Factors that should be considered in the selection of meter type, size and quantity include: Accuracy
· — meters are designed to operate within a specified accuracy or lin- earity range
Fluid properties including viscosity, density and contaminants ·
Pressure losses through meter and piping ·
Dimensional requirements for meter and necessary flow conditioning piping ·
Back pressure requirements ·
The most important operating conditions that affect the accuracy of liquid mea- surement are flow range and viscosity range [14, 15].
Flow Range — is the minimum/maximum flow rate at which a meter/measure- ment system can operate within the stated accuracy. Custody transfer meters are nor-
mally specified to operate over a 10:1 (10% to 100% of maximum flow) flow range with a linearity of +/–0.15%. The measurement accuracy can be improved by reducing the range of flows or establishing a separate meter factor for each flow rate. Today’s flow computers allow multiple meter factors to be input and automatically linearize the meter factor over the flow range.
Viscosity Range — can vary for petroleum liquids from less than 0.1 cP for LPG to over 1000 cP for heavy oils. All meters are sensitive to viscosity (with the exception of Coriolis meters) but each metering technology is affected differently. Because of slippage through internal clearances, PD meters are affected by low viscosity liquids whereas turbine and ultrasonic meters are sensitive to high viscosity crude oils.
With current meter proving methodology, the total uncertainty (UT) of a liquid custody transfer measurement can be in the range of UT = +/–0.1% at a 95% confidence level. This is industry norm for most large volume liquid transactions.
For optimum performance, the selected meters must be capable of covering a wide flow range over which the meter maintains a linear pulse output with respect to flow rate; typically 0.25% for a 10:1 flow range or turndown ratio. Meters with this capabil- ity include turbine meters, positive displacement (PD) meters, ultrasonic meters and Coriolis meters. Turbine and ultrasonic meters offer the advantages of high flow capac- ity and reduced weight, space and maintenance. Turbine and ultrasonic meters require flow conditioning piping upstream and downstream of the meter to prevent fluid swirl and non-uniform velocity profiles. Flow straightening tube bundles or conditioning plates reduce the amount of upstream piping required for flow conditioning. PD meters and Coriolis meters do not require upstream or downstream flow conditioning.
Positive displacement meters and turbine meters are the most commonly used meters in custody transfer applications. However, ultrasonic and Coriolis meters have been making inroads as they have definite advantages in some applications.
Turbine meters are preferred for high flow rates and low viscosity applications. Turbine meters are susceptible to deposition of wax in certain crude oils. However, a limited amount of fine abrasives have less effect on the life and performance of a turbine meter because solids in suspension continue to flow uninterrupted through the meter. Positive displacement meters are more affected by fine abrasives because of the close tolerances of the moving parts.
Ultrasonic meters have the advantage of low pressure losses and capability of handling corrosive liquids or liquids with contaminants.
Coriolis meters have relatively high pressure losses through the tubing assemblies and can be susceptible to deposition of certain products such as wax.
Positive displacement and Coriolis meters are only slightly affected by installation conditions whereas velocity meters such as turbine and ultrasonic meters can be highly affected. Turbine and ultrasonic meters require flow conditioning piping assemblies.
7.4.5.1 Meter Sizing
Meters should have capacity to handle the minimum and maximum expected flow rate for the meter run. PD meters are normally selected for continuous operation at about 75% of the manufacturer’s nameplate capacity if the liquid has reasonable lubricity. The capacity of PD meters is reduced to as low as 40% of nameplate capacity for liquids with poor lubricity. Turbine, ultrasonic, and Coriolis meters may be operated at full nameplate capacity with any liquid. However, pressure losses through the meter and piping at full rated capacity may be a factor in choosing the most appropriate meter size for the particular application.
7.4.5.2 Instrumentation and Accessories
Strainers and Filters — Strainers and filters should be designed to remove only solids that could damage a meter or create uncertainty of measurement. Meters can be pro- tected individually or as a bank. With turbine and ultrasonic meters, the strainer should be placed well ahead of the meter runs to prevent the problem of liquid swirl from
affecting meter performance. This is not an issue with PD or Coriolis meters. The strainer should be equipped with a pressure differential monitoring system to warn of accumulation of material in the strainer.
Sediment and Water (S&W) Determination — S&W determination procedure in- cluding the frequency of sampling must be representative of the entire volume trans- action as well as the subsequent S&W sample analysis. There are two methods to obtain the measurement; sampling or on-line analysis using a suitable product ana- lyzer. Sampling can be categorized by two methods; spot or grab sampling or continu- ous proportional sampling. It is important that the sample location be carefully selected such that the flowing stream is adequately mixed. Manual sampling procedures and equipment are addressed in ASTM D4057 (API MPMS Chapter 8.1) — Manual Sam- pling of Petroleum and Petroleum Products.
Most pipeline metering systems employ automatic sampling. Procedures are cov- ered in ASTM D4177 (API MPMS Chapter 8.2) — Automatic Sampling of Petroleum and Petroleum Products. An accurate analysis of any sample depends on the appropri- ate handling and mixing of that sample from its sourcing through to its analysis. Pro- cedures are covered in ASTM D5854 (API MPMS Chapter 8.3) — Practice for Mixing and Handling of Liquid Samples of Petroleum and Petroleum Products.
Back-pressure valves — a back-pressure valve should be installed downstream from the meter station if the line resistance downstream is insufficient to prevent va- porization at the meter assemblies under any flow conditions.
Flow control valves — Flow control valves may be placed on individual meter runs or act collectively for a number of meters. A flow control valve placed down- stream of the meter may also act as a back-pressure valve by the application of control logic to the valve actuator.
Electronic Flow Measurement (EFM) — An EFM is any flow measurement and related system that collects data and performs flow calculations electronically. This may be part of a Distributed Control System (DCS), supervisory control and data ac- quisition (SCADA) system, a Programmable Logic Control (PLC) system, or a spe- cialized flow computer.
The table below summarizes the meter sizes and applicable liquids for the selection of meters.
Flow meter Pipe size in (mm) Clean Viscous Dirty Corrosive
Turbine 0.25–24 (6–600) D/A N/A N/A A
PD < 12 (300) D/A D/A N/A A
Ultrasonic > 0.5 (12) D/A A N/A D/A
Coriolis 0.1–4 (2.5–100) D/A D/A D/A A
D/A: Designed for this application; A: Normally applicable; N/A: Not applicable. The table below summarizes the meter accuracy without smart transmitter and applicable maximum pressure, temperature, and Reynolds number [2]. The accuracy is over the upper range value of the flow rate.
Flow meter Accuracy (+/– %) Psig (kPag)Pressure, Temperature, °F (°C) Reynolds Number
Turbine 0.25 3,000 (21,000) –400 to 500
(–268 to 260)
<15 cSt
PD 0.5 3,000 (21,000) 600 (315) <8000 cSt
Ultrasonic 1.0 Pipe rating –300 to 500
(–180 to 260)
No limit
7.4.5.3 Flow Computers
Flow computers are widely used in the pipeline industry. Flow computers not only col- lect measured flow and other data, calculate volumes, correct flow rates to base condi- tions, and store all measured and calculated data, but also provide the flow information rapidly on a real-time basis.
The hardware structure of flow computers is similar to personal computers (PC). They should be rugged due to severe or even hazardous environments in which they operate. Flow computers are interfaced with flow meters and other measuring devices through their transducers and have programmable capabilities necessary for various applications. Also, they have the capabilities to upload the flow computer data to a host SCADA system and provide measurement data security by setting the security code and authorization. Unlike PCs, flow computers work in real-time and are dedicated to applications related to flow measurements.
Flow computers do not have flexible display capabilities. Their screens are small and a keypad is used to set up and view parameters. Typically, flow computers require the following displays, mostly menu-driven, to enter and access the necessary param- eters and data:
The flow computer configuration data such as unit ID, location, base pressure ·
and temperature, etc.
Meter specific parameters such as meter type, meter factor, etc. ·
Liquid product property parameters such as API gravity, volume correction · factor, etc. Communication parameters · Security · Calibration ·
Alarm parameters such as analog and digital input alarm, rate/volume alarm, ·
etc.
Diagnostic messages ·
In general, flow computers perform flow measurement and process calculations, monitor transducer inputs (both analog and digital inputs) in real-time, produce and store multiple measured and calculated output including reports, and can serve as a remote terminal unit (RTU).
Flow computers are able to provide all measurement related functions. They not only read and monitor all inputs of flow and/or volume, temperature, and pressure for most flow meters but also differential pressure from differential pressure meters and pulse input from turbine and positive displacement meters. Input also includes fluid properties such as liquid density and viscosity.
For custody transfer, flow computers need to be able to process the flow and other measurement data as specified in the standards appropriate to the measured fluids. They should be able to correct volumes to base conditions and totalize volumes from meter run totals and station totals for each product. Flow computers monitor and store batch operation data, which include batch ID, volume, and batch lifting and delivery times.
When a flow computer is used for proving meters, it not only controls the meter prover and calculates the meter factor during the proving time, but also uses the meter fac- tor and K-factor to determine accurate volume. The K-factor is the number of pulses per unit volume and the meter factor a correction applied multiplicatively to the K-factor.
Most flow computers are able to display limited outputs and produce various re- ports. The minimum required reports generated by a flow computer may include vol- ume totals and quality, batch, alarm, and audit trail reports. This information can be
directly accessed from the flow computer or uploaded to the host and accessed from the SCADA database.