Pipeliners Podcast


Russel Treat welcomes guest Ardis Bartle to the Pipeliners Podcast to discuss the importance of measurement standard operating procedures.

In this episode, you will learn about field practice, the contracts and standards in the industry that dictate how SOPs should be implemented, managing legacy procedures that are inherited with an acquired company, and how changes to measurement technology affect SOPs.

You will also learn about the most important acronyms in measurement standard operating procedures: API, AGA, GPA, and SOX. Listen to the episode to find out more.

Measurement Standard Operating Procedures: Show Notes, Links, and Insider Terms

  • Ardis Bartle is the manager of Apex Measurement and Controls LLC and a representative for Gas Certification Institute. Connect with Ardis on LinkedIn.
  • FERC (Federal Energy Regulatory Commission) regulates, monitors, and investigates electricity, natural gas, hydropower, oil matters, natural gas pipelines, LNG terminals, hydroelectric dams, electric transmission, energy markets, and pricing.
  • FERC Order 636 was issued in 1992 to relax service requirements on pipeline firms and gave customers greater purchasing flexibility by separating gas sales from transportation. The order also extended transportation to include storage and allowed end-users with firm transport contracts to sell unused capacity.
  • API 21.1 describes the minimum specifications for electronic gas measurement systems used in the measurement and recording of flow parameters for custody transfer applications utilizing industry recognized primary measurement devices.
  • API 14.3 / AGA 3 describe the design and installation parameters for measurement of fluid flow using orifice meters and other devices, and provide a reference for engineering equations, uncertainty estimations, construction and installation requirements, and standardized implementation recommendations for the calculation of flow rate through orifice meters.
  • Sarbanes Oxley was a regulatory act introduced in 2002 by two U.S. Senators designed to address malfeasance in deregulated industries following the Enron scandal. SOX 404 determines a company’s internal system of checks and balances. (Read Ardis Bartle’s complete report on how Sarbanes Oxley affects gas measurement in distribution and pipeline systems.)
  • ISA (International Society of Automation) develops standards and certifies industry professionals through the PE (professional engineer) exam.
  • AGA 7, AGA 9, and AGA 11 refer to the various types of linear meters (turbine, ultrasonic, and Coriolis, respectively) used for custody-transfer measurement applications to calculate oil and gas volumes.
  • GPA 2166 recommends the procedures for obtaining samples from flowing natural gas streams that represent the composition of the vapor phase portion of the system to be analyzed.
  • A chromatograph or a portable GC is an analytical device that combines the features of gas chromatography and mass spectrometry to identify different hydrocarbons within a test sample.
  • EGM (Electronic Gas Measurement) is the process of measuring the quality of gas using a flow computer. Volumes are recorded and generated at field level, then imported into a measurement system.
  • NGL (natural gas liquids) crude sampling requires trained field personnel to take samples in the field and inspect the quality of the liquid.
  • API 4.8 provides information for operating meter provers on single-phase liquid hydrocarbons. It is intended as a reference manual for operating proving systems.
  • API 4.5 covers the use of displacement, turbine, and ultrasonic meters as master meters.
  • AGA 9 was developed for multipath, ultrasonic transit time flow meters used for the measurement of natural gas. A multipath meter is defined as one with at least two independent acoustic paths used to measure transit time difference of sound traveling upstream and downstream.
  • A measurement map captures the following points in your organization: knowledge, custody transfer, allocation, measurement, and the measurement of your partners.
  • A LACT (Lease Automatic Custody Transfer) unit measures the net volume and quality of liquid hydrocarbons. The related system provides for the automatic measurement, sampling, and transfer of oil from the lease location into a pipeline.

Measurement Standard Operating Procedures: Full Episode Transcript

Russel Treat:  Welcome to the Pipeliners Podcast, episode 13.

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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. We appreciate you taking the time to listen to this episode. I’d like to announce our most recent winner of the customized YETI tumbler. This week’s winner is Laura Arellano-Briot.

Laura, I certainly hope I pronounced your name correctly. Laura is with Tallgrass Energy, and she will be receiving a YETI tumbler soon. If you’d like to know how you might get yours, stick around, and we’ll tell you at the end of the episode.

This week, we have with us Ardis Bartle. Ardis is extremely well known, particularly in gas measurement circles. Ardis and I have known each other pretty much since I first got into the oil and gas business because we used to be competitors. We have become good friends. I really think the world of her. We’re very lucky to have her today to talk to us about measurement SOPs.

Ardis, welcome to the Pipeliners Podcast.

Ardis Bartles:  Hey, Russel. How are you?

Russel:  I’m doing good. I’m so glad we got you on. I’m so excite to talk about measurement standard operating procedures, which I believe is your life.

Ardis:  [laughs] I live and breathe it every day.

Russel:  Exactly. Why don’t you just tell the listeners a little bit about your background maybe and how you got started doing measurement standard operating procedures?

Ardis:  My background is I came from the back office world and moved into measurement with a product that has been on the market for some time, and I started serving on the American Gas Association Transmission Measurement Committee.

As I worked with Gas Certification Institute, which is one the leading providers of API, AGA, and GPA standards and best practices training in the industry, clients started coming to me and asking about how to get a set of measurement standard operating procedures. The interesting thing about that was in the old days, everybody worked for a major pipeline, like an El Paso.

They had their same set of standard operating procedures and didn’t need anything new. Then we started having all these master limited partnerships where these midstreams and production companies would start getting involved. They needed a set of standard operating procedures. They had nothing to work with.

Russel:  That’s perfect. I think we were talking a little bit earlier too about changing how the pipeline operators operated led to this as well where measurement became more important.

Ardis:  Do you know the story behind FERC 636 and how that came about?

Russel:  I, for one, will probably make something up. But I want to hear what you would say.

Ardis:  In the old days when you and I were very young, when we used to fly on the airlines, the airlines were totally regulated. The government set the price for each and every airline ticket that we purchased. One day, the government decided that they were going to deregulate the airlines and let the free market decide the price of the airline ticket.

A young man named Ken Lay from a company called Enron said to the government, “We would like to deregulate the pipelines. In order to deregulate the pipelines, we would like to become a true carrier.” The government said, “We would be willing to do that if you would be willing to institute a set of policies and procedures regulatorily.” That group became FERC 636.

The FERC 636 essentially said that all pipelines and midstream gatherers became true carriers. All the facilities that a pipeline used to have, like a training center, like a gas lab, like a testing facility, went away because the only thing they could carry in their rate order was the measurement that needed to be done in order for them to be a true carrier as per their contracts. That’s how FERC 636 came about.

Russel:  That was a big change in the market. That occurred in the ’90s. The listeners will probably appreciate this. Ardis and I have become good friends, but we used to be competitors in the marketplace.

Ardis:  Because we were involved with companies who were addressing this opportunity. The opportunity being that people who had never been concerned about the measurement for their facilities all of a sudden became very aware that the pipelines were doing an excellent job of measurement.

It was we need to trust but verify. All of a sudden now, everybody starts looking at their measurement. As you know, Russel, what is the basis of all gas measurement in the industry?

Russel:  Oh, I’m supposed to ask the questions, Ardis. What are you doing to me here?


Ardis:  The basis is the contract. Every well, every production site, every meter, every interconnect has a contract. That contract generally has a relationship to a standard, an API 21.1, API 14.3, AGA 3. But those contracts determine how measurement is done.

Russel:  That leads to the whole conversation of standard operating procedures. One of the points you were making as we were talking earlier is who writes the contract? The contracts are not written by the measurement engineers. The contracts are written by the business development, commercial guys. They’re not normally highly specific.

They’ll say, “Well, we’re going to follow AGA 3 because this is an orifice meter,” or something like that. But they’re not going to get very detailed about what that looks like.

Ardis:  Generally, when they write a contract, they’re more concerned about the relationship and not about the measurement because it’s something they don’t really have a high knowledge of. The problem in the industry is that many, many companies now do measurement but don’t necessarily have the contract at hand to determine how they do it.

For example, you’re Chesapeake and you’ve acquired 14,000 wells. What are the odds that all those contracts are available to you?

Russel:  Gosh, I can’t even imagine. I know that in the past, I worked with a customer. They had just acquired a big system. As we were putting in the SCADA stuff, the folks that were going through all the contracts were in the room next door. It was just boxes and boxes and boxes of paper. I don’t know how they got through it all frankly.

Ardis:  Here’s your challenge. You’ve acquired legacy companies with legacy measurement, legacy contracts. Now you have to create a cohesive measurement policy across your company. You can’t use the contracts, but you can base it on the contracts. So, what do you do? You build a set of measurement Sarbanes Oxley standard operating procedures so that everyone can be speaking from the same voice.

Russel:  Couple of things we probably ought to talk about there too just to unpack the conversation for people that are listening. First is what is Sarbanes Oxley? I know it’s often referred to as SOX, just an abbreviation of Sarbanes Oxley. But what is Sarbanes Oxley? Why do I care?

Ardis:  Sarbanes Oxley was created by two senators, Senator Sarbanes, Senator Oxley, back around 2000. It was a regulatory act in order to deal with the malfeasance that was created by the same company that deregulated the industry called Enron.

SOX basically says, and this is Section 404 of the SOX contract, that all financial transactions are totally transparent throughout the organization, all the way to the highest level. Gas measurement, liquid measurement is a financial transaction. In my business, we generally say that it’s the cash register of the company. That’s what SOX is in a nutshell.

Russel:  This is what I make up about that. I think a lot of people that do measurement might not understand this. But if I’m out in the field and I’m installing a meter or I’m doing a witness or an as found, as left, whatever I’m doing, that directly goes into the financials which directly go to the, if you’re a public company, the SEC.

What Sarbanes Oxley is saying is you better put the numbers together in a way that they’re real and meaningful.

Ardis:  And totally transparent to everyone in the organization.

Russel:  Right. Not only transparent to people in the organization but transparent to others with whom you’re conducting commerce.

Ardis:  Ergo, by putting a set of standard operating procedures together for measurement, like you do for safety, for regulatory group, for your different groups, again that gives you total transparency.

Russel:  Assume I’ve never seen a measurement standard operating procedure. What is a measurement standard operating procedure? How would I explain that to somebody who maybe is a novice?

Ardis:  A measurement standard operating procedure addresses not the operation of the equipment, it addresses the measurement practice behind the equipment. So, for example, we have concepts in API and AGA based on technology. Orifice measurement is an extremely common practice that is used across the industry, and it’s based on American Gas Association Report No. 3 and an API 21.1.

This practice is reflected in a set of measurement operating procedures by providing a SOX format which we can talk about later, if you’re interested. But that SOX format reflects things like installation, quality assurance of the orifice meter, field inspection which is now called verification, calibration, and witnessing. Now, those standard operating procedure sections are important.

In the old days, we all used to write a measurement procedure that would be on field inspection and calibration. The challenge is the team of your company, who is putting in the measurement device which is generally an engineer or a third party fabrication shop, may not understand the measurement behind AGA 3 and may design or install a piece of equipment that is not a best practice or compliant.

A measurement standard operating procedure for an installation of an orifice meter or a QA of an orifice meter will prevent any measurement by a set may occur upon installation. I don’t know how many times to tell you, Russel, I’ve been down to Eagleford and done an audit, and guess what I’ve seen?

Equipment that does not have any measurement compliance in the industry, but was sold to an engineer and was told that it was totally measurement compliant.

Russel:  Yeah, that is a very common problem, particularly in the smaller operators where they don’t have the internal measurement engineering expertise, and they rely on their fabricators to provide it.

Ardis:  Well, let’s be kind to engineers. I work with ISA. I’m familiar with the PE exam. Out of the 40 questions that those guys get in October every year, how many are measurement questions? 2. Two out of 40. It covers ANC. It covers ASI. It covers ISA. It covers API.

I feel for engineers because they’re trying to put together a measurement spec with the amount of knowledge that they can consume by reading the standard. None of these standards are easy to read.

Russel:  Yeah, and that’s absolutely true. I think you make a very good point. Anybody who has any practice doing engineering knows that there’s a big difference between knowing what the book says and understanding what industry practice is.

Measurement is one of those areas that typically, if a company is focused on building a facility, they’re not focused on the measurement. A lot of times, it’s process engineers that build facilities.

Ardis:  Yes.

Russel:  It’s not measurement engineers that build facilities. Measurement engineers are doing pipeline interconnects and things of that nature. I know that we could actually probably spend a whole episode just talking about what is process measurement versus what is custody transfer measurement, and maybe we ought to do that at some point in the future.

I want to come back a little bit to what is an SOP.

Ardis:  A standard operating procedure has some very critical points. Now, we are very fortunate because SOX, Sarbanes Oxley, has set us up with some formats that has helped us design standard operating procedures. When I look at standard operating procedures just not for measurement across the industry but for other industries, for other SOPs, I see a lot of standard formats.

There’s always a scope to the document. There’s always an applicability. There’s always an applicable standard. For example, am I AGA 7 turbine, am I AGA 9, am I AGA 11 compliant frequency? We want to know what the frequency is because I need to hold you accountable to your contract. There’s some room for the procedure. There’s something called governance.

SOX says: “You must have a governance statement so you have total accountability to one person.” Then finally, we always look at control evidence, and that control evidence can be a paper form, it can be electronic, but again, it provides proof that that was executed successfully. The format of that is pretty well set in a SOX format. Your measurement side is a little bit different.

Russel:  Unpack that for us a little bit. What do you mean by the measurement side is different?

Ardis:  The measurement side will reflect what measurement or practice you’re actually trying to execute. For example, for those who do gas sampling, we will need to reflect what GPA 2166 says, and we’ll have to relate that back. A lot of gas sampling is installation, design, placing of the thermal well, placing of the probe, the construction of the materials, the pipe diameters of placement.

Then, the second part of that is the actual handling of the sample cylinder in order to ensure that you don’t create any problems or liquids in the device which we call hydrocarbon dew point. What we’re trying to do in a procedure, for example, like gas sampling, is to relate to the client the necessity to have all the tools ready to go, installed and operating correctly.

Then, handling the device or the simple cylinder to the point that when they get it to the lab or they get it to the chromatic graph or the portable GC, that it processes correctly and gives them an accurate number so they don’t have to do it over and over again.

Russel:  If I’m doing gas and natural gas liquid measurement, how many different standards do I need to be familiar with, if I’m going to write a set of SOPs?

Ardis:  You need to write a set of SOPs based upon what types of technology or what types of contracts that you have that reflect your process. If you’re a crude processor, you need SOPs that reflect your electronic gas measurement. Excuse me. We now call it EGMs, electronic gas measurements processes 21.2.

You also need the crude sampling for NGL. There’s a whole set of SOPs that reflect that. You need the processes for tanks which is API 2. You’ll also need lax which I believe, and don’t quote me here, but I believe is API 8, and, of course, you’ll probably have some situations where you’ll need to do proving.

Depending on if you’re using master meter or volume metric method, you’ll have API 4.8 or API 4.5. What I’m trying to say here is it depends on what you’re doing and how you’re getting your product from one point to the other.

Russel:  There are a lot of standards out there. You have to understand what equipment I’m using to do measurement, what’s my approach to measurement, and then what standards provide the guidance for that approach. Then you have to unpack the standard into a step by step procedure that a technician can follow.

Ardis:  Your challenge, Russel, is most of the time, you’ve inherited a legacy of something else. You’ve inherited or acquired properties that reflect what the existing measurement is. What you need to do is get all the parties on the same page.

Here’s the challenge. You’ve acquired properties in Marcellus Shale, Pittsburgh. You have properties over in Piceance based in Colorado. Those two groups are doing measurement, but they’re not doing it the same way I can guarantee you.

Russel:  There’s valid reasons for that too because those formations are different. Whether or not my gas is rich or lean or whether or not it’s wet or dry impacts how I’m going to do measurement.

Ardis:  Your challenge as a measurement manager or measurement professional is getting everyone providing you the data in the same way in order that you can use it and fill that cash register for your company. The challenge in the business is I don’t need to be getting a measurement verification report that’s half completed or a gas sample that’s missing a month or two.

Again, your challenge is always getting the field guys to get you the data that you need at the office to do the job that you need done. It’s not an equipment based data that you need. It is a measurement based data that you need in order to do your job effectively. Any measurement manager you talk to, I guarantee the first thing they say every month is, “Where is all my data?”

Russel:  [laughs] The first question they ask is, “What’s missing?” That’s an easy question. It’s not an easy thing to get an answer to necessarily. It’s a lot of data, that’s the other thing about measurement that I think people often don’t really understand unless they’re working in that domain.

What are some of the benefits of SOPs? There’s one I can think of. If you’ll let me, I’ll talk about it a little bit because this is a subject that’s near and dear to my heart. That’s the issue of lost unaccounted for. Measurement’s never perfect. It can only be done within the limitations of the equipment and of the practice.

One of the things that is always an issue is ideally whatever I measure into a system should match what I measure out of a system, but in reality, it never does. I think one of the values of getting good SOPs in place is that I can standardize my practice across a system where multiple different people are doing the work, and yet we get them all doing it the same way.

Consequently, we drive some of the error out of the process. That’s one of the benefits I would assert is a benefit of SOPs. What are some of the others?

Ardis:  Let me enhance that for a few minutes because there you’ve covered quite a few items in one strong statement. First of all, I have to have everyone doing the same thing, for example, configuring the equipment. Russel, when you go out and you have a problem with measurement in the gas or the pipeline, it’s generally not the equipment that’s causing the error.

Why do I say that? The equipment does exactly what you tell it to. If it’s an ultrasonic meter, it is doing AGA 9 correctly. If you configure it wrong, if you install it wrong, if you don’t follow your procedure, then you’re going to have a measurement bias. Is that not correct?

Russel:  Yeah, absolutely.

Ardis:  That is one of the keys to the measurement procedure.

Russel:  I think, Ardis, that it’s also important to understand that the standards provide guidelines. They don’t necessarily proscribe exactly what you’re supposed to do.

What can easily happen is if I have different manufacturers or even different organizations within a larger company, they can have a little bit of variance where both things follow the standard, but they’re done a little bit differently. That can introduce measurement difference.

Ardis:  True. That’s the reason we don’t give the guys in the field the standard because the standard has shoulds and shalls in it.

Russel:  [laughs]

Ardis:  That will drive you crazy. If you’ve ever tried to read a standard, you might as well just start taking your nap right now. They’re not written as procedures. They’re written as a practice or a best practice. What measurement procedure should do is give guidance measurement wise for installation, for making sure that when that ultrasonic meter comes in, it’s got all the proper documentation.

It’s been through the hydro test. It’s been through all the speed of sound. It’s been through the calibration. Then how it’s installed correctly so it avoids any excessive vibration, it avoids pulsation. People don’t know this, the flow conditioner has to go in correctly. It has to have the top where the top says. It has to be on the right side.

There’s a lot of small but important things in measurement for the quality assurance and the installation that are covered in the SOPs that make sure that the proper things happen and ensures a company follows those procedures.

Russel:  I would assume that one of the things the procedures is doing is it’s providing detail that’s not available in the standard.

Ardis:  Or hard to find.

Russel:  [laughs] That’s also very well said.

Ardis:  The next problem is that there are always measurement balance issues. Every company sees them, hears them, know that they exist. Why is the measurement of the gas so important? Because every morning, we get up and we have a bunch of marketing guys. Every office has these marketing guys. They have the beautiful suits and ties. They have the TVs and cameras and the glass room.

Those guys are trading gas. That’s their only job is to trade. But they get up, they get to the office and it’s 7:00 a.m. in Houston, for example. They have to know how much gas they have for the day. They’re counting on the measurement guys to tell them if they have enough gas. Because what happens, Russel, if they don’t have enough natural gas for the day?

Russel:  They’re going to miss their obligations.

Ardis:  They got to go buy it on the spot market. They got to pay outrageous prices. Guess what happens the next day? The CEO who never cared about measurement is now on the phone trying to figure out why he’s paying to buy gas on the spot market and why the measurement is not correct.

Measurement procedures are interesting because they look at the process of how you do the measurement. They look at how you conduct it. They standardize that human factor so that we all know what we’re supposed to be doing, we may not be following it. That practice is there in order to make sure that we get the measurement certainty that we need in order to conduct our business.

Russel:  There’s enough things in measurement that happen that are outside of our control. To the extent, we’re able to eliminate things outside of our control, we’re going to have better numbers and everything runs smoother. I say this, measurement’s like some other things in our business. If you’re working in measurement, you never get your name called unless there’s a problem.

Ardis:  That’s exactly right. As I tell my students, no one knows who you are until there’s a problem. But when you’re doing your job correctly, no one ever talks about you because the measurement’s done. In measurement, you have to start eliminating what possible problems could be affecting your measurement uncertainty.

Once you eliminate the equipment, which you can eliminate as long as they’re configured and working properly, then you have to start looking at the process. That’s why standard operating procedures have become so important. What big bubba does on the pipeline in Marcellus Shale and what little bubba does in Colorado may not be the same thing and will affect the measurement uncertainty that you’re dealing with.

Russel:  I want to ask one last question. Then we’ll wrap up. I know that you and I could go on and on about this. If you were starting a measurement group from scratch, what advice would you take into that situation? What are the one, two or three things that you think are really important when you’re starting out?

Ardis:  The first thing I would do, and I tell all my clients to do this, is to build a measurement map.

Russel:  What’s a measurement map?

Ardis:  In my opinion, a measurement map is what is the measurement points in your organization? What knowledge do you have? What do you not have? Are they custody transfer? Are they allocation? Where do you have measurement? Where are your partner’s measurement points? Partners being the pipeline you send to or the LACT or the trucking service you move oil or gas to.

What are those measurement points? The second is evaluate the existing team in place. I am always surprised how many companies outsource all of their measurement. There’s nothing wrong with that, but have you ever looked at that company’s measurement standard operating procedures? How educated are they about measurement practices? Who is their measurement expert?

Look at your existing team. What qualifications does your existing team have? What training have they been associated with? What is their knowledge of best practices and standards? Once you access and then look of course at what documentation is in house, did you inherit a set of standard operating procedures that came from El Paso 20 years ago?

As many of us know, almost all the measurement standards and practices have been updated in the last five years. I am still dealing with companies who are pulling out tables on onion skin. Their measurement is totally incorrect. The challenge is, you’ve got to take what you’ve got and update it to where we are in the market right now.

Russel:  I think that’s great advice. One of the things I like to do is wrap up by trying to get to maybe three key points in what we talked about. Let me try to do that. Then I’ll give you an opportunity to talk back to where I’m landing.

The first thing is standard operating procedures are about field practice. They’re step wise, how do I fabricate? How do I install? How do I do quality assurance? Then how do I operate and maintain my measurement system? Not just my equipment but all the things related to getting measurement to the accounting group. That’s one takeaway.

The other takeaway is that it starts with the contracts, then the standards, then the standard operating procedures. It all goes back to how we agree to interchange with our partners. Then lastly, if you’re starting, you really need to do an assessment of what equipment do I have? How is that equipment being used? Who do I have maintaining the equipment? Their skills and such.

Then lastly what legacy procedures do I have? Are they current? I think that one, Ardis, as I think about this is probably the biggest because when I think about the level of change that’s occurring in the technology for measurement, even in the last 10 years, it’s huge. There’s not many people putting in turbines anymore.

If the turbine would have been what they’d have put in 10 years ago, they’re probably putting an ultrasonic now.

Ardis:  True.

Russel:  Anyways, what do you think about all that? Do you think I got to the basics?

Ardis:  I think you wrapped it up excellently.

Russel:  [laughs] You’re too kind. Ardis, look, thank you so very much. I’d love to have you back at another time. Maybe we’ll take a deeper dive into some of the subjects we explored today. Thank you for being here as our guest.

Ardis:  Thank you, Russel.

Russel:  Thank you for listening to this week’s episode of the Pipeliners Podcast. Just a reminder, before you go, that you should register to win our customized Pipeliners Podcast YETI tumbler. We’re giving away one each week. Simply visit pipelinerspodcast.com/win to enter yourself in the drawing.

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Russel:  If you have questions or topics you would be interested in, please let us know on the Contact Us page at pipelinerspodcast.com, or you can reach out to me on LinkedIn. My profile name is Russel, R-U-S-S-E-L, just one “l,” Treat, T-R-E-A-T. Thanks again for listening. I’ll talk to you next week.

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