Regulatory Update on the Hazardous Liquid Regulations and ...Regulations and Recent Lessons Learned Chris Hoidal Western Region Director. ... 2002 2004 2006 2008 2010 Calendar Year

Office of Pipeline SafetyOffice of Pipeline Safety

Regulatory Update on the Hazardous Liquid Regulations and Recent Lessons Learned

Chris HoidalWestern Region Director

Office of Pipeline Safety

The Office of Pipeline Safety Mission

To ensure the safe, reliable, and

environmentally sound operation of the

nation’s pipeline transportation system.



PHMSA Regions


Gas and Hazardous Liquid Pipeline Safety Programs


Recent Changes to Regulations and Lessons Learned

• PHMSA recently issued regulations changing the scope of what hazardous liquid pipelines we regulate.

• The Western Region experienced numerous high profile incidents that highlight the need for good integration of data to prevent reoccurrence of similar events.

• What can we expect in near future?


Watershed Events

• Olympic Pipeline Explosion in June1999

• El Paso Pipeline Explosion in August 2000


Objective of the Integrity Management Rules

Improve pipeline safety through:– Requirements for periodic testing – Integrated evaluation of risk information– Improved Federal/State oversight of

operator integrity management programs and plans


Key Features of the HLIntegrity Management Rule (1)

• Provides enhanced protection for defined High Consequence Areas (HCAs)– unusually sensitive environmental areas,

urbanized areas and other populated places (delineated by the Census Bureau)

– commercially-navigable waterways


Key Features of the HLIntegrity Management Rule (2)

• Requires hazardous liquid pipeline operators to develop a written Integrity Management Program that includes:– A risk assessment of a pipeline’s integrity threats – A plan to carry out baseline and future reassessments to

assure the integrity of those P/L segments that could affect an HCA

– Repair integrity threats found during the assessments– Preventative and Mitigative Measures to provide on going risk

reduction beyond those identified by periodic assessments, e.g. “Don’t do a Pig and Dig Program.”


Applicability of the HLIntegrity Management Rule

• Applied to high pressure liquid operators with 500 or more miles of hazardous liquid pipelines in 2001

• A similar rule for operators of smaller, jurisdictional liquid pipeline systems is also in effect in 2002

• Following a series of incidents on low stress lines, particularly the BP Alaska release in 2006, Congress directed us in the PIPES Act of 2006 to expand our regulatory oversight


Another Game Changer

• The BPXA spill of 5000 BBLs on North Slope in March 2, 2006.

• Then non regulated, low stress 34-inch diameter pipeline carrying 190,000 BBLs/day

• No cleaning or ILI in some sections since the early 1990s.

• Extensive internal corrosion


New Low Stress Pipeline Rules – Cat 1

• Phase One applied 49 C.F.R. Part 195 regulations to high-risk, large-diameter (8-5/8” or larger) rural, low-stress pipelines within one-half mile of an unusually sensitive area (“USA”).

• Issued June 3, 2008.


New Low Stress Pipeline Rules – Cat 2

• Phase Two applied all Part 195 requirements – including Integrity Management (“IM”) requirements – to all rural, low stress hazardous liquid pipelines less than 8-5/8” in diameter not included in Phase One implementation, but which are located within one-half mile of a USA

• Issued May 5, 2011


New Low Stress Pipeline Rules - Cat 3

• Category 3 pipelines are the remaining rural, low-stress hazardous liquid pipelines not included in Categories 1 or 2. Because Category 3 pipelines are not within the “could affect” half-mile buffer of the USA (where Category 2 pipelines are located), IMP is not required. Annual reporting is required for all IM/HCA pipeline sections.


Effective Dates

Category 1 Compliance Deadlines:

• April 3, 2009: Identify all segments of pipeline meeting the criteria.

• July 3, 2009 Establish a written integrity management program

• January 3, 2012: Complete at least 50 percent of the baseline IM assessments

• July 3, 2015: Complete the baseline Assessments for the rest of the segments.


Category 2 and 3 Compliance Deadlines:

Category 2 July 1, 2012: Within nine months of the October 1, 2011, effective date of the final rule, an operator must identify its Category 2 and 3 pipelines

Category 3 July 1, 2012: Within nine months of the October 1, 2011, effective date of the final rule, an operator must identify its Category 2 and 3 pipelines

April 1, 2014: Within 2½ years of the effective date of the final rule, at least 50 percent of all Category 2 pipelines must have complete baseline IM assessments

October 1, 2016: Within five years of the effective date of the final rule, all Category 2 pipelines must have complete baseline IM assessments


The Operator’sIntegrity Management Program

• The Integrity Management Program must include the following elements:– Method for determining which pipeline segments could affect

HCAs– A Baseline Assessment Plan (Usually ILI or Hydro)– A process for continual integrity assessment and evaluation– A process that integrates all available information about

pipeline integrity and the consequences of a failure– Consideration and Implementation of other preventative and

mitigative measures to reduce risk


153 149138

127

10697

128

111

85

0

20

40

60

80

100

120

140

160

180

2002 2004 2006 2008 2010Calendar Year

Liquid Pipeline Spills w/Environmental Consequences (2002-2010)

Data: DOT/PHMSA Pipeline Incident Data (as of Jan. 19, 2011)

- 19 -


Recap of Integrity Management Programs to Date

• The Integrity Management Program for High Pressure Pipelines Requires– repair criteria to address issues identified by the integrity

assessment method and data analysis (Successful)– a process for review of integrity assessment results and data

analysis (Room for improvement)– a process to identify and evaluate preventive and

mitigative measures to protect HCAs (Room for improvement)

– methods to measure the integrity management program's effectiveness (Room for improvement)


IMP Enforcement actions to date


Where are accidents occurring?

• Accidents decreasing on line pipe, but….– More and more accidents are being caused

by interactive threats and on facility pipe.


Spill at Sunoco facility near Colorado City, Texas


Hazardous LiquidTime run: 8/23/2011 11:00:23 AM

ODES - Data as of 08/22/2011SMART - Data as of 08/22/2011EIA - Data as of 08/22/2011

National

ALL REPORTED Total

Incident Cause Type 2005 2006 2007 2008 2009ALL OTHER CAUSES 31 32 24 20 15 122CORROSION 80 89 77 79 75 400EXCAVATION DAMAGE 18 17 20 22 18 95INCORRECT OPERATION 35 44 34 45 37 195MAT’L/WELD/EQUIP FAILURE 165 146 150 182 172 815NATURAL FORCE DAMAGE 33 12 17 21 15 98OTHER OUTSIDE FORCE DAMAGE 7 14 8 6 6 41

Grand Total 369 354 330 375 338 1,766

020406080

100120140160180200

2005

2006

2007

2008

2009


Photo of PS 9 Alyeska Spill


Recent High Profile Incidents Where Integration of Data Was Factor

Chevron Crude Oil Release in Salt Lake City – June 2010– 800 BBL spill into city park and Red Butte Creek; est.

$5M cost to operator– ROW had been encroached upon by buildings,

structures and vegetation– Electrical Substation and grounding grid installed on

top of pipeline in 1984– Risk of fault currents posed by nearby structures not

explicitly incorporated into IM program– Fault current during storm arced from fence post tied

to grounding grid to pipeline causing leak




Another High Profile IncidentExxonMobil Silvertip – July 2011

– ExxonMobil Silvertip pipeline released estimated 1000 barrel of crude oil into the Yellowstone River near Laurel, Montana; Est. $42M damages

– River scour is cause of accident– EMPL was aware and monitored the flood

conditions; had numerous remote actuated valves at rivers

– Controllers took 56 minutes after first alarm to close valve adjacent to river


ExxonMobil Silvertip (cont.)

– ExxonMobil did not appear to explicitly integrate local river crossing information, particularly local stream information, into their IMP when determining their preventative and mitigative measures

– MT Governor’s and PHMSA task force revealing few pipeline companies incorporate river and geotechnical risks when determining P&M measures


ExxonMobil Silvertip – July 2011


ExxonMobil Silvertip – July 2011


And Another High Profile IncidentSan Bruno – September 2010

– Eight fatalities, 66 injuries, 38 homes destroyed– Operator utilized ECDA as Assessment Method– It appears that not all construction, materials,

maintenance or operational history integrated until after accident

– Large systems need a systematic way to ensure all pipeline information is integrated, particularly when ECDA is used




WHAT’S NEXT???


The Impact of Incidents

• Got the Attention of Everyone – White House, Secretary, Congress, media, oversight agencies, and the public

• Expect to See More Media Attention to Pipeline Failures

• Expect to See DOJ and EPA Stepping Up Their Attention

• Focus on States: Questions about states– as a whole - being too close to industry and lacking the will to enforce– Familiar theme to OPS

• Delayed Reauthorization (not a good thing for any of us) - 37 -


Delayed Reauthorization? Why Care?

• On Reauthorization of the Pipeline Safety Program

– Every four years Congressional scrutiny of Fed/State oversight performance

– Had hopes of it going better than in 2002 or 2006

– 7 Congressional hearings in 2010 – 5 hearings so far in 2011

– Will set the most of regulatory agenda for the next 4 years

- 38 -


Pipeline Safety Reauthorization

• General Themes / Provisions in Play– More Inspection by PHMSA and States– Stronger Enforcement – raises civil penalties 2.5x for

Feds.– Eliminating exemptions from One-Call laws– Study and regulate use of Automatic Shutoff Valves

(ASV)/Remotely Controlled Valves (RCV)– Study and regulate HL leak detection– Expansion of regulations at water crossings

- 39 -


Pipeline Safety Reauthorization

– Extends natural gas Excess Flow Valves rules to multi-family/small commercial

– Cost recovery for special permits and new construction

– Study/report on risks of Canadian crude from oil sands

– Increased data reporting – including geospatial data– Removal of exemptions for various pipelines

- 40 -


Moving Forward to Make Improvements Before

Congressional Mandates• Will Issue Rulemaking to require

Hazardous Liquid (HL) NPMS Submissions and Add’l Attribute Data

• Notice of Proposed Rulemaking on HL IMP improvements will be out in the next few months

• Recently Issued ANPRM on Natural Gas Regulations, including IM Rules


NPMS Update

• PHMSA is pursuing rulemaking to mandate NPMS submittals, including expanded pipeline attribute information.

• Operators are still required to examine their data every twelve months and determine if any part of their submission (geospatial, attribute, metadata, or public contact information) has changed. If any of these components have changed, the operator must resubmit their data to the NPMS.


NPMS Update (cont.)

• In 2010 and beyond, the annual report and NPMS submission due dates would remain March 15 for gas transmission and LNG plants and June 15 for hazardous liquid pipelines.

• PHMSA also suggests that Operator ID numbers in annual report submissions match the same assets described in NPMS submissions


Summary and Conclusions• Assessment of pipeline integrity

in high consequence areas are being expanded to low stress pipelines

• Assessment and repair has been successful. We still need to move to better data collection and integration.

• Integration of other Risks can be improved upon. GIS provides a good platform.

• Preventative and Mitigative measures must be constantly improved upon.


Summary and Conclusions (Continued)

• Congress will mandate improvements.• PHMSA is moving forward now to improve

regulations to further improve safety.

Documents

Regulatory Update on the Hazardous Liquid Regulations and ...Regulations and Recent Lessons Learned Chris Hoidal Western Region Director. ... 2002 2004 2006 2008 2010 Calendar Year