This week’s Pipeliners Podcast episode features Jim McKinney and Keith Coyle discussing the release of the second edition of API RP 80 and how the new changes came to fruition. 

In this episode, you will learn about API RP 80, what was revised in the new second edition, and why these changes took place. McKinney and Coyle also discuss the functionality test for pipelines, stating that a pipeline’s function determines the type of line it is, which leads to a conversation about what exactly gathering lines are.

Onshore Gathering Lines: Show Notes, Links, and Insider Terms

• Jim McKinney is the Chief Operating Officer & Executive Vice President of EnerVest Operating Company. He has extensive experience in Operations, Marketing, Midstream, Land, and Finance in various geographic areas including the Appalachia Conventional Basin, Utica Shale, Marcellus Shale, Gulf Coast, Arkoma, Fayetteville Shale, Granite Wash, Bakken Shale, Barnett Shale, Uinta, and Permian basins.
  • EnerVest Operating Company is a top-tier, low-cost oil and natural gas company. They own, lease, and operate North American assets for the Company and their partners.
• Keith Coyle is a Shareholder and attorney with the law firm of Babst Calland. Mr. Coyle is a member of the firm’s Washington, D.C. office and a Shareholder in the Pipeline and HazMat Safety practice. Connect with Keith Coyle on LinkedIn.
  • Babst Calland’s Energy and Natural Resources attorneys work collaboratively across legal disciplines to serve the needs of energy companies across the United States. Based in Washington, D.C., the Firm’s Pipeline and Hazardous Materials Safety practice represents clients on all types of pipeline safety and hazardous materials transportation matters.
• API (American Petroleum Institute) represents all segments of America’s oil and natural gas industry. Its nearly 600 members produce, process, and distribute most of the nation’s energy. The industry supports millions of U.S. jobs and is backed by a growing grassroots movement of millions of Americans. API was formed in 1919 as a standards-setting organization. In its first 100 years, API has developed more than 700 standards to enhance operational and environmental safety, efficiency, and sustainability.
• RP 80 – The American Petroleum Institute (API) announced it has published the second edition of recommended practice (RP) 80, Definition of Onshore Gas Gathering Lines. This RP is expected to be incorporated by reference into Part 192 when the Safety of Gas Gathering Pipelines rule is finalized by PHMSA. The second edition restructures the outline of the RP, including providing sections for definitions, outlining gas gathering and production operation functions, as well as providing examples of how those definitions and functions are applied. In general, the second edition provides a much clearer definition of what an onshore gas gathering line is compared to the first edition of RP 80.
• Pipeline Safety Act of 1968 was the first statute that required the Department of Transportation (DOT) to develop and enforce minimum safety regulations for the transportation of gasses by pipeline. 
• PHMSA (Pipeline And Hazardous Materials Safety Administration) protects people and the environment by advancing the safe transportation of energy and other hazardous materials that are essential to our daily lives. To do this, the agency establishes national policy, sets and enforces standards, educates, and conducts research to prevent incidents. They prepare the public and first responders to reduce consequences if an incident does occur.
  • NPRM (Notice of Proposed Rulemaking) in 2016 PHMSA proposed to revise the Pipeline Safety Regulations applicable to the safety of onshore gas transmission and gathering pipelines. PHMSA proposed changes to the integrity management (IM) requirements and proposed changes to address issues related to non-IM requirements. This NPRM also proposed modifying the regulation of onshore gas gathering lines.
• Mega Rule – The rule, initiated over 10 years ago, expands the definition of a “regulated” gas gathering pipeline that is more than 50 years old. It will—for the first time—apply federal pipeline safety regulations to tens of thousands of miles of unregulated gas gathering pipelines.
• GPAC (Gas Pipeline Safety Advisory) is a statutorily mandated advisory committee that provides PHMSA and the Secretary of Transportation with recommendations on proposed standards for the transportation of natural gas or hazardous liquids by pipeline. GPAC consists of 15 members, with membership evenly divided among federal and state governments, regulated industry, and the general public.
• Incidental Gathering Line – Last segment of a pipeline in a gathering system, taking the gas from a compressor station or a treatment facility or a point of commingling.
• Gathering Pipeline – Pipelines that are used to transport crude oil or natural gas from the production site (wellhead) to a central collection point. They generally operate at relatively low pressures and flow, and are smaller in diameter than transmission lines.
• Horizontal Well – An alternative method for drilling for oil and natural gas when vertical wells do not yield enough fuel or are not possible, such as shale wells.

Onshore Gathering Lines: Full Episode Transcript

Russel Treat:  Welcome to the Pipeliners Podcast, episode 230, sponsored by the American Petroleum Institute: driving safety, environmental protection, and sustainability across the natural gas and oil industry through world-class standards and safety programs. Since its formation as a standard-setting organization in 1919, API has developed more than 700 standards to enhance industry operations worldwide. Find out more about API at api.org.

[background music]

Announcer:  The Pipeliners Podcast, where professionals, Bubba geeks, and industry insiders share their knowledge and experience about technology, projects, and pipeline operations. Now your host, Russel Treat.

Russel:  Thanks for listening to the Pipeliners Podcast. I appreciate you taking the time. To show that appreciation, we’re giving away a customized YETI tumbler to one listener every episode. This week our winner is Kayson Lober with Flint Hills Resources. Congratulations Kayson, your YETI is on its way. To learn how you can win this signature prize, stick around till the end of the episode.

This week, Jim McKinney, Executive Vice President and COO at EnerVest, and Keith Coyle with Babst Calland are joining the podcast to talk about Recommended Practice 80, and the definition of onshore gathering.

Jim, Keith, welcome to the Pipeliners Podcast.

Keith Coyle:  Thanks for having me on again, Russell. I always enjoy doing the show with you.

Jim McKinney:  Thank you, Russel.

Russel:  Jim, if I could ask you if you don’t mind, maybe you could go first and give us a little introduction, and tell us a little bit about your background, and how you got involved with RP 80.

Jim:  Absolutely, Russel. Again, thank you for having us on today. My name is Jim McKinney. I’m the Chief Operating Officer for EnerVest Operating. We are a producer of oil and natural gas onshore, United States.

I’ve been in the industry 30-plus years. I’ve worked for major public companies, and now, as I said, a private equity-backed company. I’ve been involved in industry associations for 25 of those 30-plus years, associations like the American Petroleum Institute.

When this process started, the revision of RP 80 in the last few years, API had asked me if I’d be interested in participating and co-leading in the effort to revise or work on the second edition of RP 80, and I was happy to participate.

Russel:  Great. Keith, why don’t you do the same thing? You’re on the podcast somewhat frequently, but it might be helpful for listeners that hadn’t heard from you before. Give us a little bit about your background as well.

Keith:  Sure. My name is Keith Coyle. I work for Babst Calland. It’s a law firm. I specialize in matters involving pipeline and hazardous materials transportation. I had the good fortune of working with Jim, on developing some of the revisions to the latest edition of RP 80.

It’s been a great experience. People like Jim have forgotten more about this business than I’ll ever know, so I got to learn a lot and I keep learning a lot each day from working with people like Jim.

Russel:  Maybe a good place to start is what is RP 80, and what’s its history?

Keith:  I’ll take a crack at that and Jim can jump in and correct me.

RP 80 is an industry standard that the American Petroleum Institute developed in the late 1990s and published the first edition in 2000.

The impetus for the original development of the RP 80 document was a statutory change that Congress made to the Pipeline Safety Act in 1992. There was a mandate put into the law directing the Pipeline and Hazardous Materials Safety Administration to come up with new regulations for onshore gas gathering lines, including a new definition for gas gathering lines.

That was an issue that had plagued the agency really from the beginning back in the 1970s, coming up with a workable functional definition for what a gathering line is.

When Congress passed this statute in the early 1990s, PHMSA did some outreach to various industry stakeholders. One of those stakeholders, API, decided that it made sense to put together a coalition and a working group to go out and develop an industry standard that would provide what industry believes was an appropriate functional definition for onshore gas gathering lines.

That’s really where the RP 80 effort began in the ’90s. They developed a very comprehensive document that the first edition was published in 2000, and then PHMSA ended up incorporating that edition of RP 80 by reference in a rulemaking in 2006.

Russel:  The thing for me, and I’ve been in the business a long time, but the thing for me about RP 80 that I find really interesting is, on the surface of it, defining what a gathering line is, seemed to be straightforward. It gets real complicated real quick once you start peeling the layers off the onion and trying to get specific about where does the gathering system end and transition to something other than gathering. It could get quite complex quite quickly.

Keith:  Jim and I have the scars to show how difficult sometimes it is to come up with a definition that’s appropriate. Jim knows a lot more about this than I do, but there’s a wide variety of configurations in production and gathering systems throughout the United States. Things will vary depending on the age of the system, the area of the United States where it’s located.

Is it a conventional system? Is it an unconventional system installed in more recent years? Maybe I’ll punt over to Jim on that, but that’s my sense of where the challenge has been, is just trying to accommodate a wide variety of operations in the United States.

Jim:  Certainly, I think the original taskforce that worked on RP 80, and then certainly the group that Keith and I participated in, had the same type of issues. For as many different types of operators that you have, and by operators, I mean upstream companies like the one I work for, midstream companies, transmission companies, then you have all the different basins with all the different well types.

Vertical wells, horizontal wells, shale wells, coal bed methane wells, wells that need one ounce of pressure in order to be able to produce to wells that produce into a gathering line at 500 pounds or so.

Just the different scenarios across the onshore basins, and the different ways that operators have configured their systems, or dealt with the very real operational functional challenges that they have, just meant we had to get into great depth on a number of different what-if scenarios, just as they did in the beginning.

Russel:  I can certainly see where that could get really complicated really quickly. I know that there’s the distinction between what’s a flow line and what’s a gathering line, and then what’s a gathering line and what’s a transmission line. That’s the extent of my knowledge and I suspect that’s not even a fraction of one percent of the complexity.

Keith:  One of the things that’s unique about RP 80 is that it’s an industry standard, but it’s also a document that has jurisdictional implications for purposes of PHMSA’s Pipeline Safety Program. It’s always been understood that PHMSA doesn’t have statutory jurisdiction over production facilities. Production facilities aren’t just going to be limited to the production wells themselves.

It’s always been understood that there’s a certain amount of piping downstream from the well that is also going to qualify as part of a production operation, whether you call it a flow line, or a production line, or however you want to skin that cat. Understanding the extent of production operations has always been very important for the companies that are involved in that part of the business, because they’re going to be subject to different regulations, regulations by different bodies.

Not necessarily would it be appropriate to treat that piping as transportation related piping that may be used by the midstream industry, or transmission line and distribution systems.

Maybe Jim can share some of his experience on the production side. I think that would be helpful.

Jim:  Sure. Just to add to what Keith was saying, so RP 80 has become the standard by which state regulators and federal regulators as well, how they govern our production lines, our gathering lines, those types of things. From that standpoint, it’s been relied upon and reliable for over a decade.

Treating that with respect, as we considered changes and as we considered updating that rule, was tantamount and very important to the group. Certainly, for us, the beginning of production lines is easy. That’s when it comes off the wellhead, where does that end, or where’s the beginning of a gathering pipeline. Again, there were many different voices and many different points where that becomes.

Yes, we had to pick some hard and fast places where that transition takes place. As Keith mentioned, the functional test was the most important test to us and to the industry. Certainly, PHMSA understood that.

It’s not simply a matter of diameter. It’s not simply a matter of pressure. It’s functionally what is that pipeline doing. Again, we have production lines that are coming from very old, low pressure wells. We have production lines coming from horizontal wells. There’s quite a bit of difference before we actually hit a gathering pipeline.

Russel:  What drove the need to do a change? I know that, in the standard API process, review things every five years, but this last update was really a major look at the standard. What drove the need to take that hard look at the standard and do a big lift on the revision?

Jim:  PHMSA published a Notice of Proposed Rulemaking in 2016 with potential changes to their gas gathering regulations for onshore gathering pipelines. As part of that review, PHMSA asked API, a work group, to focus on several things that they wanted to consider.

One was, where’s the end of production? The second topic was the beginning of gathering. The two things we just talked about a moment ago, where did those two things happen. The third was some type of definitional or limitation on incremental gathering. Those were the three specific things that they asked us to focus on in the discussion for the work group.

Now, the NPRM, the Notice of Proposed Rulemaking, had the opportunity, had we not addressed it as an industry and with the stakeholders involved, had the opportunity for mass changes. By limiting it to those few things that we talked about, we were able to preserve the integrity of RP 80.

Keith, would you like to add to that?

Keith:  Yeah, just to follow up on what Jim was saying. When PHMSA published this proposed rule in 2016, what they had presented as an option on the table was to remove the reference to RP 80 in their regulations and establish some new or unique definitions that PHMSA wanted to use in the rules, and those definitions would have ended the production function at a point much closer to the wellhead than what has traditionally been recognized in this area of the law.

They were also looking to impose some limitations, as Jim mentioned, on the use of the incidental gathering line designation, which has been one of the more hot topics in terms of the regulators.

An incidental gathering line, just to explain it in the most simple way I can, is it’s going to be the last segment of a pipeline in a gathering system. It’s going to be the line that’s taking the gas from a compressor station or a treatment facility or a point of commingling, and it’s delivering the gas to another type of pipeline. Typically, it’s going to be a gas transmission line, but in some scenarios, it could be a distribution line. That length of piping or that segment of piping to some regulators looks a lot like a transmission line.

One of the things that’s traditionally been allowed under RP 80 at least one of the first edition is to treat that as an extension of the gathering function, essentially to allow the gathering operators to complete the journey by delivering the gas to a transmission line without having to have a transmission line at the end of their system. That was one of the more hot topics that was mentioned in the rulemaking process.

Russel:  That raises a question for me. Keith, we’ve had a number of conversations about the Mega Rule and how it’s thrown a much bigger net and capturing a whole bunch of pipe that’s designated as gathering, but it’s now going to be under some level of regulatory governance. How does RP 80 and the Mega Rule, how do those two things mesh?

Keith:  One of the things I’ll say that was some good news was that because of the efforts of people like Jim in coming up with a second edition of RP 80, those efforts were helpful in persuading PHMSA to retain the reference to RP 80 in the current rules.

So, the first edition of RP 80 is still incorporated into PHMSA’s rules by reference. They did impose a new 10-mile limitation on the use of the incidental gathering provision.

I think the folks that were involved in the rulemaking process would be pretty open about the fact that, because API went out and developed a second edition and made a good faith effort to try to address some of the concerns that the regulators had with the first edition, that allowed API to position itself in a place where now we have a second edition and we can take steps in the future to see if PHMSA can incorporate that by reference.

That was a very long winded way of answering your question, which is we still have RP 80 incorporated by reference under the Mega Rule. It’s the first edition. Now, there is a new 10- mile limitation on the use of the incident on gathering provision, but RP 80 lives to fight another day.

Russel:  I do know, just from my attendance at the GPAC that, at one point, there was some fairly serious conversation about just getting rid of RP 80.

Jim:  Absolutely, Russel. We were certainly cognizant of that as we started the second edition taskforce. Part of the stakeholders that we had from the beginning, it was not just industry, and it was not just upstream E&P companies. There were certainly a good number of midstream providers. We also had some state regulators involved. We had conversations with GPAC members.

PHMSA, while they didn’t have a vote or active role, they certainly had a person attending. They were advising as to direction or things that were maybe more important for the taskforce or the committee to address.

We had a wide array of stakeholders that participated from the beginning, some more active than others, but it was certainly an open process where we encouraged everyone to participate. That was a positive for the committee.

As we look at what did we actually accomplish, as we think about that for a moment, we certainly updated the diagrams and descriptions of RP 80. That was one key outcome for us.

Most diagrams and flowcharts were updated to a new, more current format. We changed many of the definitions for clarity. There was the thought that some of the original RP 80 had some circular references. Our goal was to eliminate those as much as possible.

We also updated it to reflect the unconventional production applications. By that, I mean shale wells, by that I mean the horizontal technology. Horizontal wells have been around a long time, and they were certainly around during the beginning of RP 80, so it was unfair to say that that was new or that was different. Certainly, the number and amount of had increased over the last decade and a half, to make that focus more important.

Keith already mentioned the incidental gathering change, so I won’t touch on that one. Those are some of the key components that we looked at, while still wanting to maintain the functional test of what a pipeline is. We didn’t use, again, diameter, pressure, ownership, or any arbitrary chosen parameter. We really focused on what is a pipeline, what’s the intent of what that pipeline is supposed to be doing as we looked at these changes.

Russel:  I’m going to tee this question up first just by saying, I am certainly only notionally familiar with RP 80. One of the questions that comes up for me, just knowing how old the original standard was versus what I know about the newer shale production model. That’s my caveat or my disclaimer, if you will, for what might not be a very intelligent question.

What’s coming up for me is to what extent does a multi-well pad, where you have six or eight wells all coming into the same pad, cause RP 80 or the definition of gathering to be different than maybe what it’s been historically?

Jim:  Just because there’s two, or three, or four wells off of the pad, that doesn’t necessarily change the pipeline, but the challenge for the team, the challenge for the industry, is what you’re referencing. If you have two, three, four new wells on the same pad, roughly producing quite a bit of natural gas in the first day, then one can only imagine that the pressure going into that pipeline is much greater than maybe in the past, so there’s no onsite compression.

Let’s take your example further. In your example, there’s no onsite compression because there’s no need for onsite compression. You lay one line in between the four wells that’s right there on the well pad to bring them all into one point, and then you take it on down to the next point.

In your example, that is still a production line. It’s still transporting gas from the wellhead to some gathering point or further point in the system. Depending on the diameter and the length, you can lose a lot of pressure between the well pad and where it changes to a gathering line, or it goes into a natural gas processing facility, or where it goes into a transmission line.

All those examples exist in real life. It’s not always production, to gathering, to transmission, to a gas plant. It’d be nice. That’d be great if it was always the same, but there are as many different scenarios and examples as we could sit here and come up with.

Russel:  I know of wellheads in the Houston area that goes straight into the gas distribution system, just because the quality of gas allows them to do that.

Jim:  Exactly. We have that quite a bit in the east as well.

Go ahead, Keith. I’m sorry.

Keith:  That’s a great follow up. To the question that Russel posed, would the convergence of multiple flow lines on a well pad signify the end of production? Not under RP 80. RP 80 is not written in a way where that arbitrary point of commingling would automatically signify the end of the production function.

Jim mentioned that depending on the basin that you’re in, there may be other things that you need to do to get that gas into suitability for delivery even into a gathering pipeline.

There’s going to be some sort of production related processing at a lot of these scenarios that needs to happen before the gas is even suitable for delivery into a gathering system, and then the gatherer is going to be responsible at the end of that journey for making sure that the gas is pipeline quality or suitable for transmission in a transmission line for ultimate delivery to consumers.

My understanding of RP 80 is not that a point like that would necessarily signify the end of the production function. You would look through the standard itself and do an analysis and say, are there production operations that are going on further downstream? Is there processing that’s going on further downstream? Are there things or activities that need to happen?

Production-related compression is something that Jim mentioned, as well as declining pressure over time. You may need to have production-related compression installed just to keep the wells productive for the remainder of their lives.

I know that makes things a little more complex for the regulators and maybe for the public, but RP 80 is a good faith effort to try to accommodate functional differences in production systems and gathering systems to help operators make the right choice on how to classify their systems.

Jim:  Absolutely. Well said, Keith.

Russel:  One of the things, Jim, that you’ve mentioned a number of times the functional use of RP 80. Can you unpack that a little bit for me? I’m a novice in this. I’m curious what that means.

Jim:  Certainly. As we said before, some of the focus from the federal government, from PHMSA, was an oversimplification. An example you cited earlier, you had two wells that were coming into a production flow line. The oversimplification would be that makes it not a production line. That changes the definition just because of that reason.

What the committee focused on and what was important to us was that this functional test of a pipeline be the key. As we think about that, as an operator, that’s more important than simply just pressure or a diameter test, because there’s many different ones.

So, in working on the definition of the onshore gathering line, there’s a five point test and some other points that I won’t bore those on the podcast. I urge you to download and purchase RP 80, second revision, and you can read through those details.

The point was to say what is happening at the beginning of that pipeline segment, and then what’s happening at the end. If you look at those two things in general, then you can determine what that pipeline is doing.

If it’s performing a production function, or a gathering function, or a transmission function were three examples. That can be seen based on this document. The point of this document was to clarify those issues and to work through those different examples for us.

RP 80 is a guideline for determining, for both operators and regulators, as I mentioned, the classification for onshore pipelines and to what regulations they may be subject to.

As a producer, we look at our pipelines as well as the federal regulations, obviously, and any state regulations, but RP 80 helps us to define, classify what segments may be subject to those rules and what segments are subject to some other state regulation or rule.

Keith:  A couple of follow-up points on what Jim just said. When we talk about function, one of the concepts that’s very important in RP 80 is this furthermost downstream concept where there are potential endpoints for production and gathering.

Operators are looking downstream and figuring out from the available endpoints, which one is the further most downstream. If I’m in the gathering phase just because I’m commingling gas from different locations, that first potential endpoint of the gathering function does not necessarily control.

I need to look downstream and see if I have a compressor station that is being used as part of the gathering function, then I would extend gathering to that point downstream, or if I have a processing plant that’s being used to clean the gas, gathering would extend to that point downstream.

A lot of these systems, you will see some or all of these endpoints present in a system. It’s not unusual to have commingling, compression, processing, all of that. Things will be different depending on the gas quality.

Jim mentioned systems in Appalachia, where you’re getting clean gas right out of the well, while you may not have a processing plant in that scenario, so you can take that endpoint off the list of potential endpoints, but there are probably going to be more than one.

Then just one other concept to mention about functionality is the ownership or operating status of the pipeline should not be controlling. I know there are other tests that are used in the pipeline world where a change in ownership or a change in operating status can impact the classification of a line.

What RP 80 instructs everyone is that’s not a controlling principle. In essence, you want to lay a map of the system out on the ground, take a look at it, and forget about who owns the piping.

You just want to look at how that gas moves from the wellhead to the ultimate delivery point and take away operator status, because in this sector of the industry, you’re going to have a bunch of different players. Jim’s companies can operate some wells. Somebody else is going to operate some wells.

People are going to be delivering gas into a gathering system. There may be multiple different systems that are flowing into and all that may go to a processing plant that’s owned by somebody else. That’s not how we want to look at this.

From the corporate side, we want to sit down and look at it and say, “Functionally, how does the gas get from the wellhead to the end of the gathering function and where do we end these points in between?”

Jim:  As you know, Russel, some companies are fully integrated from wellhead through the processing plant through the transmission line to the end customer, and then some are just a small piece of that or some segment or two or three segments of that. Keith’s point is an excellent one.

The furthermost downstream point is what we look to for the definition of that pipeline, and so that was a key piece of the second edition.

Russel:  Just listening to you guys talk, I have a whole conversation that’s going on in my head.

Being a guy who knows a lot more about automation and operations and operational risk, I could see where doing the RP 80 analysis is a way to bridge between some of the operational risk management that has to occur in a way and the integrity risk management in terms of what my assets are and the regulatory risk. By getting a comprehensive inventory of my endpoints and my pipelines and so forth, I began to understand those three domains of operating risk, asset risk, and regulatory risk. It actually provides the foundation for that analysis and drives some of the potential ambiguity out of the whole business from that standpoint. Am I getting that right?

Jim:  Yeah, that’s it. Go ahead, Keith.

Keith:  Thanks. I think so. The answer to all of these questions under RP 80 has a direct impact on your compliance obligations. If you are a production operation under RP 80, at least for purposes of PHMSA world, you don’t need to worry about it. You don’t need to worry about 192 transportation-related piping compliance.

If you’re in the gathering phase, you do need to worry about it. There are rules that are changing. We talked about that on an earlier podcast, Russel, but the nature of your compliance obligations is going to be different if you’re in the gathering phase.

You may be regulated. You may not be regulated. You may be subject to transmission line rules. You may only be subject to certain transmission line rules.

If you’ve got a transmission line at the end of your system, you better know that because the nature of your regulatory obligations in PHMSA world is going to be the highest that it can be under the current rules right now, so this analysis and getting these answers through RP 80 is so important for companies particularly in this area of changing regulations. Because if you get an answer wrong, you may create a compliance risk for your company, and that’s not where you want to be.

We want to have certainty in terms of asset classification and understanding about the rules that are going to apply to us, particularly in this era of changing regulations. Russel, how many rules if we had come out just in the last couple of months? We had one come out earlier this month too, and some of those rules applied to gathering. Some are just transmission. All of this is just very fundamentally important to understanding the nature of your compliance obligations.

Jim:  Well said, Keith. Russel, your question is spot on if a company or an industry participant will focus on their pipelines, this RP 80 document, it forces them to focus on where are their operational risks, where are their regulatory risks, what pipelines, as Keith said, are subject to what rules or not subject to those rules at all.

By working through this, as you tackle the different segments of your system, it can lead you to the correct answers as you apply these definitions.

Russel:  I think when we get into the midstream world in particular, when I say that, I mean a broadness, all of those people who are operating assets that could be thought of as midstream, and there’s lots of folks where midstream is part of what they do but not a big part of what they do.

The outcome of this conversation for me is I’m going to need to go read RP 80. I was thinking maybe there was one API standard I didn’t need to read and familiarize myself with, and now I’m having a whole different attitude about that.

Keith:  Jim and I can say there’s probably some moments about developing our RP 80 we’d like to forget. Jim has sold his efforts short. We did a lot of effort on this second edition update process, and Jim still had his day job.

Multiple meetings over many, many months, many hours in rooms, Houston, Denver, all over the place, DC, educating ourselves, educating other interested stakeholders, PHMSA, about some of these challenges, and why they’re important to industry.

If people like Jim weren’t willing to make the sacrifices they needed to make to get it done, those standards wouldn’t go forward. He’s too modest to say that, but I’ll say it for him.

Russel:  That’s really one of the things about our industry that I really appreciate is there are a lot of us that participate on these standards committees. I say this about pipelining all the time. It’s an immense technical domain, with lots and lots of very vertical specializations, and yet we all do a good job of working together. The standards are really critical to creating that common understanding that allows us to get better as an industry.

Jim:  API did a great job of bringing, as I said, a diverse group of stakeholders, but also a diverse group of talents to work through this. We needed all of them.

We had technical experts that understood measurement, and understood compression, and understood the technical side of this. We had legal experts like Keith. Certainly, I never want to underestimate what his contribution was, because we would often refer back to him as to what’s the implication of this or what’s the meaning of these few words?

We’ve all been in conversations where the meaning of a few keywords or a few phrases change the whole thing. His contribution there was so valuable.

People that could pull it together, and understand the business perspective of what we were trying to accomplish, as well as the historical side of this. It took everyone, and it was a great team effort, and one that I’m proud to be associated with through API.

Russel:  Just one final question. How thick is the section with the diagrams now versus the older standard? The reason I’m asking this question, I participated on API 1165. That was a big lift on that one. We ended up probably increasing the number of examples tenfold because that’s what was required.

Jim:  Ours was the opposite. I wouldn’t say ten-fold reduction, but it was a significant reduction. One thing that we did do, as opposed to having, I’ll call it an appendix in the back with all the diagrams and exhibits, we tried to put them closer to the language. Where we reference exhibit one or diagram one, we tried to have it very soon follow in the body.

Russel:  That’s interesting. You actually have fewer examples, and the examples are more with the text where they are doing a specific description. We had exactly the opposite outcome with 1165, a lot more examples.

Jim:  Really? OK.

Russel:  I think there’s a key difference there and probably that makes sense to unpack all that. It’s interesting to understand that. What you guys were trying to do is drive clarity.

Jim:  Right.

Keith:  Our experience having done this for a while. I was in so many more meetings with regulators where I was working with the diagrams as opposed to the text.

So, we knew we had to do a better job on the diagrams here and make those clearer because so much of what was helpful in terms of sitting down with a regulator, with the public, or with PHMSA was to work from the diagrams to show how the principles would be applied in practice.

I think most of the group felt like getting the language right is very important, but having good diagrams was almost worth the effort just in itself.

If we had done nothing but made better diagrams, I think people would have been satisfied because that is so important for the people who are doing this on the ground, to be able to point to a diagram and say, “This is my setup, or this is close to my setup. This is what I’ve been working off of.” It’s just so much easier that way than, “Here are all these words that I’m pointing to that are going to show you what my setup is, it is what it is.” I think that was invaluable.

Jim:  I agree.

Russel:  I could see where that would be hugely valuable and hugely important. I can also see where having the diagrams in the back without all the text describing them and their application can actually increase confusion and ambiguity versus clarify it.

Jim:  I agree. Certainly the experience over the last almost two decades was just as Keith and you have described where we had a number of diagrams and exhibits in the back. You’d have to go back to the language and try to figure out which was pointing to what.

As I said, we had the problem for any of us that have ever built a spreadsheet, circular referencing. Our goal was to eliminate as much as possible those circular references. If we couldn’t eliminate them, let’s explain them. Why are they there? Were they there intentionally ?

That was some of the arguments over the last few years were that, surely, that wasn’t an intentional diagram or an intentional point to make, so we had to go through those. Some, yes, were intentional, and we were able to explain those.

Russel:  I will say that I’m really glad that you guys came on this podcast. I have read a ton of standards, and I will say that listening to a conversation like this or being involved in a conversation like this, and then reading the standard, is a very different experience than just sitting down cold and reading the standard.

It’s so helpful to have the context and the background, and understand the thinking of the authors. It just makes reading the standard a much more meaningful and useful thing.

Thank you so much for coming on and sharing your experience, and thanks for the homework that I get to go read the standard now. [laughs]

Keith:  Don’t read it too late at night, Russel, unless you want to get a good night’s sleep, though, OK?

Jim:  Thank you, Russel.

Keith:  Thanks, Russel.

Russel:  I hope you enjoyed this week’s episode of the Pipeliners Podcast and our conversation with Jim and Keith. Just a reminder before you go, you should register to win our customized Pipeliners Podcast YETI tumbler. Simply visit pipelinepodcastnetwork.com/win and enter yourself in the drawing.

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Russel: If you have ideas, questions, or topics you’d be interested in or if you’d like to be a guest, please let me know either on the contact us page at pipelinepodcastnetwork.com or reach out to me on LinkedIn. Thanks for listening, I’ll talk to you next week.

Transcription by CastingWords