# ENTERPRISE PRODUCTS OPERATING LLC — Notice of Probable Violation

- **operation:** document
- **citation:** CPF 420075015
- **title:** ENTERPRISE PRODUCTS OPERATING LLC — Notice of Probable Violation
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2007-05-07
- **effective on:** Not available
- **summary:** CLOSED notice of probable violation citing 195.406(b), 195.410(a)(1), 195.420(c), 195.432, 195.573, 195.579(a).
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- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-420075015.md
- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-420075015
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/420075015
**body:**

Notice of Probable Violation involving ENTERPRISE PRODUCTS OPERATING LLC. PHMSA's enforcement data identifies the cited regulations as 195.406(b),  195.410(a)(1),  195.420(c),  195.432,  195.573,  195.579(a). The case was opened on 2007-05-07 and is reported as closed as of 2011-07-13. Proposed civil penalty: $31,000. Assessed civil penalty: $31,000. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420075015_Closure Letter_07132011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_Closure%20Letter_07132011.pdf

420075015_Closure Letter_07132011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_Closure%20Letter_07132011_text.pdf

420075015_Final Order_12022009.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_Final%20Order_12022009.pdf

420075015_Final Order_12022009_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_Final%20Order_12022009_text.pdf

420075015_operator response to notice letter_06082007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_operator%20response%20to%20notice%20letter_06082007.pdf

420075015_operator response to notice letter_061107.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_operator%20response%20to%20notice%20letter_061107.pdf

420075015_Region Notice Letter_05072007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_Region%20Notice%20Letter_05072007.pdf

420075015_Closure Letter_07132011_text.pdf

CERTIFIED MAIL - RETURN RECEIPT REQUESTED
July 13, 2011
Mr. Terry Hurlburt
Senior Vice President of Operations
Enterprise Products Operating, LLC
1100 Louisiana Street
Houston, Texas 77002
CPF 4-2007-5015
Dear Mr. Hurlburt:
On December 2, 2009, the Pipeline and Hazardous Materials Safety Administration
(PHMSA) issued to Enterprise Products Operating, LLC a Final Order in the above-
referenced case. This Order included a Compliance Order and Civil Penalty
assessment. Based on our review of the documentation you provided and confirmation
of payment of the civil penalty, it has been determined that you have complied with the
terms of this Order.
Accordingly, this case is now closed and no further action is contemplated with respect
to the matters involved in this case. Thank you for your cooperation in this matter.
Sincerely,
R. M. Seeley
Director, Southwest Region
Pipeline and Hazardous
Materials Safety Administration

420075015_Region Notice Letter_05072007.pdf

of Transportation
U.S. Department
8701 S. Gessner, Suite 1110
Houston, TX 77074
Pipeline and
Hazardous Materials
Safety Administration
NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
PROPOSED COMPLIANCE ORDER
and
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
May 7, 2007
Mr. Terry Hurlburt
Enterprise Products Operating, LP
Vice-President, Eastern Operations
2727 North Loop West
Houston, TX 77008-1044
CPF 4-2007-5015
Dear Mr. Hurlburt:
During the months of February, April and May, 2005 a representative of the Pipeline and
nited States Code, conducted pipeline safety inspections of Enterprise Product
azardous Materials Safety Administration (PHMSA), pursuant to Chapter 601 of 4
Operating, LP (Enterprise) facilities and records pertaining to the Four Corners Area
Sighway ll Pip Are Syst West Systems, Skelytown Area Systems and the Cameron
As a result of the inspection, it appears that you have committed probable violations of
the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items
inspected and the probable violations are:
I. §195.406 Maximum operating pressure
(b) No operator may permit the pressure in a pipeline during surges or othe
ariations from normal operations to exceed 110 percent of the operating
ressure limit established under paragraph (a) of this section. Each operato
must provide adequate controls and protective equipment to control the
pressure within this limit.



Enterprise could not show evidence that surge pressures had been considered,on all of
their pipelines. Enterprise should be able to show that their pipelines are adequately
protected and that surge pressures have been eonsidered on all of their pipelines.
2. $195.410(a)(1) Line markers
(a) Except as provlded in paragraph (b) of this section, each operator shall
place and maintain line markers over each buried pipeline in accordance with
the following:
(1) Markers must be located at each public road crossing, at each railroad
crossing, and in sufficient number along the remainder of each buried line so
that its location is accurately known.
Enterprise does not have sufficient markers to adequately mark their pipelines. When
crossing cultivated agricultural fields, often the markers on the far side of the field could
not be seen. From valve sites, looking in both directions, the next marker for the pipeline
could not be seen. The lack of pipeline marking is a widespread problem with the
Enterprise pipelines that were inspected.
3. 5195.420 Valve maintenance
(c) Each operator shall provide protection for each valve from unauthorized
operation and from vandalism.
During the inspections it was noted that Enterprise uses a mixture of methods of
complying with 195.420c. The CHOPS Pipeline has installed locked chain link fencing
around the valves or locating the valves within secured facilities. The methods of
protection used in the six Enterprise units that were inspected, range from no fencing or
security, to pipe post and beam enclosures with locked valves, to cyclone fencing with
barbed wire around top, to enclosing the valves in welded steel plate, and covering the
entire valve with concrete.
A review of your procedures by our inspector did not reveal a plan or procedure to
consistently specify the method of security for valve sites that is acceptable to you.
Enterprise should review their program, procedures, and facilities to ensure they are
consistent and compliant with this regulation.
4. $195.432 Breakouttanks.
(a) Except for breakout tanks ins.pected under paragraphc (b) and (c) of this
section, each operator shall, at intervals not exceeding 15 month$, but at least
once each ca|endar year, inspect each in-service breakout talak.
(b) Each operator shall inspect the physical integrity of in-service atmospheric
and low-pressure steel aboveg,round breakout tanks according to sect,ion 4 of
API Standard S53. However, ff structural conditions prevent access to the tank
bottom, the bottom integrity may be assessed according to a plan includsd in
the operations and maintenance manual under g195.402(c)(3).
(c) Each operator shall inspect the physfcal integrity of in-service steel
abovxground breakout tanks built to API Standard 2510 accordi,ng to section 6
of API 510.
(d) The intervals of inspection specified by documents referenced in
paragraphs (b) and (c) of this section begin on May 3, '1999, or on the
operator's last recorded date of the inspection, whichever is earlier.



Enterprise had not set up an API-653 and/or API-S10 inspection program, as required by
5195.432, Enterprise could not demonstrate that breakout tanks have been inspected
per the regulation.
5- 5195.573 What must I do to monitor external corrosion control?
(a) Protected nipefines, You must do the following to determine whether
cathodic protection required by this subpart complies with Sec. 195.571:
1. CIonduct tests on the protected pipeline at least once each calendar year,
but with intervals not exceeding 15 months. However, if tests at those intervals
are lmpractical for separately protected short sections of hane or ino.ffectlvely
coated pipelines, testing may be done at least once every 3 calendar. years, but
with intervals not exceeding 39 months.
(d) Breakout tanks. You must inspect each cathodic protection system used to
control corroslon on the bottorn of an aboveground breakout tank to ensure
that operation and maintenance of the system are in accordance with API
Recomrnended Practice 651. However, this inspection is not reguired if you
note in the corrosion control procedu:re$ established under Sec. 19S"402(cX3)
why compliance with all or certain operation and maintenance previsions of
API Recomrnended Practice 651 is not necessary for the safety of the t*lk.
Enterprise is just beginning to implement surveys that consider lR drop. There is not
dedicated Cathodic Protection (CP) for tank bottoms, and the tank bottoms are not
surveyed during annual Cathodic Protection survey. The first interrupted survey (to
account for lR drop)was being conducted on the Four Corners Pipeline, during the 2005
DOT inspection.
6. 5195.579 What must I do to mitigate internal corrosion?
(a) General. lf you transport any hazardous liquid or carbon dioxide that would
corrode the pipeline, you must investigate the corrosive effect of the
hazardous liquid or carbon dioxide on the pipeline and take adequate steps to
mitigate internal corrosion.
Enterprise has not done investigations to determine whether lhere is internaN corrosion
or the potential for internal corrosion. Fnterprise has performed little monitoring, and has
not done inspections to investigate whether there could be internal conosion. The
investigation of internal corosion appears to be based upon internal coupo,ns, which are
improperly iocated on pipelines, and no otherevidence could be produced. No records
of internal inspection of removed pipe could be located.
Proposed Civil ?enaltv
Under 49 United States Code, E 60122, you arc subject to a civil penalty not to exceed
$100,000 for each violation for each day the violations persists up to a maximr.rm of
$1,000,000 for any related series of violations. The Compliance Officer has reviewed
the circumstances and supportlng documentation involved in the above probabie
violation(s) and has recommended that you be prelirninarily assessed a civil penalty of
$31,000 as follows:
ltem number
1
PENALTY -fu1,ooo



Warninq ltems
With respect to item #3, we have reviewed the circumstances and supporting documents
involved in this case and have decided not to conduct additional enforcement action or
penalty assessment proceedings at this time. We advise you to promptly correct this
item. Be advised that failure to do so may result in Enterprise being subject to additional
enforcement action.
Proposed Compliance Order
With respect to items 1
, 2, 4,5, and 6 pursuant to 49 United States Code $ 601 18, the
Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance
Order to Enterprise Products Operating, L.P. Please refer to the Proposed Compliance
Orderwhich is enclosed and made a part of this Notice.
Respp,nse to this Notice
Enclosed as parl of this Notice is a document entitled Response Options for Pipeline
Operators in Comptiartce Proceedings. Please refer to this document a,nd note the
response options. Be advised that all material you submit in response to this
enforcement action is subject to being made publicly available. [f you believe that any
portion of your responsive material qualifies for confidentia! treatment undor 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 quallfles for confidential
ireatment under 5 U.S.C. 552(b). lf 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 th'e Associate Administrator for Pipeline Safety to find facts as alleged in this
Notice without further notice to you and to issue a Final Order.
ln your correspondence on this rnatter, please refer to CPF 4.2007-50'15 and for each
document you submit, please provide a copy in eleetronic format whe,never possible.
Sincerely,
4@"M4
R. M. Seeley
Director, Southwest Region
Pipeline and Hazardous Materials Safety Administration
Enclosures: PraposedComplianceOrder
Response Opfions for Pipeline Operators in Compliance Proceedings



PffiOPOSED COMPLTANCE ORDER
Pursuant to 49 United States Code $ 60118, the Pipeline and Hazardous Materials
Safety Administration (PHMSA) proposes to issue to Enterprise Products Operating, L.P.
a Compliance Order incorporating the following remedial requirements to ensure the
compliance of Enterprise Products Operating, L.P with the pipeline safety regulations:
1. Perform an audit to ensure Enterprise is in compliance with 5195.406(b). This audit
shall consist of:
r Demonstrate that all of Enterprise's pipelines listed in this letter are protected
from overpressure from surges or other variations from normal operations and
that they are in compliance with applicable procedures.
r Based upon the review, develop a plan for installation of adequate controls and
protective equipment to protect the pipelines and control the pressure within this
limit.
2. Perform an audit to ensure Enterprise is in compliance $195.410(aX1). This audit
shall consist of:
I Survey of your pipeline markers throughout the Enterprise's pipeline system.
The survey is to evaluate the line markers currently posted along the right-of-way
as well as identify those areas where additional markers are needed. The survey
shall also ensure markers comply with applicable procedures.
r Based upon the review and s,urvey develop a ptan for replacemenV,installation of
the line markers to bring Enterprise into compliance.
3.
Perform an audit to ensure Enterprise is in compliance $195.432. This audit shall
consist of:
I Survey all break out tanks, on all of Enterprise's pipelines listed in this letter,
r Based upon review and survey, develop a plan for API 653 and API 510
inspection programs to bring Enterprise into compliance.
4 ,
Perform an audit to ensure Enterprise is in compliance $195.573(a). This audit shall
consist of:
r Survey all applicable segments of Enterprise's pipelines to insure that cathodic
protection testing meets applicable criteria, and that the pipelines are protected.
r Based upon the review and survey, develop a plan for conducting cathodic
protection surveys to bring Enterprise into compliance, and ensure that all
pipelines are protected by adequate cathodic protection.
Perform an audit to ensure Enterprise is in compliance $195.579(a). This audit shall
consist of:
r Survey all applicable facilities and segments of Enterprise's pipelines to ensure
that internaI corrosion inspection, testing and,monitoring meet applicable criteria,
and that the pipelines are protected from internal corrosion.
r Based upon the review and survey, develop a,plan for conducting internal



o .
7.
corrosion surveys to bring Enterprise into compliance.
a. Results of surveys and plans, with time tables, must be submitted within 30 days
following the receipt of the Final Order.
b. All items shall be completed within 365 days following the receipt of the Final
Order.
Enterprise shall maintain documentation of the safety improvement costs associated
with fulfilling this Compliance Order and submit the tolal to Rod Seeley, Director,
Southwest Region, Pipeline and Hazardous Materials Safety Administration. Costs
shall be reported in two categories: 1) total cost associated with preparation/revision
of plans, procedures, studies and analyses, and 2) total cost associated with
replacements, additions and other changes to pipeline infrastructure.

420075015_Final Order_12022009_text.pdf

DEC 02 2009
Mr. Terry Hurlburt
Senior Vice President of Operations
Enterprise Products Operating, LLC
1100 Louisiana Street
Houston, TX 77002
Re: CPF No. 4-2007-5015
Dear Mr. Hurlburt:
Enclosed is the Final Order issued in the above-referenced case. It makes findings of violation,
assesses a civil penalty of $31,000, and specifies actions to be taken to comply with the pipeline
safety regulations. The penalty payment terms are set forth in the Final Order. When the civil
penalty has been paid and the terms of the compliance order completed, as determined by the
Director, Southwest Region, this enforcement action will be closed. Your receipt of the Final
Order constitutes service of that document under 49 C.F.R. § 190.5.
Thank you for your cooperation in this matter.
Sincerely,
Jeffrey D. Wiese
Associate Administrator
for Pipeline Safety
Enclosure
cc: Mr. R. M. Seeley, Director, Southwest Region
VIA CERTIFIED MAIL – RETURN RECEIPT REQUESTED [7005 0390 0005 6162 5098]



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
____________________________________
In the Matter of )
Enterprise Products Operating, LLC, ) CPF No. 4-2007-5015
)
)
)
Respondent. )
____________________________________)
FINAL ORDER
On February 21–25, April 5–8, 18–22, and May 2–6, 16–20, 2005, pursuant to 49 U.S.C.
§ 60117, a representative of the Pipeline and Hazardous Materials Safety Administration’s
Office of Pipeline Safety (PHMSA) conducted an on-site pipeline safety inspection of the
hazardous liquid pipeline facilities operated by Enterprise Products Operating, LLC (Enterprise
or Respondent) in New Mexico, Texas, and Oklahoma. Enterprise operates over 20,000 miles of
hazardous liquid and natural gas pipeline facilities in those and other states, as well as offshore in
the Gulf of Mexico. The facilities and records of the following systems were inspected: Four
Corners, Hobbs East, Hobbs West, Skellytown, and the Cameron Highway Oil Pipeline.
As a result of the inspection, the Director, Southwest Region (Director), issued to Respondent,
by letter dated May 7, 2007, a Notice of Probable Violation, Proposed Civil Penalty, and
Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the Notice
proposed finding that Respondent had committed violations of 49 C.F.R. Part 195, proposed
assessing a civil penalty of $31,000 for the alleged violations, and proposed ordering Respondent
to take certain measures to correct them. In accordance with 49 C.F.R. § 190.205, the Notice
also proposed finding that Respondent had committed certain probable violations of 49 C.F.R.
Part 195 and warned Respondent to take appropriate corrective action to address them or be
subject to future enforcement action.
Respondent responded to the Notice by letter dated June 8, 2007 (Response). Respondent
contested the allegations and requested that the Notice be withdrawn. Respondent did not
request a hearing, and therefore has waived its right to one.
FINDINGS OF VIOLATION
The Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows:



2
Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.406, which states:
§ 195.406 Maximum operating pressure.
(a) Except for surge pressures and other variations from normal
operations, no operator may operate a pipeline at a pressure that exceeds
any of the following . . . .
(b) No operator may permit the pressure in a pipeline during surges or
other variations from normal operations to exceed 110 percent of the
operating pressure limit established under paragraph (a) of this section.
Each operator must provide adequate controls and protective equipment to
control the pressure within this limit.
The Notice alleged that Respondent violated § 195.406(b) by failing to provide adequate controls
and protective equipment to control pressure within 110 percent of the established maximum
operating pressure (MOP) during surges and other variations from normal operations.
Specifically, the Notice alleged that Enterprise had not considered the potential for surge
pressure on all of its pipelines, and therefore could not demonstrate its pipelines had adequate
protective equipment to control pressure within 110 percent of MOP during surges.
In its Response, Enterprise contended that § 195.406(b) does not require consideration of
pressure surges. Respondent also claimed that surges are not an issue for the inspected pipelines,
which have never had any incidents of overpressure caused by surges. Based on its operating
experience, Respondent contended that its controls and protective equipment were adequate.
Section 195.406 requires that operators establish a safe MOP for normal operations, and further
provides that in order to protect a pipeline during momentary pressure excursions caused by
surges, operators must have adequate controls and protective equipment to control pressure
during surges to within 110 percent of the established MOP. While I agree with Respondent that
the text of the regulation does not explicitly state an operator shall “consider” the potential for
surges, I disagree with the company’s contention that consideration of surges is not a
requirement of the regulation. In order for an operator to understand if its controls and protective
equipment are “adequate” to protect a pipeline from spikes in pressure caused by surges, it is
necessary for the operator to consider the potential for such surges and to understand and account
for their potential effects when designing appropriate controls and protective equipment. If an
operator has not at least considered the potential for surges on its pipeline, there cannot be an
informed judgment about the adequacy of the operator’s controls to prevent pressure from
exceeding 110 percent of MOP during surges.
The evidence shows that during the inspection of Respondent’s facilities, the PHMSA
representative requested documentation to verify that Enterprise’s controls and protective
equipment were adequate to control pressure. His request included records to show that
Respondent had analyzed the potential for surges on its pipelines. Respondent was able to
produce surge analyses for several but not all of the inspected pipelines. In its Response,
Respondent did not produce any additional surge analyses but contended that surge pressures
were simply not an issue for its pipelines.



3
Respondent’s claim that surge pressures are not an issue is unsubstantiated by the evidence in the
record. Furthermore, even if a particular pipeline has no known incident of overpressure in the
past, that does not guarantee the pipeline will never experience an overpressure caused by a
surge in the future. Simply noting that a pipeline has not experienced a surge in the past does not
demonstrate that controls and protective equipment are adequate to control pressure within 110
percent of MOP in the event a surge or other variation from normal operations were to occur.
After considering all the evidence, I find that Respondent violated 49 C.F.R. § 195.406(b) by
failing to provide controls and protective equipment demonstrated to be adequate to control
pressure within 110 percent of MOP during surges and other variations from normal operations.
Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.432, which states:
§ 195.432 Inspection of in-service breakout tanks.
(a) Except for breakout tanks inspected under paragraphs (b) and (c)
of this section, each operator shall, at intervals not exceeding 15 months,
but at least once each calendar year, inspect each in-service breakout tank.
(b) Each operator shall inspect the physical integrity of in-service
atmospheric and low-pressure steel aboveground breakout tanks according
to section 4 of API Standard 653. However, if structural conditions
prevent access to the tank bottom, the bottom integrity may be assessed
according to a plan included in the operations and maintenance manual
under § 195.402(c)(3).
(c) Each operator shall inspect the physical integrity of in-service steel
aboveground breakout tanks built to API Standard 2510 according to
section 6 of API 510.
(d) The intervals of inspection specified by documents referenced in
paragraphs (b) and (c) of this section begin on May 3, 1999, or on the
operator’s last recorded date of the inspection, whichever is earlier.
The Notice alleged that Respondent violated § 195.432(b) and (c) by failing to inspect the
physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks
according to section 4 of API Standard 653, and by failing to inspect steel aboveground breakout
tanks built to API Standard 2510 according to section 6 of API 510.1 The Notice further alleged
that Enterprise did not have a written inspection program for breakout tanks.2 The PHMSA
representative noted during the inspection that Enterprise employees were not aware of the need
to determine inspection intervals in accordance with API 653 and API 510 and that the company
had been performing annual inspections pursuant to an outdated requirement in § 195.432.3
1 American Petroleum Institute (API) Standard 653, “Tank Inspection, Repair, Alteration, and Reconstruction,” and
API Standard 510, “Pressure Vessel Inspection Code: Maintenance Inspection, Rating, Repair, and Alteration,” are
both incorporated by reference at 49 C.F.R. § 195.3.
2 See also 49 C.F.R. § 195.402(c)(3), “Procedural manual for operations, maintenance, and emergencies,” which
specifies that operators must prepare and follow written procedures for conducting operations and maintenance
activities in accordance with § 195.432, among other requirements.
3 PHMSA amended § 195.432 in 1999 by incorporating the API consensus standards in order to improve the level of
safety applicable to maintenance inspections of breakout tanks. Before the revision, § 195.432 only generally
required that all breakout tanks be inspected annually. See Pipeline Safety: Adoption of Consensus Standards for
Breakout Tanks, 64 Fed. Reg. 15,926 (Apr. 2, 1999).



4
In its Response, Enterprise contested the allegation of violation and contended that the subject
breakout tanks had been inspected in full compliance with both API 653 and API 510.
Respondent submitted records from two breakout tank examinations that occurred on April 20,
2004 (tank numbers VSP-2010 and VSP-2020). Respondent also submitted an inspection
schedule that demonstrated the next visual inspections for the two tanks, among others, were to
be performed in 2009 and the next ultrasonic inspections were to be performed in 2014.
Section 195.432(b) and (c) requires operators to perform maintenance inspections of breakout
tanks at periodic intervals established in accordance with API 653 and API 510. In particular,
API 653 provides that periodic inspection intervals for atmospheric and low-pressure breakout
tanks shall be determined on the basis of specific factors listed therein; further, API 510 provides
that inspection intervals for breakout tanks built to API 2510 shall be based on a calculated
corrosion rate. Section 195.402(c)(3) also requires that operators have written procedures for
performing inspections of breakout tanks in accordance with § 195.432, including the
establishment of inspection intervals.
While Respondent claimed in its Response that it had performed inspections consistent with all
of these requirements, the operator failed to submit evidence that demonstrated full compliance.
Neither the inspection records for the two tanks nor the inspection schedule show that Enterprise
had performed inspections at intervals determined in accordance with API 653 and API 510.
Furthermore, the evidence does not include any written procedures demonstrating that
Respondent had prepared (and followed) a program for conducting breakout tank inspections,
including the establishment of inspection intervals based on the consideration of the specific
factors listed in those standards.
Accordingly, after considering all the evidence, I find that Respondent violated 49 C.F.R.
§ 195.432(b) and (c) by failing to inspect the physical integrity of in-service atmospheric and
low-pressure steel aboveground breakout tanks according to section 4 of API Standard 653, and
steel aboveground breakout tanks built to API Standard 2510 according to section 6 of API 510.
Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.573, which states:
§ 195.573 What must I do to monitor external corrosion control?
(a) Protected pipelines. You must do the following to determine
whether cathodic protection required by this subpart complies with
§195.571:
(1) Conduct tests on the protected pipeline at least once each calendar
year, but with intervals not exceeding 15 months. However, if tests at
those intervals are impractical for separately protected short sections of
bare or ineffectively coated pipelines, testing may be done at least once
every 3 calendar years, but with intervals not exceeding 39 months . . . .
(d) Breakout tanks. You must inspect each cathodic protection system
used to control corrosion on the bottom of an aboveground breakout tank
to ensure that operation and maintenance of the system are in accordance
with API Recommended Practice 651. However, this inspection is not
required if you note in the corrosion control procedures established under



5
§195.402(c)(3) why compliance with all or certain operation and
maintenance provisions of API Recommended Practice 651 is not
necessary for the safety of the tank.
The Notice alleged that Respondent violated § 195.573(a) and (d) by failing to conduct tests on
protected pipelines to determine whether cathodic protection complied with § 195.571, and by
failing to inspect cathodic protection used to control corrosion on the bottom of aboveground
breakout tanks to ensure that it complied with API Recommended Practice (RP) 651.4
Specifically, the Notice alleged that Enterprise had not considered voltage (IR) drop when
surveying cathodic protection systems, did not have dedicated cathodic protection systems for
breakout tank bottoms, and failed to survey tank bottoms during annual cathodic protection
surveys. The Notice further alleged that Respondent’s first-ever interrupted survey (to account
for IR drop) was conducted during the 2005 PHMSA inspection.
During that inspection, the PHMSA representative noted that Enterprise’s survey methods did
not account for the revised safety standards established in 2002 by the promulgation of
§§ 195.571 and 195.573.
5 Until then, operators were required only to test cathodic protection
systems to determine whether the protection was “adequate.”6 Effective January 28, 2002,
§ 195.571 established paragraphs 6.2 and 6.3 of NACE Standard RP 0169 as the standard for
determining the adequacy of cathodic protection systems for pipelines.
further requires that operators conduct tests on protected pipelines to determine if cathodic
protection complies with those standards. Likewise, § 195.573(d) establishes API RP 651 as the
standard for determining the adequacy of cathodic protection systems for breakout tanks. Both
paragraphs 6.2.2.1.1 of NACE RP0169 and 8.2.2.1 of API RP 651 state that an operator may use
the -850 mV criterion for determining the adequacy of cathodic protection, but both standards
provide that “[v]oltage drops other than those across the structure [or tank bottom]-to-electrolyte
boundary must be considered for valid interpretation of this voltage measurement.”
7 Section 195.573(a)
Protected Pipelines
In its Response, Enterprise contested the allegations of violation and contended that the company
has always considered IR drop for its pipelines. Respondent explained that it considered IR drop
in a variety of ways, including: measurement of IR drop via interrupted annual or close-interval
cathodic protection surveys; use of “IR-free” coupon test stations; visual observation and
measurement of pipe-wall thickness when lines are exposed; use of internal inspection devices;
corrosion leak history analysis; at-grade versus in-the-ditch pipe-to-soil potential measurements
at pipeline excavation sites; and potential measurement techniques that consider proper reference
cell placement and pipeline location.
4 API Recommended Practice 651, “Cathodic Protection of Aboveground Petroleum Storage Tanks,” is incorporated
by reference at 49 C.F.R. § 195.3.
5 See Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines, 66 Fed. Reg. 66,994 (Dec. 27,
2001).
6 See 49 C.F.R. § 195.416 (2001).
7 NACE International (NACE) Standard RP0169, “Control of External Corrosion on Underground or Submerged
Metallic Piping Systems,” is incorporated by reference at 49 C.F.R. § 195.3.



6
With respect to the interrupted annual or close-interval surveys, Respondent stated that in 2003,
the company conducted 396 miles of “interrupted/IR-free” annual or close-interval cathodic
protection surveys across all of its pipeline systems. Respondent also indicated that in 2004, it
conducted 65 miles of interrupted close-interval cathodic protection surveys and developed a
plan to accomplish several goals within five years, such as: conducting 20 percent of its annual
cathodic protection surveys for all of its pipeline systems using interrupted/IR-free surveys;
performing all close-intervals in an interrupted/IR-free manner; and installing IR-free coupon
test stations. Respondent indicated that pursuant to this five-year plan, it had completed more
than 7,000 miles of interrupted/IR-free annual or close-interval surveys and installed 263 IR-free
coupon test stations throughout its pipeline system.
Enterprise further indicated that it had conducted 396 miles of surveys across all of its pipeline
systems in 2003, but did not indicate what portion of the 3,200 miles of pipelines subject to this
enforcement action were included in that total. Regardless, I note that Respondent did not claim
that it performed interrupted or close interval surveys on all 3,200 miles of its pipelines in 2003.
From 2004 through 2007, Respondent indicated it conducted 7,000 miles of interrupted or close-
interval surveys on all of its pipelines; but for 2004 the company has only accounted for 65 miles
of the pipelines subject to this enforcement action, and did not specifically account for any of the
subject pipelines for individual survey years 2005, 2006, or 2007.
With respect to the various other methods that Enterprise claimed to have used to consider IR
drop, the evidence in the record does not reflect the actual use of them all. Respondent’s annual
cathodic protection survey records do not show they were all used, nor did Respondent submit
any other documentation, such as reports or summaries, that document the use of all these
methods in a manner that would enable Respondent to determine whether its cathodic protection
systems complied with applicable standards. Without such supporting evidence, I am unable to
find the use of all of these various methods actually met the specifications of § 195.573.
Breakout tanks
The Notice further alleged that Respondent did not have dedicated cathodic protection systems
for breakout tank bottoms. In its Response, Enterprise contended that such allegation, even if
true, did not state a violation of any PHMSA regulation because neither the code nor industry
standards required dedicated cathodic protection for tank bottoms. Respondent explained that
the cathodic protection system protecting the breakout tank at Skellytown Station is a
deepwell/impressed-current system that also protects below-grade station piping.
After reviewing the relevant safety requirements, I do not find any apparent requirement in
§ 195.573(d) that an operator must have a dedicated cathodic protection system for its breakout
tank bottoms. Accordingly, I am withdrawing the allegation that Respondent’s failure to provide
a dedicated cathodic protection system for breakout tank bottoms constituted a violation of
§ 195.573(d).
In addition, the Notice alleged that Respondent failed to survey tank bottoms in accordance with
§ 195.432(d) during annual cathodic protection surveys. In its Response, Enterprise contended
that cathodic protection potentials were measured at the four compass bearing locations (North,
South, East and West) around the perimeter of the subject breakout tank and were recorded



7
during annual cathodic protection surveys of the station. Respondent submitted records of those
surveys.
The records show that Respondent inspected the cathodic protection system used to control
corrosion on the bottom of the breakout tank at Skellytown Station during calendar years 2003,
2004, and 2005; however, the records do not demonstrate that these cathodic protection surveys
considered IR drop for valid interpretation of the -850 mV criterion in accordance with
§ 195.432(d) and API RP 651.
Accordingly, after considering all the evidence, I find Respondent violated 49 C.F.R.
§ 195.573(a) and (d) by failing to conduct tests on protected pipelines to determine whether
cathodic protection complies with § 195.571, and by failing to inspect each cathodic protection
system used to control corrosion on the bottom of aboveground breakout tanks to ensure that the
systems comply with API RP 651.
Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.579, which states:
§ 195.579 What must I do to mitigate internal corrosion?
(a) General. If you transport any hazardous liquid or carbon dioxide
that would corrode the pipeline, you must investigate the corrosive effect
of the hazardous liquid or carbon dioxide on the pipeline and take
adequate steps 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 Notice alleged that Respondent violated § 195.579(a) and (c) by failing to investigate the
corrosive effect of the hazardous liquid transported by pipeline. Specifically, the Notice alleged
Respondent failed to sufficiently investigate and monitor for internal corrosion and to perform
inspections to determine whether internal corrosion could develop in its pipeline system. The
Notice further alleged that Respondent used coupons to check for internal corrosion but did not
properly locate the coupons so they would accurately detect the corrosion. It also alleged
Respondent did not inspect pipe that had been removed from service for evidence of internal
corrosion.
In its Response, Enterprise contended that it did investigate, detect, prevent, and mitigate internal
corrosion through its integrity management (IM) program and its operations and maintenance
(O&M) program. Through its IM program, Respondent stated it conducted inline inspections
(ILI) using a smart pig to identify various pipe-wall anomalies such as internal corrosion, and it
investigated anomalies that met remediation criteria. In addition, through its O&M program,
Respondent stated it used internal coupons throughout its pipeline system to yield data on
internal corrosion. The validity of the coupons data was demonstrated, according to Respondent,
by the fact that the data corresponded with results from the IM anomaly investigations. Finally,



8
Respondent indicated it inspected pipe removed from service for internal corrosion, as evidenced
by a sample report submitted for the record.
By regulation, Respondent is required to implement its IM program for each pipeline segment
that could affect a “high consequence area” (HCA).8
According to Respondent’s annual report,
less than one-fifth of Respondent’s hazardous liquid pipeline system could affect an HCA. Since
Respondent’s IM program is required to cover only a fraction of the pipelines, the use of ILI
pursuant to Respondent’s IM program would be inadequate to monitor for corrosive effects on
the entire system. In addition, inline inspections of mainline pipe are not representative of the
entire pipeline system because internal corrosion generall
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