Custody Transfer Flowmeters – An Evolution in Technology

Custody Transfer (also know as Fiscal Metering) in the oil & gas industry refers to the transactional transfer of a substance, raw or refined, from one party (owner) to another.

Typically when custody transfer is taking place, the end goal is to determine the value or payment between two parties for the physical substance (gas or liquid) that has exchanged hands via pipeline. For that reason, the flow instrument that measures the total amount of product changing ownership can be viewed as a cash register between the two parties.

Flow measurements in typical process applications are focused around a repeatable value vs. direct accuracy of measurement. Meaning engineers and operators are OK with some level of inaccuracy as long as it is constant and repeatable. Because of the monetary value that changes hands in custody transfer, there can be significant fiscal risk if a measurement has even the smallest of errors.

The level of risk involved in custody transfer applications has led to the regulation of fiscal metering in the oil and gas industry by using standards developed by organizations such as; NIST, API, AGA, etc. As well as others outside of the United States.

While the number of flow meter technologies used in process control today continues to grow, not all are suitable or industry accepted for custody transfer. Here we look at 5 technologies that the petroleum industry has deemed suitable in fiscal metering applications.

Differential Pressure (orifice plates, Venturi tube, pitot tubes)

Steam - The Energy Fluid


  • As early as the 1920s, American Gas Association began studying custody transfer using Differential Pressure (DP) with orifice plates. DP measurements have been long used in process control, leading to an industry wide understanding of how they work and the maintenance required to ensure they are properly functioning. However, they do require regular maintenance and do not provide a wide measurement range for applications with large variance in flow rate. In addition they do not typically provide the accuracy that is required for liquid custody transfer the petroleum industry.


Turbine Meter

  • 1981 the AGA, Transmission Measurement Committee, published Report #7 outlining the use of turbine meter technology in gas applications. This began an industry trend of transitioning to turbine meters for fiscal metering of gases, displacing many of the DP installations. Turbine meters were able to achieve equal or greater accuracy while measuring a wider range of flow rates as well as performing well in liquid applications where orifices may not have had flexibility.


Positive Displacement

  • While the AGA is geared toward gas products, API tends to focus more on petroleum liquids. 1987 brought about the API publishing, MPMS 5.2; a report outlining the use of displacement flow meters in liquid hydrocarbon applications. PD meters are a great solution when used in small line sizes, and low flow rate applications. But similar to DP measurements they do create pressure drop, and because they are a mechanical technology, the moving part require regular maintenance.



  • Flow meters using the Coriolis effect measurement principle were developed as far back as the 1970s, however it was not until 2002 that the API published their acceptance of use in custody transfer applications (API, MPMS 5.6) . Today, Coriolis is a preferred technology for high accuracy flow applications because of the ability to accurately measure both liquids and gases in a large range of line sizes (<1″ to >12″), the lack of moving parts, as well as the ability to make a direct mass flow measurement.



  • Seen as one of the newer technologies in fiscal metering, AGA published Report #9 in 1998 outlining the use of multi-path ultrasonic flow meters in measurement of natural gas in pipelines. Ultrasonic flow meters function on transit time measurement using ultrasound, providing a velocity of a fluid being transferred. With high accuracy, high turndown ratio, and zero moving parts; they are ideal for natural gas lines ranging from 2″ to 40″ and larger. There is little to no pressure drop when using ultrasonic flow meters, which can improve the efficiency of pump stations used when transferring both liquid and gas products down pipelines.

Through development and testing, the petroleum industry has grown to accept a variety of technologies to be adequate for high the expectations of a custody transfer measurement. All these technologies have advantages along with their limitations, and each have their niche in the industry.  And while we hope you found the information in this post informative, it is also important to understand that the full scope of proper custody transfer system requires much more than simply installing a high accuracy flow meter, a complete metering system would also need to include; flow computers, provers, sample analysis, etc…and we will look at explaining more about each of these components in future nugget posts.

A Pump Control Solution for Sump Overflow Protection

Pump control in sump applications is an important task in refining and chemical process plants. Although important, many of these pumping systems are not managed by the plant’s central control system and in most cases, there is little or no method in place for monitoring liquid level within the sump or the performance of the pumping system. The right control technology and implementation on sump applications has many positive economic outcomes such as overflow risk reduction, lower energy use and longer equipment life.

Sumps are part of a plant drainage system intended to collect fluids from process drains, oily water drains, fire water run-off and rain water drainage so that all the run off is controlled and treated appropriately so that environmental risk is eliminated.


Floats, bubblers, ultrasonic, and capacitive probes are common forms of level measurement for sump pump control, yet these technologies have proven maintenance intensive due to failures resulting from buildup, plugging, and foaming. Additionally, viscosity, process condition, and product variance can also cause inaccurate level measurements with these types of technologies.

The result of unreliable level measurement and pump control can be pump “Dry Run” condition or worse yet a sump overflow and possibly an  EPA reportable event. “Dry Run” conditions create costly problems such as excessive wear on a pumps bearings, seals and impeller. The best case scenario of “Dry Run” is early maintenance to repair or replace worn components. The need for complete replacement of the pump is also a possibility. One user noted a pump replacement cost of $80,000.00. An additional risk of an undetected “Dry Run” is pump failure when the pump is most critical and a sump overflow incident results.

So how do we solve this problem? Is there a better way to monitor liquid levels within the sump and protect the equipment?

One solution is an advanced pump control system that includes a pump control panel with a SIL qualified signal conditioning instrument for pump control and system performance monitoring and is integrated with SIL 2 microwave radar for continuous level detection and SIL 2 point level detection switch. Both transmitters can be mounted on one common flange, as small as 4″.


The pump control system should be customizable to meet specific application needs and the existing electrical system.

This type of packaged system can be specified and purchased for delivery pre-wired and ready for installation so that minimal field wiring is required. The simplified installation greatly reduces the field labor costs.

System components might include:

  • Continuous level measurement and/or point level safety switches
  • A Signal Conditioning Instrument with appropriate hazardous area ratings
  • Pressure sensors
  • Enclosure per application requirements
  • Selector switches, indicators, etc… as desired
  • All Electrical and dimensional drawings for approval & documentation


Major benefits of this type of control system are:

  • Over-fill protection according to SIL 2
  • Dry Run protection according to SIL 2
  • FM Approvals for C1, D2 hazardous Areas
  • Lead-Lag pump switching to extend pump life
  • Reduced risk of an environmental incident
  • Increased life expectancy of rotating equipment via pump monitoring

Goat Nuggets thinks this is a pretty good solution for ensuring reliable sump control performance, yet we would love to hear from you in the comments section as to what others may be implementing?



Non-Contact Radar; A Brief Focus On Frequency

Radar level transmitters are often referred to as “non-contact” radar because the antenna or “horn” does not come into contact with the product or process being measured. This is in contrast to Guide Wave Radar (GWR) which requires contact with the product being measured.

Radar (Non-Contact)
Guided Wave Radar








The measurement principle of radar is; Time-of-Flight (ToF) using microwave energy. Extremely short microwave pulses at a given wave length are transmitted by the antenna system to the measured product. The pulses are reflected by the product surface and received back by the antenna system. The time from transmission to reception of the signals is proportional to the distance or product level in the vessel (ToF). A special time stretching procedure ensures reliable and precise measurement of the extremely short transmission periods and the conversion into a level measurement.

The typical radar sensor operates with low emitted power in the C, K ,or W band frequency ranges, each of which offer high reliability and tight accuracy in their respective applications:

Low frequency C band sensors (~6GHz) are typically used for continuous level measurement of liquids under difficult process conditions. They are suitable for applications in storage tanks, process vessels or standpipe. C band radars perform well in process vessels where build-up, foaming, or strong agitation is present. The C band frequency can have difficulties when measuring short ranges or when nozzle space limited due to the larger antenna systems they require.

Mid frequency K band sensors (~26GHz) are suitable for continuous level measurement of almost all liquids. They are likely the most common used radar frequency and are suitable for storage containers, reactors and process vessels, even under difficult process conditions. With the a large variety of antenna systems and materials, K band are a common solution for almost all typical applications and processes. The exception being where heavy vapors or dense foams are to be expected.

High frequency W band sensors (~80GHz) are suitable for continuous level measurement of liquids and bulk solids, in addition they can have particular advantages where K & C band radars have historically struggled. Small process fittings available with the W band sensors offer flexibility in small vessels or tight mounting spaces. The increased signal focus can increase the reliability in narrow silo or vessels with stirrers, agitators, baffles, heating spirals, etc. and avoid the common false signals from obstruction. The W band is also successful in measuring very low dielectric liquids such as liquified natural gases.

Over the past 3-4 decades, radar has emerged as one of the preferred level technologies in the process control industry. While every level application has specific details that require thought and consideration; the development and optimization of these 3 frequency ranges has made an ever-increasing number of applications solvable (and more importantly reliable) with non-contacting technology.