Casing/Tubing design manual october 2005 Chevron

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Casing/Tubing Design Manual 8-3

April 2007

8.2.4 Burst (Full-Yield)

A design factor of 1.20 for tube burst design when full-yield burst strength is used

in tube design should permit a reasonable design for sweet service condition

only.

The full-yield burst strength of the tube is based on the full yield of the tube by

the burst pressure under multi-dimensional stress state. The greater the tube wall

thickness, the higher the heavy wall full-yield burst pressure will be than the API

burst pressure and von Mises initial yield burst pressure. The same conservatism

in burst design is employed with the use of specified minimum yield strength and

the downrating of the tube wall thickness by the maximum allowable 12.5%.

However, this tube burst criterion should only be used for sweet service

condition.

8.2.5 Tension/Compression

The tension/compression design factor is applied to the lesser of the API formula

for yield of the pipe body cross section in tension or the manufacturer's

connection rating. The larger value of the design factor (1.60) is a direct reflection

of the uncertainty of old thread design and tension load estimation. The newer

thread designs incorporate negative thread load flank angles and inter-thread

pressure relief to counter trapped thread lubricant and fluid pressures and,

therefore, more confidence can be placed in both the rating and consistency of a

thread’s performance. Nevertheless, the combination of older thread designs,

load uncertainty, particularly for dynamic loads, and the complexity of threaded

connections suggests that the recommended value of tension design factor

should only be lowered in situations of extreme confidence.

8.2.6 Exception

There exists at least one exception for which the recommended design factors

should be abandoned: wear. As discussed in Chapter 4 – Tube Performance

Properties, wear will reduce the resistance of the cross section to both internal

and external pressure differential. Should offset wells with similar wellbore

trajectories and drilling environments suffer wear or should predictions made by

using wear software indicate significant loss of wall thickness, this effect should

be accounted for either by lowering performance properties or by increasing

corresponding design factors.

8.3 HPHT Wells

For all tubular applications, design of HPHT wells uses the same load scenarios

with the following exceptions:

8-4 Casing/Tubing Design Manual

April 2007

• The constant methane gradient of 2.26 kPa/m (0.1 psi/ft) is replaced by the

Young-Nagy equation

given the following input variables:

Formation pressure as a mud weight in ppg,

EMW

Specific gravity of the gas column relative to air,

True vertical depth in ft,

The average gas gradient, in psi/ft,

, is calculated from the formula:

zSG

EMWg

/260161.00032.0

−

. (8-1)

The Young-Nagy equation is empirical. The proper units must be used in the

calculation with conversion to another unit system following the calculation.

If the gas composition is unknown, a default value for

of 0.65 can be used. If

the gas composition is known, the specific gravity can be calculated from the

average molecular weight as,

SG Average MolecularWeight= /29

, (8-2)

where the average molecular weight is obtained from the mole percent

composition and compound molecular weights given in Table 8-2.

Table 8-2. Molecular Weights for Specific Gravity Calculation

Compound Molecular Wt. Compound Molecular Wt.

Methane 16.04 Pentane 72.15

Ethane 30.07 Carbon Dioxide 44.01

Propane 44.09 Nitrogen 28.02

Butane 58.12 Hydrogen Sulfide 34.08

Figure 8-1 illustrates the behavior of the Young-Nagy equation in computing gas

gradient for representative depths and reservoir pressures expressed as an

equivalent mud weight. At shallower depths, the correlation yields unrealistic

answers, and the constant values suggested earlier should be used.

The Young-Nagy equation was constructed from a simulation of thousands of shut-in

wells with the best available software model. A curve fit to the gas gradients found the

dominant parameters resulting in the equation given in the text. The temperature gradient

was found not to be a major parameter, a significant simplification.

Casing/Tubing Design Manual 8-5

April 2007

5000

10000

15000

20000

25000

-0.2 -0.1 0 0.1 0.2

Gas Gradient (psi/ft)

TVD (ft)

10 ppg

14 ppg

18 ppg

Figure 8-1. Behavior of the Young-Nagy Equation for a Gas with Specific Gravity

0.70

Tube material yield stress reduction under high temperature needs to be

considered to calculate the reduced tube burst strength.

8.4 Casing Design Criteria

The following tables, Table 8-3 and Table 8-4, summarize the drilling casing

(conductor/surface casing, intermediate casing/liner) design criteria and the

production casing and tubing design criteria, including loads, tube strength, and

design factor.

8-6 Casing/Tubing Design Manual

April 2007

Table 8-3. Drilling Casing and Liner Design Criteria

String Conductor and Surface Casing Intermediate Casing/Liner

Criteria Loading Tubular strength Design factor Loading Tubular strength Design factor

Burst 1. Gas kick

Internal: Full gas column

(gas gradient 0.10 psi/ft)

External: Formation

pressure

2. Trapped fluid

(deepwater wells only)

Internal: Drilling mud plus

annulus fluid expansion

pressure

External: Drilling mud plus

annulus fluid expansion

pressure

1. Sweet-service*

API burst strength

or VME burst

strength or

Full-yield burst

strength

2. Sour-service**

API burst strength

or VME burst

strength

(Burst strength

reduction on high

temperature, tubular

wall loss, and axial

load is

recommended)

1. Sweet-service

1.10 for API burst and

VME burst strength

1.20 for heavy-wall

burst strength

2. Sour-service

1.20

1. Gas Kick

Internal: 2/3 gas column

(1/2 gas column may be

used on deep wells) on

top of drilling mud

External: Formation

pressure

2. Pressure test

Internal: Test pressure

plus test fluid column

External: Formation

pressure

3. Trapped fluid

(deepwater wells only)

Internal: Drilling mud plus

annulus fluid expansion

pressure

External: Drilling mud

plus annulus fluid

expansion pressure

1. Sweet-service*

API burst strength or

VME burst strength

Full-yield burst

strength

2. Sour-service**

API burst strength or

VME burst strength

(Burst strength

reduction on high

temperature, tubular

wall loss, and axial

load is

recommended)

1. Sweet-service

1.10 for API burst

and VME burst

strength

1.20 for Heavy-wall

burst strength

2. Sour-service

1.20

(Continued)

Casing/Tubing Design Manual 8-7

April 2007

(Continued)

String Conductor & Surface Casing Intermediate Casing/Liner

Criteria Loading Tubular strength Design factor Loading Tubular strength Design factor

Collapse 1. Lost return

Internal: Next drilling mud

drop to balance with water

gradient at the casing

depth, but not less than

2,000 ft drop or assume

full-void pipe if casing

depth is less than 2,000 ft

(Exception: Full seawater

column to surface may be

used for offshore wells)

External: Drilling mud

2. Cementing

Internal: Drilling mud

External: Cement slurry in

place

3. Trapped fluid

(deepwater wells only)

Internal: Drilling mud plus

annulus fluid expansion

pressure External: drilling

mud plus annulus fluid

expansion pressure

API collapse rating

or approved high

collapse rating

(Collapse rating

reduction for axial

tension is

recommended).

1. Lost return

1.00 or

0.85 on good cement

section

2. Cementing 1.00

3. Trapped fluid 1.00

1. Lost return

Internal: Next drilling

mud drop to balance with

water gradient at the

casing depth, but not less

than 2,000 ft drop

(Exception: Full seawater

column to surface may

be used for offshore

wells)

External: Drilling mud

2. Salt Load (applied to

salt zone)

Internal: Empty pipe

External: 1 psi/ft

formation overburden

3. Trapped fluid

(deepwater wells only)

Internal: Drilling mud plus

annulus fluid expansion

pressure

External: Drilling mud

plus annulus fluid

expansion pressure

API collapse rating

or approved high

collapse rating

(Collapse rating

reduction for axial

tension is

recommended)

1. Lost return

1.00 or

0.85 on good

cement section

2. Salt Load

(applied to salt

zone) 1.00

3. Trapped fluid

1.00

Tension 1. Running load

Tension: Buoyant weight

plus 100,000 lb overpull

2. Green cement test

Tension: Buoyant weight

plus cement plug bump

pressure load

The lesser of API

pipe tension rating

or connection

tension rating

1.60

1. Running load

Tension: Buoyant weight

plus 10,000 lb overpull

2. Green cement test

Tension: Buoyant weight

plus cement plug bump

pressure load

The lesser of API

pipe tension rating

or connection

tension rating

1.60

* H

S partial pressure < 0.05 psi ** H

S partial pressure >= 0.05 psi

8-8 Casing/Tubing Design Manual

April 2007

Table 8-4. Production Casing, Linder, and Tubing Design Criteria

String Production Casing/Liner Tubing

Criteria Loading Tubular strength Design factor Loading Tubular strength Design factor

Burst 1. Tubing leak near

surface

Internal: Tubing leak

pressure from (1)

production shut-in, (2)

stimulation, (3) screen-

out, or (4) well kill, plus

packer fluid column

External: Formation

pressure

2. Trapped fluid (deep

water wells only)

Internal: Packer fluid plus

annulus fluid expansion

pressure

External: Drilling mud

plus annulus fluid

expansion pressure

1. Sweet-service*

API burst rating or

Heavy-wall burst

rating

2. Sour-service**

API burst rating or

VME burst rating

(Burst rating

reduction for high

temperature and on

tubular wall loss is

recommended.)

1. Sweet-service

1.10 for API burst

rating

1.20 for heavy-wall

burst rating

2. Sour-service 1.20

1. Service Load

Internal: Max. pressure

from (1) production shut-

in, (2) stimulation, (3)

screen-out, or (4) well kill.

External: Packer fluid

2. Trapped fluid

(deepwater wells only)

Internal: production shut-in

pressure

External: packer fluid with

zero pressure at wellhead

1. Sweet-service*

API burst rating or

Heavy-wall burst

rating

2. Sour-service**

API burst rating or

VME burst rating

(Burst rating

reduction for high

temperature and

tubular wall loss is

recommended.)

1.20

Collapse 1. Full void pipe

Internal: Empty pipe (zero

pressure)

External: Drilling mud

2. Salt Load (applied to

salt zone)

Internal: Empty pipe

External: 1 psi/ft

formation overburden

3. Trapped fluid (deep

water wells only)

Internal: packer fluid with

production steam

pressure at wellhead

External: drilling mud plus

annulus fluid expansion

pressure

API collapse rating

or approved high

collapse rating

(Collapse rating

reduction for axial

tension is

recommended.

1. Full void

1.00 or

0.85 on good cement

section

2. Salt Load (applied

to salt) 1.00

3. Trapped fluid

1.00

1. Full void pipe

Internal: Empty pipe (zero

pressure)

External: Packer fluid

2. Trapped fluid (deep

water wells only)

Internal: production steam

flowing pressure

External: packer fluid with

annulus fluid expansion

pressure

API collapse rating

or approved high

collapse rating

(Collapse rating

reduction for axial

tension is

recommended.

Contact ETC for

HTHP wells.)

1. Full void pipe

1.00 or

0.85 on good

cement section

2. Trapped fluid

1.00

Casing/Tubing Design Manual 8-9

April 2007

(Continued)

String Production Casing/Liner Tubing

Criteria Loading Tubular strength Design factor Loading Tubular strength Design factor

Tension/com-

pression

1. Running load

Tension: Buoyant

weight plus100,000 lb

overpull

2. Service load

Tension/compression:

Buoyant weight plus

load change due to

temperature and

pressure effects from

surface tubing leak

3. Green cement test

Tension: Buoyant

weight plus cement

plug bump pressure

load

4. Steam injection

load

Tension: Thermal

tension at cooling

period;

Compression:

Thermal compression

at heating period

The lesser of API

pipe tension rating

or connection

tension

/compression rating

(Tube buckling

bending stress is

recommended to

be included in tube

compression load)

1. Running load

1.60

2. Service load

1.60

1.30 (compression)

3. Green cement test

1.60

4. Steam injection

load

1.60 (tension)

1.00 (compression)

1. Workover load

Tension: Buoyant weight

plus 10,000 lb overpull

2. Service load

Tension/compression:

Buoyant weight plus load

change due to

temperature and pressure

effects from (1) production

shut-in, (2) stimulation, or

(3) well kill, when tubing

movement is limited

3. Steam injection load

(when tubing movement is

limited)

Tension: Thermal tension

at cooling period;

Compression: Thermal

compression at heating

period

The lesser of API

pipe tension rating

or connection

tension rating

(Tube buckling

bending stress is

recommended to be

included in tube

compression load)

1. Workover load

1.60

2. Service load

1.60 (tension)

1.30 (compression)

3. Steam injection

load

1.60 (tension)

1.00 (compression)

Triaxial 1. Tubing leak near

surface

Internal: Tubing leak

pressure from (1)

production shut-in, (2)

stimulation, (3)

screen-out, or (4) well

kill, plus packer fluid

column

External: formation

pressure

Tube material yield

stress (reduction for

high temperature is

recommended)

1.20 1. Service Load

Internal: Max. pressure

from (1) production shut-

in, (2) stimulation, (3)

screen-out, or (4) well kill.

External: Packer fluid

Tube material yield

stress (reduction for

high temperature is

recommended)

1.20

* H

S partial pressure < 0.05 psi ** H

S partial pressure >= 0.05 psi

Casing/Tubing Design Manual 8-10

April 2007

8.5 References

1. Adams, N. J., and Charrier, T.: Drilling Engineering, a Complete Well

Planning Approach, PennWell Books, Tulsa, Oklahoma (1985).

2. Burgoyne, A. T. Jr., Millheim, K. K., Chenevert, M. E., and Young, F. S. Jr.:

Applied Drilling Engineering, SPE, Richardson, Texas (1986).

3. Rader, D. W., and Burgoyne, A. T.: “Factors Affecting Bubble Rise Velocity of

Gas Kicks,” Journal of Petroleum Technology, (1975) 571-584.

4. Murphey, C. E.: "Tubing Design", appendix C, CPTC-DWPD Tech Memo 94-

02, Houston, Texas (April 1994).

5. Wu, Jiang: “Casing and Tubing Design Criteria”, Chevron ETC Tech Memo

#2002-24, Houston, Texas (September 2002).

9 Example Designs

9.1 Introduction ......................................................................................................................9-2

9.2 Stretch in a Vertical Wellbore, Single String.....................................................................9-3

9.2.1 Temperature................................................................................................................9-3

9.2.2 Ballooning....................................................................................................................9-3

9.2.3 Weight (Gravity)...........................................................................................................9-4

9.2.4 End Load.....................................................................................................................9-4

9.2.5 Net Stretch ..................................................................................................................9-4

9.2.6 Example Calculation....................................................................................................9-5

9.3 Stretch in a Vertical Wellbore, Tapered String .................................................................9-6

9.3.1 Lower Segment ...........................................................................................................9-6

9.3.2 Upper Segment ...........................................................................................................9-6

9.3.3 Example Calculation....................................................................................................9-7

9.4 Tubing Movement ............................................................................................................9-8

9.4.1 Initial Conditions........................................................................................................9-10

9.4.1.1 Internal Area.........................................................................................................9-11

9.4.1.2 External Area........................................................................................................9-11

9.4.1.3 Moment of Inertia..................................................................................................9-11

9.4.1.4 Area of Packer Cross Section...............................................................................9-11

9.4.1.5 Total Length of String ...........................................................................................9-11

9.4.1.6 Internal Pressure at Bottom of Section

.............................................................9-12

9.4.1.7 External Pressure at Bottom of Section

...........................................................9-12

9.4.1.8 Axial Force at Bottom of the Bottom Section ........................................................9-12

9.4.1.9 Axial Force at Bottom of the Section.....................................................................9-12

9.4.1.10 Effective Force.................................................................................................9-13

9.4.1.11 Effective Weight...............................................................................................9-13

9.4.2 Conditions during Stimulation....................................................................................9-14

9.4.2.1 Temperature Change............................................................................................9-15

9.4.2.2 Axial Force Change..............................................................................................9-16

9.4.2.3 Ballooning Change ...............................................................................................9-17

9.4.2.4 Buckling Change...................................................................................................9-17

9.4.2.5 Summary..............................................................................................................9-17

9.5 Production Casing Design..............................................................................................9-17

9.5.1 Preliminary Design ....................................................................................................9-20

9.5.1.1 Collapse Design....................................................................................................9-21

9.5.1.2 Burst Design.........................................................................................................9-24

9.5.1.3 Axial Load Design.................................................................................................9-26

9.5.1.4 Qualitative Considerations....................................................................................9-27

9.5.1.5 Minimum Segment Length, Number of Segments................................................9-27

9.5.1.6 Gauge Rings.........................................................................................................9-28

9.5.2 Final Design Check ...................................................................................................9-29

9.5.3 Cemented Casing versus Packer Completions.........................................................9-31

9.5.3.1 Initial Conditions ...................................................................................................9-32

9.5.3.2 Internal Area.........................................................................................................9-34

9.5.3.3 External Area........................................................................................................9-34

Casing/Tubing Design Manual 9-1

October 2005

9.5.3.4 Moment of Inertia..................................................................................................9-34

9.5.3.5 Total Length of String............................................................................................9-34

9.5.3.6 Internal Pressure at Bottom of Section

.............................................................9-34

9.5.3.7 External Pressure at Bottom of Section

............................................................9-34

9.5.3.8 Axial Force at Bottom of the Bottom Section.........................................................9-34

9.5.3.9 Axial Force at Bottom of the Section.....................................................................9-35

9.5.3.10 Effective Force .................................................................................................9-35

9.5.3.11 Effective Weight ...............................................................................................9-35

9.5.3.12 Collapse Conditions .........................................................................................9-35

9.5.3.13 Temperature Change.......................................................................................9-36

9.5.3.14 Axial Force Change..........................................................................................9-36

9.5.3.15 Ballooning Change...........................................................................................9-37

9.5.3.16 Buckling Change..............................................................................................9-37

9.5.3.17 Incremental Axial Force....................................................................................9-38

9.5.3.18 Burst Conditions...............................................................................................9-41

9.1 Introduction

The following example problems illustrate principles introduced in previous

chapters. All examples are worked to conclusion in both metric and English units.

In comparing the results of comparable calculations, agreement should be

expected for at least the first three significant digits. Calculations specific to the

current example are presented in shaded text. Unshaded text presents general

guidelines for solving the particular problem type being discussed.

Each example emphasizes a different aspect of tubular design. Table 9-1Table

9-1 indicates the specific topics covered in each of the sections to follow.

Table 9-1. Example Topics

Example Title Topics Covered

Stretch in a Vertical

Wellbore, Single String

Length change with environment

Stretch in a Vertical

Wellbore, Tapered String

Extension of single string example

Tubing Movement Length change with environment

Column buckling

Required seal length

Packer completion

Production Casing Design Standard well load case definitions

Effect of tension on collapse resistance

Practical design considerations

9-2 Casing/Tubing Design Manual

October 2005