Importance of managing fiscal risk in large volume gas custody transfer.

By Lonna Dickenson, Emerson 
Gas custody transfer refers to financial transactions where the ownership of a gas, typically natural gas with a high concentration of methane, is transported and then transferred from one operator to another.  Money is changing hands as the ownership of large quantities of gases are measured and then exchanged between two parties. 
Custody transfer, therefore, demands the highest levels of flow meter accuracy, reliability, and availability of measurement, particularly as the volume increases and the stakes are higher.  A small error of 0.25% equates to financial risk of ~$480,000 per year on 3 million standard cubic meters per day at $5.00 per million Btu (based on historic natural gas European Union import prices).  Measurement errors lead to financial exposure and the possibility of litigation and settlements which are costly in both money and time.  

Industry Best Practice for Setting Gas Measurement Uncertainty Budgets 

Due to the large economic risk, pipeline companies and other operators often set uncertainty budgets in order to mitigate financial risk or exposure.
metering station capasity annual ecomomic trade value class rererence level
Figure 1.
DNV GL, known for establishing best practices and standards globally in many aspects of the oil and gas business created a risk-based approach to managing gas measurement uncertainty. Figure 1 above illustrates their recommended uncertainty budgets which are based on annual economic trading value. 
For an economic trading value up to $100M, the recommended uncertainty limit should be Q=0.5% of flow. This would limit the customer’s financial exposure to approximately half a million dollars annually in large volume stations.  This is purely for the meter; system uncertainty budgets per the American Gas Association (AGA), should be 1.0% or close to $1M in overall uncertainty for the large metering station.

Apart from the annual trading value, these recommended uncertainty budgets are the result of the desire to weigh the cost of more robust measurement solutions against the cost of uncertainty and account for the current state of the art measurement technology capabilities, prices and uncertainties.

For smaller volumes with lower annual economic risk, it may be rational to use an ultrasonic meter with fewer paths, a metering design without check measurement or redundancy or a meter type with no diagnostics. However, in larger volume gas custody transfer applications, the cost of uncertainty is so high that state-of-the-art designs and technology are continuously evolving to even meet these lower uncertainty budgets in actual operating conditions.

Three Prevailing Large Volume Gas Measurement Technologies 

Most pipeline operators strive for an operational measurement uncertainty that is better than 0.3% but that can be difficult to achieve even with meters rated for custody transfer. Meeting this uncertainty threshold often mean piping design and meter technology limitations. Even then, this uncertainty is only truly met when the highest accuracy flow meters are operating correctly in ideal conditions. 
The calibrated (turbine and ultrasonic) /uncalibrated (orifice fittings) individual meter accuracy varies by meter type and ranges between 0.1% - 0.25% but operators must add an uncertainty allowance for installation effects, where +/-0.167% represents the lowest possible installation uncertainty accredited by international metrology standards (achieved by best-in-class custody transfer meters only). 

For larger volume gas custody transfer, there are only three prevailing technologies and ultrasonic is most often the first choice. 

Differential Pressure (DP), dating back to the 1930s can be offered in a wide range of sizes and are very good in harsh environments. The orifice fitting, one type of DP measurement, is the most common type of flow meter type used today and was the preferred gas measurement technology until the 1980s when turbine meters became accepted for custody transfer measurement and started to displace orifice fittings, particularly in cleaner downstream environments like gas pipelines and utilities. They are highly accurate, repeatable and have a wider turndown ratio, or the range of velocities a meter can measure accurately.  This provides for more flexibility for operational changes such as growth or decline and/or seasonal fluctuations of flow rates. 

The Rise and Evolution of Ultrasonic Flow Meters

Although ultrasonic measurement technology has existed since the 1960s in nuclear and industrial applications, it did not become accepted for gas custody transfer until the late 1990s, which coincided with the release of AGA 9. This report provided operators clear metrological guidelines for the use and application of ultrasonic meters for custody transfer, which fueled the growth of ultrasonic meter usage globally. 

Early ultrasonic flow meters were often misapplied because of poor designs of Doppler type ultrasonic meters and a poor understanding of the new technology in general. They were perceived initially as “black box” devices with performance issues and received a bad reputation in the industry. Advances in path configurations, micro processing speed, digital signal processing (DSP) and software led to significant improvements in their performance, diagnostics and usability. 

It is also why global metrology approvals that govern their use and application have been so important to the acceptance of ultrasonic among end users. Ultrasonic meters have continued to evolve exponentially over the last ten years offering new designs with more paths (including dedicated diagnostic and verification paths), more advanced diagnostics and more robust designs to name a few improvements. 

More paths have increased accuracy and reduced sensitivity to flow profile effects allowing for more compact installations and the option to install without flow conditioning.  The addition of diagnostic paths and conditioned-based maintenance software and services that trend diagnostics for measurement assurance and predictive maintenance are still relatively new and evolving. 
While valve noise interference can still occur, improvements in noise isolation, DSP, higher frequency sensors and filtering and stacking techniques mitigate much of the risk of valve noise for more robust measurement in operation. 

The meter sensors have also become more robust with designs that protect them from direct contact with the process, making harsh environments suitable. Applications for ultrasonic meters have continued to expand as a result.  These improvements, decreasing price and fundamental advantages (Figure 2) have accelerated the evolution from older technologies to ultrasonic as the pros and cons are weighed. This and changing needs have prompted the industry to reevaluate older standards.

Figure 2.

Minimizing the Effect of Process Disturbances on Operational Uncertainty

Even with the most advanced technology, the difficulty with meeting such tight tolerances on operational certainty is that so many variables that can occur in actual operation are not factored into the uncertainty allowance.  DNV GL found that 75% of the metering errors in the field were process related and only 25% were meter related. Process disturbances such as pulsations, valve noise, blockage and even small amounts of contaminants could have significant impacts on measurement accuracy. 
The meter could also drift over time.  Even with sophisticated internal meter diagnostics, many countries have stuck to calendar-based models for recalibration of ultrasonic meters to mitigate this risk. The ability to take a meter out of operation is an expensive prospect that requires piping designs with bypasses, meter spares, contractors and transport as well as downtime. 
To minimize meter operational uncertainty in large high-pressure metering stations, several European countries and transmission operators in Europe and in North America established new guidelines for gas custody transfer.  The potential for meters to be impacted by underlying process conditions, wear and tear or functional issues, gave rise to the best practice of using two different meters in series where the second meter is used as a check measurement to verify the primary custody transfer measurement.  It began as either a turbine meter and orifice meter or a turbine meter with an ultrasonic meter.  

However, in 2013 when the European Union started changing the pipeline infrastructure to ensure security of supply, the option for two different types of ultrasonic meters started to become accepted for bidirectional installations as well as for unidirectional installations in many cases.

In 2015, Physikalisch-Technische Bundesanstalt (PTB), the national metrology institute of Germany legalized a new guideline, TR-G18, stipulating that two gas ultrasonic meters in series could be used for verification if the two meter designs had a different number of paths or had different path configurations, and that this verification method could potentially extend the recalibration cycle indefinitely if the two meters agree and meet the criteria for installation and use.  This opened the door for other countries and operators to follow this practice of using two ultrasonic meters in series but is there more to consider?

The Problem of Common Mode Error

The original idea for using two meters in series was to use meters that operate using different physical principles, therefore, eliminating common mode effects, which is when two meters react the same way to the underlying problem thereby masking it. Yet dissimilar meters can still react similarly to disturbances and effects of certain process conditions.
Therefore, it is important to look closely before making that assumption. For example, both orifice fittings and all types of ultrasonic meters will over read in the presence of liquid or buildup.  If two different technologies can have common mode error, how can two different ultrasonic meters be used in series for verification? Even if two different manufacturers are used, the problem can still exist if the physical measurement principles and meter architecture are not different such as two meters with direct paths. 

One way this can be addressed is by combining different path types and path locations and then by comparing speed of sound (SOS) and/or flow velocity.  Each path configuration has different strengths and weaknesses on their own (Figure 3), but combined, they can make very powerful check measurements and diagnostics. Flow profile changes in the process as a result of (partial) blockage or roughness can be detected quickly in a very early stage comparing a meter with more robust direct path meter to a check meter with a single reflective verification path.

Figure 3

Furthermore, multi-path meters already do sophisticated diagnostic checks on SOS agreement per path.  If meters with both reflective and direct path types are compared, greater deviations in the SOS differences between paths will be observed. Reflective paths that are sensitive to pipe wall effects will show a clear SOS shift compared to negligible SOS shifts on direct paths.

That is how liquid and buildup contamination can be diagnosed. If the reflective measurement path is positioned to come into direct contact with the pipe wall buildup or liquid, it will create a significant shift in SOS per path and average SOS.  The graph below shows the SOS spread that resulted from just 1-1.5 mm of anti-seize sprayed across different sections of the bottom of the meter in the lab. 

Figure 4.

Both meters will overstate the volumetric flow rate and have the same directional bias in this case, but the risk can still be mitigated and detected.  Figure 4 illustrates the sensitivity of the reflective path to buildup.  The speed of sound shift of the single path is calculated by comparing measured speed of sound to calculated SOS, using the AGA 10 method.  This method uses gas composition, pressure and temperature to determine what the speed of sound should be.  This is one of the most fundamental diagnostic checks for ultrasonic meters. 

In Test 5C where the anti-seize is only on the very bottom of the pipe, the reflective path does not reflect off this small area of buildup and the SOS shifts marginally.  In Test 6C the reflective path comes directly into contact with the test condition and SOS shifts over 0.12%, orders of magnitude over the 0.2% shift allowed by AGA, signaling a problem. 

Reflective paths are critical to detection, but reflective path location is also important.  Test 5C could be detected using SOS if a vertical reflective path were present. SOS comparisons between path types and between meters is how the operator can reduce the impact of common mode error in the case where the flow rate responds with the same directional bias.  

New Test Qualification for Limiting Operational Uncertainty

With exception to liquid and buildup, reflective paths typically respond with the opposite flow error bias to that of direct paths, which drives greater separation between two meters using opposite path types for faster detection. 

DNV GL created a new test qualification for custody meters that was designed to account for uncertainty that occurs due to process conditions in the field.  Other internationally renowned metrology standards organizations (OIML R-137, AGA 9, ISO 17089) focus on calibration, design and installation effects but fail to account for real-world operating conditions in the field. 

DNV GL based the test criteria for their new meter qualification on their independent research on the most common process conditions that affect operational uncertainty.  These conditions were found at real sites all throughout the world.  Below are the results of the test qualification on a meter design with both direct and reflective path types.  

On all blockage tests and on the temperature test, the direct path meter and the reflective path meter had the opposite flow error bias, preventing common mode effect and providing an early warning of process changes.  For these process conditions velocity comparisons are enough for verification.  For liquids, buildup or roughness effects, SOS comparisons between meters and path types are needed to reduce common mode error.

Figure 5.

The meter under test is the Daniel 3416 (Figure 5), not an 8-path meter but a so called 4 + 2, which combines two independent meters into the same body: the first uses 4 direct paths in the British Gas layout and the second uses two reflective paths in different locations. 

The reflective path which is 30° off vertical is a check measurement path and the vertical reflective path is a diagnostic path used for its sensitivity to pipe bottom contamination.  Emerson has a 20-year legacy with 1-path and 2-path reflective type meters used for allocation measurement applications and a 34-year legacy with the robust 4-path British Gas layout designed for custody transfer. 

In 2015, in recognition of the potential to improve inline meter verification using dissimilar path types and the potential to exploit the weaknesses of the reflective paths for process condition detection, these meter types were combined into a single meter body.

This allowed comparisons between these path types to be made in the meter or online with new comparisons and diagnostics. Several ultrasonic meter manufacturers now offer two-in-one solutions but with different combinations and results. Emerson is the first and only manufacturer who combines the robustness of the direct paths (chordal) with sensitivity of the reflective paths for checking, verification and diagnostics enabling early warnings. 

The key to limiting the operational uncertainty due to these types of process issues is by monitoring the comparison of the two measurements. Most ultrasonic meters due to the robustness of the diagnostic data have Ethernet connectivity, and some can do their own internal inter-meter comparisons that can be easily extracted discretely without external flow computer or SCADA programming.

An Ideal Combination

Several manufacturers of ultrasonic meters have also released new models with more paths; many now offer an 8-path gas ultrasonic meter.  The availability of these higher accuracy meters negates many of the previous restrictions of using ultrasonic flow meters, it allows operators to reduce upstream piping lengths and eliminates flow conditioners as they are less sensitive to flow profile changes.

8-paths provide a more robust measurement that is not as affected by process disturbances upstream piping, tees, piping intrusions, blockages, etc. and they improve measurement availability as they can maintain their high accuracy even without all paths, making maintenance less critical. 

Additionally, this makes putting two ultrasonic meters in series even more economical while increasing measurement assurance.  Emerson’s recent OIML R-137 Accuracy Class 0.5 classification results demonstrate that the 8-path meter can maintain the highest accuracy class in both mild and severe disturbances without conventional upstream piping lengths and without flow conditioning (Figure 6). 

Figure collection 6.

Traditional process diagnostics have low correlations to measurement error even with very high degrees of swirl. Even if the diagnostics in the field differ from the calibration, this meter will maintain its calibrated accuracy level. 

Combining this highly robust measurement with one that can mitigate common error provides the solution with the lowest operational uncertainty possible with today’s technology. Emerson’s ideal combination is the Daniel 3418 combined with the Daniel 3416 for maximum accuracy, repeatability, reliability and process intelligence (Figure 7).

Figure 7.

With a Rapidly Changing Technological Environment, what is Next?

As the technology has rapidly developed over the last ten years, ultrasonic has been the fastest growing flow metering technology. They were traditionally applied in gas transmission and widely accepted in clean, dry gas environments. Now, they are now accepted at the well head, in wet gas, in corrosive gas environments. 

Ultrasonic meters are also supplied in biogas, coal bed methane, high C02 and many liquid applications including LNG. 

There are fewer restrictions for use and a much wider operating envelope than ever before. Additionally, ultrasonic manufacturers have developed condition-based monitoring systems with machine learning and are exploring use of artificial intelligence to improve online verification tools and to eliminate diagnostic interpretation. 

More operators are investing in IOT infrastructure and with more secured networks are open to the possibility of moving diagnostic data to the cloud. 

Users recognize the potential to do more with the data to manage processes, system uncertainty and advance predictive maintenance for additional operation savings. With all the new improvements and changes in the oil and gas industry, we can confidently state today's technology has opened the door to moving away from calendar-based maintenance or re-calibration to condition or risk-based maintenance or re-calibration without a high risk for common mode effects.

Question remains whether operators will believe we have arrived at a mature solution for managing operational uncertainty will a new horizon emerge for mitigating or even quantifying risk? 

Either way, ultrasonic metering solutions are progressing such that they are unparalleled in robustness and intelligence and may also soon exceed the long-term repeatability of turbine meters.  

Interested in this topic? Sign up to receive news and articles about gas flow calibration or read more about calibration here.