# ENTERPRISE PRODUCTS OPERATING LLC — Warning Letter

- **operation:** document
- **citation:** CPF 220125008W
- **title:** ENTERPRISE PRODUCTS OPERATING LLC — Warning Letter
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2012-07-25
- **effective on:** Not available
- **summary:** CLOSED warning letter citing 195.452(f)(1), 195.452(f)(3), 195.452(g), 195.452(i)(4).
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- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-220125008w
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/220125008W
**body:**

Warning Letter involving ENTERPRISE PRODUCTS OPERATING LLC. PHMSA's enforcement data identifies the cited regulations as 195.452(f)(1),  195.452(f)(3),  195.452(g),  195.452(i)(4). The case was opened on 2012-07-25 and is reported as closed as of 2012-07-25. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

220125008W_warning letter_07252012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220125008W/220125008W_warning%20letter_07252012.pdf

220125008W_warning letter_07252012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220125008W/220125008W_warning%20letter_07252012_text.pdf

220125008W_warning letter_07252012_text.pdf

WARNING LETTER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
July 25, 2012
Mr. Terry Hurlburt
Senior Vice President of Operations
Enterprise Products Operating LLC
1100 Louisiana Street
Houston, TX 77002
CPF 2-2012-5008W
Dear Mr. Hurlburt:
From June 14 to October 22, 2010, and from April 25 - 27, 2011, representatives of the
Pipeline and Hazardous Materials Safety Administration (PHMSA) inspected Enterprise
Products Operating LLCa
(Enterprise) Integrity Management Program (IMP) and pipeline
facilities in Texas, Louisiana, Arkansas, Tennessee, Missouri, Indiana, Kentucky, Illinois,
Ohio, and Pennsylvania, pursuant to Chapter 601 of 49 United States Code.
1. § 195.452 Pipeline integrity management in high consequence areas.
. . . (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;
Enterprise did not adequately identify which pipeline segments could affect a high
consequence area (HCA) because it did not conduct an HCA identification or re-analysis,
in a timely manner, subsequent to changing the product transported from McRae to West
Memphis in Line P74.
a TE Products Pipeline, LLC (TEPPCO) was the operator of record at the initiation of the inspection in June
2010. Effective August 17, 2010, TE Products Pipeline, LLC under operator identification number (OPID
number) 19237 was legally changed to Enterprise Products Operating LLC, under OPID number of 31618.



On November 12, 2009, Enterprise changed the product transported in its Line P74 from a
highly volatile liquid (HVL) to a non-HVL. HVL and non-HVL products can have
significantly different flow and dispersion characteristics when released from a pipeline.
At the time of the PHMSA field inspection of Line P74 on October 21, 2010, Enterprise
had previously identified “could-affect HCA segments” on the McRae to West Memphis
Line P74 that were based on dispersion characteristics of the previously transported HVLs
(propane and butane). While Enterprise began non-HVL flow in Line P74 on
November 12, 2009, it had not performed overland spread and water transport analyses to
determine if the change in product spread characteristics resulted in new “could-affect
HCA segments.”
Additionally, Enterprise's Pipeline Integrity Group was aware, as early as March 23, 2009,
that Line P74 was transporting non-HVLs but Enterprise had not re-scheduled or
completed an HCA re-analysis prior to PHMSA's inquiries made subsequent to the
October 21, 2010, field inspection. The HCA re-analysis could have taken two years or
more to complete after the product was first changed in the pipeline.
2. § 195.452 Pipeline integrity management in high consequence areas.
. . . (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;
Enterprise’s IMP process did not properly identify which pipeline segments could affect
an HCA because it did not include an adequate analysis of the dispersion of vapors from
the release of highly volatile liquids and volatile liquids.
Enterprise’s process did not provide a technical justification for the identification of which
pipeline segments could affect an HCA because at the time of the determination the
Potential Impact Radii (PIR) for Line P2 and Line P-63 were not available. Additionally,
the PIR for Line P-35 had been incorrectly changed during the process from the correct
value of 5,000 feet to 3,500 feet by Enterprise’s contractor during the HCA determination
process. The correct PIR for each pipeline segment was necessary to identify which
pipeline segments could affect a high consequence area due to a release of highly volatile
liquids.
3. § 195.452 Pipeline integrity management in high consequence areas.
. . . (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
2



operator must include, at minimum, each of the following elements in its written
integrity management program:
. . . (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);
Enterprise did not properly complete an analysis that integrated all available information
about the integrity of its entire pipeline and the consequences of a failure as follows:
a) The DRAS common risk model Enterprise used in its IMP to perform a minimal risk
analysis relied on Enterprise’s PODS database. The data input into the DRAS model
from PODS, however, was not sufficient in that PODS did not have all the data
required to perform the minimal risk analysis. Moreover, Enterprise was unable to
retrieve the following data via its risk model Data View application when requested to
do so by the PHMSA inspectors during the inspection.
− P2 Mainline Coating Type - Priority 2 (previous list indicated Priority 1)
− P40 Mainline Coating Type - Priority 2 (previous list indicated Priority 1)
− P2 Pipe Grade - Priority 1
− P2 ILI Technology - Priority 3 (previous list indicated Priority 1)
− P2 ILI Date - Priority 3 (previous list indicated Priority 1)
− Information on Ohio River Crossing on the A1/A3 lines, Lines P2 and P62
Mississippi River Crossings
The priorities shown above are from a list Enterprise provided to PHMSA on
08/27/2010. Priority 1 risk data are those elements that are essential to risk and which
must be included to allow the risk model to provide the minimal risk results set.
b) Enterprise did not use adequate and appropriate processes to input data and
information into the risk analysis process. Enterprise converted from its TEPPCO
Bass Trigon IAP risk model to the DRAS risk model in May 2010. During the
PHMSA inspection, Enterprise determined that the data provided to the common risk
model vendor (DRAS) was not read properly into the model; thus, invalidating the
results. On July 22, 2010, Enterprise declared the DRAS model invalid and reverted
back to the previously used TEPPCO Bass Trigon IAP model.
c) Enterprise had incorrect data in its PODS database. Maps and drawings using PODS-
extracted data indicated the following PODS data were incorrect.
− Drawing number TEPPCO Southern - P22-PAL_003, dated 08/20/2010,
incorrectly indicated the route of Line P22 as traversing under three buildings in
the (HCA) area upstream of milepost 5.
− Drawing number TEPPCO Southern - P22-PAL_005, dated 08/20/2010,
incorrectly identified the year of construction of pipeline segments as 1990 -
construction years were 1953-1955.
− Map number F16_0180_E, dated 09/09/2010,
- Incorrectly indicated that a valve existed on Line P22 near Benton, AR; and,
- Did not indicate a 3,661-foot segment as an HCA. This segment was
determined to be an HCA in 2004 by Bass Trigon, but the HCA data was not
resident in the PODS database.3



− A Line P74 main line valve located at approximately mile post (MP) 6.01 was
not indicated on drawings TEPPCO Southern--P74--PAL_001 and _ 002 dated
08/20/2010.
− A Line P74 main line valve was indicated on drawing TEPPCO Southern--P74--
PAL_009 dated 08/20/2010 at MP52-44+70. This valve had been previously
removed and a valve no longer existed at this location.
− A Line P74 main line valve was indicated on drawing TEPPCO Southern--P74--
PAL_015 dated 08/20/2010 at MP89-06+16. A valve did not exist at this
location.
− A Line P2 main line valve was indicated at station 18378+67 (MP 348.08) on
drawing TEPPCO ML-P2-PAL_107 dated 08/20/2010. Although a valve
existed on Line P62 at this location, a valve did not exist on Line P2 at this
location.
− A Line P2 main line valve located at approximately MP 441.04 was not
indicated on drawing TEPPCO ML-P2-PAL_132 dated 08/20/2010.
4. § 195.452 Pipeline integrity management in high consequence areas.
. . . (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:
Enterprise did not follow its IMP process for performing the periodic evaluation of the
integrity of its pipeline.
Enterprise’s procedure IMP SEC6-01 Information Analysis - Line Pipe required Enterprise
to perform an information analysis (IA) for its pipeline segments within 2 years of the
completion of the integrity assessment. Four of the IAs the PHMSA inspectors reviewed
during the inspection did not meet Enterprise’s required 2-year timeframe. PHMSA later
recognized that Enterprise had significantly reduced the backlog of IAs that had not been
completed within 2 years of the integrity assessment, but as of August 25, 2010, there
were still five backlogged IAs.
5. § 195.452 Pipeline integrity management in high consequence areas.
. . . (i) What preventative and mitigative measures must an operator take to protect the
high consequence area?
… (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.
4



Enterprise excessively delayed its process to determine if EFRDs were needed on certain
pipeline segments to protect high consequence areas in the event of a hazardous liquid
pipeline release.
Enterprise’s IMP procedure Emergency Flow Restricting Devices (EFRD) Analysis
Process, rev.0 was initially approved on June 14, 2010. Based on data provided by
Enterprise dated August 27, 2010, however, recommendations to perform evaluations for
installing additional EFRDs on many pipeline segments dated back to 2007. The EFRD
Recommendation Status remained open as of August 27, 2010.
For example, Enterprise’s records showed recommendations were made for an EFRD
review of Line P62 AID Segment 496, based on an October 1, 2007, information analysis.
Yet, the scheduled completion date for the EFRD feasibility study for this AID was not
until the 4th quarter of 2010. Moreover, once Enterprise completes the feasibility study
and recommends installation of an EFRD, time is still required for installation. It was
noted that all of the “open” recommended EFRD studies were scheduled for feasibility
study completion by the end of the 4th quarter of 2010.
Under 49 United States Code, §60122, you are subject to a civil penalty not to exceed
$100,000 for each violation for each day the violation persists up to a maximum of
$1,000,000 for any related series of violations. 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 correct
the items identified in this letter. Failure to do so will result in Enterprise Products
Operating LLC 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 2-2012-5008W. 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,
Wayne T. Lemoi
Director, Office of Pipeline Safety
PHMSA Southern Region
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