In the oilfield flow sensing is performed by means of a few different methods depending on the requirements of accuracy, fluid type and other application details. Flow sensors can be of the turbine type where a small turbine spins in the flow and its rotation is measured by means of a sensor outside the flow line. Venturi type flowmeters are used when it is preferable to not have an interruption in the flow and works on the principal of pressure drop in a venturi. The drop in pressure is measured by a pressure sensor and can be converted to a flow rate. Another type of flow sensor is the ultrasonic flow sensor.
Turbine Flow Meters: These meters use a freely rotating turbine positioned in the fluid stream. As fluid flows through the meter, the turbine rotates at a speed proportional to the flow rate. A magnetic pickup or Hall effect sensor detects each blade passage, generating electrical pulses. The frequency of these pulses is directly proportional to volumetric flow rate. Turbine meters offer excellent accuracy (±0.25% to ±0.5% of reading) and wide turndown ratios of 10:1 to 20:1.
Positive Displacement Meters: These meters trap discrete volumes of fluid and count the number of volumes transferred. Common types include oval gear, nutating disc, and helical rotor designs. Positive displacement meters provide the highest accuracy (±0.1% to ±0.5%) and excellent low-flow performance, making them ideal for custody transfer and chemical injection applications.
Differential Pressure Flow Meters: Based on Bernoulli's principle, these meters measure flow by sensing pressure drop across a restriction. Common types include orifice plates, venturi tubes, and flow nozzles. The pressure difference is proportional to the square of flow velocity. While lower in accuracy (±1% to ±5%), they are highly reliable with no moving parts and can handle high-temperature, high-pressure applications.
Ultrasonic Flow Meters: These non-invasive meters use transit-time or Doppler shift methods to measure flow. Transit-time meters send ultrasonic pulses both upstream and downstream, measuring the time difference to calculate flow velocity. Doppler meters measure frequency shift of ultrasonic waves reflected by particles or bubbles in the flow. Ultrasonic meters offer wide rangeability (100:1) and can be clamped onto existing pipes without cutting or welding.
Magnetic Flow Meters: Operating on Faraday's law of electromagnetic induction, these meters generate a magnetic field perpendicular to fluid flow. Conductive fluids flowing through the field generate a voltage proportional to flow velocity. Magnetic meters provide high accuracy (±0.2% to ±0.5%), no pressure drop, and excellent reliability for conductive fluids like saltwater and drilling mud.
Coriolis Mass Flow Meters: These meters measure mass flow directly by detecting the Coriolis forces generated as fluid flows through vibrating tubes. Coriolis meters provide simultaneous measurement of mass flow, density, and temperature with exceptional accuracy (±0.1% to ±0.2%). They are ideal for custody transfer and critical process control applications.
Flow Range: Oilfield flow meters are available from 0.1 GPM for chemical injection systems to over 10,000 GPM for main treating lines. Common ranges include 50-500 BPM (barrels per minute) for fracturing and cementing operations.
Accuracy: Turbine meters: ±0.25% to ±0.5% of reading; Magnetic meters: ±0.2% to ±0.5% of rate; Coriolis meters: ±0.1% to ±0.2% of rate; Ultrasonic meters: ±0.5% to ±2% of rate; Differential pressure meters: ±1% to ±5% of full scale.
Pressure and Temperature Ratings: Meters must be rated for service conditions. Common ratings include 2,000 PSI to 15,000 PSI working pressure and -40°F to +250°F operating temperature. Special high-pressure meters can handle up to 20,000 PSI for wellhead applications.
Output Signals: Pulse outputs (typically 1-10,000 pulses per barrel), 4-20 mA analog output proportional to flow rate, frequency output (0-10 kHz), and digital protocols including Modbus RTU, HART, and Foundation Fieldbus.
Fracturing Operations: Flow meters on treating manifolds measure total slurry rate and individual pump rates. Real-time flow monitoring ensures accurate proppant concentration, detects equipment failures, and verifies job design execution. Return flow measurement helps calculate fluid efficiency and formation fluid production.
Cementing Services: Precise flow measurement during cement jobs ensures proper displacement rates and volumes. Flow meters track lead cement, tail cement, and spacer volumes to verify complete wellbore coverage and proper cement placement.
Chemical Injection: Small positive displacement or Coriolis meters provide accurate measurement of corrosion inhibitors, scale inhibitors, and friction reducers. Precise metering ensures proper treatment while minimizing chemical costs and environmental impact.
Production Monitoring: Well test separators use flow meters to measure oil, gas, and water production rates. Multi-phase flow meters can measure individual phase rates without separation, reducing equipment costs and providing continuous well monitoring.
Water Flooding and Injection: Flow meters on water injection wells ensure proper injection rates to maintain reservoir pressure. Accurate flow measurement is critical for regulatory compliance and optimizing secondary recovery operations.
Piping Requirements: Install flow meters with proper upstream and downstream straight pipe runs to ensure fully developed flow profiles. Typical requirements are 10-20 pipe diameters upstream and 5-10 diameters downstream of the meter. Use flow conditioners if adequate straight pipe cannot be provided.
Orientation and Mounting: Install meters according to manufacturer specifications. Liquid meters should generally be mounted horizontally or vertically with upward flow to prevent gas accumulation. Gas meters can be mounted in any orientation. Ensure proper pipe support to prevent stress on meter body.
Filtration and Strainers: Install strainers upstream of turbine and positive displacement meters to prevent damage from debris. Use mesh size appropriate for the application (typically 50-200 mesh). Clean or replace strainer elements regularly to maintain accuracy.
Grounding and Bonding: Properly ground magnetic and ultrasonic flow meters to prevent electrostatic interference. Bond flanged meters across the flange to ensure electrical continuity. Install per NEC and API RP 500 requirements for hazardous locations.
Calibration Procedures: Flow meters should be calibrated using certified flow proving systems traceable to NIST standards. Master meter method compares the test meter against a certified master meter. Gravimetric method measures actual weight of fluid transferred. Volumetric method uses certified volume provers.
Field Verification: Perform regular field verification using portable ultrasonic meters or by comparison with custody transfer meters. Multi-point calibration at 10%, 25%, 50%, 75%, and 100% of flow range verifies linearity across operating range.
Maintenance: Turbine meters require periodic bearing replacement and rotor inspection. Magnetic meters need electrode and liner inspection for erosion or coating buildup. Ultrasonic transducers should be tested for proper operation and cleaned if fouled.
API MPMS Chapter 5: Manual of Petroleum Measurement Standards provides comprehensive guidance for metering systems including installation, operation, calibration, and maintenance requirements. Chapter 5 covers liquid measurement using various meter types.
API MPMS Chapter 14: Natural gas fluids measurement standards specify requirements for gas measurement systems, including orifice meters, turbine meters, and ultrasonic meters.
AGA Reports 3, 7, and 9: American Gas Association standards cover orifice metering (AGA-3), turbine meter measurement (AGA-7), and ultrasonic flow measurement (AGA-9) for natural gas applications.
ISO 5167: International standard for measurement of fluid flow by means of pressure differential devices installed in circular cross-section conduits running full.
NIST Handbook 44: Specifications, tolerances, and technical requirements for commercial measuring devices including flow meters used in custody transfer applications.
Custody Transfer Requirements: Meters used for custody transfer must meet stringent accuracy requirements and be regularly proved using certified proving systems. Documentation must be maintained for regulatory compliance and commercial transactions.
Hazardous Area Classification: Flow meters installed in classified hazardous areas must carry appropriate certifications such as FM, CSA, ATEX, or IECEx for Class I, Division 1/Zone 0 locations common in oil and gas operations.
