectiveness of hole cleaning actions Determining reaming, backreaming and short trip

requirements

Torque and Drag Modeling

To understand computer modeling two keypoints must be understood:

Model (Representation) noun(C):a representation of something, either as a physical objectwhich is usually smaller than the real object, or as a simpledescription of the object which might be used in calculations.

Garbage In = Garbage Out

Components Of

CASING

Components Of Torque & DragSideForces & Friction

The Weight Component of Side Force

incl

weight

Building Section

Sidewall Forces Tension and DLS

tensile

resultant

tensile

tensileload

tensile

resultant

Dropping Section

tensileloadweight

load

weight

resultant

tensileload

tensile weight

resultant

Sidewall Forces Tension and DLS*

Wall force with pipe tension and DLS:

TLDLS pi31018

=

TLDLSSF pi

Sidewall Forces Tension and DLS

Wall force with pipe tension and DLS:

DE

DLS:

Wear => Casing, Drill string components

Sideforce Components

Wn

T

FC

Wn

Wn

FBFB

Wn : side weight = linear weight x sin( inclination )

T

curvature side forceFC = T x string curvature

FCFC

Wn

FB FB

FB : bending side force(zero in soft string model)

Total Side Force = -Wn + FC + FB

Side Forces - Worst Case Scenario???

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Exercise

Exercise:

Example:Calculate the wall force across a 30 section of 5/100 DLS considering a tension of 100,000 lbs below the DL.

ftlbfSF 30/91.26171018

1000003053 =

=

pi

ftTLSFDLS 100/05.2

18000031200010181018 033

=

=

=

pipi

KOP of 1500' and a build up to 30 inclination. Our TD is10,000'. The drillstring tension at 1500' when we are drilling atTD could be around 180,000 lbs. If the average length of a jointof drillpipe is 31' and if we want to limit our side force to 2,000lbs per joint of drillpipe what is the maximum DLS can be used?

The Stiffness Component of Side Force

5 drill pipe3 1/2 drill pipe

16 deg/100ft22 deg/100ft

When does stiffness start to become a factor?

Stiffness BHA as a Hollow CylinderStiffness Coefficient = E x Iwhere:E = Youngs Modulus (lb/in2)I = Moment of Inertia (in4)

DE

I = Moment of Inertia (in )Moment of Inertia I = p (OD4 - ID4) 64

OD = outside diameter ID = inside diameter

Stiffness BHA as a Hollow CylinderWhich one is more stiff?

DE

Drill Collar? Drill Pipe?Casing?Liner?

The Buckling Component of SideForce

FbFb

Fb

Fb

Fb

String is in compression

Sinusoidal & Helical Buckling

DE

DE

Buckling - Worst Case Scenario???

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Dawson-Pasley Buckling Criteria

r

WKIEF BCRsin2 =

(lbs) load buckling sinusoidal Critical =F

DE

(in) hole andjoint toolpipebetween clearance Radial r (lbs/in)air in ht Unit weigW

)(inch inertia ofMoment (unitless)factor Buoyancy

Modulus sYoung' (deg)interest ofpoint at the hole theofn Inclinatio

(lbs) load buckling sinusoidal Critical

4

=

=

=

=

=

=

=

I

KE

F

B

CR

Guidelines for Analyzing Buckling Problems

Sinusoidal buckling is an indication of the onset of fatigue wear. Classical Sinusoidal buckling is defined by Dawson & Pasley 82

(SPE 11167) with references to Lubinski in 62. Modified Sinusoidal buckling defined by Schuh in 91 (SPE

21942) and is used in Drilling Office.Helical buckling generally results in side force loads.Helical buckling generally results in side force loads. Helical buckling defined by Mitchell (SPE 15470) and Kwon (SPE

14729) in 86.Generally Helical buckling should be considered at compressional

loads 2 times those calculated for Sinusoidal buckling

SummaryFour Components of Side Force

Weight always a consideration, light drill pipe in Horizontal wells

Tensile more pronounced with high tension and high dog legs

Stiffness negligible effect with dog legs less than 15 deg/100ft

Buckling high compressional loads with neutral point significantlyabove the bit (near surface)

Stiff vs. Soft String ModelSoft String Stiff String Drill string always in

contact with the borehole Contact area, curvature

side forces are

Drill string curvature canbe different than wellbore

Contact areas arereduced, more realisticside forces are

overestimatedreduced, more realisticside forces

More accurate torque losscalculation in a lowinclination wellbore

Borehole/Drill string contact

HIGH TORTUOSITY WELLS(local DLS >> well curvature)

Three main components of side force Side weight Curvature side force Bending side force

T T

Wn

STIFF& SOFT STRING / BOREHOLE CONTACT

LOW TORTUOSITY WELLS(local DLS

Something Additional!!Tortuosity in Planned TrajectoriesWhy add tortuosity to plans?

Account for more than Ideal T&D numbers Allows more consistent results between different

engineers

DE

engineers Account for drilling system used

Recommended Values (no offset data) Vertical, tangent sections 0.75/100ftperiod Build, drop sections 1.5/100ft period Turn only sections 1.0/100ft period

Friction

It is the resistance to motion that exists when a solid object is moved tangentially with respect to another which it touches.

W

Motion Friction

Coefficient Of Friction and Critical angle

The frictional drag force is proportional to the normal force. The coefficient of friction is independent of the apparent area

of contact

When does the Pipe Stop Moving?

Tan -1 (1/FF) = Inclination

Effect of Friction (no doglegs)

Effect of Friction (no doglegs)(a) Lowering: Friction opposes motion, so

IsinWIcosWT

FIcosWT f

=

=

IsinWIcosWT =

(b) Raising: Friction still opposes motion

IsinWIcosWT

FIcosWT f

+=

+=

Exercise 1

What is the maximum hole angle (inclination angle) that can be logged without the aid of drillpipe, coiled tubing, other tubulars or sinker bars? (assume FF = 0.4)

Friction Factors

In reality, Friction Factor (FF) used in modeling is not a true sliding coefficient of friction. It acts as a correlation coefficient that lumps together the friction forces caused by various effects, including friction.

Typically the FF will depend on a combination of effects including:

Formation Mud type Roughness of Support Tortuosity Borehole Condition

Friction Factors - RotationRotating Sliding

Sliding Velocity

Sliding FrictionVectorRPM Vector

Backreaming Friction Vector

Sliding Velocity (ROP)Drilling Friction

Vector

Backreaming friction factor from weight loss/overpull while drill string is rotating 0

Friction FactorsAre a function of the materials involved (pipe to formation

or pipe to casing) and the lubricity of the fluid (mud) between them

Water basedmud

0.0 0.1 0.2 0.3 0.4 0.5 0.6

mud

Oil basedmud

(40% reduction)Rotational .22 - .28 .13 - .17Translation .03 - .07 .02 - .05Sliding (not rotating).28 - .40 --.55 .17 - .25 -- .33

CASING

StressA point within a body under loading can be subjected to

FOUR possible types of stresses:

NORMAL STRESS, BENDING STRESS,

DE

BENDING STRESS, SHEAR STRESS, TORSIONAL STRESS

The magnitude of these stresses is dependent on the loading conditions of the body of interest.

Normal StressNormal Stress is the intensity of the net forces acting normal(perpendicular) to an infinitely small area A within an objectper unit area.

If the normal stress acting on A pulls on it, then it is referred toas tensile stress,

DE

as tensile stress,If it pushes on the area, it is called compressive stress.

Bending Stress

Bending Stress

RDE

b 2

=

(*)

DE

E = Youngs Modulus (psi)D = Diameter of the Tubular (inches)R = Radius of Curvature (inches) SPE 37353

Drill-Pipe Bending and Fatigue in Rotary Drilling of Horizontal Wells - Jiang Wu

(*)

(*)

Shear Stress

Shear Stress is the intensity of force per unit area, acting tangent to A.

If the supports are considered rigid, and P is large enough, the material of the bar will deform and fail along the planes AB and

DE

material of the bar will deform and fail along the planes AB and CD.

x

SF

L

Torsional Stress

6 psi 1012 steel, of ModulusShear

72 re Whe6

or

12

G

LNJGQ

JQd

LNdG

==

=

pi

pi

DE

L

Modulus) (Shear

GAF

StrainShearStressShear S

==

( ) 444

6

inch ; 32

inertia, ofmoment Polar J

inches pipe, theofdiameter Internal dft string, Drillpipe ofLength L

ft.lb DP, the toapplied Torque Qrev string, pipe drill in the turnsofNumber N

psi 1012 steel, of ModulusShear

dD

G

pi

Richard Von Mises

( ) ( )( ) 22 3 torsionalbendingaxial ++=Von MisesStress

DE

Axial, Bending and Torsional Stresses combined Total Stress of the drillstring component [psi]

CASING

Torque & DragDefinitions & Monitoring

Torque LossesAre defined as the difference between the torque applied at the rig floor and the torque generated at the bit. Also referred to as rotating friction.

Drag losses

Torque and Drag - Definition

Drag lossesIt is the difference between the static weight of the drillstring and the weight under movement. Also referred to as sliding friction.

drag = sideforce x friction factor torque = sideforce x friction factor x radius

Overpull / Slack-Off

Torque

Torque and Drag Monitoring Why Track hole condition and deterioration Determine hole cleaning efficiency Evaluate cuttings bed formation Determine limitation of equipment and maximum achievable depths Determine mud lubricity effects Determine effects of mud weight and mud property changes Build a friction factor database Understand problems encountered when running casing/liners Optimize string configurations and BHA and need for torque reducers

Parameters to monitor

Hookloads Picking Up

at least 5-6 meters with a constant speed

Slacking Off

T r i p p i n g H o o k l o a d s0

1 ,0 0 0

2 ,0 0 0

3 ,0 0 0

4 ,0 0 0

5 ,0 0 0

6 ,0 0 0

7 ,0 0 0

8 ,0 0 0

9 ,0 0 0

1 0 ,0 0 0

C S G 0 .4 0 O P H 0 .4 0 T r ip in

C S G 0 .2 0 O P H 0 .2 0 T r ip inC S G 0 .0 0 O P H 0 .0 0

C S G 0 .2 0 O P H 0 .2 0 T r ip o u tC S G 0 .4 0 O P H 0 .4 0 T r ip o u t

IN C L

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A total of 4 measurements required to monitor T&D

Slacking Off at least 5-6 meters

movement with a constant speed

Rotating off bottom at least 1-2 meters

off bottomTorque

Off bottom torque @ rotary speed

1 1 ,0 0 0

1 2 ,0 0 0

1 3 ,0 0 0

1 4 ,0 0 0

1 5 ,0 0 0

1 6 ,0 0 0

1 7 ,0 0 0

1 8 ,0 0 0

1 9 ,0 0 0

2 0 ,0 0 0

2 1 ,0 0 0

2 2 ,0 0 0

2 3 ,0 0 0

2 4 ,0 0 0

2 5 ,0 0 00 5 0 1 0 0 1 5 0 2 0 0 2 5 0 3 0 0 3 5 0 4 0 0 4 5 0 5 0 0 5 5 0

H o o k lo a d ( k lb s )

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T IH H o o k lo a d s

F F = 0 .0

P O H H o o k lo a d s

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Torque and Drag Monitoring When

At every connection While tripping in/out Prior to drilling out/going back into open hole After major inclination and azimuth changes Before, during and after wiper trips Before, during and after wiper trips Before and after circulating bottoms up and pumping sweeps After a mud type change and major mud proprieties change Before and after additions of torque reducers At TD before and after hole has been cleaned In case of running casing, monitor drag values every 3-5 joints

Torque and Drag Monitoring After drilling down each connection,

reciprocate the stand with good circulation and rotation to ensure good hole cleaning and any cuttings are clear of the BHA and to determine if the hole is free (situation may be different for different rigs/company procedures, so at each connection, pump/ream the last stand as necessary and as per

100

0

200

300

stand as necessary and as per instructions, for each hole size, angle, formation type, etc).

Martin Decker

200

0

400

600

A few meters off bottom, obtain rotating string weight and torque at drilling RPM and flow rate. If the T&D modeling is done correctly, this weight should be on top of the FF=0 line

Martin Decker

T r i p p i n g H o o k l o a d s0

1 , 0 0 0

2 , 0 0 0

3 , 0 0 0

C S G 0 . 4 0 O P H 0 . 4 0 T r i p i n

C S G 0 . 2 0 O P H 0 . 2 0 T r i p i n

C S G 0 . 0 0 O P H 0 . 0 0

C S G 0 . 2 0 O P H 0 . 2 0 T r i p o u t

C S G 0 . 4 0 O P H 0 . 4 0 T r i p o u t

Torque and Drag Monitoring

2-3 m

4 , 0 0 0

5 , 0 0 0

6 , 0 0 0

7 , 0 0 0

8 , 0 0 0

9 , 0 0 0

1 0 , 0 0 0

1 1 , 0 0 0

1 2 , 0 0 0

1 3 , 0 0 0

1 4 , 0 0 0

1 5 , 0 0 0

1 6 , 0 0 0

1 7 , 0 0 0

1 8 , 0 0 0

1 9 , 0 0 0

2 0 , 0 0 0

2 1 , 0 0 0

2 2 , 0 0 0

2 3 , 0 0 0

2 4 , 0 0 0

2 5 , 0 0 00 5 0 1 0 0 1 5 0 2 0 0 2 5 0 3 0 0 3 5 0 4 0 0 4 5 0 5 0 0 5 5 0

H o o k l o a d ( k l b s )

M

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D

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p

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(

f

t

)

C S G 0 . 4 0 O P H 0 . 4 0 T r i p o u t

I N C L

T I H H o o k l o a d s

F F = 0 . 0

P O H H o o k l o a d s

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Drilling Torque FF Calibration0

100

200

5000

0

10000

15000

A few meters off bottom, obtain rotating string weight and torque at drilling RPM and flow rate. If the T&D modeling is done correctly, this weight should be on top of the FF=0 line

Torque Gauge

Torque and Drag Monitoring

300

400

500

600

700

800

900

1,000

1,100

1,200

1,300

1,400

1,500

1,600

1,700

1,800

1,900

2,000

2,100

2,200

2,300

2,400

2,500

2,6000 5 10 15 20

Torque (kft-lbs)

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(

m

)

Off-btm TorqueCH=0.25, OH=0.30CH=0.20, OH=0.20

1

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1

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7

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Note: Added 1.5K needed to turn top-drive.

2-3 m

200

0

400

600

Stop rotary and obtain pick up (P/U) weight on up pipe movement, at least 5-6 meters, record both maximum PU weight and normal PU weight . (Static and dynamic frictions)Martin Decker

T r i p p i n g H o o k l o a d s0

1 , 0 0 0

2 , 0 0 0

C S G 0 . 4 0 O P H 0 . 4 0 T r i p i n

C S G 0 . 2 0 O P H 0 . 2 0 T r i p i n

C S G 0 . 0 0 O P H 0 . 0 0

C S G 0 . 2 0 O P H 0 . 2 0 T r i p o u t

Torque and Drag Monitoring

2-3 m

3 , 0 0 0

4 , 0 0 0

5 , 0 0 0

6 , 0 0 0

7 , 0 0 0

8 , 0 0 0

9 , 0 0 0

1 0 , 0 0 0

1 1 , 0 0 0

1 2 , 0 0 0

1 3 , 0 0 0

1 4 , 0 0 0

1 5 , 0 0 0

1 6 , 0 0 0

1 7 , 0 0 0

1 8 , 0 0 0

1 9 , 0 0 0

2 0 , 0 0 0

2 1 , 0 0 0

2 2 , 0 0 0

2 3 , 0 0 0

2 4 , 0 0 0

2 5 , 0 0 00 5 0 1 0 0 1 5 0 2 0 0 2 5 0 3 0 0 3 5 0 4 0 0 4 5 0 5 0 0 5 5 0

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C S G 0 . 2 0 O P H 0 . 2 0 T r i p o u t

C S G 0 . 4 0 O P H 0 . 4 0 T r i p o u t

I N C L

T I H H o o k l o a d s

F F = 0 . 0

P O H H o o k l o a d s

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5-6 m

200

0

400

600

Obtain the slack off (S/O) weight on the down movement of the pipe while returning the pipe 5-6 meters to bottom. Record both minimum slack off and normal slack off weights.

Martin Decker

T r i p p i n g H o o k l o a d s0

1 , 0 0 0

2 , 0 0 0

C S G 0 . 4 0 O P H 0 . 4 0 T r i p i n

C S G 0 . 2 0 O P H 0 . 2 0 T r i p i n

C S G 0 . 0 0 O P H 0 . 0 0

Torque and Drag Monitoring

2-3 m

2 , 0 0 0

3 , 0 0 0

4 , 0 0 0

5 , 0 0 0

6 , 0 0 0

7 , 0 0 0

8 , 0 0 0

9 , 0 0 0

1 0 , 0 0 0

1 1 , 0 0 0

1 2 , 0 0 0

1 3 , 0 0 0

1 4 , 0 0 0

1 5 , 0 0 0

1 6 , 0 0 0

1 7 , 0 0 0

1 8 , 0 0 0

1 9 , 0 0 0

2 0 , 0 0 0

2 1 , 0 0 0

2 2 , 0 0 0

2 3 , 0 0 0

2 4 , 0 0 0

2 5 , 0 0 0

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C S G 0 . 2 0 O P H 0 . 2 0 T r i p o u t

C S G 0 . 4 0 O P H 0 . 4 0 T r i p o u t

I N C L

T I H H o o k l o a d s

F F = 0 . 0

P O H H o o k l o a d s

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5-6 m

Torque and Drag Monitoring How Moving the drill string at the same speed Take the least affected, steady weight indicator reading Turn pumps off and take P/U and S/O weights and repeat

previous steps above, before the connection Take the circulating readings at the same flow rate (for each

hole section) to avoid the potential influence/interference of hydraulic lift. hole section) to avoid the potential influence/interference of hydraulic lift.

While tripping out, just obtain the pick-up weights. Obtain the slack-off weights while running in.

Pumps on readings can be used to estimate maximum depth achievable while drilling

For running casing/liner, get the S/O weights while running.

Typical Hookload Behavior (POOH)Picking up off the slips, maximum hookload (this represents the static friction factor). This will help us monitor if we are getting closer to rig limits limits Steady hookload while moving the drill string up (This represents the dynamic friction factor). This hookloadneeds to be used in the T&D charts

Hook Position

Torque & Drag

CASING

Torque & DragExamplesHole Condition

Monitoring

Poor Hole Cleaning Example6,000

7,000

8,000

9,000

10,000

11,000

12,000Me

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12 Tangent Section

LWD Gamma Ray Curve

13,000

14,000

15,000

16,000

17,000

18,000

19,000

20,000

21,000175 200 225 250 275 300 325 350 375 400 425 450 475 500 525

Hookloads (klbs)

Slack-Off Wt. Rotating Wt.

Pick/Up Wt.

1

2

1

/

4

O

H

Gamma Ray

Pick-up hookloadsindicating poor hole cleaning in tangent section

Poor Hole Cleaning- Advanced 67 degrees Break-outsRig with Pump Pressure

Limitations

HC problems

Short Trip

30% FF deterioration

Casing Running - Good

Casing Running - Poor

Gamma ray

Increasing drag running 9 5/8 casing due to hanging 5/8 casing due to hanging in ledges in wellbore

Hookload remaining constant while running in hole, indicating increase drag. Casing becomes stuck off-bottom at 15,100 feet.

Drag improves once circulation is established to clean hole

Torque & Drag

CASING

Torque & DragManagement

Further Considerations

Drillstring Design SectionsSection

TypeFunction Desired

CharacteristicsDesired

ConsiderationsI BHA Directional

ControlStiff, Light

WeightMinimize T&D

II DP Transfer Weight

Stiff, Light Weight

Minimize T&D,Adequate buckling

resistance

III DP orHWDP

TransferWeight

Stiff, Light Weight

Minimize T&D,Increased buckling

resistance

IV HWDP Transfer / Provide Weight

Stiff, Moderate Weight

Increased buckling resistance

V HWDP or DC

Provide Weight

Concentrated Weight

Transition component

VI DP Support Weight

High Tensile and Torsional Limits

Provide adequatetensile and torsional

margins

Managing Torque and DragTorque Reduction

Well Trajectory Cased Hole Open Hole Mud Lubricity Lubricating Beads Use of LCM

Drag Optimization Well Profile Mud Lubricity Drill pipe protectors Buckling Effects Weight Distribution Use of LCM

Torque reducers

Well path considerations Trajectory Bottom hole

Assemblies Optimum Profile

Weight Distribution Hole Cleaning Down hole Motors Rotation Steerable Rotary Systems

General Guidelines for T&D Optimization String design can help overcome existing drag Place heaviest Drill String Components in the vertical hole section Keep tortuosity and doglegs to a minimum (Optimization of well

trajectory) Use rotary steerable system if feasible Use torque reducing subs where side forces are the highest Ensure proper hole cleaning. Lubricants can be used to effectively reduce Torque and Drag

temporarily. Run Torque and Drag simulations at several key depths, not just at TD to

monitor hole cleaning Torque and Drag are caused by lateral forces and friction in the wellbore BHAs should be designed to achieve the desired build/turn tendencies

with the maximum amount of rotary drilling. Bit torque should be monitored

Torque & Drag Reduction

Questions??