# Presentation: 305229

## Gas Integrity Management RuleProtocols

**49 CFR 192**
**Pipeline Integrity Management**
**January 2005**
**Welcome**

## Natural Gas Transmission PipelineIntegrity Management Oversight Program

**Atlanta, Georgia**
**January 2005**
**OPS & NAPSR**
**Welcome You**

**Notes:**
Welcome to our oversight implementation workshop for Gas Integrity Management
Today and tomorrow we will be providing insights and details to the extent possible regarding our oversight implementation for the Gas Integrity Management Rule
The program will cover key elements of our development process, the inspection protocols, and implementation of our oversight program such as the format and structure of a Gas Integrity Management Inspection
We take this as a learning opportunity, as with all new regulations, we are sure there are issues we have not considered regarding or oversight program

## Welcome and Opening Remarks

**Jeff Wiese**
**OPS Program Development Director**

## Welcome

**Acknowledgements**
**Introductions**
**Administrative Announcements**
**Safety and Comfort Directions**
**Web Cast Instruction**
**Q&A**
**Agenda Review**

## Acknowledgements

**NAPSR**
**OPS’ Key Partner in Pipeline Safety**
**Major contributors to the shape and direction of IMP oversight**
**Our alignment works for everyone concerned**

## Acknowledgements

**Industry**
**INGAA, AGA, SGA, MEA, NEA**
**Actively involved and not shy**
**BG&E, Duke, El Paso, & PG&E **
**Essential reality check**
**Standards Committees**
**Particularly ASME & NACE**

## Administrative Announcements

**Slides & webcast will be available online**
***http://primis.rspa.dot.gov/gasimp***
**Attendance lists will NOT be available**
**Playing strictly to the agenda**

## Safety & Comfort

**Emergency Direction**
**Restrooms**
**Cell Phones & Pagers**

## Web Cast

**We web casting to allow participation by a larger audience – please register**
**Causes us to use very plain text for presentations:**
**For help or to submit questions: **_***GASIMP@RSPA.DOT.GOV***_

## Q & A Sessions

**Q&A Session at End of Each Day**
**Via e-mail (GASIMP@RSPA.dot.gov)**
**3x5 cards (attendees)**
**Questions from the floor (attendees)**
**Please identify yourself each time you speak**

## Agenda Review

**Starting promptly @ 8:30a ET**
**Agenda available online – ET**
**Ambitious schedule, so we’ll be following the agenda as closely as possible **
**Audience:  door closing is cue**
**Introduction of OPS DAA**

## Gas Integrity ManagementPublic Workshop

**Relationship of Gas IMP to**
**OPS Strategy**
**Ted Willke**
**Deputy Associate Administrator**
**Office of Pipeline Safety**
**Atlanta Georgia**
**January 19, 2005**

**Notes:**
It is a pleasure to be representing the Office of Pipeline Safety on an issue that has concerned many of us for a decade.  I have worked with many of you and I look forward to meeting each of you.  
As many of you know, I took 5 years away from the gas industry—spending time at Carnegie Mellon University.  As MacArthur said as he was driven out of the Philippines I SHALL RETURN.  I am here to announce I AM BACK!  
The want to welcome you to the Joint Federal/State Public meeting on Gas Integrity Management.  In the past OPS would have issued a regulation and expected you to interpret the regulations yourself.  This public meeting represents a new way of doing business—in which working with our State partners we are making an effort to explain our interpretation of the regulation and give you a chance to respond.  
Our objectives are to 
Inform you of the compliance expectations for the Gas IMP rule. 
Provide you with the opportunity to educate us about your concerns and expectations. 
Reinforce our commitment to an open dialogue with you regarding a rule that will roll out over a decade.  
At OPS we are proud of what we have accomplished—together.  Industry made a large contribution in the debate over the rule and the creation of consensus standards to guide integrity management.  The States play an even larger role in IMP implementation.  They are our partners in this exercise.  
We have much work to do—hard work.  There are bound to be bumps in the road as we go along.  We went through this process earlier with our liquid pipeline brethren.  You can thank them for breaking the pathway for you.  We should all learn from their experience.  

## OPS Strategic Focus

**Improve the safety of the nations pipelines**
**Provide the basis for increased public confidence in pipeline safety**

**Notes:**
Our joint responsibility to the American people is to ensure that our energy transportation pipelines are built, operated, and maintained in a safe manner. 
 Our overriding goal is to reduce the risk that pipelines will cause harm to people and the environment.  
We have two strategic goals:  
To reduce the number of incidents on pipeline systems every year 
To reduce the likelihood of major incidents and to mitigate their consequences if they occur.  

Major accidents have caused public concern over the pipeline system and have shaken the public’s confidence in the industry and the Office of Pipeline Safety.  
Starting with the Potomac and Edison incidents in the early 1990’s, we realized that a new focus was needed to enhance pipeline safety.  That focus became risk management.  
The Bellingham and Carlsbad incidents in the late 1990’s stirred the Congress to pass the most sweeping pipeline safety law in 30 years.  The result is the Integrity Management Program—the implementation of which we are here to discuss today.  

## Recent OPS Strategic Activities (1)

**Worked to restore our credibility by**
**Addressing Congressional mandates & resolving NTSB issues**
**Improving the knowledge and skill of our technical and inspection staff**
**Strengthening our internal management practices and data**
**Strengthened our relationship with the states, our key safety partners**

**Notes:**
Working with our State partners and industry, OPS has worked hard to restore our credibility by 

Addressing Congressional mandates & resolving NTSB issues.

Imroving the knowledge and skill of our technical and inspection staff 

Strengthening our internal management practices and data.  

As a fundamental part of enhancing our credibility has been a deliberate and studied effort to strengthen our relationships with the States; they are our key safety partners.  

## Recent OPS Strategic Activities (2)

**Promulgated new regulations to ensure:**
**The **pipeline** is in better condition**
**The operator implements management **practices** that improve safety**
**The **people** responsible for safety are better able to perform their responsibilities**

**Notes:**
When all of us share the confidence of the American people and their elected representatives, 

It becomes easier to site and build pipelines.  

It becomes easier to communicate with people in local communities.  

It becomes easier to have a dialogue with other agencies.  

The new Integrity Management regulations are designed to ensure (3 things):
That the pipeline is in better condition

That pipeline operators implement practices that improve safety 

That people responsible for safety are better able to perform their responsibilities.  

## Three Major Pillars of Our Go-Forward Strategy

**Risk and integrity management**
**Shared knowledge and responsibility**
**Expanding our role in a changing world**

**Notes:**
As we look into the future, we are going forward with three pillars of strategy:  

The first pillar is RISK AND INTEGRITY MANAGEMENT.  

II  The second pillar is SHARED KNOWLEDGE AND INFORMATION.  

The third pillar is EXPANDING OUR ROLE IN A CHANGING WORLD.  

## Key Strategies

- Risk and Integrity Management
** ****Better problem identification and understanding**
** ****Improved standards and regulations **
** ****More efficient and consistent inspection and   enforcement**
** ****More risk-based allocation of resources**
** ****Better performance evaluation**

**Notes:**
OPS has a number of key strategies for each of our pillars.  Under Risk and Integrity management,  

OPS has transformed its entire regulatory approach to better focus on integrity management. 

 We start by focusing on the greatest potential threats to pipeline safety in those areas which are at most risk of harm to people and the environment.  

We want operators to look proactively for problems on the pipeline system and allocate their resources to addressing those problems.  

Among our key strategies are: 

Better problem identification and understanding
Improved standards and regulations 
More efficient and consistent inspection and enforcement 
More risk-based allocation of resources.  
Better performance evaluation.  

OPS does NOT believe that in regulation ONE SIZE FITS ALL.  Every system, every pipeline operator, every region, every community presents a unique situation.  

That is one reason we have incorporated some 60 CONSENSUS STANDARDS by REFERENCE in the regulations.  

## Key Strategies

- Shared knowledge and responsibility
** ****Better preparation and training**
** ****Better technologies**
** ****Better informed stakeholders**

**Notes:**
To foster the sharing of knowledge and the acceptance of responsibility, OPS has three key strategies:  

OPS has taken new initiatives to better prepare and train our staff. 

 We have established a broad-based R&D programs to provide the technologies needed to assess pipeline condition, repair and maintain pipeline systems, and new methods to build, maintain, and operate pipelines.  

The Federal/State partnership is the cornerstone for assuring uniform implementation of the pipeline safety program nationwide.  OPS works closely with the National Association of Pipeline Safety Representatives (NAPSR).  And we are working hard to develop a strong relationship with the National Association of Regulatory Utility Commissioners (NARUC).  

We have worked hard to protect people from pipelines and now are also working hard to protect the pipe from people through our work with the Common Ground Alliance and our efforts to communicate and work with local communities.  

## Key Strategies

- Expanding our role
** ****Support for national energy policy**
** ****Protecting national infrastructure**
**Expanded support for local officials**

**Notes:**
As the world has changed, so must the Office of Pipeline Safety.  

Because pipelines play such a vital role in our national economy, OPS must play a role, working with other Federal agencies, in supporting the nation’s energy policies.  

One such effort has been OPS leadership in working with other agencies on permit streamlining.  With the successful conclusion of this effort, we should expect to see more rapid permitting to allow pipelines to repair pipeline defects within the requirements of the Integrity Management Program.  The impact should be less disruption of service to communities and more expeditious repair of pipelines.  

In another initiative, we are taking a greater role in the safety of LNG facilities.  This role should allow us to facilitate the siting of LNG facilities where needed while maintaining public safety.  

OPS called on the Transportation Research Board of the National Academies to look at the issue of pipeline safety and land use policies.  I was fortunate to be a member of that study panel.  The TRB report recommended that OPS develop a risk-based framework for the siting of pipelines and land use patterns around pipelines.  

## Gas IMP is a Significant Element in Implementing our Strategy

**Largest OPS regulatory action**
**Unprecedented effort by industry**
**Cooperation with NAPSR from the outset**
**Numerous National Consensus Standards**
**Development and demonstration of needed new technologies & processes**

**Notes:**
The Gas Integrity Management Program is a significant element in implementing the OPS strategy.  

The IMP rule is the largest regulatory action by OPS since the Pipeline Safety Act was passed in 1968.  

In anticipation of this rule, industry made an unprecedented effort to establish guidelines and standards to form the basis for a rational integrity management program.  

We have worked from the outset with NAPSR.  RAISE YOUR HANDS, HOW MANY OF YOU ARE FROM THE STATES?  At every public meeting we are seeing increased State participation.  NAPSR has been a key partner on our regulatory development teams and our oversight programs.  

As I mentioned earlier, there has been an enormous effort to develop national consensus standards.  And about 60 have been incorporated into our integrity management framework.  

As the industry has reduced its level of support for pipeline safety R&D, resulting from competitive pressures, OPS is taking up the slack by funding a robust R&D program.  

## Getting to Where We are has Required Broad Cooperation

**Industry has stepped forward**
**The states have participated to an unprecedented degree**
**The OPS staff has grown to meet the challenge**

**Notes:**
OPS could not accomplished all of this without the active support and effort of many people, including many who are here with us today.  

We thank the pipeline industry for their initiatives in making things happen.  

The States have participated to an unprecedented degree.  

And our own staff at OPS have grown to meet the challenge.  

I cannot think of a better way to start my tenure with the Office of Pipeline Safety than to say THANK YOU.  

Now back to Jeff.  

## Welcome and Opening Remarks

**Jeff Wiese**
**OPS Program Development Director**

**Notes:**
Welcome to our oversight implementation workshop for Gas Integrity Management
Today and tomorrow we will be providing insights and details to the extent possible regarding our oversight implementation for the Gas Integrity Management Rule
The program will cover key elements of our development process, the inspection protocols, and implementation of our oversight program such as the format and structure of a Gas Integrity Management Inspection
We take this as a learning opportunity, as with all new regulations, we are sure there are issues we have not considered regarding or oversight program

##   Integrity Management Goals

**Accelerate assessments of pipelines in High Consequence Areas (HCAs)**
**Promote rigorous, systematic management of pipeline integrity**
**Enhance governmental oversight of company integrity plans and programs**
**Increase confidence in pipeline safety**

## Integrity Management Objectives

** ****IMP oversight objectives:**
**Clearly communicated regulatory expectations**
**Nationally consistent oversight program **
**Quality of results through well trained inspection workforce**
**Program development process has been, and will continue to be, extremely transparent**
**Oversight procedures and support are available via the internet:  ****	*****http://primis.rspa.dot.gov/iim***

## Clear Regulatory Expectations 

**Communicating requirements**
**Operators should use**
_**[http://](http://primis.rspa.dot.gov/gasimp)**__**[primis](http://primis.rspa.dot.gov/gasimp)**__**[.](http://primis.rspa.dot.gov/gasimp)**__**[rspa](http://primis.rspa.dot.gov/gasimp)**__**[.dot.](http://primis.rspa.dot.gov/gasimp)**__**[gov](http://primis.rspa.dot.gov/gasimp)**__**[/](http://primis.rspa.dot.gov/gasimp)**__**[gasimp](http://primis.rspa.dot.gov/gasimp)**_
**FAQ’s, inspection protocols, flow charts, key documents, timelines, etc.**
**Public Meetings – 05/2004 & today**
**Interacting with industry**
**Pilot inspections**
**Feedback on FAQ’s and protocols**
**Technical studies and research**

## Nationally Consistent Oversight

**HQ/Field partnership for program development**
**Standardized inspection protocols**
**Detailed field guidance for inspectors**
**Field testing and reset meetings**
**Aggressive training schedule for Federal and State inspectors**
**IT solutions:  team collaboration**

## Quality of Results

**National consistent approach**
**Federal-State, HQ-field team approach for balance (11/2003)**
**Feedback to operator after audit**
**Structured, but evolving enforcement**
**NOPV for serious issues**
**NOA to foster continuous improvement**

## What Have We Accomplished?

**Designed systematic approach to oversight**
**Designed and developed the Integrity Management Website and IMP Team collaboration application**
**Conducted initial public meeting focused on the rule in May 2004**
**Developed FAQ’s to address public and industry questions**

## What Have We Accomplished?

**Developed inspection protocols and guidance for inspectors**
**Pilot tested, adjusted, and publicly disseminated the inspection protocols**
**Developed training for our Federal-State team**

## Gas IM Inspection Focus 

**Organizational **_**commitment**_
**Quality of **_**management processes**_
_**Personnel qualifications**_
**Clearly **_**documented**_** implementation basis**
_**Continual improvement**_** of program**

**Notes:**
When OPS and the states go out to inspect operators we will be looking at the capabilities of people to do their assigned tasks, the quality of management processes to address rule requirements, and the alignment and commitment of organizations to meet the challenges.  We expect operators being inspected to be able to demonstrate these characteristics in their programs
We recognize that, as required by the rule, operator management processes will continue to improve over the years, but we will require that operators have a clearly documented basis for how they satisfy rule provisions before initial efforts to comply with individual provisions are undertaken
As OPS gains experience with the implementation of this rulemaking we will continue to update our oversight program to be well aligned with the lessons learned

## Gas IM Inspections 

**Initial IMP inspections will be focused on IM Programs**
**Ultimately IMP inspections may be integrated with other inspections**
**Inspection integration**
**Spectrum of performance data**
**More complete picture of operator performance**

**Notes:**
Initial inspections will focus exclusively on operator IM programs and how each Gas IM Rule rule requirement is met by an operator’s program.

As OPS and the States begin to feel more comfortable with the strength of operator programs, we plan to begin integrating IM inspections with other types of inspections – for instance, Standard Inspections may include a review of selected IM rule requirements.

This integration, which will also involve assembly of a spectrum of performance data, will allow us to develop a more complete picture of operator performance and the reasons for that performance

## Gas IM Learning Curve 

**Goal:  safer and more efficiently managed pipeline integrity**
**Experience collection and analysis**
**Lessons learned extracted/shared**
**Data collection - significant effort**
**Requires regular communication – public, industry, regulators, and vendor communities . . .**

**Notes:**
We expect that application of the rule will result in significant learning by both the industry and the regulatory communities in how better and more efficiently to manage gas pipeline integrity.

Experience with the Liquid IM Rule has shown that for OPS to act on knowledge gained, data developed from implementation of the rule will need to be captured, analyzed thoroughly, and lessons disseminated completely (examples include immediate repair criteria and implementation of Direct Assessment).

This type of data capture and analysis will represent an unprecedented effort, without which the resources expended will not be mined to the fullest extent possible for ways to improve management practices.

Such an effort has not yet been planned, but its implementation will require continued extensive cooperation between industry and regulatory communities.

## Gas Integrity Management Oversight Program Development

**Zach Barrett**
**Introduction**
**January 2005**

## Gas Integrity Management

- Public Web Site
- Resource/Communication Tool
- http://primis.rspa.dot.gov/gasimp/

**Notes:**
This is the URL for the Gas Integrity Management Public Web Site.  The Public Web Site is the Primary Communication Tool for the key elements of OPS Gas Integrity Management Program.  Our communication efforts are supplemented by Public Meetings such as this one and our May 2004 Public Meeting in Houston, Texas, on the requirements of the rule.  Also to get the word out regarding integrity management, we have made presentations for AGA, SGA, MEA, INGAA, and State Pipeline Safety Seminars.

## Slide 35

**Notes:**
If you use the URL in the previous slide, this is what the Gas Integrity Management Home Page Looks like.  The links for the key program elements are on the left side of the page.  These are the items I will be covering in this presentation.    

## Operator Resources

**Gas Integrity Management Web Site**
**Key Documents**
**Performance Reporting**
**Fact Sheet**
**Flowchart of Rule**
**Register and View Meetings**

**Notes:**
Key Documents – Contains a Corrected version of the Gas Integrity Management Rule through the last correction document April 6, 2004; A Notice regarding when the Baseline Assessment Begins; Advisory Bulletin for when data must be submitted to the National Pipeline Mapping System.  Along with other key rulemaking documents and Advisory Bulletins.

## Slide 37

**Notes:**
A recent addition to the Key Document site is the redline change document for the inspection protocols.

## Slide 38

**Notes:**
Feedback from industry indicated a tool was needed to track the changes to the Inspection Protocols.  This is the opening page for tacking changes to the inspection protocols.

## Slide 39

**Notes:**
This page of the change tracking document illustrates how changes are tracked.  
Red Text indicates additions and strike outs for deletions.
As changes to the inspection protocols are made we will update this document.

## Operator Resources

**Gas Integrity Management Web Site**
**Key Documents**
**Performance Reporting**
**Fact Sheet**
**Flowchart of Rule**
**Register and View Meetings**

**Notes:**
Performance Reporting is a new link for the Public Web Site.  The purpose of this link is to allow operators to submit your integrity management performance reports on-line via this site.    

## Slide 41

**Notes:**
You will need your Operator ID to utilize system.  If you need help in accessing the system the “Help” link will provide you the contact information you need to get an Operator ID. 

## Slide 42

**Notes:**
The Help section also provides access to advisory bulletins and the performance measures reporting instructions.  

## Performance Reporting

**OPS Has Issued an Advisory Bulletin for Reports Due February 28, 2005**
**Gas Transmission Operators were also Mailed a Copy**
**Reports are to Cover Period From January 1 to December 31, 2004**

**Notes:**
The next deadline for reporting integrity management performance measures is February 28, 2005.  The reporting cycle is to cover the period from January 1st to December 31st, 2004.  OPS recently issued an advisory bulletin to provide additional guidance and information regarding the integrity performance reports.   OPS also direct mailed the advisory bulletin to pipeline operators.
The four measures to be reported are found in Section 9.4 of B31.8S and are:
 Number of miles of pipeline inspected versus program requirements
 Number of Immediate Repairs completed as a result of the integrity management inspection program
 Number of Scheduled Repairs completed as a result of the integrity management inspection program
 Number of leaks, failures, and incidents (classified by cause)

Remember that if you are the operator of a transmission pipeline you should be making this report.  If you have not as yet identified any HCAs along the pipeline you should provide this information so we will not schedule you for an inspection.

## Operator Resources

**Gas Integrity Management Web Site**
**Key Documents**
**Performance Reporting**
**Fact Sheet**
**Flowchart of Rule**
**Register and View Meetings**

**Notes:**
The Fact Sheet Link – Provides a high-level summary of the rule highlighting the rules’ key features.  This is a good tool for communicating the basic rule requirements to those not deeply involved in the integrity management process. 

## Slide 45

**Notes:**
 Good Overview of Rule Key Requirements
The Fact Sheet Covers Objectives, Applicability, and Key Features
The Applicability section contains OPS current policy for defining a Transmission Pipeline.  OPS recognized early in the process that the current transmission line definition needed clarification to consistently designate a pipeline as either transmission or distribution across the nation.  The OPS initiated steps for amending the current transmission line definition to base it on operating pressure as opposed to attempting to define the pipeline function.  This effort was not supported by the AGA resulting in the current policy of states defining the undefined terms in the current transmission pipeline definition such as storage facility, distribution center, etc.  
The bottom line is when designating lines sections as transmission or distribution, please make sure your application of the transmission line definition is consistent with the state programs for the states you are operating in.

## Operator Resources

**Gas Integrity Management Web Site**
**Key Documents**
**Performance Reporting**
**Fact Sheet**
**Flowchart of Rule**
**Register and View Meetings**

**Notes:**
Rule Flowchart – The flowchart takes you through the rule requirements in a logical order for completing the actions required for compliance.  

## Slide 47

**Notes:**
The letters A, B, C, and D correspond to steps in previous or forthcoming steps that are applicable at that step in the process.  
We are working to include a mouse over function that will pop up for each box on the flowchart a Detailed Description; The rule Language; and Relevant FAQs.  However, this is still under development.

## Slide 48

**Notes:**
Just wanted to illustrate there are 6 steps to the flowchart and that you access the next level by clicking on Step 1, Step 2, etc.

## Operator Resources

**Gas Integrity Management Web Site**
**Key Documents**
**Performance Reporting**
**Fact Sheet**
**Flowchart of Rule**
**Register and View Meetings**

**Notes:**

The Meetings Link – Allows you to register for upcoming meetings and view presentations from previous meetings.  Most of you should be familiar with this site as you had to access it to register for this meeting. 

## Slide 50

**Notes:**
Probably the most important thing to remember about this site is that it is where we post the presentation material from each of our meetings.
Additionally, when we web cast a meeting such as we are doing for this one, the web cast can be viewed from this site for approximately 30 days. 

## Operator Resources

**Gas Integrity Management Web Site**
**OPS Communications (Links)**
**Notifications**
**Question or Comment**
** ****Frequently Asked Questions (FAQs)**
**Inspection Protocols**

**Notes:**

Links – Is the gateway to our Communication site connecting you to other Federal, State, and Industry Web Sites.  

## Slide 52

**Notes:**
This is the home page for our Communications Web Site.
Our Communications Page contains information on the many OPS outreach efforts.
Clicking on the “Links” from this page takes you to the list of other web sites we support.

## Slide 53

**Notes:**
Some Web Sites Listed are INGAA, AGA, MEA, SGA also there is a link to research organizations such as PRCI.  I encourage you to check out the link to the National Association of State Fire Marshals and then click on the link to “Firefighter Pipeline Safety”.  

## Slide 54

**Notes:**
If you follow the links you will find this home page a “Partnership for Excellence in Pipeline Safety” where you can get information regarding the efforts of this group to help pipeline operators locate “identified sites”.
The regulation requires you to contact public officials with safety or emergency response or planning responsibilities to locate “identified sites”.
The OPS has partnered with the National Association of State Fire Marshals and is providing them with funding to facilitate this effort.  

## Operator Resources

**Gas Integrity Management Web Site**
**OPS Communications (Links)**
**Notifications**
**Question or Comment**
** ****Frequently Asked Questions (FAQs)**
**Inspection Protocols**

**Notes:**
The Notifications link is also a new addition to the Public Website.
Its purpose is to allow operators to electronically submit notifications to OPS as required by the integrity management regulation.

## Notifications

**Notifications Are Required For:**
**Substantial Change to IM Program **
**Use of “Other” Assessment Technology**
**Can Not Meet Schedule for Evaluation and Remediation**

**Notes:**
The regulation requires notifications for:
 Substantial changes to the IM program
 Use of “Other” assessment technology
 Not able to meet the schedule for evaluation and remediation of identified pipeline anomalies

It is important to note that OPS does not desire to be notified for all changes.  Some that would be expected to result in notification include:
Mergers like that would be expected to affect the way the Integrity Management Program is executed.  Additionally, large sections of pipeline being purchased by an operator could significantly affect the overall risk information used as the basis for assessments and re-assessments.
If an operator has concluded through earlier assessment data and risk information that they are not susceptible to SCC, then, due to unforeseen circumstances, SCC is discovered to be a viable threat, notification would be expected.
If an assessment technology is planned for use that has not ever been vpreviously been used by an operator, notification would be expected.
Alternatively, abandoning a previously specified assessment methodology would likely result in the need to notify OPS or the State or local pipeline authority.

## Slide 57

**Notes:**
While you cannot currently send notifications to OPS via the link on this site, we encourage you to download the “Notification Template”.  Once you have completed the template you can email it to OPS at the provided address on the link.
We are currently working to allow electronic submission via this web link soon.  

## Operator Resources

**Gas Integrity Management Web Site**
**OPS Communications (Links)**
**Notifications**
**Question or Comment**
** ****Frequently Asked Questions (FAQs)**
**Inspection Protocols**

**Notes:**
This is one of the most important links on the Public Website.  This is where you should post any questions or comments regarding the integrity management rule or oversight program.  

## Slide 59

**Notes:**
All question posted here do not result in FAQs.
If you have a question you will get a quicker and better answer than contacting TSI, Regions, or Me.
Also provides a tracking method so we don’t loose your question in day to day activities.
Please do not use it to post questions regarding other code sections of the regulations, it is dedicated to gas pipeline integrity management.

## Operator Resources

**Gas Integrity Management Web Site**
**OPS Communications (Links)**
**Notifications**
**Question or Comment**
** ****Frequently Asked Questions (FAQs)**
**Inspection Protocols**

**Notes:**
FAQs – Provides a List Frequently Asked Questions and their answers regarding the application of the Gas Integrity Management Rule.  

## Slide 61

**Notes:**
The FAQ number is listed at the front of each question, the date we received the question is posted at the end.  Answers are posted below each question.  For questions where the answers are designated as “Under Development” this means the answer is in the review process prior to posting.  You can sort the FAQs by clicking on the sort function listed at the top of the FAQ list. 

## Slide 62

**Notes:**
The FAQs are meant to provide operators with insight regarding how an inspection team will view complex regulatory issues of the regulation.  You can disagree with any of the FAQs, however, you will need to be prepared to support your position.  The FAQs are not meant to be interpretations or extensions of the regulations.  The FAQs are to help inspectors be consistent in reviewing these complex regulatory issues.    

## Operator Resources

**Gas Integrity Management Web Site**
**OPS Communications (Links)**
**Notifications**
**Question or Comment**
** ****Frequently Asked Questions (FAQs)**
**Inspection Protocols**

**Notes:**

Inspection Protocols – Are the inspection protocols for Gas Integrity Management.

## Inspection Protocol Development

**What are Inspection Protocols?**
**The Inspection Protocols are a series of questions designed to guide pipeline safety inspectors in an **_**investigative approach**_** toward assessing pipeline operator compliance with the Gas Integrity Management Regulations**

**Notes:**
Inspection protocols are a series of questions designed to guide pipeline safety inspectors in an investigative approach toward assessing pipeline operator compliance with the Gas Integrity Management Regulations.  To be successful operators should review their management processes and implementation against these inspection protocols.

## Inspection Protocol Development

**OPS Developed an Integrity Management Inspection Approach Focusing on: **
**Operator **_**Processes**_** for Managing Integrity**
**Operator Process **_**Implementation**_
**This is the Basis of the Inspection Protocols**

**Notes:**
The OPS approach for integrity management is focused on Operator Processes for Managing Integrity and Operator Implementation of those Integrity Management Processes.  The Goal is to have processes that can be consistently implemented across the company with repeatable results.  This is the basis of the inspection protocols.

## Inspection Protocol Development

**Development Team - Established by OPS and the National Association of Pipeline Safety Representatives (NAPSR) November 6, 2003 **

**Notes:**
The Inspection Protocols were developed by a group of Senior State and Federal Inspectors.  The team began early development efforts shortly after the issuance of the Gas Integrity Management Final Rule.   The National Association of Pipeline Safety Representatives (NAPSR) selected the state program team members to participate on the protocol development team.  

## Inspection Protocol Development

**Eight (8) Senior Federal Inspectors all with Integrity Management Experience representing the five (5) OPS Regions**
**Five (5) Senior State Inspectors two (2) with Integrity Management Experience**
**Ohio, New York, Nevada, Alabama, and Louisiana**

**Notes:**
The Inspection Protocol Development Team consists of 8 Senior Federal Inspectors with integrity management experience from the hazardous liquid integrity management program and 5 Senior State Inspectors 2 with Integrity Management Experience.  
This group also acts as the review team for all FAQs.

## Inspection Protocol Development

**Goals – Inspection Protocol Development**
**Protocol questions must be tightly aligned with the gas integrity regulations and referenced industry standards**
**Clearly state compliance goal in each protocol question**

**Notes:**
The goals for the development of the inspection protocols include:
The protocol questions must be tightly aligned with the gas integrity management rule and the referenced industry standards
Each protocol question must clearly state the intended compliance goal.  It should be clear to operators what we are asking them to produce to evaluate their compliance with the rule. 

## Inspection Protocol Development

**Protocol Goals Con’t – **
**Do not repeat protocols**
**Support Primary Protocols with supplemental questions **
**Protocol order should facilitate efficient completion of inspection**

**Notes:**
The Protocol questions should not be repeated to avoid covering the same issues over and over again for related subjects.
Support “Primary Protocol” questions with supplemental questions to assure complete review and understanding of the issue at hand.
The Protocol order should facilitate efficient completion of the inspection.  The idea here is to cover items early in the inspection that relate to or are foundational to the items covered later in the inspection.    

## Inspection Protocol Development

**Draft Protocols Developed through Team Meetings and Posted on Gas Integrity Management Public Web Site - End of March 2004**

**Notes:**
Operators have had the ability to review and comment on the draft inspection protocols via the Public Web Site since the end of March 2004.

## Inspection Protocol Development

**Pilot Testing of Draft Protocols with volunteer pipeline operators July and August 2004 - Duke, El Paso, Pacific Gas & Electric and Baltimore Gas & Electric **

**Notes:**
The OPS requested volunteers for pilot testing of the draft inspection protocols.
It is important to note these were not inspections and the teams did not make judgment regarding the operator’s compliance
The Pilot Testing Provided the opportunity to validate protocols in live setting with pipeline operators and identify possible inspection issues
I would like to express my sincere thanks to Duke, El Paso, Pacific Gas and Electric and Baltimore Gas and Electric for hosting OPS and being very patient with us as we worked through the protocols.  Due to their participation the inspection protocols are a better product.
There were several issues brought forward during the pilot testing of the inspection protocols.  I will cover these issues and our current positions regarding them in the following slides.

## Pilot Issues

**Consequence Factors in Risk Assessment (Protocol C.3.c)**
**Risk includes consequence factors**
**Required by B31.8S**
**HCA Identification process is a simple consequence screen**
**Consequence factors needed to discriminate the relative risk between covered segments**

**Notes:**
One of the issues brought forward during the pilot testing was that “Consequence Factors” were not required by the rule to be included in operator risk assessments as investigated by (Protocol C.3.c).  The basis for this position was that OPS had already addressed the consequences in defining HCAs. 
 Risk is by definition the probability of an event times the consequences of an event.
HCA identification process is a very simple consequence screen.  OPS believes that consequence factors are necessary to discriminate the relative risk between covered segments. 
Section 192.917(c) requires a Risk Assessment be performed that follows Section 5 of B31.8S.   
Section 5 “Risk Assessment” in B31.8S includes consequences as a factor in Risk.  The standard specifically states “Risk consequences typically consider components such as the potential impact of the event on individuals, property, business impact, and environmental impact.  In fact Section 3.3 of B31.8S lists 9 consequence factors that should be considered in the risk analysis.  
OPS believes that consideration of consequences is necessary to discriminate the relative risk between the identified HCAs.  Risk results should be reviewed by knowledgeable personnel to validate the process and evaluate risk drivers for making integrity decisions.  

## Pilot Issues

**Pressure Reduction for Immediate Repair Conditions (FAQ-229)**
**Safety Margin is Required**
**0.72 x Predicted Failure Pressure**
**Account for defect growth until repair made (up to one year)**
**Operators may justify less safety margin Based on Corrosion Growth Rate**

**Notes:**
There was some discussion during the pilot testing regarding how to arrive at a safe reduced pressure until repairs can be made.  Certainly the rule allows operation at 80 percent of the pressure the defect has experienced.  
OPS also believes that applying a 0.72 class one safety factor to the calculated failure pressure from B31.G or Rstreng also provides an appropriate factor of safety.
Operators may also consider using the corrosion growth rate factors established in Figure 4 of B31.8S as outlined in FAQ 229. 

## Pilot Issues

**“****New” Threats (e.g., Near-Neutral SCC) (Protocol C.1)**
**Rule Requires ALL Threats be Identified**
**B31.8S, §2.2 Requires that “all threats shall be considered”**

**Notes:**
There was some expression that “Near Neutral SCC” was a new threat and did not need to be considered in the threat analysis.  
192.917(a) of the Integrity Management Rule and Section 2.2 of B31.8S requires all potential threats to pipeline integrity to be identified and evaluated including SCC.
Appendix A3.1 of B31.8S acknowledges that Near Neutral SCC exists and states it would require an inspection and mitigation plan.  
OPS expects operators to consider Near Neutral SCC in its threat analysis for covered pipeline segments.

## Pilot Issues

**“****Tolerance” for PICs (FAQ-174)**
**Following factors must be accounted for:**
**P/L Location Data Accuracy**
**Building/Identified Site Location Accuracy**
**GIS Accuracy**

**Notes:**
Operators did not anticipate we would be interested in mapping accuracies in evaluating the appropriate application of potential impact circles.  OPS is not concerned if your mapping provides sub-meter accuracy, however, if your mapping is less accurate we believe that the accuracy needs to be taken into account when drawing your potential impact circles.  A conservative approach is appropriate for identifying covered pipeline segments that should received additional protections offered by the integrity management rule.  See FAQ 174 for more guidance.

## Pilot Issues

**Multiple BAPs for Each Business Entity (FAQ-38)**
**Multiple BAPs are allowed, based on legal business entities**
**Operators may aggregate all businesses into a single BAP at their discretion**

**Notes:**
The OPS approach is to apply the rule to all of an operators pipeline assets no matter where they exist geographically in the united states.
During the pilot testing it was brought to our attention that for corporate entities there were some FERC concerns that prevented treating the various operating entities in this manner.  As a result OPS is allowing a separate baseline assessment plan for each operating entity.  See FAQ-38 for further guidance. 

## Pilot Issues

**5-Year Operating Pressure Benchmark for Stable M&C Defects (FAQ-231)**
**5-Year benchmark determined based on 5 years preceding HCA Identification**
**NOT a “rolling” 5-year**

**Notes:**
There was a concern expressed that the 5-year high pressure benchmark was being treated as a rolling 5-years.
OPS looked back at the docket regarding this issue and also initiated an independent study to provide insight into this issue.  As a result OPS is clarifying that the 5-year benchmark for Manufacturing and Construction Defects is the 5-years preceding the identification of an individual HCA.
While not a requirement by the rule, operators of pipelines that have never experienced a pressure test should give consideration to triggering an assessment at 80 percent of the benchmark pressure due to the possibility of operating near a pressure supporting quasi-ductile tearing.

## Pilot Issues

**Required Digs for ICDA (Protocol D.08.b.iii)**
**Changed Protocol to Clarify the 2 Minimum Required Digs**
**One in HCA at low point near beginning of ICDA Region**
**Second in HCA near the end of the ICDA Region (defined as the liquid hold-up point predicted by the ICDA Model)**

**Notes:**
It was identified there was some uncertainty regarding the location of the excavations required by the ICDA process.  As a result the protocol was modified to identify the two required excavation locations.

## Pilot Issues

**Detailed Processes Required for Integrity Management Activities in which Operators are Actively Engaged (FAQ 140)**
**Rule allows process development to begin with a “Framework”**
**Detailed Procedures Necessary for Successful Implementation**

**Notes:**
It was brought to our attention that some operators did not realize we were looking for more than a framework for activities the operator was currently actively engaged in.  The rule allows operators to begin with a framework, however, this should evolve to a detailed procedure prior to actively engaging in an integrity management activity.  
Detailed procedures are necessary for successful implementation, these procedures can be modified as an operator gains experience or the program evolves.  See FAQ 140 for additional guidance.

## Protocol Development

**Final Protocols **
**Made Publicly Available Oct. ‘04**
**Result of Extensive, Detailed Reviews**
**Incorporate Lessons Learned from Pilot Visits**
**Very Tightly Tied to Rule Requirements**

**Notes:**
The Inspection Protocols were adjusted as a result of lessons learned from the pilot testing and posted on the Public Web Site in October of 2004.

## Slide 81

**Notes:**
At this level you see all of the protocol sections from “Section A - Identify HCAs” to “Section P – New HCAs”.

## Slide 82

**Notes:**
This level of Protocol Area A lists the individual protocol questions.  Note the see details link. 

## Slide 83

**Notes:**
This level of detail provides you with not only the primary protocol question, but also the supplemental questions designed to provide a complete answer to the primary question.  
Also note the links to the applicable sections of the integrity management regulation and the indication of “P” for a process questions and an “I” for and implementation question. 

## Protocol Presentations

**Presented by members of the Gas IM Development Team**
**Footer in each slide **
**References to source of requirements**
**FAQs**

**Notes:**
The remainder of today’s presentations are designed to provide insight into each of the protocol questions that will be used during the integrity management inspections.
Members of the protocol development team will be the presenters.

## Tomorrow

**Federal and State Training**
**Inspection Format**
**Enforcement Process**

**Notes:**
Tomorrow I will cover these remaining key areas of our oversight program.

## Gas Integrity Management Rule Protocols

**Jeff Gilliam **
**49 CFR 192.903 and 905**
**High Consequence Area Identification**
**Protocol A**
**January 2005**

**Notes:**
[Greeting to the audience. Introduce yourself and tell where you work or fit into the Gas IMP process] 

I will be discussing the gas integrity management protocols for identification of High Consequence Areas – or what we frequently refer to as HCAs.
The requirements related to HCA Identification are primarily located in 3 Rule locations:
First, the definitions section which is Section 903 of the Gas Integrity Management Rule. Pertinent definitions related to HCA identification include covered segments, HCAs, identified sites, and Potential Impact Radius.
And second, Section 905 of the Integrity Management Rule which provides the  program requirements for HCA identification. 
In addition, Section 192.5 defining Class Location Units also applies to HCA identification but is unchanged by the Gas IM Rule.

## Key Elements  High Consequence Area Identification

- A.1 Program Requirements
- A.2 Potential Impact Radius (PIR)
- A.3 Identified Sites
- A.4 Identify HCAs/Class Location
- 	(Method 1)
- A.5 Identify HCAs/PIR (Method 2)
- A.6 Newly Identified HCAs

**Notes:**
The gas integrity management rule requires that each operator identify gas transmission pipeline segments that could adversely impact HCAs. These segments are referred to as “covered segments.” Operators were required to identify covered segments by December 17, 2004. In order to confirm rule compliance for an operators’ integrity management program regarding identification of covered segments, OPS has developed a set of 6 protocol questions under Protocol Area A. These protocols will be used during integrity management inspections that will begin later this year.

The protocols are label A.1 through A.6: 
A.1 Program Requirements
A.2 Potential Impact Radius
A.3 Identified Sites
A.4 Identification Using Class Locations (Method 1)
A.5 Identification Using Potential Impact Radius (Method 2)
A.6 Identification and Assessment of Newly Identified HCAs

I’ll now walk you through the details of these protocols and provide you with insight on OPS’s expectations on how these protocols may be satisfied.

## A.1 Program Requirements

- A.1 Program Requirements – Processes in Place to Identify HCAs Using Methods 1 and/or 2
- a.	Documented Processes
- b.	Document the Method Used
- c.	Document Covered Segment Locations
- d.	HCAs identified by 12/17/2004

| Reference: |  |
| --- | --- |
| §192.905(a) | FAQ-14, 21 |

**Notes:**
Protocol A.1 establishes criteria for review of HCA Identification program requirements. This protocol includes 4 lower tier sub-elements that drill down into additional program detail. The sub-elements include:
Requirements for operator's to have documented processes,
Requirements to document which HCA identification methods are used,
Requirements for mapping of identified HCAs, 
And the requirement that HCAs were to be identified by December 17, 2004

I’ll discuss each of the lower tier sub-elements in subsequent slides.  Now to move on to the details of the protocols for HCA Identification....

## A.1.a – Documentation of Methods

- 2 Methods for HCA Identification
- Operator May Use Either, or Both
- Documented Descriptions of How HCA Identification is Implemented
- Roles and Responsibilities
- Assurance that All of the Pipeline Has Been Evaluated for HCAs.

| Reference: |  |
| --- | --- |
| §192.905(a) | FAQ-22, 172, 192 |

**Notes:**
Protocol A.1.a - The Gas Integrity Management Rule, Section 903 Definitions, establishes 2 methods that may be used for HCA identification. An operator may use either method, or both, for identification of HCAs. The operator’s integrity management program must include documented processes on how to implement HCA identification using methods (1) and (2). It is expected that the integrity management program will describe how the HCA identification requirements are implemented, roles and responsibilities for program implementation, and provide assurance that all of the operator’s gas transmission pipeline system has been evaluated for HCA identification. IMP inspections will assure that the operator has evaluated their entire gas pipeline system for the identification of HCAs. 

Note that there is a third allowable option. An operator may designate an entire segment, or their entire pipeline, as covered segments without performing the analysis described in methods 1 or 2. 

## A.1.b – Methods Used

- Documentation Specifies:
- Which Methods (or Combination of Methods) Are Used
- Which Pipeline Segments Were Evaluated by Which Method
- OPS Has No Preference

| Reference: |  |
| --- | --- |
| §192.905(a) |  |

**Notes:**
Protocol A.1.b - This expectation was touched on under the previous protocol - HCA identification program requirements allow the operator to use Method 1, Method 2, or a combination of either method. Operator program documentation will be reviewed to assure it specifies which methods or combination of methods were used for HCA identification. Documentation must also specify which pipeline segments were evaluated by which method.  OPS has no preference regarding which method an operator should use.  

## A.1.c – System Maps & Segment Documentation

- Maps or Other Suitably Detailed Documentation
- Use of GIS or Similar Mapping Software
- Demonstrate System
- Overlay of HCAs With Pipeline System
- If Mapping Software is Not Used
- Describe and Demonstrate Process
- Inaccuracies

| Reference: |  |
| --- | --- |
| §192.905(a) | FAQ-174 |

**Notes:**
Protocol A.1.c - As part of the operator’s integrity management program it is expected that piping system maps or other suitably detailed documentation will be available that shows the pipeline segments that are located in high consequence areas. As a corollary, the operator’s documentation should also clearly demonstrate which pipeline segments are not in an HCA.  It is anticipated that most large operators will utilize GIS or similar mapping software for segment identification. The operator should plan to demonstrate its system and show graphically the overlay of HCAs with its pipeline system. Such systems should be able to output useful data about the intersecting segments, such as identification of segment HCA entry and exit points (for example, latitude/longitude coordinates, milepost designations, etc).  If an operator does not use GIS, the operator will still need to describe and/or demonstrate how it performed its HCA segment identification. The operator should be able to demonstrate that its process ensures that all segments that intersect HCAs have been identified and documented. 

Electronic documentation of segment identification is sufficient as long as the information is readily accessible and usable by personnel that implement the integrity management program, and it is adequate for inspection and verification by OPS.

The operator should also address the accuracy of the pipeline location data and distance measurements to structures.  Operators must consider the potential ramifications of significant inaccuracies and address them to assure reasonable accuracy.  

## A.1.d – Completion of HCA Identification

- Completion of HCA Identification by    December 17, 2004

| Reference: |  |
| --- | --- |
| §192.907, 192.911(a) |  |

**Notes:**
Protocol A.1.d - Inspection of an operator’s gas integrity management program will include a review of records demonstrating that the operator completed identification of pipeline segments in high consequence areas by December 17, 2004. 

## A.2 - Potential Impact Radius

- A.2 Potential Impact Radius - Meets Requirements of §192.903
- a. Verify the Correct Formula is Used:
- b. Axial Extension of PIC

| Reference: |  |
| --- | --- |
| §192.903 and 905(a) | FAQ-15, 16, 119 |

**Notes:**
Protocol A.2 addresses the rule requirements for determination of the Potential Impact Radius (PIR). Section 903 of the rule states that Potential Impact Circles are circles of a radius equal to the Potential Impact Radius. For natural gas, the operator’s gas integrity management program must explicitly require that the PIR be determined by the formula “PIR equals zero point 69 times the square root of the product of the pipeline’s maximum allowable operating pressure times the square of the nominal diameter.” “R” is the radius of a circular area in feet surrounding the point of failure, “p” is the maximum allowable operating pressure in the pipeline segment in pounds per square inch and “d” is the nominal diameter of the pipeline in inches. Refer to FAQs 16 and 119 which relate to calculation of the PIR. This protocol addresses the requirement that the resultant covered segment extend axially along the length of the pipeline from the outermost edge of the first potential impact circle to the outermost edge of the last contiguous potential impact circle. Verification of these requirements will take place during IMP inspections.

Operators may want to refer to FAQ-15 for definition of covered segments and clarification on the axial extension of potential impact circles. 

## A.2.a – Use of Potential Impact Radius Formula

- Use Most Limiting MAOP in the Segment
- Flammable Gases Other Than Natural Gas
- Use B31.8S to Derive the PIR Equation
- For Nonflammable Gases, the Entire Pipeline May be Treated as an HCA
- OPS Has Further Studies Underway

| Reference: | GRI-00/0189 CFER Report |
| --- | --- |
| §192.903 PIR, 192.905(a) | FAQ-16, 119, 144, 200, 208 |

**Notes:**
For Protocol A.2.a - For pipelines that have components with different pressure ratings, operators may choose to use the lowest MAOP in calculating the PIR for the entire segment. If the line is subsequently uprated, new PIRs would have to be calculated based on a higher MAOP. Refer to FAQ-200 for further clarification on this topic.

For flammable gases other than natural gas, section 3.2 of the Supplement provides guidance on development of formulas for determining Potential Impact Radius. The guidance in this standard is derived from the C-FER report GRI‐00/0189. Operators should refer to FAQ-208. 

Note that if nonflammable gases are transported by the operator, then the use of the specific PIR equations do not apply.  In this circumstance, an operator may apply for a waiver to use an alternative method for identification of pipeline segments affecting HCAs.  See FAQ-144. 

Note that OPS has contracted with an engineering firm to develop more specific guidelines on determining the PIR for gases other than natural gas (both flammable and non-flammable).  OPS will make these reports available to the public when they are finalized.

## A.2.b – Axial Extension of Potential Impact Radius

- HCA Includes the Area Extending Axially Along the Length of the Pipeline - Outermost Edge of 1st PIC to the Outermost Edge of the Last PIC.

| Reference: |  |
| --- | --- |
| §192.903 HCA | FAQ-162, 164 |

**Notes:**
Addressing Protocol A.2.b – The operator’s IMP will be reviewed to verify implementation of the concept of extending the PIR axially in each direction along the pipeline. Using the formula discussed earlier, the PIR is calculated which defines the Potential Impact Circle of concern. The HCA is then defined by the extension of the PIR axially in each direction along the pipeline from the center of the PIC to the edge of the PIC.  So, the entire HCA extends from the outermost edge of the first PIC to the outermost edge of the last Potential Impact Circles. This HCA segment would be referred to as a Covered Segment. FAQ-162 and 164 provide additional discussion on this requirement.

## A.3 - Identified Sites

- A.3 Identified Sites - Verify Program Includes Sources Listed in §905(b)
- a.	Identified Sites Must Include ...
-    i.	Outside Areas or Open Structures occupied by ≥ 20 People
-    ii.	Buildings Occupied by ≥ 20 People
-    iii.	Facilities With People of Limited Mobility

| Reference: | FAQ-17, 121, 143, 145, 146,  |
| --- | --- |
| §192.903 Identified Sites, 192.905(b) | 151, 162, 163, 176, 182, 211 |

**Notes:**
Protocols A.3 and A.3.a address the rule requirements for locating identified sites near an operator's pipeline. Identified sites may be thought of as an area where people tend to congregate. As such, identified sites require additional consideration as a high consequence area (HCA). Inclusion of identified sites is intended to pick up isolated population areas where people tend to gather which are not picked up through the Class location or PIC building count process. These areas could include nursing homes, schools, campgrounds, or an operator’s facilities that may be close enough to the pipeline to be at risk should there be a pipeline failure. Inspection will verify that the operator’s IMP includes the following criteria defining identified sites: (i) Outside areas or open structures occupied by 20 or more people on at least 50 days in any 12 month period (days need not be consecutive), (ii) Buildings occupied by 20 or more people on at least 5 days a week for 10 weeks in any 12 month period (days and weeks need not be consecutive), and (iii) Facilities occupied by persons who are confined, have impaired mobility, or would be difficult to evacuate. FAQ-17 provides additional clarification on this topic.

There are a number of FAQs that address detailed questions related to identified sites.

## A.3 - Identified Sites

- A.3.b. Use the Following Sources...
- Routine O&M Activities, AND
- Input from Public Officials
- In the Absence of Public Official Input, the Operator Must Use 1 of the Following:
- 1.	Visible Markings Such as Signs, or
- 2.	Facility Licensing or Registration Data, or
- 3.	Official Lists or Maps

| Reference: |  |
| --- | --- |
| §192.905(b) | FAQ-18, 120, 170, 195 |

**Notes:**
Protocol A.3.b addresses sources of information that an operator should rely on to find identified sites that are located within a potential impact circle. 
Operators must use information from routine operation and maintenance activities and 
Operators must use input from public officials with safety or emergency response or planning responsibilities. 

Note that If input from a public safety official cannot be obtained, then one of the other sources as identified in protocol A.3.b.ii must be used. Inspection of an operator’s IMP will verify that these criteria are included.

## A.3.b – Sources of information for Identified Sites

- Reasonable or Good Faith Effort
- Guidance in 7/17/2003 Advisory Bulletin

| Reference: |  |
| --- | --- |
| §192.905(b) | FAQ-18, 120, 170, 195 |

**Notes:**
OPS will expect operators to conduct a reasonable or good faith effort at identifying identified sites. Operators should refer to FAQ-18 and FAQ-170 for guidance on this expectation. The operator’s IMP should include documentation describing the responsibilities for finding identified sites and the methods used.  The documentation for identified sites should be available and support conclusions that a reasonable or good faith effort at identifying identified sites has been made. Guidance has been developed by OPS for clarifying the expectations for the identification of identified sites in the July 17, 2003 Advisory Bulletin, Identified Sites as Part of High Consequence Areas for Gas Integrity Management Program. This Advisory Bulletin is available from the OPS Gas Integrity Management web site.

## A.4 - Identification Using Class Locations (Method 1)

- A.4.a Class Locations (Method 1) –
- Class 3 and 4 Piping Locations
- Use of Existing Class Location Data and Identified Sites
- Operators of Pipelines Operating Below 30% SMYS - 192.935(d) Applies

| Reference: |  |
| --- | --- |
| §192.903 HCA | FAQ-16, 149 |

**Notes:**
Protocol A.4 addresses the rule requirements for the use of Method 1 to identify HCAs. Method 1 primarily relies on the use of existing Class Location unit data in conjunction with the identification of identified sites.  

The following are high consequence areas when using Method 1: 
Class 3 or 4 locations as defined by Section 192.5. Current Class Location data may be used.  If an operator has used Method 1, then IMP inspections will verify that the operator has in fact included all Class 3 and 4 Locations as covered segments. 

If an operator chooses to use method (2) on a pipeline segment, then potential impact circles would be drawn and it is possible that some class 3 or 4 locations might not be HCAs.  In this case, however, It should be noted that there are some specific requirements in section 935(d) that apply to class 3 and 4 pipelines that are not in HCAs.  This specific requirement will be addressed later.

## A.4 - Identification Using Class Locations (Method 1)

| Reference: |  |
| --- | --- |
| §192.5(b) |  |

| Class 1 | Offshore Area
Unit < 10 Buildings |
| --- | --- |
| Class 2 | > 10 but < 46 Buildings |
| Class 3 | ≥ 46 Buildings
Within 100 Yards of Building or Area Occupied by ≥ 20 Persons, 5 Days a Week for 10 Weeks |
| Class 4 | Prevalence of Buildings with > 4 Stories |

**Notes:**
Before continuing with discussion of the Method 1 HCA methodology, I would like to review the criteria defining Class Location Units:

Class 1 Locations are defined by Section 192.5(b)(1). Class 1 Locations include offshore areas or a sliding mile unit containing 10 or fewer buildings intended for human occupancy. 

Class 2 Locations are defined by Section 192.5(b)(2). Class 2 Locations include a sliding mile unit containing more than 10 but less than 46 buildings intended for human occupancy. The length of the unit is adjusted in accordance with 192.5(c). The length of the Class 2 Location extends 660 feet on each side of the cluster of buildings.

Class 3 Locations are defined by Section 192.5(b)(3). Class 3 Locations include a sliding mile unit containing 46 or more buildings intended for human occupancy or if the pipeline is within 100 yards of buildings or areas occupied by 20 or more persons, 5 days a week, for 10 weeks.  

Class 4 Locations are defined by Section 192(b)(4) and include locations where buildings with 4 or more stories above ground are prevalent. 

Now to return to the Method 1 discussion...

## A.4 - Identification Using Class Locations (Method 1)

- A.4 Using Class Locations (Method 1) ... Class 1 & 2 Locations With PIR > 660 Feet
- b. PIC Contains ≥ 20 Buildings
-     i. May Prorate for PIRs > 660 Feet
- Until 12/17/2006
- c. PIC Contains Identified Site

| Reference: |  |
| --- | --- |
| §192.903 HCA | FAQ-191 |

**Notes:**
Protocol A.4.b When an operator uses Method 1 for HCA segment identification, Class 1 and 2 Areas by definition are not a covered segment as long as the PIR is less than or equal to 660 feet.  However, if the Class 1 and 2 Locations have a PIR greater than 660 feet, then further analysis is required. For Class 1 and 2 locations, if the PIC contains 20 or more buildings intended for human occupancy or an identified site, then the segment is an HCA.  For those piping segments meeting these criteria, the operator is required to identify where the PIR encompasses 20 or more buildings intended for human occupancy OR an identified site. 

It is recognized that operators may not have building count data for large PIRs (i.e., those greater than 660 feet). The Rule allows use of more stringent criteria using building counts for area within radius of 660 feet. Prorating may be used under both Method 1 and Method 2 for identification of HCAs. Operators in the past have collected building count and density data in support of Class Location unit designation. However, the data collected only included areas within 660 feet of the pipeline. In recognition of this, operators may chose to use more stringent criteria using building count data for areas within the 660 foot radius. The option for prorating may only be used until December 17, 2006 – after this date operators are required to collect actual building count data when the Potential Impact Radius is greater than 660 feet. The advantage of using the prorated criterion is that existing building density information can be used. For a large Potential Impact Radius, this means that the building density for HCA applicability is reduced proportionally based on the ratio of the area of the PIC to that of the area of a PIC equal to 660 feet. During IMP inspections, the operator’s evaluation of Class 1 and 2 areas will be reviewed to ensure the program has appropriately identified HCAs.

## A.5.a - Identification Using Potential Impact Radius (Method 2)

- A.5 Identification Using PIR (Method 2)
- a.	PIC Contains ≥ 20 Buildings:
-    i.	For PIRs > 660 Feet, May Prorate Building Count
- 	1.	Until 12/17/06
- b. PIC Contains Identified Site

| Reference: |  |
| --- | --- |
| §192.903 HCA | FAQ-171 |

**Notes:**
Protocols A.5 and A.5.a establish the requirements for  the use of Method 2, as defined by Section 192.903, to identify pipeline segments that potentially impact HCAs. Unlike Method 1, Method 2 does not make use of Class Location designations in its criteria. This methodology relies on identification of potential impact circles (regardless of size) containing either 20 or more buildings intended for human occupancy or an Identified Site. Like with Method 1, prorating of building counts is allowed until December 17, 2006 for cases where the PIR is calculated to be greater than 660 feet.

Note that multiple adjacent HCAs may be merged to create a single segment. Where only short segments of non-HCA pipeline separate HCAs, operators may find it more efficient to combine the areas and will have the flexibility to do so.  However, OPS will evaluate compliance with the rule, including its requirement to complete assessment of 50% of covered mileage by December 17, 2007, considering only mileage determined to be in HCAs in accordance with the criteria in the rule. Clarification on this point is provided in FAQ-171.

## A.6 - Identification and Assessment of Newly Identified HCAs

- A.6 Identification and Assessment of Newly Identified HCAs
- New or Revised HCA Segments Due to Changing Pipeline Conditions
- Operators are Expected to Remain Cognizant of Changes
- Newly-Identified HCA Incorporated into the IMP Within 1 Year

| Reference: |  |
| --- | --- |
| §192.905(c) | FAQ-19, 20,  183 |

**Notes:**
Protocol A.6 establishes the requirements for identification of new or revised HCA segments that result from changing pipeline conditions or changes in habitat conditions in the vicinity of a pipeline.

Operators are expected to remain cognizant of changes along their pipeline. Over time, new HCAs may be identified as population distributions change, or new locations develop where people congregate. Operators must consider such changes to determine whether new HCAs have been created. IMP inspections will verify that newly-identified HCAs are incorporated into the integrity management program, including the baseline assessment plan, within one year of its identification. When new information indicates an area could meet HCA criteria, the pipeline segment must be evaluated by the operator using either Method 1 or 2.  OPS recognizes that under certain circumstances, as when a pipeline  pressure is derated, a HCA may be eliminated from further consideration. An operator’s IMP must include processes to obtain this new information through Class Location changes, routine operations and maintenance activities, and periodic reviews of the pipeline. FAQ-19 and FAQ-20 provide additional clarification on this topic.

Note that FAQ-183 clarifies that a change in HCA identification methodology does not in itself constitute a change requiring notification under §192.909(b). If the change results in a significant change in the amount of system mileage that is determined to be an HCA (for example, 25% change), a notification should be submitted.

## A.6.a - Identification and Assessment of Newly Identified HCAs

- A.6 Identification and Assessment of Newly Identified HCAs...
- a. Operator’s Program Includes Processes for New Information
- 1. 	Changes in Pipeline MAOP,
- 2. 	Pipeline Modifications,
- 3. 	Changes in the Commodity Transported in the Pipeline,
*	**	**	**- continued on next slide*

| Reference: |  |
| --- | --- |
| §192.905(c) | FAQ-19, 20, 117 |

**Notes:**
Protocol A.6.a is presented on this and the next few slides. This protocol includes 10 examples of changes that could create a new HCA that an operator’s IMP would consider.

NEXT SLIDE

## A.6.a - Identification and Assessment of Newly Identified HCAs

- 4.	Identification of New Construction,
- 5.	Change in the Use of Existing Buildings,
- 6.	Installation of New Pipeline,
- 7. 	 Change in Class Location,
- 8. 	 Pipeline Reroutes
- 9. 	 Corrections to Location Data,
- 10. Field Design Changes
*	**	**	**	**- continued on next slide*

| Reference: |  |
| --- | --- |
| §192.905(c) | FAQ-19, 20, 117 |

**Notes:**
This slide shows additional examples of the specific criteria included in Protocol A.6.a for situations that warrant actions for identification of new HCAs.

## A.6.a - Identification and Assessment of Newly Identified HCAs

- New and Changing HCAs Should be Identified by the Operator
- Operators are Responsible for Monitoring Conditions Near Their Pipelines
- Operator Should Capture Changes in its HCA Identification Maps or System
- Changing Conditions Should be Evaluated At Least Annually

| Reference: |  |
| --- | --- |
| §192.905(c) | FAQ-19, 20, 117 |

**Notes:**
To continue with further discussion of protocol A.6.a, Operators are expected to exercise reasonable diligence on an ongoing basis to ensure that new or revised HCAs are promptly identified and incorporated into their segment identification and baseline assessment processes. Routine activities such as right-of-way surveillance including aerial patrols, cathodic protection surveys, maintenance, etc., must be programmatically reviewed to identify new HCAs. The operator’s IMP must explain how information obtained from such routine activities is captured in its HCA identification maps or system.

The operator’s IMP process must include a means to promptly identify local changes that signal new or expanded HCAs, including changes in Class Location Units. IMP inspections will verify that the operator has processes in place to routinely identify changes. The operator’s process should include provisions for periodic review and updating of the segment boundary definitions and to ascertain if there are new HCAs or expansion of existing HCAs. While the rule does not specify a frequency for updating data used to identify HCAs, FAQs-20 and 117 address timeframes. Operators are expected to assure that their HCA definitions are current. OPS would expect that operators would evaluate conditions along their pipelines at least annually to determine if they have changed. Under this protocol, the operator’s management of change process will be reviewed to ensure that changes in pipeline operation and design are evaluated for potential impact to HCA identification. These changes should be incorporated in the baseline assessment plan consistent with the expectations of Protocol B.4.  FAQ-19 provides additional background on OPS’s expectations regarding new or changing HCAs.

## Protocol Area A Identification of HCAs

**Conclusion – **
**Thank you for your attention**

**Notes:**
This concludes my presentation on the protocols for HCA identification. Thank you for your attention. 

## Gas Integrity Management Rule Protocols

**Don Moore**
**Threat Identification;****Data Gathering and Integration; and ****Risk Assessment - Inspection Protocol C**
**49 CFR 192.917**
**January 2005**

**Notes:**
[Greeting to the audience. Introduce yourself and tell where you work or fit into the Gas IMP process] 

 I will be covering inspection protocol “C”, which addresses 3 closely related areas in operator integrity management programs. These 3 areas are
Threat Identification,
Data Gathering and Integration, and
Risk Assessment
The rule includes requirements in these areas primarily in section 917 of the Gas Integrity Management Rule. These requirements are further developed in ASME standard, particularly in sections 3, 4, and 5; and Appendix A.

## Protocol C Structure

- C.1 - Threat Identification
- C.2 - Data Collection & Integration
- C.3 - Risk Assessment
- C.4 - Risk Assessment Validation
- C.5 - Plastic Pipe

**Notes:**
Protocol C has been structured to include gas IM rule requirements for threat identification, data collection and integration, and risk assessment.

Protocol C includes five major questions covering the 3 required program areas:

C.1 - Threat Identification,
C.2 - Data Collection & Integration,
C.3 - Risk Assessment,
C.4 - Risk Assessment Validation, and
C.5 - Plastic Pipe

## C.1 – Threat Identification

- Consider and Evaluate:
- Nine Major Threat Categories
- Cyclic Fatigue
- “All Other Potential Threats”
- Interactive Threats
- Justify Elimination of Threats from Consideration

| Reference: |  |
| --- | --- |
| §192.917(a) |  |

**Notes:**
Protocol C.1 addresses threat identification.  Operators’ integrity management programs are to identify and evaluate “all potential threats” that can lead to failures of covered pipeline segments. Threats in 9 categories must be considered and evaluated by operators (for example, corrosion, third party damage, manufacturing or construction defects). Operators must also evaluate whether cyclic fatigue or other loading conditions could lead to a failure.  The term “other loading conditions” includes (but is not limited to) ground movement and suspension bridge conditions.  Operators must consider any other unique threats that apply to their covered segments. Integrity Management programs must consider and evaluate the susceptibility of segments to the interaction of more than one threat.  For example, manufacturing defects that might otherwise be stable, could fail in combination with corrosion or aggressive pressure cycling.  Another example is a dent caused by prior third party damage could fail in combination with corrosion metal loss.  No threat should be eliminated from consideration without adequate justification based on segment characteristics. Operators must justify eliminating threats from consideration. 

## C.1.a - Threat Categories

- _9 Categories_
- 1. Internal Corrosion
- 2. External Corrosion
- 3. Stress Corrosion Cracking
- 4. Manufacturing-Related
- 5. Welding/Fabrication-Related

| Reference: |  |
| --- | --- |
| §192.917(a) | FAQ-83 |

**Notes:**
Protocol C.1.a verifies the completeness and validity of the operator’s threat identification process in considering and evaluating threats in the 9 major categories. The threat categories include:

1.	Internal Corrosion
2. 	External Corrosion
3. 	Stress Corrosion Cracking (SCC)
4. 	Manufacturing Defects
5. 	Welding and Fabrication Defects

## C.1.a - Threat Categories

- _9 Categories (Cont’d)_
- 6. Equipment
- 7. Third Party/Mechanical Damage
- 8. Incorrect Operations
- 9. Weather-Related and Outside Force

| Reference: |  |
| --- | --- |
| §192.917(a) | FAQ-83 |

**Notes:**
6.  Equipment failures
7.  Third Party or other Mechanical Damage
8.  Incorrect Operations
9.  Weather-Related and Other Natural Forces Damage

Note that FAQ-83 addresses how operators are expected to consider external conditions such as earthquake fault lines or mining subsidence in their integrity management program. As part of the information and risk analysis required by section 917(b) and (c), an operator is expected to consider all information that can affect the likelihood and consequences of pipeline failure. Section 917(b) requires that an operator gather and evaluate, as a minimum, the data specified in Appendix A of the Supplement. Section A9 of that Appendix addresses weather related and outside force threats, and includes topography, soil conditions, and earthquake faults among the data to be integrated. Thus, if such external risk factors are significant, they must be considered by the operator.

## C.1.a – Guidance for Evaluation of Specific Threats

- Third Party Damage
- Manufacturing & Construction Defects (Including Seam Defects)

| Reference: |  |
| --- | --- |
| §192.917(a), ASME B31.8S §2.2 | FAQ-91, 219, 220, 221, 231 |

**Notes:**
OPS has developed policy positions on how operators should consider the third party damage and manufacturing/construction defect threat categories, as given in FAQ-91, 219, 220, 221, and 231.  I’ll address these positions in the following slides.

## C.1.a - Specific Threats: Third Party Damage

- Two Evaluations
- Segment Susceptible to *Immediate* Failure Due to TPD?
- Does Segment Have *Residual* Damage?

| Reference: |  |
| --- | --- |
| §192.917(a), ASME B31.8S §2.2 | FAQ-91 |

**Notes:**
Evaluation of Third Party Damage must consider both immediate failures from a third party hit and damage to the pipeline that does not result in an immediate failure, but could result in a failure in the future if other threats interact with the damaged pipe. The operator must consider the applicability of both types of failure for a complete evaluation of this threat.

## C.1.a - Specific Threats:Third Party Damage

- If Segment Susceptible to *Future* Damage
- Comprehensive Additional Damage Prevention Measures (192.935)
- Virtually All Pipelines Are Susceptible

| Reference: |  |
| --- | --- |
| §192.917(a), ASME B31.8S §2.2 | FAQ-91 |

**Notes:**
All pipeline segments, especially those in HCAs, are susceptible to the threat of future TPD.  The rule requires operators to implement preventive actions – this implementation will be reviewed under Protocol C.1.a.  Section 917(e)(1) of the rule requires that operators utilize their data integration process to determine the susceptibility of their covered pipeline segments to the threat of third-party damage.  Where a covered segment is found susceptible, that section further requires the operator to implement comprehensive additional preventive measures in accordance with section 935, and to monitor the effectiveness of the preventive measures.] 

FAQ-91 addresses how operators are to assess and control risk caused by third-parties. As part of a comprehensive risk analysis required by 192.917 (c), OPS expects operators to determine the risk associated with third party damage to pipeline segments that could affect an HCA. Operators must follow section 5 of ASME B31.8S, which contains guidance on risk assessments. OPS also understands that outside force damage prevention is challenging because it involves factors outside of the operator’s control. Nonetheless, there are a number of actions operators can take to reduce the likelihood of third party damage. If a pipeline segment is in an HCA, the operator must implement the comprehensive additional preventive measures in 192.935.

## C.1.a - Specific Threats :Third Party Damage

- Integrate Data to Determine if Segment Shows Evidence of *Residual TPD* Defects
- Excavate Locations With Dent indications from ILI _*or*_
- Conduct Integrity Assessment
- Repair Conditions per 192.933

| Reference: |  |
| --- | --- |
| §192.917(a), ASME B31.8S §2.2 | FAQ-91 |

**Notes:**
The more difficult circumstance involves residual third party damage resulting from previous events that did not cause immediate pipeline failure.
For each covered segment, the rule requires that data from ILI or ECDA must be integrated with data related to any encroachment or foreign line crossing to determine where evidence indicates the likelihood of residual third-party damage. If an operator uses an ILI tool, OPS expects the operator to explicitly require that the ILI contractor call out all observed indications of denting or mechanical damage when grading the ILI data. An operator must then either excavate and examine those locations OR conduct an assessment using methods capable of detecting third party damage.  An operator must have procedures, as part of its integrity management program, describing this data integration process, the basis for decisions, and actions to be taken based on the results.

Damage identified and characterized by any of these assessment methods must be repaired in accordance with Section 933.

## C.1.a - Specific Threats:Manufacturing/Construction Defects

- Pipe Tested to Subpart J
- Stable if:
- Pressure Tested per Subpart J, *AND*
- Not Subject to Interacting Threats
- Considered Susceptible if Failure Has Been Experienced

| Reference: |  |
| --- | --- |
| §192.917(a), ASME B31.8S §2.2 | FAQ-219, 220, 221, 231 |

**Notes:**
The rule also has specific requirements that address manufacturing and construction defects, which include seam defects such as low frequency ERW pipe.  
Seam defects or other manufacturing and construction defects are considered to be stable if: 
The pipeline has been pressure tested in accordance with Subpart J; AND
The pipeline is not subject to other interacting threats that could cause defect growth or failure.
Since manufacturing and construction defects that meet these conditions are considered to be stable, any failure attributed to a M&C defect is indicative of other factors affecting the stability of those defects. Therefore, pipelines that have experienced failures due to seam defects or other manufacturing and construction defects since its last Subpart J pressure test are considered to be susceptible to these threats. 

OPS inspections will check to see if operators performed a threat identification that adequately considered other threats that could interact with M&C defects.

 FAQ-219. Are integrity assessments required for manufacturing and construction defects, including seam defects, if the pipeline has been pressure tested in accordance with Subpart J? [09/16/2004] 
Answer: OPS considers a successful Subpart J pressure test to be sufficient to reveal any manufacturing and construction defects that could jeopardize pipeline integrity at operating pressures less than or equal to MAOP, as of the date of the pressure test. Any manufacturing and construction defects that survive the Subpart J pressure test are considered to be stable and not subject to failure, unless other threats adversely affect the stability of the residual manufacturing and construction defects. An operator is expected to conduct its threat identification analysis in sufficient detail to identify if other interacting threats could adversely affect the stability of residual manufacturing and construction defects, as required by ASME B31.8S, Section 2.2, and establish its assessment plans accordingly.  Assessments addressing the threat of manufacturing and construction defects are required for pipe that has never been tested to Subpart J requirements if operating conditions on the line change.

## C.1.a - Specific Threats: Manufacturing/Construction Defects

- Pipe NOT Tested to Subpart J
- Defects “Stable” if:
- Operating Pressure  Benchmark (5-Year Max Preceding HCA Identification) *AND*
- MAOP Not Increased *AND*
- Cyclic Fatigue Stresses Not Increased *AND*
- Not Susceptible to Interacting Threats

| Reference: |  |
| --- | --- |
| §192.917(a), ASME B31.8S §2.2 | FAQ-219, 220, 231 |

**Notes:**
Pipeline segments with manufacturing and construction defects that have never been pressure tested in accordance with Subpart J, are considered to be stable if:
The segment continues to be operated at pressures at or below the maximum actual operating pressure experienced during the five years immediately preceding HCA identification AND
MAOP is not increased; AND
Stresses leading to cyclic fatigue do not increase; AND
The pipeline is not subject to other interacting threats that could cause defect growth or failure.
For pipeline segments that have never been pressure tested in accordance with Subpart J, and that do not meet all of these criteria, the segment is considered to be susceptible to threats from manufacturing and construction defects.
FAQ 220 addresses consideration of Manufacturing and Construction defects if the pipeline has never been Subpart J tested.

## C.1.b – Threat Identification

- Applies to Performance Based Programs Only

| Reference: |  |
| --- | --- |
| §192.917(a), ASME B31.8S §2.2 |  |

**Notes:**
Subquestion C.1.b applies only if an operator pursues a performance-based program, but does NOT apply to operators implementing the prescriptive approach. OPS anticipates that most operators will pursue a prescriptive-based program in the near-term. Therefore, I am not going to discuss this protocol in detail.

## C.2.a – Data Gathering & Integration

- Gather / Evaluate Data from *Entire Pipeline* Relevant to Covered Segments
- Comprehensive Data *Plan*

| Reference: |  |
| --- | --- |
| §192.917(b) | FAQ-222 |

**Notes:**
Protocol C.2 addresses rule requirements for the gathering and integration of diverse data from a variety of sources that is needed to ensure that threat and risk assessments are based on the best available information. The rule requires that data used to support threat identification and risk analysis covers the entire pipeline. Data from non-covered segments must be considered if it is relevant to understanding the threats and risks of covered segments. The rule requires that the operator have a comprehensive plan for collecting, reviewing, integrating, and analyzing the data.  OPS will inspect operator plans for conducting this data integration in some detail. 

Operators should refer to FAQ-222 which addresses this requirement.

## C.2.b & C.2.c - Required Data

- Gather and Evaluate Data for Entire Pipeline
- Must Follow B31.8S, Section 4
- Min. Data Set (B31.8S, App. A)
- Data Sources (B31.8S, Table 2)
- Additional Data Required for *Performance-Based* Approach

| Reference: |  |
| --- | --- |
| §192.917(b), ASME B31.8S §4.3 | FAQ-81, 83 |

**Notes:**
Protocols C.2.b and C.2.c address the data required by the rule and standard.  Note that the rule does not require that additional data be generated but that all existing data be collected and evaluated.

The minimum data set is given in Appendix A of the Supplement and summarized in Table 1. Required data elements include
Pipe attribute data (e.g., thickness, diameter, seam, materials)
Pipe construction data (e.g., coating, CP, pressure test, depth of cover)
Operational data (e.g., flow rate, operating pressures, leak history, encroachments, coating condition, CP performance)
Inspection data (e.g., pressure tests, ILI, geometry tool runs, CIS, coating condition inspections)
Required data sources that are to be consulted are given in Table 2. Examples include as-built drawings, O&M procedures, emergency response plans, inspection and test records, incident reports, material certifications, original construction records.  Note that the performance based requirements contained in the Supplement require additional data elements in addition to the minimum data listed in Appendix A. Certain required data are also specified in the rule itself, as listed on the next slide,,,

## C.2.b - Required Data Sources

- Minimum Data Per B31.8S, App A
- Past Incident History
- Corrosion Control Records
- Continuing Surveillance Records
- Patrolling Records
- Maintenance History
- Internal Inspection Records
- All Other Conditions Specific to Each Pipeline

| Reference: |  |
| --- | --- |
| §192.917(b), ASME B31.8S §4.3 | FAQ-81, 83 |

**Notes:**
Required data includes:
Past Incident History
Corrosion Control Records
Continuing Surveillance Records
Patrolling Records
Maintenance History
Internal Inspection Records
All Other Conditions Specific to Each Pipeline

OPS inspectors will check that operators collected, integrated and analyzed all of the data elements listed in the rule and in the Supplement.

## C.2.d - Treatment of Missing or Suspect Data

- No exclusion of a Threat Because of Lack of Data
- Conservative Assumptions
- Impact of Uncertain Data
- If Significant, Obtain Additional Data

| Reference: |  |
| --- | --- |
| §192.917(a), ASME B31.8S §4 |  |

**Notes:**
C.2.d verifies the operator process for checking the data for accuracy. It also verifies that the treatment of suspect or missing data is appropriate and consistent with the rule and standard. These requirements include:
1 - Each threat covered by the missing or suspect data is assumed to apply to the segment being evaluated. The unavailability of identified data elements is not a justification for exclusion of a threat. 
2 - Conservative assumptions are used in the risk assessment for that threat (or the segment is given higher risk priority.)
3 - Records are maintained that identify how unsubstantiated data are used, so that the impact on the variability and accuracy of assessment results can be considered. AND
4 - Depending on the importance of the data, additional inspection actions or field data collection efforts may be required. 

## C.2.e - New Information Incorporated 

- Measures to Incorporate New Information
- Timely
- Effective
- Protocol K

| Reference: |  |
| --- | --- |
| §192.911(k), ASME B31.8S §11 |  |

**Notes:**
The rule requires the operator’s program includes measures to ensure that new information is incorporated in the threat and risk evaluation in a timely and effective manner.  Inspection using protocol C.2.e will review implementation of operator’s programs to ensure new information is adequately considered.  This will be discussed in more detail when we cover Protocol K.

## C.2.f - Data Integration 

- Data Elements Analyzed
- Common Spatial Reference System
- Integration of ILI or ECDA Results

| Reference: |  |
| --- | --- |
| §192.917(e)(1), ASME B31.8S §4.5 |  |

**Notes:**
The rule and standard call for integration and analysis of the data that is gathered. The integrated data can provide improved confidence in the relevance of specific threats and can support an improved analysis of overall risk.
Inspectors will verify that operators understand the difference between data INTEGRATION and data COLLECTION.  The most important aspect of data integration is the ANALYSIS of aggregated data in order to find integrity threats and risks that would not otherwise be observed from independently reviewing individual data elements. The operator's process should address how it does both data collection and data integration, which is the analysis of aggregated data.  Inspectors will also review that the operator includes:
1 - A common spatial reference system that allows association of data elements with accurate locations on the pipeline; AND
2 – The integration of ILI or ECDA results with data on encroachments or foreign line crossings to find locations of potential third party damage. 

## C.3 - Risk Assessment

- Follow B31.8S, Section 5
- Consider All Identified Threats
- C.3.a - Use Risk Assessment To:
- Prioritize Baseline Assessments
- Prioritize Reassessments
- Evaluate Additional Preventive and Mitigative Measures

| Reference: |  |
| --- | --- |
| §192.917(c), ASME B31.8S §5 | FAQ-28, 142 |

**Notes:**
Inspection using Protocol C.3 will examine an operator’s program to confirm an operator has conducted a risk assessment that follows the elements of ASME B31.8S, section 5.  All identified threats must be considered for each covered segment. Risk assessment must integrate the results of the threat evaluation and data integration to produce risk results that support decisions in the operator’s IM program, specifically:
A risk-based schedule of baseline integrity assessments
Establish re-assessment intervals according to segment risks
Decisions on preventive and mitigative measures in order to achieve additional risk reduction beyond integrity assessment and repair activities

FAQ-28 addresses what an operator must consider in prioritizing pipe segments for assessment and re-assessment. The risk posed by each pipeline segment covered by this rule must be considered in scheduling baseline assessments and periodic re-assessments. Risks must be evaluated using a risk assessment that meets ASME/ANSI B31.8S, Section 5, as required by 192.917(c). Section 5.10 of the standard specifically addresses use of risk assessment for prioritizing pipe segments for assessment.

FAQ-142 addresses when should risk analysis be performed. Many of the elements of an IM program required by the rule depend on the results of data integration and risk analysis. For example, the baseline assessment plan must include a schedule based, in part, on risk factors. The operator's initial risk analysis should be performed early in IM program implementation, before the baseline assessment plan is finalized.

## C.3.b - Risk Assessment Approaches

- 4 Options
- Subject Matter Experts (SMEs)
- Relative Risk Ranking Models
- Scenario-Based Models
- Probabilistic Models

| Reference: |  |
| --- | --- |
| ASME B31.8S §5.5 | FAQ-166, 168 |

**Notes:**
The standard presents four options for operator risk assessment approaches. The 4 options are:
Subject Matter Experts (SMEs) – This is a more subjective assessment using persons very knowledgeable of the pipeline and applicable threats.
Relative Risk Ranking Models – This is a qualitative database type model that assigns scores for each risk factor, relative weights for the importance of each risk factor, and calculates a “score” for the relative risk of each line segment.
Scenario-Based Models – This is a quantitative event-based analysis that utilizes techniques such as event trees, decision trees and fault trees.
Probabilistic Models – This is a highly sophisticated analytical approach that is data intensive, and calculates absolute likelihood or probabilities of events along with quantitative estimates of consequences to derive an absolute value of the risk associated with each line segment.
OPS will verify that operators use one of these approaches.

Operators should refer to FAQ-166 for clarification of qualification standards that apply to Subject Matter Experts when that approach is used for risk assessment.
FAQ-168 provides additional clarification on OPS expectations regarding the use of the four risk analysis methods.. The four risk assessment approaches described in ASME/ANSI B31.8S are all valid. The approach that is appropriate for an individual operator will often be driven by circumstances specific to that operator, including the size/complexity of their system and the expertise/experience of their personnel. Some operators, particularly those with few miles of transmission pipeline, may conclude that the SME approach is sufficient.

## C.3.c - Risk Assessment Required Characteristics 

- All Approaches Require
- Identification of Relevant Threats
- Likelihood
- Consequences
- Likelihood and Consequences Combined to Calculate Overall Risk

| Reference: |  |
| --- | --- |
| ASME B31.8S §3 and 5 | FAQ-125 |

**Notes:**
Protocol C.3.c will examine an operator’s program to ensure the risk assessment accounts for factors that could affect the likelihood of a release and for factors that could affect the consequences of potential releases. Regardless of the method chosen for risk assessment, the approach must:
 Include all relevant threats to pipeline integrity for each segment
 Characterize the likelihood of segment failure due to each threat
 Characterize the nature and severity of consequences of segment failure
 Characterize the overall level of risk

## C.3.c – Risk Assessment Required Characteristics

- Logical Structure
- Incorporates Failure Experience
- Integrates Inspection Results
- Appropriate Weighting of Risk Factors
- Pipeline Subdivisions Sufficient to Represent Risk Appropriately

| Reference: |  |
| --- | --- |
| ASME B31.8S §3 and 5
 | FAQ-125 |

**Notes:**
Section 5B of the Supplement describes the necessary characteristics of the risk assessment approach.  

1 - The risk assessment approach contains a defined logic and is structured to provide a complete, accurate, and objective analysis of risk;
2 - The risk assessment considers the frequency and consequences of past events, using company and industry data;
3 - The risk assessment approach integrates the results of pipeline inspections in the development of risk estimates ;
4 - The risk assessment process includes a structured set of weighting factors to indicate the relative level of influence of each risk assessment component; and
5 - The risk assessment process incorporates sufficient resolution of pipeline segment size to analyze data as it exists along the pipeline.

FAQ-125 provides guidance on risk ranking by piggable sections.
Answer: The rule requires that an operator must use risk assessment to prioritize covered segments for baseline assessments and reassessments (192.917(c)). OPS expects to see a ranking by covered segment. Operators will need to manage their assessments, and some aggregate indication of risk, by piggable section, could be useful in that regard. Such aggregation can mask important information, however. For example, a number of low-risk covered segments in a piggable section could result in that section being determined to be of moderate risk even though it contains the highest risk covered segment in an operator's program. Operators need to know the relative risk of individual covered segments so that they can appropriately plan their assessment activities.

## C.3.d – Risk Assessment Revisions

- Risk Updated to Account for
- Integrity Assessments
- Preventive and Mitigative Measures
- Inaccuracies Identified by Maintenance or Other Activities
- Integrate w/ Day-to-Day Processes
- Continuous Improvement of Risk Model

| Reference: |  |
| --- | --- |
| §192.917(c), ASME B31.8S §5
 |  |

**Notes:**
The standard includes requirements to ensure that the operator’s process provides for updating the risk assessment if new information is obtained or conditions change on the pipeline segments.   
OPS will verify that the risk assessment plan requires that the risk for each segment be updated to reflect:
 The results from an integrity assessment 
 To account for completed prevention and mitigation actions;
 if pipeline maintenance or other activities identify inaccuracies in the characterization of the risk for any segments; 

The operator integrates the risk assessment process into field reporting, engineering, facility mapping, and other processes as necessary to ensure regular updates;
The operator uses a feedback mechanism to ensure that the risk model is subject to continuous validation and improvement.

## C.4 – Risk Assessment Validation

- Validation Process to Ensure Risk Assessment Results Are:
- Logical
- Consistent

| Reference: |  |
| --- | --- |
| §192.917(c), ASME B31.8S §5.12 |  |

**Notes:**
The rule and standard require that the operator’s IM program includes a documented validation process for the risk assessment results. The purpose of this process is to provide a “sanity check” on the risk assessment results. Risk assessment validation is a characteristic of effective risk assessment programs for both prescriptive or performance-based integrity management programs. The operator's risk assessment process should be documented in their IMP and should include elements for validation of results, updates to risk assessments to reflect new information, additional validation through inspections and evaluations, and feedback mechanisms for continuous validation and improvement.

The operator's IMP should specify processes used to validate the results of their risk assessments. Checks should include measures to ensure the assessment results are both logical and consistent with their knowledge of pipeline characteristics and industry experience. The operator may employ various means to achieve validation. Elements of validation may include:
Team review of results, 
SME reviews, OR
Review of lessons learned from industry 
OPS will inspect the methods and results of each operator’s process for validating its risk assessment.

## C.5 - Plastic Pipelines 

- Assess Threats per B31.8S, Sections 4 & 5
- Consider Threats Unique to the Integrity of Plastic Pipe

| Reference: |  |
| --- | --- |
| §192.917(d) |  |

**Notes:**
If the operator has plastic transmission lines, Protocol C.5 will verify that the information in sections 4 and 5 of the Supplement and any unique threats to the integrity of plastic pipe have been considered when assessing the threats to each covered segment of plastic pipeline. 

## Protocol Area C - Threat Identification; Data Gathering and Integration; and Risk Assessment Protocols

**Conclusion – **
**Thank you for your attention**

**Notes:**
This concludes my presentation on the protocols for risk assessment. Thank you for your attention. 

## Gas Integrity Management Rule Protocols

**Allan Beshore**
**49 CFR 192.919 and 921**
**Baseline Assessment Plan**
**Protocol B**
**January 2005**

**Notes:**
[Greeting to the audience. Introduce yourself and tell where you work or fit into the Gas IMP process]

  I will be discussing the gas integrity management protocols for inspecting the Baseline Assessment Plan.
This presentation addresses Protocol B and sections 919 and 921 of the rule.

## Key Elements Baseline Assessment Plan

- Identify Potential Threats
- Specify Assessment Methods
- Risk-Prioritized Schedule
- DA Plans (If Applicable)
- Procedure to Minimize Environmental and Safety Risks

**Notes:**
The gas integrity management rule requires that each operator develop a Baseline Assessment Plan for its covered pipeline segments.  The purpose of this requirement is two-fold:  First, to identify and repair anomalies in the highest risk segments within a predefined timeframe using assessments tools that are consistent with the threats to the pipeline; and  Second, to establish a baseline of knowledge about the pipeline system for segments that could potentially affect HCAs.

To accomplish this objective, the rule requires that the operator’s Baseline Assessment Plan contain certain key elements: 1) threat identification 2) specification of an appropriate assessment method for those threats 3) a risk-prioritized schedule for completing the baseline assessments 4) a direct assessment plan (if the operator is using direct assessment); and 5) procedures to minimize environmental and safety risks while conducting assessments.

## Key Elements Baseline Assessment Plan

- Operators With Multiple Operating Entities May Either:
- Have Separate Baseline Assessment Plans for Each Entity, OR
- Combine All Assets into a Single Baseline Assessment Plan

**Notes:**
An operator may have more than one Baseline Assessment Plan if it is appropriate for their system. This allowance is discussed in FAQ-38 which states that an operator with multiple operating entities may choose to have separate plans for each operating company or legal entity; OR a single plan covering all operating companies. Each Baseline Assessment Plan must meet the rule’s requirements and address all covered pipeline segments for the pipelines covered by the Plan.

## Protocols for  Baseline Assessment Plans 

- B.1	Assessment Methods
- B.2	Prioritized Schedule
- B.3	Use of Prior Assessments
- B.4	Newly Identified HCAs / Newly 	   Installed Pipe
- B.5	Consideration of Environmental    	   and Safety Risks, and
- B.6	Changes

**Notes:**
In order to confirm rule compliance of operators’ integrity management program for Baseline Assessment Plans, OPS has developed a set of 6 protocol questions under Protocol Area B. 

B.1 Assessment Methods 
B.2 Prioritized Schedule 
B.3 Use of Prior Assessments 
B.4 Newly Identified HCAs / Newly Installed Pipe
B.5 Consideration of Environmental and Safety Risks, and 
B.6 Changes to the Baseline Assessment Plan

I’ll now go into more detail on these protocols and provide you with OPS’s expectations on how these protocols may be satisfied by an operator’s integrity management program.

## B.1 – Assessment Methods

- Baseline Assessment Plan Includes All Covered Segments
- Assessment Method(s) for Each Covered Segment
- May Need More Than One
- Assessment Method that is Best Suited for the Specified Threats

| Reference: |  |
| --- | --- |
| §192.919(b), 921(a), (c), (h) | FAQ-217 |

**Notes:**
OPS will review the operator’s documentation to verify that a Baseline Assessment Plan has been developed and the Baseline Assessment Plan addresses all covered segments.  Furthermore, OPS will be looking to see that an assessment method or method(s) have been specified for each covered segment.  The rule specifies that an assessment method that is best suited for the specified threats be selected for the baseline assessment.  One or more the following assessment tools must be used to complete the baseline assessment.  
In-Line inspection tools
Pressure testing in accordance with Subpart J; or
Direct Assessment.
An assessment that does not use one of these 3 methods is considered “other technology”.
To address each applicable threat on a covered segment more than 1 assessment may be required.  For example, if an operator identifies both external corrosion and seam defects as applicable threats, more than 1 assessment method may be needed to complete the baseline assessment.  Also, the operator must have a documented explanation of why the method (or methods) selected are the best to address the threats.  When determining the appropriate assessment method for a specific threat, an operator must use the guidance in Section 6 of the supplement which discusses the usefulness of the various assessment methods for identifying anomalies caused by the specific threats. 

## Actual Pipeline Defects (e.g., Corrosion)
Threats From Future Event
Addressed Using P&M Measures
Assess for Damage from Previous Events
As Needed Based on Threat Identification & Data Integration

- Threats From Future Event
- Addressed Using P&M Measures
- Assess for Damage from Previous Events
- As Needed Based on Threat Identification & Data Integration

**B.1 – Assessment Methods**

| Reference: |  |
| --- | --- |
| §192.919(b), 921(a), (c), (h) | FAQ-217 |

**Notes:**
In reality, not every threat can be assessed by means of examining the current condition of the pipeline.  Threats can generally be grouped into the following 2 categories.
Threats that, if present, manifest themselves as defects in the pipeline itself. It is these types of defects that can be assessed using pipeline integrity assessment techniques such as inline inspection, hydrostatic pressure test, or direct assessment. Examples of such threats include internal corrosion, external corrosion, stress corrosion cracking, residual dents from third party damage, and residual pipe deformation from past ground movement.
Threats that represent possible future events and therefore are not detectable by the various assessment methods.  Examples of such threats include earthquake, soil movement, operator error, and future third party damage events.  These are either time independent threats that will result in prompt failures or threats that might produce future residual defects that can then be detected by a pipeline assessment.  
Although not explicitly stated in the rule, it is obvious that threats due to possible future events that have not yet resulted in detectable changes in the pipe cannot be addressed by means of an assessment of the pipeline itself.  Instead, these threats must be addressed by preventive and mitigative actions.  In this case, OPS would not expect operators to conduct assessments for these threats. However, data integration and risk assessment could reveal credible evidence that such an event has occurred in the past and that there is a reasonable likelihood that pipeline damage has been caused by the past events, resulting in residual pipeline defects.  In this case, OPS does expect operators to include assessments for these threats.  

## Operators Must Assess for TPD 
If a Threat from Residual TPD has Been Identified
Treatment of TPD Threats is Also Addressed in Protocol C. 

- If a Threat from Residual TPD has Been Identified
- Treatment of TPD Threats is Also Addressed in Protocol C.

**B.1 – Assessment Methods**

| Reference: |  |
| --- | --- |
| §192.919(b), 921(a), (c), (h) | FAQ-217 |

**Notes:**
The rule has specific requirements addressing actions an operator must take regarding potential defects from past third party damage events.
To determine if there is a need to assess for third party damage, the operator must evaluate whether evidence exists that a covered pipeline segment contains one or more residual third party damage defects.  In seeking evidence of residual third party damage defects, the operator must perform a thorough analysis and data integration including consideration of recent available assessment results.  If an operator uses an inline inspection tool, the operator needs to explicitly require the inline inspection contractor to call out all observed indications of denting when grading the inline inspection . 
If the operator identifies a location with evidence of residual defects from third party damage (for example using high resolution MFL data that indicates the possibility of a dent, or through data integration of ECDA results with right-of-way data), then the operator must perform an assessment using (a) an inline inspection tool capable of characterizing dents, or (b) pressure testing, or (c) excavation and direct physical examination. 
This situation is also addressed in the session on data integration.

## B.1 – Assessment Methods

- DA is Acceptable Method for EC, IC, and SCC Threats Only
- ECDA - Be Vigilant to Identify / Investigate Potential TPD
- DA Plans Cover Data Integration
- DA Plan Specifics Addressed in Protocol D

| Reference: |  |
| --- | --- |
| §192.919(b), 921(a), (c), (h) | FAQ-217 |

**Notes:**
The rule specifies that Direct Assessment is one of the assessment methods an operator may use.  However, direct assessment is an acceptable method for external corrosion, internal corrosion, and stress corrosion cracking threats only.  
When conducting external corrosion direct assessment, operators must be vigilant in identifying and investigating residual third party damage . 
Direct assessment plans must address operator procedures to integrate other data.
More specifics on direct assessment and the treatment of third party damage while conducting the external corrosion direct assessment process is addressed under protocol D. 

## B.1.a - Assessment Method: Inline Inspection

- Internal Inspection Tools Selection Per ASME B31.8S, Section 6.2
- Include Evaluation of Reliability of ILI Method

| Reference: |  |
| --- | --- |
| §192.921(a)(1) | FAQ-46, 48, 55, 68 |

**Notes:**
The types of internal inspection tools that are available to the operator are described in section 6 of the supplement.  Any tool(s) used must be appropriate to detect anomalies associated with the threats identified for the pipeline being assessed. OPS expects operators to evaluate the segment specific risks associated with each portion of the pipeline that could affect an HCA and determine the appropriate assessment technology or combination of technologies to confirm whether or not defects are present.
OPS will review the tool selection process to ensure consistency with the standard and the appropriateness of the tool(s) selected.  This will include an evaluation of the reliability of the inline inspection methods considered.  OPS will also verify that operators address the considerations listed in Section 6.2.5 of the supplement.

## B.1.b – Assessment Method: Pressure Test

- Pressure Test Per Subpart J
- Use of a Spike Test, Alone, is "Other Technology“
- Spike Test Can be Very Effective to Assess Certain Threats
- (e.g., Seam Defects or SCC)

| Reference: |  |
| --- | --- |
| §192.921(a)(2) | FAQ-49, 53, 109, 141, 219 |

**Notes:**
A pressure test is another acceptable assessment method.  A pressure test must meet Subpart J requirements in order to be considered a valid assessment method.  However, it should be noted that even if the pressure test meets subpart J requirements, the test may not qualify the segment for extended reassessment intervals specified in Table 3 of the supplement.  This table requires higher pressure tests, in some cases up to 3.3 times the MAOP, in order to take full advantage of the longer reassessment intervals.
Spike tests that do not meet Subpart J requirements are considered “other technology” and require OPS notification. However, it is recognized that spike tests can be very effective to assess certain threats such as seam defects or SCC.

In areas where the language of the rule and ASME B31.8S conflict regarding pressure testing, the rule requirements shall take precedence, i.e., the pressure tests must satisfy the requirements of subpart J.

FAQ-141 provides clarification of the use of spike tests and notes that a spike test may be performed along with a pressure test meeting subpart J requirements. In that case, the subpart J test is considered the primary assessment, and no OPS notification would be required regarding the use of “other technology.”

## B.1.c – Assessment Method: Other Technology

- IMP Must Require Notification to OPS and Applicable State and Local Officials to Use “Other Technology”
- Notify 180 Days Before Conducting the Assessment
- Pressure Reduction is Not an Acceptable Assessment Method

| Reference: |  |
| --- | --- |
| §192.921(a)(4) | FAQ-55 |

**Notes:**
If the assessment method is not listed in the rule, the method will be considered “other technology.”   If other technology assessment methods are used they must provide an equivalent understanding of the pipe condition.
The operator’s plans must contain provisions for notifying OPS and any applicable state regulatory bodies at least 180 days prior to use of the method.  Examples of “other technology” include, but are not limited to:
ICDA on a wet gas system (ICDA on a dry gas system is not considered “other technology”);
Long range guided ultrasound.
Note that the use of a pressure reduction in lieu of completing a baseline assessment is not an acceptable method.  
FAQ-55 addresses this issue and states: Pressure reduction is not an assessment method. Although a pressure reduction can provide an equivalent margin to failure as a pressure test, a pressure reduction provides no information about the condition of the pipeline. One of the primary objectives of this rule is for operators to obtain a better understanding of the condition of their pipe so they can make well-founded technical decisions to reduce risk and protect HCAs. Section 192.933(a) specifies that a reduction in operating pressure taken to provide an immediate improvement in safety cannot extend more than 365 days without the operator providing a technical justification that continued pressure restriction will not jeopardize the integrity of the pipeline.

## B.1.d – Assessment Method: ERW Pipe

- If Susceptible to Seam Failure (LF ERW or Lap Welded Pipe)
- Method(s) Able to Find Seam Anomalies
- Must Prioritize as “High Risk”
- Seam Defects May be Stable (i.e., Not Susceptible) –Seam Assessment Not Required  (See Protocol C)

| Reference: |  |
| --- | --- |
| §192.917(e)(4) | FAQ-219, 220 |

**Notes:**
Segments susceptible to Seam Failure  include low frequency electric resistance welded  pipe and lap welded pipe that satisfies certain criteria listed in the supplement and:
any covered or non-covered segment in the pipeline system with such pipe that has experienced seam failure, or 
operating pressure on the covered segment has increased over the maximum operating pressure experienced during the five years preceding HCA identification.
If these conditions are satisfied, the operator’s program must:
Include an assessment method in the baseline assessment plan that is capable of detecting seam anomalies; and
Prioritize the segment as “high-risk” for assessment in the first 50% of covered segments
As discussed in Protocol C, seam defects may be considered to be stable and not susceptible to failure under certain conditions.  In this case, a seam assessment is not required.

## B.1.e – Assessment Method: Plastic Pipe

- If Plastic Pipe is Susceptible to Failure from Causes Other Than Third-Party Damage:
- Use Alternate Assessment Method to Address the Identified Threats

| Reference: |  |
| --- | --- |
| §192.921(h) |  |

**Notes:**
If an operator has plastic pipeline that falls under the scope of this rule, the operator must complete a threat analysis per section 917.  For threats other than third party damage, the operator must justify the use of alternate assessment methods. 

## B.2 – Assessment Schedule

- Baseline Assessment Plan by December 17, 2004
- Include Risk Based Schedule
- Considers Applicable Risk Factors

| Reference: |  |
| --- | --- |
| §192.917(c), 919(c), 921 | FAQ-38, 72, 73, 78, 140 |

**Notes:**
Protocol B.2 relates to the development of Assessment Schedules. The deadline established by the Rule for developing the Baseline Assessment Plan schedule was December 17, 2004.
In addition to identifying the assessment method, the gas IM rule requires that operators develop a risk based schedule for completing the baseline assessments. Operators are expected to appropriately consider the applicable risk factors in the prioritization of the baseline assessment schedule.  FAQ-78 addresses how operators may apply risk ranking systems for pipelines in HCAs.

## B.2.a – Assessment Schedule: All Segments

- Baseline Assessment Plan Schedule Includes All Covered Segments Not Already Assessed

| Reference: |  |
| --- | --- |
| §192.921(a) | FAQ-6, 7, 9, 10, 34, 36, 39, 125 |

**Notes:**
Protocol B.2.a addresses the expectation that all covered segments not already assessed need to be included in the schedule.  OPS expects to see a viable, active planning and scheduling process that is likely to result in assessments being performed in the relative sequence identified by risk assessment.  OPS will review an operator’s process for managing its baseline assessment schedule.  The degree of specificity of assessment schedules will vary depending on how far in the future assessments are planned.  FAQ-39 clarifies what OPS expects for specificity with regard to schedules in baseline assessment plans. 

## B.2.b – Assessment Schedule: Risk Prioritized

- Prioritize Covered Segments Based on:
- Potential Threats
- Applicable Risk Analysis
- Utilize Risk Ranking

| Reference: | FAQ-28, 33, 35, 39,  |
| --- | --- |
| §192.917(c), 921(b) | 78, 102, 125 |

**Notes:**
Protocol B.2.b addresses operator requirements to prioritize the segment assessment schedule based on the results of the risk analysis beginning with the highest risk segments. Although OPS recognizes that due to other factors, some segments that are low risk may be scheduled in the first half of the baseline schedule, OPS expects that most of the high risk segments will be assigned to the first half of the schedule - this point is covered under FAQ-35.  Operators will need to manage their assessments, and some aggregate indication of risk, by piggable section, could be useful in that regard. Such aggregation can mask important information, however. For example, a number of low-risk covered segments in a piggable section could result in that section being determined to be of moderate risk even though it contains the highest risk covered segment in an operator's program. Operators need to know the relative risk of individual covered segments so that they can appropriately plan their assessment activities. FAQ-125 discusses the OPS expectation to see a risk ranking on a covered segment basis.

FAQ-35. Must all of the highest risk segments be assessed by December 17, 2007, or will OPS allow operators some flexibility to deal with practical issues in scheduling assessments? [04/08/2004] Answer: The rule requires that baseline assessments must be completed on at least 50 percent of the covered segments by December 17, 2007, and that assessments be prioritized based on risk. Although OPS expects operators to concentrate on the highest risk pipe, some segments not among the highest risk pipe may be counted towards the 50 percent requirement. OPS recognizes that practical issues associated with scheduling and conducting assessments may lead to some lower risk pipe being assessed prior to high-risk pipe.... 

## B.2.c – Assessment Schedule: High Risk Segments

- High-Risk Segments Means Overall High-Risk – Prioritized in Top 50%
- Manufacturing/Construction Defects
- LF ERW or Lap Welded Pipe
- Only If They Are Not “Stable”

| Reference: |  |
| --- | --- |
| §192.917(e)(3), 917(e)(4) | FAQ-35, 169, 219, 220, 221 |

**Notes:**
Protocol B.2.c addresses the rule requirements that segments with certain threats shall be considered “high risk” based on having the vulnerabilities specified. High risk segments also include covered segments that have manufacturing or construction defects (including seam defects) that are not stable (as identified during the threat identification process). Covered segments that are susceptible to these threats must be considered “high-risk” in the overall segment prioritization. These threats are considered significant enough to require that a segment be considered high risk and prioritized in the top 50% of the risk ranking.

During IMP inspections, OPS would expect that operator’s programs will include provisions identifying high risk segments. 

FAQs 35, 169, 219, 220, and 221 include additional clarification on the treatment of high risk segments.

## B.2.d – Assessment Schedule: Deadlines

- 50% Complete: 12/17/2007
- Begin w/ Highest Risk Segments
- Priority May Consider Practical Scheduling & Operational Issues
- Count Cumulative Miles of Covered Segments (Not Total Miles Assessed)
- 100% Complete: 12/17/2012
- 				*	**- continued on next slide*

| Reference: |  |
| --- | --- |
| §192.921(d) | FAQ-26, 33, 35, 36, 169 |

**Notes:**
Protocol B.2.d addresses assessment schedule deadlines. The rule requires that 50% of the covered segments shall be assessed by December 17, 2007.  
Schedule priority shall be given to the highest risk segments.
However, specific schedules may consider practical scheduling and operational issues
While both covered and non-covered mileage may be assessed during a test, only the covered segment mileage shall be counted toward meeting the 50% goal.  
OPS will evaluate the 50% progress based on the operator’s scope of jurisdictional lines. The operator is required to have 100% of the covered segment mileage assessed by December 17, 2012.  

An assessment is considered completed when field activities are completed for the last assessment tool required for that covered segment. FAQ-33 provides additional clarification on how the 50% completion criteria is met.

FAQ-33. For purposes of determining the 50% criterion, does an operator use the total mileage that has been and will be assessed, or just the mileage that has been determined to be in an HCA?  Answer: For purposes of satisfying the progress requirements, operators must use the cumulative mileage of covered segments. Operators should not use the total miles assessed in making a determination of whether the 50% criteria has been satisfied

## B.2.d – Assessment Schedule: Deadlines - continuation

- 50% Complete: 12/17/2007 (cont.)
- States May Have State-Specific 50% Progress Deadlines

| Reference: |  |
| --- | --- |
| §192.921(d) | FAQ-26, 33, 35, 36, 169 |

**Notes:**
Be aware that additional progress requirements may apply for intrastate pipelines under the jurisdiction of state authorities. 
Inspections for intrastate piping will be done by state agencies if they are a certified to do so by OPS. To facilitate OPS and state pipeline safety program inspections, it is desirable that an operator’s plan delineate which pipeline segments are intrastate and which are interstate. This information will help to focus inspection activities by states and OPS to appropriate pipe segments. Discussion related to federal versus state completion deadlines is provided in FAQ-36.

FAQ-36. If an operator develops a single Baseline Assessment Plan that covers both intra- and interstate pipelines, does the need to complete assessments on 50% of the pipeline mileage in HCAs apply to both intra- and interstate pipeline segments, or just interstate pipeline segment mileage? Should the company’s Plan identify whether pipeline segments are intra- or interstate? [06/29/2004] Answer: Operators must comply with federal and, when applicable, state pipeline safety requirements. The 50% requirement in the federal integrity management program regulation applies to all pipeline systems that are covered under the rule - interstate and intrastate. Thus, an operator may develop a single Baseline Assessment Plan that covers both intrastate and interstate pipelines. An operator is to rank, assess and remediate its system as a whole, thus assuring that the highest risk-ranked HCAs will be addressed first, regardless of whether they are on interstate or intrastate segments of the system. Inspections for intrastate piping will be done by state agencies (if they are a certified to do so by OPS). To facilitate OPS and state pipeline safety program inspections, it is desirable that an operator s plan delineate which pipeline segments are intrastate and which are interstate. This information will help to focus inspection activities by states and OPS to appropriate pipe segments.

## B.2.e – Assessment Schedule: Implementation

- Review the Operator’s Implementation to Date
- Schedule Performance
- Assessment Method Actually Used
- Completion Date of Assessment is Recorded
- “Discovery” Clock Starts

| Reference: |  |
| --- | --- |
| §192.921 | FAQ-34 |

**Notes:**
Protocol B.2.e will involve review of the implementation of an operator’s assessment program.  OPS will review the specific baseline assessment schedule to determine the status of progress made at the time of the inspection.  Assessment results will be reviewed to ensure that the assessment methods specified in the Baseline Assessment Plan were in fact the methods actually used.  Furthermore, OPS will verify that assessments were completed within the specified schedule.
The operator’s program must require that any changes to the original Baseline Assessment Plan schedule are formally approved and documented by the operator.
Finally, OPS will verify that the operator has properly recorded the date of assessment completion.  This is important because it represents the beginning of the “discovery” clock for reviewing assessment results.

FAQ-34 provides clarification on when an assessment is considered to be complete – it is the date on which final field activities related to that assessment are performed, not including repair activities for in-line inspection tool runs and direct assessments. 

## B.3 – Prior Assessments

- Prior Assessments Are Those that Were Completed Prior to December 17, 2002
- B.3.a - Threats Identified per 192.919(a)
- B.3.b - Assessment Methods Used Meet 192.921(a)
- B.3.c - Remedial Actions Have Been Carried Out to Address Conditions Listed in Section 192.933
- 		*	**- continued on next slide*

| Reference: |  |
| --- | --- |
| §192.921(e) | FAQ-27, 29, 65, 152, 161 |

**Notes:**
Protocol B.3 will be used to review an operator’s use of prior assessments. In some instances, an operator may choose to take credit for prior assessments when developing the baseline assessment plan. Assessments completed prior to December 17, 2002 (which is the date of the Pipeline Safety Improvement Act) may be credited as baseline assessments if the assessments meet the following requirements:
The threats to the segments must be identified per the requirements of section 919(a);
The assessment method must address the applicable threats; and
Anomalies meeting the requirements of section 933 must have been remediated.

## B.3 – Prior Assessments		- continuation

- Operators Can Count Prior Assessments Toward the 50% Progress Milestone
- Prior Assessment May be Credited Even if it Did Not Assess All Threats
- Perform a New Assessment for Other Threat(s)

| Reference: |  |
| --- | --- |
| §192.921(e) | FAQ-27, 29, 65, 152, 161 |

**Notes:**
Operators can take credit for prior assessments in meeting the initial 50% mileage requirement even if the covered segment is low risk.
Furthermore, if a prior assessment did not address all applicable threats, the operator may take credit for addressing those threats that were assessed with the prior assessment.  However, if other threats exist for that segment and those threats require different assessment methods, then those assessment methods will still need to be performed on the segment, in order to complete the baseline assessment. 

OPS inspection will verify that requirements related to prior assessments are included in operators’ integrity management programs. 

FAQ-29 provides additional discussion on the use prior assessments for low risk segments.

FAQ-29. Use of Prior Assessment of Low-Risk Segments Can operators count prior assessments of low-risk segments used as baselines against the requirement to complete 50% of their covered mileage by December 17, 2007? Yes. The rule requires that operators prioritize covered pipeline segments for baseline assessment based on risk. Thus, the schedule in the Baseline Assessment Plan generally should show that the highest risk segments are scheduled for assessment prior to the lower risk segments. However, this does not preclude an operator from using a prior assessment for a baseline, even if the segment(s) covered by that assessment later turn out to be relatively lower risk.

## B.4 – New HCAs/Pipe

- Operator Updates the Baseline Assessment Plan for:
- Newly Identified HCAs
- Newly Installed Pipe

| Reference: |  |
| --- | --- |
| §192.905(c), 921(f), 921(g) | FAQ-30, 31, 161 |

**Notes:**
OPS will be reviewing operator’s process documents under Protocol B.4 to ensure that requirements exist to maintain the Baseline Assessment Plan up-to-date with respect to new HCA identifications and installation of new pipe.  The gas IM rule contains requirements to update the Baseline Assessment Plan if new HCA affecting segments are identified or new pipe is installed.  
If the operator identifies a new covered segment, the operator must complete the threat analysis, identify the appropriate assessment method, and incorporate the segment into the Baseline Assessment Plan. If a new pipe is installed and that pipe segment affects an HCA, then the same requirements would apply.  

## B.4.a – New HCAs/Pipe: One Year Requirement

- Incorporate Into the Baseline Assessment Plan Within 1 Year; AND
- Assessments Have Been Appropriately Scheduled and/or Completed

| Reference: |  |
| --- | --- |
| §192.905(c) | FAQ-7, 10, 11, 25, 110 |

**Notes:**
If a new covered segment is identified, it must be incorporated into the Baseline Assessment Plan within 1 year of the identification.  As part of this incorporation, a baseline assessment would need to be scheduled.
Of course, for a new pipeline an initial pressure test that meets Subpart J could be credited as the baseline assessment.

There are several FAQs related to new HCAs and their relation to baseline assessment plans. Refer to FAQs-7, 10, 11, 25, and 110.

## B.4.b & B.4.c – Assessments for New HCAs / Piping

- Baseline Assessments Completed Within 10 Years of Identification
- For Newly _*Identified*_ HCAs,
- For Newly _*Installed*_ Pipe Determined to be a Covered Segment

| Reference: |  |
| --- | --- |
| §192.921(f), 921 (g) | FAQ-110 |

**Notes:**
If, as a result of identifying a new HCA, existing pipe is identified as a covered segment that previously was not considered to be a covered segment, a baseline assessment must be completed on that segment within 10 years from the date the HCA was identified.   If a newly installed pipe is determined to be a covered segment, then a baseline assessment must be completed on that segment within 10 years from the date the pipe was installed.  As mentioned earlier, the initial Subpart J pressure test would meet the requirements for the baseline assessment.

FAQ-110 provides additional discussion on when the operator identifies a "new" HCA that results in the designation of additional covered segments, not previously identified as a covered segment.

FAQ-110. When the operator has identified a "new" HCA that results in the designation of additional covered segments, not previously identified as covered segments, subpart 192.905(c) requires the operator to incorporate these segments into the baseline assessment plan within one year. Subpart 192.921(f) requires the operator to complete the baseline assessment on these newly identified covered segments within ten (10) years from the date the new area is identified. Is the operator required to re-prioritize the baseline assessment plan segments per 192.921(b) each time a new segment is added even though the rule specifies a ten (10) year assessment schedule for these additional segments? [05/17/2004] Answer: No. The rule specifies a ten (10) year assessment schedule for newly identified segments. Operators must list the newly identified segments in its baseline assessment plan, and document its assessment method selection and threat identification, within one year of identification. However, the assessment may be scheduled for completion at any time within that 10 year period following identification of the new HCA, without the need to re-prioritize the pre-existing assessment schedules.

## B.4.d – New HCAs/Pipe: Threats to New Sections

- Threats to These Pipeline Sections Must be Identified

| Reference: |  |
| --- | --- |
| §192.905(c), 921(f), 921(g) |  |

**Notes:**
As part of scheduling the baseline assessment on these newly identified or installed segments, a risk analysis must be performed to determine what threats are applicable to the pipeline.  

## B.4.e – New HCAs/Pipe: Assessment Methods for New or Idled Sections

- Assessment Methods Must be Appropriate for the Threats
- Operators May Defer Activities Required by the Rule for Out-of-Service Pipe
- Deferred Activities Must be Completed When that Pipeline is Returned to Service

| Reference: |  |
| --- | --- |
| §192.905(c), 921(f), 921(g) | FAQ-7 |

**Notes:**
As a result of the threat analysis, an appropriate baseline assessment method or methods must be identified.  The process used to determine the appropriate assessment method must be consistent with the approach described in section 6 of the supplement.  OPS will look to see that the assessment methods for these pipelines are specified in the Baseline Assessment Plan.  Note that operators may defer activities required by the rule for out-of-service pipe. All deferred activities must be completed as part of any later return of that pipeline to service. FAQ-7 further clarifies what is expected for idled pipe,

FAQ-7. Do the requirements of the rule apply to "idle" pipe? Answer: The regulations do not define "idle" pipe. Pipe is considered either active or abandoned. OPS understands "idle" pipe, as used in the context of this question, as pipe not currently being used to move gas but that could be put back in service at a future date. All pipe is subject to the requirements of the integrity management rule. However, idle pipe presents different risks and different treatment is appropriate. 
In-service pipe (i.e., that contains gas, but is not presently being used to transport gas) represents a potential hazard to public health and the environment, even though idle. If such pipe leaks or ruptures, an explosion could result. Leaks may go undetected for some time, since idle pipe may not be covered by operator's SCADA systems. For these reasons, operators must meet all requirements and deadlines for pipe that contains gas. Such pipe must be included when determining if the requirement to assess 50% of covered pipeline mileage by December 17, 2007, has been met.
Out-of-service pipe (i.e., pipe laid up with nitrogen) represents much less hazard. Degradation of such pipe can occur, but is not likely to result in safety impacts. OPS will accept deferral of activities required by the rule for out-of-service pipe. All deferred activities must be completed as part of any later return of that pipeline to service. A baseline assessment need not be run immediately if the deadline for completing baseline assessments (i.e., December 17, 2012) has not yet expired, unless the risk posed by the pipeline would require an earlier assessment. The baseline assessment plan should be modified to assure that a baseline assessment is completed by the appropriate deadline. If the deadline has expired, then a baseline assessment must be completed as part of returning the pipeline to service.
Adding an idle pipeline into the IM program would be considered a substantive program change and would require notification under 192.909(b).

## B.5 – Environmental and Safety Risks

- Address Requirements for Conducting the Baseline Assessments in a Manner that Minimizes Environmental and Safety Risks
- Existing Procedures May be Referenced if Adequate

| Reference: |  |
| --- | --- |
| §192.919(e) |  |

**Notes:**
The gas IM rule contains a requirement that assessments be conducted in a manner that minimizes environmental and safety risks.  Note that a similar requirement also exists in Subpart J under section 192.515 for hydrostatic testing.  As such, operators may have already addressed these types of requirements in their O&M manuals. Through Protocol B.5, OPS will review these procedures as well as evidence of implementation during assessments as part of the IM inspection. If existing safety procedures are adequate, those procedures can be referenced in the IMP program.  However, those procedures should address special safety or environmental hazards that might exist as a result of performing assessments.  

## B.5.a – Environmental and Safety Risks: Implementation

- Implement Precautions to -
- Protect Workers and Members of the Public
- Environment

| Reference: |  |
| --- | --- |
| §192.919(e) |  |

**Notes:**
Protocol B.5.a addresses potential risks that may result from pipeline integrity assessments. OPS will expect operator’s integrity assessment programs to include measures to protect the public, workers, and the environment from potential hazards that could be inherent in pipeline assessment activities.
Possible considerations may include:
Liquids and Debris From Assessments, including contaminated liquids from hydrostatic tests
Precautions for removing constrained dents
Properly Securing Flexible Hoses Under Pressure
Personnel at Safe Distances
Ignition Sources
Excavation in environmentally sensitive areas
Disposal of coal tar coatings
Run off control
Etc.

## B.6 – Updating the Baseline Assessment Plan

- Verify that the Operator Keeps the Baseline Assessment Plan Up-to-Date With Respect to New Information
- Also Refer to Protocol K

| Reference: |  |
| --- | --- |
| §192.911(k), B31.8S §11 |  |

**Notes:**
Maintaining the Baseline Assessment Plan up-to-date is vital to ensuring that the highest risk segments are assessed early in the process and are assessed with the best assessment method.  Protocol B.6 will examine operators’ change control process associated with updates to the baseline assessment plan. Given that Baseline Assessment Plan cycle is approximately 8 years, much new information will be generated during this period that may shed light on previously unknown or uncharacterized threats.  Additionally, new technology may emerge that will provide better assessment results for specific threats. OPS expects operator’s integrity management programs to address elements to update baseline assessment plans.

This topic will be discussed further in the presentation for Protocol K.

## B.6.a – Updating the Baseline Assessment Plan: Process

- Requirements to Keep the Baseline Assessment Plan Up-to-date
- Address Newly Arising Information, Applicable Threats, and Risks
- Address Changes to the Segment Prioritization or Assessment Method as Applicable

| Reference: |  |
| --- | --- |
| §192.911(k), B31.8S §11 | FAQ-25, 31, 32 |

**Notes:**
Keeping the Baseline Assessment Plan up-to-date with new HCA impact information was already discussed.  
The Baseline Assessment Plan should also be kept up-to-date with changes to risk analysis, completed baseline assessments, and other applicable operational or design information that may impact either the prioritization schedule or the assessment method selected for a particular segment. For example, a series of completed baseline assessments may reveal more problems in a given area than previously thought, which may prompt a review of the prioritization of other segments in that same area. This program element will be reviewed by OPS under Protocol B.6.a.

## B.6.b – Updating the BAP: Implementation

- For Changes to BAP, document:
- Reason for Change
- Authority for Approving Change
- Analysis of Implications
- Communication of Changes to Affected Parties
- ASME B31.8S, Section 11(a)

| Reference: |  |
| --- | --- |
| §192.911(k), B31.8S §11(a) | FAQ-30, 31, 32, 97, 98, 111 |

**Notes:**
Under Protocol B.6.b, OPS will review the Baseline Assessment Plan for changes.  Each change should be formally approved and documented as prescribed in the operator’s management of change process.
For each change, the inspector will look to see that the following are documented:
 the reason for the change
 the approval authority for the change
 an analysis of the implications of the change
 communication of the change to affected parties.
The change process should be consistent with the requirements in Section 11(a) of the Supplement.
FAQ-32. Should operators archive previous versions of their baseline assessment plans so OPS can track changes to these plans over time? [02/20/2004] Answer: Section 192.947(d) requires that operators maintain, for the useful life of the pipeline, documents to support any decision, analysis and process developed and used to implement and evaluate each element of the baseline assessment plan and integrity management program. Copies of the evolving revisions of the baseline assessment plan, and of plans for periodic reassessments, should be included with the records maintained under this section.

## B.6.b – Updating the Baseline Assessment Plan: OPS Positions

- Notify OPS Only for Changes that
- Substantially Affect the Program’s Implementation, *OR*
- Significantly Modify the Program or Implementation Schedule
- Keep Copies of the Revisions of the Baseline Assessment Plan

| Reference: |  |
| --- | --- |
| §192.911(k), B31.8S §11(a) | FAQ-30, 31, 32, 97, 98, 111 |

**Notes:**
OPS notification is only required for changes that may “substantially” affect the IM program implementation or may “significantly” modify the IM program or schedule for carrying out the program elements. Operators need not notify OPS of insignificant changes to their assessment schedules.

Baseline Assessment Plan changes should be documented and the operator should maintain copies of revisions to the Baseline Assessment Plan.  The revisions should be made available to OPS during IM inspections.

FAQs 31 and 97 provide additional clarification on OPS expectations on notification requirements

## Protocol Area B Baseline Assessment Plan

**Conclusion – **
**Thank you for your attention**

**Notes:**
This concludes my presentation on the protocols related to the Baseline Assessment Plan. Thank you for your attention. 

## Gas Integrity Management Rule Protocols

**Clyde Myers**
**49 CFR 192.923, 925, 927, 929 & 931**
**Direct Assessment Plan**
**Protocols D.1 through D.5**
**January 2005**

**Notes:**
[Greeting to the audience. Introduce yourself and tell where you work or fit into the Gas IMP process]

I will be discussing the gas integrity management protocols for inspecting a Direct Assessment Plan. Of course, this section of the inspection protocols would only apply to those operators planning on using ECDA as an assessment method.  

This presentation addresses some general requirements contained in section 923 and the External Corrosion DA requirements contained in Section 925 of the Gas Integrity Management Rule.  After that, I’ll be speaking with you about the inspection protocols for Internal Corrosion and Stress Corrosion Cracking.  

## Direct Assessment

- DA Plan
- DA Applies to EC, IC, and SCC Threats Only
- Standards Incorporated By Reference
- ASME B31.8S §6.4, A-3, B-1, B-2
- NACE RP-0502-2002
- If conflict, the More Stringent Requirement Applies

| Reference: |  |
| --- | --- |
| §192.923, 925 | FAQ-155, 167, 187 |

**Notes:**
In previous workshops and public meetings on Direct Assessment and on the Gas Integrity Management Program rules, OPS has addressed the basics of Direct Assessment methods.  Briefly, above ground survey tools were first used to evaluate and ensure that cathodic protection and coating systems were working to protect the pipeline.  Those methods and technologies have now been extended and further developed to be used as a process to evaluate and manage pipeline integrity. The concept of the ECDA process is simple.  
Find the locations along a pipeline where coating faults, CP, or other problems indicate an increased potential for corrosion metal loss, 
excavate and examine those locations, 
repair those that have degraded the pipe and
address the root causes of anomalies. 
In doing so, future corrosion is mitigated and  integrity of the pipe from the external corrosion threat is assured. 

The Pipeline Safety Improvement Act of 2002 and the Gas Integrity Rule provide that direct assessment may be used as an integrity assessment method. Operators will be expected to be able to demonstrate that DA, or any other assessment method used, is applicable for the threats and circumstances of the pipeline being assessed. This is further clarified in FAQ-187. Section 923 lists 3 specific threats for which DA may be used. 
External corrosion, 
internal corrosion, and 
stress corrosion cracking 

Both the supplement and NACE standard contain the ECDA process requirements.  These have been incorporated by reference within the Gas Integrity Rule, and the inspection protocols rely on the requirements contained in the referenced standards extensively . Regarding the requirements in the standards incorporated by reference, inspectors will review operator’s documentation to verify all requirements are met.  If the two standards differ, operators must comply with the more stringent requirement. Additional clarification on the use of the Supplement and NACE standard is provided in FAQs-155 and 167.

Inspection protocols D.01 through D.12 cover these three areas.

## External Corrosion Direct Assessment

- D.1 – ECDA Programmatic Requirements
- ECDA Must Apply 4-Step Process
- D.2 - Pre-Assessment
- D.3 - Indirect Examination
- D.4 - Direct Examinations
- D.5 - Post Assessment

| Reference: |  |
| --- | --- |
| §192.925 |  |

**Notes:**
This portion of the DA presentation will focus on the External Corrosion Direct Assessment or ECDA process. OPS will inspect an operator’s ECDA process through protocols D.1 through D.5. Protocol D.1 addresses the programmatic or documentation expectations for ECDA. Section 925 requires that each operator’s  ECDA Plan follow a 4 step process. The inspection protocols have been aligned with the 4 steps:
D.2 - Pre-assessment
D.3 - Indirect Examination
D.4 - Direct Examinations
D.5 - Post Assessment

Note that the NACE standard uses the term Indirect Inspection Step instead of Indirect Examination as the code identifies it.  They both describe the same step.

## D.1.a - ECDA Programmatic Requirements

- ECDA Plan must describe its process:
- Objectives
- Implementation
- Decisions
- Timeline
- Data Integration and Analysis
- Continual Improvement

| Reference: |  |
| --- | --- |
| §192.925(b) |  |

**Notes:**
The gas integrity rule requires that the ECDA Plan describe in detail how each of the four ECDA process steps will be implemented. Under protocol D.1.a OPS will look for details in the plan which identify:
 what the operator is attempting to accomplish, 
describe how the process will be implemented, (this includes the who, what, when, where, why, and how activities will be accomplished),
how relevant decisions are made and by whom.
the time line for completing the work to implement the plan, 
how information gained during the process will be integrated and analyzed, and 
how continual improvements will be made based on this information.

## D.1.b - Restrictive Criteria For 1st ECDA on Segment 

- Pre-Assessment
- Collect More Critical Data,
- More ECDA Regions
- Use More Than Two Tools
- Indirect Examination
- More Stringent Criteria for Categorizing Indications
- Direct Examination
- Additional Excavations & Data

| Reference: |  |
| --- | --- |
| §192.925(b)(1)(i), (b)(2)(i), (b)(3)(i) |  |

**Notes:**
Section 925 requires that for initial applications of ECDA, operators must apply more restrictive criteria for each of the first three ECDA steps.  “Initial application” means the first time ECDA is used on a covered segment.  Following are some examples of more restrictive criteria an operator may consider:

For Pre-assessment, this may mean 
defining a larger set of critical data needed in determining whether ECDA is feasible, 
breaking ECDA regions into smaller, more defined pipe sections with more specific limiting characteristics, and 
possibly selecting more than the minimum of two tools.

For Indirect Examinations, more stringent criteria might be applied to 
the magnitude of the coating fault indication to conservatively classify its severity, 
the magnitude of the anomaly for defining the urgency for excavations, or 
When repeating the indirect examinations to verify and correlate readings is indicated.

For Direct Examinations, more restrictive criteria might be applied  to
require additional excavations and additional testing and data collection at each excavation. 

## D.1.c - ECDA & Third Party Damage

- Process to Address Coating Indications
- Integrate Data to Identify Potential TPD, Such as:
- One-Call
- ROW Data
- Third Party Encroachments
- Foreign Lines

| Reference: |  |
| --- | --- |
| §192.917(b), 917(e), 925(b) | FAQ-218 |

**Notes:**
The gas integrity rule requires that operators’ ECDA procedures include a process linking the potential for third party construction damage with an indication of a coating fault to help define where third party damage may exist. 

The purpose of the requirement and protocol D.1.c is to ensure operators will match ECDA coating fault indications with data integrated from other information gathered from one call data, ROW data, third party construction activities, and information about other above ground and underground utilities and structures in the area to identify and address the possible threat of third party damage.

Inspectors will review the operator’s processes for identifying potential TPD based on the integration of data with coating indications found during indirect examination.  Operators should refer to FAQ-218 for additional clarification regarding ECDA and third party damage.

## D.1.c - ECDA & Residual Third Party Damage

- Matches of ECDA Coating Faults With Suspected Third Party Activity
- Basis for Decisions and Actions Taken

| Reference: |  |
| --- | --- |
| §192.917(b), 917(e), 925(b) | FAQ-218 |

**Notes:**
The gas integrity rule requires that the operator have a process to address the possible threat of residual third party damage when matches of ECDA indirect examination coating fault indications match other data of known or suspected excavation activities.  The operator must have a procedure to address the results and findings of this data integration. When the threat from residual third party damage is identified, an assessment must be performed.  Such follow up assessments for third party damage  may be excavation and direct examination, if the threat is local.   If more extensive, the assessment may need to involve pressure testing or ILI.  

Inspectors will review:
#1  The documented basis for decisions and actions that it will take when evidence suggests residual third party damage may exist, and 
#2  The results of assessments conducted for suspected residual third party damage locations.  

## D.2 - ECDA Preassessment

- Comply With NACE RP-0502, §3
- ECDA Feasibility
- ID ECDA Regions
- Select Indirect Tools
-  Complementary

| Reference: |  |
| --- | --- |
| §192.925(b)(1) |  |

**Notes:**
Pre-assessment is the first step in the ECDA process and is addressed by protocol D.2 and its sub-questions.  The purpose of the pre-assessment is to:

#1 determine whether the ECDA process may be used successfully to evaluate the external corrosion threat – this is called a feasibility determination, 
#2 identify pipeline areas called ECDA regions that have similar characteristics, and 
#3 identify indirect inspection tools which work best in those regions, 

Selecting two Complementary Tools to be used for each region is a key result of the pre-assessment step. Inspectors will carefully review the activities involved in this pre-assessment step, and will pay particular attention to how the operator determines that the two tools selected for each region will best capture accurate data of coating faults. “Complementary” means that the capability of each tool selected is to have strengths which compensate for the limitations of the other.  This is most effective when the tools are based on two different technologies. 

## D.2.a – Identify Data Needs 

- Pre-Assessment Data Intensive
- Historical, Current, Physical
- Must Consider Following Data:
- Pipe-Related
- Construction Related
- Soils/Environmental
- Corrosion Control
- Operational

| Reference: |  |
| --- | --- |
| NACE RP-0502 §3.1, 3.2 |  |

**Notes:**
The NACE standard requires the operator to collect, integrate and analyze pipeline data in a comprehensive and thorough fashion.  The operator must gather historical, current and physical data on the pipeline normally available in construction records, operating and maintenance records, alignment sheets, corrosion survey records and from pipeline inspection reports. 
The ECDA preassessment process step is data intensive.  
Inspectors will review the operators documentation to verify that the pipeline operator:
Has defined minimum data requirements critical to the success of the ECDA process and how it addresses missing or inadequate data such as obtaining the data or making conservative assumptions about the missing data. 
Has collected data in the five categories from Table 1 of the NACE standard. The categories being 
pipe-related, 
construction related, 
soils/environmental, 
corrosion control, and 
operational, 
Inspectors will verify operators have a process to collect and analyze this data.

## D.2.b – Feasibility Assessment

- ECDA Feasibility Assessment
- Integrate & Analyze Data to Determine:
- 2 Indirect Tools
- ECDA Regions
- Locations Where Tool Use Not Feasible
- Disbonded Coating
- Rock Backfill
- Rebar in Pavement

| Reference: |  |
| --- | --- |
| NACE RP-0502 §3.3 |  |

**Notes:**
Protocol D.2.b addresses the ECDA feasibility assessment. The NACE standard requires an operator determine that ECDA is (or is not) feasible for any region, if data can’t be collected, data is insufficient, or conservative values can’t be determined or applied.  The ECDA method may not be used for ECDA regions where the operator cannot identify two effective indirect inspection tools.  We’ll get into ECDA regions in a moment, but first we need to discuss tool selection, because one of the determining factors of regions, are pipeline locations where two indirect inspection tools will be effective.  Just as important as determining where tools will work is determining where indirect inspection tools may give false readings and are not feasible.  ECDA might not be feasible:
Where coatings cause electrical shielding such as disbonded coatings;
Where backfill has significant rock content;
Where ground surfaces contain multi layered pavements, or reinforced concrete
In areas with adjacent buried metallic structures, 
In stray current areas or areas of DC rail lines,
Where casings and underwater crossings may prevent use of ECDA.

In these areas the operator may need to use methods other than ECDA for assessing the external corrosion threat.  Inspectors will review the operators documentation to verify the operator has a process to integrate and analyze its data to:
Determine the basis of indirect examination tool reliability in each region
Identify and address locations where indirect tools may provide false readings

## D.2.c - Indirect Tool Selection

- Indirect Tool Selection
- Minimum of 2 Tools for Each Region & Basis
- Detect Corrosion or Coating Holidays
- NACE RP-0502 Table 2 &    Appendix A
- Reliable for Expected Conditions

| Reference: |  |
| --- | --- |
| § 192.925(b)(1)(ii), NACE RP-0502 §3.4 | FAQ-129, 175, 198, 204 |

**Notes:**
Protocol D.2.c addresses indirect tool selection. The rule and the referenced standards require at least 2 complementary indirect examination tools. I say at least 2 tools since there will be conditions where the 2 tools selected will give conflicting data and a third tool may be needed to resolve the problem.  Operators must document the basis for their tool selections.  In other words, why the tool’s capabilities are best suited for the conditions around the pipeline.  Each indirect examination tool has its strengths and limitations depending on characteristics of the ECDA region.  Their effectiveness varies with: soils, rock in backfill, pipe coatings,  signal interference conditions, depth of cover, construction practices, etc.   
Appendix A of the NACE standard contains a description of indirect examination methods operators use.  Table 2 provides guidance on tool selection, and identifies conditions under which some indirect tools may not be reliable.  Operators may use tools not listed in Appendix A as long as the operator justifies their use.  Inspectors will review the operators documentation to verify the operator has evaluated the capabilities of each of its indirect examination tools, where they work effectively and integrated its data for each region providing a basis for selecting two tools for each region. 

Inspectors will also review the operators documentation showing the tools selected for each region are complementary, i.e. as the NACE standard describes complementary: "the strengths of one tool compensate for the limitations of another." Generally, an operator should endeavor to use tools based on different technologies. Note that FAQs 129, 175, 198, and 204 provide additional background information in support of this protocol element.

## D.2.d – Identify ECDA Regions

- Identify Regions
- Physical Characteristics
- Corrosion History
- Expected Future Corrosion
- Same Indirect Inspection Tools
- A Region Need Not Be Contiguous

| Reference: |  |
| --- | --- |
| NACE RP-0502 §3.5 |  |

**Notes:**
The NACE standard defines an ECDA region as a section or sections of a pipeline segment that: 
1) Have similar physical characteristics
2) Have similar operating histories
3) Have similar expected future corrosion conditions, and
4) Are assessed using the same two indirect examination tools. 

Note that ECDA regions need not be contiguous.  A single region may be physically located at various places along a pipeline. Under protocol D.2.d, inspectors will review each operator’s documentation to verify that they have gathered and evaluated their data on the pipeline and (1) have identified criteria for establishing ECDA regions, and (2) have documented the ECDA region boundaries.  

## D.2.d - ECDA Regions

**D.2.d - ECDA Regions**

**Sandy-Loam**
**Med Resist**
**No History**

**Sandy**
**Well Drained**
**Low Resist**
**No History**

**Sandy**
**Well Drained **
**Med. Resist.**
**Some Problems**

**Loam**
**Poor Drainage**
**High Resist**
**Many Problems**

**River**

**ECDA 1**

**ECDA 2**

**ECDA 3**

**ECDA 4**

**ECDA 5**

**CIS/DCVG**

**CIS**
**EM**

**CIS/DCVG**

**Notes:**
This simple example shows how you might integrate key data for selecting regions based on soils, corrosion histories, and survey tools that might work well in those regions. Note that even though the same tools are used in regions 1 & 2 and in regions 4 & 5, they have been identified as different regions due to differences in their corrosion histories or differences in their environments, with different soil resistivity or different moisture or drainage conditions.  

Depending on different conditions and characteristics encountered in the regions, even though the same tools are used, the operator may need to apply different criteria to evaluate tool results. The environment in a region may have an affect on the signals and potentials a tool detects, which in turn affects tool readings in ways that are specific to that particular  region.

OPS will inspect documentation of the basis for tool selection decisions.

## D.2.d - ECDA Region Changes

- Regions May be Modified Consistent With Region Criteria
- Based on Indirect Inspection
- e.g., Tools Not Performing Consistently Throughout Region
- Based on Direct Examination
- e.g., Improved Knowledge of Soil Conditions

| Reference: |  |
| --- | --- |
| NACE RP-0502 §3.5 | FAQ-177 |

**Notes:**
The NACE standard allows adjustments to ECDA regions as the process is applied. For instance, conditions may be encountered in the field during the indirect examination step where an operator determines certain tools are not working as well as anticipated and a different survey tool must be used.  Another example is that soil conditions observed during direct examinations may differ from conditions assumed when ECDA Regions were first determined. In these instances, inspectors will review the operators’ documentation to verify a management of change process has been followed and verify that the reasons for the changes in regions are consistent with the region definition and the operator’s region criteria.  

FAQ-177 provides additional background information on changing regions.

##  D.3 - ECDAIndirect Examination

- Locate Indications of Coating Faults & Corrosion Activity
- Identify Severity of Indications
- Identify Excavation Priorities

| Reference: |  |
| --- | --- |
| §192.925(b)(2) |  |

**Notes:**
Protocol D.3 addresses Indirect examination. This is the second step in the ECDA process.

The purpose of indirect examination is to:
1) Locate potential coating faults, and  other anomalies that are indicative of corrosion activity.  These are referred to as “indications.”
2) Determine the severity of indications, and 
3) Define criteria for the urgency of excavation and direct examination of indications.

Integrating the indirect inspection data with information previously gathered during the pre-assessment step is key to determining the severity of indications

## D.3.a – Conduct Indirect Examinations

- 2 Indirect Examination Tools
- Over Each ECDA Region
- Follow Industry Tool SOPs
- Establish Spacing of Readings
- Reduced Spacing in Suspect Areas
- Document Data from Indirect Examinations

| Reference: |  |
| --- | --- |
| NACE RP-0502 §4.2 | FAQ-104 |

**Notes:**
As part of protocol D.3.a, inspectors will review the operator’s documentation to see if the operator has:
1) Inspected the entire ECDA region with two indirect examination tools, (Note that operators should premark each ECDA boundary),
2) Followed standard industry practices as described in Appendix A of the NACE standard,
3) Specified and implemented appropriate physical spacing for taking tool readings, including reducing the spacing in suspect areas, and
4) Documented all tool results including data on all readings and analysis to identify all indications.

FAQ-104 clarifies that the rule requires that an operator’s plan for using direct assessment as a primary assessment method must comply with Section 6.4 of the Supplement (and Appendices B2 and A3 for internal corrosion and stress corrosion cracking, respectively) and the NACE standard. To comply with both standards, an operator must fulfill the more restrictive requirements. Indirect examinations with both complimentary tools must thus be made over the entire length of an ECDA region.

## D.3.b – Identify Indications

- Align and Compare Data
- Consider Spatial Errors
- Compare Results of Tools for Consistency
- Unresolved Discrepancies Classified as More Severe
- Identify Indications

| Reference: |  |
| --- | --- |
| §192.925(b)(2)(iii), (iv), NACE RP-0502 §4.2, 5.2 |  |

**Notes:**
This slide and the next several will address Protocol D.3.b and what OPS inspectors will be looking for. After the indirect inspection indications have been determined, operators must address all indications by:
Aligning and comparing the results of the tool runs
Resolving spatial errors, 
Addressing any data inconsistencies, and 
Identifying indications
Note that if inconsistencies between tool data can not be resolved, the location must be classified as a more severe indication.

## D.3.b – Classify Indication Severity

- Establish Classification Criteria
- Capabilities of Tools
- Unique Conditions of Region
- Presence of Active Corrosion
- Expertise Level of Analysts

| Reference: |  |
| --- | --- |
| §192.925(b)(2)(iii), (iv), NACE RP-0502 §4.2, 5.2 | FAQ-213 |

**Notes:**
After indications are identified, the NACE standard requires the operator to classify indications according to their severity.
The classification reflects the likelihood of corrosion activity at each indication and is required input for developing the excavation plan.

To identify severity criteria for each indication, Operators need to take into account:
Capabilities of indirect inspection tool:  for example, the magnitude of the voltage drop, CP potentials, signal loss, or percent attenuation per length of pipe.  
Unique conditions within the ECDA region, 
Whether corrosion is active at the location,
Expertise level of personnel analyzing the inspection data.

## D.3.b – Classify Indication Severity

- Table 3 of NACE 0502
- Severe – Moderate – Minor
- Active Corrosion is Severe
- If Indeterminate, Indications Must be Classified as Severe

| Reference: |  |
| --- | --- |
| §192.925(b)(2)(iii), (iv), NACE RP-0502 §4.2, 5.2 | FAQ-213 |

**Notes:**
Table 3 of the NACE standard provides a recommended classification scheme and identifies indications as either severe, moderate or minor.  When ECDA is used for the first time on an ECDA region, if the operator cannot determine whether corrosion is active, indications should be classified as severe. When survey results indicate significantly different sets of locations where corrosion activity may exist which cannot be resolved, operators must classify them as severe.  OPS will review the classification criteria and inspect tool logs to confirm the correct classification of indications.

FAQ-213 addresses at what point during ECDA one moves from severe, moderate, minor to immediate, scheduled, monitored. The point we change is when we proceed from classification of an indication to establishing priorities for excavation of that indication.

## D.3.b – ECDA Process Pre-Assessment Check

- Compare Indirect Results With:
- Pre-assessment Results
- Prior History
- If Inconsistent, Re-evaluate:
- ECDA Feasibility
- ECDA Region criteria
- Tool Selection

| Reference: |  |
| --- | --- |
| §192.925(b)(2)(iii), (iv), NACE RP-0502 §4.2, 5.2 | FAQ-177 |

**Notes:**
Before proceeding to define excavation priorities, the NACE standard requires the operator to compare indirect inspection results with pre-assessment results and prior history to confirm or re-evaluate the feasibility of ECDA, region determinations, and tool selection.  Indirect inspection results should be consistent with expectations derived during the pre-assessment; if not, the pre-assessment must be re-evaluated.  In some cases this may result in the need to use additional indirect inspections or redo indirect survey tools or perhaps conduct some preliminary direct examinations of the locations to resolve inconsistent data.  The inspectors will review the operator’s documentation to verify that the operator performed this required step.

FAQ-177 addresses if operators can aggregate ECDA regions after the process is started and they determine that some regions have common features. It points out that operators can aggregate ECDA regions if they have similar characteristics.

## D.3.b – Establish Excavation Priorities

- Prioritize Direct Exam of Each Indication
- Example Criteria RP-0502 Table 4
- Urgency of Excavation
- Immediate Action Required
- Scheduled Action Required
- Suitable for Monitoring

| Reference: §192.925(b)(2)(iii), (iv),  | FAQ-57, 58, 196, |
| --- | --- |
| NACE RP-0502 §4.2, 5.2 | 199, 203, 213 |

**Notes:**
The gas integrity rule requires operators to establish criteria for determining the urgency for excavation of each indication identified during indirect examination.  The NACE standard recommends the following 3 priority designations: immediate, scheduled, or monitored.  Immediate indications are those that pose an immediate threat to the pipeline’s integrity. Section 5.2 and Table 4 of the NACE standard provide examples of criteria addressing excavation priorities.  For instance, immediate action is required for indications with likely ongoing corrosion activity in areas of prior corrosion.  

Inspectors will review the operators documentation to verify that the operator:
Specifies criteria for determining excavation priority for indications.
Assigns priorities for excavation to each of the indications identified during the indirect examinations, and
Develops a schedule for the excavation of priority indications (immediates and scheduled).

Operators will want to refer to several FAQs related to establishment of priorities – FAQs 57, 58, 196, 199, 203, and 213.

## D.3.b - Clarification Regarding “Immediate” Indication Terminology

- “Immediate” Indication Terminology
- Compared to 192.933

| Reference: |  |
| --- | --- |
| §192.925(b)(2)(iii), (iv), NACE RP-0502 §4.2, 5.2 | FAQ-58 |

**Notes:**
The NACE standard uses “immediate,” “scheduled,” and “monitored” to describe the excavation priorities of indications.  This terminology is similar to the remediation categories in Section 933, namely “immediate,” “one-year,” and “monitored.”  These similar terms can be confusing but are entirely different. When an actual pipeline defect is discovered, such as might occur following an ILI, it may meet one of the remediation criteria at which time a deadline for completing repairs or remediation is established.

With ECDA, an “immediate” indication identifies the potential for a coating fault that is reason to suspect active corrosion and is deemed severe enough to excavate with the highest priority.  However, until the line is excavated, there is not enough information to reasonably conclude that an actual pipe defect is known to exist.  Therefore, the requirements of Section 933 do not apply to indications based on their excavation priority.  Upon excavation and inspection of the pipeline, if an actual pipeline defect exists, then the defect is categorized and remediated in accordance with Section 933.

What constitutes "discovery of a condition“ is covered by FAQ-58. 

[Speaker Info:  FAQ-58 text:  Discovery of a condition occurs when an operator has adequate information about the condition to determine that it presents a potential threat to the integrity of the pipeline. Depending on circumstances, an operator may have adequate information when the operator receives the preliminary internal inspection report, gathers and integrates information from other inspections, or when an operator receives the final internal inspection report. Operators are required to obtain sufficient information about a condition to make this determination no later than 180 days after an integrity assessment, unless the operator can demonstrate that the 180-day period is impractical.]

## D.4 - ECDADirect Examinations

- Required Excavations & Data Collection
- Assess Corrosion Activity
- Measure Pipe Surface Conditions
- Measure Immediate Surrounding Environment Data
- Defect Size and Growth Rate
- Remediate Defects & Determine Root Cause
- Verify Classifications & Excavation Priorities

| Reference: |  |
| --- | --- |
| §192.925(b)(3), NACE RP-0502 §5.1.1 |  |

**Notes:**
Direct examination is the third step in the ECDA process and is addressed by protocol D.4. The objectives of the direct examination step as outlined by the NACE standard are to: 
 Excavate indications at locations most susceptible to corrosion activity and then assess the corrosion activity, including determining
Pipe surface conditions
Environmental Data
Defect size, and corrosion growth rate

 Remediate defects discovered and determine root causes, and 
 A process evaluation which includes 
Verifying severity classifications, and
Verifying excavation priorities.

## Minimum Excavations

- NACE RP-0502-2002, §5.10
- No. of Regions in the Segment
- No. of Immediate Indications
- Scheduled Indications
- Defect Found at Scheduled Indication More Severe Than Defect at Immediate
- Monitored Indications
- First Application of ECDA

**Notes:**
Excavations and direct examinations must be conducted based on the priority established for the indications.  Section 5.10 of the NACE standard identifies the minimum number of excavations required for each indication priority under a variety of circumstances which can be somewhat confusing.  This depends on:
The number of ECDA regions in a pipeline segment,
The number of immediate indications,
Whether scheduled indications have been identified,
Whether a scheduled indication was more severe than an immediate indication,
Whether monitored indications have been identified, and 
Whether this is the first time ECDA has been applied to the region.

Remember as NACE defines these, a pipeline segment may contain one or more ECDA regions.   OPS will inspect the operator’s process for determining which and how many indications must be excavated for compliance with the requirements of Section 5.10 of the NACE standard.

## D.4.a - ECDADirect Examinations

- Minimum Requirements For:
- Consistent Data Collection
- Recordkeeping in Each Region
- Types of Data
- Conditions Encountered
- Corrosion Activity Expected
- Availability & Quality of Prior Data

| Reference: |  |
| --- | --- |
| §192.925(b)(3), NACE RP-0502 §5.3, 5.4 | FAQ-57 |

**Notes:**
The ECDA direct examination process step is very specific and methodical in its requirements to collect data during excavations especially at areas where corrosion activity is most likely. Operator’s recordkeeping must include:
Types of data – which should include: data prior to, during and after each excavation and before coating removal
Conditions encountered – e.g. water conditions, soil resistivity, nature of backfill, coating type and condition  
Corrosion Expected – (from preassessment and indirect inspection data)
Availability and Quality of Prior Data. – Foreign line crossings, interference, third party activity or missing data assumptions.

FAQ-57 addresses how soon the results of pipeline integrity assessment be evaluated. Operators are expected to review the results of integrity assessments promptly. Operators are required to obtain sufficient information to identify conditions that present a potential threat to the integrity of the pipeline no more than 180 days after an integrity assessment, unless the operator can demonstrate that it is impracticable to obtain the information within this limit.

## D.4.a - ECDADirect Examinations (cont.)

- Remove Coating, Clean Pipe
- Identify/Map Corrosion
- Measure & Document All Significant Defects
- Depth and Morphology Measurements
- Magnetic Particle for Cracks
- UT for Internal Defects

| Reference: |  |
| --- | --- |
| §192.925(b)(3), NACE RP-0502 §5.3, 5.4 |  |

**Notes:**
Operators must have comprehensive direct examination procedures to capture data necessary for morphology measurements.  For example: photographic evidence of pipe conditions before and after coating removal, soil chemistry (soil pH and resistivity at pipe depth), corrosion products chemistry, and pH of water behind the coating

Operators will have to justify reinspection intervals for covered segments.  Data needed for that justification in part comes from the data collected during direct examinations, for example;  size and map of defect, and corrosion growth rates.

To take advantage of the excavation, while the pipe is available for examination, the NACE standard suggests operators conduct other evaluations of the pipe at this time, such as for cracks, internal defects and for possible stress corrosion cracking.  Although this is not a mandatory requirement in the standard, this recommendation should be implemented by all operators, unless a strong technical justification is documented.

## D.4.b - ECDADirect Examinations

- Remaining Strength Evaluation
- RSTRENG, ASME B31G
-  SOPs Must Include Criteria:
- Defects Exceed Allowable Limits
- Similar Defects May Exist in the Region
- Suitability of ECDA Process Based on Root Cause

| Reference: |  |
| --- | --- |
| §192.925(b)(3)(iii), 933, NACE RP-0502 §5.5 |  |

**Notes:**
Under protocol D.4.b, inspectors will review the operators documentation to verify :
The method to calculate remaining strength at defect locations,
The criteria for actions to be taken if corrosion defects exceed allowable limits (for example the NACE standard, section 5.5, states that all defects may not be discovered, so if any defect exceeds allowable limits, then other defects should be assumed to be present elsewhere in the region), and
The criteria for deciding what actions should be taken when root cause analysis reveals conditions for which ECDA is not well suited.

## D.4.b - ECDADirect Examinations

- If Remaining Strength or Pf is less than  (MAOP) X (SF)
- Repair or Replace or Lower MAOP
- Consider Alternative Method for Assessing Region With Remaining Strength Concerns

| Reference: |  |
| --- | --- |
| §192.925(b)(3)(iii), 933, NACE RP-0502 §5.5 | FAQ-68 |

**Notes:**
Operators must define what the allowable limits for corrosion defects are for their pipe segments. This is defined as the maximum allowable operating pressure multiplied by an appropriate safety factor.   For defects whose remaining strength is below acceptable levels, alternative methods of assessing the pipe’s integrity must be considered for the entire region where the defect was found, unless it can be shown to be isolated or unique in a root cause analysis.  Defects discovered that meet the criteria specified in Section 933 must be remediated in accordance with those requirements, which are covered in Protocol E.

FAQ-68 provides guidance on  the consideration of tool tolerances when determining if a detected anomaly meets repair criteria.

## D.4.c, d - ECDADirect Examinations

- Root Cause Analysis
- Identify Underlying Root Cause for Each Significant Corrosion Area
- Formal Root Cause Analysis
- Remediation Activities
- Mitigate or Preclude Future Corrosion

| Reference: |  |
| --- | --- |
| §192.925(b)(3)(ii)(b), NACE RP-0502 §5.6.2, 5.7, 5.9.2 |  |

**Notes:**
It is extremely important for operators to have in place a formal root cause identification process, and its personnel be trained in the identification of root causes.  Root causes must be identified, and remediated to ensure the integrity of the pipeline. 

Inspectors will review the operators’ documentation to verify:
Procedures address requirements to perform formal root cause analyses on all significant corrosion activity,
Root cause analyses have been performed, and
Significant root causes have been mitigated to preclude future corrosion and ensure the integrity of the pipeline.  

## D.4.e - ECDADirect Examinations

- Perform an In-process Evaluation
- Evaluate Criteria Used to:
- Classify Severity of Indications
- Establish Priorities of Excavations
- On 1st Use, Classification and Prioritization Criteria May Not Be Relaxed

| Reference: |  |
| --- | --- |
| §192.933, NACE RP-0502 §5.7, 5.8 | FAQ-130 |

**Notes:**
Inspectors will review the operator’s documentation to verify that:

In process evaluation of Direct Examination data is used to reevaluate the criteria used to: 
Classify severity of indications, and
Establish priorities for direct examinations. 
And make adjustments to those criteria as necessary (Note: On 1st time use of ECDA, classification & priorities may not relaxed)

Operators should refer to FAQ-130 for discussion on whether modifications in criteria or changes to the ECDA plan requires notification to OPS. OPS need not be notified unless the changes substantially affect the total IM program's implementation or significantly modify an operator's overall IM program or the schedule for carrying out program elements identified in Section 909(b). Changes in the plans to conduct ECDA direct assessments on specific covered segments would not meet this threshold. 

## D.4.f, g – Changes in Plan & Time Frames

- Establish Basis for Changing:
- Classifications of Severity
- Priorities for Excavation Required
- Establish & Implement
- Internal Notifications of Changes
- Time Frame for Direct Examinations

| Reference: |  |
| --- | --- |
| §192.909, 911(k), 925(b)(3)(iii), (iv) |  |

**Notes:**
The gas integrity rule requires that each operator’s procedures include criteria that describes: how and on what basis an operator will :
make changes to its criteria for classifying severity, and
Make changes in the criteria for prioritization of indications

Operators must provide internal notifications for any changes in the ECDA Plan that affect the severity classification, priority of direct examination, and time frame for direct examination of indications.

Inspectors will review the operator’s documentation to verify it has procedures for each of these requirements.

##  D.4.h – Process for Defects other than EC

- Process for Defects Discovered Other Than External Corrosion
- i.e., ILI or Subpart J Test Methods for:
- Mechanical Damage
- Stress Corrosion Cracking
- Seam Weld  Issues

| Reference: |  |
| --- | --- |
| §192.933, NACE RP-0502 §5.1.5 |  |

**Notes:**
The NACE standard requires the operator to have a process to address conditions other than external corrosion found during the ECDA process.  The gas integrity rule requires that these other threats be assessed by means other than ECDA in accordance with rule requirements.

Under protocol D.4.h, inspectors will review the operators documentation to verify a process is in place to address conditions other than external corrosion found during the ECDA process.

## D.5 -  Post Assessment Objectives

- Determine Reassessment Intervals
- Assess Overall Effectiveness of the ECDA Process

| Reference: |  |
| --- | --- |
| §192.925(b)(4), 939 |  |

**Notes:**
The fourth and final step of the ECDA process is Post-Assessment.
The objectives of the post assessment step are to: 
Determine reassessment intervals, and
Assess the overall effectiveness of the ECDA process

## D.5.a -  Reassessment Intervals 

- Based on Worst Defect Found at a  Scheduled Indication
- Half of Calculated Remaining Life
- Corrosion Growth Rates
- Measured Data, *OR*
- Default Rate of 16 mil/yr (App D)

| Reference: |  |
| --- | --- |
| NACE RP-0502 § 6.1.2, 6.1.3, 6.2, 6.3 |  |

**Notes:**
Section 6.1.2 of the NACE standard requires that each operator define its reassessment intervals based on the most severe scheduled indication. This is because all immediate indications will be addressed during direct examinations, and monitored indications are expected to experience insignificant growth before the next assessment.

Section 6.1.3 of the NACE standard requires that each operator establish reassessment intervals based on one half the estimated true life of the pipe.  The purpose of basing reassessment intervals one half the true life estimate is to be conservative, since there are uncertainties in:
Remaining flaw sizes,
Maximum corrosion growth rates, and
Periods of a year in which defects grow due to corrosion.

 Inspectors will review the operator’s documentation to verify:
Remaining life calculations are based on:
Maximum flaw size is the worst defect found at a scheduled indication that was excavated
Corrosion growth rate based on measured corrosion rate data applicable to the region or use the default value in Appendix D3.2 of 16 mills per year, and  
Appropriate reassessment intervals are based on half the calculated remaining life

## D.5.b – Reassessment Interval Limits

- Intervals Must Not Exceed 192.939
- 10 Years if Above 50% SMYS
- 15 Years if Between 30 & 50% SMYS,
- 20 Years if Below 30% SMYS
- Direct Examination Results May Affect Re-Assessment Interval

| Reference: |  |
| --- | --- |
| §192.925(b)(4)(ii) | FAQ-197 |

**Notes:**
Maximum reassessment intervals for ECDA are also limited by the values established in the gas integrity rule section 939, as shown on this slide.  The gas integrity rule also requires operators procedures contain criteria for evaluating whether any conditions found during direct examinations in each ECDA region indicate a need for a reassessment interval less than that specified in section 939.  For example, if evidence of MIC is found during direct examination, the default corrosion rate may not be conservative and the appropriate reassessment interval may need to be less than the maximum allowed by the rule.

Inspectors will review the operators documentation to verify that:
The reassessment intervals provided in section 939 are not exceeded for the level of SMYS at which the ECDA region operates. and 
Operators’ direct exams have not discovered any conditions warranting more frequent reassessment intervals than specified in section 939.  

## D.5.c – Assessment of ECDA Effectiveness 

- Process Validation Dig(s)
- One Additional Direct Exam to Validate ECDA Process (2 If 1st Use of DA)
- 1 At a Scheduled Indication,
- 1 Where No Indication Was Found
- Re-Evaluate if Defects More Severe Than Expected

| Reference: |  |
| --- | --- |
| §192.925, 945(b), NACE RP-0502 §6, 6.4.2, 6.4.3 |  |

**Notes:**
The second objective of the post assessment step is to evaluate the effectiveness of the ECDA process.  Additional confirmation must be provided that the ECDA process has been successful.   

Inspectors will review documentation to verify that operators have established post assessment process effectiveness procedures which require an additional randomly selected direct examination. Two additional digs would be required for first time applications of ECDA on a segment. Examinations would include one direct exam at a “scheduled” indication and one direct exam where no indication was detected.

If the validation excavations find that defects are more severe than expected, which would result in reassessment intervals sooner than previously determined, the ECDA process has to be re-evaluated and repeated or an alternate assessment method used.

## D.5.c – Assessment of ECDA Effectiveness 

- Performance Measures
- Long Term Effectiveness of ECDA
- Controlling External Corrosion
- RP-0502 Suggests Measures
- Number of Reclassifications
- Trend the Number of Immediate and Scheduled Indications

| Reference: |  |
| --- | --- |
| §192.925, 945(b), NACE RP-0502 §6, 6.4.2, 6.4.3 |  |

**Notes:**
Another aspect of evaluating the effectiveness of the ECDA process involves identifying performance measures by which to monitor the long term effectiveness of ECDA at controlling the threat of external corrosion. 

The NACE standard suggests performance measures including:
Reliability or repeatability of process measures such as the number of reclassifications and reprioritizations (to evaluate severity and priority criteria), and
Frequency at which immediates or scheduled indications arise (whether corrosion is being managed effectively demonstrating improvement in the integrity of the pipeline). 

Inspectors will review the operator’s documentation to verify that the operator has procedures for addressing long term effectiveness of the ECDA process and has identified appropriate performance measures.

## D.5.d – ECDA Post Assessment

- Improve ECDA by Incorporating Feedback Throughout Process

| Reference: |  |
| --- | --- |
| §192.907(a), NACE RP-0502 §6.5 |  |

**Notes:**
The NACE standard requires the operator to improve ECDA by incorporating feedback throughout the ECDA processes as well as during scheduled activities and reassessments.

Inspectors will review the operator’s documentation to verify that opportunities for continued improvement of the ECDA process have been identified and that feedback has been evaluated and acted upon.

## Protocol Area D.1 through D.5 External Corrosion Direct Assessment 

**Conclusion – **
**Thank you for your attention**

**Notes:**
This concludes my presentation on the protocols for External Corrosion Direct Assessment. Thank you for your attention. 

##  Gas Integrity Management Rule Protocols 

**Clyde Myers**
**49 CFR 192.927**
**Internal Corrosion Direct Assessment**
**Protocols D.6 through D.10**
**January 2005**

**Notes:**
[Greeting to the audience. Introduce yourself and tell where you work or fit into the Gas IMP process]

In this portion of the presentation I’ll be going over the rule requirements and Protocols on Internal Corrosion Direct Assessment – or ICDA. The requirements I will be citing are in the regulation. As part of this review, I am going to tie those requirements with the inspection protocols that are going to be used. In addition, I will reference the published FAQ’s to further clarify the requirements. 

## Internal Corrosion Direct Assessment (ICDA)

**49 CFR 192.927**
**ASME B31.8S**

| Reference: |  |  |
| --- | --- | --- |
| §192.927 |  |  |

**Notes:**
Section 927 specifies the requirements for using Internal Corrosion Direct Assessment.  

This section only applies if an operator is using Internal Corrosion Direct Assessment as an assessment method for the internal corrosion threat. 

Section 927 specifies that operators using direct assessment for internal corrosion must follow the requirements in Section 6.4 and Appendix B2 of the Supplement.

##  Internal Corrosion Direct Assessment

- D.6	Dry Gas ICDA Programmatic Requirements
- D.7	Dry Gas ICDA Pre-Assessment
- D.8	Dry Gas ICDA Direct Examination
- D.9	Dry Gas ICDA Post-Assessment
- D.10	Wet Gas ICDA Programmatic Requirements

| Reference: |  |  |
| --- | --- | --- |
| §192.927 |  |  |

**Notes:**
Compliance with rule requirements will be verified through protocols D.6 through D.10. The 5 protocols are:

D.6 – Dry Gas Internal Corrosion Direct Assessment Programmatic Requirements
D.7 – Dry Gas Internal Corrosion Direct Assessment Pre-Assessment
D.8 – Dry Gas Internal Corrosion Direct Assessment Direct Examination
D.9 – Dry Gas Internal Corrosion Direct Assessment Post-Assessment
D.10 – Wet Gas Internal Corrosion Direct Assessment Programmatic Requirements

The following slides will review these protocols in more detail. As noted, the first 4 protocols address provision for Dry Gas Internal Corrosion Direct Assessment  and the last one addresses Wet Gas 

## D.6.a - Dry Gas (DG) ICDAPlan

- DG ICDA Plan per 192.927(c)
- Pre-Assessment
- ICDA Region Identification
- Identification of Locations for Excavation and Direct Examination
- Post Assessment

| Reference: |  |  |
| --- | --- | --- |
| §192.927(c) |  | FAQ-105, 147, 155, 193 |

**Notes:**
The rule requires operators to develop and follow an Internal Corrosion Direct Assessment plan. Protocol D.6.a will be used for inspection of the plan which must that provide for
Pre-assessment includes data collection; feasibility determination; and ICDA region determination.
Regions are determined by 
Analyzing gas inputs and other locations where flow characteristics change, and
performing steady state flow modeling calculations to determine the critical inclination angle of liquid holdup; and
producing a pipeline inclination profile; and 
integrating the flow model results with the pipeline data and inclination profile to determine locations that are the most likely to have internal corrosion 
Likely locations of internal corrosion include low points, such as drips and sags, along the upstream part of the region; and holdup locations predicted by the flow model.
Direct examination includes excavation and detailed examination of pipe at locations most likely to have internal corrosion.
Post assessment includes 
determination of the reassessment interval. 
an assessment of the effectiveness of the ICDA process, which requires additional excavations, and 

Inspectors will verify that operators have prepared a Dry Gas Internal Corrosion Direct Assessment plan that meets all of the provisions of Section 927 and section 6.4 and Appendix B2 of the Supplement..

## D.6.b - DG ICDAPlan Requirements

- DG ICDA Plan Requirements
- Criteria for Key Decisions
- DG ICDA Feasibility
- DG ICDA Region Identification
- Conditions Requiring Excavation
- Implementing Each DG ICDA Step

| Reference: |  |  |
| --- | --- | --- |
| §192.927(c)(5)(i) | FAQ-105, 127, 128, 147, 158 , 193 |  |

**Notes:**
Protocol D.6.b addresses requirements that each operator’s ICDA plan include criteria it will apply in making key decisions in implementing each stage of the Internal Corrosion Direct Assessment process. The plan must address each critical element and provide criteria for the decisions to address the requirements of Section 927 and Section 6.4 and Appendix B2 of the Supplement. Inspectors will review the specific criteria an operator applies in making key decisions for: 
The feasibility of applying ICDA – inspectors will see if there is sufficient data to apply Dry Gas ICDA and effectively use the flow model (inspectors will pay particular attention to key parameters such as pipe elevations, low points, road and river crossings, flow rates, gas pressure and temperature and pipe diameter);
The definition and criteria for identifying ICDA Regions – inspectors will review the basis upon which the end points of regions are determined; 
The criteria used to select locations for excavation
The criteria used in implementing each stage of the Dry Gas Internal Corrosion Direct Assessment process.

FAQ-105 and 147 addresses how to handle situations when there is a concern of a lack of complete data. FAQ-193 addresses the lack of an approved ICDA standard.

## D.6.c & d - DG ICDA

- DG ICDA Plan Requirements
- More Restrictive Criteria 1st Use
- DG ICDA Analysis Applied to Entire Pipeline
- If Corrosion is Found:
- Remediate Per 933, and
- Evaluate All Segments (Covered and Non-Covered Segments) With Similar Characteristics

| Reference: |  |  |
| --- | --- | --- |
| §192.927(c)(5)(ii), (iii) |  | FAQ-107 |

**Notes:**
The rule requires that a ICDA plans contain provisions for applying more restrictive criteria when conducting ICDA for the first time on a covered segment. In addition, the rule requires that the analysis be carried out on the entire pipeline in which covered segments are present.  If corrosion is found at any excavation, operators must not only remediate the condition, but evaluate the potential for internal corrosion in all pipeline segments (both covered and non-covered) that have similar characteristics.  FAQ-107 clarifies provisions that analysis be carried out on the entire pipeline.  Inspectors will check that ICDA plans include these requirements.

## D.7.a - DG ICDA Pre-Assessment

- Gather and Integrate Data
- Facility & Historical Data
- Information to Support Flow Model
- Gas Input and Withdrawal Points
- Low Points (Drips, Traps, etc.)
- Elevation Inclines
- Flow Rates
- Cleaning Pig Data

| Reference: | FAQ-104, 105, 126, |
| --- | --- |
| §192.927(c)(1)(i), (ii), (iii), (iv) | 127, 147, 158 |

**Notes:**
In the Preassessment step, the rule requires operators to gather and integrate facility data and historical data that includes (as a minimum) the data elements listed in Appendix A2 of the Supplement.

Inspectors will review the operator’s documentation to verify that the data gathering and integration process has included:
All data in Appendix A2 of the Supplement concerning facility, and historical information such as past upset conditions
Any other data needed to effectively conduct the ICDA process
Information necessary to support use of a flow model
Identification of each gas input and withdrawal point
Low points, elevation inclines and liquid hold-up features such as drips, traps, etc,
Range of flow rates, and 
How cleaning pigs may have been used.

Operators should review the FAQs associated with the data gathering and integration element of ICDA Pre-Assessment. There are several – 104, 105, 126, 127, 147, and 158.

## D.7.b - DG ICDA Pre-Assessment Data Analysis

- Integrated Data Analysis
- Determine DG ICDA Feasibility
- Identify DG ICDA Regions
- Support Use of a Flow Model
- Identify Where Liquids Are Entrained and Accumulate

| Reference: |  |
| --- | --- |
| §192.927(c)(5)(i) | FAQ-81, 105, 126, 127, 158 |

**Notes:**
The rule requires that each operator integrate and analyze its data to determine whether they have sufficient data to:
Perform the ICDA process – determine feasibility
Identify ICDA regions, and the locations where liquids may be entrained,
Support the use of a flow model, and
Apply the flow model to determine the critical angle for each region where electrolyte may accumulate 

It should be noted that the language in the rule requires the operator to use the flow model to identify “where internal corrosion may occur.”  The intent of this language is that the downstream end of the ICDA region is defined as the location where the critical inclination angle is first exceeded.  The specific requirements for selecting the minimum required dig locations are based on this approach.  It should be noted that the draft NACE standard on ICDA uses a different approach to define ICDA regions.  Operators that utilize the NACE standard on ICDA should be aware of this difference and ensure that they select dig locations that comply with the rule requirements. Inspectors will review the operator’s documentation to verify each of these critical data sets have been identified, collected and analyzed.  Good record keeping and accurate logs in data integration are important.

There are also several FAQs associated with integrated data analysis – FAQs 81, 105, 126, 127, and 158

## D.7.c - DG ICDA - Identify Excavation Locations

- Flow Model GRI 02-0057 Must Consider Changes In:
- Diameter, Gas Inputs and Withdrawals, Gas Velocity, Pressure and Temperature
- Identify Points of Water Accumulation
- Use of Other Flow Models
- Flow Model Not Needed if 100% of Region is Examined

| Reference: |  |  |
| --- | --- | --- |
| §192.927(c)(2) |  | FAQ-158 |

**Notes:**
The regulation specifies the Flow Model that must be used is GRI 02-0057, entitled  ‘‘Internal Corrosion Direct Assessment of Gas Transmission Pipelines—Methodology’’.   This model uses pipe diameter, gas inputs and withdrawals, gas velocity, and pressure, to define the critical pipe angle of inclination above which water film cannot be transported by the gas.  

If operators choose to use another model, the inspector will question if it is equivalent to GRI 02–0057.  Operators must be prepared to demonstrate how the other model was validated.

Note that if the entire region is excavated and directly examined, then application of a flow model is not required.  This may be a viable option for very short segments such as crossovers.

FAQ-158 addresses the use of both past and current operating conditions when using the Internal Corrosion Direct Assessment process.

## D.8.a - DG ICDA Identify Excavation Locations

- Site Selection and Direct Exam
- Integrate Critical Inclination Angle With Pipeline Inclination Profile
- Locate Likely IC Sites, Electrolyte Predicted

| Reference: |  |  |
| --- | --- | --- |
| §192.927(b), 927(c)(3) B31.8S §6.4  |  |  |

**Notes:**
The gas integrity rule requires the operator to identify locations where Internal corrosion is likely to exist, and where electrolyte accumulation is predicted. To accomplish this, flow-modeling results must be integrated with the pipeline inclination profile to identify likely internal corrosion excavation sites such as locations prone to liquid hold-up. Modeling should include consideration of inclination angles at road crossings, rivers, drainage ditches, etc. For operators doing 100% visual examination, no sites need be identified since the entire Internal Corrosion Direct Assessment Region will be excavated. The operator’s Internal Corrosion Direct Assessment plan must include these elements. Protocol D.8.a will be used by inspectors to verify operators programs provide for these provisions. 

## D.8.b - DG ICDADirect Examination

- Direct Examination Using UT, Radiography, or Other Techniques
- A Min. 2 Locations/DG ICDA Region
- 1st at Low Point Nearest Beginning
- 2nd Downstream Near End

| Reference: |  |  |
| --- | --- | --- |
| §192.927(c)(2), (3) B31.8S §6.4.2 |  |  |

**Notes:**
Operators must perform a direct examination for internal corrosion at each excavation, using ultrasonic thickness measurements, radiography, or other generally accepted measurement techniques performed by qualified individuals. 
The Internal Corrosion Direct Assessment Plan must include requirements that at a minimum of 2 locations be examined for each ICDA Region. 1 location must be the low point in the region and the second location must be further downstream near the end of the ICDA region.  As a reminder, the end of the ICDA region is considered to be the first downstream location where the critical inclination angle is exceeded.  Therefore, this in effect, requires that the excavation be made near the critical angle of inclination. 

At least two locations in each ICDA region within a covered segment must be selected:
One location at a low point near the beginning of the region, and
The one location along the onset of the slope of the critical angle further downstream, 

Protocol D.8.b will guide OPS inspectors to verify operators meet these requirements.

## DG ICDA - Identify Excavation Locations

**Critical Angle of Inclination**

**DG ICDA Region**

**Flow**

**First Low Point**
**In **
**ICDA Region**

**Notes:**
This slide represents a DG ICDA region with flow left to right. If there were a low point on the upstream side of the ICDA region, possibly a river crossing, or a drip, trap, or dead leg nearer the beginning of the region, then this would be one location that must be excavated. The second excavation location is determined by the flow model.   Water accumulation will occur on the uphill sections of pipe (in the direction of flow) where the critical angle of inclination has been exceeded. Thus, these are the areas that need to be excavated to determine if internal corrosion has been occurring. 

## D.8.c - DG ICDADirect Examination

- If Corrosion Exists
- Evaluate Severity & Remediate
- Perform Additional Excavations or Use Alternative Assessment for Internal Corrosion
- Evaluate Similar Pipe (Both Covered and Non-Covered)

| Reference: |  |  |
| --- | --- | --- |
| §192.927(c)(3)(i), (ii), (iii) |  | FAQ-132 |

**Notes:**
If internal corrosion is found, then the severity and remaining strength of the pipe must be evaluated, and the defect must be remediated in accordance with rule section 933. 
Also, additional excavations must be performed or else a different assessment method must be performed such as ILI or hydrostatic pressure test.
Additionally, pipe with similar characteristics must be evaluated in the operators system – for both covered and non-covered segments.
Inspectors will review excavation and repair records to check for compliance with these requirements.  If corrosion was discovered, inspectors will check follow-up documentation to see that the extent of internal corrosion was properly investigated.

For additional background on direct examination, operators should refer to FAQ-132.

## D.9.a - DG ICDA Post Assessment

- Post Assessment Evaluation and Monitoring- Objectives
- Evaluate Effectiveness of DG ICDA
- Reassessment Intervals

| Reference: |  |  |
| --- | --- | --- |
| §192.927(c)(4), 939(b), B31.8S App B.2 |  | FAQ-132 |

**Notes:**
The fourth and final step of the ICDA process is the post-assessment evaluation step as addressed by Protocol D.9.   Section 927 of the Rule requires operators to evaluate the effectiveness of the process and determine reassessment intervals within 1 year from the time the ICDA was completed. To accomplish this objective, the operator must perform one or more additional digs at predicted downstream water accumulation sites with inclination angles greater than the critical angle. If internal corrosion is found in areas downstream of the first location where the pipeline inclination angle is exceeded, then the critical inclination angle needs to be re-evaluated and additional areas selected for local examination to evaluate the nature and extent of the problem.

When determining reassessment intervals, a conservative approach is to be applied since the process may not discover all locations of internal corrosion. The reassessment interval may not be longer than that specified in the Supplement.

FAQ-132 addresses how to determine a new reassessment schedule if defects requiring remediation are identified using ICDA during a Confirmatory Direct Assessment.

## DG ICDA Post Assessment

**Direct Exam Location**

**Location of Additional Dig For Post Assessment**

**Critical Angle of Inclination**

**Notes:**
The Supplement requires operators to perform one or more additional excavations at predicted downstream water accumulation sites with inclination angles greater than the critical angle. 

This slide shows the identification of a critical inclination angle along the pipeline at the yellow arrow on the right, that is greater than the original estimated critical angle at the green arrow on the left, for the purpose of performing a validation examination. 

## D.9.b - DG ICDA Post Assessment

- Post Assessment Monitoring Where IC Has Been Identified:
- Continual Monitoring Required
- Frequency of Monitoring Based on Results of All Integrity Assessments
- Risk Factors of Segment

| Reference: |  |  |
| --- | --- | --- |
| §192.927(c)(4)(ii), B31.8S App A.2 |  |  |

**Notes:**
Section 927 requires the continued monitoring of Internal Corrosion areas where internal corrosion has been identified using techniques such as coupons, UT sensors or electronic probes, periodically drawing off liquids at low points and chemically analyzing the liquids for the presence of corrosion products. 

Operators must base the frequency of the monitoring and liquid analysis on results from all of their integrity assessments that have been conducted in accordance with this integrity rule, and risk factors specific to the covered segment.  If the information provides reason to be concerned about a particular location, or the risk associated with that location is higher, then the operator’s process should require monitoring of the location more frequently.

In cases where evidence of internal corrosion has been discovered, inspectors will pay particular attention to the operator’s program it has established to continually monitor the internal corrosion threat.

## D.10 - ICDA for Wet Gas

- If Operator Elects ICDA for Wet Gas the Operator Must:
- Develop a Plan to Effectively Address Internal Corrosion
- Provide Notifications to OPS 180 Days Prior

| Reference: |  |  |
| --- | --- | --- |
| §192.927(b), (c) |  | FAQ-127 |

**Notes:**
For those contemplating using Internal Corrosion Direct Assessment for wet gas pipelines (and pipelines that once transported wet gas), OPS considers wet gas Internal Corrosion Direct Assessment as the use of “other technology.”  An operator choosing this option must notify the Office of Pipeline Safety (OPS), as well as any State agency if applicable, at least 180 days before conducting the assessment, in accordance with Section 949. 

FAQ-127 addresses the use of Internal Corrosion Direct Assessment processes for pipelines with electrolytes present.

## Protocol Area D.6 – D.10 Internal Corrosion Direct Assessment

**Conclusion – **
**Thank you for your attention**

**Notes:**
That concludes my presentation for Internal Corrosion Direct Assessment Protocols.  

Thank you for your attention.

## Gas Integrity Management Rule Protocols

**Clyde Myers **
**49 CFR 192.929 **
**Stress Corrosion Cracking Direct Assessment**
**Protocols  D.11 and D.12**
**January 2005**

**Notes:**
[Greeting to the audience. Introduce yourself and tell where you work or fit into the Gas IMP process] 

I will be discussing the gas integrity management protocols D.11 and D.12, for inspecting a Stress Corrosion Cracking Direct Assessment Plan. This section of the inspection protocols only applies to those operators planning on using SCCDA. The rule provides that direct assessment may be used as an integrity assessment method for stress corrosion cracking, and incorporates by reference Appendix A-3 of the Supplement. 

Last month NACE adopted its standard on SCCDA, RP0204 which provides some further guidance, and detail in addressing a structured SCCDA method for both high and near neutral pH SCC, however, currently only the B31.8S standard has been incorporated by reference within the Gas IMP rule. The inspection protocols rely on the requirements currently contained in the gas integrity rule and in B31.8S.

 Regarding the requirements in the standards incorporated by reference, inspectors will be looking to see that all incorporated requirements are met, and that the more stringent requirement is addressed if requirements differ between the rule and the standard. 

## SCCDA

- High pH SCC
- SCCDA Plan Must Meet B31.8S Appendix A3
- D.11 – SCCDA Data Gathering & Evaluation
- D.12 – SCCDA Assessment, Examination, & Threat Remediation

**Notes:**
The gas integrity rule defines Stress Corrosion Cracking Direct Assessment (SCCDA) as a process to assess a covered pipe segment for the presence of SCC primarily by systematically gathering and analyzing excavation data for pipe having similar operational characteristics and residing in a similar physical environment.  SCC is a general term that covers both high-pH and near-neutral pH SCC. 

With regard to high-pH SCC, Appendix A3 of the Supplement provides a process by which to assess the threat. Protocols D.11, SCCDA Data Gathering & Evaluation, and D.12, SCCDA Assessment, Examination, & Threat Remediation, focus on high pH SCCDA.

## SCCDA

- Near-Neutral pH SCC
- Plans Reviewed on a Case-by-Case Basis

| Reference: |  |  |
| --- | --- | --- |
|  |  | FAQ-97, 98, 99 |

**Notes:**
With regard to near-neutral SCC, the Supplement acknowledges the threat of near-neutral SCC and states that the threat of near neutral pH SCC similarly requires an inspection and mitigation plan.   However, the Supplement does not provide explicit guidance for operators to follow.  If an operator identifies the threat of near-neutral SCC on its pipeline, and if it chooses to assess the threat using SCCDA and develops its own process for doing so, then OPS will review the plan on a case-by-case basis. 

FAQs-97, 98, and 99 provide information regarding alternative plans and associated notifications to OPS.

## SCCDA Plan (High pH)

- SCCDA Plan Must Address:
- Data Gathering, Integration (D.11)
- Data Collected at All Excavations Meeting SCC Likelihood Criteria
- Including Non-Covered Segments
- Assessment, Examination, & Threat Remediation (D.12)

| Reference: |  |  |
| --- | --- | --- |
| §192.929(b) |  | FAQ-128 |

**Notes:**
The SCCDA Plan for high pH SCC must address as a minimum 2 steps:
1) Data gathering, integration and evaluation of data from at all pipeline excavations meeting the SCC likelihood criteria (not just those in covered segments). 
2) The second step focuses on the assessment method, which could involve pressure testing, assessment, excavations, direct examinations, evaluation and threat remediation.

The inspectors will review the operator’s documentation to verify that the SCCDA Plan includes these steps.

Note that FAQ-128 clarifies the consideration of portions of pipelines not in high consequence areas. The rule requires that operators using SCCDA systematically gather and analyze excavation data for pipe at all sites an operator excavates during the conduct of its pipeline operations where the criteria in ASME B31.8S, appendix A3.3 indicate the potential for SCC. Relevant data from pipe not in covered segments must be considered in this process. 

## D.11.a - SCCDA Data Gathering & Integration

- Systematic Process to Collect, Integrate, and Evaluate Data
- Evaluate & Identify SCC Segments
- Prioritize Assessments

| Reference: |  |  |
| --- | --- | --- |
| §192.929(b)(1)ASME B31.8S App A.3.3 |  | FAQ-223 |

**Notes:**
Protocol D.11.a focuses on data gathering and integration. The rule requires each operator to have a systematic process to collect and evaluate data for each covered segment.  The purpose is to:
Determine if conditions for the high pH SCC threat are present, and if so to
Prioritize the covered segments for assessment.
FAQ-223 addresses the kind of information that must be collected to use stress corrosion cracking direct assessment process.

## D.11.a - SCCDA Data Gathering & Integration

- Minimum Data Set (Appendix A3)
- Age of Pipe,
- % SMYS,
- Operating Temperature,
- Distance From Compressor Station,
- Coating Type,
- Past Hydro Information,
- If Data is Missing
- Use Conservative Assumptions

| Reference: |  |  |
| --- | --- | --- |
| §192.929(b)(1)ASME B31.8S App A.3.3 |  |  |

**Notes:**
The minimum data which must be collected for each segment includes:
 1) Age of pipe
 2) Operating stress level (%SMYS)
 3) Operating temperature
 4) Distance of segment from a compressor station
 5) Coating type
 6) Past hydrotest information for reasons other than SCC investigation.

If data is missing operators must assign conservative values or higher priorities for assessment.

## Screening Criteria for High-pH SCC Susceptibility

- Segment Experienced in Service or Hydro Test SCC Leak or Rupture, OR
- Susceptible to High pH SCC if Segment Meets All Criteria:
- Stress > 60% SMYS
- Historic Temp > 100°F
- < 20 Miles Downstream of Compressor
- > 10 Years Old
- Coating Other Than Fusion Bonded Epoxy

**Notes:**
If a pipeline segment has experienced an in service incident or a hydrostatic test leak or rupture caused by SCC, the pipeline segment must be further evaluated unless the conditions that led to the SCC have been corrected. 

For pipelines that have never experienced an SCC failure, a pipeline segment is considered susceptible to high-pH SCC if all of the following 5 criteria are met.
The operating stress exceeds 60% of specified minimum yield strength.
The historic operating temperature exceeds 100o F.
The segment is less than 20 miles downstream of a compressor station.
The pipeline is more than 10 years old.
The coating type is other than fusion-bonded epoxy.

## D.12.a - SCCDA Assessment Method

- Assessment Method Required
- Bell Hole, or
- Hydro Test Program
- Written Inspection, Examination, and Evaluation Plan

| Reference: |  |  |
| --- | --- | --- |
| §192.929(b)(2) |  |  |

**Notes:**
Inspectors will review the operator’s documentation to verify that each segment identified as meeting the 5 screening factors for high pH SCC risk has a written Inspection, Examination, and Evaluation Plan as required by the Supplement.

The rule requires that the operator must assess the covered segment using one of two methods specified in Appendix A3 of the Supplement. 

Those methods are;
The bell hole examination and evaluation method, or
The hydrostatic testing method. 

If defects are found, operators must remediate the threat in accordance with Appendix A3.4 of the Supplement.

## D.12.b – Factors in Selecting Dig Sites

- Bell Hole Examination & Evaluation
- Identify Criteria for Dig Site Selection
- History of SCC in Area
- Mechanical Damage, Dents, Soils/Moisture, Steep Slopes
- Coating Anomalies
- General Corrosion
- Other Integrity Threats Present in Segment
- Greatest Stress, Pressure Fluctuations, and Highest Temperatures

| Reference: |  |  |
| --- | --- | --- |
| §192.929(b)(2) |  |  |

**Notes:**
For Bell Hole Examination & Evaluation Process, the first action is to identify Criteria for Dig Site Selection and determine the sites for direct examinations. Factors to consider in selecting sites to dig include
1. 	If there is a history of SCC in the area of interest (e.g., service failures, hydrostatic test failures, ILI indications, or previous digs) dig near the previous locations of SCC. Industry experience indicates that there is a higher probability of SCC occurring near other places where it has been found.
2.	If previous SCC locations have been associated with unique characteristics of the pipe, dig in other areas with those characteristics.  Some pipeline companies have found correlations with areas of mechanical damage such as dents; geophysical features such as soil moisture, drainage, or soil type, steep slopes with soil subsidence; or coating anomalies.
3.	If there is no history of SCC in the area of interest, locations with coating anomalies should be considered.  For non-shielding coatings, such as coal tar or asphalt, these areas might be identified from a close-interval survey (CIS) or a coating-fault survey.
4.	If ILI tools have been run in pipe with shielding coatings (such as polyethylene tape) and there is no history of SCC in the area, locations of dents or general corrosion should be considered. 
5.	In the absence of any other suitable indicators, select locations where the stresses, pressure fluctuations, and temperatures are highest.
6.	For subsequent digs in the same area, sites should be selected that have the same unique features that were revealed in earlier digs, if there were any.  If not, select other areas where stresses, pressure fluctuations, and/or temperatures were relatively high

## D.12.b - Bell Hole Assessment Method

- Direct Examination for SCC
- Including Areas of Coating Disbondment
- Magnetic Particle Inspection

| Reference: |  |  |
| --- | --- | --- |
| §192.929(b)(2) |  |  |

**Notes:**
After dig locations have been specified, operators must excavate and directly examine the pipe for SCC.  Inspectors will review the operator’s direct examination procedures and records to verify that they address:
Examination of the pipe for SCC, including addressing areas of coating disbondment,
Pipe must be inspected using magnetic particle inspection (MPI) with a documented inspection procedure.

## D.12.b - Bell Hole Assessment Method

- If No SCC Indication:
- Define Re-Evaluation Interval
-  Mitigate SCC Indications:
- Hydro Test Valve Section for SCC
- Evaluate Repair/Removal/Test
- Engineering Critical Assessment

| Reference: |  |  |
| --- | --- | --- |
| §192.929(b)(2) |  |  |

**Notes:**
1) If no SCC is found, identify a re-inspection interval for additional bell hole inspections.
2) If SCC indications are identified, one of the following three mitigation methods shall be used.
	i) Evaluate repair or removal methods for SCC.  Industry research such as PR-218-9307 addresses repair methods for SCC; or
	ii) Conduct a hydrostatic test of the affected valve section per Appendix A3.4 of the Supplement; or
	iii) An Engineering Critical Assessment may be conducted to evaluate the risk and identify any further mitigation methods.

## D.12.b - Hydro Test Assessment Method

- Hydrotest Method B31.8S A3.4
- Long Term Mitigation
- Hydrostatic Retest Program
- Engineering Critical Assessment (ECA)
- If Hydrotest Failure Due to SCC:
- Engineering Critical Assessment Must Demonstrate Safety
- Consider Defect Growth Mechanisms

| Reference: |  |  |
| --- | --- | --- |
| §192.929(b)(2) |  |  |

**Notes:**
If the Bell Hole Examination & Evaluation is not used, Appendix A3 of the Supplement requires the operator to apply the hydrostatic testing method for SCC described in Section A3.4(b) of the Appendix.  This method is designed to optimize the removal of critical sized flaws while minimizing growth of sub-critical sized flaws. 

Inspectors will review operator’s procedures for conducting hydrostatic tests for compliance with the requirements of Appendix A3.4:
The operator shall use one of the following two options to address long term mitigation of SCC. 
1) Implement a written Hydrostatic retest program or other inspection program with a technically justifiable interval, or
2) Perform an Engineering Critical Assessment to evaluate the risk and identify whether further mitigation methods are necessary.  This may result in a further hydro retest program, some other periodic inspection program or possibly no action. 

If a leak or rupture due to SCC occurred, the Engineering Critical Assessment must provide a technically defensible plan demonstrating satisfactory pipeline safety performance that considers defect growth mechanisms.

For speaker’s information: An Engineering Critical Assessment – A written document that evaluates the risks of SCC and provides a technically defensible plan that demonstrates satisfactory pipeline safety performance.  The document shall consider the defect growth mechanisms of the SCC process.

## D.12.b – SCC In-Service Leak or Rupture

- If In-Service Leaks or Ruptures Are Attributed to SCC
- Implement Hydrotest Program in ASME B31.8S Appendix A3.4(b)
- Written Plan
- Hydro Test within 12 Months
- No Other Test Medium Permitted

| Reference: |  |  |
| --- | --- | --- |
| §192.929(b)(2) |  |  |

**Notes:**
Appendix A3 of the Supplement requires each operator to have procedures to address pipeline segments which experience an SCC service failure caused by SCC.  The process must provide that each such segment:
Have a written inspection, examination, and evaluation plan prepared, and
Be evaluated by the hydrostatic test method within 12 months of the incident or test failure. 
Hydrostatic pressure testing is required, use of other test mediums is not permitted.

Inspectors will review the operator’s documentation to verify that procedures address these requirements. 

## D.12.c - SCCDA Reassessment Intervals & Performance Measures

- Assessment Results Determine Reassessment Intervals
- Hydro Retest Program
- Engineering Critical Assessment

| Reference: |  |  |
| --- | --- | --- |
| §192.939(a)(3) |  |  |

**Notes:**
The Supplement requires the operator to determine technically justifiable re-assessment intervals for long term mitigation of SCC. 

Under protocol D.12.c, inspectors will review the operator’s documentation to verify that technically justifiable re-assessment intervals for long term mitigation of SCC are identified in the SCCDA Plan, and that the operator:
Implements a written Hydrostatic retest program with a technically justifiable interval, or  
Performs an Engineering Critical Assessment (ECA) which evaluates the risks of SCC and provides a technically defensible plan demonstrating satisfactory pipeline safety performance.  The ECA must consider the defect growth mechanisms of the SCC process. 

## D.12.c - SCCDA Reassessment Intervals & Performance Measures

- Establish Performance Measures
- No. of SCC In-Service Leaks/Failures
- No. of SCC Repair or Replacements
- No. of SCC Hydrostatic Test Failures

| Reference: |  |  |
| --- | --- | --- |
| §192.929(b) |  |  |

**Notes:**
Lastly, Appendix A3.6 of the Supplement requires the operator to establish SCCDA performance measures.

The purpose of the measures is to determine the effectiveness of the program and to confirm the re-inspection interval.

Inspectors will review operator’s documentation to verify:
Performance measures have been established as follows:
Number of SCC in-service leaks/failures,
Number of SCC repair or replacements, and
Number of SCC hydrostatic test failures.

Inspectors will also verify that a process has been established to gather the data and monitor the program’s performance.

##  Protocol Area D.11 & D.12 SCC Direct Assessment 

**Conclusion – **
**Thank you for your attention**

**Notes:**
That concludes my presentation on the protocols for Stress Corrosion Cracking Direct Assessment.

Thank you for your attention.

## Gas Integrity Management Rule Protocols 

**John Pepper**
**49 CFR 192.931**
**Confirmatory Direct Assessment**
**Protocol G**
**January 2005**

**Notes:**
[Greeting to the audience. Introduce yourself and tell where you work or fit into the Gas IMP process] I will be discussing CDA, how the code allows its use and the associated Confirmatory Direct Assessment Inspection Protocols.

When Congress passed the Pipeline Safety Act of 2002 they mandated that all gas pipelines located in HCAs must be assessed no later than December 17, 2012. In addition, they mandated that all pipelines be assessed every 7 years after the initial assessment. CDA, or Confirmatory Direct Assessment, is a method operators may use to address 2 threats: internal and external corrosion. The Supplement and Section 939 permit full assessments for pipeline segments under certain operating conditions to be accomplished at intervals up to 20 years.  For example, an operator having a covered segment operating at less that 30% SMYS that has removed all indications, may schedule the next full assessment 20 years after the baseline assessment. At years 7 and 14, a CDA may be used for internal and external corrosion threats thus meeting the 7 year assessment requirements as long as the only threats are internal and external corrosion.  Of course the operator may perform a full assessment at the seven year intervals instead of a CDA. For other threats, other assessment methods must be used in accordance with section 935.

CDA may be used as the interim assessment method regardless of the method used for the baseline assessment, such as ILI or pressure testing or direct assessment. Inspectors will use protocol G for inspection of operators’ CDA programs.  Protocol G consists of one question with 4 sub-questions.

## G.1.a - Confirmatory Direct Assessment

- CDA Only Allowed for 2 Threats
- Internal and External Corrosion
- CDA is Used as:
- Interim Re-assessment Method  Must Follow a Plan Which Meets
- 192.931 (CDA) and
- 192.927 (ICDA) for IC,  and
- 192.925 (ECDA) for EC

| Reference: |  |
| --- | --- |
| §192.931(a) | FAQ-131 |

**Notes:**
The gas integrity rule requires that each operator planning to use CDA, develop a Plan that meets the requirements contained in  section 925 for external corrosion direct assessment and section 927 for internal corrosion direct assessment.  Inspectors will verify that CDA is applied only for the threats of external and internal corrosion.

For those operators using CDA as the interim assessment method at the seven year interval, inspectors will be looking for operators to have a CDA Plan which:
Meets all of the requirements in Sections 925 and 927,
Limits the plan’s application to external and internal corrosion threats, and
Addresses other threats by other assessment methods.

Section 192.931 provides specific guidance for what steps a CDA must contain. 

FAQ-131 addresses the use of confirmatory direct assessment (CDA) for stress corrosion cracking. In short, CDA may not be used to address stress corrosion cracking. The rule specifies that CDA can only be used for external and internal corrosion.

## G.1.b - Confirmatory Direct Assessment - External Corrosion

- CDA for External Corrosion Must Meet §192.925
- Exceptions:
- Only 1 Indirect Exam Tool is Required
- Direct Examination (Each ECDA Region)
- All Immediate Action Indications
- Only 1 High Risk Indication Meeting Scheduled Action Must be Excavated

| Reference: |  |
| --- | --- |
| §192.931(b), 925 |  |

**Notes:**
The gas integrity rule requires that each operator using CDA for external corrosion must ensure their CDA Plan meets all of the requirements of the four step process outlined in Section 925 (Protocols D.1 through D.5) and in the NACE standard.  Each requirement in Section 925 and each requirement in the NACE standard must be accomplished just as it would in a baseline assessment.  

There are two exceptions to this.  

1. Only one indirect inspection tool is required. The data obtained from this one tool still must be integrated with data obtained in the pre-assessment step and any data obtained during prior assessments.

2.  In addition to excavating all immediate indications, a minimum of one high risk scheduled indication must be excavated and evaluated in each ECDA region. 

## G.1.c - Confirmatory Direct Assessment - Internal Corrosion

- Internal Corrosion Plan
- Must Meet §192.927 (ICDA)
- Exception: Only 1 High Risk Location in Each ICDA Region Must be Excavated
- Use RP-0502 to Determine Reassessment Interval (Half of Remaining Life)

| Reference: |  |
| --- | --- |
| §192.931(c), 925 |  |

**Notes:**
The rule requires that each operator using CDA for internal corrosion must ensure that they follow the four step ICDA process outlined in Section 927 (Protocols D.6 through D.9) and in the Supplement, section 6.4 and Appendix B2. All requirements of each step of the process must be completed just as it would in a baseline assessment. One exception is provided for ICDA.  That exception is that only one excavation is required in each ICDA region.

Even though CDA may be used for internal corrosion, any internal corrosion defect that is discovered must be analyzed using Section 6.2 and 6.3 of the NACE standard to determine the next assessment schedule. Any defect discovered during the CDA process requiring remediation prior to the next scheduled full assessment high risk indication must be evaluated applying the remaining life and half life calculations contained in sections 6.2 and 6.3 of the NACE standard .

Also, the operator must schedule the next assessment in accordance with these calculated reassessment interval results.

## G.1.d - Confirmatory Direct Assessment

- If Defects Require Near-Term Remediation
- Immediate or Scheduled Defects
- Recalculate Remaining Life & Reassessment Interval
- Immediate Defects
- Reduce Pressure Per §192.933
- Maintain Pressure Reduction Until a  “Full” Assessment is Conducted

| Reference: |  |
| --- | --- |
| §192.931(d) | FAQ-131, 132, 133, 228 |

**Notes:**
Inspectors will also review the operators documentation to verify that operators have remediated  all immediate defects, and have rescheduled reassessment intervals if such defects are discovered. 

Should an operator discover an immediate defect, inspectors will review documentation to ensure steps were taken to make the covered segment safe, including pressure reductions if required by Section 933.

Note that if a defect found using CDA meets any criteria for an immediate condition in Section 933(d)(1), then the operator must immediately reduce pressure and maintain the pressure reduction until an assessment is conducted using one of the methods specified in section 921.  This requirement means that such an assessment must be completed within one year, since the pressure reduction may not remain in effect for more than a year, unless other steps are taken as described in Section 933.

FAQ-132 addresses how to determine a new reassessment schedule if defects requiring remediation are identified using DG ICDA during a CDA assessment.

FAQs 131, 133, and 228 address additional aspects related to the CDA process.

## Protocol Area G -Confirmatory Direct Assessment Protocols 

**Conclusion – **
**Thank you for your attention**

**Notes:**
This concludes my presentation on Confirmatory Direct Assessment - Thank you for your attention.

## Gas Integrity Management Rule Protocols

**Jeff Gilliam**
**49 CFR 192.933**
**Remediation - Protocol E**
**January 2005**

**Notes:**
[Greeting to the audience. Introduce yourself and tell where you work or fit into the Gas IMP process...] 

For the next few minutes, I will be discussing the gas integrity management protocols for inspecting Remediation activities.

This presentation addresses Protocol E and section 933 of the rule.

## Key Elements Remediation

- E.1	Discovery and Evaluation
- E.2	Classification and Remediation
- E.3	Operator Response when Timelines Cannot be Met
- E.4	Record Review for Discovery, Repair and Remediation Activities

**Notes:**
The protocols for Remediation activity inspection address the following key areas:
Process for discovery and evaluation of anomalies identified during the assessment process
Process used to classify and remediate these anomalies
Operator responses when the timeframes specified by the Rule for anomaly evaluation and remediation cannot be met, and
Review of the discovery, repair and remediation records.

## E.1 – Discovery, Evaluation & Remediation Scheduling

- Define Discovery
- Document Discovery Date
- Remediation Schedule
- Deviations Allowed as a Result of Exceptional Performance

| Reference: |  |  |
| --- | --- | --- |
| §192.933(a) |  | FAQ-56, 58, 65, 215 |

**Notes:**
Protocol E.1 is directed at reviewing Integrity Management Program documentation for requirements associated with anomaly discovery and evaluation.  Sub-protocol items address inspection for the following:
Definition of when an anomaly that threatens pipeline integrity has been discovered.
A requirement to record the date of discovery for each anomaly.
The process and criteria for developing a remediation schedule, and
When an operator maintains qualification as an Exceptional Performer, documentation of the process to be followed when deviating from remediation timelines specified by the Rule.

Operators should refer to FAQs 56, 58, 65 and 215 which provide additional clarification on discovery, evaluation, and remediation scheduling.

## E.1.a - Discovery

- Process Used to Evaluate Assessment Results and Discover Anomalies
- Discovery Definition Based on Operator’s Processes

| Reference: |  |  |
| --- | --- | --- |
| §192.933(b) |  | FAQ-58 |

**Notes:**
Protocol E.1.a will be used by inspectors to examine an operator’s discovery process.  The operator’s Integrity Management Program procedures or program documentation must contain a definition of what constitutes “discovery” of an anomaly that threatens pipeline integrity.  Each operator is expected to have its own process of technical evaluation and review of assessment information that results in identification or discovery of anomalies.  Integrity Management Program documentation should detail this process.  Appropriate operator approvals should be part of the process.  FAQ-58 has information on what constitutes discovery.

FAQ-58. What constitutes "discovery of a condition"?  Answer: Discovery of a condition occurs when an operator has adequate information about the condition to determine that it presents a potential threat to the integrity of the pipeline. Depending on circumstances, an operator may have adequate information when the operator receives the preliminary internal inspection report, gathers and integrates information from other inspections, or when an operator receives the final internal inspection report. Operators are required to obtain sufficient information about a condition to make this determination no later than 180 days after an integrity assessment, unless the operator can demonstrate that the 180-day period is impractical.

## E.1.b – Date of Discovery

- Program Must Require Date of Discovery be Documented
- Applies to All Assessment Methods
- Begins the Remediation Time Clock
- 180-Day Discovery Phase

| Reference: |  |  |
| --- | --- | --- |
| §192.933(b) |  | FAQ-232 |

**Notes:**
Once the condition has been “discovered,” the discovery date must be documented.  This date serves as the start date for required remediation timelines.  The operator’s program documentation is expected to state the need for recording the date of discovery.  

The discovery process must be completed within 180 days of completion of the pipeline’s integrity assessment.  For ILI assessments, this means 180 days after the date the pig was pulled from the trap.  If multiple pig types are used for an entire assessment and the different types of pigs are pulled from the trap on different dates, then different 180-day timelines apply.

## E.1.c – Prioritized Remediation Schedule

- Prioritized Schedule for Remediation of Anomalous Conditions
- Technical Evaluation
- Apply Criteria from Rule and B31.8S

| Reference: |  |  |
| --- | --- | --- |
| §192.933(c) |  | FAQ-215 |

**Notes:**
Protocol E.1.c is focused on the need for a prioritized remediation schedule.  Based on technical evaluation of assessment information and application of criteria from Section 933 and the Supplement, the operator must develop a schedule for anomaly remediation.  Program documentation is expected to describe how this schedule is prepared, where it can be located, and procedures for updating the schedule.

## E.1.d – Exceptional Performance Schedules

- Must First Meet the Requirements of Section 192.913(b)
- Justification for Pipeline Integrity Not Being Jeopardized

| Reference: |  |  |
| --- | --- | --- |
| §192.913(c)(2) |  |  |

**Notes:**
Protocol E.1.d only applies to operators using the performance-based approach and also qualifies as an “exceptional performer.”  In these cases, operators may deviate from the schedule requirements cited in the Rule for anomaly remediation, providing the operator demonstrates that the safety of the covered pipeline segment is not jeopardized.  If the operator does not meet Section 913(b) requirements for being designated as an exceptional performer, or if the basis of safety is not documented, the timeframes specified by Section 933 apply as written.

## E.2 – Requirements for Identifying Anomalies

- Pressure Reductions or Shutdown
- Classification Criteria
- Immediate Conditions
- One-Year Conditions
- Monitored Conditions
- Subsequent Monitoring Actions
- Other Threat Conditions

| Reference: | FAQ-56, 62, 66, 67, 68, 69 |  |
| --- | --- | --- |
| §192.933(c), (d) |  | 70, 134, 135 |

**Notes:**
Protocol E.2 is directed at the classification of anomalies and remediation activities.  When immediate repair conditions are discovered, the Rule requires a pressure reduction or shutdown of the line until repairs are complete.  In addition, there are classification criteria that operators are expected to apply to discovered anomalies to determine if they fit in one of the following categories:
Immediate Conditions
One-Year Conditions, and
Monitored Conditions

When classifying a condition as one that is suitable for monitoring, the operator must record and monitor the condition during subsequent risk assessments and integrity assessments to identify any changes that indicate the need for remediation.  Threat conditions that do not meet the special conditions specified in Section 933 must be completed on a timeframe consistent with provisions of the Supplement.

Operators should review the FAQs for additional information related to Classification and Remediation requirements.

## E.2.a – Pressure Reductions/Shutdowns

- Applies to All Immediate Threat Conditions
- Determining Pressure Reduction
- ASME B31.G
- RSTRENG
- 80% of Operating Pressure at Time of Discovery (Not MAOP)

| Reference: |  |  |
| --- | --- | --- |
| §192.933(d)(1) |  | FAQ-134, 181, 215, 229 |

**Notes:**
Protocol E.2.a addresses the requirement to take an immediate pressure reduction or shut down the pipeline for all conditions classified as an Immediate Condition. When required to temporarily reduce pressure, three options for determining the temporary (reduced) operating pressure are permitted by the Rule.  The operator may use ASME B31.G, or RSTRENG, or may reduce to 80% of the operating pressure for the pipeline at the time of discovery.  Note that this is 80% of operating pressure, not 80% of MAOP.

RSTRENG and B31G both calculate a predicted “burst pressure” or “failure pressure.”  Selection of a safe operating pressure based on this burst pressure must include an appropriate safety factor.  OPS has established that an appropriate safety factor would result in reducing operating pressure to 72% of the burst pressure. This is the pressure that the operator may operate at when employing this option. This safety factor is consistent with the Class 1 design safety factor.  Alternatively, an operator may reduce pressure to a higher pressure than 0.72 time burst pressure, if it can show that defect growth until one year after the pressure reduction will not result in a predicted burst pressure less than or equal to 1.1 times the temporary operating pressure.  One year of defect growth is based on the amount of time a temporary pressure reduction is allowed to remain in force before the repair must be completed.

FAQ-134 also emphasizes the promptness of pressure reduction. 
FAQ-181 addresses requirements for safety related condition reports for immediate repair conditions.
FAQ-215 addresses the requirement that an operator is to examine an immediate repair condition within 5 days of discovery, however pressure reduction is to be taken as promptly as possible. 
FAQ-229 addresses the required safety margin when determining the amount of pressure reduction.

## E.2.a – Pressure Reductions/Shutdowns(continuation)

- “Immediate”
- As Soon as Safety Allows
- Without Undue Delay
- Immediate Conditions Are Considered Potential Imminent Integrity Threats

| Reference: |  |  |
| --- | --- | --- |
| §192.933(d)(1) |  | FAQ-134, 215 |

**Notes:**
When an immediate condition is discovered, the operating pressure must be reduced (or the pipeline must be shutdown) immediately.  The rule does not establish specific mandatory timeframes for this action.  However, an immediate condition is to be treated as a potentially imminent threat to pipeline integrity and pressure reductions must be implemented urgently.  Pressure reductions must be implemented as soon as it is safe to do so and without undue delay.  OPS will review the timeliness of operator actions to reduce pressure when immediate conditions are discovered.  

In some circumstances, operators may be able to complete a repair faster than a pressure reduction could be implemented.  The operator would not be considered out of compliance in this circumstance.  However, initiating repair activities is not an adequate basis to delay the process of implementing a pressure reduction.

## E.2.b – Classification Criteria

- Immediate Conditions
- Predicted Failure is _<_ 1.1 Times MAOP
- Dent w/Metal Loss, Cracking, or Stress Riser
- Engineering Judgment
- Metal Loss on Seam of LF-ERW Pipe
- All Indications of SCC
- Other Indications that Require Immediate Action

| Reference: |  |  |
| --- | --- | --- |
| §192.933(d)(1), (2), (3), ASME B31.8S §7.2.1, 7.2.2, 7.2.3 |  |  |

**Notes:**
Protocol E.2.b addresses criteria for immediate repair conditions.  The criteria that results in the classification of a condition as “immediate” are provided by this slide.  These come from Section 933(d) of the Rule as well as from ASME supplement.  Immediate conditions are those:
Where the predicted failure pressure is less than or equal to 1.1 times MAOP.
Where there is a dent with accompanying metal loss, cracking, or a stress riser.
Where engineering judgment by technical evaluators or management indicate that the condition must be immediately dealt with.
Where metal loss is present on the longitudinal seam of low frequency ERW or lap welded pipe.
Where there is any indication of Stress Corrosion Cracking, or
Where there is any indication that the condition might result in rupture of the pipeline and require immediate action.

Inspectors will verify that operators address these criteria in their integrity management program.

## E.2.b – Classification Criteria (continuation)

- One-Year Conditions
- Smooth Dent on Upper 2/3
- Depth > 6% of Diameter
- Dent Depth > 2% of Diameter
- Affecting Curvature at Longitudinal Seam or Girth Weld

| Reference: |  |  |
| --- | --- | --- |
| §192.933(d)(1), (2), (3), ASME B31.8S §7.2.1, 7.2.2, 7.2.3 |  |  |

**Notes:**
The following criteria apply to those conditions that are to be identified as “One-Year Conditions”.  These come directly from Section 933(d) of the Rule.
Smooth dents on the upper 2/3 of the pipeline (between the 8 o’clock and 4 o’clock position) that have a depth that is greater than 6% of the pipeline’s diameter.  The depth criteria is 0.5 inches for pipeline with a Nominal Pipe Size less than 12 inches.
Any dent having a depth greater than 2% of the pipeline’s diameter that affects curvature at a longitudinal seam weld or a girth weld.  The depth criteria is 0.25 inches for pipeline with a Nominal Pipe Size less than 12 inches.

## E.2.b – Classification Criteria (continuation)

- Monitored Conditions
-  Dent on Lower 1/3
- Depth > 6% of Diameter
-  Dent on Upper 2/3
- Depth < 6% of Diameter & Critical Strain Levels Not Exceeded
- Dent With Depth > 2% of Diameter
- Affecting Curvature at a Girth or Longitudinal Seam Weld & Critical Strain Levels Not Exceeded

| Reference: |  |  |
| --- | --- | --- |
| §192.933(d)(1), (2), (3), ASME B31.8S §7.2.1, 7.2.2, 7.2.3 |  |  |

**Notes:**
Some conditions do not warrant repair, but instead require monitoring to determine if their status changes such that they present an integrity concern.  The following criteria is to be used in designating monitored conditions.  These criteria come directly from Section 933(d) of the Rule.
A dent on the lower 1/3 of the pipe (between the 4 o’clock and 8 o’clock positions) having a depth greater than 6% of the pipeline’s diameter.  The depth criteria here is 0.5 inches for pipeline with a Nominal Pipe Size less than 12 inches.
A dent on the upper 2/3 of the pipe (between the 8 o’clock and 4 o’clock positions) having a depth greater than 6% of the pipeline’s diameter, but for which engineering analysis concludes that critical strain levels are not exceeded.  The analysis must be documented.  The depth criteria is 0.5 inches for pipeline with a Nominal Pipe Size of less than 12 inches.
A dent with a depth greater than 2% of the pipeline’s diameter that affects curvature at a girth weld or a longitudinal seam weld, but for which engineering analysis concludes that critical strain levels are not exceeded.  Here again, the analysis must be documented.  The depth criteria is 0.25 inches for pipeline with a Nominal Pipe Size of less than 12 inches.

OPS will be looking for the operator’s compliance with the criteria – including documentation and analysis of both immediate and monitored repair conditions.

## E.2.c – Subsequent Monitoring

- Process to Track Monitored Conditions
- Check for Changes in Monitored Conditions That Could Require Remediation

| Reference: |  |  |
| --- | --- | --- |
| §192.933(d)(3) |  |  |

**Notes:**
Protocol E.2.c. examines the process for monitoring conditions that do not require scheduled repair.  Integrity Management program procedures must address the activities necessary to monitor the status of these conditions.  It is expected that an identification process has been developed to tag these conditions.  It is also expected that this process will evaluate the conditions as other risk factors could potentially affect their status.  In other words, this monitoring process must evaluate these conditions at appropriate times between assessment activities when conditions indicate that worsening of the conditions might have occurred.

OPS will verify that an operator’s program addresses what is to be done once a monitored condition has been determined to have deteriorated to the point that it requires remediation.

## E.2.d – Other Threat Conditions

- Conditions That Do Not Meet the Special Requirements of 933(d)
- Must Meet the Remediation Scheduling Requirements of ASME B31.8S, Section 7, Figure 4.

| Reference: |  |  |
| --- | --- | --- |
| §192.933(c) |  |  |

**Notes:**
Protocol E.2.d addresses other threat conditions.  Other threat conditions are those that do not meet the special requirements in Section 933(d).  These conditions must be repaired on a schedule that is determined by examining Figure 4 in Section 7 of the Supplement.  This Figure enables the operator to determine the remediation schedule based on the ratio of Predicted Failure Pressure to MAOP and the operating stress.

## E.3 – Response when Timelines for Evaluation and Remediation Cannot Be Met

- Pressure Reduction or Other Action
- Documented Justification
- Notification Requirements

| Reference: |  |  |
| --- | --- | --- |
| §192.933(a) |  |  |

**Notes:**
Protocol E.3 is concerned with operator responses when remediation timeframes cannot be met.  Included in this protocol is the inspection of 
actions that must be taken when a pressure reduction exceeds one year, 
providing a documented justification for not meeting the specified remediation schedule, and 
OPS and State notification requirements.

## E.3.a – Pressure Reduction or Other Action

- Temporary Pressure Reduction Requirement
- ASME B31.G
- RSTRENG
- 80% of Operating Pressure at Time of Discovery (Not MAOP)

| Reference: |  |  |
| --- | --- | --- |
| §192.933(a) |  |  |

**Notes:**
Protocol E.3.a addresses rule requirements that the Integrity Management Program documentation must address the requirement to take appropriate actions when the specified timeframes in Section 933 or the Rule cannot be met.  There are two options to be taken in these cases.  First, the operator may take a temporary pressure reduction until the remediation actions can be completed.  The means for determining the appropriate reduced pressure are the same as those for immediate repair conditions, namely:
Use ASME B31.G
Use RSTRENG, or
Reduce to 80% of Operating Pressure at the time the anomaly was discovered (not MAOP).

Continued on next slide

## E.3.a – Pressure Reduction or Other Action (continuation)

- Other Actions to Ensure Safety
- If Pressure Reduction > 365 Days, Document Pipeline Integrity is Not Jeopardized

| Reference: |  |  |
| --- | --- | --- |
| §192.933(a) |  |  |

**Notes:**

The second option is to take some other action that will ensure the safety of the affected pipeline segment.  The nature of this “other action” is not specified, but is left to the operator to determine what constitutes the appropriate action.  The actions taken must be documented and are subject to review during inspections.

In situations where pressure reductions are taken and this reduction is expected to last longer than 365 days, the operator must document the justification for why the continuation of the reduction without repair of the condition will not jeopardize pipeline integrity.  A notification is not required in this case, but the justification must be available for review by OPS.

## E.3.b – Documented Justification

- Justification Must Include
- Why the Specified Remediation Schedule Cannot Be Met
- Why the Changed Schedule Will Not Jeopardize Public Safety

| Reference: |  |  |
| --- | --- | --- |
| §192.933(c) |  |  |

**Notes:**
OPS will use Protocol E.3.b to inspect an operator’s program documentation to verify it addresses the appropriate actions to be taken when specified remediation timeframes cannot be met.  Procedures must specify that a documented justification must be developed that addresses the following two points:
Why can the originally specified remediation schedule not be met?
Why will the new schedule for remediation NOT result in a condition that will jeopardize public safety?
Similar to the aforementioned justifications, this must be documented, but is not required to be submitted to OPS.

## E.3.c – Notification Requirements

- Notify OPS or State or Local Pipeline Safety Authority when:
- Schedule Cannot Be Met AND
- Safety Cannot Be Provided By a Temporary Pressure Reduction or Other Action
- Section 192.949 Addresses Notification

| Reference: |  |  |
| --- | --- | --- |
| §192.933(c) |  |  |

**Notes:**
The rule contains allowances for circumstances in which a repair can not be completed within required timeframes and pressure can not be reduced.  In this case, notification must be provided to OPS and the appropriate State or Local Pipeline Safety Authority, as applicable.  Section 949 of the rule provides guidance for the notification process.  It is expected that the operator’s Integrity Management program documentation include these steps for developing the justification and providing the appropriate notification.

## E.4 – Record and Implementation Review

- Discovery Timeframes
- Remediation Schedule
- Remediation Actions
- Pressure Reductions
- For Immediate Repair Conditions
- For Extended Repair Timeframes

| Reference: | FAQ-56, 58, 62, 65, 66, 67,  |
| --- | --- |
| §192.933 | 68, 70, 134, 135, 224, 225 |

**Notes:**
Protocols E.1, E.2, and E.3 are primarily concerned with Integrity Management Program Processes and Procedures.  Protocol E.4 is focused on reviewing repair and remediation records and other records (such as operating logs) which document the implementation of these processes.  This record/implementation review will examine the following activities or documents:
Review of assessment results and the discovery of anomalies and their timeliness
The Operator’s Remediation Schedule
Actions taken to repair or otherwise remediate discovered conditions
Pressure reductions taken in response to the discovery of immediate conditions or in response to remediation schedules extending beyond those specified in the rule or the Supplement.

Numerous FAQs are related to remediation activities which would also relate to records requirements.  Operators are encouraged to review the FAQs in detail.

## E.4 – Record and Implementation Review (continuation)

- Evaluation and Remediation for Anomalous Conditions
- Documented Basis for Pressure Reductions Longer than 365 Days
- Completion of Remediation Activities

| Reference: | FAQ-56, 58, 62, 65, 66, 67,  |
| --- | --- |
| §192.933 | 68, 70, 134, 135, 224, 225 |

**Notes:**
Continuing on, the record/documentation review will include:
The evaluation and remediation steps taken for anomalous conditions,
The documented justification for continuing a pressure reduction beyond 365 days, and
Documents indicating when a remediation activity has been completed.

## E.4.a – Remediation Schedule

- Remediation Schedule for Each Anomaly
- Track Completion of Remediation Activities

| Reference: |  |  |
| --- | --- | --- |
| §192.933(c), (d) |  |  |

**Notes:**
Protocol E.4.a -  Each condition that meets the criteria for an anomaly requiring repair must have an associated date scheduled for completion.  An inspector would expect to see an operator’s repair schedule for all anomalies discovered from an assessment.  This schedule should be used to track completion of remediation activities and demonstrate compliance with required timeframes.

## E.4.b – Discovery Timeframes

- Discovery Completed Within 180 Days
- 180 Days Measured from Date Final Field Activities Completed
- Date of Discovery Part of Schedule
- Documentation Explaining When Discovery Date Cannot Be Met

| Reference: |  |  |
| --- | --- | --- |
| §192.933(b) |  | FAQ-34 |

**Notes:**
Protocol E.4.b - Each anomaly should have an associated discovery date documented.  This date will be used by the OPS inspector to confirm that the discovery action was completed within the 180-day timeframe prescribed by the Rule.  The date the assessment activity was complete, for example, the date an ILI device was removed from the trap, should also be documented to enable the inspector to determine when the 180-day time clock started.

More information is presented on the completion date for an assessment in the response to FAQ-34.

It is a reasonable approach to ensure the discovery date is documented on the remediation schedule.

When the 180-day timeframe for completing the discovery activity cannot be met, documentation should be available and presented to the inspector that explains why discovery could not be accomplished in that timeframe.

## E.4.c – Remediation Actions

- Documentation of Remediation Actions Taken
- Are These Actions Sufficient to Ensure Integrity Will Not Be Jeopardized Before Next Assessment?

| Reference: |  |  |
| --- | --- | --- |
| §192.933(a) |  |  |

**Notes:**
Under Protocol E.4.c,  repair records will be examined to determine what was done to repair an anomaly.  These records should be complete and have sufficient detail necessary to show that the repair was accomplished in a manner that will restore the pipeline integrity to a condition that will not be jeopardized before the next scheduled assessment.  It would be expected that the date for the next assessment will have been determined in order to reach this conclusion.

## E.4.d – Pressure Reductions

- Timely Identifications and Reductions
- Proper Application of Calculation Method
- Operating Pressure at Time of Discovery

| Reference: |  |  |
| --- | --- | --- |
| §192.933(a) |  | FAQ-229 |

**Notes:**
Protocol E.4.d will be used by OPS inspectors to examine how an operator implements pressure reductions.  When pressure reductions are taken, either as a result of immediate repair condition discovery or as a result of having to extend the repair schedule of an anomaly, the actions taken as a result of this pressure reduction process will be reviewed.  The timeliness of the actions to identify the need for the pressure reduction and the timeliness of the reduction itself will be examined.  This may include looking at operational logs.

The means by which the magnitude of the pressure reduction was determined will be reviewed for adequacy.  Records showing how this value was determined should be available for inspection.

Some record of operating pressure at the time of discovery must be available to enable the inspector to confirm the appropriate reduction has been taken.

## E.4.e – Immediate Condition Evaluation & Repair

- Immediate Repair Evaluation
- Root Cause
- Lessons Learned
- Evaluation and Selection of Remediation Actions
- ASME B31.8S, Section 7

| Reference: |  |  |
| --- | --- | --- |
| §192.933(d)(1) |  |  |

**Notes:**
Protocol E.4.e -  When immediate repair conditions are discovered, it is expected that an in-depth evaluation of the condition, its magnitude, and generic implications will be conducted.  The OPS inspector may examine the thoroughness of an operator’s efforts to evaluate the technical aspects of this type of anomaly and specify the appropriate corrective/preventive measures.  The requirements in Section 7 of the Supplement as they relate to immediate repair conditions will be used when appropriate to determine if the proper actions have been taken.

## E.4.f – Pressure Reductions Exceeding 365 Days

- Documented Technical Justification
- Date Initial Pressure Reduction Was Taken

| Reference: |  |  |
| --- | --- | --- |
| §192.933(a) |  |  |

**Notes:**
When a pressure reduction has been taken as a mitigative measure for anomalies that cannot be repaired in accordance with timeframes required by the Rule, special actions must be performed if that pressure reduction extends beyond 365 days.  The documented technical justification for the extension of this reduction time must be available to the OPS inspector.  Included with this should be some evidence that objectively demonstrates when the initial pressure reduction was taken.  The justification must demonstrate the pipeline integrity is assured until the anomaly can be remediated.

## E.4.g – Completion of Remediation Activities

- Repair Records
- Date of Completion vs. Schedule
- Information Provided to Other Program Elements

| Reference: |  |  |
| --- | --- | --- |
| §192.933(c), (d) |  |  |

**Notes:**
Protocol E.4.g.  As noted earlier, repair records will be examined.  One area of concern to the inspector will be to determine if the repair was completed on time as specified in the remediation schedule.  Obviously, as long as the schedule timeframes of the Rule are met, adjustments to the schedule may be accommodated without technical justification.  These types of schedule adjustments would be expected to occur as the operator attempts to gain efficiency in the remediation process.

There should also be evidence that repair or configuration changes have been documented and integrated into other elements of the Integrity Management program, such as the risk assessment program element, so that the appropriate adjustments may be made to reflect pipeline configuration. For instance, the risk assessment should be updated to reflect the replacement or repair of a segment.

## E.4.h – Monitored Condition Evaluation & Repair

- Evaluated During Subsequent Assessments
- Risk Assessments
- Integrity Assessments
- If Conditions Change Remediation May be Required

| Reference: |  |  |
| --- | --- | --- |
| §192.933(c), (d) |  |  |

**Notes:**
Protocol E.4.h will be used to inspect an operator’s program to verify that anomalies meeting any of the criteria of section 933(d)(3) as "monitored conditions" are evaluated during subsequent risk assessments and integrity assessments to identify any change that may require remediation and that any required remediation is scheduled and implemented in accordance with the applicable requirements of section 933 and the Supplement.  OPS will inspect operator records to confirm that monitored conditions are being tracked and will be re-reviewed at subsequent assessments.

## E.4.i –Remediation Activities Not Completed Within Timeframes

- Notifications to OPS and State/local
- Remediation Activities Not Completed Within 192.933 Timeframes
- Temporary Pressure Reduction Not Provided

| Reference: |  |  |
| --- | --- | --- |
| §192.933(c) |  |  |

**Notes:**
For remediation activities that have not been completed in accordance with section 933  timeframes, and for which the operator has not provided safety through a temporary pressure reduction, OPS and appropriate State or local authorities must be notified.  OPS will inspect operator records to confirm that the required notifications have been submitted in situations where the remediation schedule cannot be met and safety cannot be ensured by either reducing operating pressure or some other appropriate action. 

## Protocol Area E Remediation

**Conclusion – **
**Thank you for your attention**

**Notes:**
This concludes my presentation on the protocols for Remediation. Thank you for your attention. 

## Gas Integrity Management Rule Protocols

**John Pepper**
**49 CFR 192.913, 937, 939, 941, 943**
**Continual Evaluation and Assessment**
**(and Low Stress Reassessment)**
**Protocol F**
**January 2005**

**Notes:**
[Greeting to the audience. Introduce yourself and tell where you work or fit into the Gas IMP process] 

Today I’m going to discuss the protocols for reviewing programs to continually evaluate the integrity of the pipeline and perform ongoing reassessments. These protocols are located in area F.

## Continual Evaluation and Assessment

- F.1	Periodic Evaluations
- F.2	Reassessment Methods
- F.3	Low Stress Reassessment
- F.4	Reassessment Intervals
- F.5	Deviations from Reassessment Requirements
- F.6	Waiver from Reassessment Interval
- F.7	Consideration of Environmental and Safety Risks

**Notes:**
As background for continual evaluation and assessment, there are several sections of the gas integrity management rule that are addressed by Protocol F.  The areas addressed in this protocol include:
F.1 - Periodic evaluations – these “evaluations” involve a different process than “assessments.”  Evaluations are analytical reviews of a wide range of data and information regarding the pipeline integrity that includes but goes beyond simply “assessment” results.  “Assessments” of pipelines on the other hand are tests, or actual measures of the pipeline’s condition and can be performed using a variety of tools or inspection techniques.  We will discuss more about evaluations and assessments in later slides.
F.2 - Identifying reassessment methods – Operators must determine the appropriate reassessment method or methods that will be used. 
F.3 - Low stress reassessments – Low stress assessments may be applied to pipelines operating at less than 30% SMYS.
F.4 - Reassessment intervals – The gas rule includes requirements describing the maximum reassessment intervals for covered segments
F.5 - Deviations from Reassessment Requirements – The rule permits a performance-based approach to extend the maximum reassessment intervals.
F.6 - Waiver from Reassessment Interval – In two situations, the rule specifies that operators may request a waiver to extend the reassessment interval beyond the maximum interval. 
F.7 - Consideration of Environmental and Safety Risks – The gas IM rule contains a requirement that assessments be conducted in a manner that minimizes environmental and safety risks. 

## F.1 - Periodic Evaluation

- Based on Data Integration and Risk Assessment
- Identify the Specific Threats and the Risk Represented by These Threats

| Reference: |  |
| --- | --- |
| §192.917, 937(b) |  |

**Notes:**
The first set of protocols I will discuss involve the review of the periodic evaluation process.  The concept of a periodic (and continuing) evaluation of gas pipeline integrity is an important feature of the new rule. 
Protocol F.1 requires the inspector to verify that the operator conducts a periodic evaluation of pipeline integrity based on data integration and risk assessment as specified in 192.917 and then to identify the threats specific to each covered segment and the risk represented by these threats. 
Section 192.917, paragraph (b) requires an operator to gather and integrate data from its entire pipeline system that could be relevant to identifying potential threats to the covered pipeline segment.  During an IM inspection, the inspector will verify that the data from the entire pipeline is considered and not just data from covered segments.  Furthermore, an operator is only required to gather and integrate existing data about its pipeline system.  However, as part of the continuing improvement process, OPS expects operators to begin collecting needed data that was not previously available and begin using it in subsequent evaluations.
An important goal of this evaluation is to identify threats not previously thought to be applicable to its pipeline.  As more information is learned about the pipeline, operators must be diligent to thoroughly integrate and analyze all available information in order to identify all credible threats to its pipeline, including those threats not previously recognized.  The inspectors will review the IM Program to determine if it contains requirements to conduct periodic integrity evaluations that are technically sound, justifiable and adequate for making integrity related decisions.

## F.1.a - Periodic Evaluation: Data Integration

- Past and Present Assessment Results
- Data Integration
- Risk Assessment
- Decisions About Remediation
- Additional Preventive and Mitigative Actions

| Reference: |  |
| --- | --- |
| §192.917, 937(b) | FAQ-81 |

**Notes:**
Protocol F.1.a - The inspectors will verify that the periodic evaluation considers, in an ongoing manner, certain data sources for each covered segment, including: 
Completed integrity assessment results (such as, baseline assessments as well as those completed prior to the baseline if applicable); 
data integration (including environmental and Right-of-Way data), 
risk assessment; 
remediation decisions (such as the number, type, and severity of anomalies that were not remediated); and  
additional preventive and mitigative measures.

Note that FAQ-81. clarifies what type of information must be integrated in performing a continual evaluation of pipeline integrity.

## F.1.b - Periodic Evaluation: Thoroughness

- Verify Periodic Evaluations of Data Are:
- Thorough,
- Complete, and
- Adequate for Establishing Reassessment Methods and Schedules

| Reference: |  |
| --- | --- |
| §192.937(b) |  |

**Notes:**
As part of the review process, protocol F.1.b requires inspectors to check documentation of completed evaluations to ensure thoroughness and completeness.  Furthermore, the periodic evaluation will be reviewed to determine whether it is adequate for establishing the appropriate reassessment methods and interval.  The inspectors will be looking for a documented basis for the operator’s conclusions.

## F.1.c – Periodic Evaluation: Interval 

- Verify an Appropriate Plan is Established for Performing Required Periodic Evaluation
- Should Start After Completing the Baseline Assessment

| Reference: |  |
| --- | --- |
| §192.937(b) |  |

**Notes:**
Protocol F.1.c - OPS will expect that the first periodic evaluations for a particular segment will begin some time after the completion of the baseline assessment.  The rule does not require that reevaluations be conducted on a specific maximum interval or timeframe as it does for reassessments.  An operator must conduct a periodic evaluation as frequently as needed to assure pipeline integrity.  An operator must base the frequency of evaluation on risk factors specific to its pipeline and on the availability of new data or information related to pipeline integrity.  Some examples are provided on the next slide.

## F.1.c – Periodic Evaluation: Interval

- New Information Triggers Evaluation
- New Assessment Results
- In-Service Rupture or Leak
- Risk Conditions Change
- Significant Design/Operational Changes

| Reference: |  |
| --- | --- |
| §192.937 |  |

**Notes:**
In addition to a planned evaluation, the operator’s IMP should require evaluation of pipeline integrity as needed in response to certain events, in order to assure that pipeline integrity threats are promptly identified and that the integrity program is adequate to address those threats.  The inspectors will verify that operators have controls in place that identify those factors/events that should initiate an immediate reevaluation of pipeline integrity.  At a minimum, the integrity of a pipeline should be reevaluated:
Upon receipt of integrity assessment results (baseline or reassessment)
After any in-service rupture or leak (the reevaluation should determine the root cause of the failure or leak).  Note that the Supplement, Table 3, Note 1 requires immediate re-evaluation of the re-assessment interval in response to a time-dependent failure.
Whenever risk conditions of the pipeline change significantly
Whenever significant changes are made to the design or operation of the pipeline (for example whenever the MAOP is increased).

## F.1.d – Periodic Evaluation: Updates

- Review Evaluation Results
- Determine if New Information Warrants Changes to Reassessment Intervals and/or Methods
- Make Changes as Appropriate

| Reference: |  |
| --- | --- |
| §192.937 |  |

**Notes:**
The inspectors will verify that the evaluation results are reviewed to determine if the new information warrants changes to assessment methods or the assessment interval.  Examples might include the identification of a new threat or the discovery of corrosion growth occurring faster than predicted.  Assessment plans must be changed accordingly.

## F.2 - Reassessment Methods

- Establishment of the Reassessment Method Consistent With §192.937(c)

| Reference: |  |
| --- | --- |
| §192.937(c), 941 |  |

**Notes:**
After completing periodic evaluations, the operators determine the appropriate reassessment method or methods.  Under protocol F.2, OPS inspectors will review how the operator uses the periodic evaluation results to identify an appropriate reassessment method or methods.  In most cases the process used by the operator to identify the appropriate reassessment method will be the same process that was used to identify the baseline assessment method, which is covered by Protocol B, unless new threats have been identified or the previous assessment was determined to be ineffective.

## F.2.a - Reassessment Methods: Selection

- Reassessment Method and Selection of Appropriate Tool to Meet ASME B31.8S, Section 6

| Reference: |  |
| --- | --- |
| §192.937(c)(1), (2), (3), (4), (5) | FAQ-133, 141, 187, 216, 228 |

**Notes:**
As with the baseline assessment, the inspectors will verify that the operator’s process for selecting the reassessment method is consistent with the Supplement and that methods selected for the “primary” reassessment other than those specified in the Supplement are considered “other technology.”
We are using the term “primary” here to distinguish these methods from the “interim” reassessment methods such as Confirmatory Direct Assessment which will be discussed later.

There are several FAQs that operators should review with regard to selection of reassessment methods – FAQs 133, 141, 187, 216, and 228.

## F.2.a - Reassessment Method: Selection Process

- “Primary” Reassessment Methods:
- Internal Inspection Tool(s)
- Pressure Test (Subpart J)
- Direct Assessment
- Other Technology
- “Interim” Reassessment Methods:
- Confirmatory Direct Assessment
- Low Stress Reassessment

| Reference: |  |
| --- | --- |
| §192.937(c)(1), (2), (3), (4), (5) | FAQ-133, 141, 187, 216, 228 |

**Notes:**
The same three major assessment method types are specified for performing the “primary” reassessment:
 Internal inspection
 Pressure test
 Direct assessment
 Other technology may be used, but requires notification.
In addition, two other reassessment methods are given which may be used to meet the “interim” 7-year reassessment interval requirement which we will discuss shortly.
Confirmatory Direct Assessment and 
Low stress reassessment, 

## F.2.a - Reassessment Method: Third Party Damage

- Assess for TPD if a Threat from Residual TPD has Been Identified
- Treatment of TPD Threats was Discussed in Detail in Protocol C
- Assessment Options Same as Discussed in Protocol B

| Reference: |  |
| --- | --- |
| §192.937(c)(1), (2), (3), (4), (5) | FAQ-133, 141, 187, 216, 228 |

**Notes:**
As we discussed under the BAP protocol presentation, the operator must evaluate whether evidence exists that a covered pipeline segment contains one or more residual third party damage defects in order to determine whether there is a need to assess for third party damage .  IM inspections will verify that the operator’s program addresses assessment for third party damage.  These requirements are the same as those previously discussed under Protocols B and C, so I will not discuss them again.  

## F.2.a - Reassessment Method: DA

- DA is an Acceptable Method for EC, IC, and SCC Threats Only

| Reference: |  |
| --- | --- |
| §192.937(c)(1), (2), (3), (4), (5) | FAQ-133, 141, 187, 216, 228 |

**Notes:**
Also discussed under the BAP protocol presentation was the restriction that DA is acceptable method for EC, IC, and SCC threats only. 

Protocol D also addresses the DA plan and more specifics on treatment of TPD while conducting ECDA.

## F.2.a - Reassessment Method: CDA

- CDA Limited to External and Internal Corrosion Threats
- Follow the 4 Step Procedure for ECDA and ICDA
- Can be Used in Combination With “Primary” Assessment Method

| Reference: |  |
| --- | --- |
| §192.937(c)(1), (2), (3), (4), (5) | FAQ-133, 141, 187, 216, 228 |

**Notes:**
Use of Confirmatory Direct Assessment, or CDA, is limited to 2 time dependent threats, External and Internal Corrosion. 

The CDA process must follow the 4 step procedure as outlined in the ECDA and ICDA processes. The main purpose of the CDA process is to check the effectiveness of preventive and mitigative steps taken as a result of the “primary” integrity assessments at the prescribed time intervals.  

CDA can also be used in combination with any of the prescribed “primary” assessment evaluations.

## F.2.a - Reassessment Method: CDA

- An “Interim” Method to Comply With PSIA to Assess Every 7 Years
- Conducting CDA Can Not Extend the Schedule for Next “Primary” Assessment
- CDA May Shorten the Interval if Unexpected Results Are Obtained

| Reference: |  |
| --- | --- |
| §192.937(c)(1), (2), (3), (4), (5) | FAQ-133, 141, 187, 216, 228 |

**Notes:**
The CDA process can only be used as an “interim” integrity assessment between the “primary” integrity evaluations that take place at the maximum intervals specified in the Supplement and the rule.  In this manner, the legal requirements of the PSIA can be met.  The use of CDA can not extend the full reassessment interval using the “primary” assessment methods, but could indicate the need to shorten the reassessment interval if unexpected results are obtained such as the discovery of corrosion growth rates that exceed assumed or predicted values.

FAQ-228 discusses the conduct of confirmatory direct assessments. CDA is an interim measure, intended to provide for assessments at the minimum frequency specified in the Pipeline Safety Improvement Act of 2002. It provides assurance that significant unknown degradation is not occurring, but does not provide a knowledge of pipe condition equal to that which would be obtained from one of the other specified methods. A successful CDA allows operation for the remainder of the assessment interval (or until the next CDA in the case of low-pressure pipeline on 20-year interval and for which the interval has more than 7 years to run) but it does not allow that interval to be extended.

## F.2.b - Reassessment Method: Implementation

- Review of Methods Selected for Reassessments
- Verification Methods Are Appropriate for Identified Threats

| Reference: |  |
| --- | --- |
| §192.937(c), 941 |  |

**Notes:**
Protocol F.2.b - The inspectors will review the results of the assessment method determination process to verify that the process steps were properly followed and that the results are consistent with the threats identified in the periodic evaluation.

## F.3 – Low Stress Reassessment

- For Pipelines Operating at <30% SMYS
- To Address Threats of External and Internal Corrosion

| Reference: |  |
| --- | --- |
| §192.941 |  |

**Notes:**
As mentioned earlier, for pipelines operating at < 30% SMYS, an operator may choose to use a "low stress reassessment" method to address threats of external and internal corrosion. 

## F.3.a – Low Stress Reassessment: Baseline Complete

- Baseline Assessment on the Covered Segment Completed Prior to Implementing the "Low Stress Reassessment" Method

| Reference: |  |
| --- | --- |
| §192.941(a) |  |

**Notes:**
In order to use a low stress assessment, the operator must have completed a baseline assessment. Verification of completion will be performed under protocol F.3.a.

## F.3.b – Low Stress Reassessment: External Corrosion

- For Cathodically Protected Pipe
- Electrical Surveys Every 7 Years
- Use Survey to Evaluate CP Effectiveness and Corrosion Threat

| Reference: |  |
| --- | --- |
| §192.941(b)(1) |  |

**Notes:**
The rule also provides specific requirements for the use of this assessment method depending on whether it is being used to address external or internal corrosion. Inspectors will verify the specific requirements have been included in operators’ integrity management programs.
For use in addressing external corrosion, the requirements for using low stress reassessment vary depending on whether the pipe is cathodically protected or not.  
If the line is cathodically protected, the operator must:
Perform an electrical survey at least every 7 years (for example a close interval survey would be an electrical survey); and
Use the results of these surveys as part of an overall evaluation of cathodic protection and corrosion threat.

## F.3.b – Low Stress Reassessment: External Corrosion

- Evaluation Must Include:
- Repair and Inspection Records
- Corrosion Monitoring Records
- Exposed Pipe Inspection Records
- Pipeline Environmental Information

| Reference: |  |
| --- | --- |
| §192.941(b)(1) |  |

**Notes:**
Furthermore, the evaluation performed by the operator must include, at a minimum, the following types of data and information:
Repair and inspection records
Corrosion monitoring records
Exposed pipe inspection records
Pipeline environment information

## F.3.b – Low Stress Reassessment: External Corrosion

- For Unprotected Pipe or Where Electrical Surveys Are Impractical:
- Leakage Surveys at 4-month Intervals; and
- Identification and Remediation of Areas of Active Corrosion Every 18 Months

| Reference: |  |
| --- | --- |
| §192.941(b)(1)
 |  |

**Notes:**
Given certain field conditions, electrical surveys may be impractical.  Such conditions may include reinforced pavements, stray current areas, and casings. 

If the segment is unprotected pipe or the pipe is cathodically protected but electrical surveys are impractical, the operator must:
Conduct leakage surveys at 4-month intervals (per 192.706); AND
Every 18 months identify and remediate areas of active corrosion by evaluating the following:
Leak repair and inspection records
Corrosion monitoring records
Exposed pipe inspection records
Pipeline environment information

## F.3.c – Low Stress Reassessment: Internal Corrosion

- Gas Analysis for Corrosive Agents
- At Least Once Each Calendar Year
- Periodic Testing of Removed Fluids
- Test Fluids Removed From Storage Field
- At Least Once Each Calendar Year

| Reference: |  |
| --- | --- |
| §192.941(c)(1), (2), (3) |  |

**Notes:**
If low stress reassessment is to be used to address internal corrosion, the following requirements apply:
Gas analysis for corrosive agents must be performed at least once each calendar year;
Periodic testing of fluids removed from the segment must be conducted; and
At least once each calendar year test fluids removed from each storage field that affect a covered segment.

## F.3.c – Low Stress Reassessment: Internal Corrosion

- Data Integration Every 7 Years
- Internal Corrosion Leak Records
- Incident Reports
- Test Records
- Implement Remediation Actions

| Reference: |  |
| --- | --- |
| §192.941(c)(1), (2), (3) |  |

**Notes:**
Furthermore, to address internal corrosion, at least every 7 years the operator must integrate data from the previously mentioned testing with the following:
Internal corrosion leak records
Incident reports
Test records
Based on the results of this data integration, the operator’s IMP must require definition and implementation of appropriate remediation actions.

## F.4 – Reassessment Interval

- Process for Establishing the Reassessment Intervals
- Maximum Intervals Specified in §192.939 and ASME B31.8S

| Reference: §192.937(a),  |  |
| --- | --- |
| 939(a), (b), 913(c), ASME B31.8S §5 | FAQ-28 |

**Notes:**
The gas IM rule and the Supplement describe maximum reassessment intervals for covered segments.  These maximum intervals vary depending on:
 The pipe stress of the segment under consideration; and
 The assessment method selected.
The requirements allow longer reassessment intervals for pipe that has lower stress levels.

Note that some reassessments may be required to be performed before 100% of baseline assessments are complete for an operator’s system.

FAQ-28 addresses what an operator must consider in prioritizing pipe segments for assessment and re-assessment. The risk posed by each pipeline segment covered by this rule must be considered in scheduling baseline assessments and periodic re-assessments. Risks must be evaluated using a risk assessment that meets Section 5 of the supplement, as required by section 917(c).  Section 5.10 of the supplement specifically addresses use of risk assessment for prioritizing pipe segments for assessment.

## F.4.a – Reassessment Interval – Seven Years

- Reassess Covered Segments  7 Years After the Baseline Assessment
- Unless the Periodic Evaluation Indicates an Earlier Reassessment
-  (Refer to Protocol F.1)

| Reference: |  |
| --- | --- |
| §192.937(a) | FAQ-40, 41, 42, 43, 45, 133 |

**Notes:**
Regardless of the “primary” reassessment method or the stress level of the pipe, there is a legal requirement that some type of reassessment must be performed on each covered segment at intervals not to exceed 7 years.  This reassessment can be a “primary” assessment method or an “interim” reassessment such as a CDA or a low stress reassessment.
The interval “7 years” should be measured in actual years not calendar years.

There are several FAQs associated with reassessment intervals.  I would like to point out FAQ-41 which clarifies that the specified number of years means actual years rather than calendar years.

## F.4.b – Reassessment Interval: ≥30% SMYS

- If Reassessment Interval is >7 Years
- Perform CDA Within 7 Years Followed by a Reassessment at the Established Interval
- Intervals Not to Exceed 192.939(b) Values
- Unless Deviation Permitted Under 939.913(c)

| Reference: |  |
| --- | --- |
| §192.939(a) | FAQ-40, 41, 45, 78, 133 |

**Notes:**
For pipe operating at or above 30% SMYS, if the reassessment interval is greater than 7 years, a CDA must be performed within 7 years after the last “primary” assessment. This CDA satisfies the regulatory requirement that reassessment intervals not exceed 7 years. Requirements related to the CDA process are addressed by protocol G.

The reassessment interval for a pipe that operates at or above 30% SMYS must not exceed the values listed in section 939(b) unless the operator is utilizing provisions in the rule regarding exceptional performance which we will discuss later.

## F.4.b – Reassessment Interval: ≥30% SMYS

- Full Interval for “Primary” Reassessment
- For Pressure Test, ILI, or Other Technology
- Analysis of:
- Identified Threat(s) & Last Assessment
- Data Integration & Risk Assessment
- OR
- Intervals from ASME B31.8S, Table 3
- For Direct Assessment, Refer to Protocol D

| Reference: |  |
| --- | --- |
| §192.939(a) | FAQ-40, 41, 45, 78, 133 |

**Notes:**
The full reassessment interval using a “primary” assessment method must be established.  For pipe that operates at or above 30% SMYS, the rule requires that this interval be established as follows: For pipe assessed by a pressure test or internal inspection one of two choices is available:  One option is to perform an evaluation of the identified threats, the most recent assessment, the data integration and the risk assessment. This analysis may determine that appropriate interval is less than the maximum allowable.  If the evaluation concludes that a shorter interval is appropriate, the operator must use the shorter interval.  As an example, the risk assessment of a particular segment may determine that the corrosion threat on the line is particularly aggressive, such as might occur due to MIC.  In such cases, based on the anomalies identified during the baseline assessment and evidence of susceptibility to MIC, a reassessment interval of 10 or 15 years or even 7 years may not acceptable.  The interval must be selected to effectively manage the threats and risks associated with the line. The second option is to not perform this analysis, but to use the intervals specified in Table 3 of the Supplement.  These are either 10 or 15 years depending on whether the pipe is operated at more than 50% SYMS or not, and depending on the predicted failure pressure of remaining (un-repaired) defects discovered during ILI or the pressure test values.  I will present a summary of Table 3 values in a few minutes.  However, operators are cautioned not to default to these values if there are indications that aggressive defect growth is occurring.  As specified in Note 1 to Table 3, the values in Table 3 are maximums and may need to be shortened depending on specific threats and risks.
No matter which choice is selected, operators are responsible to select intervals that are sufficient to assure pipeline integrity.  When an operator chooses direct assessment as the assessment method, Protocol D is used for examination of an operator's process for determination of allowable reassessment intervals.  

## F.4.c – Reassessment Interval: <30% SMYS 

- Similar to Lines Operating  30%
- Main Difference is Use of Applicable Column in Table 3 of B31.8S.

| Reference: §192.937(a),  |  |
| --- | --- |
| 939(b)(1), (2), (3), (4), (5) | FAQ-40, 41, 45, 133, 178, 228 |

**Notes:**
For pipelines that operate at less than 30% SMYS, the process for determining the reassessment interval is essentially the same as that used for pipe operating over 30% SMYS.  The main difference is that the entry point into Table 3 of the Supplement is the “<30%” column.  As you will see, the maximum reassessment intervals are longer for lower stress pipe.

I would like to point out that FAQ-178 clarifies that provisions applicable to pipelines operating below 30% SMYS apply to pipelines for which the MAOP is less than 30% SMYS. Increasing operating pressure to greater than 30% SMYS would require uprating pursuant to Subpart K. For integrity management purposes, the requirements applicable to each covered pipeline segment must be met at all times. Some requirements vary depending on pipe stress level. There is no grace period allowed to come back into compliance if stress levels are changed. Operators planning to increase stress levels to >30% SMYS must determine, as part of planning for that increase, whether additional actions need to be taken to be in compliance with integrity management requirements. If an assessment has not been performed in over 15 years, the maximum interval allowed for pipelines between 30 and 50% SMYS under 192.939, then an assessment would need to be conducted before the pressure increase is implemented. (Note that similar considerations are required for pressure changes that would increase stress levels to above 50% SMYS).

## F.4.c – Reassessment Interval: <30% SMYS (continuation) 

- If Interval is > 7 Years, the Operator Must Conduct at **** 7 Year Intervals Either
- CDA, or
- Low Stress Reassessment
- Full Assessment With “Primary” Assessment Required Before End of Assessment Interval ( 20 Yr)

| Reference: §192.937(a),  |  |
| --- | --- |
| 939(b)(1), (2), (3), (4), (5) | FAQ-40, 41, 45, 133, 178, 228 |

**Notes:**
Similarly, if the reassessment interval for pipe operating at less than 30% SMYS is greater than 7 years, a CDA or a low stress reassessment must be performed at 7 year (or shorter) intervals.  A low stress reassessment is performed at 7 year intervals much like a CDA.  If this method if selected, the operator must still perform an assessment using ILI, pressure test or direct assessment before the end of the reassessment interval (not to exceed 20 years).

## F.4.d – Reassessment Interval: Prior Assessments

- If Prior Assessment Credited as a Baseline Assessment
- Reassess by December 17, 2009

| Reference: |  |
| --- | --- |
| §192.937(a) | FAQ-152 |

**Notes:**
For those segments on which a prior assessment was credited as a baseline assessment, the initial reassessment must occur by December 17, 2009.

FAQ-152 provides additional background on this topic - The rule requires (192.921(e)) that an assessment conducted prior to December 17, 2002, must meet the baseline requirements in Subpart O if it is to be used as a baseline assessment. A key element of those requirements is that the assessment method be based on the threats faced. Section 192.921(a) requires that an operator must select the method, or methods, that are best suited to address the identified threats. 

## F.4.e – Reassessment Interval: Implementation

- Appropriate Reassessment Intervals
- Adequate Documentation
- Technical Bases Support the Intervals Selected

| Reference: |  |
| --- | --- |
| §192.939 |  |

**Notes:**
The inspectors will review the documentation developed to support the reassessment interval determinations to verify that the requirements of the IM program were followed and that the intervals were appropriately determined.  The basis for selection of reassessment intervals must be documented.  An IM program should not always default to the maximum allowed intervals in Table 3 without adequate written basis.
While the intervals specified in Table 3 of the supplement are maximums, the option to use the maximum interval is contingent on several factors depending on the assessment method selected.  The factors involve:
 The number of repairs made;
 Prevention activities completed; and
 The nature of the threats.
As stated in Note 1 of Table 3, certain threats can be extremely aggressive and may significantly reduce the interval between inspections.  Occurrence of a time-dependent failure requires immediate reconsideration of the appropriateness of the reassessment intervals.

## F.4.e – Max. Reassessment Interval: Implementation

| Assessment Method | 50% SMYS | 30% SMYS 50% SMYS | 30% SMYS |
| --- | --- | --- | --- |
| ILI, PT, DA | 10 years* | 15 years* | 20 yrs** |
| CDA | 7 years | 7 years | 7 years |
| Low Stress Reassessment | NA | NA | 7 yrs*** |

- *	CDA Must Be Performed at 7 Year Intervals
- **	Low Stress Reassessment or CDA Must Be Performed at 7 Year Intervals
- ***	Add’l Ongoing Actions Required Per 192.941

**Notes:**
To review, this slide provides a summary of the maximum reassessment intervals prescribed in Table 3 of the Supplement. As you can see, the maximum reassessment intervals increase as the pipe stress levels decrease. Maximum intervals vary from 10 to 20 years for primary assessment methods.  In all cases where the reassessment interval is greater than 7 years, an interim CDA or low stress reassessment must be performed at 7 year intervals.  Additionally, selection of a low stress reassessment involves additional ongoing actions that we will discuss in a few minutes.
Several of the conditions specified in Table 3 of the Supplement that are required to achieve the maximum intervals are as follows:
For pressure tests, the test pressure must meet specified values, depending on the MAOP of the pipe.  The required test pressure varies from 
1.25 times the MAOP for 5 year intervals for pipe operating at or above 50% SMYS to 
3.3 times the MAOP for a 20 year reassessment interval for pipe operating  below 30% SMYS.
For in-line inspections, the predicted failure pressure of the worst remaining (unrepaired) defect must exceed specified values in the table. 
For direct assessment, the maximum interval is 5 years for pipe operating 50% SMYS and 10 years for pipe operating below 50% SMYS, unless all indications are excavated examined and repaired, as required in Table 3 of the Supplement.

## F.5 – Deviations From Interval Requirements

- Program Meets or Exceeds B31.8S
- At Least 2 Integrity Assessments
- Anomalies Remediated
- Integration of Results and Lessons Learned
- Interim Reassessments Every 7 Years

| Reference: |  |
| --- | --- |
| §192.913 | FAQ-43, 45, 173, 227 |

**Notes:**
Protocol F.5 applies only if an operator pursues a performance-based program, but does NOT apply to operators implementing the prescriptive approach. OPS anticipates that most operators will pursue a prescriptive-based program for the near-term. Therefore, I am not going to discuss this protocol in detail, but will note the high-lights of this protocol question.
If operators implement a performance-based integrity management program they may choose to pursue an option to extend the maximum reassessment intervals.  In order to take advantage of this option, operators must satisfy the following requirements:
The operator must use a performance based IM program that meets or exceeds the requirements of the Supplement
The operator must have completed at least 2 integrity assessments on the segments to be included under the performance based approach
Anomalies identified in previous integrity assessments must have been remediated
Results and lessons learned from the more recent integrity assessment must have been incorporated into the operator’s data integration and risk assessment, and
Operators must still perform some reassessment (for example a CDA) at 7 year intervals.
Inspectors will perform a detailed review of any programs identified  as “exceptional performance” to verify that all of the requirements specified in the rule for such programs were appropriately implemented.

## F.6 – Waivers For Reassessment Intervals

- Appropriate Process Requirements for Waivers
- Waivers Are Justified
- Lack of Internal Inspection Tools
- Cannot Maintain Local Product Supply

| Reference: |  |
| --- | --- |
| §192.943(a)(1) | FAQ-43, 210 |

**Notes:**
The rule lists two specific situations in which operators may request a waiver to OPS in order to extend the reassessment interval beyond the maximum interval.  These situations are:
An operator who uses internal inspection as an assessment method may be able to justify a longer reassessment period for a covered segment if internal inspection tools are not available due to circumstances beyond its control, such as abnormally high demand for the tool.  To justify this, the operator must demonstrate that it cannot obtain the internal inspection tool services within the required reassessment period and that the operator is taking action in the interim to ensure the integrity of the covered segment.
An operator may be able to justify a longer reassessment period for a covered segment if the operator demonstrates that it cannot maintain local product supply if it conducts the reassessment within the required interval.
However, given the long intervals between required reassessments, an operator would need to make a strong argument that either of these conditions could not have been averted by prudent planning.

## F.6 – Waivers For Reassessment Intervals (continuation)

- Submit Waiver at Least 180 Days Before the End of the Required Reassessment Interval
- Unless Impractical Due to Unforeseen Local Product Supply Issues
- Submit Waiver Request as Soon as Need for Waiver is Known

| Reference: |  |
| --- | --- |
| §192.943(a)(1) | FAQ-43, 210 |

**Notes:**
If the operator decides to apply for a waiver, the waiver must be submitted to OPS at least 180 days before the end of the reassessment interval, unless unforeseen product supply issues make the period impractical.  Operators should be able to plan for seasonal product demand when scheduling assessments.  An example might be a situation where two lines provide local supply and one is scheduled to be taken out of service for an assessment, but the other line experiences a situation (such as an incident) that requires it to be taken out of service, thus necessitating that the assessment on the remaining line be delayed.   If such unexpected local product supply issues make the 180-day advance notification period impractical, an operator must apply for the waiver as soon as the need for a waiver becomes known.
Inspectors will review any documentation associated with waiver requests.

FAQ-43 provides additional discussion on the extension of assessment intervals and FAQ-210 provides information on notification requirements.

## F.7 – Environmental and Safety Risks

- Program Requirements to Minimize Environmental and Safety Risks
- Precautions Protect
- Workers
- Members of the Public
- Environment

| Reference: |  |
| --- | --- |
| §192.911(o) |  |

**Notes:**
As was discussed in the BAP protocol presentation, the rule contains a requirement that assessments be conducted in a manner that minimizes environmental and safety risks when conducting integrity assessments.  
A similar requirement also exists in Subpart J under section 192.515. 
In all likelihood, operators have already addressed these types of requirements in their everyday operations. Inspectors will review these procedures as well as evidence of implementation during assessments as part of the IM inspection.

As part of the review of the operator’s program, inspectors will look for measures that the operator has implemented to protect
Workers
The public, and
The environment

## Protocol Area F Continual Evaluation and Assessment

**Conclusion – **
**Thank you for your attention**

**Notes:**
This concludes my presentation on the protocols for Continual Evaluation and Assessment. Thank you for your attention. 

## Gas Integrity Management Rule Protocols

**Jill Henry **
**49 CFR 192.935**
**Preventive and Mitigative Measures**
**Protocol H**
**January 2005**

**Notes:**
[Greeting to the audience. Introduce yourself and tell where you work or fit into the Gas IMP process]  I will be discussing the gas integrity management protocols for Preventive and Mitigative Measures - or what I will refer to as P&M Measures.

The requirements related to Preventive and Mitigative Measures are primarily located in 3 Rule locations as shown on the next 2 slides...

## Three Basic Areas in §192.935

- General Requirements
- Third Party Damage & Outside Force Damage
- Automatic Shut-off Valves (ASV) and/orRemote Control Valves (RCV)

**Notes:**
The majority of the P&M Requirements can be found in Section 935.  There are three basic areas discussed in this section. They are:

General Requirements
Third Party Damage & Outside Force Damage
Automatic Shut-off Valves (ASV) and/or Remote Control Valves (RCV)

NEXT SLIDE - Other Areas Included in Preventive & Mitigative

## Other P&M Requirements

- Preventive Measures Aspect of Third Party Damage Requirements of §192.917(e)(1)
- Corrosion Evaluation and Remediation Requirements of §192.917(e)(5)

**Notes:**
In addition to requirements contained in  Section 935, preventive and mitigative measures are also addressed for two “particular threats” outlined in Section 917(e):

“Comprehensive additional preventive measures” are required if Third Party Damage is identified as a threat from Section 917(e)(1) as part of an operators threat identification process.

If corrosion is identified as a threat on a covered segment, then the evaluation and remediation requirements found in Section 917(e)(5) must be addressed.

## Protocols for  Preventive and Mitigative Measures 

- H.1 General Requirements (Identification of Additional Measures)
- H.2 Third Party Damage
- H.3 Pipelines Operating Below 30% SMYS
- H.4 Plastic Transmission Pipeline

**Notes:**
The gas integrity management rule requires that each operator must take additional measures beyond those already required by Part 192 to prevent a pipeline failure and to mitigate the consequences of a pipeline failure in a high consequence area. In order to confirm rule compliance of operators’ integrity management program for Preventive and Mitigative Measures, OPS has developed a set of 8 protocol questions under Protocol Area H. 

The protocols are label H.1 through H.8: 
H.1 General Requirements (Identification of Additional Measures) 
H.2 Third Party Damage 
H.3 Pipelines Operating Below 30% SMYS 
H.4 Plastic Transmission Pipeline ...

[Continued on the next slide.....]

## Protocols for  Preventive and Mitigative Measures 

- H.5 Outside Force Damage
- H.6 Corrosion
- H.7 Automatic Shut-Off Valves or Remote Control Valves
- H.8 Implementation of Additional P&M Measures

**Notes:**
...
H.5 Outside Force Damage 
H.6 Corrosion 
H.7 Automatic Shut-Off Valves or Remote Control Valves 
H.8 General Requirements (Implementation of Additional Measures) 

I’ll now walk you through the details of these protocols and provide you with insight on OPS’s expectations on how these protocols may be satisfied by an operator’s integrity management program.

## H.1 - General Requirements (Identification of Additional Measures) 

- Process to Identify Additional Measures to Prevent Pipeline Failures and Mitigate Potential Consequences.

| Reference: |  |
| --- | --- |
| §192.935(a) | FAQ-90, 180 |

**Notes:**
Protocol H.1 is intended to verify that an operator has a process in place to identify additional measures to prevent  pipeline failures and to mitigate the consequences of  pipeline failures in HCA’s. As noted by FAQ-90, operators will be expected to promptly identify the need for additional P&M Measures. Preventive and mitigative actions are responses to specific threats. While it would be valuable to have assessment results in hand when considering additional preventive and mitigative measures, the baseline assessment for some segments may not be conducted for several years – some as late as 2012.  Therefore, operators should not necessarily wait until after an assessment is conducted to perform a risk analysis and identify additional P&M measures.  Operators can, and should, gather enough information to evaluate risk and make timely determinations regarding preventive and mitigative measures.

## H.1 - General Requirements (Identification of Additional Measures) 

- H.1.a –Process Based on:
- Identified Threats
- Consider Threats in ASME B31.8S
- Risk Assessment
- Identify Needed P&M Measures

| Reference: |  |
| --- | --- |
| §192.935(a) | FAQ-113 |

**Notes:**
Protocol H.1.A addresses gas rule Section 935(a) requirements that the operator’s process must include consideration of threats as identified in Section 2.2 of the Supplement. 

The process must also include time dependent threats such as internal corrosion, external corrosion, and stress corrosion cracking; static or residual threats such as manufacturing defects, third party damage, outside force damage; and human error. The operator’s IMP should, at a minimum, include consideration of these threats in the evaluation process for identification of preventative and mitigative measures.

The rule also requires the use of risk assessment for determining what preventative and mitigative measures are needed for covered segments. The requirements for the risk assessment process are described in Section 5 of the Supplement.  It is expected that the operator’s IMP will describe how the risk assessment results are used to make decisions regarding P&M measures.

## H.1 - General Requirements (Identification of Additional Measures) 

- H.1.b –Spectrum of Alternatives
- Automatic Shut-Off Valves
- Remote Control Valves
- Leak Detection Systems
- Pipe Replacement
- Personnel Training
- Additional Inspections, Maintenance, etc.

| Reference: |  |
| --- | --- |
| §192.935(a) |  |

**Notes:**
The operator’s IMP should have a documented decision process that relies on risk analysis of its pipeline to identify additional measures to protect high consequence areas and to enhance public safety. The process should include, but not necessarily be limited to: 
additional measures such as installing Automatic Shut-off Valves or Remote Control Valves, 
installing computerized monitoring and leak detection systems, 
replacing pipe segments with pipe of heavier wall thickness, 
providing additional training to personnel on response procedures, 
conducting drills with local emergency responders
implementing additional inspection and maintenance programs.

OPS recognizes that each operator is likely to have a different process for making decisions about the implementation of additional preventive and mitigative actions.  Some operators may make use of a formalized "decision model" for their evaluation, while others may use a more informal process based on general considerations.  Whatever method is used, the use of a risk analysis is required, and should be reflected in the process that is used for evaluating a spectrum of potential preventive and mitigative measures. 

## H.2 - Third Party Damage

** **

- Additional P&M Measures for TPD
- Enhancements to Damage Prevention Programs
- Actions Identified by Data Integration

| Reference: |  |
| --- | --- |
| §192.935(b) | FAQ-90 |

**Notes:**
Protocol H.2 guides inspectors to evaluate an operator’s preventive and mitigative measures with regard to threats due to third party damage.

Third party damage is a significant challenge to safe pipeline operations. This protocol will focus on 2 key areas:  
 enhancements to operators’ damage prevention programs and 
(2) preventive and mitigative actions identified through data integration processes.

## H.2 - Third Party Damage

- H.2.a – Enhancements to Damage Prevention Program
- Use of Qualified Personnel
- Central Data Base for Excavation Damage Information
- Covered & Non-Covered Segments
- Root Cause to Identify P&M Actions
*- continued on next slide*

| Reference: |  |
| --- | --- |
| §192.935(b)(1) |  |

**Notes:**
Protocol H.2.A reviews implementation of enhancements to operators’ damage prevention programs. Operators are required to have a written damage prevention program that meets the requirements of 192.614. Section 935(b)(1) of the Gas Integrity Management Rule requires that this program be enhanced to include additional requirements.  Inspection will verify that either the damage prevention program includes enhanced requirements above and beyond the minimum requirements contain in Section 614 or that the operator’s IMP has specific requirements to promptly develop such enhancements. The enhancements, at a minimum, must include the following: 

Using qualified personnel for work an operator is conducting that could adversely affect the integrity of a covered segment, such as marking, locating, and direct supervision of known excavation work. 

Use of a central database of information that is location specific on excavation damage that occurs in both covered and non covered segments in the transmission system. The data should include a root cause analysis supporting identification of targeted additional preventative and mitigative measures in the high consequence areas. 

And continuing on the next slide...

## H.2 - Third Party Damage

- H.2.a – Enhancements to Damage Prevention Program
*- continued from previous slide*
- One-Call System Participation
- Monitoring of Excavations
- Investigation of Encroachments
- Excavation/Remediation, or
- Above Ground Survey

| Reference: |  |
| --- | --- |
| §192.935(b)(1) |  |

**Notes:**

Participation in one-call systems in locations where covered segments are present. 

Monitoring of excavations conducted on covered pipeline segments. 

If an operator finds physical evidence of encroachment involving excavation, then the operator must either excavate the area near the encroachment or conduct an above ground survey using methods defined in the NACE Standard.

And finally, the operator’s enhanced damage prevention program should also require excavation and remediation of any indication of coating holidays or discontinuity warranting direct examination. 

## H.2 - Third Party Damage

- H.2.b –Comprehensive Additional Preventive Measures
- For Significant TPD Threat Identified Through Data Integration

| Reference: |  |
| --- | --- |
| §192.917(e)(1) |  |

**Notes:**
Protocol H.2.b focuses on comprehensive additional P&M measures in cases where a significant TPD threat was identified through the data integration process.  The process for data integration and collection is inspected under Protocols C.2 and C.3 as discussed earlier.   As part of these processes, risk assessments are to be performed to help determine what preventative and mitigative measures are needed for covered segments. The results of the data integration will be reviewed to determine if third party damage was identified as a significant threat to covered pipeline segments. 

If significant third party damage risks are identified, the operator should have implemented comprehensive additional preventive measures. Inspectors will review the operator’s decision making process that is used to determine what additional preventive measures should be taken. Some examples might include:
increased patrols
improved public communication and awareness
additional pipeline location markers
use of marker tape or alarm tape

## H.3 - Pipelines Operating Below 30% SMYS

** **

- Damage Prevention Requirements for Pipelines Operating Below 30% SMYS
- Requirements for Pipelines Located in High Consequence Areas
- Requirements for Pipelines in Class 3 and 4 Locations But Not Located in High Consequence Areas

| Reference: |  |
| --- | --- |
| §192.935(d) |  |

**Notes:**
Protocol H.3 provides integrity management inspection requirements related to P&M measures for pipelines that operate below 30% SMYS.

2 subsets of requirements are included:  1 for those pipelines operating below 30% SMYS that are located in a high consequence area; and second a set of requirements for those pipelines operating below 30% SMYS that are located in a class 3 or 4 area but not in a high consequence area.

Note that some of these protocol requirements are the same as provided under protocol H.2 for pipelines operating above 30% SMYS.

## H.3 - Pipelines Operating Below 30% SMYS

- H.3.a – Pipelines Located in HCA, Damage Prevention Program to Include:
- Use of Qualified Personnel
- One-Call System Participation
- Monitoring of Excavations or Bi-Monthly Patrols
- Follow-Up Investigations

| Reference: |  |
| --- | --- |
| §192.935(d) | FAQ-90 |

**Notes:**
Protocol H.3.a is for pipelines operating below 30% SMYS located in a HCA and is similar to protocol H.2.a except that it does not include elements for collection of excavation damage information in a central database. 

Inspection will verify that either the damage prevention program includes the enhanced requirements or that the operator’s IMP has elements addressing the required enhancements and complements to the written damage prevention program required by 192.614. 

The enhancements, at a minimum, must include the following: 
Using qualified personnel for work an operator is conducting that could adversely affect the integrity of a covered segment. 
Participation in one-call systems in locations where covered segments are present. 
And finally, the operator’s enhanced damage prevention program should also require that excavations near the pipeline be monitored or that bi-monthly patrols be conducted. If indications of unreported construction activity are found, inspection should verify that required follow up investigations are conducted to determine if mechanical damage has occurred. 

## H.3 - Pipelines Operating Below 30% SMYS

- H.3.b – Class 3/4 Area & Not in HCA, Damage Prevention Program Includes:
- Use of Qualified Personnel
- One-Call System Participation
- Monitoring Of Excavations or Bi-Monthly Patrols
- Follow-Up Investigations
- Semi-Annual / Quarterly Leak Surveys

| Reference: |  |
| --- | --- |
| §192.935(d) | FAQ-230 |

**Notes:**
Protocol H.3.b deals with damage prevention requirements for class 3 or 4 pipeline locations that are not located in an HCA. 

This protocol is essentially the same as I just covered under H.3.a for pipelines operating below 30% SMYS located in a HCA except that 1 additional requirement is included; that is that the operator performs semi-annual leak surveys - quarterly for unprotected pipelines or cathodically protected pipe where electrical surveys are impractical.

## Pipelines Operating Below 30% SMYS

| P&M Measure | In HCA | Class 3 / 4 & Non-HCA |
| --- | --- | --- |
| Qualified Personnel | X | X |
| One-Call | X | X |
| Excavation Monitoring 
OR Bimonthly Patrols | X | X |
| Semi-Annual Leak Survey* |  | X |

- *Quarterly if Unprotected or Electrical Surveys
-   Impractical

**Notes:**
This slide summarizes the requirements discussed for protocols H.3.a and H.3.b.  Again, note that the only difference is that lines located outside of HCAs but in Class 3 or 4 locations have an additional requirements to conduct a periodic leak survey.

## H.4 - Plastic Transmission Pipeline

** **

- TPD Prevention Program:
- H.4.a – Use of Qualified Personnel
- H.4.b - One-Call system Participation
- H.4.c - Monitoring of Excavations
-  Follow-Up Investigations

| Reference: |  |
| --- | --- |
| §192.935(e) |  |

**Notes:**
Protocol H.4 discusses damage prevention requirements for plastic transmission pipelines. 

The integrity management protocol inspection requirements for plastic pipelines are essentially a subset of the requirements I covered under protocol H.2 for pipelines operating at greater than 30% SMYS, so we will not discuss them again.

## H.5 - Outside Force Damage

** **

- Threats Due to Outside Force
- (e.g., Earth Movement, Floods, Unstable Suspension Bridge)
- H.5.a – Operator to Take Measures to Minimize Consequences

| Reference: |  |
| --- | --- |
| §192.935(b)(2) | FAQ-90 |

**Notes:**
Operators are required to make a determination if outside forces are a significant threat to the integrity of a covered segment. Outside force may include:
threats from earth movement
floods, and
unstable suspension bridge.

If a significant threat applies, then measures must be taken to minimize the consequences to the covered segment.  For example, these measures include, but are not limited to, 
increasing the frequency of aerial, foot or other methods of patrols, 
adding external protection, 
reducing external stress, and
relocating the line

Integrity Management inspections will verify that an operator’s covered segments have been evaluated to identify susceptibility to outside force damage. Inspectors will also verify that if a pipeline is susceptible to outside force damage, then appropriate measures have been taken to minimize potential consequences to the covered segments.

## H.6 - Corrosion

**  **

- P&M Actions to Address Corrosion
- H.6.a - Identify Severe Corrosion
- Evaluate & Remediate
- All Segments with Similar Coating & Environment
- Both Covered and Non-Covered Segments
- Schedule for Evaluation & Remediation

| Reference: |  |
| --- | --- |
| §192.935(e)(5) | FAQ-135 |

**Notes:**
Protocol H.6 deals with preventive and mitigative measures to address corrosion threats that could adversely affect pipeline integrity as defined by Section 933. The operator’s IMP will be reviewed to verify: 1) That it includes provisions for evaluation and remediation of corrosion threats; 2) That the operator makes a determination if severe corrosion exists on a covered pipeline segment that could adversely affect the integrity of the line, and 3) That if severe corrosion is identified, then the IMP must require evaluation and remediation, as necessary, of all pipeline segments - both covered and noncovered - with similar material coating and environmental characteristics. 

Operators will be expected to establish and maintain a schedule for evaluation and remediation of the similar segments consistent with the operator’s established operating and maintenance procedures under Part 192 for testing and repair.  Provisions for establishment and control, including change control provisions, of the schedule must be documented in the operator’s IMP. Note that FAQ-135 addresses how segments not in HCAs must be considered after discovering corrosion in a covered segment. The rule requires that operators who identify corrosion in a covered segment that could adversely affect the integrity of the line must evaluate and remediate, as necessary, all pipeline segments (both covered and non-covered) with similar material coating and environmental characteristics (192.917(e)(5)). This section of the rule refers to conditions identified in section 192.933 as those requiring this evaluation and remediation. Those conditions represent severe corrosion -- instances in which the remaining strength of the pipe is less than or equal to 1.1 times MAOP. As a matter of prudence, OPS would expect operators to consider non-covered segments, as appropriate, when less severe corrosion is found (for example, when a new corrosion threat has been identified), but such broader evaluations are not required by the rule.

## H.7 - Automatic Shut-Off Valves or Remote Control Valves

**  **

** **

- Determine if ASVs/RCVs Needed
- H.7.a - Process to Use Risk Assessment-Based Process for Decision Making

| Reference: |  |
| --- | --- |
| §192.935(c) | FAQ-86 |

**Notes:**
Protocol H.7 is designed for inspection of operator evaluations of the need for adding automatic shut-off valves or remote control valves.  Each operator’s IMP must include a risk assessment-based process describing methodology for determining if an automatic shut-off valve or remote control valve should be added.  As a minimum, the following factors must be included in the process: 
 * swiftness of leak detection and pipe shutdown capabilities
 * the type of gas being transported
 * operating pressure
 * the rate of potential release
 * pipeline profile
 * the potential for ignition
 * location of nearest response personnel

FAQ-86 affirms the rule requirement that an operator is required to install an ASV or RCV if the operator determines that it would be an efficient means to protect an HCA in the event of a gas release.

## H.8 - General Requirements (Implementation of Additional Measures)

**  **

** **

- Implement Additional Measures to Prevent & Mitigate a Pipeline Failure
- H.8.a – Document Decisions and Results
- Input from Relevant Parts of the Organization

| Reference: |  |
| --- | --- |
| §192.935(a) |  |

**Notes:**
Protocol H.8.a guides inspectors to review the results of the operator’s P&M processes to assure that appropriate additional P&M actions are planned, scheduled, and implemented. The review will check that input was obtained from relevant parts of the organization such as operations, maintenance, engineering, and corrosion control. Preventive and mitigative measures that are proposed to reduce specific identified risks are best developed or specified by the parts of the organization that have the most knowledge of the areas under evaluation.  

As was mentioned earlier, OPS recognizes that each operator is likely to have a different process for making decisions about the implementation of additional preventive and mitigative actions.  Some operators may make use of a formalized "decision model" for their evaluation, while others may use a more informal process based on general considerations.  Whatever method is used, the use of a risk analysis is required, and should be reflected in the decisions made to select additional preventive and mitigative measures. 

## H.8 - General Requirements (Implementation of Additional Measures)

- H.8.b – Decision-Making Process Considers
- Likelihood
- To Identify Actions for _Prevention_ of Pipeline Failures
- Consequences
- To Identify Actions for _Mitigation_ of Pipeline Failures

| Reference: |  |
| --- | --- |
| §192.935(a) |  |

**Notes:**
Protocol H.8.b guides inspectors to verify that the P&M decisions considered both the likelihood and consequences of pipeline failures. The underlying reason for this protocol is to make sure that the consequence factors are not overlooked. 

Clearly, segments and facilities that represent the highest risk are the most important candidates for additional preventive and mitigative actions.  Therefore, the inspection team will determine if additional actions have been evaluated for the highest risk operations as indicated by the risk analysis. While the evaluation may or may not result in action being implemented, it is important to determine that the operator’s process gives priority to the highest risk portions of the pipeline. 

## H.8 - General Requirements (Implementation of Additional Measures)

- H.8.c – Additional P&M Measures Must be:
- Identified
- Documented, and
- Implemented (or Scheduled)

| Reference: |  |
| --- | --- |
| §192.935(a) |  |

**Notes:**
Protocol H.8.c guides inspectors to verify that additional P&M measures are identified and documented and have actually been implemented, or scheduled for implementation.  Operators should also document how P&M activities are incorporated into O&M manuals and are actually being accomplished in the field.  

It is expected that most operators will use existing company work processes to implement additional actions. It is likely that some additional P&M actions will be non-hardware process or procedural changes which should be straightforward to inspect. In the case of hardware changes, OPS understands that modifications are often scheduled around budget cycles and/or operational constraints.  To implement a planned preventive and mitigative action might require the involvement of several groups, such as Engineering, Maintenance, Operations, Planning and Budget, and Project Management.  Both hardware and procedural changes will be evaluated by OPS to verify that the additional actions are actually implemented or scheduled for implementation.

## Protocol Area H Preventive and Mitigative Measures 

**Conclusion – **
**Thank you for your attention**

**Notes:**
This concludes my presentation on the protocols for P&M Measures. Thank you for your attention. 

## Gas Integrity Management Rule Protocols

**Steve Nanney**
**49 CFR 192.909, **
**911(k)(l)(m) & (n), 915, 945, 947 **
**Management & Administrative**
**Protocols I, J & K**
**January 2005**

**Notes:**
[Greeting to the audience. Introduce yourself and tell where you work or fit into the Gas IMP process]

I will be presenting the gas integrity management protocols for inspecting various Management and Administrative activities required by the Rule.

This presentation addresses Protocol Sections I, J, and K and covers various sections  of the Rule.
Document – before/after
Communication – before/after
Submit

## Key Elements Management & Admin.

- I - Performance Measures
- J - Recordkeeping
- K - Management of Change
- L - Quality Assurance
- M - Communications Plan
- N - Submittal of Program Documents

**Notes:**
Numerous portions of the Rule deal with management and administrative programs that are key elements of the IM program process. Many of these processes are already being performed by operators, so the challenge will be to ensure that the IM process is properly integrated into the existing programs.  The following subject areas are considered to be part of the Management and Administrative protocol set:
Protocol I - The development and administration of performance measures
Protocol J - Recordkeeping activities
Protocol  K - Program requirements that manage and control changes to the program and the pipeline.
Protocol L - The quality assurance process
Protocol  M - Communication Plans for both internal and external communication
Protocol N - Requirements for the submittal of program documents to OPS, when requested.

## I.1 – Performance Measures (Required Measures)

- Four Measures in B31.8S, Section 9.4
- Number of Miles of Pipeline Inspected
- Number of Immediate Repairs Completed
- Number of Scheduled Repairs Completed
- Number of Leaks, Failures, and Incidents
- Measures Taken Semi-Annually (Through June 30 and Dec. 31)

| Reference: |  |
| --- | --- |
| §192.945(a) B31.8S §12(b)(5) | FAQ-136, 137, 186 |

**Notes:**
The first area of discussion is the development of program performance measures and associated reporting requirements.  The requirements for this activity are found in section 945 of the Rule.  The associated protocol set is found in Section I of the protocols.

Protocol I.1 is shown in this slide.  Operators are expected to measure the effectiveness of their program using the four measures found in Section 9.4 of the Supplement.  These measures are:

Number of miles of pipeline inspected versus program requirements
Number of immediate repairs completed as a result of the integrity management inspection program
Number of scheduled repairs completed as a result of the integrity management inspection program
Number of leaks, failures, and incidents classified by cause

The rule requires that these metrics be taken on a semi-annual basis and program documents are expected to address the need to take these measures. Further, it is specified that these measures be taken through each June 30th and each December 31st.  Program requirements should exist that define these dates for data accumulation.

## I.1 – Performance Measures (Required Measures)

- Threat-Specific Measures in B31.8S, Appendix A

| Reference: |  |
| --- | --- |
| §192.945(a) B31.8S §12(b)(5) | FAQ-82, 136, 137, 186 |

| External Corrosion | Equipment |
| --- | --- |
| Internal Corrosion | 3rd Party Damage |
| SCC | Incorrect Operations |
| Manufacturing | Weather / Outside Force |
| Construction |  |

**Notes:**
Inspectors will be looking for proper application of the process to select and employ the threat-specific measures found in Appendix A of the Supplement.  These threats are:
External corrosion threats
Internal corrosion threats
SCC threats
Manufacturing threats
Construction threats
Equipment threats
3rd party damage threats
Incorrect operations, and
Weather related and outside force

It is expected that operators will be able to demonstrate that they have been through the threat-specific list of metrics, identify the applicable threats to their pipeline system, and call for the use of the applicable metrics to measure IM program effectiveness.  It would also be expected that operators periodically review their threat listing to make sure that any new threats identified result in the appropriate expansion of the list of performance measures to be taken.

## I.2 – Performance Measures (Record Verification)

- Performance Measures Taken Semi-annually
- Report for Section 9.4 Measures Filed by Due Dates (End of August and End of February)

| Reference: |  |
| --- | --- |
| §192.945(a) | FAQ-137, 194 |

**Notes:**
Performance measures will be evaluated by confirming that the data is taken semi-annually. The inspector will also confirm that the threat-specific measures used by the operator cover the full set of identified threats to the pipeline.

Reporting of the 4 performance measures required by Section 9.4 of the Supplement are required by the end of the second month following the measurement period.  The first report filling date was August 31st of 2004.  Reporting will be accepted on-line.  More details on use of the IMDB reporting will be given in a later presentation.  The due date for the measures taken by the end of December is the last day of February for the next year.  Inspectors will confirm that these dates have been met. Threat-specific measures are not required to be reported to OPS, but will be reviewed during an inspection.

Note that FAQs 137 and 194 provide additional details related to record verification and performance measures.

## I.3 – Performance Measures(Exceptional Performance Measures)

- Operator Meets 192.913(b)
- Define and Implement Additional Performance Measures
- Report Measures Semi-Annually

| Reference: |  |
| --- | --- |
| §192.913(b)(vii) | FAQ-194, 209 |

**Notes:**
Protocol I.3 provides inspection guidance for those operators using the Exceptional Performance provisions of the rule. Note that in the near-term, OPS does not anticipate these provisions to be used by operators.  By inspecting the protocols associated with Section 913, the conclusion will be made whether the operator does, in fact, meet the requirements for Exceptional Performance designation.  Such operators must, as part of their exceptional performance, define and implement additional IM program metrics that monitor the effectiveness of their program.  These metrics are in addition to the minimum required metrics specified in Section 9.4 and Appendix A of the Supplement.  The specific metrics are not prescribed, but it will be expected that the operator can demonstrate the process by which these additional metrics were determined and the reasons why they are useful.  These measures must be taken semi-annually and reported semi-annually similar to the Supplement Section 9.4 measures. 

FAQs 194 and 209 provide additional background information related to this protocol question.

## J.1 – Recordkeeping

- Identify Records to be Retained
- Identify Location Where Kept
- Specify Retention Requirements

| Reference: |  |
| --- | --- |
| §192.947 B31.8S §12.1, 12.2(b)(1) | FAQ-32, 165, 189 |

**Notes:**
Section J of the protocols deals with the process of recordkeeping.  This protocol set covers the requirements set forth in Section 947 of the Rule.  

Protocol J.1 is concerned with IM compliance records and their retention period.  The first step in this process is to identify which records are to be kept.  Inspectors will look for a listing of document types to be retained and will then review the procedures that result in the generation of those documents to confirm that steps are included to ensure that the records are sent to appropriate locations where they can be readily retrieved.  Document retention requirements would also be reviewed to verify that required records are retained for the useful life of the pipeline.

Note that FAQs-32, 165, and 189 provide additional information on recordkeeping requirements.

## J.1 – Recordkeeping (cont.)

- Types of Records to be Kept
-  Written IM Program & Procedures
-  Threat Identification & Risk Assessment
-  Baseline Assessment Plan
-  Training
-  Remediation Schedule & Technical Basis
-  Direct Assessment
-  Confirmatory Direct Assessment
-  Notifications

| Reference: |  |
| --- | --- |
| §192.947 B31.8S §12.1, 12.2(b)(1) | FAQ-32, 165, 189 |

**Notes:**
The following types of records are specifically identified in the Rule as records that are required to be kept for the useful life of the pipeline:
The written IM program, including applicable procedures
Threat identification and risk assessment documentation, including any documents that provide the basis for any assumptions made.
The Baseline Assessment Plan.  This would also include any future assessment plans.
Training and qualification information for personnel and vendors participating in the IM Program processes.
The schedule prepared to perform remediation of anomalies and the technical assessment of those activities.
Direct Assessment documentation.
Confirmatory Direct Assessment documentation, and
Any notifications provided to OPS, State or local pipeline safety authorities.
Inspectors may examine a sampling of these records or may be checking these records as they apply to other areas of inspection.

## J.1 – Recordkeeping (continuation)

- Types of Records to Be Kept
- Supporting Documentation Such as:
- The Basis for Analytical Assumptions
- Selection of P&M Measures
- Operating Logs
- Calculations that Support a Pressure Reduction
- Disposition of Anomalies
- Performance Metrics

| Reference: |  |
| --- | --- |
| §192.947 B31.8S §12.1, 12.2(b)(1) | FAQ-32, 165, 189 |

**Notes:**
One additional type of documentation that is specified by the Rule are those records that support decisions affecting the IM Program and pipeline integrity.  This is a broad set of information and includes analysis documents, evaluations, decision documents, calculations, change documents, amendments, revisions, deviations, and determinations made affecting the IM program or pipeline integrity.  Some examples of this type of documentation include:

The basis for assumptions used to support a technical approach, such as risk analysis weighting factors,
Basis for selection of additional preventive and mitigative measures, including those candidate measures that were considered but not implemented,
Operating logs that record operating pressure for a pipeline at the time an immediate threat condition is discovered,
Documentation of the calculations that determine the proper level to reduce operating pressure when an immediate threat condition is discovered, 
Technical decisions made based on assessment results that impact the way an anomaly is to be categorized or remediated, and
Performance metrics

## K.1 – Mgmt. of Change (IM Program Changes)

- Document Reasons for Changes
- Notification for Significant Changes
- Filed within 30 Days of Adopting the Change

| Reference: |  |
| --- | --- |
| §192.909(a), (b) | FAQ-97, 98, 99, 111, 153, 201 |

**Notes:**
Protocol Section K is concerned with the Management of Change process employed by the operator. There are two aspects of Management of Change :  (1) Changes to the IM Program; and (2) Changes to the  pipeline that affect integrity.  Requirements regarding Management of Change are found in Sections 909 and 911(k).  The 911(k) section directly invokes Section 11 of the Supplement.
Protocol K.1 addresses changes to the IM program itself.  In all cases, changes to the program and its implementation must be documented.  Changes must be accomplished in accordance with a defined change process.  Inspectors will review the operator’s change process as it is defined in procedures, then confirm that changes are made to program documentation in accordance with these procedures.
Program changes must be documented and approved prior to implementation of the change.  This will be verified by examining revisions and their documented reason along with confirming implementation dates.
When changes to the IM Program are significant in nature, OPS must be notified within 30 days of adopting the change.  The effective date of such changes will be compared to any notification dates.  Examples of the types of program changes that would be expected to require notification are as follows:
Merger of Companies or major acquisition of a pipeline system,
Determination of susceptibility to SCC when previously considered unsusceptible,
Introduction of an assessment methodology not previously used, or
Abandoning an assessment methodology previously planned for use.

Note that there are numerous FAQs associated with the management of change process: FAQ-97, 98, 99,111, 153,and 201

## K.2 – Mgmt. of Change (B31.8S, Section 11)

- Procedures that Control the Change Process
- Technical, Physical, Procedural, and Organizational Changes

| Reference: |  |
| --- | --- |
| §192.911(k) B31.8S §11(a) |  |

**Notes:**
Protocol K.2 is intended to confirm that the requirements invoked from Section 11 of the Supplement have been met.  

The first sub-item in this protocol will inquire whether the operator has a process for handling changes.  Then, a sampling of changes will be reviewed to ensure that technical, physical, procedural and organizational changes that could affect pipeline integrity are being processed using these change control procedures.

## K.2 – Mgmt. of Change(B31.8S, Section 11 (cont.))

- Procedures Address:
-  Reason for Change
-  Authority for Approval
-  Analysis of Implications
-  Required Permits
-  Documentation Requirements
-  Communication of the Change
-  Time Limitations
-  Staff Qualifications

| Reference: |  |
| --- | --- |
| §192.911(k) B31.8S §11(a) | FAQ-139 |

**Notes:**
The following are required elements, as specified in Section 11 of the Supplement, to be addressed by the change process procedures:
The reason for the change must be documented.  It is expected that the Management of Change process ensures that a description of what is to change and why it is to be changed gets written down as part of the change documentation.
The procedures must identify the appropriate internal (company) authorities who must approve the change.
Each change must undergo an analysis of the full implications of the change.  This is essential to ensure that all aspects of the change are understood and documented.
Management of Change procedures must also identify when permits are required and direct that they be obtained.
The procedures will be reviewed to ensure that required documentation to be included in the change package is identified.
One essential aspect of any change is ensuring that all parties affected by the change are informed and have the opportunity to update any affected documents and documentation, for example, risk analysis information, O&M plans, training manuals, procedures, and drawings.
Change procedures will be reviewed to ensure that appropriate time constraints are identified as a change is processed.
Finally, the qualifications of personnel involved in the change process must be addressed by the Management of Change program or procedures.

## K.2 – Mgmt. of Change(B31.8S, Section 11 (cont.))

- IM Program Changes Reflected in Pipeline System
- Pipeline System Changes Reflected in the IM Program
- Review Before Implementation
- Risk Assessments Involved as Applicable

| Reference: |  |
| --- | --- |
| §192.911(k) B31.8S §11(a) | FAQ-139 |

**Notes:**
As adjustments are made to the IM program, these changes will possibly affect the pipeline system itself.  An example might be the decision to implement new or different preventive or mitigative features.  Inspectors will confirm that the program changes are implemented in the pipeline’s physical features and the O&M manual, as necessary.

Similarly, physical changes to the pipeline must be reflected in other IM program documentation.  An example is the need to reflect the completion of remediation actions in the risk assessment for the covered segment.

An effective change control process will ensure that a thorough review of the change is performed by all affected parties BEFORE the change is implemented.  This will help ensure that the configuration of the pipeline is accurately understood and minimize errors in the change process.

Once again the impact of changes on risk assessment data must be an integral part of the Management of Change process.

## Management & Administrative Protocols I, J & K 

- Conclusion of Protocols I, J, and K
- Thank you for your attention.

**Notes:**
This concludes my presentation on the first set of management and administrative protocols. The second set, protocols L. M, and N will be covered next.

Thank you for your attention.

## Gas Integrity Management Rule Protocols

**Steve Nanney**
**49 CFR 192.909, **
**911(k)(l)(m) & (n), 915, 945, 947 **
**Management & Administrative**
**Protocols L, M & N**
**January 2005**

**Notes:**
[Greeting to the audience. Introduce yourself and tell where you work or fit into the Gas IMP process]

Now I will be presenting the second set of gas integrity management protocols for inspecting various Management and Administrative activities required by the Rule.

This presentation addresses Protocol Sections L, M and N and covers various sections of the Rule.

## L.1 – Quality Assurance(B31.8S, Section 12)

- Defined Responsibilities and Authorities
- IM & QA Program Reviews
- Corrective Actions
- Use of External Resources

| Reference: |  |
| --- | --- |
| §192.911(l), B31.8S §12 | FAQ-76 |

**Notes:**
Protocol Section L addresses the requirements of a Quality Assurance process.  Requirements for the QA Process are found in Sections 909, 911(L), and 915 of the Rule.
Protocol L.1 in this Section addresses the required portions of Section 12 of the Supplement.  This Section has a mix of “should” and “shall” statements.  The protocol is focused on the “shall” statements.
The first part of this protocol will check to verify that essential IM program responsibilities and authorities are defined in program documentation.  There should also be provisions for IM program and QA program reviews that help management understand the effectiveness of these programs.
A corrective action process is an essential part of any QA process.  Inspectors will look for procedures that contain requirements for the corrective action process.  When corrective actions are specified for some aspect of the IM Program, the inspector will verify that the specified corrective actions were, in fact, completed and that they were sufficient to address the concern needing correction.
If the operator chooses to use external resources, such as an ILI vendor, inspectors will confirm how the operator ensures control of such processes and will review the associated documentation within the operators quality program.

## L.2 – Quality Assurance(Personnel Qualifications)

- Supervisors
- Performing/Evaluating Assessments
- Implementing P&M Measures
- Locating Buried Structures
- Supervising Excavations
- Others
- Persons That Implement IM Program
- Employees
- Contractors, Consultants, Vendors

| Reference: |  |
| --- | --- |
| §192.911(l), B31.8S §12 | FAQ-76 |

**Notes:**
Protocol L.2 is concerned with establishing the qualification requirements and the documentation that supports the conclusion that an individual is qualified to do his/her job.  Personnel requiring qualification include:
Supervisory personnel
Personnel who perform pipeline integrity assessments and those who evaluate the results.
Personnel who implement preventive and mitigative measures must be trained and qualified to do their assigned duties.  This includes personnel who locate buried structures, supervisors who are in charge of excavation activities and others who are involved in the specification and implementation of Preventive and Mitigative measures.
In addition personnel who execute the various parts of the IM program must be qualified.  Inspectors will be searching for evidence that these people have been trained as indicated in their qualification records.  Operators are responsible for ensuring the qualification of not only their own personnel, but also the personnel of contractors, consultants, and vendors that implement various aspects of the IM program.

## L.3 – Non-Mandatory Statements in Standards Invoked by the Rule

- Approaches to Address “Should” Statements in Standards
- Incorporate as Recommended
- Justify Equivalent Alternative
- Document Justification for Not Implementing
- Some “Non-mandatory” Actions in Standards Are Required by Rule

| Reference: |  |
| --- | --- |
| §192.7(a) | FAQ-155, 167 |

**Notes:**
Protocol L.3 is intended to remind OPS inspectors that the “should” statements in the invoked standards or reports must be addressed.  OPS expects that operators will implement those actions that the standards indicate should be performed.  Operators cannot simply ignore the “should” statements in the standard.  There are three options an operator has when “should” statements appear in these referenced documents.  
The inspector will look to see if the “should” statements have been implemented as recommended.  
If an operator does not like the recommendation as written, an equivalent alternative may be selected.  The basis for the operator choosing his alternative must be justified in writing.
The last choice is to simply not implement the “should” statement.  When this choice is taken, the reason the “should” statement is not implemented must be documented.  Operators must have a strong technical basis for not implementing any action that the standard indicates “should” be performed.  

Also, note that some “non-mandatory” requirements in the standards have been explicitly invoked in the rule.  In these cases, the non-mandatory aspects of the standard become mandatory requirements.  FAQs 155 and 167 provide additional information on the implementation of non-mandatory requirements in the standards.

## M.1 – Communications Plan (B31.8S, Section 10)

- API RP-1162
- Invoked by Proposed Rule
- IM Requirements for External Communications Met by Implementing Proposed Rule
- Internal Communications

| Reference: |  |
| --- | --- |
| §192.911(m), B31.8S §10.3 | FAQ-167, 184 |

**Notes:**
API Recommended Practice 1162 has provisions for external communications that are being/have been invoked by a new Rule on Public Education Programs for Hazardous Liquid and Gas Pipeline Operators.  The requirements of the Integrity Management Rule for external communications will be met by those operators who comply with the Public Education Rule.  The Integrity Management Rule focuses on execution of the operator’s Communication Plan for HCAs, but this plan may be part of a larger, more integrated effort.
The internal communications process will be examined to determine the effectiveness of communicating IM Program goals, requirements, and performance to company participants and stakeholders.  Management support for the program is essential and one element that demonstrates this support is internal communication that emphasizes the roles, responsibilities, and achievements of those participating in the process.  Both the internal communication plan and its execution will be inspected.

## M.1 – Communications Plan (B31.8S, Section 10)

- External Communications Affecting:
-  ROW Landowners and Tenants
-  Public Officials
-  Emergency Responders
-  General Public

| Reference: |  |
| --- | --- |
| §192.911(m), B31.8S §10.3 | FAQ-167, 184 |

**Notes:**
Protocol M addresses requirements for the development of a Communications Plan.  This set of protocols provides for inspection of compliance with Section 911(m) of the Rule which invokes Section 10 of the Supplement.
Operator Communications Plans are expected to address both external and internal communications activities in order to keep affected parties informed of the progress and performance of IM program activities.  External communications may already be embodied in activities being conducted by operators.  An integration with pertinent aspects of the IM program would be expected.  External communications plans must include appropriate communications with the following groups of people:
Rights-of-Way landowners and tenants
Public officials other than emergency responders
Both local and regional emergency responders, and
The general public
Plans should address the frequency and nature of the communication activity and identify the means by which communication is effected.  When changes to the IM program are made that could have an impact on others, the timeliness of communication of the changes must be considered.  These aspects of External Communications will be examined by the inspector along with the implementation of the plan – that is, has the plan been carried out as intended?

## M.2 – Communications Plan(Safety Concerns)

- Upon Request, Address Safety Concerns Raised by
- OPS
- State or Local Pipeline Safety Authorities
- Address in IM Procedures

| Reference: |  |
| --- | --- |
| §192.945(a) |  |

**Notes:**
Section 911(m) of the Rule includes requirements for the operator to address safety concerns raised by OPS inspectors, and State or Local Pipeline Safety Authorities having  jurisdiction by virtue of an Interstate Agent Agreement.  When concerns have been raised, inspectors will check that the concerns have been fully addressed.  Addressing safety concerns would be expected to include not only a correction of the immediate concern, but an evaluation of the cause, the generic implications, and any appropriate actions to prevent recurrence of the concern.  Compliance with this requirement must be addressed in IM Program procedures.

## N.1 – Submitting Program Documents

- Submit IM Documentation Upon Request to:
- OPS
- State or Local Pipeline Safety Authorities
- Address in IM Program Procedures
- OPS Intends to Request IM Program Documentation

| Reference: |  |
| --- | --- |
| §192.911(n) |  |

**Notes:**
One protocol item exists in Section N.  It addresses Section 911, paragraph (n) of the Rule regarding the submittal of IM Program documentation to OPS and State or local pipeline safety authority as applicable.  This documentation must be submitted when requested.  It is expected that the operator will have procedures or program documents that implement this requirement.  When a request has been made, operators should retain documentation as evidence compliance.  

It is the intention of OPS to request operator’s IM program documentation prior to an IM inspection to facilitate performance of the inspection.

## Management & Administrative Protocols L, M & N 

- Conclusion of Protocols I, J, and K
- Thank you for your attention.

**Notes:**
This concludes my presentation on the second set of management and administrative protocols. 

Thank you for your attention.

## Gas Integrity Management Oversight

**Zach Barrett**
**Inspection Format and Related Issues**
**January 2005**

## Training

**CBT Modules**
**Federal and State Inspectors**
**Supplement Classroom Training**
**Select Technical Topics**
**On-line Exams**

## Training

**Regional Classroom Training**
**Federal and State Inspectors**
**Protocols**
**Preparation for Inspection**
**Conducting Inspections**
**Exams**

## Inspection Format

**Risk-based Selection of Operators for Inspection**
**Based on Information Reported to OPS and Inspector Insights**
**Under Development – Will initiate when sufficient data and inspection experience is gained**

## Inspection Format

**Inspection Teams will be Multi-Regional**
**Comprised of Senior Inspectors**
**Number Assigned Dependant on Operator Size**
**One Lead Inspector**

## Inspection Format

**Operator Notification at least One Month Prior to Inspection**
**Inspections Estimated to be Two Weeks in Duration **

## Inspection Format

**Inspections Will be Extended if Necessary to Assure all Protocol Items are Covered**
**Small Teams May Be Utilized to Investigate Specific Issues**

## Inspection Format

**Inter-state Agents Will Participate in Federal Inspections**
**Inspections encompassing Interstate pipelines where OPS has delegated inspection authority to a state pipeline safety program**

## Inspection Format

**If Intra-state Pipelines are Included in an Inter-state Pipeline Operator Plan:**
**State Pipeline Safety Programs With Safety Authority will be Invited to Participate in the Federal Inspections**

## Inspection Format

**Pre-Inspection**
**Conducted by Lead Inspector**
**Scheduled a Few Weeks Prior to Actual Inspection**
**Face to Face or by Conference Call**

## Inspection Format

**Pre-Inspection**
**Coordinates Inspection Logistics**
**OPS will request advanced access to Integrity Management Program Process and Procedures (Intra-net Portal an Option)**

## Inspection Format

**Inspection Protocols Utilized to Determine Operator Compliance **
**Inspection Team Will Caucus After Each Protocol Section**
**Exit Interview Held at Completion of Each Week**

## Inspection Format

**Inspection Teams will Check Implementation Using Vertical Slice of a Process**
**Process and Implementation Audit **
**Review of Integrity Management **_**Processes**_** and **_**Implementation Documentation**_

## Inspection Format

**Inspection Documentation**
**Executive Summary**
**Detail Inspection Report**
**Protocol Development Form**
**Operator will be provided access to review for factual content**

## Inspection Format

**Periodic Re-set Meetings **
**Federal Inspectors**
**Communicate Inspection Findings and Issues**
**Inspection Process Check – Suggested Improvements**
**Coordinate Compliance Issues and Inspection Process Improvements**

## Enforcement

**Follow Standard Process**
**State Actions **
**Intrastate Pipelines**
**Federal Actions**
**Interstate Pipelines**
**Intrastate Pipeline without a State Authority **

## Enforcement

**Notice Letter**
**Provides Operator Response Options **
**Written Response or Hearing **
**Hearing is informal**

## Enforcement

**Possible Enforcement Actions**
**Warning Letter**
**Notice of Amendment**
**Notice of Probable Violation**
**Civil Penalty**
**Compliance Order**
**Depends on Individual Case Circumstances**

## Conclusion

**Thank you for participating**
**Feedback Forms**
**Can Provide Comments Via the Public Web Site under Questions and Comments**

## Conclusion

**Success of Integrity Management Depends on You!**
**It’s About Safety**
**Protection for Our Families, Friends, and Loved Ones**
**It’s Worth It!**