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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???
DE
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???
DE
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 )
M
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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
D
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p
t
h
(
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)
M
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d
D
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p
t
h
(
m
)
Off-btm TorqueCH=0.25, OH=0.30CH=0.20, OH=0.20
1
3
3
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1
4
.
7
5
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
M
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p
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(
f
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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
M
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D
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(
f
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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??