**White Paper on**

**Fracture Control**

**Prepared for the Joint Industry Project (JIP) Committee -**

**Alternate Design with Life Cycle Management**

**May 16, 2008**

Prepared by:

Manufacturing and Quality Assurance Team

**Joint Industry Project Committee**

**Alternate Design with Life Cycle Management**

**Steering Committee:**

Alliance Pipeline, Inc. Harold Kraft

Boardwalk Pipeline Partners Frank Maria

CenterPoint Energy Chris Bullock

El Paso Pipeline Group David Bowmaster

Panhandle Energy David Johnson

Spectra Energy Richard Kivela

TransCanada Joe Zhou

Williams Larry Borski

**Committee Support:**

Kiefner and Associates (KAI) Michael Rosenfeld

Process Performance Improvement

Consultants, LLC (P-PIC) John Zurcher

Mark Hereth

Keith Leewis

**Manufacturing and Quality Assurance Team:**

CenterPoint Energy Scott Mundy

Panhandle Energy Liz Rutherford

Spectra Energy Steve Rapp

TransCanada Joe Zhou

Consultant Brian Rothwell

P-PIC Mark Hereth

P-PIC Keith Leewis

**Fracture Control Plan**

The fracture control plan addresses initiation, propagation and arrest
for the entire range of pipeline operating temperatures, pressures and
gas compositions planned for the pipeline diameter, and grade.

The key fracture control requirements are:

1.  Resistance to fracture initiation,

2.  Resistance to fracture propagation, and

3.  Arrest of ductile fracture.

Fracture control begins in the initial phases of the pipeline life
cycle, that is, design and material specification.

### Pipe Design and Material Specification

The line pipe should be specified and manufactured in accordance with
the company line pipe specification which incorporates the American
Petroleum Institute Standard 5L, product specification level 2 (PSL 2).
The pipe should meet, at a minimum the supplemental requirements (SR)
for maximum operating pressures and minimum operating pressures. The
Forty-Third edition of the standard, Effective October 2004, With Errata
December 2004, is in effect at the time of publication of this white
paper. The Forty-Fourth edition will be effective on October 1, 2008.

The chemistry of the steel plate should be specified to achieve desired
control of welding processes as well as fracture initiation, propagation
and arrest. The steel must be low carbon, low sulfur, micro alloyed,
fine-grained, fully-killed steel with calcium treatment for
desulphurization, and inclusion and shape control.

A manufacturing procedure specification and quality assurance plan are
developed that specifies the quality of the plate or coil and ultimately
the pipe. This includes a comprehensive mill inspection program to check
for inclusions that could affect the pipe quality. The quality assurance
plan should also include ultrasonic testing. Plate, coil and pipe
dimensional tolerances are controlled in accordance with API 5L and the
company pipe specification.

Pipe steel is a low carbon, calcium treated for sulfur control, high
strength, low-alloy material. Pipe carbon content is 0.12% maximum per
company specification. Pipe carbon equivalent is 0.43% maximum per the
mill's manufacturing procedure specification. PCM (carbon equivalents)
is 0.23% maximum per the mill's manufacturing procedure specification,
as per API 5L.

Fracture control tests will be conducted in accordance with API standard
5L, Appendix F and include the following tests conducted at a
temperature to be determined by the operator:

(a) SR 5A - Fracture Toughness Testing for Shear Area;

(b) SR 5B - Fracture Toughness Testing for Absorbed Energy; and

(c) SR 6 - Fracture Toughness Testing by Drop Weight Tear Test:

In establishing the temperatures at which tests are to be conducted, the
operator will consider the ambient ground temperature at the depth of
the pipe throughout the year.

Line pipe acceptance criteria for fracture control shall be:

(a) A minimum all-heat average absorbed energy requirement for the
    stress factor of 80% as a Charpy V-Notch values based on SR 19.1(b)
    of the PSL 2, Supplemental Requirements.

(b) The Drop Weight Tear Test values, which are measures of a steel
    pipeline's resistance to brittle fracture, will be at least 80
    percent of the average-shear area for all heats with a minimum
    result of 60 percent of the shear area for any single test.

(c) The Charpy Shear Area Test values, which are measures of a steel
    pipeline's resistance to fracture propagation, will be at least 80
    percent of the average-shear area for all heats with a minimum
    result of 80 percent of the shear area for any single test.

(d) The pipe is additionally manufactured in accordance with Appendix F
    of API 5L in order to control the overall fracture properties and
    insure the pipe can resist and self arrest fracture within eight
    pipe joints with a 99 percent probability. Alternatively, the
    operator may establish an alternative plan to resist crack
    initiation, crack propagation and to arrest ductile fractures,
    including but not limited to the use of crack arrestors.

Line Pipe as Manufactured

The line pipe manufacturing mill will conduct the tests specified above
as per API 5L. A Metallurgical and Pipe Test Report (MTR) will be
produced for each heat number in accordance with API 5L.

The results of a review of the line pipe with respect to the acceptance
criteria are provided below.

R**esistance to Brittle Fracture Initiation and Propagation**

The resistance to brittle fracture is determined from measurements of
the fracture appearance (shear area) using a drop-weight tear test
(DWTT) on specimens representative of the pipe body. The test
requirements are specified in API 5L, Appendix F, SR6, Drop-Weight Tear
Testing. Two test specimens are taken from a length of pipe from each
heat, referred to as a lot. API 5L, SR6.4 acceptance criteria require
that at least 80% of the heats exhibit a fracture appearance shear area
of 40% or more for the specified test temperature.

There may be instances where DWTT was not specified for existing
pipelines. API 5L, in earlier editions, did not require the use of
DWTTs. However, the chemistry of the pipe and the modern manufacturing
processes used can demonstrate that the pipe is not brittle. In
addition, Charpy toughness tests at multiple temperatures; with
temperatures as low as -50^o^F can be used. Pipe showing upper shelf
toughness at temperatures as low as -20^o^F, demonstrating ductility at
even low temperatures, and that the pipe is not brittle.

The operator may also consider the ambient ground temperature for the
part of the country that the pipeline will operate in. For example, in
the Midwestern and Southern parts of the United States the ground
temperature at the depth of pipe is approximately 55^o^F year round[^1].
The flowing gas temperature will reach this temperature at some distance
from the compressor stations, but never go below this temperature except
in above ground piping. The expected temperature drop across station
piping will not typically be more than five (5) ^o^F. If for example the
toughness testing is done at 20°F, there is a margin of approximately 30
^o^F for above ground piping[^2] and for most of the pipe, 35 ^o^F above
the temperature of the DWTTs, the temperature at which the pipe is known
to be ductile. The flowing gas temperature is well above the fracture
initiation transition temperature by virtue of the margin as compared to
the temperature at which tests were conducted.

## Ductile Fracture Resistance

The initiation resistance to leak or rupture is also estimated by the
Charpy v-Notch value and this pipe can tolerate large through wall tears
as leaks rather than ruptures. The resistance to ductile (tearing)
fracture propagation is determined by measurements of the transverse
energy absorption of Charpy test specimens representative of the pipe
body. The test requirements are specified in API 5L, Appendix F, SR5,
Absorbed Energy. Test specimens were taken from a length of pipe from
each heat. Tests are conducted using full-size or specimens. API 5L,
SR5B.3 acceptance criteria require that the lowest individual reading of
three specimens not be less than 75% of the specified value.

**Ductile Fracture Arrest - Required Fracture Toughness**

API 5L, Appendix F, Supplemental Requirement (SR) 19.1 states that the
required fracture toughness for pipe operating at a stress factor of
0.72 or greater can be estimated using equation 1.

> Cvn = 0.0345(h)^3/2^(D/2)^1/2^ (1)
>
> Where
>
> Cvn = minimum all-heat average full-size Charpy V-notch absorbed
> energy requirement, ft-lb.
>
> h = hoop stress @ MAOP
>
> D = pipe diameter, Inches

This equation is included in ASME B31.8, and is referred to as the
American Iron and Steel Institute (AISI) equation.

One can apply correlations developed by Battelle in establishing arrest
toughness thresholds for pipe as manufactured. Requirements published by
PHMSA in Special Permit Grants and proposed in a NOPR establish that a
fracture must arrest within five pipe joints with a 90% probability or
eight pipe joints with a 99% probability. Figure 1 depicts the basis
developed by Battelle[^3].

Figure 1 -- Fracture Length Probabilities as Related to Percentage of
Arrest Pipes

**Additional Considerations -- Adjustment for Higher Toughness Pipe**

The equations described above for calculating required toughness levels
were developed when lower toughness pipe was being manufactured. The
understanding of the role and importance of chemistry increased
dramatically over the eighties and nineties. Brian Leis and Robert Eiber
evaluated the validity of the American Iron and Steel Institute and
other equations referenced in ASME B31.8S for pipe of higher
toughness[^4]. Validation work applying the Battelle Formula showed that
the formula is non-conservative for higher toughness pipe, i.e., pipe
with toughness values greater than 70 ft-lbs[^5]. Leis and Eiber
developed a correction to account for the non-conservative nature of the
original formula as show below, in the same reference.

CV~arrest~ = CV + 0.00269CV^2.04^ -- 15.62 (2)

For example, the required toughness for a pipe with a calculated
toughness using the Battelle equation of 75 ft-lbs., is +2 ft-lbs. The
adjustment for pipe with a required toughness of 100 ft-lbs., is +17
ft-lbs., or an adjusted toughness of 117 ft-lbs.

The Battelle Formula can be applied to line pipe to evaluate the need to
adjust for higher toughness pipe. The Battelle Formula is another widely
recognized equation, referenced in Canadian and Australian standards and
also included in ASME B31.8. The Battelle Formula, referred to as the
two-step model, has been simplified for use in API 5L and ASME B31.8, as
shown below.

> CV = 0.0108(h)^2^(Dt/2)^1/3^ (3)
>
> Where
>
> CV = minimum all-heat average full-size Charpy V-notch absorbed energy
> requirement, ft-lb.
>
> h = hoop stress
>
> D = pipe diameter, Inches
>
> t= pipe wall thickness, inches

The Battelle Formula is known to be valid for pipe grades up to and
including X70 operated in the range of 60 to 80% of SMYS[^6].

**Additional Considerations -- Enriched Gas and Potential for Two-Phase
Decompression**

The key to fracture control and ultimately arrest is that the gas
decompression velocity is greater (faster) than the velocity of a
fracture tip running through the steel. Rich gases are known to have a
slower decompression velocity, therefore cracks in tougher steels,
although running at a slower speed, continue to remain fully hoop stress
loaded. These cracks can continue running as the driving pressure is not
escaping out of the rupture fast enough to drop the internal pressure
and help the crack tip blunt, thereby allowing arrest[^7].

The question that arises is, does an environment exist following a
rupture of the pipeline where two-phase decompression can occur. The
answer is obtained by comparing the pipeline operating regime with the
phase diagram of an enriched gas. The phase diagram for a gas is
dependent on its composition.

Battelle has developed a model for predicting the behavior of rich gases
and is referred to as the Battelle Two Curve Model. Alternatively, an
operator can model an enriched gas scenario as described below.

The operator will review historical and projected gas quality and
identify a composition that best represents an enriched gas scenario for
the pipeline. This will include consideration of the existing tariff
provisions for parameters such as hydrocarbon dew point and hexanes
plus. An enriched gas scenario generally occurs when unprocessed gas is
commingled with processed gas. The unprocessed gas when blended with
processed gas will yield a gas that is more enriched than the gases
considered in the development of the simplified Battelle Formula. For
comparative purposes, the gas composition of the gas as envisioned in
the Battelle work and an example enriched gas scenario are shown in
Table 1.

In general, the gas becomes more enriched as the hexanes plus fraction
increases.

##### Table 1 -- Example Gas Compositions

+-----------------------+-----------------------+-----------------------+
| #### Component        | **Example Lean Gas**  | **Example Enriched    |
|                       |                       | Gas**                 |
+-----------------------+-----------------------+-----------------------+
| **Methane**           | 93.88                 | 95.44                 |
+-----------------------+-----------------------+-----------------------+
| **Ethane**            | 4.964                 | 2.482                 |
+-----------------------+-----------------------+-----------------------+
| **Propane**           | 0.262                 | 0.524                 |
+-----------------------+-----------------------+-----------------------+
|                       |                       |                       |
+-----------------------+-----------------------+-----------------------+
| **iso-Butane**        | 0.057                 | 0.113                 |
+-----------------------+-----------------------+-----------------------+
| **n-Butane**          | 0.094                 | 0.187                 |
+-----------------------+-----------------------+-----------------------+
| **iso-Pentane**       | 0.036                 | 0.284                 |
+-----------------------+-----------------------+-----------------------+
| **n-Pentane**         | 0.030                 | 0.236                 |
+-----------------------+-----------------------+-----------------------+
|                       |                       |                       |
+-----------------------+-----------------------+-----------------------+
| **Hexane**            | 0.029                 | 0.057                 |
+-----------------------+-----------------------+-----------------------+
| **Heptane**           | 0.024                 | 0.048                 |
+-----------------------+-----------------------+-----------------------+
| **Octane**            | 0.003                 | 0.006                 |
+-----------------------+-----------------------+-----------------------+
|                       |                       |                       |
+-----------------------+-----------------------+-----------------------+
| **Nitrogen**          | 0.251                 | 0.251                 |
+-----------------------+-----------------------+-----------------------+
| **Carbon Dioxide**    | 0.371                 | 0.372                 |
+-----------------------+-----------------------+-----------------------+
|                       |                       |                       |
+-----------------------+-----------------------+-----------------------+
| **Higher Heating      | 1,053                 | 1,057                 |
| Value**[^8]           |                       |                       |
+-----------------------+-----------------------+-----------------------+
| **Cricondentherm --   | -1 ^o^F               | 31 ^o^F               |
| Hydrocarbon Dew       |                       |                       |
| Point**               |                       |                       |
+-----------------------+-----------------------+-----------------------+

Figure 2 depicts the phase diagram for the example, enriched gas as
defined in Table 1. The phase diagram is the combination of pressures
and corresponding temperatures that describe the vapor-liquid
equilibrium of the enriched gas[^9]. The phase diagram has a signature
curvature shape as indicated by the blue triangles in Figure 2. The
operating regime for an example pipeline is also depicted in the figure
using red circles. It reflects the pressure and temperature decay that
occurs as gas travels away from the compressor station (at the far
right, for example, a compressor station discharge - P=1,480 psig and
T=145^o^F). The operating regime is based on a temperature loss of four
degrees Fahrenheit and a pressure loss of five pounds per mile. The
pressure loss continues until the gas reaches the next compressor
station, whereas the flowing gas temperature decreases until it
equilibrates with the ambient ground temperature; which in this example
is approximately 55^o^F.

![](media/image1.wmf)

**Figure 2 -- Depiction of Enriched Gas Phase Diagram and**

##### Pipeline Operating Regime

If a rupture were to occur, it is generally accepted that the gas
release will be isentropic[^10], that is, there will be no work exerted
and no loss of energy. This is a very conservative assumption, as line
pipe will be installed under at least 36-inches of ground cover. In
fact, the force exerted to remove the ground cover off of the pipe and
allow the free flow of gas will consume energy.

In any event, as the gas releases at the point of rupture, the
temperature of the gas will decrease as the pressure decreases. The rate
of temperature decrease is controlled by the Joule-Thomson effect; that
is, for natural gas, there is a seven degree Fahrenheit temperature loss
for every 100 pounds of pressure drop. A line, referred to as the
Joule-Thomson (JT) line, can be constructed from any point on the
operating regime, intercepting the phase diagram, to evaluate whether
two-phase decompression can occur. The JT line depicted on Figure 2
shows that if a rupture were to occur at a location of the line where
the pressure was 900 psig and the corresponding flowing gas temperature
was 55^o^F that two-phase decompression can occur. However, the
important point is that while two-phases can exist, the pressure at
which it occurs is at approximately 900 psig. At pressures greater than
900 psig, the decompression is single phase.

It is known that a high-pressure pipeline will lose about half of its
pressure from a rupture in approximately two minutes[^11]. The reduction
in this scenario from 1,480 to 900 psig would occur in approximately 75
percent of that time or 90 seconds. Analyses of past incidents have
shown that ductile fractures have velocities in the range of 400 to 800
feet per second[^12]. The most conservative approach is to assume the
lower end of the range, 400 feet per second. Presuming that a pipe joint
is approximately 40 feet in length, a running ductile fracture will
travel 10 joints un-arrested in one second. However, recall that
virtually all of the joints were found to be arrest pipe based on the
fracture toughness requirements specified above. Even in the event that
there were three consecutive non-arrest joints, the fracture will arrest
within the fourth, in approximately one half of a second. This analysis
demonstrates that any fracture will have arrested well before the
pressure will reach 900 psig, so the pipe will never experience a
two-phase regime prior to fracture arresting. Constructing a JT line
from any other point on the operating line at lower pressures will yield
a similar result; that is, two phases will not exist prior to fracture
arrest.

The operator must apply the approach to the specific circumstances that
exist for the subject pipeline system. Two-phase decompression occurs
when the operating line intersects the phase diagram. This will occur
more readily as the ground temperature is lower or the gas is enriched;
it becomes more likely as the two occur coincidentally.

**Prevention of Fracture Initiation -- Practices and Procedures**

The most effective means of preventing fracture of the pipe is to
prevent the line from being struck through excavation or allowing
corrosion to develop. The enhanced provisions of damage prevention and
internal and external corrosion prevention programs provided as part of
the operator's Integrity Management Program will serve as the first
lines of defense. This includes active measures such as participation in
one-call systems, supervision of excavations[^13], communication and
outreach with the community and landowners[^14], and frequent
patrolling, among other leading practices such as the Common Ground
Alliance - Best Practices for Damage Prevention. It also includes
regular daily monitoring of the as-received gas quality, targeted use of
coupons, use of periodic above ground surveys and in-line cleaning and
inspection tools to identify and remediate actionable anomalies.

[^1]: ^?^ Louisiana Department of Natural Resources.

[^2]: Above ground piping is typically in stations is operated at lower
    stress levels.

[^3]: "Fracture Control Technology for Natural Gas Pipelines", PRCI
    Report No. PR-3-9113, Battelle Memorial Institute, December 1993;
    Figure 53, page 86.

[^4]: Leis, Brian, and Robert Eiber, Fracture Propagation Control in
    Onshore Transmission Pipelines, Onshore Pipeline Technology
    Conference, Istanbul, Turkey, December, 1988, p. 19.

[^5]: Ibid, p. 19

[^6]: Ibid, p. 23

[^7]: Ibid, p. 3.

[^8]: Note: Enriched gases have often been referred to in the literature
    as gases having higher heating values, or Btu content. The richness
    of the gas is not reliably related to the heating value; the dew
    point of the gas, and actually the cricondentherm hydrocarbon dew
    point is actually the more appropriate way to describe an enriched
    gas. As can be seen in Table 1, the heating values of the two gases
    are very similar, it is the elevated levels of the higher molecular
    weight hydrocarbons that make the gas richer, in this case yielding
    a higher cricondentherm hydrocarbon dew point.

[^9]: The pressures and temperatures for the phase diagram were derived
    using a Peng Robinson equation of state applied for the composition
    of the enriched gas in Table 1.

[^10]: Leis and Eiber, p. 14; and Makino, H., Natural Gas Decompression
    Behavior in High Pressure Pipelines, ISIJ International, Vol. 41
    (2001), No. 4, pp. 389--395.

[^11]: GRI-Study on Valve Spacing

[^12]: Ibid, Leis and Eiber, p. 4.

[^13]: API RP1166 is a recommended practice for monitoring excavations
    on the pipeline R-O-W.

[^14]: API RP1162 is a recommended practice for developing and
    implementing communication and public outreach programs.