Drill String Design & BHA Design

IPM DPT

DPT Drill String and BHA design

Schlumberger Private

Drill String and BHA Design

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 • TH Hill DS-1 Drill String Design

Objectives 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.



•

Agenda 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



I.

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

D P

1. Transmit and support axial loads - WOB


The drillstring serves the three main following functions :

2. Transmit and support torsional loads - rpm 3. Transmit hydraulics to clean the hole and cool the bit.

DC


WOB

Drill String Components


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… DPT Drill String and BHA design

The Kelly/Top Drive


Strictly speaking, Kelly/ Topdrive are not components of the drill string; however, they provide the essential requirements for drilling a well: 1) Transmit rotation to the drillstring. 2) Provide access to the drilling fluid into the drillstring. 3) Support the weight of the string.


The Kelly

•

Supports the weight of the drillstring

•

Connects to the swivel and allow circulation thru pipe.

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 DPT Drill String and BHA design


The Kelly is the rotating link between the rotary table and the drill string. • Transmits rotation and weight-on-bit to the drillbit

Kelly Cock


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


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

Advantages over the kelly system: 1. Efficient reaming and back reaming. 2. Circulating while running in stands

hole or pulling out of hole in

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



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

Stabilizers



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!!) 5. Help preventing differential sticking and key seating.

Roller Reamers



Drill Pipe



Drill Pipe Function To serve as a conduit or conductor for drilling fluid To transmit the rotation from surface to the bit on bottom

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



Components

Drill Pipe Classification 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

For example a drill pipe could be - 5”, Range 2, G-105, 19.5ppf, New DPT Drill String and BHA design


1. Size

Drill Pipe Grades There are four grades of pipe commonly used today.

Min Yield

Avg / MaxYield

E or E-75

75,000

85,000 / 105,000

X or X-95

95,000

110,000 / 125,000

G or G-105

105,000

120,000 / 135,000

S or S-135

135,000

145,000 / 165,000



Grade

Mechanical Properties of Steel Young Modulus E = Stress divided by Strain = 30,000,000 Schlumberger Private

Stress & Strength Stress = Strength divided by Cross Section Area

Strain & stretch Strain = Stretch divided by original length


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

Ultimate Tensile Stress The stress which will break the steel



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.

Exercise DP-00



Used Drill Pipe Classification Unlike casing and tubing, which are normally run new, drill pipe is normally used in a worn condition. It therefore has Classes: No wear, has never been used

Premium:

Remaining wall not less than 80%.

Class 2: Class 3:


New:

Remaining wall not less than 70%. 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. DPT Drill String and BHA design

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

•The drill-pipe can have • Internal upsets (IU), ( OD stays the same ) • External upsets (EU), ( ID stays the same ) • Internal and External Upsets (IEU).



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

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.

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. DPT Drill String and BHA design


Nominal Weight - Refers to an obsolete standard. ( Weight of Range I pipe with connections ) Is used today to refer a class of Drill pipe.

Calculating Approximate Weights Wt/ft =

Wt DP Adjusted ×29.4 + Wt ToolJt Approx 29.4 +L ToolJtAdj



Wt/ft =

approx. adj. wt.DP ×29.4 + approx. wt. tool jt 29.4 + tool jt adjusted length

Calculating Approximate Weights Wt DP Adj

Nom upset Wt =Tube Wt + 29 .4

….(1)

Data from Table 7API 5D

)

(

)

− 0 .501×d ×(D − DTE ) 2

L= combined length of pin and box (in) d= inside diameter of pin (in)

….(2)

D= outside diameter of pin (in)

DTE= diameter of box at elevator upset (in)

Data from Spec 7 Fig 6 Table 7

LTool Jt Adj =

L + 2 .253×(D − DTE ) ft 12

….(3) Datat from Spec 7 Fig 6 Table 7



(

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

Exercise DP-01

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

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. DPT Drill String and BHA design


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 internallyexternally upset. ( IEU ).

DP Data from Table 7 Spec 5d



DP Data from Table 7 Spec 7



API RP 7G • Table 1-3 New Pipe Data • Table 4-5 Premium Pipe Data Schlumberger Private

• 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


Tool Joints 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 ) DPT Drill String and BHA design


•

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 ?

Make-Up Torque Charts



Drillstring Connections 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

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

5/8” GAUGE POINT PITCH DIAMETER

If the pitch diameter is 5.0417 in Æ This is an NC50 connection Multiply 5.0417 by 10 → 50.417 Choose first two digits → 50 Hence NC 50



Connection Number is Pitch dia*10 truncated to two digits

NC Drillstring Connections

• 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”) • 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.

Connection Interchangeability NC 38 NC 40 NC46

NC50

2-3/8

3-1/2

4

4-1/2

4-1/2

5

2-7/8

Int Flush

IF

Full Hole Extra Hole

FH XH

2-7/8 3-1/2

Dbl Streamline

DSL

3-1/2

Slim Hole SH 2-7/8 Ext Flush EF

4

3-1/2

4-1/2 4

5-1/2

4-1/2

4-1/2



NC 26 NC 31

Drill Collars



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

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 DPT Drill String and BHA design


Functions To put weight on bit (WOB) To keep the drill string from buckling

More functions of Drill Collars 1. Protect the Drill string from Bending and Torsion 2. Control direction and inclination of wells Schlumberger Private

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 DPT Drill String and BHA design

More Types of Drill Collars Slick Drill Collar

Spiral Drill Collar

2. In areas where differential sticking is a possibility spiral drill collars and spiral HWDP should be used in order to minimize contact area with the formation.



1. Both slick and spiral drill collars are used .

Drill Collars Strapping length OD slip recess

Well# Date: Rig: BHA#: Hole Size

Item Bit Bit Sub 9 1/2" Drill Collar Stab 9 1/2" Drill Collar 9 1/2" Drill Collar 9 1/2" Drill Collar

connection

TRG 1 28-Jul-03 IDPT 1 26"

Sl # 1234 SL 235 9546 237689 9503 9521 9520

Bit # Sl # Type Manuf Jets

ID 3 1/8" 3 1/8" 3 1/8" 3 1/8" 3 1/8" 3 1/8"

OD 26" 9 1/2" 9 1/2" 9 1/2" 9 1/2" 9 1/2" 9 1/2"

FN

0.67 0.93 0.78 0.95 1.03

Pin 7 5/8" R 7 5/8" 7 5/8" 7 5/8" 7 5/8" 7 5/8"

R R R R R

Box 7 5/8 R 7 5/8 R 7 5/8 R 7 5/8 R 7 5/8 R 7 5/8 R

Length 0.75 1.01 8.96 2.36 9.01 9.04 8.99

1 1234 atm 234 Hughes 20-20-20

Remarks New



elevator Fish neck recess

I D

API Drill Collar Sizes ID Range

2 7/8 3 3 1/8 3 1/4 3 1/2 3 3/4 4 4 1/8 4 1/4 4 1/2 4 3/4 5 5 1/4 5 1/2 5 3/4 6

1 - 1.5 1 - 1.5 1 - 1.5 1 - 1.5 1 - 1.5 1 - 1.5 1 - 2.25 1 - 2.25 1 - 2.25 1 - 2.25 1.5 - 2.5 1.5 - 2.5 1.5 - 2.5 1.5 - 2.8125 1.5 - 3.25 1.5 - 3.25

Weight Range ppf 16 - 19 18 - 21 20 - 22 22 - 26 27 - 30 32 - 35 29 - 40 32 - 43 35 - 46 41 - 51 44 - 54 50 - 61 57 - 68 60 - 75 60 - 82 68 - 90

OD

ID Range

6 1/4 6 1/2 6 3/4 7 7 1/4 7.5 7.75 8 8 1/4 8 1/2 9 9 1/2 9 3/4 10 11 12

1.5 - 3.5 1.5 - 3.5 1.5 - 3.5 1.5 - 4 1.5 - 4 1.5 - 4 1.5 - 4 1.5 - 4 1.5 - 4 1.5 - 4 1.5 - 4 1.5 - 4 1.5 - 4 1.5 - 4 1.5 - 4 1.5 - 4

Weight Range ppf 72 - 98 80 - 107 89 - 116 84 - 125 93 - 134 102 - 144 112 - 154 122 - 165 133 - 176 150 - 187 174 - 210 198 - 234 211 - 248 225 - 261 281 - 317 342 - 379



OD

Drill Collar Connections Characteristics • DC connections are rotary shouldered connections and can mate the various DP connections • 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 DPT Drill String and BHA design


• The shoulder provide the only positive seal against fluid leakage

Drill Collar Connections Stress Relief Features • Stresses in DC connections are concentrated at the base of the pin and in the bottom of the box (stronger)

• 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 DPT Drill String and BHA design


• 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.

Stress Relief Pin Feature



Stress Relief Pin & Box Features



Drill Collar Connections • The stress relief groove is to mitigate the fatigue cracks where the face and threads would have otherwise joined

• 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. • The Low-Torque face is to increase the compressive stress at normal M/U torque above that of a regular face DPT Drill String and BHA design


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

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 large OD connections.


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 makeup torque for the connections in the hole to avoid over tightening connections which can lead to damage of seals.

Torque Limits for DC PAC H-90 API NC

DC< 7 in DC>7 in 79.5% N/a 51.1% 56.2% 56.8% 62.5%



• API recommended makeup torque for connections is a percentage of the total torsional yield of the connection

M/U Torque as % of total torque

Make Up Torque Tables for DCs



Heavy Weight Drill Pipe



Heavy Weight Drill Pipe

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 DPT Drill String and BHA design


Design Heavier wall and longer tool joints Center wall pad Also available in spiral design

Heavy Weight Drill Pipe Characteristics 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 buckle DPT Drill String and BHA design


•

Heavy Weight Drill Pipe HWDP in Compression? •

HWDP can be run both in tension and in compression

•

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



BUT!!!


II.




Bottom Hole Assembly Selection

•


•




I.

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

• 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



• More weight available for WOB • Greatest stiffness to resist buckling and smooth directional tendencies • Cyclical movement is restricted due to tighter Clearances

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 axial loads is within the BHA – with a safety factor of 15%

BHA Design Drill Collar Weight & Neutral Point

Tension

Neutral point Compression

Design WOB

Max Available Wt = 1.15 Max Working Wt Neutral Point (NP) to tension should be in drill collars

WOB



DF for excess BHA=1.15

BHA Design Procedure For Selecting Drill Collars: 1. Determine the buoyancy factor for the mud weight in use using Schlumberger Private

the formula below:

BF = 1- (MW/65.5) where BF =Buoyancy Factor, dimensionless MW =Mud weight in use, ppg 65.5 =Weight of a gallon of steel, ppg


BHA Design 2. Calculate the required collar length to achieve the desired weight on bit: Schlumberger Private

DC Length = 1.15* WOB / (BF*Wdc) 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. DPT Drill String and BHA design

BHA Design 3. For directional wells:

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



DC Length = DC Length Vertical / Cos I

Exercise DP-03 Number And Size Of Drill Collars

Hole deviation = 0° Mud density

= 12 ppg



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

Stiffness

• Stiffness Coefficient : = Moment of Inertia x Young’s Modulus of Elasticity = л (OD4 – ID4) / 64 x 30.000.000



• 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

Exercise DP-04



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

Z box 32 D BSR = = 4 4 Z pin π ( R − d ) R 32 (D4 − b4 ) Z box BSR = = 4D 4 Z pin ( R − d ) R

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. . d= inside diameter or bore.



π (D4 − b4 )

Section Modulus for Connections



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.


BSR in Connections


This table is from T.H. Hill & Associates Inc. Standard DS-1.


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 2.5-3.2 (3.4 if using lo-torq connection) • Abrasive formations 2.5-3.0 • New DCs 2.75 – more wear resistant



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

API BSR Charts


• 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


T.H.Hill BSR Tables



Stiffness Ratio

( (

4 4 ODupr ODlwr − IDlwr

Z lwr SR = = 4 4 Z upr ODlwr ODupr − IDupr

) )

Note: Stiffness ratios are calculated using tube ODs & IDs, not connections. DPT Drill String and BHA design


• 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

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 • Stabilization and other directional requirements

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

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? What would be your final BHA? Length? Buoyed Weight?



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?


II.





•


•




I.

Drill Pipe Selection Principles • Drill Pipe selection is governed by two major factors: Size+Weight and Strength

• 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 Drill Pipe might have to work in H2S environment DPT Drill String and BHA design


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

Axial Loads P Tension Design

Drillpipe

Ldp

Drillcollars

Ldc



The greatest tension (working load Pw) on the drillstring occurs at the top joint at the maximum drilled depth

Working Strength

Drill Pipe Selection Parameters Tension Design Total weight, Tsurf, carried by the top joint of drillpipe when the drill bit is just off bottom ;

]

….(1) Drillpipe

Ld p

Ldp = length of Drill Pipe Wdp = weight of Drill Pipe per unit length

Drillcollars Ldc

Ldc = weight of Drill Collars Wdc = weight of Drill Collars per unit length DPT Drill String and BHA design


[

Tsurf = (Ldp ×W dp + Ldc ×W dc ) × BF

P

Drill Pipe Selection Parameters Tension Design The drillstring is not designed according to the minimum yield strength!!! If Drill Pipe reaches yield: • Drill Pipe can have permanent deformation.

Tmax = 0.9 x Tyield

….(2)

Tmax = Max. allowable design load in tension , lb Tyield = 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. Do not double dip! DPT Drill String and BHA design


To prevent deformation damage to drillpipe, API recommends the use of maximum allowable design load ( Pa)

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

Choice of MOP should consider • Overall drilling conditions • Hole drag • Likelihood of getting stuck • Slip crushing • Dynamic loading


Drill Pipe Selection Parameters Margin of Overpull 1.

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



Determine max design load (Tmax) : (maximum load that drillstring should be designed for)

Drill Pipe Selection Parameters Margin of Overpull 2. Calculate total load at surface using

]

3. Margin Of Overpull : Minimum tension force above expected working load to account for any drag or stuck pipe.

MOP = Tmax - Tsurf

….(3)



[

Tsurf = (Ldp ×W dp + Ldc ×W dc ) × BF

….(1)

Drill Pipe Selection Parameters Margin of Overpull

Ldp =

T yield ×0 .9 − MOP W dp × BF

W dc − × Ldc ….(4) W dp



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

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

W dp × BF

W dc − × Ldc W dp ….(4)

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



Ldp =

T yield ×0 .9 − MOP

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 Weight (Wdp) and for Minimum Yield Strength

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 Schlumberger Private

2

Hoop Stress S h DK  DK   = 1+ +  Tensile Stress St 2 Ls  2 Ls  D = Pipe OD (in) ; Ls = Slip length (in )

K = 1 / tan( y + z ) ; y = Slip Taper (9ο 27 ' 45'' )

z = ArcTan( µ ) ; µ = coeff Friction (0.08 for dope )


Slip Crushing Force • Generally expressed as a Factor

PLoad

Sh = PAxial St

Horz to Tang Stress Ratio DP SLIP LENGTH TUBE 12 in 16 in 2 3/8 2 7/8 3 1/2 4 4 1/2 5 5 1/2 6 5/8

1.25 1.31 1.39 1.45 1.52 1.59 1.66 1.82

1.18 1.22 1.28 1.32 1.37 1.42 1.47 1.59



Hoop Stress Working load * = Equivalent Axial Load Tensile Stress

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



L dp

T yield × 0 . 9 Sh W dc ST = − × L dc W dp × BF W dp

Exercise DP-07 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:

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?



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

Mixed String Design • Step 1 • If we use different drill pipe, the weaker pipe goes on bottom and stronger on top

Ldp

Pt ×0 .9 − MOP W dc = − × Ldc W dp W dp

• Step 2 • Drill collars and bottom drillpipe act as the weight carried by top section…effectively the drill collar • Apply the equation for top drill pipe last DPT Drill String and BHA design


• Apply equation to bottom drill pipe first

Exercise DP - 09 Mixed Drill Pipe 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

Calculate : 1. 2. 3. 4.

Max. length of E pipe that can be used. Length of G pipe to use. MOP for the G and E pipe. Max weight on slips for the G and E pipe.



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.

Other Loads

• • • • •


• Collapse under Tension • Burst • Other loads not covered here Shock Loads Bending Loads Buckling Loads Torsion Torsion with Simultaneous Tension


Biaxial Collapse

PBiaxial Collapse PNonimal Collapse

= K <1



• 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:

Biaxial Collapse • Collapse load is worst when For dry test work where pipe is run in empty

PNo min al Collapse

4 − 3Z 2 − Z = 2

Load Z= 2 2 0.7854(OD − ID ) * Yp Average • Note the use of the Average Yield Point not minimum



PBiaxial Collapse

Biaxial Collapse

Grade E X G S

YpAvg 85,000 110,000 120,000 145,000 DPT Drill String and BHA design


• 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

Exercise DP-10

• New 5” Gr E 5” OD, 4.276” ID, Avg Yp= 85,000 psi



• 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?

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”

Load Z= 2 2 0.7854(OD − ID ) * Yp Average 50,000 Z= 2 2 0.7854(4.855 − 4.276 ) * 85,000 Z = 0.1417 DPT Drill String and BHA design

DP -10 PBiaxial Collapse PNo min al Collapse

4 − 3Z 2 − Z = 2 Schlumberger Private

4 − 3 * 0.14167 − 0.14167 = 2 PBiaxial Collapse = 0.922 PNo min al Collapse 2

• Nominal Collapse is 7,041 • Biaxial reduced collapse is 6,489 DPT Drill String and BHA design

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

• IPM Specified Collapse design factor is 1.1-1.15



• • • •

Burst • Barlows formula applies

• Results are found in Spec 7G Table 3,5 & 7 • Burst will occur if internal pressure load > burst rating



PBurst

2 * Yp * t = D

Exercise DP11 - Burst Load Case

• 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



• Worst load case happens during DST operations in a gas well. Pressure at surface is BHP- gas gradient with no backup

DP-11 • From last Example 5” 19.5# E Premium • OD=5, Wall = 0.2896” Yp= 75,000

• Design factor = 8688/4516=1.92



• Burst = 8688 psi • BHP= 12*0.052*9,000-200=5,416 psi • P Surf= 5416-900=4516 psi

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 • Collapse under tension Design check

Drill String Design Factors Tension DFt Governs Max allowable tension on the system SLB DFt is 1.1

Excess BHA Wt Dfbha Amount of BHA in terms of Wt in excess of that used to drill to assure all Compressive and torsional loads are kept in the Collars, SLB Dfbha is 1.15



Margin of OverPull MOP Desired excess tensile capacity over an above the hanging weight of the string at Surface. SLB MOP 50-100K

Drill String Design Factors

Collapse DFc Tube is de-rated to account for Biaxial Tensile reduction and a design factor of is used SLB DFc is 1.1-1.15



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

Drill String Design Factors Burst DFb Simple burst is used with no allowance for axial effects SLB DFB is 1.0



Buckling DFB In Highly deviated wells it is possible to use DP in compression, provided it is not buckled.


II.





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•




I.

Buoyancy 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 DPT Drill String and BHA design


•

DP12 - Buoyancy

• What is the hook load with BF? • What is the hook load with Pressure Area Force?



• We are running open ended DCs 9” x 3” – 192ppf • The fluid in the well is 14 ppg • The depth is 10000 ft

Bending & Buckling 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

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The tube may not necessarily be yielded as buckling does not necessarily occurs plastically

•

The load which produces buckling is called the Critical Buckling Load


•


Neutral Points •

Neutral Point of Tension & Compression:

The point within a tube where the sum of the axial forces are equal to zero Schlumberger Private

•

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 DPT Drill String and BHA design

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



Buckling 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 compressive force in the drillstring exceeds a critical load

(OD 4 − ID 4 ) * BF * (OD 2 − ID 2 ) * sin(α ) Fcrit = 1617 Dhole − ODtooljt



•

DP13 – Max WOB in inclined holes



Drillstring Design Now you should be able to describe: Functions of Drill Pipe , Drill Collars and BHA selection

•

Grades of Drill Pipe and strength properties

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Thread types and tool joints

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Drill collar weight and neutral point

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Bending Stress Ratios and Stiffness Ratios

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Margin of overpull – Slip crushing force

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Basic design calculations based on depth to be drilled.

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Functions of stabilizers and roller reamers

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Critical Buckling force and Neutral Point of Bending



•

Drill String Design & BHA Design

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