In this episode of the Pipeliners Podcast, host Russel Treat welcomes back measurement expert Ardis Bartle to discuss the Bureau of Land Management Onshore Order, which governs measurement for producing properties on the land managed or owned by the BLM a/k/a the U.S. government.
Why should pipeliners care about the new BLM onshore order? Listen to this important episode to understand the implications for the pipeline industry, the latest rules in-play, and how politics influenced the new BLM order.
BLM Onshore Order: Show Notes, Links, and Insider Terms
- Ardis Bartle is the Manager of Apex Measurement & Controls and a representative for Gas Certification Institute (GCI). Connect with Ardis on LinkedIn.
- Listen to Ardis’ previous podcast appearances discussing Measurement SOPs and the latest measurement trends.
- The Bureau of Land Management (BLM) is responsible for administering, maintaining, and preserving more than 247 million acres of public land across the U.S.
- 43 CFR is a rule published by the BLM in November 2016 titled “Waste Prevention, Production Subject to Royalties, and Resource Conservation.”
- Onshore Order 3170 defines general practices for onshore oil and gas production.
- Onshore Order 3173 defines the requirements for site security and production handling.
- Onshore Order 3174 defines the requirements for the measurement of oil.
- Onshore Order 3175 defines the requirements for the measurement of gas.
- Onshore Order 3178 defines royalty-free use of lease production.
- Onshore Order 3179 defines waste prevention and resource conversation.
- The Bureau of Indian Affairs (BIA) works with the BLM to set up lease agreements for oil and gas production on tribal, allotted, or other Indian land.
- A royalty point is the location where a producer is assigned the responsibility of measuring production on Indian land. This is vital because the measurement affects the calculation of the volume or quality of production on which the royalty is owed.
- The Bureau of Safety and Environmental Enforcement (BSEE) assesses, inspects, and regulates the latest technology used in offshore facilities.
- Rule 17 (or Directive 17) in Canada defines the requirements for measurement points used for accounting and reporting purposes, as well as those measurement points required for upstream petroleum facilities and some downstream pipeline operations under existing regulations.
- PID (Photoionization Detector) is used for gas chromatography to detect and measure the amount of gas in a defined area.
- PLC (Programmable Logic Controller) is a computerized system in operations that automates processes that require reliability within a given time period. PLCs are especially useful for pipeliners to automate difficult tasks in the field.
- A measurement process flow diagram is used in measurement to document the flow of processes and equipment in a system.
- The Production Measurement Team (PMT) of the BLM acts as a central advisory body to ensure that oil and gas produced from Federal and Indian leases is accurately measured and properly reported through the review of new measurement technology, equipment, and processes.
- An Electronic Flow Meter (EFM) measures the amount of substance flowing in a pipeline and performs other calculations that are communicated back to the system.
- Colorado Engineering Experiment Station, Inc. (CEESI) performs NIST traceable primary and secondary calibration for numerous types of flow meters and fluids.
- Stormy Phillips is an oil and gas measurement technical expert contracted to the BLM at CEESI.
- The American School of Gas Measurement Technology (ASGMT) educates measurement professionals on natural gas measurement, pressure regulation, flow control, and other measurement topics.
- The 2018 ASGMT School is scheduled for September 17-20 in Houston.
- A meter tube inspection ensures that meter tubes and devices meet industry requirements to continue use in the field for accurate measurement.
- 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.
- An orifice plate inspection is a requirement to verify that the orifice meter is “manufactured to the specifications” of the API 14.3 and AGA 3 rules.
- Thermowells are tubular fittings used to protect temperature sensors installed in industrial processes. A thermowell consists of a tube closed at one end and mounted in the process stream.
- The FMP number is the Facility Measurement Point assigned to an operator who is approved by the BLM to produce in a designated area. The operator must submit an electronic application for an FMP number before any production can leave a permanent measurement facility, according to 43 CFR 3173.
- The Gas Analysis Reporting and Verification System (GARV) is defined by an instruction memorandum (IM) issued by the BLM under the 43 CFR 3175 requirement. The system calls for operators to use specific makes, models, and sizes of equipment and software versions approved by the BLM (upon recommendation of the PMT) beginning January 17, 2019.
BLM Onshore Order: Full Episode Transcript
Russel Treat: Welcome to the Pipeliners Podcast, episode 33.
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.
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This week we’re very fortunate to have coming back to join us Ardis Bartle. She’s going to be talking to us about the Bureau of Land Management Onshore Order, which is governing measurement for producing properties on BLM managed lands or lands owned by the U.S. government.
You might ask yourself, “Why do I as a pipeline care?” That’s why we have Ardis coming onboard to talk to us. Ardis, welcome back and thank you for joining us again on the Pipeliners Podcast.
Ardis Bartle: My pleasure.
Russel: I asked you back because I want you to talk to us about the BLM Onshore Order. For those of you who are familiar with measurement, BLM’s a big topic right now. Of course, you typically think of BLM being a wellhead order.
But, in one of our conversations, we were talking about this and you’re like, “Oh, no, Russel, pipeliners need to be aware of this as well.” I guess the first question I want to ask is, why would a pipeline operator, or why should a pipeline operator need to know about the BLM onshore order?
Ardis: This is the first time in 30 years that the Bureau of Land Management has modified existing 43 CFR and issued new, updated onshore regulations.
The onshore regulations we’re dealing with at this time are the Onshore Regulation 3170, which deals with something called facility measurement points, the Onshore Order 3173, which deals with site security, 3174, which deals with oil measurement, and of course, the big one, 3175, which deals with gas measurement.
Now the impact of these new onshore regulations not only addresses an operator, but also addresses the purchaser, or whoever is responsible for the measurement of that royalty point.
Russel: Yeah. That’s got to be a big deal for the midstream guys.
Ardis: If you’re a midstreamer or a pipeline, you have to know whether you are the measurement for a royalty point or not. Now the confusion in the business at the moment is many companies consider themselves a custody transfer point as a measurement point. The BLM does not look at it that way.
The BLM says a facility measurement point means an operator requested a BLM approved point where oil or gas produced from a federal or Indian lease, unit, PA, or CA is measured. The measurement affects the calculation of the volume or quality of production on which the royalty is owed.
Again, what is important here is it’s important for midstreams and pipelines. Both of them have been actively going out to their producers and asking are you a royalty point with the BLM.
Russel: I guess that’s the first key question. For the listeners that don’t know, the Bureau of Land Management is a federal department that governs federal land, national parks, Indian lands, that sort of thing.
Ardis: They’re responsible for onshore activities. BSEE is responsible for offshore.
Russel: Right. These things have got the measurement community up on tippy-toes trying to figure out what to do. Why don’t you tell us a little a bit about actually what’s in the rule. What does the rule saying that’s new or different related to measurement?
I know that’s a big question. Maybe you can summarize that so we can do that in the confines of a podcast.
Ardis: We’re going to try to go through each of the rules and the impact of each of those rules. I’ll try not to get too detailed.
Facility measurement points are a new concept. The BLM is instituting a website where each royalty point will need to be registered and identified as a facility measurement point. All measurement reporting will relate to that facility measurement point. 3170 is dealing with that issue.
3173 is site security. The most significant part of this in regards to measurement is you are required to have a measurement diagram of your measurement facility.
Russel: I guess this is very much like — I think it’s called Rule 17 in Canada where they require that for every measurement site there be a simple, what I would call a block diagram that shows the various pieces of what’s on the site and how they’re laid out.
Ardis: Exactly. It’s not a PID. It’s not a PLC diagram. It’s a measurement diagram.
Russel: It’s a measurement process flow diagram.
Ardis: Correct. Then, we move to 3174, which is oil. There’s been quite a bit done in that vein for the community. There’s not a lot new in this.
What’s really important is they’re identifying more with proving and proving procedures. The question that’s in the mind of many of the existing producers — high plains and midstream — is that the new onshore order says that all proving will be done under normal operations.
There was great discussion at the last API meeting in Austin on what does the BLM mean by normal operations. The BLM has approached API and asked them to give an identity of what that means. In the meantime, we’re all struggling to figure out exactly what normal operations for proving means when we look at 3174.
Russel: That’s always a difficult issue in the pipeline operations world. In the control room, they talk about normal and abnormal. Then, there’s another category that’s not well understood which would be normal/not usual, meaning, it’s normal for me to do this but I don’t do it very often.
Ardis: Exactly. Part of 3170, not only was it the facility measurement point, but the BLM instituted a retention policy for all your records.
The BLM now wants you to keep your records for seven years unless you are audited. Until they release you from the audit, you will keep the records indefinitely. The fines are pretty substantial in regards to the recordkeeping.
Russel: I would assume that that record’s not just of the original measurement, but of all modification and change to measurement for updating and analysis, or editing, or that kind of stuff, too. Would that be correct?
Ardis: It’s pretty extensive. When we get to 3175 is where the most significant changes come. This is all related to the gas measurement side.
This is also where some of the confusion and lack of understanding has occurred in the business. Especially when you look at most BLM properties, an operator, a producer may not handle the measurement for his particular connection, or his particular. The purchaser may have it.
The struggle with dealing with the Bureau of Land Management and dealing with midstreams and pipelines is the Bureau of Land Management has no civil capability to go after a midstream or a pipeline. They can only civilly prosecute an operator — I mean a producer. The challenge is they can only get a midstream or a pipeline for recordkeeping.
Most of the pipelines and midstreams have started to institute a BLM person. If you go to most of the majors now, there’s one person responsible on the measurement side to ensure that the midstream or the pipeline is meeting the BLM requirements. That’s where I’m seeing a lot of updating on procedures, processes, things along that line.
Now the challenge with 3175 is under 3175, there’s no approved measurement equipment, period. They have created a production measurement team generally referred to as a PMT.
The PMT is going to open season in August and allow measurement vendors — EFMs, chromatographs, linear devices, differential devices, analysis samplers, transducers, transmitters, they have a whole set of categories. They’re going to allow them to submit their products to be reviewed and approved by the PMT team.
In the meantime, everything is grandfathered until the PMT team does their analysis. They will post the approved vendors on the website. They will not post rejected vendors. It will be up to each of the companies to go to their vendors and find out if they are approved or been rejected.
The struggle with all this is the first round in August, they’re only allowing each vendor to submit one product in each category. I encourage all the companies to find out where their particular product is in the cycle, or what the vendor is planning to submit.
If you’re like Emerson, you have multiple EFMs. Which EFM are you going to submit for approval? Companies need to budget if they’re going to have to replace product in the next couple of years. Also, the PMT process is going to take some time.
Russel: Who’s on this PMT team?
Ardis: Rich Easterbrook, Beth Poindexter. Stormy Phillips is the contractor from CEESI who’s on loan. There’s several others that are on this PMT team.
Most of them are established BLM people who’ve been around a long time. Stormy is the new edition. I think they have another spot open that they’re planning to fill pretty soon in that area.
Russel: I don’t know if you know this because we haven’t talked about it, but there is going to be a panel at the American School of Gas Measurement Technology in September on the BLM order.
We’ve actually set aside — Ardis knows this, but the listeners probably don’t. I’ve been involved with the American School of Gas Measurement Technology for many years. I’m the guy who’s putting together the panel for the BLM order discussion. Stormy Phillips is one of the guys who’s on that panel. That ought to be a really interesting situation.
The plan there is we’re going to allow each of the people on the panel to have a little bit of a presentation. Mostly, we’re just going to open it up for Q&A. It ought to be interesting and educational when we do that in September.
Ardis: There you go.
Russel: I’ll link the details up about the American School in the show notes so that the listeners can find that if they’re interested.
Ardis: I’m going to circle back to 3175. 3175’s got two major components to it. The first is something called meter tube inspection. Meter tube inspection’s pretty much been an American AGA 3 process or a procedure that many, many companies do.
The BLM is now asking that that schedule go into effect immediately after January 17th if you’re very high. Now, it’s also including high gas meter tubes.
Russel: When you say high gas, you mean high flow rate, right?
Ardis: High flow rate. Let me give you the numbers here that are off the order. The order says, “If your flowing over a thousand Mcf a day, that’s considered a very high meter. If you’re flowing 200 to 1,000, that’s considered a high meter.” Both of those right now are subject to meter tube inspections by the BLM.
You’re required to give the BLM 72 hours notice to meet you in the field. You will inspect the meter tube through the normal AGA 3 process. You will also take a borescope and you will go into the tube to identify pitting, obstructions, dirt, things along that line.
Then a determination will be made at that point if the meter tube passes as per the BLM. If the meter tube does not pass, you will remove the meter tube from the existing installation and have it either rehoned or whatever needs to be done in order to get the meter tube to pass.
If it’s found that you have some pitting, they’re working on something called an IM. It’s called an intentional memorandum. That has not been released yet. It’s due in the next 30 days.
They have a resolution to the pitting depending upon the severity of the pitting, which may not require taking the meter tube out of service. This is most impactful for those clients whose meter tubes have been in service for a long period of time, and may have not been as stringently reviewed for meter tube inspections as others.
I’m also noticing that in certain areas of the country, the BLM has actually been out measuring the meter tubes to make sure that they’re compliant with AGA 3. As many people know, the flow conditioner needs to be at least 10 diameters from the first obstruction.
There’s a certain location for the thermowell. There are certain locations and the BLM is checking to make sure that those are correctly and accurately done. If they don’t fall into it, they’re looking at citing you and then asking you to make a replacement to that meter tube.
I want to be clear here. The BLM does not like to fine. They’ve made it clear to us that they would rather cite and have you resolve the problem quickly rather than to fine you.
This is now the challenge for a lot of these companies to get all their meter tubes on an inspection schedule quickly and get the BLM out to them so they can go out and start inspecting these with the BLM. Now if you are installing a very high or high new meter tube — this is brand new — then they have a whole other set of guidelines that go beyond that.
In practice, they can determine that if they choose, they can call for a two-week, orifice plate inspection until the plate comes out clean. That’s determined on a case-by-case basis, but they do carry the option and the order that they can say two-week plate inspections until they determine the plate comes out clean.
Again, this is determined by your local office, your BLM person who comes out to inspect you. It does apply right now and the order is in place.
Russel: I think that’s really great information, Ardis. I’m sitting here, I’m listening to you talk, and I’m just thinking about what all of this means for the operators. Here’s the one question I’d like you to talk about a little bit if you could.
I know it’s not uncommon, particularly for higher rate flows, for there to be either two physical meter tubes — one is a check to the other — or a single meter tube and two EFMs where one’s a check to the other. How, if at all, does the BLM address check metering versus custody? Who’s responsible for the measurement?
Ardis: Again, the royalty point is the only thing the BLM is concerned about. Now, here’s the interesting thought. The royalty point can have 2 or 3 wells associated with it, or 10 wells, depending on how it’s been set up. The royalty point is what they’re concerned about. Each of those wells will have to have sampling done based on the FMP number.
The BLM has also eliminated all co-mingling. There will be no more co-mingling according to the order. If you think you’re co-mingling, the arrangement needs to be changed in order to ensure that all the measurement is occurring in the royalty zone in the BLM, they’ve become very clear.
Russel: This has got to have some of the producers just absolutely scrambling because this idea of royalty point is brand new.
Ardis: That’s the challenge right now. The pipelines and the midstreams are very cognizant that their challenge is to identify who has a royalty point and who does not.
It’s been interesting because pipelines and midstreams who did not think they had any royalty points all of a sudden have found out by sending out a letter to their producers that they have all these royalty points they did not know about.
The second challenge is that the equipment that is on the royalty point may not be in compliance with the new order, 3175. Now why do I say that? 3175 essentially says that the API 21.1 calculations and 14.3 will be calculated in the EFM or the EGM, whatever you call it — electronic flow meter, electronic gas measurement.
The problem is that many clients out there have older EFMs. They don’t have the updated flow calculations. The vendor has chosen not to update those.
What they’ve been doing is they’ve been sending the data to their measurement back office, whether that be PGAS, or Flow-Cal, or whoever they use. They’ve been correcting the calculation in the back office in order to make it relevant.
The BLM says you can’t do that anymore. Once we establish the list of approved vendors, you will be required to replace that equipment and any other equipment on your measurement point — your transmitter, your transducer, any item that does not apply to the flow calculations that meets 3175.
A lot of companies are looking at the equipment they’re using right now and trying to determine over the next two years what they’re going to need to replace and what they’re going to need to keep.
They’re kind of in limbo because they can’t do anything until the PMT committee says, “Hey, this is the list of approved vendors that you can go talk to.”
Russel: Hopefully, when they come out with this is the list, they’ll give people some time to make the change.
Ardis: They’re talking about 180 days is what they’re saying at this point.
Russel: I would be surprised if industry doesn’t try and make that longer. That could potentially be a huge capital investment for some operators.
Ardis: The next challenge is that the 3175 also wants to capture the heating value of the gas that you’re providing. They’re instituting a new program where they’re going to have you report your heating value for your gas samples. They call that a GARV, and I will tell you what a GARV stands for. It stands for gas analysis reporting and verification system.
Everything will go online. You will go online. You will bring up your FMP, and you will report your gas analysis heating value. They’ve tightened up the requirements for your sampling, your heating value, your reporting, and your uncertainty.
The present uncertainty calculation that everyone is using for the BLM is going to be modified and upgraded. The schedule is about a year, a year-and-a-half out for that.
They’ve also tightened up times between samples. We used to tell a technician you can go out in May and take a sample, and then your next sample for the next month you can do some time in June. You can’t do that anymore. You have 45 days from the time you start a sample ‘til the time you take it.
Also, there was no provision in 3175 for portable gas chromatographs. This really took the industry by shock because many clients use portable chromatographs to analyze their samples.
The BLM has instituted an intentional, an IM again. That IM will be coming out with a portable chromatograph procedure, which will allow you to apply for a variance.
As the BLM has been very kind to share with us, you can apply for a variance for just about anything. The question is whether they will grant it. They will probably not grant it if it has clarity inside the rule.
They are planning to go out for another rulemaking. The last rulemaking took about eight years. We suspect the next rulemaking will take about eight years, also.
Also, we were notified at the last measurement school that under President Trump, they are required to look at all regulations and determine if any of those regulations are onerous.
They will open a review cycle and notify the industry to allow them to comment. My understanding is whatever they comment will still have to go back into some kind of rulemaking process.
Russel: We’re seeing exactly the same kind of thing on the pipeline rules and the pipeline safety stuff, these Trump guidelines about if I create a new regulation, I got to get rid of two, and all new regulations need to be under review. They’re also looking for regulations they can rollback because they’re overly onerous.
It’s been a long time since I’ve been out on a BLM site and looked at the measurement, but I certainly have some knowledge. Some of that measurement’s been in place for a very long time without a whole lot of modernization. From the BLM standpoint, you see where they’re coming from, but from an operator’s standpoint, it certainly raises a question.
I do want to ask one other question though about this because in my mind it’s muddled. You talked about the royalty point and the fact that a lot of the midstream operators and pipeliners are finding out they have BLM royalty points. If there’s an error with measurement, or an issue around measurement related to the BLM, who has the responsibility to correct that?
Ardis: The operator has a responsibility from a recordkeeping point of view, if it’s a midstream or a pipeline. The producer, or the owner of the wellhead has the civil and criminal responsibility, also.
Russel: To me, that’s a problem because I don’t know that the contracts that are currently in place contemplate that reality.
Ardis: Here’s the real problem. This is what I have been trying to explain to producers. Most producers are not as organized as midstreams or pipelines. Most midstreams and pipelines have standard operating procedures based on API 21.1, which is the latest version called 2013.
When that was implemented, API 21.1 was extremely clear that we don’t inspect anymore, we verify. When we install, before we flow gas, we commission. We install, we commission, we verify. If we need to, we calibrate. The problem is that many companies did not read 21.1, version 2013, and are still practicing to the older version of API.
The next challenge is because they’ve not been doing this, the BLM is requiring them to provide documentation to prove that they are commissioning. They want documentation to show the last 10 verifications.
The BLM can show up at a verification or an inspection, and they want to see my documented last 10 verifications, and if needed, my procedure on how we do that.
Same thing on gas sampling. We went from I could eyeball it, and this looks like a good procedure and I’m good with that. I now want to look at all of your paperwork.
This goes to the back office, Russel. They can look at the last 50 events from the SCADA system, or the EFM if the EFM can hold it, the last 50 configurations, the last 50 alarms.
Basically, they’re saying what you’re giving us may be good. We want to see the documentation to back up everything that’s occurred before this to see how many times you’ve possibly gone out and modified, or re-verified, or calibrated a unit and cause new measurement error.
Russel: That’s all regulatory requirements, right? We’re going to write a rule to tell you what to do. What we want to do is we want to be auditors. As regulators, we want to be able to come in and look and see through documentation that you’re actually doing that.
Ardis: For example, when they show up for a sample, you have to prove to them — you have to have the documentation on-hand — how that sample was cleaned. Most companies use third party labs.
Those third party labs supposedly have procedures. Now, you have to make sure that all your third parties line up with you because when the BLM comes out, they want to see the procedure you’re using to clean that sample bottle.
They want to see all of this documentation, which they did not necessarily have to see before this rule.
Russel: This is really, really interesting information, Ardis. I really appreciate it. Being a guy who started in measurement, this is fascinating to me. To me, it seems like it’s fairly comprehensive. It’s a substantial order. There’s a lot here that people are going to have to do.
Certainly, I think it’s going to cause measurement to get better not just with BLM stuff, but more broadly, measurement will get better. It’s going to take some time, it’s going to take some effort for sure.
Ardis: The industry as a total will have to become more measure… companies that did not take seriously measurement will now look at measurement in a whole different light. They will have it more documented. What I’m noticing is they’re all taking the high road on this. They’re looking at how to make sure they implement this all the way down so that their partners, whoever they’re doing the operations for, has total clarity on what’s going to be required.
They put pretty much everyone on notice that if the equipment that we have with you is not up to par with the PMT committee, we will be replacing it. You probably will bear the expense on that. I think the producers are just not really clear on where to go at this point.
Russel: I really appreciate you coming and sharing this information with our listeners. If somebody is working this issue and would like to reach out to you, because I know you’re a domain expert in this area, and learn more, what’s the best way to get in contact with you?
Ardis: It would be to reach me at Gas Certification Institute. Our website is gascertification.com. We would love to talk with them and help them out further.
Russel: Great. Thank you so much, Ardis, for joining us. I’m certain we’re going to have you back because there’s other things you’re working on that I know our listeners are going to want to hear about. Thanks again. We appreciate it.
Ardis: Thank you.
Russel: I hope you enjoyed this week’s episode of the Pipeliners Podcast. I certainly enjoyed the conversation with Ardis Bartle and learned a lot about the BLM and how they’re going to be affecting our business in the measurement domain.
Just a reminder before you go, you should register to win our customized Pipeliners Podcast YETI tumbler. Simply visit pipelinepodcastnetwork.com/win to enter yourself in the drawing.
Russel: If you have ideas, questions, or topics you’d be interested in learning more about on the Pipeliners Podcast, please let us know on the Contact Us page at pipelinepodcastnetwork.com or reach out to me directly on LinkedIn. Thanks again for listening. I’ll talk to you next week.
Transcription by CastingWords