Michael: All right, good morning, everyone.
I have nine o'clock on the clock
I'm going through and looking at right now,
and it seems like we've had a decent amount of people
go through and join in.
So, welcome to the presentation
on the Railroad Commission, Pipeline Safety,
specialized pipeline inspections.
A couple of housekeeping items
before we go through and get to the presenters
to go through and talk about their topics.
First off, please do know that
this PowerPoint is ready for download.
If you go to the RRC website,
go through and follow the link right here,
that's on the slide.
It should also go through and be posted
in the Q&A section of the Zoom meeting.
So you should be able to find it there as well.
So you can go through and do as a simple copy and paste
and all of that.
So if you know that you can go through and get ahold of that
to go through and follow along with us
or just to go through and have it after the presentation
is over with.
So, to go through and kind of get us started
and get us gonna know what's going on
with all this right here,
whenever we go through and do specialized inspections,
one thing that the Railroad Commission
always likes to try to go and do,
is make sure that whenever we go through and call anyone,
if you, your company is a subsidiary of your company's,
anything along those lines,
we wanna make sure that we get everybody
that's underneath the umbrella of that specific plan
that we're going through and talking about.
That way we can go through and kind of
cut down on the number of inspections
and the number of times
we had to go through and meet with you
or others in your company.
So, let's say, for example, you go through and have,
four or five different companies
under your little umbrella that you have
for whatever reasons you go through and have them.
We wanna make sure that we get all four or five of those
done at one time,
that way we don't have to go through and see you
four or five different times
and be looking at the same thing over and over again,
that we've already seen.
So whenever an inspector from our group
goes through and calls you,
and asks, "Hey, I want to go through and do
a specialized operator qualification inspection,"
let them know right there on the phone when they call you,
"Hey, by the way,
I've got all these different companies right here as well.
Can we get them all done at one time?"
We wanna go through and do that
to make it easier for y'all and for us at the same time.
Another item is make sure that you go through
and know that whenever we go through and do one of these,
we're gonna be looking at both Texas Administrative Code,
which is the state code,
and 49 CFR or Code of Federal Regulations,
which is basically the federal or PHMSA code
at the same time when we're doing
an inspection on one of your programs.
So do be aware that we will be asking questions about both.
Also, we do have someone that is going through
and manning the questions
in the question and answers section of the presentation,
so feel free to ask your questions
throughout the presentation,
and we'll do the best that we can to get you an answer there
when you've asked it.
If there happens to be one that we cannot,
we will go through and do our best to get you an answer
as quickly as we can afterwards.
So, to get started, we're going to go through
and have Mr. Ross Richardson go first,
who's gonna be talking about new construction.
So Ross, whenever you're ready.
-: Thank you, Michael.
Hello everyone, good morning.
My name is Ross Richardson.
I am the new construction lead for the state of Texas,
Pipeline and Safety division.
When we're talking about construction,
new constructional pipelines,
what are we talking about?
Well, this can be new pipeline systems,
extension of an existing pipeline system,
relocation of an existing pipeline system
or a placement of a pipeline.
So why is new construction important?
New construction is our top priority
here in Pipeline Safety.
And the reason being is,
it all starts with the construction of a pipeline.
If you construct a pipeline safely,
you get out on the right foot.
So, it all starts with construction
and it is a top priority.
So, how does the Railroad Commission track new construction?
We utilize what is called a PS-48 form.
That form is filled out by the operator
and it basically states what the project is,
what it will involve, where it's located,
and that type of information.
PS-48 forms can be found here at this link,
which is on the RRC website.
So, what rules regulate
the reporting of a new pipeline project construction?
You have your federal codes,
that will be 49 CFR 191.22, for gas pipelines.
And then you have, 49 CFR 195.64,
and that would be for liquid pipelines.
And then you also have Texas Administrative Code 8.115,
which is a general for all regulated
jurisdictional pipelines within the state.
And then also for H2S pipelines,
you have Texas Administrative Code 3.36 and 3.106.
So when we come out and do
a typical new construction inspection,
what is involved?
Well, your first step is going to be your pre-inspection.
This is when, I, the inspector, or other inspectors,
reach out to the operator
and get an explanation of the scope of project
to help better schedule for that week of inspection
and/or weeks of inspection.
This will involve, like I said, the scheduling, the scope,
notify the operator what is expected during this inspection
and that type of information.
The second step, is gonna be procedures and records review
and the details of the project,
on-site and/or recently virtually, due to COVID,
the review of those records and procedures virtually as well
can be conducted.
And this covers, like I said, all the details,
procedures, records, all that information.
And then the third would be the field inspection.
This would be our, the inspector, myself,
will go out to the field
and conduct the visual field inspection portion
of the pipeline that's either being constructed
or has been completed,
you know, the construction is completed.
And then fourth, will be the closing and the findings.
And there will be a closing at each week of inspection
or each inspection closing
to notify you of alleged violations of findings,
that type of information.
So why do we conduct new construction inspections
with the Railroad Commission of Texas?
Number one, is public safety.
We conduct these to keep the public safe
and to also keep the environment safe and property safe.
And here's my contact information.
If you have any questions now or moving forward,
again, I am the new construction lead.
My cell phone number there, 512-436-5308,
give me a call anytime.
And then of course, my email address,
and that's ross.richardson@rrc.Texas.gov.
Thank you for your time.
Michael: All right. Thank you, Ross.
So next up we have Mr. Jose Cheverez
or as he likes to go through and be called, Chevy.
And he's gonna be talking about
operations and maintenance.
So Chevy, whenever you're ready to get started.
-: Good morning, everybody.
Like Michael said, I usually go by Chevy.
So if you'd call me, I'll answer Chevy,
pretty much the entire Railroad Commission knows me as Chevy
and a lot of operators.
So, everyone knows about that nickname.
So today we're gonna cover the inspection format,
how we do our O&M inspections,
the documents and records that we're gonna look at
as well as any common concerns that we have in Texas
for each pipeline system type.
Next slide.
So the inspection format is like Michael said earlier,
we're gonna start with the opening meeting,
we're gonna determine how many operator IDs
or company IDs are covered under that inspection,
to make sure we have the entire scope.
And how your O&M is broken apart,
and whether it's all encompassing or not,
and what sections there are.
Then we'll do the procedural review of all the procedures,
which we'll talk about more.
The documents or records, we'll talk about more.
And then we'll have that same closing meeting
where we'll cover all the goods, the bads,
the notes, the findings, and the alleged violations.
Next slide.
So the inspection forms we use for O&M's
can be provided by the inspector prior to the inspection.
We use three Railroad Commission forms,
we've adopted forms 8.1, 8.2, and 8.3,
specifically for each type, transmission, distribution,
and hazardous liquids, respectively.
And then for an LNG facility,
we still use the PHMSA form since Texas does not add any,
or at least Pipeline Safety
does not add any additional regulations for LNG.
Next slide.
So, once we start on that O&M,
we're gonna go through the entire O&M
from start to finish, page one to page 999.
We're gonna go through every single procedure
and look for the compliance with the federal code
and the minimum expectations.
That's going to include any local or regional
standard operating procedures that you have,
if they're specific to an area or to a specific pipeline.
So we'll need you to bring those along
if you're gonna do an inspection,
as well as the original
equipment manufacturer specifications.
These are part of the O&M
because the manufacturer has specific requirements
on how to maintain that equipment,
and you'll have to follow those
in order to stay in compliance.
The standalone programs that we do exclude
are basically the other inspections
that we're gonna cover today.
Like Ross before, new construction is a separate inspection.
And the other inspectors that'll follow me,
the leads that'll follow me,
those programs are standalone inspections.
And so, we won't cover those during the O&M.
We may have a little overlap
just because of the way the rule is covered,
but we're gonna try to stick to the O&M
as much as possible.
So this is a short list of the reports,
records, and details we're gonna look at during an O&M.
If you notice, this is a lot of the high level stuff,
that's gonna be applicable to the entire O&M
or to the company as a whole,
or to an entire pipeline system,
not just a single segment or region.
We're trying to cover what the company is doing
at the high level,
because once we know the procedures and policies
are accurate and effective at that level,
then we get into the standard comprehensive inspections
to make sure that that's being followed.
And of course, the inspector always has the right
to request additional documentation
based off what he asked for prior to the inspection
or anything he finds during the inspection.
So, common concerns we've had.
This data comes from the last two years
since we didn't have the presentation last year.
I've covered this from September 1st of fiscal year or 2019,
all the way to July 1st.
So for gas transmission companies,
we had some issues with the O&M updates
and the annual reporting.
So the annual reporting is either not there
or it's been late or it's inaccurate,
it doesn't match your T4 miles.
So your T4 regulated miles
and your annual report Texas miles should match,
because that's all of your regulated piping
for both Texas and for the feds.
And so those two numbers should match,
and if they don't within a certain tolerance
or you can't justify why those numbers don't match,
that's where we have the concern.
Same with the O&M updates,
we've had a lot of rule changes in 2020 and 2021.
And so, those rules need to get into the O&M
by the effective dates or else you're not in compliance.
For gas distribution,
record keeping has become a problem,
especially with the municipality
or with private distribution operators.
The rules are all there,
we look at the O&M to meet compliance,
but then you have to show compliance
with all of those regulations as well.
And so, the record keeping has to be sufficient,
it has to be dated and written correctly,
and it has to cover all the details
to prove compliance with the regulations.
We're not concerned with the clerical errors,
we're concerned with things being missing,
things being inaccurate,
because the information is inaccurate, not because of typos.
With municipalities,
the leak complaints have become an issue,
both in the procedures,
as well as the 10:00 AM reviews by supervisors
the next business day,
they're just generally not there,
either in the procedure or the record.
So we're really cracking down on that
to make sure it gets covered.
For liquid operators,
for the last two years, we're giving them a thumbs up.
We've had over 100 inspections of liquid operators,
and we have only had two violations repeated
on two separate occasions,
a P5 not being filed, either not being filed or delinquent,
and then the emergency plan training and review
was not either recorded or completed.
So, we understand that COVID-19,
and 2020 was a very difficult year,
but those records still need to be in compliance.
And they still need to be there,
and the training still needs to be held.
Other than that,
we had nearly over 70 of the 115 liquid inspections
that were done in those two years,
did not have any violations.
So, hazardous liquids, in general,
have done very good in the last two years.
And for O&Ms across the board, all of three types of O&M's,
it's a general lack of specificity.
The rules require you to stay in compliance.
And a lot of the rules are written in a manner
to allow the operator to make the decisions on their own.
When it's written that way,
you have to make those decisions and put them in writing.
So every procedure should have a who, what,
where, when, and how, for every single procedure,
every single thing that you're doing.
And some of those are given to you by the code,
the rest have to be decided by the operator.
So we need to see all of that
in every single procedure we look at.
Next slide.
So, we covered how we do the O&M inspections,
a short list of the documents and records
that we use and what we look at,
and the common concerns we've had
in the last couple of years.
If you download this presentation,
there are some helpful links
in the notes section of the slides
that you can use to help prepare for an inspection.
I've also included my contact information
if you need to call or email me for any O&M questions,
but that's all I've got for right now and today.
Thank you.
Michael: Thank you, Chevy,
Up next, we have Mr. Blaine Jacobs,
who's gonna be going through
and talking about drug and alcohol.
So, Blaine whenever you're ready sir.
-: Yes, my name is Blaine Jacobs.
I am the lead for the drug and alcohol
specialized inspections.
The agenda we'll be going over today
are the agencies involved
with the drug and alcohol programs, regulations,
the inspection process, common inspection issues,
and at the end, there'll be some informational websites.
The agencies involved with the drug and alcohol,
the main one is U.S Department of Transportation,
they oversee the movement of everything
in the United States as far as drug and alcohol.
Under that, will be the Office of Drug & Alcohol
Policy and Compliance.
Basically, that is the entity that is responsible
for publishing the rules and regulations,
and they are the ones who interpret
the rules and regulations.
And then under that, there are various agencies
that fall underneath that blanket,
Office of Pipeline Safety,
which is Pipeline Hazardous Material Safety Administration
is one of them.
You've also got Federal Motor Carrier,
you have the U.S Coast Guard, you have
Federal Aviation.
Different ones that are involved in transportation,
and each one is required to have
a drug and alcohol plan and procedures,
each one have their specific requirements.
So you need to make sure that your plan is designed
and meets the requirements for
Pipeline Hazardous Material Safety Administration.
The regulations that you're gonna be dealing with
is gonna be 49 CFR 199
and 49 CFR Part 40.
199 basically tells what DOT
and OPS require an operator to do
as far as our policies and procedures.
For now, CFR Part 40,
addresses the parties who conduct testing
and how the test will be conducted.
Inspection process.
The pre-inspection operator
will be notified by the inspector.
At that time, the operator can request a copy
of the inspection form that we use, protocol form,
so that you have an idea of what it is
we're gonna be looking for during the inspection.
The inspection itself will be a review of the plan
and supporting documents.
The inspection is designed
or geared towards your designated employee representative,
which is the person who manages your drug and alcohol plan.
It's usually somebody, depending on the size of the company,
is usually somebody in the HR department.
Then possibly, be a collection site visit,
depending on what's found in the initial part
of the inspection process.
Common issues that have been come across.
Operator did not have a plan that met all the requirements
of Parts 199 and Part 40.
Then again, they must contain all the elements
required by PHMSA.
Basically, you've got 199 and Part 40,
and both of those have to be,
has specific issues or since specific items
that need to be contained
within your drug and alcohol plans.
Another one is, no process to ensure contractors
or service providers were compliant with regulations.
As an operator, you've hired third-party contractors
or third-party service providers to perform functions
associated with your drug and alcohol plan.
And you, as the operator, responsible for ensuring
that those individuals are performing those tasks
according to regulation.
I99.115, the operator is responsible for
contract compliance with regulations.
And 40.11 and 40.15, is said that it is,
where the operator's responsible
for Service Agent compliance with regulations.
Collection site monitoring.
We run a across a lot of operators
who have no documentation showing that they are
making sure that the collection sites are in compliance.
That's under 199.115 and 199.245,
based on whether it's the drug side of it
or the alcohol misuse prevention portion of the plan.
Well, here's some informational websites that you can go to
that have what...
As specific information that as an employer
or operator, you need to know,
and answers any questions you might have as far as
what needs to be in your plan,
they also offer a pamphlet that PHMSA put out last year,
they go step by step on how to inspect a collection site.
Again, there's my contact information.
If you have any questions,
don't hesitate to reach out and get in touch with me.
Thank you for your time.
Michael: All right. Thank you, Blaine.
Next up, we have public awareness and damage prevention,
it's gonna be talked about by Mr. Pete Longoria.
So whenever you're ready, sir.
-: Okay.
Good morning, my name is Pete Longoria,
and I'm the team lead
for public awareness and damage prevention.
So a quick overview of everything
that I'm gonna cover today.
So we're gonna start with
the importance of public awareness,
then we're gonna move on to the regulations
that govern public awareness,
the public awareness and inspection process,
some quick information on damage prevention,
damage prevention regulations,
the inspection process for damage prevention,
common issues found during public awareness
and damage prevention inspections,
and then of course, my contact information.
So, why is public awareness important?
Well, we raise the awareness of presence of pipelines
to the intended stakeholder audiences.
And so, really the goal is to increase public understanding
on the role of pipelines.
So helping them understand that pipelines are the most,
the safest and most reliable way
to transport natural gas, crude, and refined product.
And in turn, this also helps you as an operator,
is promoting the safe operation of pipeline.
So in the case of the public awareness,
kind of getting ahead into damage prevention,
but 811 is a big thing that we stress,
calling before you dig.
Letting the public know that there's a pipeline in the area,
that can decrease your third-party strikes.
And also, the information that you provide
to the stakeholders has key information
on how to identify potential leaks or hazards
associated with pipeline releases,
they could potentially have them
notifying you before you have a bigger event.
So, under federal regulation,
each operator must establish a public awareness program.
So there is a gas and the liquid requirement,
so that is 49 CFR 192.616, for the gas,
and 195.440 for liquid.
In addition, API RP 1162 is incorporated by reference.
This is where you as an operator find resources as far as
how to identify your stakeholder audiences,
how frequently you should be corresponding
with these stakeholder audiences,
and also, methods to evaluate your program
and see whether or not the program is effective.
Keeping in mind... Oops, sorry.
So just real quick on the previous one,
keep in mind that there are two additional,
there are additional regulations
in Texas Administrative Code
for conducting liaison activities once per calendar year,
not to exceed 15 months, and these are, TAC 8.235
and TAC 8.310.
So the inspection process for public awareness is,
as everybody else mentioned,
we wanna make sure that we're capturing
any and all subsidiaries under that are covered by the plan.
So, after we go ahead and verify that,
we're gonna verify the miles of regulated pipeline.
So, we're gonna break it down
by gas gathering, gas transmission,
liquid gathering, and liquid pipelines,
and the miles associated with each.
And after that, the main records portion is,
identification of your stakeholder audiences,
are you making the appropriate time,
correspondents at the appropriate times
to your stakeholder audiences?
And then the biggest one is your annual reviews
and your effectiveness evaluations
to determine where it is that your program is.
So, coming into damage prevention.
So the leading cause of pipeline incidents
is third-party damage.
So the goal of damage prevention
is to prevent damage to pipeline and its facilities.
So again, as I mentioned before,
public awareness damage prevention go hand in hand.
You reach out to the public,
you make them aware of the pipelines in the area,
and we can help bring these numbers down.
And so, just quick definition,
excavation includes digging, trenching, blasting,
and anything similar.
So just like with public awareness,
an operator must carry out a damage prevention program.
So here you have 192.614 for gas,
195.442 for liquid, And in addition to that,
there is Texas Administrative Code Chapter 18,
which has requirements for both excavators and operators.
So just as with public awareness,
we'll do a breakdown of mileage by commodity.
And then in addition to that,
the difference here is we're gonna look at,
are you identifying your excavators?
And we're gonna verify your one-call tickets.
So, regulation requires you to keep them for five years.
And in addition, we'll compare your numbers
reported to PHMSA for third-party damage
and your Texas damage reporting form submissions.
So the most common issue, it's mainly with public awareness,
and it's incomplete effectiveness evaluation.
So the big three are either the effectiveness evaluations
are exceeding the four-year mark,
stakeholders aren't understanding
the material being provided,
and also, some operators are gathering the information,
but they're not able to come up with a conclusion
as to whether or not their program is effective.
So those are the big three issues that we see.
And so, here's my contact information.
If you have any questions, feel free to reach out to me.
Thank you.
Michael: All right. Thank you, Pete.
Up next, we have control room management
and Mr. Mark Herrin is gonna go through
and talk on that subject.
And, whenever you're ready, sir.
-: Right, good morning everybody.
I'm the current control room management active lead,
and here to talk about control room.
So I pulled the definitions from the code.
Control room, do you have a place and location
for your controllers or personnel
that's gonna be watching the SCADA system below?
But you need a kind of computer based system
that you get the information from your pipeline,
pressures, anything of that nature into the control room.
Go on the next slide, please.
And then we have the controller,
and they could define here by somebody that
remotely monitors and controls the safety related operations
of a pipeline facility with a SCADA system.
So from this, we can see that,
you know, control room is,
you got a system, you see the information,
and they can control it one way or the other.
Next slide.
And the FAQ A.07, which I have the link to the FAQ's
at the end of this slide.
This has a definition of,
it helps you identify a controller.
It's anybody that,
whether you interact with the SCADA system
to manipulate a valve
or you call anybody else that can manipulate that valve
or take care of an issue
you see on a system or monitor.
Those are controllers.
Next slide.
So, we'll talk about what to expect
during the CRM inspection.
So, generally we're going to determine
what of your facilities are control rooms specifically.
So, everything we're gonna talk about,
we're gonna look at the process you use,
procedures and documentation
for everything throughout the process.
Next slide.
What is your effective data and control room plan
and when was it implemented?
The original date, original time
when the control room was either active
or the control room plan went into effect.
Then we'll go into roles and responsibilities.
What's the Controller Authority?
Does he have authority
to do everything he needs in his powers?
Does that cover abnormal operations
and emergency operations?
What is his physical domain?
Is it the one console that covers everything?
Does that console only cover certain pipeline facilities?
We'll talk about shift change.
What are your procedures for that?
How do you document it?
We'll go through all of that good stuff.
Next slide.
All right, so do you give anyone to supersede
or direct your controllers?
So it's very important that you need to say,
if they don't, nobody else can tell them what to do,
need to put in your plan
that it's either allowed or not allowed.
How are they qualified
if they are allowed to supersede them?
And has there been any record events that's happened?
Next.
In your plan, you need to define what additions, expansions,
or replacements are within your facilities.
What are your procedures going to be for that?
FAQ's C.15 and C.19 are good for that.
All right, then next we're gonna look at
your implementation of 1165.
Procedures, documentation,
talking about how your screens look,
how all that stuff was implemented.
Did you have a checklist?
Or we just gonna look at it.
Next slide.
All right, safety related points.
What is your process of going through those
and making sure that everything that's safety related
is in the SCADA system?
What's the records of that?
Do you have a master list?
I have the point to point verification,
going out there saying,
all right, this communicates, it's working,
they have accurate information.
Next slide.
What is your internal communication plan?
Do you call everybody?
What's your procedures and process?
Do we call everybody, get their names?
Make sure that the phone numbers are still good
in an emergency.
Do you have a backup SCADA system?
So we need to find out if you have one,
we'll take a look at it,
if not, it's something we don't have to look at at all.
So, the process of how you go out to it, check it,
logistics of how to getting out there,
what's your timeline and then the records of all that?
Next slide.
Fatigue management.
Something that has been missed lately is,
operator specific fatigue risks,
it could be anything
specific to your control room specifically,
such as Downtown Houston traffic could cause an issue,
you might've changed your start times
for you controllers specifically.
We'll talk about,
did your controllers have any accidents or incidents
and did fatigue play a role in that?
How did you investigate that?
If you did investigate that and found nothing,
did you document it?
If there was something that happened,
how did you document that?
Then you're gonna talk about, the shift lengths.
How did you determine that?
Is there, did you do a study?
Did you use a pre-approved?
Then we're gonna do fatigue training.
What did you use? Presentations,
how do you continue that training as well?
Next slide.
Go into the alarm management.
So what is the philosophy that you use
for your alarm management, rationalization?
And then we're going to your safety related points
that we looked at earlier.
What are those set points?
We'll go through and see what you got.
Then you'll need to do your annual review
of your alarm management plan,
one year not to exceed 15 months.
So, you can't have that 15 months and skip a year,
you have to do it every year.
Next slide.
Monthly analysis.
What you took off scan,
did you inhibit any alarms, false alarms?
Did you have any forced values?
If so, how are you monitoring that?
Are you making any corrections?
Is there a timeline to get things fixed?
And then, the timeline we're talking about promptly,
that you define promptly fixing it as a week, a year,
you might be a little long for a SCADA system point.
So, next slide.
Measuring your workload.
How do you know workload studies,
making sure that they're not overburdened
or they can't get their work done
and in case something happens?
So, we'll look at the workload study you're doing,
how did you measure the metrics,
if the metrics make sense,
and how many records do you have?
Look at your alarm deficiency resolution.
FAQ E.16 is very good for this
to give you an idea of what to do
if you don't already have an idea.
Next slide.
Change management.
So, you're changing a valve out in the field
to another location and that valve no longer exists.
Did you inform the control room
or have anybody from the control room participate
in how that might affect the pipeline?
So that's one of the change managements that we'll look at.
Next slide, please.
Lessons learned.
So, did your company have any incidents or accidents
or any, you know, near misses that
you could take to the control room or anywhere
and apply that as a lessons learned.
If something outside the company happened
that could potentially help your company.
So, you would recommend
adding any of that stuff you can find.
Next slide.
We're going to training.
So, what are the qualifications to become a controller?
And when do you determine them to be qualified?
Because you can complete CBT's relatively quickly
if you're using CBT's on the job training.
You probably wouldn't have somebody
two weeks into their training
to start working on a controller.
So when do you determine them to be qualified
to run as a controller.
And then you'll wanna review
your current training program every year.
Next slide.
This one is relatively new, the control room team training.
You need to identify
who works with the control room personnel.
So that's gonna be people in the field,
that's gonna people who do anything out there,
schedulers,
do they talk to any other company controllers?
You just need to talk to anybody within your company
that you can get on that.
And then what are your procedures
for identifying those people?
How do you get their training done?
If you have new hires into the field,
when do you establish they need to have this training done?
We'll look at the documentation that you have.
And then, FAQ's PHMSA put out,
H.05 through H.09 is very helpful
and I recommend going through those for this program.
Next slide please.
And here's the link to the FAQ's as I was talking about,
this will bring you, I checked it today again,
and this is still a good link.
Recommend going through this,
it's a little lengthy,
but it's got great information for control rooms
and control room operators.
Next slide.
And this is my contact information.
Again, I'm the current control room lead.
If you have any questions
and you need some help or guidance,
please contact me and we'll work through whatever you got.
Thank you very much.
Michael: All right. Thank you, Mark.
Up next, for operator qualification,
we have Mr. Derek Lawrence.
So whenever you're ready, sir.
-: Thank you, Michael.
My name is Derek Lawrence,
I am the OQ lead for the state of Texas.
Today we'll be covering what to expect on an OQ inspection
and as well as some of the code references for that.
We starting with covered tasks and the definitions of that,
OQ evaluations,
then we'll go over record maintenance,
program review,
and then commonly cited violations.
The covered task is,
is a part of any task, that is, meets the four-part task,
which is a requirement of state or federal code,
an operation or maintenance task, and is...
My apologies.
Is performing a pipeline facility
and is detrimental to the safety
of the pipeline system itself.
Just so you know, the Texas Administrative Code
is applicable to the rule for the four-part task.
One thing we've been seeing in the field
is generic covered tasks,
where we'll go through an operator's OQ plan,
and we're noticing that,
they all have a list of covered tasks
that are applicable to the rule,
but they're not using it all.
So, one thing that might be helpful to you guys
to know which tasks do you need is to go through,
and when you're doing your review of your program,
make sure that the tasks that are in your program
are applicable to your pipeline that you're using.
For example, if you have gas
and you don't do any liquid pipelines,
you probably don't need,
you know, starting up a pump as a covered task,
because that would be related to liquid lines.
We're gonna start with
what we're gonna look for in an OQ evaluation.
This will come from the definitions page right now,
and that's 192.803 and 192.503.
Is for you to get our definition for AOC,
which is an operators are asked to ensure that AOC,
which is that abnormal operating conditions,
are noted on their evaluations
along with the appropriate responses
to ensure that the responses are correct,
basically, you need to make sure that
someone who is qualified can perform the covered tasks
and recognize and react to an AOC.
The evaluation methods listed in code are several,
and you can use written evaluation,
oral evaluation, Work Performance History Review,
observation during performance on the job,
on-the-job training or simulations
or another form of assessment.
192.805 and 195.505,
this is where you get the bulk of your OQ program from.
You need to identify covered tasks,
ensure through evaluation that individuals are qualified
to perform covered tasks,
that you have procedures for directing and observing
non-qualified individuals under a span of control.
This is only if you allow non-qualified individuals
to perform covered tasks on your pipeline facility.
If you're requiring only covered individuals
to perform covered tasking,
I wouldn't say you need to worry about direct and observe,
but it's always helpful to have that procedure in there
in case you have a new trainee coming on
who would do the tasks, you need to make sure that you have
your span of control setup
which is the number of how many individuals
a person who is qualified can observe performing said tasks.
You need to be able to evaluate an individual's performance
contributed to an incident.
One thing we're seeing is that some operators are using
suspension and disqualification interchangeably.
We would highly recommend that you
figure out what those terms are for your plan
and use them where they belong,
such as, do you suspend someone
when there's an accident occurred
and they were performing covered task
until you have time to do the investigation
to determine whether or not
they contributed or caused that incident?
Disqualification would be after you've determined,
yes, they've been, you know, they contributed to that.
Then you would be able to go back and say,
you need to go back through your training.
You need to be able to evaluate if
individuals are no longer qualified
to perform covered tasks.
This could be from observing them perform the covered task,
maybe they've had a long absence from that covered task,
whether that's through sickness, injury,
just it's not something that they've done
in a couple of years,
maybe they need to be re-evaluated.
So you would wanna have procedures in place
to look into that.
You need to be able to communicate changes
to your individuals,
is that through meetings, emails, telephone calls,
updates to your, you know,
publishing updates of your manual to all of your employees.
Ensuring that individuals have the necessary
knowledge and skills.
So, when they're qualified,
it's important that they don't just have
a theoretical knowledge,
they have the ability to actually do the tasks.
We've seen cases where some operators,
they don't have a way
that either they weren't doing any CBT's or test,
there was no way for them to indicate
whether that an individual had the knowledge
or skill sometimes to perform a covered tasked.
And you need to have procedures
to update PHMSA and the Railroad Commission
of significant changes to your program.
Important to note that during evaluations,
we are gonna be looking to make sure that you,
you as an operator are not using observation
of on-the-job performance as a sole method of evaluation.
And same with Work Performance History Review,
neither of these can be used as a sole method.
And this was back in 2002
for Work Performance History Review
and on-the-job performance in 2004.
So by now, these should not be used as sole methods,
you can combine them with others,
whether that's a written test, oral tests or the like.
Records, records are covered by 192.807 and 195.507.
These records need to be for your employees
and for your contractors.
Please have a method of obtaining contract records
before we get to the inspection, having them available.
You need to make sure for both employees
and contractors that are qualified,
that you have an identification
of who the individual is in the record,
the identification of the covered tasks
that the individual can perform,
the dates of the current qualifications
and the method used to qualify the individual.
We are seeing cases where some of this information
is being left out.
It's important that for the records to be complete,
that you have those four things.
Ensure that for both employees and contractors,
that you are keeping records for five years
after the last time that task,
last time that person was qualified for the task,
whether that be they've gotten re-qualified on a task.
So you will need to hold the old record for five years,
or maybe they've retired
or have left the company for some other reason,
or just maybe they were promoted to a task
that no longer requires them to perform covered tasks.
You need to keep those records for five years
from the date they're no longer performing those tasks.
For the program review,
you can send them to safety@rrc.Texas.gov.
This is anytime you make a significant change,
or if you just wanna send it in,
when you develop a new plan.
I know sometimes we have operators
who develop new plans periodically,
they just decide, you know what?
we're gonna scrap this and just start over.
Send that in to safety@rrc.Texas.gov
so that we can review it.
And this will not count as an inspection,
but is something that we do require that operators do.
Also, please note that OQ and O&M manuals go hand in hand.
So it is very important to make sure that your tasks
that you have for in your O&M manual,
cause they're operation and maintenance tasks
which is part of the four-part task,
that you have OQs for those tasks.
Commonly cited violations that we're seeing,
wanna make you guys aware of,
you have a chance to look through your program,
determine if you have some of these issues and fix them,
is that operators are failing to notify
the Commission of significant changes.
So, a significant change is determined by you, the operator,
it should be written in your procedures.
When you meet that significant change
based on something you've done to your manual,
you need to go ahead and send it into the Commission
and let us know.
It is helpful if you tell us,
maybe with the manual, when you send it in,
what it is that the significant changes are,
and it really helps us in reviewing your manual.
We're also seeing that the operators are using
Work Performance History Review
as a sole method of evaluation.
Just remember that that is no longer allowed,
but it can be used in conjunction with another task.
We're seeing that the operators
are not following procedures as outlined in their OQ plan,
meaning either as something like they're not,
they may have an annual review written into their plan
and they're not doing it.
So if you have something when written in your plan,
we follow it.
But also, your individuals that are qualified,
make sure that they are able to do the task steps
as outlined per your OQ plan.
Excuse me.
We're also seeing operators not have procedures
and/or records for contractors performing covered tasks.
The operator is ultimately responsible
for all work done by a contractor
and is responsible for having their OQ records
and procedures to allow those individuals to work,
whether that is how you're going to
bring them into your plan,
are you gonna train them on your plan?
Do they have their own plan? Have you reviewed that plan?
These kinds of things need to be considered
in your procedures when developing contract for personnel.
In summary, we've covered today, covered tasks,
OQ evaluations, record maintenance, and program review.
Just remember that the covered task
is something that meets the four-part tasks.
That operators should develop a tasks list
for their company and for the tasks that they are performing
with the span of control.
And the years of the evaluation is good
for whether that's one, two, three, four, five,
and it should be able to justify
what the reasoning for those evaluation intervals
based on difficulty
or how often is performed and other items.
I thank you so much for your time.
My contact information is provided on the screen.
Again, my name is Derek Lawrence,
I am the OQ lead for the state of Texas.
My number is 512-971-3067,
and you can reach at derek.lawrence@rrc.Texas.gov.
Thank you.
Michael: Thank you, Derek.
Up next, for talking about
both gas and liquid integrity managements,
we have Miss Jennifer Delacruz.
-: Good morning, everyone.
My name is Jennifer Delacruz.
I'm the lead for liquid integrity,
and Evon Boothe is actually the lead for gas.
So just starting with the applicability for gas,
this is gonna be any gas transmission pipeline
that could affect an HCA.
And for liquids, it's each hazardous liquid
and carbon dioxide pipeline that could affect an HCA.
And then, for the state regulations,
this is gonna cover basically all other
intrastate transmission pipelines not affecting HCAs,
and this includes gas and liquids.
Okay, so some common issues that we see in integrity,
the main one's gonna be documentation or integrity.
All decisions need to be,
really everything you do related to integrity
needs to be documented,
and this will include decisions to not take an action.
So just as an example,
you conduct an EFRD analysis,
and you conclude that you don't need
to install any additional ones.
That's totally fine, just document that,
and the justification behind it.
An HCA determination needs to be done by all operators.
So even if you don't have any HCA,
so you still need to complete this part
of the integrity requirement,
and document that as well.
Please keep in mind that when you're responding
to any alleged violations,
keep them very concise and specific
to what the violation was in reference to,
and that way we can tell how you're correcting it.
Okay, so to touch a little bit on
Texas integrity management rules
and some of the terms used.
They don't always line up with the federal regulations,
so just risk-based and prescriptive.
For Texas rules, you have to select whether you're gonna be
risk-based or prescriptive per segment,
that can change so you can have
some risk-based, some prescriptive.
When we're talking about risk-based,
we mean based on a risk model.
And then for prescriptive, it's a set interval
based on figures 1 and 2 and TAC 8.101B2,
and that's gonna be based on diameters, class,
products and some other parameters as well.
Please keep in mind direct assessment
is only allowed for risk-based programs.
So if you choose to be prescriptive,
you cannot use ECDA as an integrity assessment method.
Okay, so for the federal rules,
again, this is only for could affect HCAs.
And then again, with the terms here for gas,
a prescriptive is really a simple risk plan.
And then you've got performance,
which is a robust risk plan based on 21 thread categories.
And just FYI,
I've never seen an operator use the performance method.
For liquid, it's gonna be a risk model.
And again, if it's an non-HCA pipeline,
you'll follow Texas rules.
Okay, so for gathering under the gas rule,
they are exempt from integrity,
but do expect an inspection.
Just that we might conduct one
just to verify that the determination was made properly
and the documentation of how you came to that conclusion.
And then for liquids, really the only exemption
is for Category 3 low stress pipeline in a rural area.
There was a new liquid rule
that became effective July 1st, 2020,
and this is for assessments
for certain underwater facilities in HCAs.
There's a whole paragraph there in 454
that describes the whole applicability there,
but really, it's facilities that are greater than 150 feet,
under the surface of the water,
and you'll need to do an ILI every 12 months,
and any other pipeline integrity assessment
completed on a schedule based on risks.
So you would have to do both of these.
And here's mine and Evon's contact information,
please feel free to reach out with any questions.
Thank you.
Michael: All right. Thank you, Jennifer.
Up next, for distribution integrity management,
since we consider those to be separate,
Mr. Isaac Monrreal.
-: Thank you, Michael.
My name is Isaac Monrreal,
I'm the lead for the distribution integrity management,
what we most affectionately call DIMP.
Just kind of briefly go through a lot of this,
we do have a new DIMP form
that we are updating periodically.
So, whenever you get a phone call to,
for an inspector to come out and conduct an inspection,
please ask them for the new DIMP forms.
That is a combination of both state and federal codes,
including the TAC 8.209.
So when you do get that phone call,
please be aware that please come prepared
for all additional records and operating personnel,
and most specifically, other manuals that you may have.
Sometimes what we see is that you'll have your procedures
in other manuals,
such as your operation and maintenance manual
for your leak complaints, leak management programs.
So, just please come prepared with that,
it kind of goes a long way
for whenever we're conducting an inspection.
One thing that I always like to highlight
and talking about baseline
and the difference between
transmission and distribution integrity management.
Specifically for distribution,
we're really talking about baseline for performance measures
and that's generalistically,
basically, a year or a series of years
that then an operator establishes
for each mandatory performance measure
under 192.1007 Part E.
And then for those of y'all
who are using the SHRIMP program,
which is a Simple Handy Risk-based
Integrity Management Program that PHMSA gave a grant for.
The SHRIMP program does not do the baseline for you,
it gives you a little bit of guidance,
but it's that extra step that you have to do
in order to meet compliance with the code.
So, some of the common issues that we've been running into
is again, kind of we're talking about for baseline
is that you're not doing all of the five mandatory,
the performance measures, that you're not documenting them,
or you're not establishing them.
Some other issues that we've run into quite frequently
is for your periodic reviews,
that they're either not done within the timeframe,
under the slot which is five years.
Or you're just not documenting that,
what specifically did you actually review?
And then in general, just a general lack of documentation.
That's kind of like, kind of been like a recurring issue
that we've kind of seen over and over and over again,
not just with your DIMP program,
but also as it applies to state code for the 8.209.
So I just kinda want to emphasize just a little bit,
you can go to the next slide please.
And please, please, please document as much as you can,
the DIMP program was intended to be a live document.
We want you to be documenting legitimately
every step, every action, every year.
So then, also when we come and do an inspection,
it just goes a lot smoother.
So the last thing that I'll just want to put up on the slide
is my contact information.
If you have any questions, comments, or social observations,
DIMP or GIMP related, feel free to reach out
and I'll be more than happy to help out.
Thank you for your time.
Michael: All right. Thank you, Isaac.
-: All right.
Michael: Up next, for incidents and accidents,
we have Mr. Godspower Oniovosa.
So whenever you're ready, sir.
-: Thank you, Michael.
My name is Godspower Oniovosa,
I'm the Accident/Incident investigation lead
for the state of Texas.
As we all know, accident and incident brings safety,
kind of a shield into our body when we have them.
But with the operations with your pipeline operators,
there are safety requirements
that whenever operator has accident or an incident
on their pipelines,
they must report to the Railroad Commission
or the federal Commission.
And there are safety requirements that are required,
whenever there's an accident or incident
happens on the pipelines.
So for federal regulation that when an event
involves the release of a gas on a pipeline
or from a another gas facility
of petroleum gas or refrigerant gas,
pipeline operators are required to report
under the federal regulation of 191.3,
if that results into an event of a death or personal injury
or installation on an estimated property damage of $122,000.
Or if it involves only tensional release of the gas
that is above of 3 million cubic or more,
operators are required to report.
And also likewise, if this event involves
liquid or carbon dioxide or hazardous liquid
from any of the pipelines, also (indistinct) storage,
or involves the release of liquids,
under the federal regulation of 195.5 and 195.52,
pipeline operators must also report that accident
to the federal, PHMSA, or to the Texas Railroad Commission.
And if the events that involves the release of a liquid,
if it involves the release of five gallons or,
less the five barrels
or involves death of a person or personal injury
necessitating hospitalization,
are also estimated property damage,
involving cost of clean up
and recovery of value of the product
that is up to exceeding $50,000,
they're also required to report that incident.
Also on gathering lines, gas and liquid,
this is to be regulated by
the Texas Administrative Code (indistinct)
under the regulated gathering lines.
Whenever those releases are, you know,
released from the gathering lines, either gas or liquid,
the safety requirements by Texas Administrative Code 8.11,
you're required to report those incidents.
I wanna make some changes,
there are some little changes that came up recently.
On March 12th, I think this year, 2021,
there was a change on one of the consequences
under the regulation 191.3.
Actually before, it was when the estimated property damage
was like exceeding $50,000,
but now, there are this changes, start operating in March,
that whenever it exceeds,
estimated property damage is $122,000.
And this was as a result of adjustments before inflation,
which was made to determine,
and that determination is made in appendix A in Part 191.
And I also want to also remind us,
for liquid, there was no changes.
The estimated property damage is still exceeding $50,000,
but the difference is that it is inclusive of your products.
Then also, another reminder is that,
operators have to have in their O&M,
accident and incident investigation procedure.
This is for you to analyze the accident
and also to determine the cause
and to mitigate and minimize
the possibility of the recurrence.
And this are requirement per the federal code
of 192.617 and for gas,
and 195.402 A5-6 for liquid.
And for Class 1 and rural gathering
which I had mentioned earlier,
that this is being regulated
by Texas Administrative Code of 8.11.
The reporting criteria we can find is about,
for gas is 8.210A,
and for liquid is 8.301A,
which is stuff that you can find out
on the release or whenever there's a release
from Class 1 or rural gathering
and the consequences that you must, as operator,
must report to the Railroad Commission.
And also about 8.110E,
you're also required to perform an investigation requirement
to analyze the accident to determine the cost
and also to provide corrective action.
So one of the (indistinct) expectations
of the Railroad Commission is,
one, whenever there's a release,
whenever there's a reportable incident or accident,
you are required by a procedure
to analyze the accident and incidents
to the time and the cost.
And not just only the time and the cost,
and also the plan to minimize reoccurence.
These are also be determined
that whenever with inspectors coming,
when they're performing the accident investigation,
you should be able to show documentation that this process,
or these procedures are followed.
And also, you also required to submit
the 30-day report with applicable forms
to the safety at Railroad Commission of Texas, .Texas.gov.
I think if you will,
for now if you have any information,
as I told you, I'm the incident lead,
and as (indistinct) all my contact information
is (indistinct), Godspower Oniovosa,
and my email and my phone contact.
You can feel free to reach me, thank you.
Michael: All right. Thank you Godspower.
And that was all of our presenters that we had.
Here on this slide,
we go through and have the Commissioners listed out
and a physical mail address,
you can go through and reach out to them at,
or any inquiries to anyone else in the Railroad Commission
that you go through and have.
We do want to go through and remind y'all
that there is an evaluation
that y'all can go through and take and complete
at the following website.
Again, if you download the copy of this presentation,
you will have that link and be able to access it,
go through and fill it out if you so choose to.
And again, somewhere to the beginning,
we're gonna be going through an archive in this video,
and you can find it at the link that was provided,
first, at the beginning of the presentation,
and second, should be a link somewhere in the Q&A section
to go through and list that out.
So, thank you very much for going through and attending
and I hope you have a wonderful rest of your day.