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� 195.452 Pipeline
integrity management in high consequence areas.
(a) Which
pipelines are covered by this section? This section applies to each hazardous
liquid pipeline and carbon dioxide pipeline that could affect a high
consequence area, including any pipeline located in a high consequence area
unless the operator effectively demonstrates by risk assessment that the
pipeline could not affect the area. (Appendix C of this part provides
guidance on determining if a pipeline could affect a high consequence area.)
Covered pipelines are categorized as follows: (1)
Category 1 includes pipelines existing on May 29, 2001, that were owned or
operated by an operator who owned or operated a total of 500 or more miles of
pipeline subject to this part. (2)
Category 2 includes pipelines existing on May 29, 2001, that were owned or
operated by an operator who owned or operated less than 500 miles of pipeline
subject to this part. (3)
Category 3 includes pipelines constructed or converted after May 29, 2001. (b) What
program and practices must operators use to manage pipeline integrity? Each
operator of a pipeline covered by this section must: (1) Develop
a written integrity management program that addresses the risks on each
segment of pipeline in the first column of the following table not later than
the date in the second column:
(2) Include
in the program an identification of each pipeline or pipeline segment in the
first column of the following table not later than the date in the second
column:
(3) Include
in the program a plan to carry out baseline assessments of line pipe as
required by paragraph (c) of this section. (4) Include
in the program a framework that� (i)
Addresses each element of the integrity management program under paragraph
(f) of this section, including continual integrity assessment and evaluation
under paragraph (j) of this section; and (ii)
Initially indicates how decisions will be made to implement each element. (5)
Implement and follow the program. (6) Follow
recognized industry practices in carrying out this section, unless� (i) This
section specifies otherwise; or (ii) The
operator demonstrates that an alternative practice is supported by a reliable
engineering evaluation and provides an equivalent level of public safety and
environmental protection. (c) What
must be in the baseline assessment plan? (1) An operator must include
each of the following elements in its written baseline assessment plan: (i) The
methods selected to assess the integrity of the line pipe. An operator must
assess the integrity of the line pipe by any of the following methods. The
methods an operator selects to assess low frequency electric resistance
welded pipe or lap welded pipe susceptible to longitudinal seam failure must
be capable of assessing seam integrity and of detecting corrosion and
deformation anomalies. (A)
Internal inspection tool or tools capable of detecting corrosion and
deformation anomalies including dents, gouges and grooves; (B)
Pressure test conducted in accordance with subpart E of this part; (C)
External corrosion direct assessment in accordance with �195.588; or (D) Other
technology that the operator demonstrates can provide an equivalent
understanding of the condition of the line pipe. An operator choosing this
option must notify
the Office of Pipeline Safety (OPS) 90 days before conducting the assessment,
by sending a notice to the address or facsimile number specified in paragraph
(m) of this section. (ii) A
schedule for completing the integrity assessment; (iii) An
explanation of the assessment methods selected and evaluation of risk factors
considered in establishing the assessment schedule. (2) An
operator must document, prior to implementing any changes to the plan, any
modification to the plan, and reasons for the modification. (d) When
must operators complete baseline assessments? Operators must complete
baseline assessments as follows: (1) Time
periods. Complete assessments before the following deadlines:
(2) Prior
assessment. To satisfy the requirements of paragraph (c)(1)(i) of this
section for pipelines in the first column of the following table, operators
may use integrity assessments conducted after the date in the second column,
if the integrity assessment method complies with this section. However, if an
operator uses this prior assessment as its baseline assessment, the operator
must reassess the line pipe according to paragraph (j)(3) of this section.
The table follows:
(3) Newly-identified
areas. (i) When information is available from the information analysis
(see paragraph (g) of this section), or from Census Bureau maps, that the
population density around a pipeline segment has changed so as to fall within
the definition in �195.450 of a high population area or other populated area,
the operator must incorporate the area into its baseline assessment plan as a
high consequence area within one year from the date the area is identified.
An operator must complete the baseline assessment of any line pipe that could
affect the newly-identified high consequence area within five years from the
date the area is identified. (ii) An
operator must incorporate a new unusually sensitive area into its baseline
assessment plan within one year from the date the area is identified. An
operator must complete the baseline assessment of any line pipe that could
affect the newly-identified high consequence area within five years from the
date the area is identified. (e) What
are the risk factors for establishing an assessment schedule (for both the
baseline and continual integrity assessments)? (1) An operator must
establish an integrity assessment schedule that prioritizes pipeline segments
for assessment (see paragraphs (d)(1) and (j)(3) of this section). An
operator must base the assessment schedule on all risk factors that reflect
the risk conditions on the pipeline segment. The factors an operator must
consider include, but are not limited to: (i) Results
of the previous integrity assessment, defect type and size that the
assessment method can detect, and defect growth rate; (ii) Pipe
size, material, manufacturing information, coating type and condition, and
seam type; (iii) Leak
history, repair history and cathodic protection history; (iv)
Product transported; (v) Operating
stress level; (vi)
Existing or projected activities in the area; (vii) Local
environmental factors that could affect the pipeline ( e.g., corrosivity
of soil, subsidence, climatic); (viii)
geo-technical hazards; and (ix)
Physical support of the segment such as by a cable suspension bridge. (2)
Appendix C of this part provides further guidance on risk factors. (f) What
are the elements of an integrity management program? An integrity
management program begins with the initial framework. An operator must
continually change the program to reflect operating experience, conclusions
drawn from results of the integrity assessments, and other maintenance and
surveillance data, and evaluation of consequences of a failure on the high
consequence area. An operator must include, at minimum, each of the following
elements in its written integrity management program: (1) A
process for identifying which pipeline segments could affect a high
consequence area; (2) A
baseline assessment plan meeting the requirements of paragraph (c) of this
section; (3) An
analysis that integrates all available information about the integrity of the
entire pipeline and the consequences of a failure (see paragraph (g) of this
section); (4)
Criteria for remedial actions to address integrity issues raised by the
assessment methods and information analysis (see paragraph (h) of this
section); (5) A
continual process of assessment and evaluation to maintain a pipeline's
integrity (see paragraph (j) of this section); (6)
Identification of preventive and mitigative measures to protect the high
consequence area (see paragraph (i) of this section); (7) Methods
to measure the program's effectiveness (see paragraph (k) of this section); (8) A
process for review of integrity assessment results and information analysis
by a person qualified to evaluate the results and information (see paragraph
(h)(2) of this section). (g) What
is an information analysis? In periodically evaluating the integrity of
each pipeline segment (paragraph (j) of this section), an operator must
analyze all available information about the integrity of the entire pipeline
and the consequences of a failure. This information includes: (1)
Information critical to determining the potential for, and preventing, damage
due to excavation, including current and planned damage prevention
activities, and development or planned development along the pipeline
segment; (2) Data
gathered through the integrity assessment required under this section; (3) Data
gathered in conjunction with other inspections, tests, surveillance and
patrols required by this Part, including, corrosion control monitoring and
cathodic protection surveys; and (4)
Information about how a failure would affect the high consequence area, such
as location of the water intake. (h) What
actions must an operator take to address integrity issues? �(1) General
requirements . An operator must take prompt action to address all
anomalous conditions the operator discovers through the integrity assessment
or information analysis. In addressing all conditions, an operator must
evaluate all anomalous conditions and remediate those that could reduce a
pipeline's integrity. An operator must be able to demonstrate that the
remediation of the condition will ensure the condition is unlikely to pose a
threat to the long-term integrity of the pipeline. An operator must comply
with �195.422 when making a repair. (i) Temporary
pressure reduction . An operator must notify PHMSA, in accordance with paragraph (m)
of this section, if the operator cannot meet the schedule for evaluation and
remediation required under paragraph (h)(3) of this section and cannot
provide safety through a temporary reduction in operating pressure. (ii) Long-term
pressure reduction . When a pressure reduction exceeds 365 days, the
operator must notify
PHMSA in accordance with paragraph (m) of this section and explain the
reasons for the delay. An operator must also take further remedial action to
ensure the safety of the pipeline. (2) Discovery
of condition. Discovery of a condition occurs when an operator has
adequate information about the condition to determine that the condition
presents a potential threat to the integrity of the pipeline. An operator
must promptly, but no later than 180 days after an integrity assessment,
obtain sufficient information about a condition to make that determination,
unless the operator can demonstrate that the 180-day period is impracticable. (3) Schedule
for evaluation and remediation . An operator must complete remediation of
a condition according to a schedule prioritizing the conditions for
evaluation and remediation. If an operator cannot meet the schedule for any
condition, the operator must explain the reasons why it cannot meet the
schedule and how the changed schedule will not jeopardize public safety or
environmental protection. (4) Special
requirements for scheduling remediation �(i) Immediate repair
conditions. An operator's evaluation and remediation schedule must
provide for immediate repair conditions. To maintain safety, an operator must
temporarily reduce operating pressure or shut down the pipeline until the
operator completes the repair of these conditions. An operator must calculate
the temporary reduction in operating pressure using the formula in section
451.7 of ASME/ANSI B31.4 (incorportaed by reference, see �195.3). An operator
must treat the following conditions as immediate repair conditions: (A) Metal
loss greater than 80% of nominal wall regardless of dimensions. (B) A
calculation of the remaining strength of the pipe shows a predicted burst
pressure less than the established maximum operating pressure at the location
of the anomaly. Suitable remaining strength calculation methods include, but
are not limited to, ASME/ANSI B31G (�Manual for Determining the Remaining
Strength of Corroded Pipelines� (1991) or AGA Pipeline Research Committee
Project PR�3�805 (�A Modified Criterion for Evaluating the Remaining Strength
of Corroded Pipe� (December 1989)). These documents are incorporated by
reference and are available at the addresses listed in �195.3. (C) A dent
located on the top of the pipeline (above the 4 and 8 o'clock positions) that
has any indication of metal loss, cracking or a stress riser. (D) A dent
located on the top of the pipeline (above the 4 and 8 o'clock positions) with
a depth greater than 6% of the nominal pipe diameter. (E) An
anomaly that in the judgment of the person designated by the operator to
evaluate the assessment results requires immediate action. (ii) 60-day
conditions. Except for conditions listed in paragraph (h)(4)(i) of this
section, an operator must schedule evaluation and remediation of the
following conditions within 60 days of discovery of condition. (A) A dent
located on the top of the pipeline (above the 4 and 8 o'clock positions) with
a depth greater than 3% of the pipeline diameter (greater than 0.250 inches
in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12). (B) A dent
located on the bottom of the pipeline that has any indication of metal loss,
cracking or a stress riser. (iii) 180-day
conditions. Except for conditions listed in paragraph (h)(4)(i) or (ii)
of this section, an operator must schedule evaluation and remediation of the
following within 180 days of discovery of the condition: (A) A dent
with a depth greater than 2% of the pipeline's diameter (0.250 inches in
depth for a pipeline diameter less than NPS 12) that affects pipe curvature
at a girth weld or a longitudinal seam weld. (B) A dent
located on the top of the pipeline (above 4 and 8 o'clock position) with a
depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a
pipeline diameter less than NPS 12). (C) A dent
located on the bottom of the pipeline with a depth greater than 6% of the
pipeline's diameter. (D) A
calculation of the remaining strength of the pipe shows an operating pressure
that is less than the current established maximum operating pressure at the
location of the anomaly. Suitable remaining strength calculation methods
include, but are not limited to, ASME/ANSI B31G (�Manual for Determining the
Remaining Strength of Corroded Pipelines� (1991)) or AGA Pipeline Research
Committee Project PR�3�805 (�A Modified Criterion for Evaluating the
Remaining Strength of Corroded Pipe� (December 1989)). These documents are
incorporated by reference and are available at the addresses listed in
�195.3. (E) An area
of general corrosion with a predicted metal loss greater than 50% of nominal
wall. (F)
Predicted metal loss greater than 50% of nominal wall that is located at a
crossing of another pipeline, or is in an area with widespread
circumferential corrosion, or is in an area that could affect a girth weld. (G) A
potential crack indication that when excavated is determined to be a crack. (H)
Corrosion of or along a longitudinal seam weld. (I) A gouge
or groove greater than 12.5% of nominal wall. (iv) Other
conditions. In addition to the conditions listed in paragraphs (h)(4)(i)
through (iii) of this section, an operator must evaluate any condition
identified by an integrity assessment or information analysis that could
impair the integrity of the pipeline, and as appropriate, schedule the
condition for remediation. Appendix C of this part contains guidance
concerning other conditions that an operator should evaluate. (i) What
preventive and mitigative measures must an operator take to protect the high
consequence area? �(1) General requirements. An operator must take
measures to prevent and mitigate the consequences of a pipeline failure that
could affect a high consequence area. These measures include conducting a
risk analysis of the pipeline segment to identify additional actions to
enhance public safety or environmental protection. Such actions may include,
but are not limited to, implementing damage prevention best practices, better
monitoring of cathodic protection where corrosion is a concern, establishing
shorter inspection intervals, installing EFRDs on the pipeline segment,
modifying the systems that monitor pressure and detect leaks, providing
additional training to personnel on response procedures, conducting drills
with local emergency responders and adopting other management controls. (2) Risk
analysis criteria. In identifying the need for additional preventive and
mitigative measures, an operator must evaluate the likelihood of a pipeline
release occurring and how a release could affect the high consequence area.
This determination must consider all relevant risk factors, including, but not
limited to: (i) Terrain
surrounding the pipeline segment, including drainage systems such as small
streams and other smaller waterways that could act as a conduit to the high
consequence area; (ii)
Elevation profile; (iii)
Characteristics of the product transported; (iv) Amount
of product that could be released; (v)
Possibility of a spillage in a farm field following the drain tile into a
waterway; (vi)
Ditches along side a roadway the pipeline crosses; (vii)
Physical support of the pipeline segment such as by a cable suspension
bridge; (viii)
Exposure of the pipeline to operating pressure exceeding established maximum
operating pressure. (3) Leak
detection. An operator must have a means to detect leaks on its pipeline
system. An operator must evaluate the capability of its leak detection means
and modify, as necessary, to protect the high consequence area. An operator's
evaluation must, at least, consider, the following factors�length and size of
the pipeline, type of product carried, the pipeline's proximity to the high
consequence area, the swiftness of leak detection, location of nearest
response personnel, leak history, and risk assessment results. (4) Emergency
Flow Restricting Devices (EFRD). If an operator determines that an EFRD
is needed on a pipeline segment to protect a high consequence area in the
event of a hazardous liquid pipeline release, an operator must install the
EFRD. In making this determination, an operator must, at least, consider the
following factors�the swiftness of leak detection and pipeline shutdown
capabilities, the type of commodity carried, the rate of potential leakage,
the volume that can be released, topography or pipeline profile, the
potential for ignition, proximity to power sources, location of nearest
response personnel, specific terrain between the pipeline segment and the
high consequence area, and benefits expected by reducing the spill size. (j) What
is a continual process of evaluation and assessment to maintain a pipeline's
integrity? �(1) General. After completing the baseline integrity
assessment, an operator must continue to assess the line pipe at specified
intervals and periodically evaluate the integrity of each pipeline segment
that could affect a high consequence area. (2) Evaluation.
An operator must conduct a periodic evaluation as frequently as needed to
assure pipeline integrity. An operator must base the frequency of evaluation
on risk factors specific to its pipeline, including the factors specified in
paragraph (e) of this section. The evaluation must consider the results of
the baseline and periodic integrity assessments, information analysis
(paragraph (g) of this section), and decisions about remediation, and
preventive and mitigative actions (paragraphs (h) and (i) of this section). (3) Assessment
intervals . An operator must establish five-year intervals, not to exceed
68 months, for continually assessing the line pipe's integrity. An operator
must base the assessment intervals on the risk the line pipe poses to the
high consequence area to determine the priority for assessing the pipeline
segments. An operator must establish the assessment intervals based on the
factors specified in paragraph (e) of this section, the analysis of the
results from the last integrity assessment, and the information analysis
required by paragraph (g) of this section. (4) Variance from the 5-year
intervals in limited situations �(i) Engineering basis. An
operator may be able to justify an engineering basis for a longer assessment
interval on a segment of line pipe. The justification must be supported by a
reliable engineering evaluation combined with the use of other technology,
such as external monitoring technology, that provides an understanding of the
condition of the line pipe equivalent to that which can be obtained from the
assessment methods allowed in paragraph (j)(5) of this section. An operator
must notify OPS
270 days before the end of the five-year (or less) interval of the
justification for a longer interval, and propose an alternative interval. An
operator must send the notice to the address specified in paragraph (m) of
this section. (ii) Unavailable technology. An
operator may require a longer assessment period for a segment of line pipe
(for example, because sophisticated internal inspection technology is not
available). An operator must justify the reasons why it cannot comply with
the required assessment period and must also demonstrate the actions it is
taking to evaluate the integrity of the pipeline segment in the interim. An
operator must notify
OPS 180 days before the end of the five-year (or less) interval that the
operator may require a longer assessment interval, and provide an estimate of
when the assessment can be completed. An operator must send a notice to the
address specified in paragraph (m) of this section. (5) Assessment
methods. An operator must assess the integrity of the line pipe by any of
the following methods. The methods an operator selects to assess low
frequency electric resistance welded pipe or lap welded pipe susceptible to
longitudinal seam failure must be capable of assessing seam integrity and of
detecting corrosion and deformation anomalies. (i)
Internal inspection tool or tools capable of detecting corrosion and
deformation anomalies including dents, gouges and grooves; (ii)
Pressure test conducted in accordance with subpart E of this part; (iii)
External corrosion direct assessment in accordance with �195.588; or (iv) Other technology that the
operator demonstrates can provide an equivalent understanding of the
condition of the line pipe. An operator choosing this option must notify OPS 90 days
before conducting the assessment, by sending a notice to the address or
facsimile number specified in paragraph (m) of this section. (k) What
methods to measure program effectiveness must be used? An operator's
program must include methods to measure whether the program is effective in
assessing and evaluating the integrity of each pipeline segment and in
protecting the high consequence areas. See Appendix C of this part for
guidance on methods that can be used to evaluate a program's effectiveness. (l) What
records must be kept? (1) An operator must maintain for review during an
inspection: (i) A
written integrity management program in accordance with paragraph (b) of this
section. (ii)
Documents to support the decisions and analyses, including any modifications,
justifications, variances, deviations and determinations made, and actions
taken, to implement and evaluate each element of the integrity management
program listed in paragraph (f) of this section. (2) See
Appendix C of this part for examples of records an operator would be required
to keep. (m) How does an operator notify PHMSA? An
operator must provide any notification required by this section by: (1) Entering the information directly
on the Integrity Management Database Web site at http://primis.phmsa.dot.gov/imdb/;
(2) Sending the notification to the
Information Resources Manager, Office of Pipeline Safety, Pipeline and
Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE.,
Washington, DC 20590; or (3) Sending the notification to the
Information Resources Manager by facsimile to (202) 366�7128. [Amdt.
195�70, 65 FR 75406, Dec. 1, 2000, as amended by Amdt. 195�74, 67 FR 1660,
1661, Jan. 14, 2002; Amdt. 195�76, 67 FR 2143, Jan. 16, 2002; 67 FR 46911,
July 17, 2002; 70 FR 11140, Mar. 8, 2005; Amdt. 195�85, 70 FR 61576, Oct. 25,
2005; Amdt. 195�87, 72 FR 39017, July 17, 2007; 73 FR 16571, Mar. 28, 2008;
73 FR 31646, June 3, 2008] Editorial
Note:
By Amdt. 195-87, 72 FR 39017, July 17, 2007, �195.452 was amended
by revising paragraph (h)(4); however, the amendment could not be
incorporated due to inaccurate amendatory instruction.
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Appendix C to Part 195�Guidance
for Implementation of an Integrity Management Program
This
Appendix gives guidance to help an operator implement the requirements of the
integrity management program rule in ��195.450 and 195.452. Guidance is
provided on: (1)
Information an operator may use to identify a high consequence area and
factors an operator can use to consider the potential impacts of a release on
an area; (2) Risk
factors an operator can use to determine an integrity assessment schedule; (3) Safety
risk indicator tables for leak history, volume or line size, age of pipeline,
and product transported, an operator may use to determine if a pipeline
segment falls into a high, medium or low risk category; (4) Types
of internal inspection tools an operator could use to find pipeline
anomalies; (5)
Measures an operator could use to measure an integrity management program's
performance; and (6) Types
of records an operator will have to maintain. (7) Types
of conditions that an integrity assessment may identify that an operator
should include in its required schedule for evaluation and remediation. I.
Identifying a high consequence area and factors for considering a pipeline
segment's potential impact on a high consequence area. A. The rule
defines a High Consequence Area as a high population area, an other populated
area, an unusually sensitive area, or a commercially navigable waterway. The
Office of Pipeline Safety (OPS) will map these areas on the National Pipeline
Mapping System (NPMS). An operator, member of the public, or other government
agency may view and download the data from the NPMS home page http://www.npms.rspa.dot.gov.
OPS will maintain the NPMS and update it periodically. However, it is an
operator's responsibility to ensure that it has identified all high
consequence areas that could be affected by a pipeline segment. An operator
is also responsible for periodically evaluating its pipeline segments to look
for population or environmental changes that may have occurred around the
pipeline and to keep its program current with this information. (Refer to
�195.452(d)(3).) For more information to help in identifying high consequence
areas, an operator may refer to: (1) Digital
Data on populated areas available on U.S. Census Bureau maps. (2)
Geographic Database on the commercial navigable waterways available on http://www.bts.gov/gis/ntatlas/networks.html.
(3) The
Bureau of Transportation Statistics database that includes commercially
navigable waterways and non-commercially navigable waterways. The database
can be downloaded from the BTS website at http://www.bts.gov/gis/ntatlas/networks.html.
B. The rule
requires an operator to include a process in its program for identifying
which pipeline segments could affect a high consequence area and to take
measures to prevent and mitigate the consequences of a pipeline failure that
could affect a high consequence area. (See ��195.452 (f) and (i).) Thus, an
operator will need to consider how each pipeline segment could affect a high
consequence area. The primary source for the listed risk factors is a US DOT
study on instrumented Internal Inspection devices (November 1992). Other
sources include the National Transportation Safety Board, the Environmental
Protection Agency and the Technical Hazardous Liquid Pipeline Safety
Standards Committee. The following list provides guidance to an operator on
both the mandatory and additional factors: (1) Terrain
surrounding the pipeline. An operator should consider the contour of the land
profile and if it could allow the liquid from a release to enter a high
consequence area. An operator can get this information from topographical
maps such as U.S. Geological Survey quadrangle maps. (2) Drainage
systems such as small streams and other smaller waterways that could serve as
a conduit to a high consequence area. (3)
Crossing of farm tile fields. An operator should consider the possibility of
a spillage in the field following the drain tile into a waterway. (4)
Crossing of roadways with ditches along the side. The ditches could carry a
spillage to a waterway. (5) The
nature and characteristics of the product the pipeline is transporting
(refined products, crude oils, highly volatile liquids, etc.) Highly volatile
liquids becomes gaseous when exposed to the atmosphere. A spillage could
create a vapor cloud that could settle into the lower elevation of the ground
profile. (6)
Physical support of the pipeline segment such as by a cable suspension
bridge. An operator should look for stress indicators on the pipeline
(strained supports, inadequate support at towers), atmospheric corrosion,
vandalism, and other obvious signs of improper maintenance. (7)
Operating conditions of the pipeline (pressure, flow rate, etc.). Exposure of
the pipeline to an operating pressure exceeding the established maximum
operating pressure. (8) The
hydraulic gradient of the pipeline. (9) The
diameter of the pipeline, the potential release volume, and the distance
between the isolation points. (10)
Potential physical pathways between the pipeline and the high consequence
area. (11)
Response capability (time to respond, nature of response). (12)
Potential natural forces inherent in the area (flood zones, earthquakes,
subsidence areas, etc.) II. Risk
factors for establishing frequency of assessment. A. By
assigning weights or values to the risk factors, and using the risk indicator
tables, an operator can determine the priority for assessing pipeline
segments, beginning with those segments that are of highest risk, that have
not previously been assessed. This list provides some guidance on some of the
risk factors to consider (see �195.452(e)). An operator should also develop
factors specific to each pipeline segment it is assessing, including: (1)
Populated areas, unusually sensitive environmental areas, National Fish
Hatcheries, commercially navigable waters, areas where people congregate. (2) Results
from previous testing/inspection. (See �195.452(h).) (3) Leak
History. (See leak history risk table.) (4) Known
corrosion or condition of pipeline. (See �195.452(g).) (5)
Cathodic protection history. (6) Type
and quality of pipe coating (disbonded coating results in corrosion). (7) Age of
pipe (older pipe shows more corrosion�may be uncoated or have an ineffective
coating) and type of pipe seam. (See Age of Pipe risk table.) (8) Product
transported (highly volatile, highly flammable and toxic liquids present a
greater threat for both people and the environment) (see Product transported
risk table.) (9) Pipe
wall thickness (thicker walls give a better safety margin) (10) Size
of pipe (higher volume release if the pipe ruptures). (11)
Location related to potential ground movement (e.g., seismic faults, rock
quarries, and coal mines); climatic (permafrost causes settlement�Alaska);
geologic (landslides or subsidence). (12)
Security of throughput (effects on customers if there is failure requiring
shutdown). (13) Time
since the last internal inspection/pressure testing. (14) With
respect to previously discovered defects/anomalies, the type, growth rate,
and size. (15)
Operating stress levels in the pipeline. (16)
Location of the pipeline segment as it relates to the ability of the operator
to detect and respond to a leak. ( e.g., pipelines deep underground,
or in locations that make leak detection difficult without specific sectional
monitoring and/or significantly impede access for spill response or any other
purpose). (17)
Physical support of the segment such as by a cable suspension bridge. (18)
Non-standard or other than recognized industry practice on pipeline
installation ( e.g., horizontal directional drilling). B. Example:
This example illustrates a hypothetical model used to establish an
integrity assessment schedule for a hypothetical pipeline segment. After we
determine the risk factors applicable to the pipeline segment, we then assign
values or numbers to each factor, such as, high (5), moderate (3), or low
(1). We can determine an overall risk classification (A, B, C) for the
segment using the risk tables and a sliding scale (values 5 to 1) for risk
factors for which tables are not provided. We would classify a segment as C
if it fell above i. For the
baseline assessment schedule, we would plan to assess 50% of all pipeline
segments covered by the rule, beginning with the highest risk segments,
within the first 3 ii. For our
hypothetical pipeline segment, we have chosen the following risk factors and
obtained risk factor values from the appropriate table. The values assigned
to the risk factors are for illustration only. Age of
pipeline: assume
30 years old (refer to �Age of Pipeline� risk table)� Risk
Value=5 Pressure
tested: tested
once during construction� Risk
Value=5 Coated: (yes/no)�yes Coating
Condition: Recent
excavation of suspected areas showed holidays in coating (potential corrosion
risk)� Risk
Value=5 Cathodically
Protected: (yes/no)�yes�Risk
Value=1 Date
cathodic protection installed: five years after pipeline was constructed
(Cathodic protection installed within one year of the pipeline's construction
is generally considered low risk.)�Risk Value=3 Close
interval survey: (yes/no)�no�Risk
Value =5 Internal
Inspection tool used: (yes/no)�yes. Date of pig run? In last five
years�Risk Value=1 Anomalies
found: (yes/no)�yes,
but do not pose an immediate safety risk or environmental hazard�Risk Value=3 Leak
History: yes,
one spill in last 10 years. (refer to �Leak History� risk table)�Risk Value=2 Product
transported: Diesel
fuel. Product low risk. (refer to �Product� risk table)�Risk Value=1 Pipe
size: 16
inches. Size presents moderate risk (refer to �Line Size� risk table)�Risk
Value=3 iii.
Overall risk value for this hypothetical segment of pipe is 34. Assume we
have two other pipeline segments for which we conduct similar risk rankings.
The second pipeline segment has an overall risk value of 20, and the third
segment, 11. For the baseline assessment we would establish a schedule where
we assess the first segment (highest risk segment) within two years, the
second segment within five years and the third segment within seven years.
Similarly, for the continuing integrity assessment, we could establish an
assessment schedule where we assess the highest risk segment no later than
the second year, the second segment no later than the third year, and the
third segment no later than the fifth year. III. Safety
risk indicator tables for leak history, volume or line size, age of pipeline,
and product transported. Leak
History
1Time-dependent
defects are those that result in spills due to corrosion, gouges, or problems
developed during manufacture, construction or operation, etc. Line
size or Volume transported
Age
of Pipeline
1Depends on
pipeline's coating & corrosion condition, and steel quality, toughness,
welding. Product
Transported
1The degree of acute
and chronic toxicity to humans, wildlife, and aquatic life; reactivity; and,
volatility, flammability, and water solubility determine the Product
Indicator. Comprehensive Environmental Response, Compensation and Liability
Act Reportable Quantity values may be used as an indication of chronic
toxicity. National Fire Protection Association health factors may be used for
rating acute hazards. IV. Types
of internal inspection tools to use. An operator
should consider at least two types of internal inspection tools for the
integrity assessment from the following list. The type of tool or tools an
operator selects will depend on the results from previous internal inspection
runs, information analysis and risk factors specific to the pipeline segment: (1)
Geometry Internal inspection tools for detecting changes to ovality, e.g.,
bends, dents, buckles or wrinkles, due to construction flaws or soil
movement, or other outside force damage; (2) Metal
Loss Tools (Ultrasonic and Magnetic Flux Leakage) for determining pipe wall
anomalies, e.g., wall loss due to corrosion. (3) Crack
Detection Tools for detecting cracks and crack-like features, e.g., stress
corrosion cracking (SCC), fatigue cracks, narrow axial corrosion, toe cracks,
hook cracks, etc. V. Methods
to measure performance. A. General.
(1) This guidance is to help an operator establish measures to evaluate
the effectiveness of its integrity management program. The performance
measures required will depend on the details of each integrity management
program and will be based on an understanding and analysis of the failure
mechanisms or threats to integrity of each pipeline segment. (2) An
operator should select a set of measurements to judge how well its program is
performing. An operator's objectives for its program are to ensure public
safety, prevent or minimize leaks and spills and prevent property and
environmental damage. A typical integrity management program will be an
ongoing program and it may contain many elements. Therefore, several performance
measure are likely to be needed to measure the effectiveness of an ongoing
program. B. Performance
measures. These measures show how a program to control risk on pipeline
segments that could affect a high consequence area is progressing under the integrity
management requirements. Performance measures generally fall into three
categories: (1)
Selected Activity Measures�Measures that monitor the surveillance and
preventive activities the operator has implemented. These measure indicate
how well an operator is implementing the various elements of its integrity
management program. (2)
Deterioration Measures�Operation and maintenance trends that indicate when
the integrity of the system is weakening despite preventive measures. This
category of performance measure may indicate that the system condition is
deteriorating despite well executed preventive activities. (3) Failure
Measures�Leak History, incident response, product loss, etc. These measures
will indicate progress towards fewer spills and less damage. C. Internal
vs. External Comparisons. These comparisons show how a pipeline segment
that could affect a high consequence area is progressing in comparison to the
operator's other pipeline segments that are not covered by the integrity
management requirements and how that pipeline segment compares to other
operators' pipeline segments. (1)
Internal�Comparing data from the pipeline segment that could affect the high
consequence area with data from pipeline segments in other areas of the
system may indicate the effects from the attention given to the high
consequence area. (2)
External�Comparing data external to the pipeline segment (e.g., OPS incident
data) may provide measures on the frequency and size of leaks in relation to
other companies. D. Examples.
Some examples of performance measures an operator could use include� (1) A
performance measurement goal to reduce the total volume from unintended
releases by -% (percent to be determined by operator) with an ultimate goal
of zero. (2) A
performance measurement goal to reduce the total number of unintended
releases (based on a threshold of 5 gallons) by __-% (percent to be
determined by operator) with an ultimate goal of zero. (3) A
performance measurement goal to document the percentage of integrity management
activities completed during the calendar year. (4) A
performance measurement goal to track and evaluate the effectiveness of the
operator's community outreach activities. (5) A
narrative description of pipeline system integrity, including a summary of
performance improvements, both qualitative and quantitative, to an operator's
integrity management program prepared periodically. (6) A
performance measure based on internal audits of the operator's pipeline
system per 49 CFR Part 195. (7) A
performance measure based on external audits of the operator's pipeline
system per 49 CFR Part 195. (8) A
performance measure based on operational events (for example: relief
occurrences, unplanned valve closure, SCADA outages, etc.) that have the potential
to adversely affect pipeline integrity. (9) A
performance measure to demonstrate that the operator's integrity management
program reduces risk over time with a focus on high risk items. (10) A
performance measure to demonstrate that the operator's integrity management
program for pipeline stations and terminals reduces risk over time with a
focus on high risk items. VI.
Examples of types of records an operator must maintain. The rule
requires an operator to maintain certain records. (See �195.452(l)). This
section provides examples of some records that an operator would have to
maintain for inspection to comply with the requirement. This is not an
exhaustive list. (1) a
process for identifying which pipelines could affect a high consequence area
and a document identifying all pipeline segments that could affect a high
consequence area; (2) a plan
for baseline assessment of the line pipe that includes each required plan
element; (3)
modifications to the baseline plan and reasons for the modification; (4) use of
and support for an alternative practice; (5) a
framework addressing each required element of the integrity management
program, updates and changes to the initial framework and eventual program; (6) a
process for identifying a new high consequence area and incorporating it into
the baseline plan, particularly, a process for identifying population changes
around a pipeline segment; (7) an
explanation of methods selected to assess the integrity of line pipe; (8) a
process for review of integrity assessment results and data analysis by a
person qualified to evaluate the results and data; (9) the
process and risk factors for determining the baseline assessment interval; (10)
results of the baseline integrity assessment; (11) the
process used for continual evaluation, and risk factors used for determining
the frequency of evaluation; (12)
process for integrating and analyzing information about the integrity of a
pipeline, information and data used for the information analysis; (13)
results of the information analyses and periodic evaluations; (14) the
process and risk factors for establishing continual re-assessment intervals; (15)
justification to support any variance from the required re-assessment
intervals; (16)
integrity assessment results and anomalies found, process for evaluating and
remediating anomalies, criteria for remedial actions and actions taken to
evaluate and remediate the anomalies; (17) other
remedial actions planned or taken; (18)
schedule for evaluation and remediation of anomalies, justification to
support deviation from required remediation times; (19) risk
analysis used to identify additional preventive or mitigative measures,
records of preventive and mitigative actions planned or taken; (20)
criteria for determining EFRD installation; (21)
criteria for evaluating and modifying leak detection capability; (22)
methods used to measure the program's effectiveness. VII.
Conditions that may impair a pipeline's integrity. Section
195.452(h) requires an operator to evaluate and remediate all pipeline
integrity issues raised by the integrity assessment or information analysis.
An operator must develop a schedule that prioritizes conditions discovered on
the pipeline for evaluation and remediation. The following are some examples
of conditions that an operator should schedule for evaluation and
remediation. A. Any
change since the previous assessment. B.
Mechanical damage that is located on the top side of the pipe. C. An anomaly
abrupt in nature. D. An
anomaly longitudinal in orientation. E. An
anomaly over a large area. F. An
anomaly located in or near a casing, a crossing of another pipeline, or an
area with suspect cathodic protection. [Amdt.
195�70, 65 FR 75409, Dec. 1, 2000, as amended by Amdt. 195�74, 67 FR 1661,
Jan. 14, 2002]
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