# TESORO REFINING & MARKETING COMPANY, LLC — Notice of Amendment

- **operation:** document
- **citation:** CPF 520080006M
- **title:** TESORO REFINING & MARKETING COMPANY, LLC — Notice of Amendment
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2008-03-13
- **effective on:** Not available
- **summary:** CLOSED notice of amendment citing 192.903, 192.905(a), 192.905(b)(1), 192.917, 192.935(a), 192.935(b)(1), 192.937.
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- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/520080006M
**body:**

Notice of Amendment involving TESORO REFINING & MARKETING COMPANY, LLC. PHMSA's enforcement data identifies the cited regulations as 192.903,  192.905(a),  192.905(b)(1),  192.917,  192.935(a),  192.935(b)(1),  192.937. The case was opened on 2008-03-13 and is reported as closed as of 2009-02-10. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

520080006M_notice of amendment_03132008.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520080006M/520080006M_notice%20of%20amendment_03132008.pdf

520080006m_notice of amendment_03132008_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520080006M/520080006m_notice%20of%20amendment_03132008_text.pdf

520080006M_operator response_08212008.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520080006M/520080006M_operator%20response_08212008.pdf

520080006m_notice of amendment_03132008_text.pdf

SENT TO COMPLIANCE REGIS Y
Hardcopy +ctroTtiC y
ii of Copiers +I Date ~ I p ii
U. S. Department
of Transportation
Pipeline and
Hazardous Materials Safety
Administration
12300 W Dakota Ave, Suite 110
Lakewood, CO 80228
NOTICE OF AMENDMENT
CERTIFIED MAIL - RETURN RECEIPT RE UESTED
March 13, 2008
Mr. John W. Moore
V. P. Pipelines, Terminals, Trucking, and Rail (PTTR)
Tesoro Los Angeles Refinery
2101 E Pacific Coast Highway
Wilmington, CA, 90748
CPF 5-2008-0006M
Dear Mr. Moore:
On December 17 through December 20, 2007, a representative of the Pipeline and Hazardous
Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code
inspected your Integrity Management Program in Los Angeles, California.
On the basis of the inspection, PHMSA has identified the apparent inadequacies found within
Tesoro's plans and procedures, as described below:
HCA Identification
$192. 905 How does an operator identify a high consequence area?
(a) General. To determine which segments of an operator's transmission pipeline
system are covered by this subpart, an operator must identify the high consequence
areas. An operator must use method (1) or (2) from the definition in g 192. 903 to
identify a high consequence area. An operator may apply one method to its entire
pipeline system, or an operator may apply one method to individual portions of the
pipeline system. An operator must describe in its integrity management program
which method it is applying to each portion of the operator's pipeline system. The
description must include the potential impact radius when utilized to establish a



high consequence area. (See appendix E. I. for guidance on identifying high
consequence areas. )
(b)(1) Identified sites. An operator must identify an identified site, for purposes of
this subpart, from information the operator has obtained from routine operation
and maintenance activities and from public officials with safety or emergency
response or planning responsibilities who indicate to the operator that they know of
locations that meet the identified site criteria. These public officials could include
officials on a local emergency planning commission or relevant Native American
tribal officials.
(2) If a public official with safety or emergency response or planning
responsibilities informs an operator that it does not have the information to identify
an identified site, the operator must use one of the following sources, as
appropriate, to identify these sites.
(i) Visible marking (e. g. ,
a sign); or
(ii) The site is licensed or registered by a Federal, State, or local government
agency; or
(iii) The site is on a list (including a list on an internet web site) or map maintained
by or available from a Federal, State, or local government agency and available to
the general public.
(c) Newly identified areas. When an operator has information that the area
around a pipeline segment not previously identified as a high consequence area
could satisfy any of the definitions in f 192. 903, the operator must complete the
evaluation using method (1) or (2). If the segment is determined to meet the
definition as a high consequence area, it must be incorporated into the operator's
baseline assessment plan as a high consequence area within one year from the date
the area is identified.
$192. 905 How does an operator identify a high consequence area?
$192. 903 What definitions apply to this subpart?
High consequence area (HCA) means an area established by one of the methods
described in paragraphs (1) or (2) as follows:
(1) An area defined as-
(i) A Class 3 location under $192. 5; or
(ii) A Class 4 location under f192. 5; or
(iii) Any area in a Class 1 or Class 2 location where the potential impact radius is
greater than 660 feet (200 meters), and the area within a potential impact circle
contains 20 or more buildings intended for human occupancy; or
(iv) Any area in a Class 1 or Class 2 location where the potential impact circle
contains an identified site.



(2) The area within a potential impact circle containing-
(i) 20 or more buildings intended for human occupancy, unless the exception in
paragraph (4) applies; or
(ii) An identified site.
(3) Where a potential impact circle is calculated under either method (1) or (2) to
establish a high consequence area, the length of the high consequence area extends
axially along the length of the pipeline from the outermost edge of the first potential
impact circle that contains either an identified site or 20 or more buildings intended
for human occupancy to the outermost edge of the last contiguous potential impact
circle that contains either an identified site or 20 or more buildings intended for
human occupancy. (See Figure E. I. A. in Appendix E. )
(4) If in identifying a high consequence area under paragraph (1)(iii) of this
definition or paragraph (2)(i) of this definition, the radius of the potential impact
circle is greater than 660 feet (200 meters), the operator may identify a high
consequence area based on a prorated number of buildings intended for human
occupancy with a distance of 660 feet (200 meters) from the centerline of the
pipeline until December 17, 2006. If an operator chooses this approach, the
operator must prorate the number of buildings intended for human occupancy
based on the ratio of an area with a radius of 660 feet (200 meters) to the area of the
potential impact circle (i. e.
,
the prorated number of buildings intended for human
occupancy is equal to 20 x (660 feet) [or 200 meters]/potential impact radius in feet
[or meters]**2).
Identified site means each of the following areas:
(a) An outside area or open structure that is occupied by twenty (20) or more
persons on at least 50 days in any twelve (12)-month period. (The days need not be
consecutive. ) Examples include but are not limited to, beaches, playgrounds,
recreational facilities, camping grounds, outdoor theaters, stadiums, recreational
areas near a body of water, or areas outside a rural building such as a religious
facility; or
(b) A building that is occupied by twenty (20) or more persons on at least five (5)
days a week for ten (10) weeks in any twelve (12)- month period. (The days and
weeks need not be consecutive. ) Examples include, but are not limited to, religious
facilities, office buildings, community centers, general stores, 4-H facilities, or roller
skating rinks; or
(c) A facility occupied by persons who are confined, are of impaired mobility, or
would be difficult to evacuate. Examples include but are not limited to hospitals,
prisons, schools, day-care facilities, retirement facilities or assisted-living facilities.
Potential impact circle is a circle of radius equal to the potential impact radius
(PIR).



Potential impact radius (PIR) means the radius of a circle within which the
potential failure of a pipeline could have significant impact on people or property.
PIR is determined by the formula r = 0. 69* (square root of (p*d Q)), where 'r' is
the radius of a circular area in feet surrounding the point of failure, 'p' is the
maximum allowable operating pressure (MAOP) in the pipeline segment in pounds
per square inch and 'd' is the nominal diameter of the pipeline in inches.
~ Item 1A: $192. 905(a)
Tesoro's High Consequence Area (HCA) identification process does not document the
method used to identify HCAs.
~ Item 1B: $192. 903
The calculations performed by Tesoro's consultant, SECOR, to determine the potential
impact radius (PIR) appear to use a value for the pipe diameter of 10. 52 inches, while
the Tesoro IMP states that the pipe outside diameter is 10. 75 inches. This results in a
lower PIR.
~ Item 1C: $192. 905(b)(1)
The Tesoro HCA identification results do not indicate whether high consequence areas
that were identified include the area extending axially along the length of the pipeline
from the outermost edge of the first potential impact circle to the outermost edge of the
last contiguous potential impact circle.
~ Item 1D: $192. 905(a) and $192. 905(b)(1)A(2)
The Tesoro HCA identification does not include a systematic identification of potential
identified sites in the vicinity of the pipeline. The HCA identification did not include
consideration of the "Coke Barn" facility as an identified site, even though the site
occupancy may meet the criteria for an identified site.
Risk Assessment
$192. 917 How does an operator identify potential threats to pipeline integrity and
use the threat identification in its integrity program?
(a) Threat identification. An operator must identify and evaluate all potential
threats to each covered pipeline segment. Potential threats that an operator must
consider include, but are not limited to, the threats listed in ASME/ANSI B31. 8S
(ibr, see $192. 7), section 2, which are as follows:
(1) Time dependent threats such as internal corrosion, external corrosion, and
stress corrosion cracking;
(2) Static or resident threats, such as fabrication or construction defects;



(3) Time independent threats such as third party damage and outside force
damage; and
(4) Human error.
(b) Data gathering and integration. To identify and evaluate the potential threats
to a covered pipeline segment, an operator must gather and integrate existing data
and information on the entire pipeline that could be relevant to the covered
segment. In performing this data gathering and integration, an operator must
follow the requirements in ASME/ANSI B31. SS, section 4. At a minimum, an
operator must gather and evaluate the set of data specified in Appendix A to
ASME/ANSI B31. SS, and consider both on the covered segment and similar non-
covered segments, past incident history, corrosion control records, continuing
surveillance records, patrolling records, maintenance history, internal inspection
records and all other conditions specific to each pipeline.
(c) Risk assessment. An operator must conduct a risk assessment that follows
ASME/ANSI B31. SS, section 5, and considers the identified threats for each
covered segment. An operator must use the risk assessment to prioritize the
covered segments for the baseline and continual reassessments ($/192. 919, 192. 921,
192. 937), and to determine what additional preventive and mitigative measures are
needed ($192. 935) for the covered segment.
The Tesoro IMP does not document the risk assessment process that will be used in
future risk assessments. A risk assessment is needed to set priorities for integrity
assessments and it is required to support evaluation of preventive and mitigative
measures. Current documentation is from a Shell risk assessment process was last
implemented in 2004. Potential errors were found in the risk scorecard evaluation that
was part of the risk assessment at that time. IMP Section 3 does not indicate what risk
assessment process will be conducted in the future.
3. Reassessment Intervals
$192. 937 What is a continual process of evaluation and assessment to maintain a
pipeline's integrity?
(a) General. After completing the baseline integrity assessment of a covered
segment, an operator must continue to assess the line pipe of that segment at the
intervals specified in g 192. 939 and periodically evaluate the integrity of each
covered pipeline segment as provided in paragraph (b) of this section. An operator
must reassess a covered segment on which a prior assessment is credited as a
baseline under g 192. 921(e) by no later than December 17, 2009. An operator must
reassess a covered segment on which a baseline assessment is conducted during the
baseline period specified in g 192, 921(d) by no later than seven years after the
baseline assessment of that covered segment unless the evaluation under paragraph
(b) of this section indicates earlier reassessment.



(b) Evaluation. An operator must conduct a periodic evaluation as frequently as
needed to assure the integrity of each covered segment. The periodic evaluation
must be based on a data integration and risk assessment of the entire pipeline as
specified in g 192. 917. For plastic transmission pipelines, the periodic evaluation is
based on the threat analysis specified in g 192. 917(d) For all other transmission
pipelines, the evaluation must consider the past and present integrity assessment
results, data integration and risk assessment information (g 192. 917), and decisions
about remediation (g 192. 933) and additional preventive and mitigative actions (g
192. 935). An operator must use the results from this evaluation to identify the
threats specific to each covered segment and the risk represented by these threats.
The assumed corrosion growth rate used to obtain the seven year reassessment interval is
not conservative. The corrosion growth analysis assumes a corrosion half life of 39
years. This is not consistent with NACE defaults and predicts slower corrosion growth
than would be obtained using these default figures. Tesoro does not offer a basis for
making these more optimistic assumptions.
Preventive and Mitigative Measures
$192, 911 What are the elements of an integrity management program?
(h) Provisions meeting the requirements of $192. 935 for adding preventive and
mitigative measures to protect the high consequence area.
$192. 935
(a) General requirements. An operator must take additional measures beyond
those already required by Part 192 to prevent a pipeline failure and to mitigate the
consequences of a pipeline failure in a high consequence area. An operator must
base the additional measures on the threats the operator has identified to each
pipeline segment. (See $192. 917) An operator must conduct, in accordance with
one of the risk assessment approaches in ASME/ANSI B31. 8S (ibr, see $192. 7),
section 5, a risk analysis of its pipeline to identify additional measures to protect the
high consequence area and enhance public safety. Such additional measures
include, but are not limited to, installing Automatic Shut-off Valves or Remote
Control Valves, installing computerized monitoring and leak detection systems,
replacing pipe segments with pipe of heavier wall thickness, providing additional
training to personnel on response procedures, conducting drills with local
emergency responders and implementing additional inspection and maintenance
programs.



(b) Third party damage and outside force damage—
(1) Third party damage. An operator must enhance its damage prevention
program, as required under $192. 614 of this part, with respect to a covered
segment to prevent and minimize the consequences of a release due to third party
damage. Enhanced measures to an existing damage prevention program include, at
a minimum—
(i) Using qualified personnel (see g 192. 915) for work an operator is conducting
that could adversely affect the integrity of a covered segment, such as marking,
locating, and direct supervision of known excavation work.
(ii) Collecting in a central database information that is location specific on
excavation damage that occurs in covered and non covered segments in the
transmission system and the root cause analysis to support identification of
targeted additional preventative and mitigative measures in the high consequence
areas. This information must include recognized damage that is not required to be
reported as an incident under part 191.
(iii) Participating in one-call systems in locations where covered segments are
present.
(iv) Monitoring of excavations conducted on covered pipeline segments by pipeline
personnel. If an operator finds physical evidence of encroachment involving
excavation that the operator did not monitor near a covered segment, an operator
must either excavate the area near the encroachment or conduct an above ground
survey using methods defined in NACE RP-0502-2002 (incorporated by reference,
see $192. 7). An operator must excavate, and remediate, in accordance with
ANSI/ASME B31. SS and $192. 933 any indication of coating holidays or
discontinuity warranting direct examination.
(2) Outside force damage. If an operator determines that outside force (e. g. ,
earth
movement, floods, unstable suspension bridge) is a threat to the integrity of a
covered segment, the operator must take measures to minimize the consequences to
the covered segment from outside force damage. These measures include, but are
not limited to, increasing the frequency of aerial, foot or other methods of patrols,
adding external protection, reducing external stress, and relocating the line.
(c) Automatic shut-off valves (ASV) or Remote control valves (RCV). If an
operator determines, based on a risk analysis, that an ASV or RCV would be an
efficient means of adding protection to a high consequence area in the event of a gas
release, an operator must install the ASV or RCV. In making that determination,
an operator must, at least, consider the following factors — swiftness of leak
detection and pipe shutdown capabilities, the type of gas being transported,
operating pressure, the rate of potential release, pipeline profile, the potential for
ignition, and location of nearest response personnel.



(d) Pipelines operating below 30'/o SMYS. An operator of a transmission pipeline
operating below 30 lo SMYS located in a high consequence area must follow the
requirements in paragraphs (d)(l) and (d)(2) of this section. An operator of a
transmission pipeline operating below 30'/o SMYS located in a Class 3 or Class 4
area but not in a high consequence area must follow the requirements in
paragraphs (d)(1), (d)(2) and (d)(3) of this section
(1) Apply the requirements in paragraphs (b)(1)(i) and (b)(1)(iii) of this section to
the pipeline; and
(2) Either monitor excavations near the pipeline, or conduct patrols as required by
g 192. 705 of the pipeline at bi-monthly intervals. If an operator finds any indication
of unreported construction activity, the operator must conduct a follow up
investigation to determine if mechanical damage has occurred.
(3) Perform semi-annual leak surveys (quarterly for unprotected pipelines or
cathodically protected pipe where electrical surveys are impractical).
(e) Plastic transmission pipeline. An operator of a plastic transmission pipeline
must apply the requirements in paragraphs (b)(1)(i), (b)(1)(iii) and (b)(1)(iv) of this
section to the covered segments of the pipeline.
~ Item 4A: $192. 935(a)
The Tesoro IMP process for evaluation of preventive and mitigative measure is not
defined adequately A risk assessment was conducted in 2004, but this was performed
using Shell pipeline approach that is not the approach that is intended to be used in the
future.
~ Item 4B: $192. 935(b)(1)
The Tesoro IMP does not require the preventive and mitigative evaluation to consider
the alternatives specified in 192. 935(a). It is not clear what alternatives were considered
in the risk assessment completed in 2004.
~ Item 4C: $192. 935(a)
The Tesoro IMP does not document a systematic decision-making process to decide
which measures are to be implemented, considering both the likelihood and
consequences for pipeline failures.
Res onse to this Notice
This Notice is provided pursuant to 49 U, S. C. $ 60108(a) and 49 C. F. R. g 190. 237. Enclosed as
part of this Notice is a document entitled Response Options for Pipeline Operators in
Compliance ProceeCkngs. Please refer to this document and note the response options. Be
advised that all material you submit in response to this enforcement action is subject to being
made publicly available. If you believe that any portion of your responsive material qualifies
for confidential treatment under 5 U. S. C. 552(b), along with the complete original document



you must provide a second copy of the document with the portions you believe qualify for
confidential treatment redacted and an explanation of why you believe the redacted information
qualifies for confidential treatment under 5 U. S. C. 552(b). If you do not respond within 30 days
of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this
Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in
this Notice without further notice to you and to issue a Final Order.
If, after opportunity for a hearing, your plans or procedures are found inadequate as alleged in
this Notice, you may be ordered to amend your plans or procedures to correct the inadequacies
(49 C. F. R. $ 190. 237). If you are not contesting this Notice, we propose that you submit your
amended procedures to my office within 30 days of receipt of this Notice. This period may be
extended by written request for good cause. Once the inadequacies identified herein have been
addressed in your amended procedures, this enforcement action will be closed.
In correspondence concerning this matter, please refer to CPF 5-2008-0006M and, for each
document you submit, please provide a copy in electronic format whenever possible.
Sincerely~
's Hoidal
Director, Western Region
Pipehne and Hazardous Materials Safety Administration
cc: PHP-60 Compliance Registry
PHP-500 J. Gilliam (¹120054)
Bernadette Frieh, PTTR Environmental Compliance Manager
Enclosure: Response Options for Pipehne Operators in Comphance Proceedings
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