Custody transfer

Custody Transfer in the oil and gas industry refers to the transactions involving transporting physical substance from one operator to another. This includes the transferring of raw and refined petroleum between tanks and tankers; tankers and ships and other transactions. Custody transfer in fluid measurement is defined as a metering point (location) where the fluid is being measured for sale from one party to another. During custody transfer, accuracy is of great importance to both the company delivering the material and the eventual recipient, when transferring a material.

The term "fiscal metering" is often interchanged with custody transfer, and refers to metering that is a point of a commercial transaction such as when a change in ownership takes place. Custody transfer takes place any time fluids are passed from the possession of one party to another.

Custody transfer generally involves:

• Industry standards;
• National metrology standards;
• Contractual agreements between custody transfer parties; and
• Government regulation and taxation.

Due to the high level of accuracy required during custody transfer applications, the flowmeters which are used to perform this are subject to approval by an organization such as the American Petroleum Institute (API). Custody transfer operations can occur at a number of points along the way; these may include operations, transactions or transferring of oil from an oil production platform to a ship, barge, railcar, truck and also to the final destination point, such as a refinery.

Metering methods

Custody transfer is one of the most important applications for flow measurement. Many flow measurement technologies are used for custody transfer applications; these include differential pressure (DP) flowmeters, turbine flowmeters, positive displacement flowmeters, Coriolis flowmeters and ultrasonic flowmeters.

Differential pressure flowmeters

Differential pressure (DP) flowmeters are used for the custody transfer of liquid and gas to measure the flow of liquid, gas, and steam. The DP flowmeter consist of a differential pressure transmitter and a primary element. The primary element places a constriction in a flow stream, while the DP transmitter measures the difference in pressure upstream and downstream of the constriction.

In many cases, pressure transmitters and primary elements are bought by the end-users from different suppliers. However, several vendors have integrated the pressure transmitter with the primary element to form a complete flowmeter. The advantage of this is that they can be calibrated with the primary element and DP transmitter already in place.

Standards and criteria for the use of DP flowmeters for custody transfer applications are specified by the American Gas Association (AGA) and the American Petroleum Institute (API).

An advantage of using a DP flowmeters is that they are the most studied and best understood type of flowmeter. A disadvantage of using a DP flowmeters is that they introduce a pressure drop into the flowmeter line. This is a necessary result of the constriction in the line that is required to make the DP flow measurement.

One important development in the use of DP flowmeters for custody transfer applications has been the development of single and dual chamber orifice fittings.

Turbine flowmeters

The first turbine flowmeter was invented by Reinhard Woltman, a German engineer in 1790. Turbine flowmeters consist of a rotor with propeller-like blades that spins as water or some other fluid passes over it. The rotor spins in proportion to flow rate (see turbine meters) . There are many types of turbine meters, but many of those used for gas flow are called axial meters.

The turbine flowmeter is most useful when measuring clean, steady, high-speed flow of low-viscosity fluids. In comparison to other flowmeters, the turbine flowmeter has a significant cost advantage over ultrasonic flowmeters, especially in the larger line sizes, and it also has a favourable price compared to the prices of DP flowmeters, especially in cases where one turbine meter can replace several DP meters.

The disadvantage of turbine flowmeters is that they have moving parts that are subject to wear. To prevent wear and inaccuracy, durable materials are used, including ceramic ball bearings.

Positive displacement flowmeters

Positive displacement (PD) flowmeters are highly accurate meters that are widely used for custody transfer of commercial and industrial water, as well as for custody transfer of many other liquids. PD flowmeters have the advantage that they have been approved by a number of regulatory bodies for this purpose, and they have not yet been displaced by other applications.

PD meters excel at measuring low flows, and also at measuring highly viscous flows, because PD meters captures the flow in a container of known volume. Speed of flow doesn’t matter when using a PD meter.

Coriolis flowmeters

Coriolis flowmeters have been around for more than 30 years and are preferred in process industries such as chemical and food and beverage. Coriolis technology offers accuracy and reliability in measuring material flow, and is often hailed as among the best flow measurement technologies due to direct mass flow, fluid density, temperature, and precise calculated volume flow rates. Coriolis meters do not have any moving parts and provide long term stability, repeatability, and reliability. Because they are direct mass flow measurement devices, Coriolis meters can handle the widest range of fluids from gases to heavy liquids and are not impacted by viscosity or density changes that often effect velocity based technologies (PD, Turbine, Ultrasonic). With the widest flow range capability of any flow technology, Coriolis can be sized for low pressure drop. This combined with the fact that they are not flow profile dependent helps eliminate the need for straight runs and flow conditioning which enables custody transfer systems to be designed with minimal pressure drop.

It has to be mentioned that any measurement instrument that relies on one measurement principle only will show a higher measurement uncertainty under two-phase flow conditions. Conventional measurement principles, like positive displacement, turbine meters, orifice plates will seemingly continue to measure, but will not be able to inform the user about the occurrence of two-phase flow. Yet modern principles based on the Coriolis effect or ultrasonic flow measurement will inform the user by means of diagnostic functions.

Flow is measured using Coriolis meters by analyzing the changes in the Coriolis force of a flowing substance. The force is generated in a mass moving within a rotating frame of reference. An angular, outward acceleration, which is factored with linear velocity is produced due to the rotation. With a fluid mass, the Coriolis force is proportional to the mass flow rate of that fluid.

A Coriolis meter has two main components: an oscillating flow tube equipped with sensors and drivers, and an electronic transmitter that controls the oscillations, analyzes the results, and transmits the information. The Coriolis principle for flow measurement requires the oscillating section of a rotating pipe to be exploited. Oscillation produces the Coriolis force, which traditionally is sensed and analyzed to determine the rate of flow. Modern coriolis meters utilize the phase difference measured at each end of the oscillating pipe.

Ultrasonic flowmeters

Ultrasonic flowmeters were first introduced into industrial markets in 1963 by Tokyo Keiki (now Tokimec) in Japan. Custody transfer measurements have been around for a long time, and over the past ten years, Coriolis and ultrasonic meters have become the flowmeters of choice for custody transfer in the oil and gas industry.

Ultrasonic meters provide volumetric flow rate. They typically use the transit-time method, where sounds waves transmitted in the direction of fluid flow travel faster than those travelling upstream. The transit time difference is proportional to fluid velocity. Ultrasonic flow meters have negligible pressure drop if recommended installation is followed, have high turndown capability, and can handle a wide range of applications. Crude oil production, transportation, and processing are typical applications for this technology.

The use of ultrasonic flowmeters is continuing to grow for custody transfer. Unlike PD and turbine meters, ultrasonic flowmeters do not have moving parts. Pressure drop is much reduced with an ultrasonic meter when compared to PD, turbine, and DP meters. Installation of ultrasonic meters is relatively straightforward, and maintenance requirements are low.

In June 1998, The American Gas Association published a standard called AGA-9. This standard lays out the criteria for the use of Ultrasonic flowmeters for Custody Transfer of Natural Gas.

Components

Custody transfer requires an entire metering system that is designed and engineered for the application, not just flowmeters. Components of a custody transfer system typically include:

• Multiple meters/meter runs;
• Flow computers;
• Quality systems (gas chromatographs to measure energy content of natural gas and sampling systems for liquid);
• Calibration using in-place or mobile provers for liquid, or master-meter for liquid or gas; and
• Supporting automation.

A typical liquid custody transfer skid includes multiple flowmeters and meter provers. Provers are used to calibrate meters in-situ and are performed frequently; typically before, during, and after a batch transfer for metering assurance. A good example of this is a Lease Automatic Custody Transfer(LACT) unit in a crude oil production facility.

Accuracy

In the ISO 5725-1 standard accuracy for measuring instruments is defined as “the closeness of agreement between a test result and the accepted reference value”. This term “accuracy” includes both the systematic error and the bias component. Each device has its manufacturer stated accuracy specification and its tested accuracy. Uncertainty takes all the metering system factors that impact measurement accuracy into account. The accuracy of flowmeters could be used in two different metering systems that ultimately have different calculated uncertainties due to other factors in the system that affect flow calculations. Uncertainty even includes such factors as the flow computer's A/D converter accuracy. The quest for accuracy in a custody transfer system requires meticulous attention to detail.

Custody transfer requirements

Custody transfer metering systems must meet requirements set by industry bodies such as AGA, API, or ISO, and national metrology standards such as OIML (International), NIST (U.S.), PTB (Germany), CMC (China), and GOST (Russia), among others. These requirements can be of two types: Legal and Contract.

Legal

The national Weights & Measures codes and regulations control the wholesale and retail trade requirements to facilitate fair trade. The regulations and accuracy requirements vary widely between countries and commodities, but they all have one common characteristic - “traceability”. There is always a procedure that defines the validation process where the duty meter is compared to a standard that is traceable to the legal metrology agency of the respective region.

Contract

A contract is a written agreement between buyers and sellers that defines the measurement requirements. These are large-volume sales between operating companies where refined products and crude oils are transported by marine, pipeline or rail. Custody transfer measurement must be at the highest level of accuracy possible because a small error in measurement can amount to a large financial difference. Due to these critical natures of measurements, petroleum companies around the world have developed and adopted standards to meet the industry's needs.

In Canada, for instance, all measurement of a custody transfer nature falls under the purview of Measurement Canada. In the USA, the Federal Energy Regulatory Commission (FERC) controls the standards which must be met for interstate trade.

Liquid custody transfer

Custody transfer of liquid flow measurement follow guidelines set by the ISO. By industrial consensus, liquid flow measurement is defined as having an overall uncertainty of ±0.25% or better. The overall uncertainty is derived from an appropriate statistical combination of the component uncertainties in the measurement system.

Mode of measurement

Volume or mass measurement

Liquid flow measurements are usually in volumetric or mass unit. Volume is normally used for stand-alone field tanker loading operations, while mass is used for multi-field pipeline or offshore pipeline with an allocation requirement.

Mass measurement and reporting are achieved by

• Measurement of volume flow rate (for example, by turbine or ultrasonic meter) and fluid density
• Direct mass measurement by Coriolis meter

Sampling system

An automatic flow-proportional sampling system is used in flow measurement to determine the average water content, average density and for analysis purposes. Sampling systems should be broadly in accordance with ISO 3171. The sampling system is a critical section during flow measurement. Any errors introduced through sampling error will generally have a direct, linear effect on the overall measurement.

Temperature and pressure measurement

Temperature and pressure measurement are important factors to consider when taking flow measurements of liquids. Temperature and pressure measurement points should be situated as close to the meter as possible, in reference to their conditions at the meter inlet. Temperature measurements that affect the accuracy of the metering system should have an overall loop accuracy of 0.5°C or better, and the corresponding readout should have a resolution of 0.2°C or better.

Temperature checks are performed by certified thermometers with the aid of Thermowells

Pressure measurements that affect the accuracy of the metering system should have an overall loop accuracy of 0.5 bar or better and the corresponding readout should have a resolution of 0.1 bar or better.

Gaseous custody transfer

Custody transfer of gaseous flow measurement follow guidelines set by the international bodies. By industrial consensus, gaseous flow measurement is defined as mass flow measurement with an overall uncertainty of ±1.0% or better. The overall uncertainty is derived from an appropriate statistical combination of the component uncertainties in the measurement system.

Mode of measurement

Volume or mass unit

All gaseous flow measurement must be made on single-phase gas streams, having measurements in either volumetric or mass units.

Sampling

Sampling is an important aspect, as they help to ascertain accuracy. Apt facilities should be provided for the purpose of obtaining representative samples. The type of instrumentation and the measuring system may influence this requirement.

Gas density

Gas density at the meter may be determined either by:

• Continuous direct measurement, by on-line densitometer
• Calculation, using a recognised equation of state together with measurements of the gas temperature, pressure and composition.

Most industries prefer to use the continuous measurement of gas density. However, both methods may be used simultaneously, and the comparison of their respective results may provide additional confidence in the accuracy of each method.

Best practices

In any custody transfer application, a true random uncertainty has an equal chance of favouring either party, the net impact should be zero to both parties, and measurement accuracy and repeatability should not be valued. Measurement accuracy and repeatability are of high value to most seller because many users install check meters. The first step in designing any custody transfer system is to determine the mutual measurement performance expectations of the supplier and the user over the range of flow rates. This determination of mutual performance expectations should be made by individuals who have a clear understanding of all of the costs of measurement disputes caused by poor repeatability. The second step is to quantify the operating conditions which are not controllable. For a flow measurement, these can include:

• Expected ambient temperature variation;
• Maximum static line pressure;
• Static line pressure and temperature variation;
• Maximum allowable permanent pressure loss;
• Flow turndown; and
• Expected frequency of flow variation and/or pulsation.

The third and final step is to select hardware, installation and maintenance procedures which will ensure that the measurement provides the required installed performance under the expected (uncontrollable) operating conditions. For example, the user can:

• Select a static and/or differential pressure transmitter which has better or worse performance under the given real-world operating conditions.
• Calibrate the transmitter(s) frequently or infrequently.
• In the case of a DP flowmeter, size the primary element for a higher or lower differential pressure (higher DP's provide higher accuracy, at the expense of higher pressure loss).
• Select a flowmeter and pressure transmitter with faster or slower response.
• Use long or short interconnection (impulse) lines, or direct connect for fastest response.

While the first and second steps involve gathering data, the third step may require calculations and/or testing.

General formula for calculating energy transferred (LNG)

The formula for calculating the LNG transferred depends on the contractual sales conditions. These can relate to three types of sale contract as defined by Incoterms 2000: an FOB sale, a CIF sale or a DES sale.

In the case of an FOB (Free On Board) sale, the determination of the energy transferred and invoiced for will be made in the loading port.

In the case of a CIF (Cost Insurance & Freight) or a DES (Delivered Ex Ship) sale, the energy transferred and invoiced for will be determined in the unloading port.

In FOB contracts, the buyer is responsible to provide and maintain the custody transfer measurement systems on board the vessel for volume, temperature and pressure determination and the seller is responsible to provide and maintain the custody transfer measurement systems at the loading terminal such as the sampling and gas analysis. For CIF and DES contracts the responsibility is reversed.

Both buyer and seller have the right to verify the accuracy of each system that is provided, maintained and operated by the other party. The determination of the transferred energy usually happens in the presence of one or more surveyors, the ship’s cargo officer and a representative of the LNG terminal operator. A representative of the buyer can also be present.

In all cases, the transferred energy can be calculated with the following formula:

E =(VLNG × DLNG × GVCLNG) - Egas displaced ± Egas to ER (if applicable)

Where:

E = the total net energy transferred from the loading facilities to the LNG carrier, or from the LNG carrier to the unloading facilities.

VLNG= the volume of LNG loaded or unloaded in m3.

DLNG = the density of LNG loaded or unloaded in kg/m3.

GCVLNG = the gross calorific value of the LNG loaded or unloaded in MMBTU/kg

E gas displaced = The net energy of the displaced gas, also in MMBTU, which is either: sent back onshore by the LNG carrier when loading (volume of gas in cargo tanks displaced by same volume of loaded LNG), Or, gas received by the LNG carrier in its cargo tanks when unloading in replacement of the volume of discharged LNG.

E(gas to ER) = If applicable, the energy of the gas consumed in the LNG carrier’s engine room during the time between opening and closing custody transfer surveys, i.e. used by the vessel at the port, which is:

+ For an LNG loading transfer or

- For an LNG unloading transfer

External links

• Measurement Canada.
• CMC
• Tokyo KEIKI
• API
• Flow Research
• GUIDANCE NOTES FOR PETROLEUM MEASUREMENT (Highly recommended)
• ISO