Casing/Tubing design manual october 2005 Chevron

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performance and the flow through the tubing and surface facilities to analyze well

performance as a system.

After the production tubing has been sized, production casing is usually sized to

provide sufficient clearance to anticipate:

• Multiple/dual completions with more than one tubing string.

• Control lines for surface controlled safety valves.

• Artificial lift equipment, such as gas lift mandrels.

• Provision for washing over the production tubing, particularly if a heavy

packer fluid is used or if production occurs outside the tubing.

• The possibility of deepening the well in the future.

Shallower strings, intermediate and surface casing strings, are usually sized

based on cementing guidelines and standard bit sizes. The preferred annular

clearance for proper cement placement is 38.1 mm (1.5 in.) on diameter;

although, smaller clearances are often used. In the open hole, underreaming is

an important compromise allowing larger diameter casing, while promoting

adequate cement placement.

Table 2-5 can be used to size intermediate and surface tubulars. To use the

table:

1. Starting at the bottom, find the production casing nominal outside diameter in

either the “Recommended” or “Allowable” OD column (Columns 3 and 4).

2. Moving to the left on the current row, determine the bit size (Column 2) and

casing size (Column 1) that will accommodate the production casing. The

casing size (Column 1) will give the nominal outside diameter for the deepest

intermediate casing/liner.

3. Repeat the process, moving up the hole, until all intermediate and surface

casing sizes and corresponding bit sizes have been selected.

Table 2-5. Casing Sizing Table

-1-

Nominal OD

mm (in.)

-2-

Standard Bit Size,

Drift Diameter

mm (in.)

-3-

Recommended

Next Nominal OD

mm (in.)

-4-

Allowable Next

Nominal OD

mm (in.)

914.4 (36.000) 838.2 (33.000) 762.0 (30.000)

711.2 (28.000)

660.4 (26.000)

762.0 (30.000) 660.4 (26.000) 609.6 (24.000)

558.8 (22.000)

508.0 (20.000)

609.6 (24.000) 558.8 (22.000)

508.0 (20.000)

406.4 (16.000)

473.1 (18.625)

457.2 (18.000)

454.0 (17.875)

508.0 (20.000) 444.5 (17.500) 355.6 (14.000)

346.1 (13.625)

339.7 (13.375)

406.4 (16.000)

406.4 (16.000) 374.6 (14.750) 301.6 (11.875)

298.4 (11.750)

355.6 (14.000)

346.1 (13.625)

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October 2005

-1-

Nominal OD

mm (in.)

-2-

Standard Bit Size,

Drift Diameter

mm (in.)

-3-

Recommended

Next Nominal OD

mm (in.)

-4-

Allowable Next

Nominal OD

mm (in.)

273.0 (10.750) 339.7 (13.375)

355.6 (14.000)

346.1 (13.625)

339.7 (13.375)

311.1 (12.25) 250.8 (9.875)

244.5 (9.625)

301.6 (11.875)

298.4 (11.750)

273.0 (10.750)

-1-

Nominal OD

mm (in.)

-2-

Standard Bit Size,

Drift Diameter

mm (in.)

-3-

Recommended

Next Nominal OD

mm (in.)

-4-

Allowable Next

Nominal OD

mm (in.)

301.6 (11.875)

298.4 (11.750)

269.9 (10.625) 219.1 (8.625) 250.8 (9.875)

244.5 (9.625)

273.0 (10.750) 241.3 (9.500)

222.2 (8.750)

196.9 (7.750)

193.7 (7.625)

177.8 (7.000)

219.1 (8.625)

196.9 (7.750)

193.7 (7.625)

250.8 (9.875)

244.5 (9.625)

215.9 (8.500)

200.0 (7.875)

177.8 (7.000)

168.28 (6.625)

139.70 (5.500)

196.9 (7.750)

193.7 (7.625)

168.28 (6.625)

219.1 (8.625) 200.0 (7.875)

165.10 (6.500)

139.70 (5.500)

127.00 (5.000)

168.28 (6.625)

139.70 (5.500)

196.9 (7.750)

193.7 (7.625)

165.10 (6.500)

155.58 (6.125)

127.00 (5.000)

114.30 (4.500)

139.70 (5.500)

127.00 (5.000)

177.8 (7.000) 155.58 (6.125)

149.22 (5.875)

114.30 (4.500)

101.60 (4.000)

127.0 (5.000)

114.30 (4.500)

168.28 (6.625) 149.22 (5.875)

120.65 (4.750)

101.60 (4.000)

88.90 (3.500)

114.30 (4.500)

101.60 (4.000)

139.70 (5.500) 120.65 (4.750) 88.90 (3.500) -

2.2.6 Example Problem

The production casing for a well has been determined to be 114.3 mm (4.500

in.). Assume that we wish to follow recommended clearances for all shallower

strings. To select bit sizes and intermediate and surface casing sizes for the rest

of the wellbore, the following procedure may be followed:

1. Finding 114.30 mm (4.500 in.) in Column 3, we can use a 155.58 mm (6.125

in.) bit with either 196.9 mm (7.750 in.), 193.7 mm (7.625 in.) or 177.8 mm

(7.000 in.) casing. Here the latter is selected to keep shallower hole

diameters as small as possible.

2. Finding 177.8 mm (7.000 in.) in Column 3, we can use either a 215.9 mm

(8.500 in.) bit with 250.8 mm (9.875 in.) or 244.5 mm (9.625 in.) casing, or a

222.2 mm (8.75 in.) bit with 273.0 mm (10.750 in.) casing. Again, the

Casing/Tubing Design Manual 2-13

October 2005

smallest option is selected, a 215.9 mm (8.500 in.) bit with 244.5 mm (9.625

in.) casing.

3. Finding 244.5 mm (9.625 in.) in Column 3, the corresponding bit and casing

size are 311.1 mm (12.25 in.) and 339.7 mm (13.375 in.), respectively.

4. Finding 339.7 mm (13.375 in.) in Column 3, the corresponding bit and casing

size are 444.5 mm (17.500 in.) and 508.0 mm (20.000 in.), respectively.

5. Finding 508.0 mm (20.000 in.) in Column 3, the corresponding bit and casing

size are 660.4 mm (26.000 in.) and 762.0 mm (30.000 in.), respectively.

6. Finding 762.0 mm (30.000 in.) in Column 3, the corresponding bit and casing

size are 838.2 mm (33.000 in.) and 914.4 mm (36.000 in.), respectively.

2.3 References

1. Drilling Engineering, a Complete Well Planning Approach, N.J. Adams and T.

Charrier, PennWell Books, Tulsa, Oklahoma (1985).

2. Applied Drilling Engineering, A.T. Burgoyne Jr., K.K. Millheim, M. E.

Chenevert, and F.S. Young Jr., Society of Petroleum Engineers, Richardson,

Texas, (1986).

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3 Tube Specification

3.1 Introduction ......................................................................................................................3-1

3.2 Standards.........................................................................................................................3-1

3.3 Groups .............................................................................................................................3-2

3.4 Manufacturing Process.....................................................................................................3-3

3.5 Chemistry.........................................................................................................................3-4

3.6 Inspection and Testing.....................................................................................................3-5

3.6.1 Range..........................................................................................................................3-6

3.6.2 Drift Diameter ..............................................................................................................3-7

3.6.2.1 Exceptions..............................................................................................................3-7

3.6.3 Hydrostatic Test...........................................................................................................3-7

3.6.4 Mechanical Properties.................................................................................................3-8

3.6.5 Yield Stress...............................................................................................................3-10

3.6.5.1 Tensile (Ultimate) Stress and Elongation..............................................................3-11

3.6.6 Flaw Inspection..........................................................................................................3-13

3.7 Couplings.......................................................................................................................3-14

3.8 Marking, Coating, and Thread Protection.......................................................................3-15

3.9 Sour Service...................................................................................................................3-15

3.10 Temperature Effects.......................................................................................................3-16

3.10.1 Yield Strength............................................................................................................3-16

3.10.2 Young’s Modulus.......................................................................................................3-18

3.10.3 Poisson’s Ratio..........................................................................................................3-19

3.10.4 Coefficient of Thermal Expansion..............................................................................3-20

3.11 References.....................................................................................................................3-21

3.1 Introduction

In order to handle the performance properties of the tube and connector, the

specification of a tubular string element, including grade and dimensional

considerations, needs to be discussed first. This chapter addresses a number of

issues linking later chapters on tubular performance with ensuing discussions on

design. When selecting tubulars from a vendor's inventory, the performance

properties of the tube should be calculated from formulas presented in ISO

10400/American Petroleum Institute (API) Bulletin 5C3 [API, Latest Edition] using

minimum yield and ultimate strengths as specified in ISO 11960/API

Specification 5CT1.

3.2 Standards

The American Petroleum Institute Specification 5CT, Specification for Casing and

Tubing (Spec 5CT) and the International Standard ISO 11960, Petroleum and

Natural Gas Industries-Steel Pipes for Use as Casing or Tubing for Wells (ISO

11960) are the industry standards for the manufacture, testing, and inspection of

An exception to this rule is high-collapse casing.

Casing/Tubing Design Manual 3-1

October 2005

OCTG

, and should always be considered the minimum acceptable standard

when purchasing new pipe. Neither Spec 5CT nor ISO 11960 addresses uses

tubulars. The documents are essentially the same in format and content,

specifying manufacturing to one or the other results in the same product.

Corrosive Resistance Alloy (CRA) tube can have material properties governed by

the mills’ manufacturing specifications, and will not be discussed here.

3.3 Groups

OCTG is divided into four groups by grade to better define manufacturing, testing

and inspection criteria. Table 3-1 shows the four groups, the grades in each

group, and manufacturing process and heat treatment for each grade. Each

grade designation consists of a letter and a number. The letter has no real

significance. The number designates the minimum yield of the steel in 1,000-psi

units. For example, grade P-110 is a Group 3 steel with a minimum yield of

110,000 psi.

Table 3-1. Process of Manufacture and Heat Treatment (API Specification 5CT,

Specification for Casing and Tubing, Fifth Edition, April 1, 1995)

Group Grade Type Process of

Manufacture

Heat Treatment

°F

1 H40 S or EW None

J55 S or EW None

(See Note)

K55 S or EW None

(See Note)

N80 S or EW (See Note)

2 L80 1 S or EW Q&T 1050

L80 9Cr S Q&T 1100

L80 13Cr S Q&T 1100

C90 1 S Q&T 1150

C90 2 S Q&T 1150

C95 S or EW Q&T 1000

T95 1 S Q&T 1200

T95 2 S Q&T 1200

3 P110 S or EW Q&T

4 Q125 1 S or EW Q&T

Q125 2 S or EW Q&T

Q125 3 S or EW Q&T

Q125 4 S or EW Q&T

Note: Full length normalized, normalized and tempered (N&T), or quenched and

OCTG, Oil Country Tubular Goods, includes steel casing, tubing, pup joints,

connectors, and couplings.

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October 2005

Group Grade Type Process of

Manufacture

Heat Treatment

°F

tempered (Q&T) at the manufacturer's option or if so specified on the purchase

order.

Grades of steel with letter designations other than those designated in Table 3-1

for instance, HC-95 and C-110, are not recognized by API and are not controlled

by API manufacturing and inspection requirements. The manufacturing and

quality requirements are those agreed to by the end user and the manufacturer.

3.4 Manufacturing Process

The manufacturing process is either seamless (SMLS) or electric resistance-

welded (ERW). The SMLS process takes a solid billet, usually round, that is

heated and rotary pierced. After piercing, the billet is elongated and the walls

thinned to produce a seamless tube. Several different types of equipment are

used to produce seamless pipe. The plug mill, pilger mill, mandrel mill, and

retained mandrel mill are examples.

The ERW process takes a continuous coil of flat steel with the desired final wall

thickness, called “skelp,” forms it into a round tube and welds the longitudinal

seam. The high-frequency welder heats the edges of the rounded coil to around

1400

C (2600°F). The edges are squeezed together to produce a forge weld. No

filler or welding rod is used. The resulting internal and external weld flash is

removed. Individual joints are then cut from this continuous tube.

As indicated in Table 3-1, a specified method of full-length heat treatment is

given for each grade. The heat treatment of SMLS and ERW pipe takes place

after rolling and ranges from “as rolled” (none) for some Group 1 grades to

“quenched and tempered” (Q&T) for grades in Groups 2, 3, and 4. Grades J-55,

K-55, and N-80 may also be heat-treated using the normalized (N) or normalized

and tempered (N&T) methods. Heat treatment is required to obtain the higher

yield strengths and develop desired ductility and toughness.

• The Q&T process involves heating individual tubes to approximately 870-

930°C (1600 to 1700°F) in an austenizing furnace, and then the tubes soak

at this temperature for a specified amount of time depending on the

chemistry of the steel, the thickness pipe, and the specific mill. The evenly

heated tube is then rapidly quenched, or cooled, to below 93°C (200°F) using

water or oil as the cooling medium. After quenching, the pipe is reheated, or

tempered, to approximately 560 to 650°C (1050 to 1200°F) in a tempering

furnace and then allowed to air cool to room temperature.

• The N&T process involves heating individual tubes in an austenizing furnace,

allowing the tubes to air cool, reheating them in the tempering furnace, and

then allowing them to air cool to room temperature again.

• “Normalizing” involves heating individual tubes in an austenizing furnace and

allowing the tubes to air cool to room temperature.

ERW pipe must also have the weld seam heat-treated, or seam annealed to

above 540°C (1000°F) to relieve the stresses of welding and produce a

Casing/Tubing Design Manual 3-3

October 2005

normalized grain structure. The ductility of the weld and heat affected zone (HAZ)

is increased if the weld seam is heat treated to above 840°C (1550°F).

API grade P-110 or Q-125 or proprietary equivalents manufactured by the ERW

process should be purchased to the requirements of Chevron MCQA.01

specification, which specifies additional mechanical property requirements

intended to assure consistent material properties through the weld.

3.5 Chemistry

Another element important in the manufacture of OCTG is the chemistry of the

steel. Table 3-2 lists the minimums and maximums for the various required

elements of each grade. Note that grades C-90 and T-95 have two different types

and grade Q-125 has four different types. Historically, end-user and mill

representatives writing the API standards could not agree so more than one type

was specified. In all three cases it is usually best to specify Type 1 chemistry

because more elements are controlled and maximum phosphorous and/or sulfur

are lower

Grade L-80 has three types, but each has a specific purpose:

• Type 1 is a Sulfide Stress Cracking (SSC) resistant steel with 80-ksi

minimum yield.

• Type 2 has 9% chromium added for resistance to CO

corrosion and is

usually used for manufacturing tubular accessories.

• Type 3 has 13% chromium added for more resistance to CO

corrosion.

Types 2 and 3 have limited resistance to SSC.

Table 3-2. Chemical Requirements (by Percentage of Weight)-API Specification 5CT,

Specification for Casing and Tubing, Fifth Edition, April 1, 1995

Carbon Manganese Molybdenum Chromium Ni Cu P S Si

Grp Gde Type Min. Max. Min. Max. Min. Max. Min. Max. Max. Max. Max. Max. Max.

1 H40 0.030 0.030

J55 0.030 0.030

K55 0.030 0.030

N80 0.030 0.030

2 L80 1 0.43

1.90 0.25 0.35 0.030 0.030 0.45

L80 9Cr 0.15 0.30 0.60 0.90 1.10 8.00 10.00 0.50 0.25 0.020 0.010 1.00

L80 13Cr 0.15 0.22 0.25 1.00 12.00 14.00 0.50 0.25 0.020 0.010 1.00

C90 1 0.35 1.00 0.25

0.75 1.20 0.99 0.030 0.010

C90 2 0.50 1.90 N.L. N.L. 0.99 0.030 0.010

C95 0.45

1.90 0.030 0.030 0.45

T95 1 0.35 1.20 0.25

0.85 0.40 1.50 0.99 0.020 0.010

T95 2 0.50 1.90 0.99 0.030 0.010

3 P110 .030

.030

Phosphorous and sulfur are contaminants in steel.

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October 2005

Carbon Manganese Molybdenum Chromium Ni Cu P S Si

4 Q125 1 0.35 1.00 0.75 1.20 0.99 0.020 0.010

Q125 2 0.35 1.00 N.L. N.L. 0.99 0.020 0.020

Q125 3 0.50 1.90 N.L. N.L. 0.99 0.030 0.010

Q125 4 0.50 1.90 N.L. N.L. 0.99 0.030 0.020

Note: N.L. = No Limit. Elements shown must be reported in product analysis.

a The carbon content for L80 may be increased to 0.50 percent maximum if the

product is oil quenched.

b The molybdenum content for grade C90, Type 1, has no minimum tolerance if

the wall thickness is less than 0.700 inch.

c The carbon content for Grade C95 may be increased to 0.55 percent maximum

if the product is oil quenched.

d The molybdenum content for Grade T95, Type 1, may be decreased to 0.15

percent minimum if the wall thickness is less than 0.700 inch.

e The phosphorous is 0.020 percent maximum and the sulfur is 0.010 percent

maximum for EW Grade P110.

3.6 Inspection and Testing

After rolling, the rest of the pipe manufacturing process is devoted to inspection

and testing. This quality-assurance process is designed to prove that the tube is

free of flaws and is the correct size, weight, grade, and length specified by the

mill manufacturing plan and the API standard.

Several types of inspection and testing are conducted to check the quality of the

finished product. Mechanical testing consists of non-destructive and destructive

testing. Destructive testing requires that a sample of the steel from the finished

product be removed to perform the tests. Verification of the outside diameter,

wall thickness, weight, length, and straightness are non-destructive mechanical

tests.

Table 3-3 and 3-4 list the tolerances for these variables.

Table 3-3. Dimensions and Tolerances of Tube by API Standards

Outside Diameter Wall Weight

Min. Max. Min. Min. Max. Straightness

< 14.30 mm

(4.500 in.)

-0.031 in. +0.031

in.

12.5%

0.2% of Length

(see Table 3-4)

≥ 14.30 mm

(4.500 in.)

-0.5% of

1.00% -

12.5%

0.2% of Length

(see Table 3-4)

Single -3.5% +6.5%

Carload -1.75%

Tube wall-thickness is a very important measure of the tube, as it affects the tube

performance properties (or the tube strength). Less wall-tolerance tube (i.e. -10%

or -8%) than that of API standards may be ordered from some mills, giving higher

tube performance properties.

Casing/Tubing Design Manual 3-5

October 2005

Figure 3-1 presents the measured tube wall-thickness distributions on tubes

manufactured by several mills in a JIP (DEA-130). It shows the normalized tube

wall thickness, the ration of actual wall thickness and specified (nominal) wall

thickness. The wall thickness is shown to have an average value of about 0.98 to

1.02 (average) and a minimum value of about 0.94 to 0.97. (The minimum value

is by statistics on limiting the probability that the wall thickness is less will be

below 1%.) These minimum values are above the API-minimum wall thickness of

87.5% nominal wall.

Figure 3-1. Tube Wall-Thickness Statistical Data

3.6.1 Range

Table 3-4 lists range lengths for tubing and casing.

Table 3-4. Tube Lengths by API Standards

Range Casing Tubing

1 4.9 to 7.6 m/16 to 25 ft. 6.1 to 7.3 m /20 to 24 ft.

2 7.6 to 10.4 m /25 to 34 ft. 8.5 to 9.6 m/28 to 32 ft.

3 34+ ft N/A

All casing should be ordered as Range 3. All tubing should be ordered as Range

. The increased length is seldom difficult to handle and choosing a longer

average length reduces the number of threaded connections in a string; thus,

reducing both cost and the probability of a connection leak or failure.

Contrary to the API values shown in the table, tubing can sometimes be obtained as

Range 3. When this is possible, Range 3 tubing is recommended.

3-6 Casing/Tubing Design Manual

October 2005

3.6.2 Drift Diameter

Drift diameter is an assured inside diameter. As a minimum, the drift diameter as

defined in Table 54 of API Specification 5CT should be ordered.

3.6.2.1 Exceptions

Certain popular weights of casing have special drift diameters that, although

recognized by the API (Table 27 of API Specification 5CT), must still be specified

on the purchase order. A complete list of these special products is given in Table

3-5.

Table 3-5. Special Drift Diameters

Size

(in)

Weight Outside Diameter

mm/(in)

Mandrel Length

mm/(in)

Mandrel Diameter

mm/(in)

7 23.0 177.8/(7.000) 152/(6) 158.75/(6.250)

7 32.0 177.8/(7.000) 152/(6) 152.40/(6.000)

7-5/8

52.8 193.7/(7.625) 152/(6) 155.58/(6.125)

7-3/4 46.1 196.9/(7.750) 152/(6) 165.10/(6.500)

8-5/8 32.0 219.1/(8.625) 152/(6) 200.02/(7.875)

8-5/8 40.0 219.1/(8.625) 152/(6) 193.68/(7.625)

9-5/8 40.0 244.5/(9.625) 305/(12) 222.25/(8.750)

9-5/8 53.5 244.5/(9.625) 305/(12) 215.90/(8.500)

9-5/8 58.4 244.5/(9.625) 305/(12) 212.72/(8.375)

9-7/8

62.8 250.8/(9.875) 305/(12) 215.90/(8.500)

10-

3/4

45.5 273.1/(10.750) 305/(12) 250.82/(9.875)

10-

3/4

55.5 273.1/(10.750) 305/(12) 244.48/(9.625)

11-

3/4

42.0 298.5/(11.750) 305/(12) 279.40/(11.000)

11-

3/4

60.0 298.5/(11.750) 305/(12) 269.88/(10.625)

11-

3/4

65.0 298.5/(11.750) 305/(12) 269.88/(10.625)

13-

3/8

72.0 339.7/(13.375) 305/(12) 311.15/(12.250)

13-

5/8

88.2 346.1/(13.625) 305/(12) 311.15/(12.250)

Not currently recognized by API as a valid special drift diameter.

3.6.3 Hydrostatic Test

Hydrostatic testing is performed by the manufacturer on each finished pipe to a

pressure of 20.68 MPa (3,000 psi) or 80% of minimum yield stress whichever is

less, regardless of grade. (Except for grade Q-125, which always requires the

alternate test pressure.) To obtain a higher test pressure, specify testing to the

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October 2005