Custody transfer in the oil and gas industry refers to the transactions involving the handover of a physical substance from one operator to another. This includes the transferring of raw and refined petroleum between tanks and railway tank cars; onto 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. The use of the phrase "fiscal metering" does not necessary imply any single expectation of the quality of the instrumentation to be installed. "Fiscal" refers to the meter's service, not its quality. "Fiscal" usually means ‘concerned with government finance’.
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.
To complete standards and/or agreements and achieve maximum accuracy all parties included in fuel distribution processes (sellers and buyers, transport & storage services, fiscal departments) must follow the custody transfer procedures, appropriate measurements and related documenting operations must be fully implemented. Custody transfer measurements involve measurements in pipelines, storage tanks, transportation tanks (tankers, trailers or railway tanks) - whole fuel distribution process must be traceable. In order measurements can be made in a volume or mass units (or both), so various metering methods are commonly used.Zivenko, O. and Gudyma, I., 2017. Accuracy Improvement of an LPG Inventory System. In Proc. XXIII Technical Scientific Conference EKO Varna Proceedings “Transport, ecology–sustainable development (pp. 15-17).
Current volume of a product stored in a tank can be calculated using a tank capacity table (sometimes called "tank calibration table") and current levels and temperatures of a product in a tank. Tank capacity table stores data about level and appropriate volume in a tank and have a very high impact on overall accuracy of volume calculation. Typical accuracy of a capacity tables for custody transfer operations is 0.05..0.1%. Initial installation of a tank, its accuracy and lifecycle changes (like inclination or sediments) affect the accuracy of the capacity table so they must be revised periodically. Some capacity tables are multidimensional and store additional data - like heel and trim for ships tanks density of stored products and/or are used in systems for automated volume/mass calculations.
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 determine flow rate from the pressure difference produced by a primary flow element installed in the pipeline. They are used for measuring liquids, gases and steam, including applications involving custody transfer.
A typical DP flow measurement system consists of a primary element, such as an orifice plate, Venturi tube or flow nozzle, together with a differential pressure transmitter. The primary element creates a controlled change in the flow velocity and pressure. The transmitter measures the differential pressure between pressure taps located upstream and downstream of the primary element. Under defined flow conditions, the differential pressure can be related to the flow rate.
For an idealized incompressible flow, the relationship between differential pressure and flow rate is approximately proportional to the square of the flow rate. Consequently, the flow rate is commonly calculated from the measured differential pressure together with parameters such as fluid density, pressure, temperature, and the geometry of the primary element.
DP flowmeters require the primary element and associated pressure-measurement system to be selected and installed according to the applicable design and measurement requirements. The performance of the complete system can be affected by factors including pipe geometry, upstream flow disturbances, pressure-tap configuration, fluid properties, impulse-line conditions and transmitter accuracy.
For custody-transfer applications, differential-pressure flow measurement is covered by industry standards and recommended practices, including ISO 5167 for differential-pressure devices and relevant documents published by the American Petroleum Institute (API) and American Gas Association (AGA), depending on the fluid and application.
A principal advantage of DP flowmeters is the extensive body of engineering data, standards and operating experience associated with differential-pressure measurement. Orifice plates and other primary elements can also be relatively simple to inspect, replace and characterize.
A limitation is the permanent pressure loss introduced by the primary element. The magnitude of this loss depends on the type and geometry of the element and the operating conditions. This pressure loss can increase the energy required to transport the fluid through the system.
For gas and liquid measurement, DP systems may be combined with pressure and temperature measurements and fluid-property calculations to determine flow at specified reference conditions. In natural-gas applications, flow computers may also perform the required compensation and calculation functions.
Orifice fittings are commonly used where an orifice plate must be removed or inspected without major disassembly of the pipeline. Single-chamber and dual-chamber designs allow the plate to be accessed while reducing the amount of pipeline disassembly required, subject to the design and operating procedure of the installation.
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 considered 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 affect 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.
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. 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 measure fluid velocity using ultrasonic acoustic signals and can be used to determine volumetric flow rate. Several measurement principles are used, including transit-time and Doppler methods. Transit-time meters determine fluid velocity from the difference in the time taken by acoustic pulses to travel upstream and downstream through the flowing fluid. Multipath designs use several acoustic paths to obtain velocity information at different locations across the pipe.
Ultrasonic flowmeters are available as inline and clamp-on instruments. Inline transit-time meters are installed in the pipeline, while clamp-on meters mount transducers on the outside of the pipe and can measure flow without cutting into the process line. The suitability of a particular ultrasonic meter depends on factors including fluid properties, pipe geometry, flow profile, acoustic conditions and the required measurement uncertainty.