January 19, 2009
Distribution Integrity
Management Program
A discussion document
DIMP Interest Group Steering Committee
• Mike Beatty, Manager, Engineering & Construction, South Carolina
Electric & Gas Company
• Craig Hoeferlin, Vice President, Operations, Laclede Gas Company
• Phillip Murdock, Director, Asset Management, Atmos Energy
• David Cicoria, Manager, Systems Operations, Columbia Gas of
Virginia, a Nisource Company
• Mike Grubb, Staff Executive, SGA
• Fraser Farmer, Staff Executive, SGA
Some material provided by
Andrew Lu, American Gas Association
49CFR192 - Federal Regulation

Needs modification to include risk-based
distribution integrity management process:




High-level, performance-based flexible federal
reg
Implementation guidance
Nation-wide education program (as part of
implementing 3-digit One-call)
<DIMP or Damage Prevention>
Continuing research & development
2
Distribution Characteristics
1)
2)
3)
4)
5)
Distribution pipeline systems exist in restricted geographical areas
that are predominantly urban/suburban, because the purpose of
these pipelines is to deliver natural gas to end users – residential,
commercial, industrial and institutional customers.
Distribution pipelines are generally small in diameter (as small as
5/8 inch), and are constructed of several kinds of materials
including a significant percentage of plastic pipe.
Distribution pipelines also have frequent branch connections,
since service lines, providing gas to individual customers, branch
off of a common “main” pipeline, typically installed under the
street.
The dominant cause of distribution incidents is excavation damage
with third party damage being the major contributor to these
incidents.
Other than as caused by excavation damage, distribution pipeline
failures almost always involve leaks, rather than ruptures, because
the internal gas pressure is much lower than
for transmission pipelines.
3
The 7 Key Elements
as noted in NPRM 192.1007 June 25, 2008
a)
Knowledge of the system’s infrastructure
b)
Identify threats (existing and potential)
c)
Evaluate and prioritize risk
d)
Identify and implement measures to address risks
e)
Measure performance, monitor results and evaluate effectiveness
f)
Periodic evaluation and improvement
g)
Report results
4
Notable Required
Elements in a DIMP Plan
• 192.1007 d) Formal risk assessment of threats to an operator’s
distribution system, including risk posed by operator’s employees –
“Assuring Individual Performance” - “PTP”
• Data integration (Leaks, corrosion data, 3rd party damages, etc.)
• Mechanism or process to identify any potential problems with
compression couplings
• 192.1007 d) Requirement to identify and implement risk reduction
strategies, w/ emphasis on effective leak management program
(“LEAKS”) and “enhanced” damage prevention program.
• 192.1009 Proposed requirement for operator to report all plastic pipe
‘failures’ (including fittings, couplings, valves and joints) to the state
agency.
5
Notable Required
Elements in a DIMP Plan
• 192.1019 a) Special provisions are proposed for master meter and
liquefied petroleum operators
• 192.1007 f) Operator must conduct a complete DIMP program reevaluation at least every five years
• 192.1005 a) Operator is given 18 months from the date of final rule
issuance to develop and implement a written IM program
• Eliminates § 192.383
• Invites comment on the desirability of requiring permanent markings
on plastic pipe and the proposed approach of relying on ASTM.
(Would possibly help with risk management)
• SHRIMP for smaller operators - APGA
6
Threats
The categories of threats to be considered should include
the eight threats identified in the Pipeline and Hazardous
Materials Safety Administration (PHMSA) Annual
Distribution Report, PHMSA Form 7100.1-1 as “Cause of
Leaks” in Part C:
1)
2)
3)
4)
5)
6)
7)
8)
Excavation
Other outside force
Natural Forces
Incorrect Operations
Equipment
Corrosion
Material or welds (construction)
Other
7
Implementation







Establish a Framework (SGA/NGA joint project)
Region = system vs. segment
Prioritize threats, using risk assessment methods,
in each segment based on personnel (SME)
knowledge and construction, operation &
maintenance records
Assess needs, opportunities & plans to address
each threat/region
Develop metrics to evaluate performance
Document
Continuous improvement cycle
8
Timeline






DOT Inspector General issues report to Congress on DIMP
(June 2004)
AGF Study on “Safety Performance and Integrity of the
Natural Gas Distribution Infrastructure” (Jan 2005)
DIMP Phase 1 Report is published by PHMSA (Dec 2005)
GPTC working on DIMP Guidance Material. Final “draft” is
completed and awaits issuance of regulation (late 2006)
2006 PIPES Act passed, mandating DIMP by Dec 31, 2007
and EFVs by June 1, 2008 (Dec 2006)
NPRM on DIMP issued (June 25, 2008)



Comments due Sep 23, 2008
Final Rule for DIMP anticipated (mid- 2009)
DIMP Plan will be required within 18 months from Rule
issuance (late-2010)
9
PHMSA - data driven


PHMSA wants to be data driven in DIMP
reporting
AGA/PHMSA task group on national metrics


Christina Sames, AGA - indicators to demonstrate
improvements
Internal vs. external reporting metrics
10
Guidance

Need particular support for smaller operators
Should develop guidance to assist operators in
determining:
(a) threat prioritization methods
(b) risk control practices
(c) performance measures that are most appropriate for their risk
control program.



Implementation guidance
(GPTC - Gas Piping Technology Committee)
SHRIMP
NGA/SGA Framework
11
GPTC






Final draft issued (Oct 13/06)
Approval of draft - Nov 6/07 - ANSI Reno
meeting
Sync with NPRM in July 2008
Sync with final rule in mid-2009
Good working relationship
industry<>PHMSA. Important not to have
major industry objections later in the process.
GPTC web site.
12
SHRIMP
simple, handy, risk-based, integrity,
management, plan












A Plan implementation resource
Being developed by APGA - John Erickson
Focus > smaller operators (also for large)
A software tool using interactive rule/expert techniques to derive a
DIMP document
Proscriptive, not customizable
Consistent with Final Rule & GPTC guidelines
Like tax preparation software
Expert working group - APGA, AGA, PHMSA …
Consultants - to make the software
Grant from PHMSA
Available upon issuance of Final Rule
Extension to include interfaces to workflow etc for DIMP reporting
13
NGA/SGA Generic
Distribution Integrity Management Plan






A joint NGA/SGA project
A Plan implementation resource
Generic part + customizable part
Expert working group (DIWG) – NGA, SGA
Consultants - to make the Plan Apr 2009 to July 2009
Available 1 month after issuance of Final Rule
Available to joint industry project participants
14
Prevention & Mitigation


Damage prevention programs
Leak management programs

Public Awareness programs
Operator Qualifications programs

Other programs

DIMP or separate initiatives?
Stand-alone programs?
15
State Damage Prevention Programs
Some states have implemented effective comprehensive
damage prevention programs that have resulted in significant
reductions in the frequency of damage from excavation.
Effective programs include nine elements:
1.
2.
4.
5.
6.
7.
8.
Enhanced communication between operators and excavators
Fostering support and partnership of all stakeholders in all phases
(enforcement, system improvement, etc.) of the program
Operator’s use of performance measures for persons performing locating of
pipelines and pipeline construction
Partnership in employee training
Partnership in public education
Enforcement agencies’ role as partner and facilitator to help resolve issues
Fair and consistent enforcement of the law
Use of technology to improve all parts of the process
9.
Analysis of data to continually evaluate/improve program effectiveness
3.
Potential obstacle: Other utilities may have different priorities (e.g.
telecoms want lost revenue recovery)
16
State Damage Prevention Programs



Not all states have implemented such
programs.
Federal legislation and/or funding is likely
needed to support the development and
implementation of such programs by all
states. Work on this legislation can begin
immediately.
This represents the greatest single
opportunity for distribution pipeline safety
improvements.
17
Leak Management
Management of gas leaks is fundamental to
successful management of distribution risk, and an
effective leak management program is thus a vital
risk control practice. Effective programs include the
following elements:
1.
2.
3.
4.
5.
Locate the leak
Evaluate its severity
Act appropriately to mitigate the leak
Keep records, and
Self-assess to determine if additional actions are
necessary to keep the system safe.
18
Excess Flow Valves


Congress passed PIPES Act in 2006
mandating the installation of EFVs as of June
1, 2008.
After June 1, 2008, EFVs must be installed
where:




New/replacement services lines serving single
residential customers
Operating pressure > 10 psig
Contamination will not prevent proper operation
EFV in size required is commercially available
19
Performance Tracking



Track damage prevention metrics both for internal
use in evaluating the effectiveness of an operator’s
program (by operators) and for evaluating progress
at the national level.
Once reportable Performance Measures are
finalized, develop a national baseline from which
trends in performance can be monitored, and a
means of tracking trends from the baseline.
Form a joint stakeholder group to conduct an annual
data review, to resolve issues, and to produce a
national performance measures report.
20
Performance Measures
7 performance measures as noted in § 192.1007:
1. # hazardous leaks eliminated/repaired, by cause
2. # of excavation damages
3. # of excavation tickets
4. # of EFVs installed
-----------------------------------------------------------------5. Total # of leaks eliminated/repaired, by cause
6. Total # of hazardous leaks eliminated/repaired, by material
7. Any additional measures to evaluate effectiveness of
operator’s program in controlling each identified threat
21
Data Reporting
Considering changes to data reporting:
1.
Require additional information for incidents when cause is
excavation damage – identify useful information from review of
the Damage Information Reporting Tool (DIRT) and state
reporting requirements
2.
Expand incident report form to add information on the causes
of incidents resulting from vehicles hitting gas facilities
3.
Report hazardous leaks eliminated by material in addition to
cause; indicate presence of protection (e.g., coating, cathodic
protection)
4.
Report hazardous leaks eliminated rather than all leaks
eliminated/repaired during the year and the known system
leaks at the end of the year scheduled for repair
5.
Add a check box (and appropriate criteria) on whether the
regulations clearly require reporting or whether the report is
submitted at the discretion of the operator
22
Plastic Pipe Data Collection
• In 2001, national effort was initiated to collect data on plastic
pipe performance
• AGA is the administrator of this database
• PHMSA has expressed concern with the transparency of
how the effort is being managed; specifically how the data is
collected , who has access to it and whether it is effective
based upon how it is currently set up.
• The DIMP NPRM asks questions whether the reporting
should be mandatory; who should manage the database;
and if it makes sense to start a new effort to improve
availability of results and sharing of “information” to all
operators.
• Obstacles may include anti-trust issues, legal disclosures,
and data integrity.
23
Plastic Pipe Data Collection
– AGA perspective
• Companies submit data to the PPDC because they trust
that it is kept strictly confidential.
• PPDC has been successful and changing the reporting
structure or the administrator will jeopardize this success.
• Those who are involved in PPDC are in favor of keeping it
status quo.
• If there were a national problem with couplings or a
particular plastic pipe, then the PPDC is equipped to
identify such a problem for the industry.
• It doesn’t make sense to have two separate plastic pipe
databases.
24
Assuring Individual Performance
• Prevention Through People is a concept that was promoted
by Admiral Barrett, and it has been used in public meetings
to discuss CRM.
• Under 192.1007 “What are the required IM program
elements?”, it would require operators to evaluate and
manage the contribution of human error and intervention to
risk. (cites human factors, including fatigue management)
• This section must consider existing programs the operator
has implemented to comply with Damage prevention
programs, public awareness, OQ and drug & alcohol
testing.
• Read Section XI. Prevention Through People on
p.36027-36028 of Federal Register NPRM.
25
Assuring Individual Performance
– AGA perspective
• PTP was not included in DIMP Phase 1 Report.
• OQ, DP, Drug & Alcohol Testing and Public
Education requirements should sufficiently address
how an operators manages human error.
• Operator error historically has been the cause of a
very small % of reportable incidents. (< 5% in past
10 years)
• What does an effective fatigue management plan
look like?
• How can an operator directly control the actions of
people that it does not employee?
26
Service Line Inspections
• DIMP is supposed to be a performance-based rule, yet there
are existing sections in the code that are counter to this
philosophy - - § 192.481 Atmospheric Corrosion and §
192.723 Leakage Surveys.
• In 2007, AGA worked with NAPSR and PHMSA to form a
government-industry Service Line Inspection Committee to
discuss issues relating to leak surveys and corrosion
inspections on both inside and outside meter installations.
• Objective: To collect data from service line inspections
performed throughout North America and evaluate the true
effectiveness of these surveys and inspection requirements
and the potential consequences of changing the regulations.
• Report to be issued by consultant by October 2008.
• Study will hopefully support industry’s case for special
permits under DIMP Rule.
27
Research & Development

Review Phase 1 report for R&D
conclusions.
28
AGA Comments
1 of 4. Documentation for Gas Distribution Integrity Management Plans
Avoid excessive record keeping requirements
The primary concern that AGA has with sections 192.1007 and
192.1015 is that PHMSA deviates from the recommendations of the
DIMP phase 1 report in that the proposed rule appears to require
unnecessary and excessive documentation within an operator’s
distribution integrity management plan.
The regulation’s requirement that operators document all of the
decisions they make in implementing distribution integrity
management is not practical.
Gas distribution systems are so intricate that it would require an
enormous paperwork burden to document all the decisions
associated with providing service to millions of customers.
29
AGA Comments
2 of 4. Plastic Pipe Data Collection and Analysis
The need to modify the Plastic Pipe Database Committee (PPDC)
AGA notes that the existing Plastic Pipe Database Committee
(PPDC) has done an excellent job in tracking the trends in plastic
material performance and believes that eliminating this committee
and creating a completely new plastic pipe database is unnecessary
and counterproductive.
30
AGA Comments
3 of 4. Prevention Through People
Inability of operators to implement vague and unenforceable human factor
requirements in integrity management programs
The proposed distribution integrity management program regulations include
requirements for operators to understand the threats affecting the integrity of their
systems and to implement appropriate actions to mitigate risks associated with these
threats. These include a first step towards instituting a ‘‘Prevention Through People’’
(PTP) program to address human impacts on pipeline system integrity. Human impacts
include both errors contributing to events and intervention to prevent or mitigate events.
As part of considering the threat of inappropriate operation (i.e., inappropriate actions by
people), this proposed rule would require operators to evaluate the potential for human
error.
Seeking to reduce incidents by minimizing human error is commendable. However, the
AGA has some fundamental problems with the PTP concept in the proposed rule. A
major problem is that the concept as presented in the rule is too vague to be an
enforceable regulation.
31
AGA Comments
4 of 4. Alternative Inspection Intervals
The need to efficiently implement alternative inspection intervals
AGA supports the concept of alternative inspection intervals. When the pipeline safety
code was adopted in the early 1970s it was reasonable and prudent to adopt a
consistent set of federal pipeline safety standards for the entire nation. Now, in the 21st
century, data analysis can distinguish the effectiveness of pipeline safety inspections.
Operators and regulators can use this analysis to tailor their regulations to meet the
needs of the local stakeholders.
The underlying purpose of PHMSA’s integrity management requirements is to improve
knowledge of the condition of each operator’s pipeline and to use that information to
identify new risk control solutions and to better focus risk reduction efforts. Resources
would be better allocated to higher risk threats. Furthermore, AGA does not believe the
DIMP regulation would be cost beneficial unless an effective method to implement
alternative inspection intervals is included in a final rule.
32
SGA - Assisting its members






Work with DIMP Interest Group Steering Committee to define
implementation issues that should be addressed and to
manage desired outcomes. Keep Interest Group on track, on
timeline.
Do a survey to define current practices
Do WebCon on the 7 elements – Fall 2009
Support the ‘guidance’ process
Develop a starter shell DIMP for members (similar process to
Transmission; NGA/SGA DIWG) – Fall 2009
Face-to-face meeting when Rule is issued – Fall 2009
33
More Information

SGA DIMP IG web page http://www.southerngas.org



Please contact any member of the steering committee for further
information:






click on “Interest Groups”
then on “DIMP”
Mike Beatty, Manager, Engineering & Construction, South Carolina
Electric & Gas Company
Craig Hoeferlin, Vice President, Operations, Laclede Gas Company
David Huff, Director Distribution Operations, E.ON/U.S. (L.G.&E.)
Phillip Murdock, Director, Asset Management, Atmos Energy
David Cicoria, Manager, Systems Operations, Columbia Gas of Virginia, a
Nisource Company
SGA contacts:



Randy Randolph, Staff Executive, SGA
Mike Grubb, Staff Executive, SGA
Fraser Farmer, Staff Executive, SGA
34