# CHEVRON PRODUCTS COMPANY — Warning Letter

- **operation:** document
- **citation:** CPF 520195003W
- **title:** CHEVRON PRODUCTS COMPANY — Warning Letter
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2019-01-21
- **effective on:** Not available
- **summary:** CLOSED warning letter citing 194.121(a), 194.121(b), 195.264(b)(1)(i), 195.432(b), 195.434, 195.577(a), 195.579(c), 195.581, 195.583(a).
- **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-enforcement-520195003w.json
- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-520195003w.md
- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-520195003w
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/520195003W
**body:**

Warning Letter involving CHEVRON PRODUCTS COMPANY. PHMSA's enforcement data identifies the cited regulations as 194.121(a),  194.121(b),  195.264(b)(1)(i),  195.432(b),  195.434,  195.577(a),  195.579(c),  195.581,  195.583(a). The case was opened on 2019-01-21 and is reported as closed as of 2019-01-21. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

520195003W_Warning Letter_01212019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520195003W/520195003W_Warning%20Letter_01212019.pdf

520195003W_Warning Letter_01212019_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520195003W/520195003W_Warning%20Letter_01212019_text.pdf

520195003W_Warning Letter_01212019_text.pdf

WARNING LETTER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
January 21, 2019
Mr. John S. Watson
Chairman and Chief Executive Officer
Chevron Products Company
6001 Bollinger Canyon Road
San Ramon, CA 94583
CPF 5-2019-5003W
Dear Mr. Watson:
From July 25 through 29, 2016, representatives of the Pipeline and Hazardous Materials Safety
Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49
United States Code (U.S.C.), inspected your Willbridge Facilities in Portland, Oregon. As part
of that inspection we reviewed your operation and maintenance procedures, and supporting
implementation records and documentation. I sincerely apologize for our late transmittal of these
findings to Chevron, but still hope that by detailing our observations and regulatory findings that
you can further improve public safety.
Based on our inspection findings, PHMSA determined you may have committed probable
violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations (CFR). The
deficiencies noted and probable violations were:
1. § 194.121 Response plan review and update procedures.
(a) Each operator shall update its response plan to address new or different
operating conditions or information. In addition, each operator shall review its
response plan in full at least every 5 years from the date of the last submission or the
last approval as follows…
(b) If a new or different operating condition or information would substantially
affect the implementation of a response plan, the operator must immediately modify



its response plan to address such a change and, within 30 days of making such a
change, submit the change to PHMSA. Examples of changes in operating conditions
that would cause a significant change to an operator's response plan are:…
The operator did not update its response plan to address new or different operating conditions or
information. The most recent version of the operator’s facility response plan was submitted to
PHMSA in February 2016 and, prior to that submission, in 2014, 2010, 2008, and 2004
(Submissions). Each of those Submissions, or the letters received by the operator in response to
the Submissions, generally describes new or different operating conditions or information
reflected or to be included in the updated response plans. However, the operator produced no
records that demonstrate that the operator reviewed (and updated where necessary) its response
plan to address the new or different operating conditions or information described in the
Submissions.
The operator provided p. 43 of the table of contents of the facility response plan entitled “Record
of Changes.” The Record of Changes simply details two changes made on August 2, 2016 and
fails to fill out any of the columns entitled “Section/Amended/Page Number,” “Department
Notified Yes/No,” and “Initials of Person Making Changes.” Furthermore, the Record of
Changes did not capture the historic changes reflected in the response plan Submissions to
PHMSA or the resulting correspondence. The current Record of Changes document is not
sufficient to show that the operator reviewed and updated the facility response plan as required in
§ 194.121(a).
2. § 195.264 Impoundment, protection against entry, normal/emergency venting or
pressure/vacuum relief for aboveground breakout tanks.
...
(b) After October 2, 2000, compliance with paragraph (a) of this section requires the
following for the aboveground breakout tanks specified:
(1) For tanks built to API Spec 12F, API Std 620, and others (such as API Std 650
(or its predecessor Standard 12C)), the installation of impoundment must be in
accordance with the following sections of NFPA-30 (incorporated by reference, see
§ 195.3);
(i) Impoundment around a breakout tank must be installed in accordance with
section 22.11.2; and...
Regarding its 2009 Chevron Willbridge Terminal Expansion Project, the operator did not
demonstrate that the impoundment areas were installed according to § 195.264 or NFPA-30
Section 22.11.2.1. The operator provided the August 5, 2016 “Chevron Willbridge Terminal
NFPA-30 Impoundment Evaluation” (Evaluation) to demonstrate compliance with NFPA-30
Section 22.11.2 for its 2009 Chevron Willbridge Terminal Expansion Project, which installed
two large gasoline/diesel storage tanks and corresponding impoundments. However, several
deficiencies exist as to demonstrating compliance using this sole document. Compliance with
NFPA-30 Section 22.11.2.1 requires “[a] slope of not less than 1 percent away from the tank
2



shall be provided for at least 50 ft (15 m) or to the dike base, whichever is less.” The operator
stated in the Evaluation that the slope was “[c]onfirmed visually and through observations that
rainwater freely drains away from tanks.” Visual confirmation for a quantifiable requirement is
not sufficient to satisfy either § 195.264 or NFPA-30 Section 22.11.2.1. Chevron should have
used a quantifiable measure of the slope to demonstrate compliance.
3. § 195.432 Inspection of in-service breakout tanks.
...
(b) Each operator must inspect the physical integrity of in-service atmospheric and
low-pressure steel above-ground breakout tanks according to API Std 653 (except
section 6.4.3, Alternative Internal Inspection Interval) (incorporated by reference,
see § 195.3). However, if structural conditions prevent access to the tank bottom, its
integrity may be assessed according to a plan included in the operations and
maintenance manual under § 195.402(c)(3). The risk-based internal inspection
procedures in API Std 653, section 6.4.3 cannot be used to determine the internal
inspection interval.
The operator did not inspect the physical integrity of in-service atmospheric and low-pressure
steel above-ground breakout tanks according to API Standard 653, as required by § 195.432.
API Standard 653 (Third Edition, December 2001) requires that “[a]ll tanks shall be given a
visual external inspection by an authorized inspector” in Section 6.3.2.1. PHMSA inspectors in
the field observed the following on Tank 47: a petroleum sheen high on the side of the riveted
tank, a gouge a few feet above the ground on the side of the tank, and a coating failure hole that
appeared to contain corrosion pits. None of these deficiencies were noted in the May 21, 2013
Tank #47 API 653 External Inspection Report. These observed deficiencies are inconsistent with
adequate regular inspection and maintenance of the facilities.
4. § 195.434 Signs.
Each operator must maintain signs visible to the public around each pumping
station and breakout tank area. Each sign must contain the name of the operator
and a telephone number (including area code) where the operator can be reached at
all times.
The operator did not maintain signs visible to the public around each pumping station and
breakout tank area that included name of the operator and a telephone number where the operator
can be reached at all times. Inspectors observed inadequate signage on both the terminal area
and the impoundment area of the Willbridge Facilities. On the terminal side of the street (the
gated side), inspectors observed only one sign sufficient to meet requirements on hundreds of
feet of available space of fencing, which included several entrances and exits from the facilities.
On the tank farm/impoundment wall side of the street, only one sign was observed containing
emergency information and that sign did not contain the name of the operator. On that same
side, hundreds of feet of unmarked impoundment walls, including numerous vehicle and
3



personnel access points, were lacking proper signage. The main “Chevron” sign on the tank
farm side of the property was buried in shrubs and was not visible to the general public. Signage
at the operator’s Chevron Willbridge Facilities did not fully comply with the visibility
requirements of § 195.434.
5. § 195.577 What must I do to alleviate interference currents?
(a) For pipelines exposed to stray currents, you must have a program to identify,
test for, and minimize the detrimental effects of such currents.
The operator did not demonstrate that the Chevron Willbridge Facilities were tested and
determined not to be exposed to stray currents nor did they produce documentation of an
interference current program. The “Chevron Distribution Terminals O&M Manual,” Procedure
602.3 Interference Currents, does not meet § 195.577(a) because no testing for interference
currents is required by the procedure. The operator stated that no interference current testing has
ever been performed in the Willbridge Facilities despite the presence of numerous potential
sources of interference current such as other pipelines and terminals in the area, as well as
adjacent tank farms. The operator’s personnel stated that they understood that identification,
testing, and minimizing the effects of stray currents, in accordance with § 195.577, applies to the
breakout tanks and other facilities at the Willbridge Facilities. The operator made no effort to
determine whether stray currents existed at the facilities and concluded, with no data or analysis,
that no stray current existed. Without testing for stray current, the operator’s assumption that no
stray current exists is unfounded and violates § 195.577(a).
6. § 195.579 What must I do to mitigate internal corrosion?
...
(c) Removing pipe. Whenever you remove pipe from a pipeline, you must inspect the
internal surface of the pipe for evidence of corrosion. If you find internal corrosion
requiring corrective action under § 195.585, you must investigate circumferentially
and longitudinally beyond the removed pipe (by visual examination, indirect
method, or both) to determine whether additional corrosion requiring remedial
action exists in the vicinity of the removed pipe.
The operator did not inspect the internal surface of the pipe whenever pipe was removed from a
pipeline at the Willbridge Facilities. The operator verified that removed pipe was never
inspected for internal corrosion as required for compliance with § 195.579(c). Further, there are
no records documenting internal corrosion inspections on removed pipe sections.
7. § 195.581 Which pipelines must I protect against atmospheric corrosion and what
coating material may I use?
(a) You must clean and coat each pipeline or portion of pipeline that is exposed to
the atmosphere, except pipelines under paragraph (c) of this section.
4



(b) Coating material must be suitable for the prevention of atmospheric corrosion.
(c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, you
need not protect against atmospheric corrosion any pipeline for which you
demonstrate by test, investigation, or experience appropriate to the environment of
the pipeline that corrosion will:
(1) Only be a light surface oxide; or
(2) Not affect the safe operation of the pipeline before the next scheduled inspection.
Chevron Products Company (Chevron) did not protect its pipelines at the Willbridge facilities
from atmospheric corrosion as required by 49 C.F.R. § 195.581(a). Specifically, Chevron did
not clean and coat each pipeline or portion of pipeline that is exposed to the atmosphere, or by
demonstrating by test, investigation, or experience appropriate to the environment of the
pipelines, that corrosion will only be a light surface oxide, or that the corrosion will not affect the
safe operation of the pipeline before the next scheduled inspection. Visual observation of
Chevron’s Willbridge facilities by PHMSA inspectors showed numerous areas of regulated
pipeline, pipeline P-110 in particular, without coating and with severe atmospheric corrosion.
Visual evidence revealed that the current conditions are inconsistent with a light surface oxide,
as the corrosion appears severe and to have existed for several years.
Chevron asserts that even if the corroded infrastructure is not simply a light surface oxide, the
corrosion does not affect the safe operation of pipeline P-110. In response to PHMSA
inspectors’ questions about observable pipeline corrosion, Chevron submitted a document
entitled “§ 195.581(c) Discussion” (Discussion). The Discussion addresses two Chevron-
selected locations on a single pipe, P-110, comparing Ultrasonic (UT) inspections from 2005 and
2011 to demonstrate compliance with § 195.581(c)(2). (Pictures of P-110 and schematics of the
ultrasound location are attached as exhibits to the Violation Report.) The Discussion shows little
to no metal loss in the two locations addressed, and the wall thickness is shown to have slightly
increased in certain o’clock positions at the locations on the two Chevron-selected points on
pipeline P-110.
In response to PHMSA inspectors’ questions, Chevron provided a report after the inspection
from its own expert, Mr. Phil Meyers, entitiled the January 18, 2011 “Willbridge Cathodic
Protection Justification.” In that report, Mr. Meyers opined that a volume expansion occurs
during the corrosion process which may show a false increase in wall thickness. Further,
Chevron stated that the data from pipe P-110, as listed in the Discussion, illustrates the worst
case scenario of pipeline corrosion on P-110. The “worst case scenario” refers to the most
progressed corrosion on the pipe. The data from points P01-01 and P01-02 on P-110, the two
Chevron-selected locations addressed in the Discussion, produced average corrosion rates of 1.2
mils/year and 0.2 mils/year, respectively. However, the PHMSA inspectors observed significant
pitting at area P01-02, in contrast to the UT data and photographs supplied by the operator. The
PHMSA inspectors also question the area P02-01, a third point listed in the Discussion on the
same pipe, which showed significant (30+%) metal loss and consistent (4 out of 4 measurements
in excess of 0.1 inches) metal loss for the 2005 - 2011 time period. The average corrosion rate at
P02-01 was 17 mils/year, one and two orders of magnitude over the “worst case scenario” points
5



chosen by Chevron. Accordingly, Chevron incorrectly identified its worst case scenario of
pipeline corrosion on P-110. The rate of corrosion is shown to be greatly increased in a third
area of the P-110 pipeline simply by looking at the UT data Chevron provided in the Discussion.
Even by UT testing, Chevron fails to demonstrate that the corrosion will not affect the safe
operation of the pipeline before the next scheduled inspection, particularly if 30+% corrosion
loss over 6 years is seen on parts of the P-110 pipeline.
The documents provided by Chevron did not demonstrate by test, investigation, or experience
appropriate to the operating environment of the pipeline, that corrosion will only be light surface
oxide, or that the corrosion will not affect the safe operation of the pipeline before the next
scheduled inspection.
8. § 195.583 What must I do to monitor atmospheric corrosion control?
(a) You must inspect each pipeline or portion of pipeline that is exposed to the
atmosphere for evidence of atmospheric corrosion, as follows:
If the pipeline is located onshore then the frequency of inspection is: At least once
every 3 calendar years, but with intervals not exceeding 39 months.
For all pipelines at the Willbridge Terminal, the operator did not produce records demonstrating
compliance with 49 C.F.R. § 195.583(a). The pipelines at the Willbridge Terminal are onshore
pipelines and are exposed to the atmosphere. Accordingly, Chevron is required to inspect each
pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric
corrosion at least once every 3 calendar years, but with intervals not exceeding 39 months.
Chevron stated that weekly checks, monthly checks, and 5-year API 570 inspections, in
combination, satisfy § 195.583(a). Chevron provided May - July 2016 records of weekly and
monthly checks of the pipelines at the Willbridge Terminal, which showed no mention of any
atmospheric corrosion as opposed to what the PHMSA inspectors saw in the field. More detailed
API 570 inspections were disclosed which note some atmospheric corrosion issues, however,
these inspections are performed on a 5-year interval.
Additionally, Chevron’s internally developed weekly and monthly checklists were not completed
by qualified atmospheric corrosion inspectors. Also, the weekly and monthly checks were not
focused on atmospheric corrosion but instead, the foci were the “Willbridge Terminal Routine
Duties” and the “Willbridge Terminal Monthly In-Service Tank Inspection,” respectively. The
operator’s current practices of a combination of weekly and monthly checks and 5-year
inspections are insufficient to comply with the requirements of § 195.583(a).
As of April 27, 2017, under 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil
penalty not to exceed $209,002 per violation per day the violation persists up to a maximum of
$2,090,022 for a related series of violations. We have reviewed the circumstances and
supporting documents involved in this case, including the extensive time to transmit our
findings, and have decided not to conduct additional enforcement action or penalty assessment
6



proceedings at this time. We advise you to correct the item(s) identified in this letter. Failure to
do so will result in Chevron being subject to additional enforcement action.
No reply to this letter is required. If you choose to reply, in your correspondence please refer to
CPF 5-2019-5003W. 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).
Sincerely,
Chris Hoidal
Acting Director, Western Region
Pipeline and Hazardous Materials Safety Administration
Cc: PHP-60 Compliance Registry
PHP-500 J. Owens (#152513)
7
- **truncated:** false
- **body characters:** 18970