Custody Transfer

Metering imports, exports, and allocations is a serious matter for plants. If the metering systems in your plant under-measure custody transfer of intermediates and final products to another business, profits are lost. Over-measure and your business shortchanges your customers, which can damage your reputation and expose you to legal liability. Given its importance, custody transfer has been the subject of many posts here on the blog.

Lots of factors can impact the accuracy of your metering system including system design, equipment selection, maintenance and upkeep, and the skills of your metering staff. I caught up with Emerson's Donald Angus who is a member of the METCO services team, based in Aberdeen, Scotland. METCO works with process manufacturers to provide total metering services to operate, maintain, and manage metering systems to ensure their accuracy. Some process manufacturers have concluded that metering skills are not a core business function, so they look to service providers such as METCO to perform this function.

Donald shares that key performance indicators (KPIs) are often established with risk/reward terms. If the metering performance does not meet the agreed KPIs, the service team does not get paid. These contracts typically include metering maintenance/recertification, metering data validation & reporting, mis-measurement reporting, spares management, service coordination, and metering personnel management.

The METCO team has more than 70 on-site metering specialists and more than 40 consultants, auditors, and engineers based in Aberdeen. Given these risk/reward-based contracts, the skill development of this team is a critical activity. Scotland has a rigorous competency program, Scottish Vocational Qualifications (SVQs), designed to benchmark individual skills against national standards of competence. It's described:

Scottish Vocational Qualifications (SVQs) are based on standards of competence (National Occupational Standards) that describe a candidate's ability to work in real conditions - having an SVQ is a kind of guarantee that a candidate is competent to the standards that the SVQ is based on. The National Occupational Standards (NOS) are developed by Sector Skills Councils (SSCs) on behalf of business and industry - as part of the development process, an SSC will liaise with employers within its sector.

The METCO metering team is certified to level 3 in measurement and is the only center in the world to offer this level of measurement certification.

Custody transfer metering falls under the jurisdiction of regulations such as the U.S. Sarbanes-Oxley act. Accurate and repeatable measurements are critical to compliance with the law and avoiding civil and possible criminal litigation. Having highly competent metering specialists as part of the plant's extended team might make economic sense based on the regulatory environment in which your plant operates.

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In an earlier post, I recapped a podcast on ultrasonic flow meters and their use in custody transfer applications. Gerard Hwang and Dave Seiler, at Emerson's Daniel Measurement and Control business shared an interesting energy analysis with me. It was an energy calculation for various flow measurement technologies in a liquid (oil tanker) loading application.

Typically, liquid loading applications such as crude oil custody transfer between parties, involve large volumes and sizable flow rates. It takes energy to pump these liquids from their source to their destination. Any pressure drop caused by the flow measurement can be directly translated into an energy cost.

In addition to diagnostics around fluid flow phenomena (e.g., cross-flow, asymmetry and swirl) which can increase flow measurement uncertainty, a fundamental design advantage ultrasonic flow meters have in high-volume flow measurement applications is that they are "full-bore" meters. This means that there are no restrictions, internal obstructions, or bends, which will cause a pressure drop across the meter--the loss incurred is that of an equal length of straight run pipe.

The example was from a large U.S. pipeline company, which transports oil, gas, and refined petroleum products. In this case, the liquid was crude oil and its viscosity was 23.3 centipoise (cPs). The flow rate ranged from 1,800 to 22,000 barrels per hour (BPH), and the crude oil had a specific gravity (S.G.) of 0.86. The maximum design pressure was ANSI 300# and a temperature range from -10 degC to 40 degC.

At maximum flowrate, a 16" ultrasonic flow meter resulted in a 0.12 psi pressure drop. Other flow measurement technologies required multiple meters in parallel to accommodate the same volumetric throughput and caused any where from 5-12 psi drop. This multi-meter design also increased the number of block and control valves required around the meters.

The energy cost calculation for loading operations 90 days per year at 22,000 BPH is:

(0.12psi x 22,000BPH / 2,448*) x $0.07 USD/KWh x 24 hours x 90 days = $163

*2,448 is a conversion factor from PSI and BPH to hydraulic horsepower (HP) divided by the pump and motor efficiency to get electrical HP multiplied by the conversion from HP to KW to get power.

In other words, the cost of the energy loss from pressure drop across the ultrasonic flow meter is almost negligible. With the differential pressures across other flow meter technologies, energy costs range from $6,800 to over $15,000 per year.

Now if you multiply this cost by all the flow meters performing these large custody transfer applications in your organization, daily, these energy cost savings add up to reduce operational costs.

Update: I received some feedback on the post and cleaned up a few of the paragraphs above.

I saw in my Sound Off blog RSS feed that Dan Hackett, part of Emerson's Daniel Measurement and Control business, did a podcast interview with Walt Boyes. The 25-minute podcast is on some new Daniel Ultrasonic flow measurement technology being introduced at the upcoming Emerson Exchange.

Dan starts by describing how these critical ultrasonic flow measurements work. I thought Dan's explanation was more understandable than my Guadalupe River rafting analogy in an earlier post. If there's no flow, the time it takes the ultrasonic pulse to travel across the pipe from one side upstream to the other side downstream and back is the same. As the flow increases, the time difference between the travel across the pipe each way increases--since one way the pulse goes with the flow and the other way it goes against the flow.

Dan described how some of the Daniel liquid and gas ultrasonic flow meters have 4 measurement paths to get different measurements at different points to integrate an average flow. The average axial velocity multiplied by the area of the pipe gives the uncorrected volume flow rate through the ultrasonic flow meter.

He described how these critical meters are used primarily in custody transfer applications. For those not familiar with the term, custody transfer is like the cash register where the possession of feedstocks, intermediates, and finished products changes hands between companies, governments, or countries. The measurements must be highly accurate and agreed to by both parties.

As Walt pointed out in one of his questions, ultrasonic flow measurement, because of low-pressure drop and high turndown capability, can handle a wide range of applications from very high temperatures to very high pressures. Dan described an application in gas measurement where this technology was being applied. Offshore and onshore gas production measure high-pressure natural gas--usually at the custody transfer point with the gas distribution pipelines. High volume consumers of natural gas, such as power plants and aluminum producers will meter the incoming natural gas. Also, many municipal districts measure the incoming natural gas before it goes into their distribution systems for the area businesses and residences.

For liquid custody transfer, crude oil production and processing are typical applications for ultrasonic flow measurement. Dan mentioned that right now it's mainly used in the feedstock and finished products areas of refineries, and less so in the process itself, where other flow measurement technologies are typically applied. In a refinery, the custody transfer surrounding the incoming crude and the refined products such as gasoline, diesel fuel, and kerosene are good applications for ultrasonic flow measurement. A final application Dan notes was liquefied natural gas (LNG) facilities where the incoming natural gas is measured and also in regasifiers where the liquid is converted back to high pressure gas for final distribution.

The new ultrasonic flow meter transducer being shown at the Emerson Exchange extends the temperature and viscosity range to address more applications like the heavy crudes found in the oil sands and oil shales. Typically, conditioning processes were required to reduce viscosity and or temperature, which add operational costs to the custody transfer measurement process.

One of the big enhancements Dan mentioned was on the software side, where diagnostics now embedded expert knowledge to identify conditions such liquid fractions in gas and pipeline deposit layer buildup. In oil & gas applications, the first case helps spot expensive liquid condensate giveaway. Accumulated buildup inside of pipes impacts the integrity of the custody transfer measurements. When these diagnostics are connected to the Daniel CUI 5 or AMS Device Manager software, operators and maintenance personnel are notified of a problem immediately and offered suggestions for corrective action. The CUI 5 baseline viewer provides a consolidated view for monitoring performance within pre-set ranges.

I found the podcast to be 25 minutes well spent as well as the recent email newsletter in getting up to speed on the latest developments in ultrasonic flow measurement and good application fits.

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Here's a story about a portable high-flow petroleum pipeline-proving rig. If you're in the oil & gas production, refining, or distribution business, I probably don't need to define what this is.

For the rest of us, a prover:

...is used for rapid, accurate calibration of a wide range of flow measurement technologies. Applications range from load rack, crude and refined product pipelines and marine terminals to offshore. The Compact Prover is used for rapid, accurate calibration of a wide range of flow measurement technologies. Applications range from load rack, crude and refined product pipelines and marine terminals to offshore platforms and FPSOs.

It's important to prove the accuracy of the flow meters measuring the hydrocarbons to account properly for the revenue it produces. As I've mentioned in an earlier post, this has implications for Sarbanes-Oxley financial compliance in the U.S.

Emerson's Dave Seiler, part of the Daniel measurement and control group, shared a story of a recently completed project. The team provided a Daniel compact prover to C&W Meter, a company that provides proving services to truck loading, pipeline, and custody transfer meters for major oil companies all through the North Eastern US.

Dave described the project as a portable 42-foot long custom trailer on which C&W Meter mounted a large 40 kW generator on the top shelf and at the back mounted some 12" hydraulically operated loading arms that allows them to connect to large, high-flow pipelines. C&W meter uses this 34" Daniel portable prover for large size meters on a pipeline. They believe this application to be the largest portable prover in North America.

The C&W meter website describes this prover application:

Currently in operation is our portable High Flow petroleum pipe line proving rig complete with Daniel 34" Small Volume Prover and 12" Master Turbine Meter. The trailer mounted proving system has a maximum flow rate of 18,000 Bph/12,600 Gpm of refined petroleum products - gasoline and distillates. The Master Turbine Meter is used for proving Ultrasonic Flow Meters that require a long sample time to achieve the required data uncertainty. The High Flow proving rig has 12" loading arms with a pressure rating of ANSI class 300# - 720 psig max working pressure. The loading arms are hydraulically actuated for fast, easy connection to the pipe line. The proving rig is fully powered by an onboard diesel generator.

Now I realize all this might be tough to visualize if you're not already familiar with provers, so C&W Meter's Mike Scott was kind enough to send me some pictures of the prover in action. I want to first warn those of you with social media-blocking IT departments, that I've uploaded the pictures to Flickr in order to embed this slideshow.

Hopefully, as more process automation bloggers and trade magazines use sites such as Flickr, YouTube, Twitter, etc. these IT walls will come down!

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Emerson's Steve Jones, part of the Micro Motion Coriolis flow and density measurement business, recently wrote an article on bunker metering for Bunkerspot magazine. Entitled, Critical Mass in the Bunker Industry, it describes the importance of accurate measurement of bunker fuel--also known as heavy fuel oil (HFO).

For those not familiar with bunker fuel, I found this definition:

Bunker fuel is also known by other names: heavy oil, #6 oil, resid, Bunker C, blended fuel oil, furnace oil and other often locally used names. No matter the origin of bunker fuel it has common properties where ever found: color, viscosity, contaminants, and operator problems.

In the article, Steve pointed to the challenges associated with trying to measure volumetrically the flow of bunker fuel used in the marine industry. Measurement errors are typically 1-3% and can be as high as 5%, which can lead to large discrepancies between fuel supplier and fuel consumer. Imagine if your car's gas gauge and the gas station refueling pumps were accurate to plus or minus 3%. You'd be wondering if you'd be getting all the fuel you purchased and wondering if you had fuel left in your tank as it runs low.

A better approach is to use mass-based measurement with Coriolis flow meters. Mass measurement can accurately measure the different bunker fuel grades, and impurities that have not been filtered out. Steve also noted:

Coriolis meters are non-intrusive, meaning that there are no moving parts or obstructions in contact with the fluid being measured. In addition to mass measurement, a single device provides an independent and very accurate density measurement of the fluid and a temperature measurement - three measurements from one device.

Bunker delivery operations have tank-stripping processes, which clear the tanks of sludge and water. This process means air can become entrained with the bunker fuel. Coriolis measurement provides accurate measurement even in these conditions, as I've discussed in an earlier entrained gas post.

Steve raised one other important requirement for bunker applications--in-situ meter verifications. He wrote:

Meter verification technology on Micro Motion meters measures the actual mechanical characteristics to a very high accuracy -- in line and without removing the meter. When a change in the meter's tube performance is detected, the results determine whether measurement performance remains within the original factory specifications.

Steve described bunker measurement mass flow meter trials with A.P.Moller-Maersk and ExxonMobil Marine Fuels. These trials are entering their second phase with a view to gain custody transfer certification. Steve concludes:

While Emerson continues to work with A.P.Moller-Maersk, ExxonMobil and others to provide international metrology certification of Coriolis measurement in fuel oil bunkering applications, initial test results illustrate the great potential this technology offers to the advantage of the marine industry as a whole.

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A common theme found in my 2008-blog posts was energy efficiency. Given the state of the global economy, 2009 posts will likely have a common theme on ways to improve profitability through cost savings and productivity increases.

Just before the holidays, my email spy service found a new flow measurement paper written by Emerson's Bert Konings. The paper, Accurate Flow Measurement Improves Profit, describes flow measurement and its direct impact on the profitability of process manufacturing plants. He sums up the importance of flow measurement:

Get it right, and the plant is more efficient, produces less waste, minimizes rework and lowers maintenance costs. Get it wrong and the consequences can be significant. Inaccurate measurement in fiscal applications can lead to a plant being overcharged for raw materials or effectively giving away the product. Inaccurate meters used to measure utilities can also add to costs. Meters used to provide a mass balance across the plant need to be accurate or technicians will either spend time chasing product losses that aren't there, or they will set the tolerance so wide that product losses are not identified early enough.

As I've discussed in earlier flow measurement posts, the technology choices are plentiful. Bert describes the pros and cons of many types including differential pressure across an orifice plate or venturi, positive displacement (turbine meters, oval gear meters), ultrasonic, vortex, and Coriolis mass flow.

Bert describes Coriolis measurement as being:

...based on the principle that when fluid is moving through an oscillating tube, forces are induced which causes the tube to twist. The amount of twist is directly proportional to the mass flow rate of the fluid flowing through the tube.

What has made the Coriolis measurement technology popular is its high accuracy and lack of moving parts. High accuracy helps the quality, throughput/productivity side of a plant's economics. Maintenance costs are helped by the lack of moving parts. As Bert notes:

By selecting the right materials for an application, the effects of erosion and wear can be avoided and maintenance reduced to virtually zero.

Other advantages include direct mass measurement, online density measurements, high repeatability, and low pressure-drop across the meter.

A drawback to retrofitting other flow measurement technologies with Coriolis measurement has been the need for four wires (or up to 9 based on automation supplier.) Running additional wires and conduit is often an expensive proposition, $20 USD / foot according to one U.S. Chemical manufacturer. The Micro Motion team addressed this in 2008 by releasing a 2-wire Coriolis flow and density measurement meter. I discussed some of the applications for chemical manufacturers in an earlier post. Other industries and applications Burt lists are:

...suited for use in the chemical, petrochemical and refining industries, and for continuous process and mass balance applications.

Give the article a read if you're weighing flow measurement options.

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On several occasions, I've discussed the subject of flow measurement and custody transfer. My WatchThatPage email spy service alerted me to a great new article by Emerson's N.K. Chaudhary. He's a member of the flow group based in Singapore.

His article, Improving Custody Transfer, describes the role of Coriolis direct mass flow measurement and some tips when using them in a custody transfer application. In describing the importance of good measurement in custody transfer, I'll borrow N.K.'s words:

Whenever liquid product such as refined petroleum changes custody from one supplier or distributor to the next, it must be accurately measured and scrupulously accounted for.

There are many types of flow technologies. The article describes the three basic categories including inferential volumetric flow, direct volumetric flow and direct mass flow. Each has advantages and disadvantages. Inferential flow measurement devices include magnetic, ultrasonic, differential pressure and turbine-based flow meters. Positive displacement (PD) technology fits in the direct volumetric flow category.

The bulk of the article describes direct mass flow measurement. The best examples of these are Micro Motion Coriolis flowmeters. N.K. describes how these meters arrive at a volumetric flow rate:

To determine a volumetric flow rate, a mass flow meter must also know the density of the fluid, which is accomplished by measuring the natural frequency of tube vibration. The fluid's flowing density is proportional to the square of the period of vibration of the flow tubes (inversely proportional to the frequency squared).

Coriolis flowmeters were approved by the American Petroleum Institute (API) in custody transfer applications in 2002 (API MPMS 5.6). N.K. cites a number of reasons that Coriolis technology has been widely accepted in custody transfer flow measurement:

...longstanding high accuracy and repeatability, versatility, reliability, tolerance of solid particles, and more recently low pressure drop and high performance.

N.K. offers some installation guidelines such as to avoid installing the Coriolis sensor at the highest point in the pipe. This is where gas is most likely to separate out. As I mentioned in an earlier entrained gas post, digital signal processing can filter out signal disturbance caused by slug flow conditions.

Unlike many of the other flow measurement technologies, Coriolis meters can be installed without long, straight pipe runs upstream and downstream which can simplify the installation. In applications with very high flow rates, it may make sense to install multiple Coriolis flowmeters in parallel. The total flow measured is the sum each output.

The article also describes OIML approval standards and proving methods to meet regulatory requirements. If you are considering alternatives for flow measurement in custody transfer applications, this article might help in your analysis.

Last week I did a post about pipeline surge pressure relief and a technical guide about this written by Emerson's Daniel business. They are known for gas and liquid fiscal flow measurement solutions for the oil and gas industry.

I received a nice follow up note from Dave Seiler about a Latin American refiner who was fighting turbine meter maintenance problems due to large concentrations of foreign materials in the pipeline liquid flow. The problem was so acute that they actually had to install two meters in parallel so they could switch between meters while the other was being maintained.

The refinery engineers worked with the local Daniel team to replace the turbine meters with a 6-inch liquid ultrasonic flow meter. These do not have moving parts, unlike the turbine meters, which were being impacted by the particulates in the flow.

I didn't know much about the ultrasonic technology in flow applications, so I googled around and found a Hydrocarbon Processing magazine article reprint, Use liquid ultrasonic meters for custody transfer, in the Daniel area of the EmersonProcess.com website.

Dave is a co-author of this paper. The article does a great job of simplifying how the ultrasonic technology works. It also includes the math on how the ultrasonic flow measurement works.

My analogy, fresh from a rafting trip down the Guadalupe River, is to imagine that you're floating down the river with an ultrasonic transducer on one bank, and another on the other bank a little further downstream. Ultrasonic pulses are sent between the two transducers in each direction. The pulse traveling across the river from the upstream one to the downstream one will obviously travel faster since it's going across the river with the current. And of course, the reverse is true; it takes longer to travel across the river going upstream against the current. With the formulas in the article and enough perseverance, you can calculate the river's flow rate from these time differences. For the 3D world of pipe flow, the authors' explain:

The resulting time difference is proportional to the fluid velocity passing through the meter spool. Single and multiple acoustic paths can be used to measure fluid velocity. Multipath meters tend to be more accurate since they collect velocity information at several points in the flow profile.

Now back to the story... after the installation of an ultrasonic flow meter, the refiners saw that the meter was reporting low flow rates when the product in the pipe switched between gasoline and diesel.

The local Daniel service technicians collected maintenance logs using their Customer Ultrasonic Interface software (CUI) and sent it to the support team in Houston for detailed analysis. The team verified that the meter was working correctly for both liquids. They deduced that the flow was being diverted somehow during the transmix, or product switchover, where both products are flowing through the pipe until the switchover has been completed. This was possible because of the meters ability to accurately measure both flow rate and speed of sound of the liquid passing through the meter with extremely high accuracy.

The refiner verified that this is what indeed was happening where this transmix was being routed away through a smaller pipeline for further reprocessing. With the age of the refinery and the retirement of experienced operators, the current operators had not been able to see this transmix operation occurring in their process. The refinery engineers were impressed that the team in Houston could deduce this from their analysis of the data.

The refinery engineers involved in this project are presenting a workshop at this year's Emerson Exchange in late September. If you face similar challenges, you might want to catch this one.

A 2004 study by the U.S. Department of Energy shows continued global growth for the like Liquefied Natural Gas (LNG) industry as one of the sources to meet global energy demand. Our Micro Motion division recently announced that Coriolis technology is ideal in cryogenic mass flow metering applications like LNG (-153.1 degC). LNG can be stored and transported much more efficiently in a liquid state than in a gaseous state.

I came across a Chemical Engineering magazine article entitled, Flow Measurement in Bitter Cold: How to Use Coriolis Meters in Cryogenic Service which better describes why Coriolis technology works well in the bitter cold of more than -100 degC.

The authors, Emerson's Tim Patten and Keven Dunphy describe how harsh temperatures pose problems for many flow measurement technologies. These problems are related to mechanical parts, wetted seals, and materials of construction with poor impact strength. And from a measurement standpoint, it's expensive to keep the cryogenic fluids cold, so they are kept slightly below their boiling points. As the fluid flows past an obstacle such as a valve, flashing can occur. Pockets of gas form in the liquid making flow measurement difficult at best.

Tim and Keven point out that Coriolis technology is well suited since it has no moving wetted parts, nor temperature sensitive materials, and it has the accuracy required to satisfy custody transfer regulations. They recommend careful attention be paid to the pressure drop across the meter to avoid flashing by increasing the meter size. Their rule of thumb:

...the difference between the discharge pressure and liquid vapor pressure at the fluid temperature should be maintained at a factor of at least three times the pressure drop across the meter.

The article also provides tips on density measurement limitations, insulation best practices, and non-linear compensation. These tips apply not only to LNG but other cryogenic applications like liquid helium.

Many process manufacturers have flow metering stations where ownership of incoming raw materials, intermediates, and/or outgoing products change. This custody transfer process is common with oil and gas producers, refiners, and chemical/petrochemical manufacturers.

Accuracy is critical since these measurements impact the bottom lines for both the seller and buyer. And, with the introduction in the U. S. of the Sarbanes-Oxley (SOX) Act of 2002, companies are required to put the controls in place to prove the accuracy of these measurements. Other countries have similar regulations requiring these documented proof-of-accuracy processes.

Robert Fallwell, a regional manager in Emerson's Metco Services business, has written an excellent article, Sarbanes-Oxley audits: coming soon in the July issue of Control Engineering magazine.

Robert shares his expertise on how process manufacturers need to prepare for the SOX auditors. He boils it down to:

...they ask for proof that flow measurements are accurate, that you have procedures to ensure measurement accuracy, and that the plant's operators, engineers, and production accountants have been trained in the correct procedures for the measurement control process.

If your business is impacted by SOX or similar regulations, you'll want to incorporate some of the ideas presented in this article.