Casing/Tubing design manual october 2005 Chevron

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alternate hydrostatic test pressure when ordering material. Tables 36 through 52

in API Spec 5CT have the standard and alternate hydrostatic test pressures for

each size, weight, and grade of casing and tubing.

The alternate hydrostatic pressure is calculated using the same formula used by

API BUL 5C3 to calculate the internal yield (burst) rating.

(

)

Pf tD

API

= 2

(3-1)

where

API

is the API minimum yield stress, is wall thickness and is

outside diameter.

t D

The value of

for calculating the internal yield rating is 0.875. The value of

for calculating the alternative hydrostatic test pressure is 0.800. Dividing 0.800 by

0.875, the alternate test pressure is 91.4% of the minimum burst rating.

f f

3.6.4 Mechanical Properties

The chemical composition is analyzed and reported from a sample removed from

the finished product. Other important mechanical properties of the steel

determined from the sample are the yield and tensile strength and the hardness.

These requirements are listed in Table 3-6. The elongation, the toughness, the

grain size and, the SSC resistance are also important. The frequency of sampling

and the specified minimum and maximum values and tolerances vary between

grades and/or sizes and are usually considered the minimum acceptable.

Table 3-6. Grade Mechanical Properties

Grade Minimum

Yield

(MPa/ksi)

Maximum

Yield

(MPa/ksi)

Minimum

Tensile

(MPa/ksi)

Maximum

Hardness

(HRC)

H-40 276/40 552/80 414/60 -

J-55 379/55 552/80 517/75 -

K-55 379/55 552/80 655/95 -

N-80 552/80 758/110 689/100 -

L-80 552/80 655/95 655/95 23

C-90 621/90 724/105 689/100 25.4

C-95 655/95 758/110 724/105 -

T-95 655/95 758/110 724/105 25.4

C-110 758/110 827/120

793/115 28

P-110 758/110 965/140 862/125 -

Q-125 862/125 1034/150 931/135 -

These numbers are accepted by Chevron, but may not be used by other

operators.

The minimum and maximum yield strength values determine the grade of the

steel and they are a measure of the resistance of the tube stress. The tensile

strength is the ultimate stress the material can withstand and is used to

determine joint strength of casing.

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Figure 3-2 displays the uniaxial tension test and the result on a sample of casing

steel for determining its mechanical properties. Dividing the applied force, F, by

the cross-sectional area of the sample, A, the axial stress can be determined.

Similarly, the axial strain

∆

LL/ can also be directly measured. The right-

hand portion of Figure 3-2 is a plot of stress as a function of strain. Notice from

the figure that as the sample is loaded along path OA, the relation between

stress and strain is linear,

(3-2)

where

m is the slope of the line and

is the value of

0. If the sample

was loaded to any point between O and A and then unloaded, the path OA

would, within practical limits, be retraced to the origin. Such behavior is termed

“elastic.” Evaluating the constants in Eq. (3-2),

and

so that:

(3-3)

The constant E is called Young’s Modulus.

API

0.005

ε = ∆L / L

σ = F / A

∆L

Figure 3-2. Typical Uniaxial Stress-Strain Curve

Before proceeding to higher loading states, it is worth mentioning that axial strain

is not the only dimensional change that will occur in the bar sample. Extension in

the axial dimension will be accompanied by contraction in the transverse

direction. This contraction in the transverse direction will also vary linearly with

the axial loading in the sense that:

εµε

transverse

=− =−

(3-4)

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where

is Poisson’s ratio. Additionally, notice that

can also be measured

directly during the deformation experiment. The quantities

and

are

independent and completely determine isotropic linearly elastic stress-strain

behavior for isothermal loading.

Consider now an experiment where the sample is loaded along path OABC. The

following facts are pertinent:

• Above the stress state corresponding to point A, the relation between stress

and strain is no longer linear.

• Upon unloading from any point C above point A, the metal will not retrace the

original loading path, but rather it will unload along path CDE, which is

parallel to path OA. Unloading along path CDE occurs elastically.

• Once completely unloaded, the material will now possess a permanent,

inelastic strain (

= OE).

• If the bar at state E is now reloaded, the stress-strain behavior will be elastic

and follow path EDC. Continued loading beyond the stress level

corresponding to point C will follow path CFG.

• Point G represents the ultimate strength of the material. States beyond that

corresponding to point G are undefined.

3.6.5 Yield Stress

Behavior of the sample beyond point A is termed “inelastic.” Following the first

occasion for which the stress corresponding to point A is exceeded, it will be

necessary to compile a new set of constitutive (stress-strain) relations for the

material. Because of its importance as a limit point of elastic behavior

, the stress

corresponding to point A is given a special name, the initial yield stress, denoted

The yield stress,

, is a difficult, if not an impossible, number to obtain

experimentally. Close examination of the character of the curve in Figure 3-2 will

indicate that, experimentally, by the time one detects inelastic behavior, the yield

stress has already been exceeded. In order to circumvent this experimental

problem, it is common practice to approximate the yield stress by means of a

suitable alternate definition. For example, probably the most popular alternate

definition of yield stress is the so-called 0.2% offset stress, which is determined

by the intersection of the experimental stress-strain curve with a line parallel to

the elastic portion of the curve (i.e., slope =

) and passes through the point

= 0.002 (such a line would be similar to line CDE in Figure 3-2). On the other

hand, API defines the yield stress as the stress corresponding to

= 0.005

. As

For simplicity, the yield point, signifying the onset of inelastic behavior, and the

proportional limit, signifying the upper limit of applicability of Eq. (B-38) have been

assumed to coincide. However, for real materials, this is not always true.

The value of strain corresponding to yield may vary with grade. For example, the yield

stress for grade P-110 is defined as the stress corresponding to

= 0.006, and the yield

stress for grade Q-125 is defined as the stress corresponding to

= 0.0065.

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indicated in Figure 3-2,

API

, the API yield stress, does not in general

correspond to

3.6.5.1 Tensile (Ultimate) Stress and Elongation

The ultimate stress,

, is the maximum stress recorded at the time the

specimen breaks. Corresponding to this stress is a given value of strain. The

value of this ultimate strain, or elongation, is a measure of the ductility of the

steel.

The two stress-strain pairs (

API

, 0.005) and (

, Elongation) are the only

points taken from the uniaxial stress-strain curve for use in API formulas. Table

3-6 presents a list of the minimum acceptable values of

API

and

for tubular

steel grades currently recognized by the API.

The actual tube material yield stress measured from a uniaxial tension test on a

sample of casing steel may not be exactly the same as the specified minimum

yield stress by API standards. The graph in Figure 3-3 of measured tube yield

stress distributions is from a JIP (DEA-130). It shows that the measured

normalized pipe yield stress, the ratio of actual pipe yield strength and API

specified (minimum) pipe yield strength has an average value of about 1.08 to

1.28 (average), and a minimum value of about 0.85 to 1.08. (The minimum value

is by statistics on limiting the probability that the normalized pipe yield stress is

lower will be below 1%.) The minimum value of normalized pipe yield stress less

than 1.0 means that the tube yield stress is less than the current API minimum

yield strength requirement, which is not good. Care should be taken on such

tubes for a safe casing and tubing design.

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Figure 3-3. Tube Yield Strength Statistic Data

The hardness value is specified only for Group 2 grades that are designed to be

used in a potential sour gas environment. Generally, the lower the hardness

value the more resistant the steel to SSC. A surface hardness test is sometimes

used to identify the grade when the grade of a pipe cannot be easily determined

from the markings on the pipe or the markings are in question. This can be

misleading as hardness correlates better with tensile strength than with yield

strength.

Elongation is a measure of ductility. Elongation is inversely proportional to the

tensile strength. The higher grades, therefore, have lower elongation

requirements. The minimum elongation in a two-inch specimen is determined

from the following formula:

(

)

eAU= 625000

02 09

, (3-5)

where

e is elongation,

is the cross-sectional area of the test specimen in in

and

is the tensile strength of the specimen in psi.

Toughness is a measure of resistance to crack propagation and is measured by

the Charpy V-Notch Impact Test. The value is measured in ft-lb. [(Joules), the

higher the value, the better the toughness.] Minimums based on grade and size

of the sample are listed in Spec 5CT. Most steel manufactured today can easily

meet the API toughness requirements.

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3.6.6 Flaw Inspection

Inspection of pipe is required to find imperfections or flaws in the pipe body

created during the manufacturing process. Pipe body flaws are discontinuities or

irregularities that are only created during the manufacturing process and include

cracks, seams, laps, plug scores, cuts, gouges, and pits. These flaws can be

linear or nonlinear and can occur in any orientation, longitudinal, transverse, or

oblique. The methods employed to detect flaws are visual, magnetic particle

(MPI), electromagnetic (EMI), and ultrasonic (UT). The inspection methods for

each grade, as required by API Spec 5CT, are listed in Table 3-7.

Table 3-7. Pipe Body Inspection Methods

Grade Visual EMI UT MPI

(Circular

Field)

H40, J55, K55 R N N N

N80 (N, N&T)

N80, (Q&T) R A A A

L80, C95

P110 R A A --

C90, T95, Q125 R B C B

R = required

N = not required

A = one method or any combination of methods shall be used.

-- = not applicable

B = at least one method (excluding the visual method) shall be used in addition to

UT to inspect the outside surface.

C = UT shall be used to inspect the inside and outside surface.

When flaws are detected they must be ground out completely and the remaining

pipe body wall thickness under the flaw must be 87.5% or more of the originally

specified nominal wall thickness or the pipe is a reject.

UT and EMI equipment must use reference standards containing notches and/or

holes to verify system response. The depths of the reference standards are

usually either 12.5% or 5% of nominal pipe body wall and must be on the same

diameter and wall thickness pipe as that to be inspected. The specific reference

standard requirements for each grade are listed in Table 3-8.

Table 3-8. Artificial Reference Indicators

Notch

Location

Notch

Orientation

Notch Size Radially

Drilled Hole

Grade OD ID Long. Trans

Depth

Lgth

Width Diam

Pipe body

N80(Q&T)

L80,C95 R R R N 12.5 2.0 0.040 1/8

C90,T95

P110, Q125 R R R R 5.0 2.0 0.040 1/16

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Notch

Location

Notch

Orientation

Notch Size Radially

Drilled Hole

P110 to SR16 R R R R 12.5 2.0 0.400 1/8

Weld seam

Q125 and

P110

R R R N 5.0 2.0 0.040 1/16

All other

grades

R R R N 10.0 2.0 0.040 1/8

R = required when using notches

N = not required

Notches shall be rectangular or u-shaped as specified in Figure 2 of ASTM E

213. For seamless pipe, at the option of the manufacturer, notches may be

oriented at such an angle to optimize detection of anticipated flaws.

Depth as a percent of specified wall thickness. The depth tolerance shall be +/-

15% of the calculated notch depth with a minimum notch depth of 0.012 in. +/-

.002 in.

Maximum, in inches, at full depth.

Drilled hole diameter (through the pipe wall) shall be based on the drill-bit size

in inches. When calibrating EMI equipment using drilled holes, the inspection

system shall be capable of producing signals from both ID and OD notches that

are equal to or greater than the reject threshold established using the drilled hole.

This system capability shall be recorded as specified in 9.7.9 (API 5CT).

Note that grades H-40, J-55, K-55, and N-80 (N, N&T) are not included in Table

3-8. This is because API 5CT only requires a visual inspection for pipe body

flaws in these grades. If additional inspection is desired it should be specified on

the purchase request and should include type of inspection (EMI, UT, MT), the

standardization notch orientation (ID, OD, Longitudinal, Transverse), and the

notch size.

EMI and UT type inspections are good when the equipment is properly calibrated

and standardized. However, because both use wave theory (EMI is magnetic and

UT is sound) for detection purposes, another inspection is often required to

check the entire length of the pipe.

The end area (EA) or special end area (SEA) inspection is necessary because of

wave leakage near the ends of the pipe using EMI or UT inspection equipment.

The length of the end area needing to be checked varies from 150 to 300 mm (6

to 12 in.) depending on the equipment and the size of the pipe. Some mills

simply cut the end area off to eliminate the requirement. Those that perform the

inspection typically use MT. The difference between EA and SEA is that an SEA

is performed on threaded pipe and usually includes some type of thread

dimensional check. The EA or SEA inspection should ideally be performed after

threading and before coupling installation.

3.7 Couplings

Couplings must be of the same grade and type and given the same heat

treatment as the pipe on which they are to be installed. Most couplings are cut

from "mother" tubes manufactured, tested, and inspected similar to seamless

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OCTG. ERW couplings are not allowed. Couplings may also be manufactured

using sub-critical forgings or centrifugal casting for Groups 1, 2, and 3. Finished

couplings, which include machining, require a wet fluorescent MT for acceptance

before installation.

3.8 Marking, Coating, and Thread

Protection

All pipe should be marked for easy identification. The guidelines and

requirements of API 5CT Section 10 should be followed. Note that even when the

manufacturer meets API specifications, it is not required to apply the API

monogram to the product. As a minimum, all pipe purchased for down hole use

should meet API 5CT requirements and the application of the monogram should

be required when placing a purchase request.

Chevron deepwater practice has been using the 1/2/3/4 white band system for

marking minimum wall of the pipe: one is API 87.5%, two is 90%, three is 92.5%,

four is 95% or greater for minimum wall of pipe.

The manufacturer will apply an external coating to finished tubulars to protect

them from rust while in transit. This coating is usually good for three to six

months in an average environment. If pipe is stored for longer periods or in a

harsh environment, a more corrosion resistant coating should be applied to the

pipe.

Thread protectors with the appropriate thread compound should be installed on

all threaded pipe whenever it is being moved and when it is in storage. API

modified thread compound is not considered a corrosion-resistant compound and

should not be depended upon to protect threaded connections from corrosion for

more than two to three months in an average environment. Storage compounds

and several of the newer environmentally friendly thread compounds provide

better corrosion resistance and should be considered for use under thread

protectors.

3.9 Sour Service

The use of a tubular in a particular interval in a sour well is dictated by the lowest

temperature that will be encountered in that interval during the life of the well.

The lowest temperature at which a particular grade should be used is given in

Table 3-9.

Table 3-9. Sour Service Temperatures

Grade

°C °F

H-40 Any Any

J-55 Any Any

K-55 Any Any

N-80 (Q&T) 65 150

N-80 (N, N&T) 80 175

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Grade

°C °F

L-80 Any Any

C-90 Any Any

C-95 65 150

T-95 Any Any

C-110 Any Any

P-110 80 175

Q-125 107 225

Any Any

X-52

Any Any

X-56

Any Any

X-60

Any Any

X-80

Any Any

Line pipe grade for surface casing.

3.10 Temperature Effects

Temperature has a detrimental effect on the mechanical properties of steel.

Within the range of temperatures common to oil field operations, the yield and

ultimate strength and Young’s modulus decrease with increasing temperature.

The coefficient of thermal expansion increases with increasing temperature.

Poisson’s ratio is only slightly affected by temperature.

When analyzing the effect of temperature on a design, all temperature effects

should be considered. The tube resistance is lowered with temperature increase

through the adverse affect of temperature increase on yield and ultimate

strength. Conversely, the load to which the tube is subjected may decrease

through the dependence of Young’s modulus, Poisson’s ratio, and the coefficient

of thermal expansion on temperature. For example, placing a tubular in a hot

environment may decrease its resistance to differential pressure by decreasing

its yield strength. However, the increment in axial compression induced in the

string, which is proportional to the product of Young’s modulus and the coefficient

of thermal expansion, will increase thus offsetting a portion of the resistance

decrease.

3.10.1 Yield Strength

Figure 3-4 illustrates the affect of temperature on yield strength of carbon steel

from several sources. Temperature degradation of yield strength becomes

significant at 150°C (300°F), where the loss of yield strength is on the order of

10%.

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0.75

0.8

0.85

0.9

0.95

1.05

0 100 200 300 400 500 600

Temperature, Deg F

Yield Degredation Factor

Recommended

Mill Data

Consultant

Operator 1

Operator 2

Figure 3-4. Effect of Temperature on Yield Strength of Carbon Steel

NOTE: The curve labeled “Mill Data” is a composite of four mills.

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