3 3 DS rig WH pandadesign

• ObjectivesAt the end of this lecture YOU will be able to: •List drillstring components and describe functions •Define grades and strength properties •Calculate drillcollar weight for

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• Course Contents

1 Objectives

2 Functions of drillstring components

3 Grades and strength properties of drillpipe

4 Drillcollar weight and neutral point

5 Drillstring design methods incl MOP

6 Drillstring damage and inspection

7 Rig sizing considerations

8 Wellhead components

9 Plug and Abandon considerations

DS Design, Rig Sizing WH and P&A

• Objectives

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

•List drillstring components and describe functions

•Define grades and strength properties

•Calculate drillcollar weight for required WOB

•Design drillstring in vertical wells

•Describe drillstring damage and inspection methods

•Perform rig sizing calculations

•List wellhead functions and components

•Describe P&A considerations

DS Design, Rig Sizing WH and P&A

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© COPYRIGHT 2001, NExT All Rights Reserved

Drillstring Design

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

The drillstring serves the following functions :

1 Transmits rotation to the drillbit

2 Exerts weight on the bit

3 Guides and controls the trajectory of the bit,

4 Allows fluid circulation

WOB DC

D P

Drillstring Design

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Basic components of drillstring:

Functions of Drillstring

Drillstring Design

  Strictly speaking, Kelly/

Topdrive are not components of the drill string However, the Kelly/

top drive provide the essential requirement for rock breakage (drilling)- namely rotation  

The Kelly/Top Drive

Components

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

• Supports the weight of the drillstring

• Connects the swivel to the uppermost length of

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

The lower Kelly cock operates manually.

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

Components

Kelly cock

Advantages over the kelly system:

1 Circulating while 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 The top drive functions in the same way as the kelly

Top Drive

Components

The grade of drill pipe describes the minimum yield strength of the pipe.

In most drillstring designs, the pipe grade is increased for extra strength rather than increasing the pipe

weight

Drill Pipe Grades

GRADE Minimum Yield

Stress (psi)

Letter Alternate Designation  

Drill pipe is classified to account for the degree of wear

API RP7G - DP Classes

New: No wear, has never been used

Premium: Uniform wear and a minimum wall thickness of

80% of new pipe

Class 2: Drill pipe with a minimum wall thickness of

70% with all the wear on one side so long as

the cross sectional area is the premium class

Class 3: Drill pipe with a minimum wall thickness of

Drill Pipe Classification

Tooljoints

A drillpipe joint is an assembly of three components:

• drillpipe with plain-ends and

• one tooljoint at each end (Pin & Box) All API tooljoints have a minimum yield strength of 120,000 psi regardless of the grade of the drillpipe they are used on (E, X, G, S)

API sets tooljoint torsional strength at 80% of the tube torsional strength : this is the torsional strength ratio of 0.8. 

Make up torque is determined by pin ID or box OD The make up torque is 60% of the tool joint torsional capacity.

Drill Pipe

d) IF

XH PAC OH SH DSL

c) SST

b) REG FH

a) NC

V-038R

V-040 V-050

Thread Styles and Forms

Drillstring Connections

gauge point, multiplied by 10.

5/8”

GAUGE POINT PITCH DIAMETER

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

Drillstring Connections

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 31/2” pipe

There are 17 NC’s in use : NC-10 (1 1/16”) through NC-77 (7 3/4”)  NC-23 and above use the V-38R thread form.

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

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

Hence NC 50

Drillstring Connections

Predominant component of the BHA

Both slick and spiral drill collars are used

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

First section of the drillstring to be designed

The length and size of the collars will affect the grade, weight and dimensions of the drill pipe to be used.

DRILL COLLAR SELECTION

Drill Collars

Has the same OD as a standard drill

pipe but with much reduced inside diameter ( usually 3”) and has an extra tool joint

It is used between standard drill pipe

and drill collars to provide a smooth transition between the section

module of the drillstring components. 

Slick or Spiral

HEAVY-WALLED DRILLPIPE (HWDP) 

HWDP

All wells whether vertical or deviated require careful design of

the BHA to control the direction of the well in order to achieve the target objectives

The main means by which directional control is maintained on a

well is by the effective positioning of stabilisers within the BHA

STANDARD BHA CONFIGURATIONS

BHA Design

• Pendulum assembly

Types of Rotary BHAs

BHA Design

DRILL COLLAR

DRILL COLLAR

DRILL COLLAR

DRILL COLLAR

DRILL COLLAR DRILL

COLLAR

DRILL COLLAR

DRILL COLLAR

DRILL COLLAR

DRILL COLLAR

DRILL COLLAR

DRILL COLLAR

DRILL COLLAR

DRILL COLLAR

DRILL COLLAR

DRILL COLLAR STAB

STAB

STAB STAB

STAB STAB

STAB

STAB STAB

STAB STAB

STAB

STAB

STAB STAB

SHOCK SUB

SHOCK SUB

SHOCK SUB

SHOCK SUB

SHOCK SUB

SHOCK SUB

FULL GAUGE STAB

FULL GAUGE STAB

FULL GAUGE STAB

FULL GAUGE STAB PONY

PONY

PONY DRILL

COLLAR

1 Drill collars provide weight on bit as they can be run in

compression while keeping the drill pipe in tension

compared to drill pipe

constant tension in the drill pipe

Drillcollar as Weight

BHA Design

buoyed weight on the collars

Minimum Drillcollar Weight & Neutral Point

BHA Design

Tension

Neutral point

Design WOB

WOB WOB

BHA Design

Drillcollar Weight & Neutral Point

Procedure For Selecting Drillcollars:

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

BF = 1- (MW/65.5)

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.

BHA Design

Procedure For Selecting Drillcollars:

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

BHA Design

Procedure For Selecting Drillcollars:

Determine the size and number of drill collars required to provide a weight-on-bit of 55,000 lbf assuming

Hole deviation = 0°

Mud density = 12 ppg

Example : Number And Size Of Drillcollars

BHA Design

= 67,319 x 1.15 = 77,416 lbf

BHA Design

Assume that the available drillcollar size is OD/ID, 9/3”” From calculations, the weight per foot for the size is 192 lb/ft

(Most drillcollars come in 30 ft lengths) One drillcolar weighs= 30*192=5,760 lb

= 13.54

==> 14 Joints

Solution cont’d

Design Parameters

API RP7G - Tables

• Table 1-3 New Pipe Data

• Table 4-5 Premium Pipe Data

• Table 6-7 Class Two Pipe Data

• Table 8 Tooljoint Data

• Table 10 Make-up Torque Data

• Table 13 DC Weight, 14 M/U Torque

• Fig 26-32 Drill Collar BSR Data

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

Tensile Forces include:

–Buoyant weight carried–Shock loading

–Bending forces

Note P is the total weight of the submerged drillstring It is highly dependent on mud weight The higher the mud weight the

less weight seen at surface at the Martin Decker The influence of

mud weight is shown through the term BF: buoyancy factor

API recommends the use of BF

Design Parameters

Tension Design 

The drillstring is not designed to its maximum strength: yield

strength If drillpipe reaches yield:

1 Drillpipe will have total deformation made up of elastic

and plastic (permanent) deformation

2 Permanent stretch will remain in drillpipe

3 It may be difficult to keep drillpipe straight

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

maximum allowable design load ( Pa)

Pa = Max allowable design load in tension , lb

Pt = theoretical yield strength from API tables , lb0.9 = a constant relating proportional limit to yield strength

Design Parameters

Tension Design 

MOP = Pa – P ……… (3)

DF = Pa / P …………(4)

Choice of MOP or SF should consider

– Overall drilling conditions– Hole drag

– Likelihood of getting stuck– Slip crushing

– Dynamic loading

Margin of Overpull

Design Parameters

1 Determine max design load (Pa) :

(maximum load that drillstring should be designed for)

Pa = 0.9 x Minimum Yield Strength … lb

Class of pipe must be considered

Design Procedure

Margin of Overpull

P - P

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

P = dp × dp + dc × dc ×

Design Procedure

dc dp

dc dp

t

W

W BF

• Drillcollars length : 600’ and weight in air is 150 lb/ft

• MOP = 100,000 lbs

• 5” / 19.5 lb/ft Premium G105 DP with NC50 connections

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

– Carry out calculations with and without MOP – Use API - RP7G Tables for the values of Approximate

Weight (Wdp) and for Minimum Yield Strength

Example: Single Grade of Drillpipe

Design Procedure

Actual Load carried ( P)

P= 0.85 [ 21.92 x Ldp + 150 x 600] … (2) (RP7G T9)

ft x

x x

962 ,

16 85

0 92 21

600 150

85 0 535 , 392

Max Drilling Depth = Ldp + Ldc = 16,962 + 600 = 17,562 ft

Maximum design load ( Pa)

Pa = 0.9 x Minimum Yield Strength

Pa= 0.9 x 436, 150 = 392,535 lb …(1) (RP7G – T4)

For zero MOP (1) = (2)

Solution

Design Procedure

Example  

A drill string consists of 600 ft of 8 ¼ in x 2.13/16 in drillcollars and the rest is a 5 in, 19.5 lbm/ft Grade X95 drillpipe If the required MOP is 100,000 lb and mud weight is 10 ppg, calculate the maximum depth of hole that can be drilled when (a) using new drillpipe (b) using Premium drillpipe having a yield strength (Pt) of 394,000 lb

Solution  

(a) Weight of drill collar per foot is 

where, ρs = density of steel = 489.5 lbm/ft

A = cross-sectional area (in)

(Note : From API Tables, weight of drill collar = 161 lbm/ft)

= 160 6 lbm ft/ 2444

Design Procedure

The maximum hole depth that can be drilled with a new drillpipe

of Grade X95 under the given loading condition is

(b) Now Pt = 394 600 , lb :

• Step 2

– Drillcollars and bottom drillpipe act as the weight carried by

top section…effectively the drillcollar

– Apply the equation for top drillpipe last

and stronger on top

Mixed Drillpipe Design

MOP in a deviated well deviated

( ) lbf W

Fs = 1500 × dp

Shock Loading The additional tensile force generated by shock loading is given by

( ) lbf OD

W

Fb = 63 × θ × dp×

BendingThe additional tensile force generated by bending is given by

Other Tensile Forces

Design Procedure

Design Factor

• Design Factor of 1.6 should be applied to

the tension load due to the typical used nature of the drill pipe and to account for any shock loading of the pipe when setting slips.

• If the shock loading is quantified and

included in the load calculation, a safety factor of 1.3 can be used.

• Nominal weight of drillpipe is always less than the actual weight of the drillpipe plus tooljoints due to;

• extra weight added by the tooljoint and

•extra metal added at pipe ends to increase thickness

•This increased thickness is called “Upset” and is used to decrease the frequency of pipe failure at the point where the pipe meets the tooljoint

•The drillpipe can have internal upsets (IU), external upsets (EU) and internal and external upsets (IEU) follows:

Weight of drillpipe and tooljoints

Drill Pipe Adjusted Weights

•When making up and breaking out, the tool joint must be as close to the rotary slips as is possible to avoid bending the pip

•There is a maximum allowable height for the tool joint above the slips : below this height the pipe will not bend when the maximum recommended torque is applied to the tool joint Fours factors contribute to this limit

- Angle of separation between the make-up and break-out tong.

- Length of the tong arm Lt The shorter the arm, the lower the

maximum height

- Maximum recommended torque for the connection T

Where :

•Hmax;height of tool joint shoulder above slips (ft).

•Y’;minimum tensile yield stress of pipe (psi).

•Lt-length of tong arm (ft).

•T-torque applied to tool joint (line pull in ft.lbs).

•D/d-outside and Inside Diameter of tooljoint

Tooljoint Make-up

T D

d D

x xL xY

.

) (

00348

d D

x xL

xY

)(

00491

• Drillpipe fatigue wear generally occurs because the outer wall of the pipe in a dogleg is stretched resulting in additional tension loads

• As the pipe is rotated one half cycle the stresses change to the other side of the pipe.

•For example during one rotation

of the pipe the stress at any point may change from 50,000 psi to -20,000 psi and back to 50,000 psi.

Fatique Damage due to Cyclic Loading

Drill String Failure

1 Washouts can also develop

due to cracks developing within the drillpipe due to vibrations or cyclic loading

2 Washouts are usually detected

by a decrease in the standpipe pressure, between 100-300 psi over 5-15 minutes

3 This is easily distinguished

from sudden drops in pump pressure which could be due

to a lost jet nozzle or some surface leak.

Washouts

Drill String Failure

• Magnetic Inspection : MPI / Upset

Inspection

• Ultrasonic End Area Inspection

• Blacklight Magnetic Inspection

Drill String Inspections

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Rig Selection & Sizing

Rig Sizing

– A drilling rig is a device used to drill, case and

cement water, oil and gas wells,

– The correct procedure for selecting and sizing a

drilling rig is as follows:

• Design the well,

• Establish the various loads to be expected during

drilling and testing and use the highest This point establishes the DEPTH RATING OF THE RIG,

• Compare the ratings of several rigs with the design

load,

• Select the appropriate rig.