Drilling Torque & Drag

8/15/2019 Drilling Torque & Drag

1/66

CASING

Torque & Drag


2/66

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 Torqueand Drag


3/66

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


4/66

Torque and Drag ModelingTo understand computer modeling two key

points 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 simple

description of the object which might be used in calculations.

Garbage In = Garbage Out


5/66

CASING

Torque & Drag

SideForce’s & Friction


6/66

The Weight Component of Side Force

incl

weight


7/66

Building Section

Sidewall Forces – Tension and DLS

tensile

resultant

tensile

tensileload

tensile

Dropping Section

loadweightweight

tensile

load

tensileweight

resultant


8/66

Sidewall Forces – Tension and DLS*

Wall force with pipe tension andDLS:

31018××××= LDLSF π


9/66

Sidewall Forces – Tension and

DLS

Wall force withpipe tension andDLS:

DE

Wear => Casing,

Drill stringcomponents


10/66

Sideforce Components

Wn

T

Wn

W

FBFB

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

T

curvature side force

FC

= T x string curvature

C

FC FB FB

FB:bending side force

(zero in soft string model)

Total Side Force = -Wn + FC + FB


11/66

Side Forces - Worst Case Scenario???

DE


12/66

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.

ft lbf SF 30 / 91.26171018

1000003053

=×

×××=

π

ft T L

SF DLS 100 / 05.2

18000031

200010181018 033

=××

××=

××

××=

π π

KOP of 1500' and a build up to 30° inclination. Our TD is

10,000'. The drillstring tension at 1500' when we are drilling atTD could be around 180,000 lbs. If the average length of a joint

of 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?


13/66

The Stiffness Component of Side Force

5” drill pipe

3 1/2” drill pipe

16 deg/100ft

22 deg/100ft

When does stiffness start to become a factor?


14/66

Stiffness – BHA as a Hollow Cylinder

Stiffness Coefficient = Ex I

where:

E = Young’s Modulus(lb/in2)

I = Moment of Inertia in4

DE

Moment of Inertia

I = p (OD4 - ID4) ÷ 64

OD = outside diameter

ID = inside diameter


15/66

Stiffness – BHA as a Hollow Cylinder

Which one is more stiff?

DE

Drill Collar? Drill Pipe?

Casing?Liner?


16/66

The Buckling Component of SideForce

FbF

b

FbString is in compression


17/66

Sinusoidal & Helical Buckling

DE


18/66

DE


19/66

Buckling - Worst Case Scenario???

DE


20/66

Dawson-Pasley Buckling Criteria

r

W K I E F BCR

θ sin2

×××××=

DE

(in)holeand jointtoolpipebetweenclearanceRadialr(lbs/in)airinhtUnit weigW

)(inchinertiaof Moment

(unitless)factorBuoyancy

ModulussYoung'

(deg)interestof pointat theholetheof nInclinatio

4

=

=

=

=

=

=

I

K

E

B

CR

θ


21/66

Guidelines for Analyzing Buckling

ProblemsSinusoidal 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 (SPE14729) in ‘86.

Generally Helical buckling should be considered at compressional

loads √2 times those calculated for Sinusoidal buckling


22/66

SummaryFour Components of Side Force

Weight always a consideration, light drill pipe inHorizontal wells

Tensile more pronounced with high tension and high

dog legsStiffness negligible effect with dog legs less than 15

deg/100ft

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


23/66

Stiff vs. Soft String ModelSoft String Stiff String

Drill string always incontact with the borehole

Contact area, curvature

Drill string curvature canbe different than wellbore

Contact areas are

overestimated

,

side forces More accurate torque loss

calculation in a low

inclination wellbore


24/66

Borehole/Drill string contact

HIGH TORTUOSITY WELLS(local DLS >> well curvature)

Three main components ofside force

Side weight

Curvature side force

Bendin side force

TT

Wn

STIFF& SOFTSTRING/ BOREHOLECONTACT

LOWTORTUOSITY WELLS(local DLS


25/66

Something Additional!!

Tortuosity in Planned Trajectories

Why add tortuosity to plans? Account for more than “Ideal” T&D numbers

Allows more consistent results between different

DE

eng neers

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


26/66

Friction

It is the resistance to motion that exists when a solid

object is moved tangentially with respect to anotherwhich it touches.

W

Motion Friction


27/66

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


28/66

When does the Pipe Stop Moving?

Tan -1 (1/FF) = Inclination


29/66

Effect of Friction (no doglegs)


30/66

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

IsinWIcosWT

FIcosWT f

−=∆

−=∆

(b) Raising: Friction still opposes motion

IsinWIcosWT

FIcosWTf

µ +=∆

+=∆


31/66

Exercise 1

What is the maximum hole angle (inclination angle) thatcan be logged without the aid of drillpipe, coiled tubing,other tubulars or sinker bars?

(assume FF = 0.4)


32/66

Friction Factors

In reality, Friction Factor (FF) used in modeling is not

a true sliding coefficient of friction. It acts as acorrelation coefficient that lumps together the frictionforces caused by various effects, including friction.

Typically the FF will depend on a combination ofeffects including:

Formation Mud type Roughness of Support Tortuosity Borehole Condition


33/66

Friction Factors - RotationRotating Sliding

SlidingFrictionVector

RPMVector

BackreamingFriction Vector

(ROP)Drilling FrictionVector

Backreaming friction factor from

weight loss/overpull while drillstring is rotating 0


34/66

Friction Factors

Are a function of the materials involved (pipe to formationor pipe to casing) and the lubricity of the fluid (mud)

between them

Water based

0.0 0.1 0.2 0.3 0.4 0.5 0.6

Oil based

mud(40% reduction)

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


35/66

CASING


36/66

StressA point within a body under loading can be subjected to

FOUR possible types of stresses:

NORMAL STRESS,

BENDING STRESS,

DE

SHEAR STRESS,

TORSIONAL STRESS

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


37/66

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

DE

as ens e s ress ,If it pushes on the area, it is called compressive stress .


38/66

Bending Stress

Bending

Stress

R

D E b

2

×=σ

DE

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


39/66

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

DE

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


40/66

x ∆

S F

Torsional Stress

6

72 re Whe6

or

12

L

N J GQ

J

Qd

L

N d G

×

×××=××=

×

×××=

π σ

π σ

τ

τ

DE

θ

Modulus)(Shearθ

G A

F

Strain Shear

Stress Shear S

==

( ) 444 inch;32

inertia,of momentPolarJ

inchespipe,theof diameterInternal d

ftstring,Drillpipeof LengthL

ft.lbDP,thetoappliedTorque Qrevstring,pipedrillin theturnsof NumberN

,

d D −×→

→

→

→

→

π


41/66

Richard Von Mises

( ) ( )( ) 22 3 torsional bending axial σ σ σ ++=Von MisesStress

DE

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


42/66

CASING

Torque & Drag

Definitions & Monitoring


43/66

Torque Losses

Are defined as the difference between the torqueapplied at the rig floor and the torque generated atthe bit. Also referred to as rotating friction.

Torque and Drag - Definition

Drag lossesIt is the difference between the static weight of thedrillstring and the weight under movement. Also

referred to as sliding friction.

drag = sideforce x friction factor

torque = sideforce x friction factor x radius

O ll / Sl k Off


44/66

Overpull / Slack-Off

T


45/66

Torque

T d D M i i Wh


46/66

Torque and Drag Monitoring Why

Track hole condition and deterioration

Determine hole cleaning efficiency

Evaluate cuttings bed formation

Determine limitation of equipment and maximum achievabledepths

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 torquereducers

Parameters to monitor


47/66

Parameters to monitor

Hookloads

Picking Up

at least 5-6 meterswith a constantspeed

Slackin Off

T r ip 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 i n

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

C S G 0 . 4 0 O P H 0 . 4 0 T ri p o u tI N C L

s i n g S t r i n g

l i

a t i o n

A total of 4 measurements required to monitor T&D

at least 5-6 metersmovement with aconstant speed

Rotating off bottom

at least 1-2 metersoff bottom

Torque

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 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

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

M e a s u r

e d D e p t h ( f t )

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

F F = 0 . 0

P O H H o o k lo a d s

9 5 / 8 " C a

8 . 5

I n c l i n

i

Torque and Drag Monitoring When


48/66

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 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


49/66


After drilling down each connection,reciprocate the stand with goodcirculation and rotation to ensure goodhole cleaning and any cuttings are clear

of the BHA and to determine if the hole is“free” (situation may be different fordifferent rigs/company procedures, so ateach connection, pump/ream the last

100

0

200

300

stan as necessary an as per

instructions, for each hole size, angle,formation type, etc).

Martin Decker


50/66

T d D M it i


51/66

Drilling Torque FF Calibration0

100

200

5000

0

10000

15000

A few meters off bottom,obtain rotating string weightand torque at drilling RPMand flow rate. If the T&Dmodeling is done correctly,

this weight should be on topof the FF=0 line

Torque Gauge


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

2,600

0 5 10 15 20

Torque (kft-lbs)

M e a s u r e d D e p t h (

Off-btm Torque

CH=0.25, OH=0.30

CH=0.20, OH=0.20

1 3 3 / 8 " C a s i n g

1 4 . 7 5

Note: Added 1.5K needed

to turn top-drive.

2-3 m


52/66



53/66

200

0

400

600

Obtain the slack off (S/O)weight on the downmovement of the pipe whilereturning the pipe 5-6meters to bottom. Recordboth minimum slack off andnormal 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 ip i n

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

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


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 0

M e

a s u r e d D e p t h ( f t )

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

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 lo a d s

9 5 / 8 " C a s i n g S t r i n g

8 . 5

n c l i n a t i o n

5-6 m

Torque and Drag Monitoring How


54/66

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 repeatprevious steps above, before the connection

Take the circulating readings at the same flow rate (for eachhole section to avoid the otential influence/interference ofhydraulic lift.

While tripping out, just obtain the pick-up weights. Obtainthe 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)


55/66

Typical Hookload Behavior (POOH)

Picking up offthe slips,maximumhookload (thisrepresents thestatic friction

factor). Thiswill help usmonitor if weare gettingcloser to rig

Steadyhookload whilemoving the drillstring up (Thisrepresents thedynamicfriction factor).

This hookloadneeds to beused in theT&D charts

Hook Position


56/66

CASING

Examples

Hole ConditionMonitoring

Poor Hole Cleaning Example


57/66

g p

6,000

7,000

8,000

9,000

10,000

11,000

12,000 M e a s u r e d D e p t h ( f

t )

1 3 3

12 ¼” Tangent Section

LWD Gamma RayCurve

13,000

14,000

15,000

16,000

17,000

18,000

19,000

20,000

21,000

175 200 225 250 275 300 325 350 375 400 425 450 475 500 525

Hookloads (klbs)

Slack-Off Wt. Rotating Wt.

Pick/Up Wt.

1 2 1 / 4 O H

Gamma

Pick-up hookloadsindicating poor holecleaning in tangent

section

Poor Hole Cleaning- Advanced


58/66

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

Limitations

HC problems

Short Trip

30% FF deterioration

Casing Running - Good


59/66

Casing Running - Poor


60/66

Increasing drag running 9”

in ledges in wellbore

Hookload remaining constantwhile running in hole, indicatingincrease drag. Casing becomesstuck off-bottom at 15,100 feet.

Drag improves oncecirculation is established toclean hole


61/66

CASING

Management

Further Considerations

Drillstring Design Sections


62/66

g gSection

TypeFunction Desired

CharacteristicsDesired

Considerations

I BHA DirectionalControl

Stiff, LightWeight

Minimize T&D

II DP TransferWeight

Stiff, LightWeight

Minimize T&D,Adequate buckling

resistance

III DP orHWDP

TransferWeight

Stiff, LightWeight

Minimize T&D,Increased buckling

resistance

IV HWDP Transfer /

ProvideWeight

Stiff, Moderate

Weight

Increased buckling

resistance

V HWDPor DC

ProvideWeight

ConcentratedWeight

Transition component

VI DP SupportWeight

High Tensile andTorsional Limits

Provide adequatetensile and torsional

margins

Managing Torque and Drag


63/66

Torque Reduction Well Trajectory Cased Hole Open Hole Mud Lubricity Lubricating Beads

Drag Optimization

Well Profile

Mud Lubricity

Drill pipe protectors Buckling Effects

Torque reducers

Well path considerations

Trajectory Bottom hole

Assemblies Optimum Profile

Hole Cleaning Down hole Motors

Rotation

Steerable Rotary Systems

General Guidelines for T&D Optimization


64/66

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


65/66


66/66

Questions??

Documents

Drilling Torque & Drag