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Torque & Drag CASING
Objectives At the end of this module you will be able to:
Explain and define Side Forces Explain and define Friction Factor 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 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 key points must be understood: Model (Representation) – noun(C): a representation of something, either as a physical object which is usually smaller than the real object, or as a simple description of the object which might be used in calculations.
Garbage In = Garbage Out
Components Of Torque & Drag CASING SideForce’s & Friction
The Weight Component of Side Force
incl
weight
Sidewall Forces – Tension and DLS Building Section tensile
tensile
resultant
tensile load
resultant
weight weight
Dropping Section
tensile
resultant
weight
tensile load
tensile load
Sidewall Forces – Tension and DLS*
Wall force with pipe tension and DLS:
DLS × π × L × T SF = 18 × 10 3
Sidewall Forces – Tension and DLS Wall force with pipe tension and DLS: Wear => Casing, Drill string components DE
Sideforce Components Wn : side weight = linear weight x sin( inclination )
Wn
Wn
FB
FB
T Wn
FC FC
FB
curvature side force
FB : bending side force (zero in soft string model)
FC = T x string curvature
T Total Side Force = -Wn + FC + FB
FB
Side Forces - Worst Case Scenario???
DE
Exercise Example: Calculate the wall force across a 30’ section of 5°/100’ DLS considering a tension of 100,000 lbs below the DL. SF =
Exercise:
5 × π × 30 ×100000 = 2617.91lbf / 30 ft 18 ×103
KOP of 1500' and a build up to 30° inclination. Our TD is 10,000'. The drillstring tension at 1500' when we are drilling at TD could be around 180,000 lbs. If the average length of a t of drillpipe is 31' and if we want to limit our side force to 2,000 lbs per t of drillpipe what is the maximum DLS can be used? 18 × 103 × SF 18 × 103 × 2000 DLS = = = 2.050 / 100 ft π × L ×T π × 31×180000
The Stiffness Component of Side Force
When does stiffness start to become a factor? 5” drill pipe 16 deg/100ft 3 1/2” drill pipe 22 deg/100ft
Stiffness – BHA as a Hollow Cylinder Stiffness Coefficient = E xI where: E = Young’s Modulus (lb/in2) I = Moment of Inertia (in4) Moment of Inertia I = p (OD4 - ID4) ÷ 64 OD = outside diameter ID = inside diameter DE
Stiffness – BHA as a Hollow Cylinder Which one is more stiff?
Drill Collar?
DE
Drill Pipe? Casing? Liner?
The Buckling Component of SideForce Fb Fb Fb
String is in compression
Fb
Sinusoidal & Helical Buckling
DE
DE
Buckling - Worst Case Scenario???
DE
Dawson-Pasley Buckling Criteria
FCR
E × I × K B × W × sin θ = 2× r
FCR = Critical sinusoidal buckling load (lbs)
θ
= Inclination of the hole at the point of interest (deg) E = Young' s Modulus K B = Buoyancy factor (unitless) I
= Moment of inertia (inch 4 )
W = Unit weight in air (lbs/in) r = Radial clearance between pipe tool t and hole (in)
DE
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 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
Summary Four Components of Side Force Weight
always a consideration, light drill pipe in Horizontal wells
Tensile
more pronounced with high tension and high dog legs negligible effect with dog legs less than 15 deg/100ft high compressional loads with neutral point significantly above the bit (near surface)
Stiffness Buckling
Stiff vs. Soft String Model Soft String Stiff String Drill string always in Drill string curvature can with the borehole be different than wellbore area, curvature areas are side forces are reduced, more realistic overestimated side forces More accurate torque loss calculation in a low inclination wellbore
Borehole/Drill string LOW TORTUOSITY WELLS (local DLS << well curvature)
Three main components of
Wn
side force Side weight Curvature side force Bending side force
T
STIFF & SOFT STRINGTORTUOSITY / BOREHOLE HIGH WELLS
T
(local DLS >> well curvature)
Wn
Wn
Stiff- and soft-string models
T
SOFTSTRING/ BOREHOLE
give the same result for an untortuous plan
Wn Wn
T STIFFSTRING/ BOREHOLE
T
T : axial load, Wn : component of drillstring weight perpendicular to borehole axis
T
Something Additional!! Tortuosity in Planned Trajectories Why add tortuosity to plans? for more than “Ideal” T&D numbers Allows more consistent results between different
engineers for drilling system used
Recommended Values (no offset data)
DE
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.
Friction
Motion W
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
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
∆T = W cos I − Ff ∆T = W cos I − µW sin I (b) Raising: Friction still opposes motion ∆T = W cos I + Ff
∆T = W cos I + µW sin I
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 Tortuosity Borehole Condition
Friction Factors - Rotation Rotating
Sliding
Backreaming Friction Vector
RPM Vector Drilling Friction Vector Backreaming friction factor from weight loss/overpull while drill string is rotating 0<µ<0.05 Drilling Friction from torque loss while drill string is rotating 0.1< µ <0.3
Sliding Friction Vector Sliding Velocity (ROP)
Sliding Friction Factor from weight loss/overpull while drill string is not rotating 0.1< µ <0.3
Friction Factors Are a function of the materials involved (pipe to formation or pipe to casing) and the lubricity of the fluid (mud) between them 0.0
0.1
0.2
0.3
0.4
0.5
0.6
Water based mud Oil based mud (40% reduction)
Rotational .22 - .28 Translation .03 - .07 Sliding (not rotating).28 - .40 --.55
.13 - .17 .02 - .05 .17 - .25 -- .33
CASING
Stress A point within a body under loading can be subjected to FOUR possible types of stresses:
NORMAL STRESS, BENDING STRESS, SHEAR STRESS, TORSIONAL STRESS
The magnitude of these stresses is dependent on the loading conditions of the body of interest.
DE
Normal Stress Normal Stress is the intensity of the net forces acting normal (perpendicular) to an infinitely small area A within an object per unit area. If the normal stress acting on A pulls on it, then it is referred to as tensile stress, If it pushes on the area, it is called compressive stress.
DE
Bending Stress Bending Stress
σ
b
=
E ×D 2R
(*)
E = Young’s 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
DE
Shear Stress Shear Stress is the intensity of force per unit area, acting tangent to A. If the s are considered rigid, and P is large enough, the material of the bar will deform and fail along the planes AB and CD.
DE
Torsional Stress στ =
FS ∆x
π ×G×d × N 12 × L or
στ = 6 × d ×
L
θ
Q J
Where Q =
π ×G × J × N 72 × L
G → Shear Modulus of steel, 12 ×106 psi N → Number of turns in the drill pipe string, rev Q → Torque applied to the DP, ft.lb L → Length of Drillpipe string, ft d → Internal diameter of the pipe, inches J → Polar moment of inertia,
FS Shear Stress A = G (Shear Modulus) = Shear Strain θ
DE
π 32
(
)
× D 4 − d 4 ; inch 4
Richard Von Mises Von Mises Stress
=
((σ ) + (σ axial
))
2
bending
+ 3σ
2 torsional
Axial, Bending and Torsional Stresses combined Total Stress of the drillstring component [psi]
DE
Torque & Drag CASING Definitions & Monitoring
Torque and Drag - Definition Torque Losses Are 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 It 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 A total of 4 measurements required to monitor T&D T r ip p in g H o o k lo a d s 0 C S G 0 . 4 0 O P H 0 . 4 0 T r ip in 1 ,0 0 0
C S G 0 . 2 0 O P H 0 . 2 0 T r ip in
2 ,0 0 0
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 ip o u t
3 ,0 0 0
C S G 0 . 4 0 O P H 0 . 4 0 T r ip o u t IN C L
4 ,0 0 0 5 ,0 0 0 6 ,0 0 0 7 ,0 0 0
9 ,0 0 0 1 0 ,0 0 0 1 1 ,0 0 0 1 2 ,0 0 0
Inclination
9 5/8" Casing String
8 ,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
T IH H o o k lo a d s
8.5
Measured Depth (ft)
Hookloads Picking Up at least 5-6 meters with a constant speed Slacking Off at least 5-6 meters movement with a constant speed Rotating off bottom at least 1-2 meters off bottom Torque Off bottom torque @ rotary speed
2 2 ,0 0 0
P O H H o o k lo a d s
2 3 ,0 0 0
F F = 0 .0 2 4 ,0 0 0 2 5 ,0 0 0 0
50
100
150
200
250
300
H o o k lo a d (k lb s )
350
400
450
500
550
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 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 ts
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 instructions, for each hole size, angle, formation type, etc). 200
100
Martin Decker
0
300
Torque and Drag Monitoring A few meters off bottom,
400
Martin Decker
600
T r ip p in g H o o k lo a d s 0
0
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 ip in
C S G
0 .2 0 O P H
0 . 2 0 T r ip in
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 ip o u t
C S G
0 .4 0 O P H
0 . 4 0 T r ip o u t
IN C L
4 ,0 0 0 5 ,0 0 0 6 ,0 0 0 7 ,0 0 0
9 ,0 0 0 1 0 ,0 0 0 1 1 ,0 0 0 1 2 ,0 0 0
Inclination
9 5/8" Casing String
8 ,0 0 0
Measured Depth (ft)
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
2-3 m
1 9 ,0 0 0 2 0 ,0 0 0 2 1 ,0 0 0
T IH
8.5
200
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
2 2 ,0 0 0
H o o k lo a d s
P O H
H o o k lo a d s
2 3 ,0 0 0
F F = 0 .0 2 4 ,0 0 0 2 5 ,0 0 0 0
5 0
1 0 0
1 5 0
2 0 0
2 5 0
3 0 0
H o o k lo a d (k lb s )
3 5 0
4 0 0
4 5 0
5 0 0
5 5 0
Torque and Drag Monitoring A few meters off bottom,
10000
Torque Gauge
0
0 100
Drilling Torque FF Calibration
200 Off-btm Torque
300
CH=0.25, OH=0.30
400 133/8"C asing
CH=0.20, OH=0.20
500 600 700
Note: Added 1.5K needed to turn top-drive.
800 900 1,000 M easuredD epth(m )
1,100 1,200 1,300 1,400 1,500 1,600 1,700 1,800
14.75
5000
obtain rotating string weight and torque at drilling RPM and flow rate. If the T&D 15000 modeling is done correctly, this weight should be on top of the FF=0 line
1,900 2,000
2-3 m
2,100 2,200 2,300 2,400 2,500 2,600 0
5
10 Torque (kft-lbs)
15
20
Torque and Drag Monitoring Stop rotary and obtain pick up
400
Martin Decker
T r ip p in g H o o k lo a d s 0
0
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 ip in
C S G
0 .2 0 O P H
0 . 2 0 T r ip in
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 ip o u t
C S G
0 .4 0 O P H
0 . 4 0 T r ip o u t
IN C L
4 ,0 0 0 5 ,0 0 0 6 ,0 0 0 7 ,0 0 0
9 ,0 0 0 1 0 ,0 0 0
5-6 m
1 1 ,0 0 0 1 2 ,0 0 0
Inclination
9 5/8" Casing String
8 ,0 0 0
Measured Depth (ft)
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
2-3 m
1 9 ,0 0 0 2 0 ,0 0 0 2 1 ,0 0 0
T IH
8.5
200
(P/U) weight on up pipe movement, at least 5-6 meters, record both maximum PU weight and normal PU weight . (Static 600and dynamic frictions)
2 2 ,0 0 0
H o o k lo a d s
P O H
H o o k lo a d s
2 3 ,0 0 0
F F = 0 .0 2 4 ,0 0 0 2 5 ,0 0 0 0
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
Torque and Drag Monitoring
400
Martin Decker
600
T r ip p in g H o o k lo a d s 0 1 ,0 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 ip in
C S G
0 .2 0 O P H
0 . 2 0 T r ip in
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 ip o u t
C S G
0 .4 0 O P H
0 . 4 0 T r ip o u t
IN C L
4 ,0 0 0 5 ,0 0 0 6 ,0 0 0 7 ,0 0 0
5-6 m
1 1 ,0 0 0 1 2 ,0 0 0
Inclination
9 ,0 0 0 1 0 ,0 0 0
9 5/8" Casing String
8 ,0 0 0
Measured Depth (ft)
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
2-3 m
1 9 ,0 0 0 2 0 ,0 0 0 2 1 ,0 0 0 2 2 ,0 0 0
8.5
200
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.
T IH
H o o k lo a d s
P O H
2 3 ,0 0 0
F F = 0 .0 2 4 ,0 0 0 2 5 ,0 0 0
H o o k lo a d s
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.
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)
Hook Position
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 Steady hookload while moving the drill string up (This represents the dynamic friction factor). This hookload needs to be used in the T&D charts
Torque & Drag Examples Hole ConditionCASING Monitoring
13 3/8" Casing String
Poor Hole Cleaning Example 6,000
12 ¼” Tangent Section
7,000
LWD Gamma Ray Curve
9,000 10,000 11,000 12,000 13,000 12 1/4 OH
Measured Depth (ft)
8,000
14,000 15,000 16,000
Pick-up hookloads indicating poor hole cleaning in tangent section
Pick/Up Wt.
17,000 18,000 19,000 20,000
Slack-Off Wt.
Gamma Ray
Rotating Wt.
21,000 175
200
225
250
275
300
325
350
Hookloads (klbs)
375
400
425
450
475
500
525
Poor Hole Cleaning- Advanced 67 degrees Break-outs
Rig 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 in ledges in wellbore
Drag improves once circulation is established to clean hole Hookload remaining constant while running in hole, indicating increase drag. Casing becomes stuck off-bottom at 15,100 feet.
Torque & Drag Management CASING Further Considerations
Drillstring Design Sections Section Type
Function
Desired Characteristics
Desired Considerations
I
BHA
Directional Control
Stiff, Light Weight
Minimize T&D
II
DP
Transfer Weight
Stiff, Light Weight
Minimize T&D, Adequate buckling resistance
III
DP or HWDP
Transfer Weight
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
Weight
High Tensile and Torsional Limits
Provide adequate tensile and torsional margins
Managing Torque and Drag Torque Reduction Well Trajectory Cased Hole Open Hole Mud Lubricity Lubricating Beads Use of LCM Torque reducers Well path considerations Trajectory Bottom hole Assemblies Optimum Profile
Drag Optimization Well Profile Mud Lubricity Drill pipe protectors Buckling Effects 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??
Objectives At the end of this module you will be able to:
Explain and define Side Forces Explain and define Friction Factor 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 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 key points must be understood: Model (Representation) – noun(C): a representation of something, either as a physical object which is usually smaller than the real object, or as a simple description of the object which might be used in calculations.
Garbage In = Garbage Out
Components Of Torque & Drag CASING SideForce’s & Friction
The Weight Component of Side Force
incl
weight
Sidewall Forces – Tension and DLS Building Section tensile
tensile
resultant
tensile load
resultant
weight weight
Dropping Section
tensile
resultant
weight
tensile load
tensile load
Sidewall Forces – Tension and DLS*
Wall force with pipe tension and DLS:
DLS × π × L × T SF = 18 × 10 3
Sidewall Forces – Tension and DLS Wall force with pipe tension and DLS: Wear => Casing, Drill string components DE
Sideforce Components Wn : side weight = linear weight x sin( inclination )
Wn
Wn
FB
FB
T Wn
FC FC
FB
curvature side force
FB : bending side force (zero in soft string model)
FC = T x string curvature
T Total Side Force = -Wn + FC + FB
FB
Side Forces - Worst Case Scenario???
DE
Exercise Example: Calculate the wall force across a 30’ section of 5°/100’ DLS considering a tension of 100,000 lbs below the DL. SF =
Exercise:
5 × π × 30 ×100000 = 2617.91lbf / 30 ft 18 ×103
KOP of 1500' and a build up to 30° inclination. Our TD is 10,000'. The drillstring tension at 1500' when we are drilling at TD could be around 180,000 lbs. If the average length of a t of drillpipe is 31' and if we want to limit our side force to 2,000 lbs per t of drillpipe what is the maximum DLS can be used? 18 × 103 × SF 18 × 103 × 2000 DLS = = = 2.050 / 100 ft π × L ×T π × 31×180000
The Stiffness Component of Side Force
When does stiffness start to become a factor? 5” drill pipe 16 deg/100ft 3 1/2” drill pipe 22 deg/100ft
Stiffness – BHA as a Hollow Cylinder Stiffness Coefficient = E xI where: E = Young’s Modulus (lb/in2) I = Moment of Inertia (in4) Moment of Inertia I = p (OD4 - ID4) ÷ 64 OD = outside diameter ID = inside diameter DE
Stiffness – BHA as a Hollow Cylinder Which one is more stiff?
Drill Collar?
DE
Drill Pipe? Casing? Liner?
The Buckling Component of SideForce Fb Fb Fb
String is in compression
Fb
Sinusoidal & Helical Buckling
DE
DE
Buckling - Worst Case Scenario???
DE
Dawson-Pasley Buckling Criteria
FCR
E × I × K B × W × sin θ = 2× r
FCR = Critical sinusoidal buckling load (lbs)
θ
= Inclination of the hole at the point of interest (deg) E = Young' s Modulus K B = Buoyancy factor (unitless) I
= Moment of inertia (inch 4 )
W = Unit weight in air (lbs/in) r = Radial clearance between pipe tool t and hole (in)
DE
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 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
Summary Four Components of Side Force Weight
always a consideration, light drill pipe in Horizontal wells
Tensile
more pronounced with high tension and high dog legs negligible effect with dog legs less than 15 deg/100ft high compressional loads with neutral point significantly above the bit (near surface)
Stiffness Buckling
Stiff vs. Soft String Model Soft String Stiff String Drill string always in Drill string curvature can with the borehole be different than wellbore area, curvature areas are side forces are reduced, more realistic overestimated side forces More accurate torque loss calculation in a low inclination wellbore
Borehole/Drill string LOW TORTUOSITY WELLS (local DLS << well curvature)
Three main components of
Wn
side force Side weight Curvature side force Bending side force
T
STIFF & SOFT STRINGTORTUOSITY / BOREHOLE HIGH WELLS
T
(local DLS >> well curvature)
Wn
Wn
Stiff- and soft-string models
T
SOFTSTRING/ BOREHOLE
give the same result for an untortuous plan
Wn Wn
T STIFFSTRING/ BOREHOLE
T
T : axial load, Wn : component of drillstring weight perpendicular to borehole axis
T
Something Additional!! Tortuosity in Planned Trajectories Why add tortuosity to plans? for more than “Ideal” T&D numbers Allows more consistent results between different
engineers for drilling system used
Recommended Values (no offset data)
DE
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.
Friction
Motion W
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
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
∆T = W cos I − Ff ∆T = W cos I − µW sin I (b) Raising: Friction still opposes motion ∆T = W cos I + Ff
∆T = W cos I + µW sin I
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 Tortuosity Borehole Condition
Friction Factors - Rotation Rotating
Sliding
Backreaming Friction Vector
RPM Vector Drilling Friction Vector Backreaming friction factor from weight loss/overpull while drill string is rotating 0<µ<0.05 Drilling Friction from torque loss while drill string is rotating 0.1< µ <0.3
Sliding Friction Vector Sliding Velocity (ROP)
Sliding Friction Factor from weight loss/overpull while drill string is not rotating 0.1< µ <0.3
Friction Factors Are a function of the materials involved (pipe to formation or pipe to casing) and the lubricity of the fluid (mud) between them 0.0
0.1
0.2
0.3
0.4
0.5
0.6
Water based mud Oil based mud (40% reduction)
Rotational .22 - .28 Translation .03 - .07 Sliding (not rotating).28 - .40 --.55
.13 - .17 .02 - .05 .17 - .25 -- .33
CASING
Stress A point within a body under loading can be subjected to FOUR possible types of stresses:
NORMAL STRESS, BENDING STRESS, SHEAR STRESS, TORSIONAL STRESS
The magnitude of these stresses is dependent on the loading conditions of the body of interest.
DE
Normal Stress Normal Stress is the intensity of the net forces acting normal (perpendicular) to an infinitely small area A within an object per unit area. If the normal stress acting on A pulls on it, then it is referred to as tensile stress, If it pushes on the area, it is called compressive stress.
DE
Bending Stress Bending Stress
σ
b
=
E ×D 2R
(*)
E = Young’s 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
DE
Shear Stress Shear Stress is the intensity of force per unit area, acting tangent to A. If the s are considered rigid, and P is large enough, the material of the bar will deform and fail along the planes AB and CD.
DE
Torsional Stress στ =
FS ∆x
π ×G×d × N 12 × L or
στ = 6 × d ×
L
θ
Q J
Where Q =
π ×G × J × N 72 × L
G → Shear Modulus of steel, 12 ×106 psi N → Number of turns in the drill pipe string, rev Q → Torque applied to the DP, ft.lb L → Length of Drillpipe string, ft d → Internal diameter of the pipe, inches J → Polar moment of inertia,
FS Shear Stress A = G (Shear Modulus) = Shear Strain θ
DE
π 32
(
)
× D 4 − d 4 ; inch 4
Richard Von Mises Von Mises Stress
=
((σ ) + (σ axial
))
2
bending
+ 3σ
2 torsional
Axial, Bending and Torsional Stresses combined Total Stress of the drillstring component [psi]
DE
Torque & Drag CASING Definitions & Monitoring
Torque and Drag - Definition Torque Losses Are 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 It 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 A total of 4 measurements required to monitor T&D T r ip p in g H o o k lo a d s 0 C S G 0 . 4 0 O P H 0 . 4 0 T r ip in 1 ,0 0 0
C S G 0 . 2 0 O P H 0 . 2 0 T r ip in
2 ,0 0 0
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 ip o u t
3 ,0 0 0
C S G 0 . 4 0 O P H 0 . 4 0 T r ip o u t IN C L
4 ,0 0 0 5 ,0 0 0 6 ,0 0 0 7 ,0 0 0
9 ,0 0 0 1 0 ,0 0 0 1 1 ,0 0 0 1 2 ,0 0 0
Inclination
9 5/8" Casing String
8 ,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
T IH H o o k lo a d s
8.5
Measured Depth (ft)
Hookloads Picking Up at least 5-6 meters with a constant speed Slacking Off at least 5-6 meters movement with a constant speed Rotating off bottom at least 1-2 meters off bottom Torque Off bottom torque @ rotary speed
2 2 ,0 0 0
P O H H o o k lo a d s
2 3 ,0 0 0
F F = 0 .0 2 4 ,0 0 0 2 5 ,0 0 0 0
50
100
150
200
250
300
H o o k lo a d (k lb s )
350
400
450
500
550
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 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 ts
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 instructions, for each hole size, angle, formation type, etc). 200
100
Martin Decker
0
300
Torque and Drag Monitoring A few meters off bottom,
400
Martin Decker
600
T r ip p in g H o o k lo a d s 0
0
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 ip in
C S G
0 .2 0 O P H
0 . 2 0 T r ip in
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 ip o u t
C S G
0 .4 0 O P H
0 . 4 0 T r ip o u t
IN C L
4 ,0 0 0 5 ,0 0 0 6 ,0 0 0 7 ,0 0 0
9 ,0 0 0 1 0 ,0 0 0 1 1 ,0 0 0 1 2 ,0 0 0
Inclination
9 5/8" Casing String
8 ,0 0 0
Measured Depth (ft)
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
2-3 m
1 9 ,0 0 0 2 0 ,0 0 0 2 1 ,0 0 0
T IH
8.5
200
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
2 2 ,0 0 0
H o o k lo a d s
P O H
H o o k lo a d s
2 3 ,0 0 0
F F = 0 .0 2 4 ,0 0 0 2 5 ,0 0 0 0
5 0
1 0 0
1 5 0
2 0 0
2 5 0
3 0 0
H o o k lo a d (k lb s )
3 5 0
4 0 0
4 5 0
5 0 0
5 5 0
Torque and Drag Monitoring A few meters off bottom,
10000
Torque Gauge
0
0 100
Drilling Torque FF Calibration
200 Off-btm Torque
300
CH=0.25, OH=0.30
400 133/8"C asing
CH=0.20, OH=0.20
500 600 700
Note: Added 1.5K needed to turn top-drive.
800 900 1,000 M easuredD epth(m )
1,100 1,200 1,300 1,400 1,500 1,600 1,700 1,800
14.75
5000
obtain rotating string weight and torque at drilling RPM and flow rate. If the T&D 15000 modeling is done correctly, this weight should be on top of the FF=0 line
1,900 2,000
2-3 m
2,100 2,200 2,300 2,400 2,500 2,600 0
5
10 Torque (kft-lbs)
15
20
Torque and Drag Monitoring Stop rotary and obtain pick up
400
Martin Decker
T r ip p in g H o o k lo a d s 0
0
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 ip in
C S G
0 .2 0 O P H
0 . 2 0 T r ip in
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 ip o u t
C S G
0 .4 0 O P H
0 . 4 0 T r ip o u t
IN C L
4 ,0 0 0 5 ,0 0 0 6 ,0 0 0 7 ,0 0 0
9 ,0 0 0 1 0 ,0 0 0
5-6 m
1 1 ,0 0 0 1 2 ,0 0 0
Inclination
9 5/8" Casing String
8 ,0 0 0
Measured Depth (ft)
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
2-3 m
1 9 ,0 0 0 2 0 ,0 0 0 2 1 ,0 0 0
T IH
8.5
200
(P/U) weight on up pipe movement, at least 5-6 meters, record both maximum PU weight and normal PU weight . (Static 600and dynamic frictions)
2 2 ,0 0 0
H o o k lo a d s
P O H
H o o k lo a d s
2 3 ,0 0 0
F F = 0 .0 2 4 ,0 0 0 2 5 ,0 0 0 0
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
Torque and Drag Monitoring
400
Martin Decker
600
T r ip p in g H o o k lo a d s 0 1 ,0 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 ip in
C S G
0 .2 0 O P H
0 . 2 0 T r ip in
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 ip o u t
C S G
0 .4 0 O P H
0 . 4 0 T r ip o u t
IN C L
4 ,0 0 0 5 ,0 0 0 6 ,0 0 0 7 ,0 0 0
5-6 m
1 1 ,0 0 0 1 2 ,0 0 0
Inclination
9 ,0 0 0 1 0 ,0 0 0
9 5/8" Casing String
8 ,0 0 0
Measured Depth (ft)
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
2-3 m
1 9 ,0 0 0 2 0 ,0 0 0 2 1 ,0 0 0 2 2 ,0 0 0
8.5
200
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.
T IH
H o o k lo a d s
P O H
2 3 ,0 0 0
F F = 0 .0 2 4 ,0 0 0 2 5 ,0 0 0
H o o k lo a d s
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.
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)
Hook Position
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 Steady hookload while moving the drill string up (This represents the dynamic friction factor). This hookload needs to be used in the T&D charts
Torque & Drag Examples Hole ConditionCASING Monitoring
13 3/8" Casing String
Poor Hole Cleaning Example 6,000
12 ¼” Tangent Section
7,000
LWD Gamma Ray Curve
9,000 10,000 11,000 12,000 13,000 12 1/4 OH
Measured Depth (ft)
8,000
14,000 15,000 16,000
Pick-up hookloads indicating poor hole cleaning in tangent section
Pick/Up Wt.
17,000 18,000 19,000 20,000
Slack-Off Wt.
Gamma Ray
Rotating Wt.
21,000 175
200
225
250
275
300
325
350
Hookloads (klbs)
375
400
425
450
475
500
525
Poor Hole Cleaning- Advanced 67 degrees Break-outs
Rig 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 in ledges in wellbore
Drag improves once circulation is established to clean hole Hookload remaining constant while running in hole, indicating increase drag. Casing becomes stuck off-bottom at 15,100 feet.
Torque & Drag Management CASING Further Considerations
Drillstring Design Sections Section Type
Function
Desired Characteristics
Desired Considerations
I
BHA
Directional Control
Stiff, Light Weight
Minimize T&D
II
DP
Transfer Weight
Stiff, Light Weight
Minimize T&D, Adequate buckling resistance
III
DP or HWDP
Transfer Weight
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
Weight
High Tensile and Torsional Limits
Provide adequate tensile and torsional margins
Managing Torque and Drag Torque Reduction Well Trajectory Cased Hole Open Hole Mud Lubricity Lubricating Beads Use of LCM Torque reducers Well path considerations Trajectory Bottom hole Assemblies Optimum Profile
Drag Optimization Well Profile Mud Lubricity Drill pipe protectors Buckling Effects 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??
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