Drill String Design & BHA Design

(1)

S chlumb erg er P riv ate

IPM DPT

(2)

References

• API RP 7G Drill Stem Design and Op Limits

• API SPEC 7 Specifications for Rotary Drilling

Elements

• API SPEC 5D Specifications for Drill Pipe

• SLB Drill String Design manual

(3)

At the end of this lecture YOU will be able to describe:

• Functions of Drill Pipe , Drill Collars and BHA selection

• Grades of Drill Pipe and strength properties

• Thread types and tool-joints

• Drill collar weight and neutral point

• Bending Stress Ratios and Stiffness Ratios

• Margin Of Overpull

• Basic design calculations based on depth to be drilled.

• Functions of stabilizers and roller reamers.

(4)

I. Introduction to Drill String Design: Overview

II. Drill String Components

• Drill Collars - Drill Pipe - HWDP

III. Drill String Design

• Bottom Hole Assembly Design

• Drill Pipe Selection

• Buckling and max WOB

(5)

The drill string is the mechanical linkage connecting the drill bit on bottom to the rotary drive system on the surface.

The drillstring serves the three main following functions :

1. Transmit and support axial loads - WOB

2. Transmit and support torsional loads - rpm

3. Transmit hydraulics to clean the hole and cool the

bit. DC WOB

D P

(6)

The Drill String includes all tubular equipment between the Kelly Swivel and the bit

•

Kelly

• Surface Safety Valves • Drill Pipe

• Heavy Walled Drill Pipe • Drill Collar

• Jars – Shock Subs – Bumper Subs – Junk Baskets – Accelerators etc…

(7)

Strictly speaking, Kelly/ Topdrive are not components of the drill string; however, they provide the essential requirements for drilling a well:

The Kelly/Top Drive

1) Transmit rotation to the drillstring. 2) Provide access to the drilling fluid

into the drillstring.

(8)

• Transmits rotation and weight-on-bit to the drillbit

• Supports the weight of the drillstring

• Connects to the swivel and allow circulation thru pipe.

The Kelly is the rotating link between the rotary table and the drill string.

The Kelly comes in lengths ranging from 40 to 54 ft with cross sections such as hexagonal (most common), square or triangular.

Connected to a Kelly Saver Sub

(9)

The Kelly cock is used to close the inside of the drillstring in the event of a kick.

The upper & lower Kelly cocks operate manually.

IBOP / DPSV are not run in the drill string but kept handy on the rig floor

The Kelly is usually provided with two safety valves, one at the top and one at the bottom, called Kelly cock.

(10)

Advantages over the kelly system:

1. Efficient reaming and back reaming.

2. Circulating while running in hole or pulling out of hole in stands

3. The kelly system can only do this in singles; ie 30 ft.

The top drive is basically a combined rotary table and kelly.

It is powered by a separate motor and transmits rotation to the drill string directly without the need for a rotary table.

(11)

Stabilizers

(12)

Stabilizers

Reasons for Using Stabilizers:

1. They are used as a fundamental method of controlling the directional behavior of most BHAs.

2. Help concentrate the weight of the BHA on the bit.

3. Minimize bending and vibrations which cause tool joint wear and damage to BHA components such as MWDs. 4. Reduce drilling torque by preventing collar contact with the side of the hole and by keeping them concentric in the hole. (FG!!)

(13)

Roller Reamers

(14)

Drill Pipe

(15)

Drill Pipe

Function

To serve as a conduit or conductor for drilling fluid

To transmit the rotation from surface to the bit on bottom

Components

A pierced, seamless tube of forged steel or extruded Aluminum

Tool joints attached to each end of the seamless tube

Tool Joints

Provide connections for the drill string

Separate pieces of metal welded to the seamless tube Thick enough to have pin or box cut into them

(16)

Drill Pipe Classification

1. Size 2 3/8” to 6 5/8” – refers to OD of pipe body

2. Length Range 1 18 to 22 ft, Range 2 27 to 30ft, Range 3 38 to 45 ft

3. Grade E - 75, X – 95, G – 105, S – 135

the numbers denote 1000’s of psi minimum yield strength

4. Weight Depending upon the size of pipe different weight ranges

5. Class API classification for used pipe

(17)

Drill Pipe Grades

145,000 / 165,000 135,000 S or S-135 120,000 / 135,000 105,000 G or G-105 110,000 / 125,000 95,000 X or X-95 85,000 / 105,000 75,000 E or E-75

Avg / MaxYield

Min Yield

Grade

(18)

Mechanical Properties of Steel

Young Modulus

E = Stress divided by Strain = 30,000,000

Stress & Strength

Stress = Strength divided by Cross Section Area

Strain & stretch

(19)

Mechanical Properties of Steel

Elastic Limit

Limit of stress beyond which, when the stress is removed, the steel will have acquired a permanent stretch.

Minimum Yield Stress

The stress which gives a stretch of 0.5% (0.005”). When the stress is removed, the steel will have acquired 0.2% of permanent

deformation.

Ultimate Tensile Stress

(20)

Exercise DP-00

(21)

New: No wear, has never been used

Premium: Remaining wall not less than 80%.

Class 2: Remaining wall not less than 70%. Class 3: Remaining wall less than 70%.

Other details such as, dents and mashing, slip area mechanical damage, stress induced diameter variations, corrosion cuts and

gouges, specified on Table 24 ( Classification of Used Drill Pipe ) of

API RP 7G.

Unlike casing and tubing, which are normally run new, drill pipe is normally used in a worn condition. It therefore has Classes:

(22)

Where the pipe joins the tooljoint, the pipe wall thickness is increased or “upset”.

•This increased thickness is used to decrease the frequency of pipe failure at the point where the pipe meets the tool-joint.

•The drill-pipe can have

• Internal upsets (IU), ( OD stays the same )

•

External upsets (EU), ( ID stays the same )

•

Internal and External Upsets (IEU).

(23)

Drill Pipe Weights

When referring to Drill Pipe Weights, there are four important ones:

Plain end Weight – Refers to the weight per foot of the pipe body.

Nominal Weight - Refers to an obsolete standard. ( Weight of

Range I pipe with connections ) Is used today to refer a class of Drill pipe.

Adjusted Weight – Refers to the weight per foot of pipe including the upset but excluding the tool joint based on a length of 29.4 ft

Approximate Weight – The average weight per foot of pipe and tool joints of Range II pipe. This approximate weight is the number to use in Design calculations.

(24)

S chlumb erg er P riv ate ToolJtAdj Approx ToolJt Adjusted DP L 29.4 Wt 29.4 Wt Wt/ft length adjusted jt tool 29.4 jt tool wt. approx. 29.4 DP wt. adj. approx. Wt/ft + + × = + + × =

(25)

4 .

29 Wt

upset

Nom

Wt

Tube

Wt

_DP _Adj

=

+

(

)

(

)

(

_TE

)

TE Adj Jt Tool D D d D D d D L Wt − × × − − × + − × = 2 3 3 2 2 501 . 0 167 . 0 222 . 0

L= combined length of pin and box (in) D= outside diameter of pin (in) d= inside diameter of pin (in) D_TE= diameter of box at elevator upset (in)

Data from Spec 7 Fig 6 Table 7

….(1)

….(2)

Data from Table 7API 5D

(

D D

)

_ft L L TE Adj Jt Tool 12 253 . 2 × − + = ….(3)

Datat from Spec 7 Fig 6 Table 7

(26)

Calculate the approximate weight of tool joint and drillpipe assembly for 5 in OD, 19.5 lb/ft Drill Pipe having NC50 tool joints with 6.625 in OD, 2.75 in ID and being

internally-externally upset. ( IEU ).

Compare the value against the one published on Table 9 of API RP7G.

Exercise DP-01

Tables 7API 5D and Table 7 of the Specification can be found in handout # 1 of tables.

Table 9 of API RP7G can be found on handout # 2 of tables.

(27)

(28)

(29)

• Table 1-3 New Pipe Data

• Table 4-5 Premium Pipe Data

• Table 6-7 Class Two Pipe Data

• Table 8-9 Tool-joint Data

• Table 10 Make-up Torque Data

• Table 12 Connection interchangeability

• Table 24 Classification of used DP

(30)

• All API tool joints have a minimum yield strength of 120,000 psi

regardless of the grade of the drill pipe they are used on (E, X, G, S) .

• API sets tool joint torsional strength at minimum 80% of the

tube torsional strength.

• Make up torque is determined by pin ID or box OD. The make

up torque is 60% of the tool joint torsional capacity. The equation for determining make up can be obtained from the appendix of API RPG7. ( Numeral A.8.2 ). This equation is rather complex, so the API developed a series of charts to find the recommended make up torque to any connection given the tool jt OD of box and ID of pin. These charts can be found in API RP 7G ( Figures 1 to 25 )

(31)

Exercise DP02

Using some tables (?) and some figures (?) of API RP7G what should be the make up torque of NEW 19.5 ppf G105 and S135 drill pipe ?

How do these values compare to the ones reported on Table 10 ?

(32)

(33)

The most common thread style in drillpipe is NC

The thread has a V-shaped form and is identified by the pitch diameter, measured at a point 5/8 inches from the shoulder

Connection Number is Pitch dia*10 truncated to two digits

5/8”

GAUGE POINT PITCH DIAMETER

The size of a rotary shouldered connection is fixed by its gauge point pitch diameter.

Drillstring Connections

Multiply 5.0417 by 10 → 50.417 Choose first two digits → 50

Hence NC 50

If the pitch diameter is 5.0417 in Æ This is an NC50 connection

(34)

• Typical sizes: NC 50 for tool joints with 6 1/2” OD for 5”

pipe and NC 38 for 4 3/4” tool joints and 3 1/2” pipe.

• Seal is provided by shoulder not threads. A clearance

exists between the crest of one thread and the root of the mating thread

• Use of Lead based dope vs Copper based dope for DCs.

Not for sealing but for lubrication, to help make-up and prevent galling

• There are 17 NC’s in use : NC-10 (1 1/16”) through

NC-77 (7 3/4”)

(35)

Connection Interchangeability

Ext Flush Slim Hole Dbl Streamline Extra Hole Full Hole Int Flush 4-1/2 EF 4-1/2 4 3-1/2 2-7/8 SH 5-1/2 4-1/2 3-1/2 DSL 5 4-1/2 3-1/2 2-7/8 XH 4 FH 4-1/2 4 3-1/2 2-7/8 2-3/8 IF NC50 NC46 NC 40 NC 38 NC 31 NC 26

(36)

Drill Collars

(37)

Drill Collars

Description

They are heavy walled metal tubes The ends are threaded (box and pin)

Functions

To put weight on bit (WOB)

To keep the drill string from buckling

Types

Comes in many OD and ID sizes Typically 4 ¾” to 9 ½” OD

Most commonly in lengths of 30-31 feet

Square collars where the holes tend to be crooked Spiral collars where there is chance of getting stuck Collars with elevator and slip recesses

(38)

1. Protect the Drill string from Bending and Torsion 2. Control direction and inclination of wells

3. Drill straighter holes or vertical holes 4. Provide Pendulum effect

5. Reduce dog legs, key seats and ledges

6. Improve the probabilities of getting casing in the hole. 7. Increase bit performance

8. Reduce rough drilling, sticking and jumping 9. As a tool in fishing, testing, completing

(39)

Slick Drill Collar Spiral Drill Collar

More Types of Drill Collars

1. Both slick and spiral drill collars are used .

2. In areas where differential

sticking is a possibility spiral drill collars and spiral HWDP should be used in order to minimize

(40)

Drill Collars Strapping

length

Fish neckelevator_recess _recessslip OD I D connection Well# TRG 1 Bit # 1 Date: 28-Jul-03 Sl # 1234

Rig: IDPT Type atm 234

BHA#: 1 Manuf Hughes

Hole Size 26" Jets 20-20-20

Item Sl # ID OD FN Pin Box Length Remarks

Bit 1234 26" 7 5/8" R 0.75 New Bit Sub SL 235 3 1/8" 9 1/2" 7 5/8 R 1.01 9 1/2" Drill Collar 9546 3 1/8" 9 1/2" 0.67 7 5/8" R 7 5/8 R 8.96 Stab 237689 3 1/8" 9 1/2" 0.93 7 5/8" R 7 5/8 R 2.36 9 1/2" Drill Collar 9503 3 1/8" 9 1/2" 0.78 7 5/8" R 7 5/8 R 9.01 9 1/2" Drill Collar 9521 3 1/8" 9 1/2" 0.95 7 5/8" R 7 5/8 R 9.04 9 1/2" Drill Collar 9520 3 1/8" 9 1/2" 1.03 7 5/8" R 7 5/8 R 8.99

(41)

API Drill Collar Sizes

OD ID Range Weight Range OD ID Range Weight Range

ppf ppf 2 7/8 1 - 1.5 16 - 19 6 1/4 1.5 - 3.5 72 - 98 3 1 - 1.5 18 - 21 6 1/2 1.5 - 3.5 80 - 107 3 1/8 1 - 1.5 20 - 22 6 3/4 1.5 - 3.5 89 - 116 3 1/4 1 - 1.5 22 - 26 7 1.5 - 4 84 - 125 3 1/2 1 - 1.5 27 - 30 7 1/4 1.5 - 4 93 - 134 3 3/4 1 - 1.5 32 - 35 7.5 1.5 - 4 102 - 144 4 1 - 2.25 29 - 40 7.75 1.5 - 4 112 - 154 4 1/8 1 - 2.25 32 - 43 8 1.5 - 4 122 - 165 4 1/4 1 - 2.25 35 - 46 8 1/4 1.5 - 4 133 - 176 4 1/2 1 - 2.25 41 - 51 8 1/2 1.5 - 4 150 - 187 4 3/4 1.5 - 2.5 44 - 54 9 1.5 - 4 174 - 210 5 1.5 - 2.5 50 - 61 9 1/2 1.5 - 4 198 - 234 5 1/4 1.5 - 2.5 57 - 68 9 3/4 1.5 - 4 211 - 248 5 1/2 1.5 - 2.8125 60 - 75 10 1.5 - 4 225 - 261 5 3/4 1.5 - 3.25 60 - 82 11 1.5 - 4 281 - 317 6 1.5 - 3.25 68 - 90 12 1.5 - 4 342 - 379

(42)

S chlumb erg er P riv ate Characteristics

• DC connections are rotary shouldered connections and can mate

the various DP connections

• The shoulder provide the only positive seal against fluid leakage

• The lubricant is Copper based dope

• The connection is the weakest part of the entire BHA

• The DC connections go through cycles of tension-compression

and are subject to bending stresses

• Improper M/U torque, improper or insufficient lubricant, galling

can all lead to connection failure

(43)

Stress Relief Features

• Stresses in DC connections are concentrated at the base of the

pin and in the bottom of the box (stronger)

• DP body bends easily and takes up the majority of the applied

bending stress, DP connections are therefore subjected to less bending than the DP body.

• DCs and other BHA components are however much stiffer than

the DPs and much of the bending stresses are transferred to the connections.

• These bending stresses can cause fatigue failure at the

connections Stress Relief Groove / Bore Back

(44)

(45)

(46)

Drill Collar Connections

• The stress relief groove is to mitigate the fatigue cracks

where the face and threads would have otherwise joined

• The Bore Back serves the same purpose at the bottom of the

box

• Stress relief features should be specified on all BHA

connections NC-38 or larger.

• Pin stress relief grooves are not recommended on

connections smaller than NC-38 because they may weaken the connection’s tensile and torsional strength.

• Bore Back boxes could be used on smaller connections.

(47)

Lo-Torq Feature

•The low torque feature

consists in removing part of the shoulder area of the pin and box.

•This allows for lower make up

torque maintaining adequate shoulder loading.

•It is a common feature in

(48)

Torsion limits for DC

Torque is rarely limited by the DC connection because it is usually higher in the DP at surface and lower in the DC.

• If DC make-up torque >Dp make-up torque you have no

routine problems.

• BH Torque at any point should not exceed 80% of make-up torque for the connections in the hole to avoid over

(49)

Torque Limits for DC

M/U Torque as % of total torque

• API recommended

make-up torque for connections is a percentage of the total torsional yield of the

connection _{API NC} _56.8% _62.5% 56.2% 51.1% H-90 N/a 79.5% PAC DC>7 in DC< 7 in

(50)

(51)

(52)

Heavy Weight Drill Pipe

Design

Heavier wall and longer tool joints Center wall pad

Also available in spiral design

Function

Used in transition zones between DC and DP This prevents the DP from buckling

Can be used in compression (?) Used for directional drilling

Used in place of DC sometimes (?) To keep Drill Pipe in tension

Not to be used for Weight on Bit in normal circumstances

(53)

• Has the same OD as a standard drill pipe but

with much reduced inside diameter (usually 3” for 5” DP) and has an integral wear pad upset in the middle.

• It is used between standard Drill Pipe and Drill

Collars to provide a smooth transition between the different sections of the drillstring

components.

• Tool-Joint and Rotary shouldered connection

just like DP

• HWDP, although stiffer than DP, can also

Characteristics

(54)

• HWDP can be run both in tension and in compression

BUT!!!

• Manufacturers recommend not to run HWDP in compression

in hole sizes larger than 12 ¼”

• Experience shows that they should not be run in

compression in Vertical Holes

• If run in compression, rules of thumb are:

• TJOD + 6” > OH diameter

• 2 x TJOD > OH diameter

HWDP in Compression?

(55)

• Bottom Hole Assembly Selection

(56)

Drill Collar Selection Principles

• Drill Collar selection is governed by two major factors:

Weight and Stiffness --- Size!

• Usually the largest OD collar that can be safely run is the best selection

• More weight available for WOB

• Greatest stiffness to resist buckling and smooth directional tendencies

• Cyclical movement is restricted due to tighter Clearances

• Usually Shortest BHA possible to

• Reduce handling time at surface

• Minimize # of Connections in the hole

• Minimize total DC in contact with the wall for differential sticking exposure

(57)

Weight

• BHA Weight must be sufficient for the planned WOB

• BHA Weight must be sufficient to account for Buoyancy

• BHA Weight must be sufficient to account for hole

inclination

• BHA Weight must be sufficient so that the neutral point of

(58)

S chlumb erg er P riv ate Compression Tension Neutral point Design WOB

BHA Design

Drill Collar Weight & Neutral Point

DF for excess BHA=1.15

Neutral Point (NP) to tension should be in drill collars

15 .

1 =

Wt

Working

Max

Wt

Available

Max

(59)

Procedure For Selecting Drill Collars:

1. Determine the buoyancy factor for the mud weight in use using the formula below:

where

BF =Buoyancy Factor, dimensionless MW =Mud weight in use, ppg

65.5 =Weight of a gallon of steel, ppg

BHA Design

(60)

2. Calculate the required collar length to achieve the desired weight on bit:

DC Length = 1.15* WOB / (BF*W_dc) where:

WOB=Desired weight on bit , lbf (x 1000) BF =Buoyancy Factor, dimensionless W dc =Drill collar weight in air, lb/ft 1.15 =15% safety factor.

The 15% safety factor ensures that the neutral point remains within the collars when unforeseen forces (bounce, minor deviation and hole friction) are present.

(61)

3. For directional wells:

DC Length = DC Length Vertical / Cos I

where: I= Well inclination

Note that for horizontal wells drill collars are not normally used and BHA selection is based entirely on the prevention of buckling

(62)

Determine the number of 9 inch OD by 3 in ID drill collars required to provide a weight-on-bit of 55,000 lbf assuming

Hole deviation = 0°

Mud density = 12 ppg

Number And Size Of Drill Collars

(63)

Stiffness

• The BHA must have sufficient Stiffness to stabilize the

BHA, optimize ROP and prevent the formation of Key Seats, ledges and doglegs

• The larger the DC, the stiffer the BHA

• Stiffness Coefficient :

= Moment of Inertia x Young’s Modulus of Elasticity = л (OD4 _{– ID}4_{) / 64 x 30.000.000}

(64)

Exercise DP-04

(65)

Bending Strength Ratio

• BSR is the relative stiffness of the box to the pin of a given connection.

• Describes the Balance between two members of a connection and how they are likely to behave in a rotational cyclical environment

R

d

R

D

b

D

Z

BSR

R

d

R

D

b

D

Z

BSR

pin box pin box

)

(

)

(

)

(

32 )

(

32

4 4 4 4 4 4 4 4

−

=

−

=

π

Where:

Zbox = box section modulus Zpin = pin section modulus

D = Outside diameter of pin and box

b = thread root diameter of box threads at

. end of pin.

R = Thread root diameter of pin threads ¾

. of an inch from shoulder of pin.

(66)

(67)

BSR in DC Connections

• A Connection is said to be balanced if the BSR is 2.5

• When BSR is higher tend to see pin failures

• When BSR is lower tend to see more box failures

• However, field experience has shown that:

• 8” Dc having BSR’s of 2.5 usually fail in the box

• 4-3/4” DC having BSR as low as 1.8 very rarely fail in the box.

(68)

BSR in Connections

(69)

Additional BSR Guidelines

• High RPM, Soft Formation Small DC (8 in in 12.25 hole or

6 in in 8.25 hole) 2.25-2.75

• Low RPM Hard Formations Large DC (10 in in 12-1/4 hole

2.5-3.2 (3.4 if using lo-torq connection)

• Abrasive formations 2.5-3.0

(70)

• Fortunately for you API have worked the

problem!!! • Pages 39-44 of Spec 7G list the BSR of Connections by OD and ID of the collar

API BSR Charts

(71)

T.H.Hill BSR Tables

(72)

Stiffness Ratio

• The SR measures the stiffness of a connection in a transition between 2 types of pipe

• Based on field experience, in a transition from one collar or pipe to another the SR should not exceed

• 5.5 for routine drilling

• 3.5 for severe or rough drilling

(

)

(

4 4

)

4 4 upr upr lwr lwr lwr upr upr lwr

ID

OD

ID

OD

Z

SR

−

=

(73)

BHA Design Process

• Design the Collars

• Max OD DC which can be handled, fished and drilled with

• Excess BHA wt • WOB • Buoyancy • Safety factor • Connection Selection • BSR • SR • Torque capability

(74)

Exercise DP-05

On Seeyoulater land rig we find the following collars:

9” OD x 3” ID – 6 5/8” FH connection 8” OD x 3” ID – 6 5/8” REG connection 6 ¼” OD x 2 ¼” ID – NC46 connection

Given that we will drill a vertical 12 ¼” hole, with 9.5 ppg mud and 65000 pounds in a relatively hard formations, what API collar would you recommend?

What would your recommendation on BSR be for the connection chosen? Check your recommended DCs with your recommended BSR

What would be the SR between the DC and 5” DP be? Is it acceptable?

If not what would you do?

(75)

(76)

Drill Pipe Selection Principles

• Drill Pipe selection is governed by two major factors:

Size+Weight and Strength

• Usually the Drill Pipe with largest OD and ID is preferred

• Less pressure loss in the string

• More hydraulics available at the bit

• The Drill Pipe selection must address the following:

• Drill Pipe must allow to drill to TD

• Drill Pipe must support all weight below it (BHA+DP)

• Drill Pipe must provide Overpull capacity

• Drill Pipe must withstand slip crushing force

• Drill Pipe must resist burst and collapse loads

(77)

The greatest tension (working

load P_w) on the drillstring occurs

at the top joint at the maximum drilled depth Working Strength Drillcollars Drillpipe _L dp L_dc P

Axial Loads

Tension Design

(78)

S chlumb erg er P riv ate Tension Design

Total weight, T_surf, carried by the top joint of drillpipe when the drill bit is just off bottom ;

(

)

[

L

W

L

W

]

BF

T

_surf

=

_dp

×

_dp

+

_dc

×

_dc

×

L_dp = length of Drill Pipe

W_dp = weight of Drill Pipe per unit length L_dc= weight of Drill Collars

W = weight of Drill Collars per unit length

….(1) Drillcollars Drillpipe _L d p L_dc P

(79)

The drillstring is not designed according to the minimum yield strength!!! If Drill Pipe reaches yield:

• Drill Pipe can have permanent deformation.

To prevent deformation damage to drillpipe, API recommends the use of

maximum allowable design load ( Pa)

T_max = 0.9 x T_yield ….(2)

T_max = Max. allowable design load in tension , lb T_yield = theoretical yield strength from API tables , lb

0.9 = a constant relating proportional limit to yield strength

IPM Defines a tension Design factor of 1.1 be applied to design loads. These accomplish the same thing.

Tension Design

(80)

Margin of overpull is nominally 50-100k, or in the limit of the difference between the maximum allowable load less the actual load

Choice of MOP should consider

• Overall drilling conditions

• Hole drag

• Likelihood of getting stuck

• Slip crushing

• Dynamic loading

(81)

1. Determine max design load (T_max) :

(maximum load that drillstring should be designed for)

T_max = 0.9 x Minimum Yield Strength … lb Class of pipe must be considered

Drill Pipe Selection Parameters

(82)

S chlumb erg er P riv ate surf

- T

T

MOP

=

_max

3. Margin Of Overpull : Minimum tension force above

expected working load to account for any drag or stuck pipe. 2. Calculate total load at surface using

(

)

[

L

W

L

W

]

BF

T

_surf

=

_dp

×

_dp

+

_dc

×

_dc

×

….(3) ….(1)

Margin of Overpull

(83)

S chlumb erg er P riv ate dc dp dc dp yield dp

L

W

BF

W

MOP

T

L

−

×

−

×

=

0 .

9

4. The maximum length of Drill Pipe that can be used is obtained by combining equations 1 and 3 and solving for the length of Drill Pipe

….(4)

Margin of Overpull

(84)

S chlumb erg er P riv ate dc dp dc dp yield dp

L

W

BF

W

MOP

T

L

−

×

−

×

=

0 .

9

When the Drill String is stuck, (and it most certainly is if there is Overpull !) the buoyancy is lost!

….(4)

THINK OF STUCK PIPE!!!

When the Drill String is stuck, (and it most certainly is if there is Overpull !) the buoyancy is lost!

(85)

Exercise DP-06

• Drill Collars length : 600’ and weight in air is 150 lb/ft.

• MOP = 100,000 lbs.

• 5” / 19.5 lb/ft Premium G-105 DP with NC50 connections.

Calculate the maximum hole depth that can be drilled ? Assume BF= 0.85

• Carry out calculations without MOP and with MOP of

100,000 lb

• Use API - RP7G Tables for the values of Approximate

(86)

Slip Crushing Force

• Slips because of the taper try to crush the Drill Pipe. This

hoop stress is resisted by the tube, and this increases the overall stress in the steel

( )

(

for

dope

)

Friction

coeff

ArcTan

z

Taper

Slip

y

z

y

K

in

length

Slip

L

in

OD

Pipe

D

L

DK

L

DK

S

Stress

Tensile

Stress

Hoop

s s s t h

08 .

0 ;

)

(

)

45

27

9 (

;

)

tan(

/

1 ;

)

(

2

1

'' ' 2

=

+

=













+

=

µ

ο

(87)

• Generally expressed as a Factor

DP TUBE 12 in 16 in 2 3/8 1.25 1.18 2 7/8 1.31 1.22 3 1/2 1.39 1.28 4 1.45 1.32 4 1/2 1.52 1.37 5 1.59 1.42 5 1/2 1.66 1.47 6 5/8 1.82 1.59 SLIP LENGTH Horz to Tang Stress Ratio

Load

Axial

Equivalent

Stress

Tensile

Stress

Hoop

load

Working

*

=

Axial t h Load

P

S

P

=

(88)

Drill Pipe Selection Parameters

• You can only drill as far as you can set pipe in the slips.

• Different than overpull, this is based on working loads

dc dp dc dp T h yield dp

L

W

BF

W

S

T

L

−

×

=

9 .

0

(89)

A drill string consists of 600 ft of 8 ¼ in x 2 13/16 in drill collars and the rest is a 5 in, 19.5 lbm/ft Grade X95 drill pipe with NC50 connections. If the required MOP is 100,000 lb and mud weight is 10 ppg, calculate:

1) The maximum depth of hole that can be drilled when using (a) new and (b) Premium Drill Pipe. (MOP only)

2) What is the maximum depth that can be drilled taking into consideration slip crushing force for (a) and (b) above? To what hook-load does this correspond? What is the MOP in this case?

(90)

S chlumb erg er P riv ate •

Step 2

• Drill collars and bottom drillpipe act as the weight

carried by top section…effectively the drill collar

•

Step 1

• If we use different drill pipe, the weaker pipe goes on

bottom and stronger on top

• Apply equation to bottom drill pipe first

dc dp dc dp t dp

L

W

MOP

P

L

=

×

0 .

9 −

−

×

(91)

An exploration rig has the following grades of DP to be run in a 15,000 ft deep well :

• Grade E : New 5” OD –19.5 # NC 50

• Grade G : New 5” OD – 19.5# NC 50

It is desired to have an MOP of 50000 lbs on the grade E pipe. The total length and weight of DCs plus HWDP are 984 ft and 101,000 lb respectively. MW at 15,000’ = 13.4 ppg.

Calculate :

1. Max. length of E pipe that can be used.

2. Length of G pipe to use.

3. MOP for the G and E pipe.

4. Max weight on slips for the G and E pipe.

(92)

Other Loads

• Collapse under Tension

• Burst

• Other loads not covered here

• Shock Loads

• Bending Loads

• Buckling Loads

• Torsion

(93)

Biaxial Collapse

• The DP will collapse if:

External Pressure Load > Collapse pressure rating

• A Design factor of 1.15 is used:

External Pressure Load < Collapse rating / 1.15

• When the string is in tension, the Collapse rating is further

de-rated:

1 <

= K

P

Collapse Nonimal Collapse Biaxial

(94)

Biaxial Collapse

• Collapse load is worst when For dry test work where pipe

is run in empty

• Note the use of the Average Yield Point not minimum

Average Collapse al No Collapse Biaxial

Yp

ID

OD

Load

Z

P

*

)

(

7854

.

0

2

3

4

2 2 2 min

−

=

−

=

(95)

Biaxial Collapse

• For nominal Collapse

• Use D/t and correct formula Spec 7G Appendix A 3

• Use the results found in Table 3-6 RP-7G

• For OD and ID, use Table 1 RP-7G

• For Avg Yp Use Table in section 12.8 RP 7G

145,000 S 120,000 G 110,000 X 85,000 E Yp_Avg Grade

(96)

Exercise DP-10

• We are going to dry test a liner lap at 9,000 ft. We will run in

with a packer set in tension with 50,000 lb. We will run the

packer in on 5 in 19.5 #/ft Grade E premium grade DP. At the time of the test there will be nothing inside the drill pipe. The annulus will have 12.0 ppg mud. What is the collapse load on the bottom joint of DP?

(97)

DP-10

• Premium has 80% wall remaining

• Wall will be 0.8*(5-4.276)/2=0.2896 • ID will be 4.276” • OD will be 4.276+2*0.2896 =4.855”

1417

.

0

000 ,

85 *

)

276 .

4

855 .

4 (

7854

.

0

000 ,

50 *

)

(

7854

.

0

2 2 2 2

=

−

=

−

=

Z

Yp

ID

OD

Load

Z

Average

(98)

DP -10

• Nominal Collapse is 7,041

• Biaxial reduced collapse is 6,489

922 .

0

2 14167

.

0 14167

.

0 *

3

4

2

3

4

min 2 2 min

=

−

=

−

=

Collapse al No Collapse Biaxial Collapse al No Collapse Biaxial

P

Z

P

(99)

DP-10

• Collapse load is 9,000*0.052*12= 5616 psi

• Design load is 5616*1.15= 6,458

• Derated collapse is 6489, so we are ok

• Collapse design factor is 6489/5616=1.16

(100)

Burst

• Barlows formula applies

• Results are found in Spec 7G Table 3,5 & 7

• Burst will occur if internal pressure load > burst rating

D

t

Yp

(101)

Exercise DP11 - Burst Load Case

• Worst load case happens during DST operations in a gas

well. Pressure at surface is BHP- gas gradient with no backup

• In the last example assume we are performing a DST test

in the well at 9000 ft with BHP 200 psi less than the mud wt. What is the burst DF on the top of the Premium Grade E

(102)

DP-11

• From last Example 5” 19.5# E Premium

• OD=5, Wall = 0.2896” Yp= 75,000

• Burst = 8688 psi

• BHP= 120.0529,000-200=5,416 psi

• P Surf= 5416-900=4516 psi

(103)

Drill String Design Process-2

After the BHA Design is performed:

• Slip Crushing forces on DP

• Overpull tensile design at surface

• Lengths of DP Sections

• Burst Design Check

(104)

Drill String Design Factors

Tension DF_t Governs Max allowable tension on the system

SLB DF_t is 1.1

Margin of OverPull MOP Desired excess tensile capacity

over an above the hanging weight of the string at Surface. SLB MOP 50-100K

Excess BHA Wt Df_bha Amount of BHA in terms of Wt in

excess of that used to drill to assure all Compressive and

(105)

Torsion No Design Factor Required. Tool Joints are made

up to 60% of Torsional Capacity, and Tool joints are

designed to 80% of the tube Torsion Capacity. Thus if the design limits to tool joint make-up there is an adequate

design factor built into the system

Collapse DF_c Tube is de-rated to account for Biaxial

Tensile reduction and a design factor of is used SLB DF_c

is 1.1-1.15

(106)

Burst DF_b Simple burst is used with no allowance for axial

effects SLB DF_B is 1.0

Buckling DF_BIn Highly deviated wells it is possible to use

DP in compression, provided it is not buckled.

(107)

(108)

• Buoyancy is the weight of the displaced fluid

• Buoyancy is usually accounted for via BF

• Buoyancy is creating a hydrostatic effect: the

Pressure-Area Force

• The forces acting on a drillstring are the self-weight

and the hydrostatic pressure of the drilling fluid

• Buoyancy is creating a force acting at the bottom of

the drill string and placing the lower portion of the drill string in compression and reducing the hook load by HP x CSA

(109)

DP12 - Buoyancy

• We are running open ended DCs

9” x 3” – 192ppf

• The fluid in the well is 14 ppg

• The depth is 10000 ft

• What is the hook load with BF?

(110)

• A tube subjected to a load will bend

• Bent is a condition in which the

bending increases proportionally with load

• When a little increase in load will

result in large displacements, the tube is said to be buckling

• The tube may not necessarily be yielded as buckling does not

necessarily occurs plastically

• The load which produces buckling is

(111)

• Neutral Point of Tension & Compression: The point within a tube where the sum of the

axial forces are equal to zero

• Neutral Point of Bending:

The point within a tube where the sum of moments are equal to zero

The point within a tube where the average of the radial and tangential stress in the tube equals the axial stress

The point within a tube where the buoyed

weight of the tube hanging below that point is equal to an applied force at its bottom end

(112)

Neutral Point of Bending occurs where the effective hydrostatic force equals the compressive force in the drillstring.

(113)

Neutral point of bending is H = WOB / buoyed weight per foot of string

• In vertical wells, buckling will occur only below the neutral point of bending, hence the necessity to keep the buoyed weight of the BHA exceeding the WOB

• In deviated wells, buckling will not only occur below the neutral point of bending but also above the neutral point of bending when the