Flow Meters: 8 Types for Oil & Gas Piping

Quick Reference

8 types of flow meters for oil & gas piping: Coriolis (mass flow, custody transfer) · Ultrasonic (non-intrusive, large pipes) · Electromagnetic (conductive liquids) · Thermal (gas mass flow) · Turbine (clean liquids) · Differential Pressure (orifice, venturi, pitot) · Positive Displacement (viscous fluids, billing) · Vortex (steam, low maintenance). Selection depends on fluid type, accuracy needs, pipe size, and custody transfer requirements.

Classification of flow meter types for oil and gas

Flow Meters in Oil & Gas

What Are Flow Meters?

A flow meter measures the rate at which fluid or gas moves through a pipeline, expressed as volume or mass per unit time (liters per minute, kilograms per second, etc.).

Industrial Flow Meter

In oil and gas, flow meters serve two fundamental purposes: process control (you need to know what’s flowing where) and custody transfer (money changes hands based on these readings). Get the measurement wrong, and you either lose product or lose a client.

The main flow meter types (Coriolis, ultrasonic, electromagnetic, turbine, differential pressure, positive displacement, vortex, and thermal) each have distinct strengths. Which one you pick depends on the fluid (clean liquid? dirty slurry? wet gas?), the pipe size, the required accuracy, and whether particulates, temperature, or pressure will complicate things.

Key Takeaway: Flow meter selection in oil and gas depends on the application: Coriolis meters for high-accuracy mass flow and custody transfer, ultrasonic meters for non-intrusive measurement on large pipes, electromagnetic meters for conductive liquids and slurries, differential pressure meters for versatile and cost-effective service, and positive displacement meters for precise volumetric billing. Regular calibration against traceable standards is mandatory for all custody transfer applications.

Flow Meter Applications in Oil & Gas

In the field, flow meters handle four main jobs:

Application	Purpose	Typical Meter Types
Custody transfer	Measuring volumes at buy/sell points where ownership changes	Coriolis, ultrasonic (multi-path), PD meters
Process control	Regulating flow within the plant to maintain setpoints	Vortex, DP, electromagnetic, turbine
Leak detection	Comparing upstream/downstream readings to spot pipeline losses	Ultrasonic (clamp-on), Coriolis
Emissions monitoring	Measuring flare gas, vent gas, and discharges for environmental compliance	Thermal, ultrasonic, vortex

What Is Custody Transfer?

Custody transfer is the point where ownership of a commodity (crude oil, natural gas, refined products, LNG) changes hands between buyer and seller. Every barrel or cubic meter at that point has a dollar value attached, so measurement accuracy is not optional. A 0.25% error on a 100,000 bbl/day transfer point costs someone real money, every single day.

Electromagnetic flow meter for custody transfer

Custody transfer metering stations typically use Coriolis or positive displacement meters for liquids and multi-path ultrasonic meters for gas, backed by quality analyzers, provers, and third-party verification. The documentation (quantity, quality, time, conditions) must be bulletproof, because it is the first thing auditors and lawyers pull during a dispute.

Pro Tip

For custody transfer, always install a meter prover or master meter in the metering run. Proving the meter under actual operating conditions catches drift that laboratory calibration cannot detect. Budget for quarterly proving at minimum, and monthly on high-value transfer points.

The 8 Types of Flow Meters

• Coriolis: Direct mass flow, highest accuracy. The standard for custody transfer and multi-parameter measurement (mass, density, temperature).
• Ultrasonic: Non-intrusive, no pressure drop. Transit-time for clean fluids, Doppler for dirty fluids. Dominates large-diameter pipelines.
• Electromagnetic: Handles conductive liquids including slurries, corrosive fluids, and wastewater. No moving parts, no pressure drop.
• Thermal: Direct gas mass flow without pressure/temperature compensation. Excellent at low flow rates and for emissions monitoring.
• Turbine: High accuracy on clean, steady liquid flows. Linear output and fast response, but moving parts wear over time.
• Differential Pressure: The oldest technology, still the most widely installed. Orifice plates, venturi tubes, pitot tubes.
• Positive Displacement: Traps and counts discrete volumes. Best accuracy on viscous fluids and low-flow custody transfer.
• Vortex: No moving parts, handles liquids, gases, and steam. The default choice for steam metering in process plants.

Coriolis Flow Meters

The Coriolis flow meter is the benchmark for mass flow measurement. One or more tubes vibrate at their natural frequency, and as fluid flows through, the Coriolis forces create a phase shift in the vibration pattern that is directly proportional to mass flow rate. Measuring the vibration frequency also gives you fluid density, so from a single instrument you get mass flow, volumetric flow, density, and temperature.

Coriolis flowmeter

What makes the Coriolis meter so valued in custody transfer is that it measures mass directly, with no need to calculate density separately and multiply. Changes in temperature, pressure, or viscosity do not affect the reading. There are no moving parts in the flow path, so maintenance is minimal.

The downside? Cost. A 6-inch Coriolis meter can run 3-5x the price of an equivalent orifice plate installation. Size is also a practical limit; Coriolis meters above 12 inches become heavy, expensive, and introduce significant pressure drop. But on a custody transfer station moving $50M/year in product, the payback on that accuracy is measured in weeks, not years. Coriolis meters dominate in petrochemical batching, oil and gas custody transfer, and pharmaceutical dosing, anywhere the cost of inaccuracy exceeds the cost of the instrument.

Pro Tip

Coriolis meters are orientation-sensitive. For liquids containing entrained gas or for two-phase flow, mount with the tubes vertical and flow upward. This prevents gas pockets from accumulating in the tube bends and causing measurement errors or “dry firing” that damages the sensor. Check the manufacturer’s specific recommendations for your application.

Ultrasonic Flow Meters

Ultrasonic flow meters measure fluid velocity using sound waves, then calculate flow rate from the velocity and pipe cross-section. Their biggest advantage is that clamp-on models require no pipe penetration: no process shutdown, no pressure drop, no contamination risk. You bolt transducers to the outside of the pipe and start measuring.

Ultrasonic flow meter

Two types exist, and choosing the wrong one is a common field mistake:

Transit-time ultrasonic flow meters send ultrasonic pulses both with and against the flow. The time difference between downstream and upstream pulses gives you the fluid velocity. These work well on clean, particulate-free liquids, but scatter and absorb badly if the fluid carries solids or gas bubbles.

Doppler ultrasonic flow meters rely on the frequency shift of ultrasonic signals bouncing off suspended particles or bubbles. They actually need particulates or aeration to function, the exact opposite of transit-time meters. If someone hands you a Doppler meter for clean demineralized water service, send it back.

Ultrasonic meters excel on large-diameter pipelines (24 inches and above) where other technologies become prohibitively expensive or impractical. Multi-path transit-time meters with 4+ paths now achieve custody-transfer accuracy on gas pipelines per AGA Report No. 9, and they are the standard choice for fiscal metering on large gas trunk lines.

Common Mistake

Installing ultrasonic flow meters with insufficient straight pipe upstream. Transit-time meters need a fully developed flow profile. Turbulence from elbows, valves, or reducers causes major errors. Follow manufacturer’s requirements: typically 10-20 pipe diameters of straight run upstream and 5 diameters downstream. In tight spaces, use flow conditioners, not shorter runs.

Electromagnetic Flow Meters

Electromagnetic flow meters (mag meters) operate on Faraday’s law of electromagnetic induction: when a conductive fluid passes through a magnetic field, it generates a voltage proportional to its velocity. Two electrodes in the pipe wall pick up this voltage, and the meter calculates volumetric flow rate from the velocity and pipe cross-sectional area.

The critical requirement is that the fluid must be electrically conductive, with a minimum conductivity of about 5 µS/cm for most meters. This rules out hydrocarbons, pure water, and gases, but opens the door to a wide range of applications that other meters handle poorly: produced water, drilling mud, chemical injection, water treatment, and slurry service.

Electromagnetic meters have no moving parts and no obstructions in the flow path, which means zero pressure drop and nothing to wear or foul. The wetted parts can be lined with PTFE, rubber, or ceramic to handle corrosive and abrasive fluids. This makes them the go-to choice for:

• Produced water and injection water in oil and gas operations
• Slurry service (mining, dredging, cement) where particulates would destroy turbine or PD meters
• Corrosive chemicals (acids, caustics) where the liner protects the meter body
• Wastewater and effluent monitoring for environmental compliance
• Utility water metering in refineries and petrochemical plants

Accuracy is typically ±0.5% of reading for inline meters and ±2% for insertion types. The meters are available in sizes from ½ inch to 120 inches, covering everything from chemical dosing lines to large-diameter cooling water headers.

Pro Tip

Always verify the fluid conductivity before specifying a mag meter. Produced water and most aqueous solutions are fine (conductivity well above 5 µS/cm), but be cautious with deionized water, high-purity condensate, and any hydrocarbon, as these will not register. If in doubt, measure the conductivity of a sample before you commit to the purchase order.

Common Mistake

Empty pipe conditions cause electromagnetic flow meters to output erroneous readings (often full-scale). On applications where the pipe may drain or run partially full, always specify an empty pipe detection option. Without it, the meter will report phantom flow and corrupt your totalizer readings.

Thermal Flow Meters

Thermal flow meters (thermal mass flow meters) measure gas mass flow rate by quantifying heat transfer. They are the go-to choice for gas measurement (flare gas, vent gas, emissions monitoring, HVAC airflow, biogas), especially at low flow rates where other technologies lose sensitivity.

Thermal flow meter

Two measurement methods are used. The constant temperature differential method maintains a fixed temperature difference between a heated sensor and a downstream reference; as flow increases, more heat is carried away, and the power required to hold that differential is proportional to mass flow. The constant power (hot-wire anemometer) method applies fixed power to a heated element and measures the cooling effect: faster flow, more cooling, lower element temperature.

The practical advantage: thermal meters give you mass flow directly without needing separate pressure and temperature compensation. They have no moving parts, handle very low flow rates well, and work on clean, dry gases. Their weakness is sensitivity to gas composition changes; if the thermal conductivity of the gas shifts (say, because the CO2/methane ratio changes in a biogas line), the reading drifts. For that reason, they need application-specific calibration and are not typically used for custody transfer.

Common Mistake

Thermal flow meters calibrated on one gas composition will read incorrectly on another. If the process gas mixture changes seasonally or between sources (common in biogas, landfill gas, and associated gas), the meter must be recalibrated or configured with a gas correction factor. Ignoring this causes errors of 10-30%.

Turbine Flow Meters

Turbine flow meters are straightforward: fluid spins a rotor, a magnetic pickup counts the blade passes, and each pulse corresponds to a known volume. The pulse frequency is linear with flow rate, which makes signal processing simple and response time fast.

Turbine flow meter

Under optimal conditions (clean, steady flow, moderate viscosity), turbine meters achieve ±0.5% accuracy or better, with a wide turndown ratio. They have been a workhorse for petroleum product measurement and natural gas metering (per AGA Report No. 7) for decades.

The catch is that turbine meters have moving parts in the flow stream, and those parts wear. Particulates chew up the bearings and blade edges, viscous fluids drag on the rotor, and pulsating flow from reciprocating pumps can destroy accuracy and fatigue the blades. I have seen turbine meters in dirty crude service lose 2% accuracy in under six months. If your fluid is not clean and your flow is not steady, pick a different technology. When the application fits, though (clean refined products, aviation fuel, demineralized water), turbine meters deliver excellent performance at a reasonable cost.

Field Note

Pulsating flow from reciprocating pumps or compressors is a turbine meter killer. The rotor over-speeds on pulses and under-speeds between them, causing positive measurement errors of 5-15%. If you must measure pulsating flow with a turbine meter, install a pulsation dampener upstream. Better yet, switch to a Coriolis or vortex meter that is immune to pulsation effects.

Differential Pressure Flow Meters

Differential pressure (DP) flow meters are the oldest and most widely installed flow measurement technology in the world. The principle is Bernoulli’s equation in practice: put a restriction in the pipe (orifice plate, venturi tube, flow nozzle, or pitot tube), measure the pressure drop across it, and calculate the flow rate from the square root of that pressure difference.

Differential flow meter

Orifice plates are by far the most common primary element: a flat plate with a precision-bored hole, sandwiched between flanges. They are cheap, well-understood, and covered by extensive standards (ISO 5167, AGA Report No. 3). Venturi meters recover more pressure (lower permanent pressure loss) but cost more and take up more space. Flow nozzles sit between the two in terms of cost and pressure recovery. Pitot tubes (and averaging pitot tubes like Annubar) are insertion devices that measure velocity at a point or across the pipe, useful for large ducts and stacks where installing an orifice plate is impractical.

DP meters handle liquids, gases, and steam across a wide range of temperatures and pressures. They have no moving parts and, with a quality DP transmitter, can deliver ±1% accuracy on well-characterized flows. The trade-off is a permanent pressure drop (energy lost to the restriction) and a square-root relationship that limits the useful turndown ratio to about 4:1 or 5:1 with a single transmitter. For wider rangeability, you need stacked transmitters or a different technology.

Common Mistake

An orifice plate installed backwards (with the beveled edge facing upstream instead of downstream) will read incorrectly by 5-15% and you may not notice for months. Always verify the flow direction arrow stamped on the plate handle matches the actual process flow direction. This is especially critical after turnaround maintenance when plates are removed and reinstalled.

Pro Tip

For new installations, consider conditioning orifice plates (plates with multiple holes instead of a single bore). They require only 2 pipe diameters of straight run upstream versus 20-40D for standard orifice plates, a significant advantage in tight plant layouts where straight-run requirements drive up piping costs.

Positive Displacement Flow Meters

Positive displacement (PD) flow meters trap a fixed volume of fluid, transfer it through a chamber, and count the cycles. Each cycle equals a known volume, so the total flow is simply the number of cycles multiplied by the chamber volume. No inference, no calculation from velocity profiles, just direct volumetric measurement.

Positive displacement flow meters

Common PD meter types include rotary vane, oval gear, piston, and diaphragm designs. The choice depends on the fluid: oval gear meters handle viscous liquids well (heavy fuel oil, lubricants), diaphragm meters dominate residential gas metering, and piston meters are common in chemical dosing.

PD meters shine on viscous fluids and at low flow rates, conditions where turbine meters and DP meters lose accuracy. In fact, higher viscosity actually improves PD meter performance by reducing slippage past the sealing surfaces. This makes them a natural fit for crude oil custody transfer and heavy fuel oil billing.

The trade-off is mechanical complexity. Moving parts wear, especially with abrasive or dirty fluids. PD meters also impose a pressure drop on the system. Calibration drift from wear is a real concern on high-value custody transfer points; budget for regular proving and do not assume the factory calibration will hold indefinitely.

Vortex Flow Meters

Vortex flow meters use the von Karman vortex street principle: a bluff body in the flow path sheds alternating vortices, and the shedding frequency is proportional to fluid velocity. A piezoelectric or capacitive sensor downstream picks up the vortices and converts the frequency into a flow signal.

Vortex flow meters

No moving parts, minimal pressure drop, and they handle liquids, gases, and steam; vortex meters are among the most versatile options in process flow measurement. Steam metering in particular is where vortex meters have carved out a dominant position, because they tolerate the high temperatures and pressures that would destroy turbine meter bearings.

The limitations are real, though. Vortex meters need a minimum Reynolds number to generate stable vortex shedding, so they lose accuracy at low flow rates and with high-viscosity fluids. They are also sensitive to flow disturbances; an elbow or control valve too close upstream produces asymmetric vortex shedding and measurement errors. Budget for proper straight runs (typically 15-20D upstream, 5D downstream) or install flow conditioners. For general process monitoring, utility steam, and compressed air measurement, vortex meters are hard to beat on a cost-per-point basis.

Pro Tip

Multi-variable vortex meters measure flow, temperature, and pressure simultaneously, then calculate compensated mass flow for steam and gas. This eliminates the need for separate transmitters and reduces installed cost by 30-40% on steam loops. Specify them whenever you need compensated steam flow, which is nearly always, since uncompensated volumetric steam measurement is nearly meaningless.

Flow Meter Comparison Table

Type	Accuracy	Turndown	Pressure Drop	Moving Parts	Best Application	Relative Cost
Coriolis	±0.1-0.2%	80:1 to 100:1	Moderate	None	Custody transfer, mass flow	High
Ultrasonic	±0.5-1% (±0.1% multi-path)	50:1 to 100:1	None (clamp-on)	None	Large pipes, gas fiscal metering	Medium-High
Electromagnetic	±0.5%	30:1 to 100:1	None	None	Conductive liquids, slurries	Medium
Thermal	±1-2%	100:1	Low	None	Gas mass flow, low flow rates	Medium
Turbine	±0.5%	10:1 to 20:1	Moderate	Rotor, bearings	Clean liquids, petroleum products	Low-Medium
Differential Pressure	±1-2%	4:1 to 5:1	High (orifice)	None	General purpose, established plants	Low
Positive Displacement	±0.5%	10:1 to 20:1	High	Gears, vanes	Viscous fluids, liquid billing	Medium
Vortex	±0.75-1%	20:1 to 40:1	Low-Moderate	None	Steam, general process	Low-Medium

How to Select a Flow Meter

Selecting the right flow meter starts with the fluid and the application, not the technology. Work through these questions in order:

Step 1: What is the fluid?

• Gas → Consider thermal (low flow), ultrasonic, vortex, or DP (orifice/venturi)
• Clean liquid → Coriolis, ultrasonic (transit-time), turbine, vortex, or DP
• Conductive liquid or slurry → Electromagnetic
• Viscous liquid (>10 cP) → Positive displacement or Coriolis
• Steam → Vortex (first choice), DP (orifice or nozzle)

Step 2: What accuracy do you need?

• Custody transfer (±0.1-0.5%) → Coriolis, PD, or multi-path ultrasonic
• Process control (±1-2%) → Almost any technology works; optimize on cost and maintenance
• Indication only (±2-5%) → Clamp-on ultrasonic, rotameter, or variable area

Step 3: What is the pipe size?

• Small bore (½” to 2”) → Coriolis, turbine, PD, electromagnetic
• Medium (3” to 12”) → All types viable; select based on fluid and accuracy
• Large (>12”) → Ultrasonic, electromagnetic, DP (venturi/pitot), or insertion vortex

Step 4: What are the constraints?

• No shutdown allowed → Clamp-on ultrasonic or insertion meters
• Zero pressure drop required → Clamp-on ultrasonic or electromagnetic
• Minimal maintenance → Electromagnetic, ultrasonic, vortex (no moving parts)
• Limited straight run → Coriolis (0-5D) or conditioning orifice plate (2D)
• Hazardous area → Verify meter has appropriate ATEX/IECEx certification

Flow Meter Selection Guide by Fluid Type

Fluid	First Choice	Second Choice	Avoid
Crude oil	Coriolis	PD (oval gear)	Electromagnetic
Refined products	Turbine	Coriolis	-
Natural gas (fiscal)	Ultrasonic (multi-path)	DP (orifice, AGA 3)	PD
Process gas	Vortex	Thermal	Turbine
Steam	Vortex	DP (orifice/nozzle)	Coriolis, electromagnetic
Produced water	Electromagnetic	Ultrasonic	Turbine
Slurry / drilling mud	Electromagnetic	Doppler ultrasonic	Turbine, PD
Chemical injection	Coriolis	PD (piston)	DP
Flare gas	Thermal	Ultrasonic	DP (low-pressure issues)
LNG / cryogenic	Coriolis	Turbine	Electromagnetic, vortex

Installation Guidelines

Every flow meter has straight-run requirements, meaning the length of undisturbed pipe needed upstream and downstream to develop a proper velocity profile. Violating these requirements is the single most common cause of flow measurement error in the field.

Straight Run Requirements by Meter Type

Meter Type	Upstream (pipe diameters)	Downstream (pipe diameters)	Notes
Coriolis	0-5D	0-3D	Least sensitive; some manufacturers specify zero straight run
Electromagnetic	5-10D	3-5D	More tolerant than most; 5D upstream sufficient for most disturbances
Ultrasonic (transit-time)	10-20D	5D	Multi-path designs are more tolerant; single-path needs full 20D
Ultrasonic (clamp-on)	10-20D	5D	Same as inline; pipe condition and wall thickness matter more
Turbine	10-15D	5D	Very sensitive to swirl; use straightening vanes after two elbows in different planes
DP (orifice plate)	20-40D	5-7D	Depends on beta ratio and upstream fitting; ISO 5167 has detailed tables
DP (venturi)	5-20D	4D	Better than orifice; gradual convergence is less profile-sensitive
Vortex	15-20D	5D	Sensitive to asymmetric flow; a control valve upstream needs 30D+
Thermal	15-20D	10D	Insertion types are very profile-sensitive
PD	0D	0D	No straight run needed; PD meters are immune to flow profile disturbances

Field Note

When you cannot meet straight-run requirements, install a flow conditioner (tube bundle, perforated plate, or tab-type). But do not assume a flow conditioner is a universal fix. It only eliminates swirl and asymmetry, not pulsation. And it introduces its own pressure drop. The best solution is always to design the piping for adequate straight runs from the start. Retrofitting flow conditioners is expensive and sometimes impossible.

General Installation Rules

• Orientation: Mount Coriolis meters vertically (flow up) for liquids with entrained gas. Mount electromagnetic meters with electrodes horizontal to avoid air bubble or sediment contact. Mount vortex meters in any orientation, but vertical with flow up is best for liquids.
• Grounding: Electromagnetic meters require proper grounding rings or grounding electrodes. Poor grounding causes erratic readings and is the #1 installation error with mag meters.
• Isolation valves: Always install isolation valves upstream and downstream of inline meters for maintenance access. Budget for a bypass line on critical custody transfer meters.
• Impulse tubing (DP meters): Keep impulse lines short, sloped properly (down for liquids, up for gas), and free of air traps (liquids) or condensate traps (gas). Use seal pots and condensate pots where needed. A badly run impulse line causes more measurement errors than a bad transmitter.

Flowmeter Calibration

All flow meters drift over time. Wear on moving parts, fouling of sensors, changes in fluid properties, electronic drift: the question is not if a meter will lose accuracy, but when and how much. Calibration compares the meter’s reading against a known reference and corrects the output.

When and How Often

Calibration frequency depends on the application. Custody transfer meters on high-value product lines may need proving monthly or even weekly. Process control meters in benign service might go 12-24 months between calibrations. Harsh service (abrasive slurries, corrosive chemicals, high-temperature steam) accelerates drift and demands shorter intervals. Always start with the manufacturer’s recommendation, then adjust based on operating experience and historical drift data.

Calibration Methods

Method	Description	Best For
In-situ proving	A pipe prover or master meter installed in the line; calibrate without removal	Custody transfer stations, large meters
Off-site laboratory	Meter removed and sent to an accredited flow lab	High-accuracy verification, periodic recertification
Master meter comparison	A calibrated reference meter installed in series	Process meters, spot-checks

All reference standards must be traceable to national metrology institutes (NIST, PTB, etc.). A calibration against an untraced reference is worthless.

The Calibration Sequence

The process is straightforward: pre-test to document as-found condition, adjust until readings match the reference, verify across the operating range, and document everything. That documentation (as-found data, as-left data, adjustments made, reference standard traceability) is not paperwork for its own sake. It is your evidence trail for audits, disputes, and regulatory inspections.

Field Note

For custody transfer meters, don’t rely solely on manufacturer calibration intervals. Verify meters against a master meter or prover at startup and whenever you suspect drift, because even a 0.1% error on a high-volume transfer adds up to significant financial discrepancy over months. Document everything; calibration records are the first thing auditors request during disputes.

Standards and Codes Reference

Flow meter selection, installation, and operation in oil and gas are governed by an extensive set of standards. The table below lists the key references every instrument engineer should know:

Standard	Title / Scope	Applies To
ISO 5167 (Parts 1-4)	Measurement of fluid flow - Pressure differential devices	Orifice plates, nozzles, venturi tubes
AGA Report No. 3	Orifice Metering of Natural Gas	Natural gas orifice metering (custody transfer)
AGA Report No. 7	Measurement of Natural Gas by Turbine Meters	Turbine meters for gas fiscal metering
AGA Report No. 9	Measurement of Gas by Multipath Ultrasonic Meters	Ultrasonic meters for gas custody transfer
AGA Report No. 11	Measurement of Natural Gas by Coriolis Meter	Coriolis meters for gas fiscal metering
API MPMS Ch. 5	Metering (Manual of Petroleum Measurement Standards)	Liquid petroleum metering
API MPMS Ch. 6	Metering Assemblies	Prover design and operation
API MPMS Ch. 7	Temperature Determination	Temperature measurement at metering points
API MPMS Ch. 8	Sampling	Representative sampling at custody transfer
IEC 61511	Functional safety - Safety instrumented systems	Flow meters in SIS/SIF applications
ISO 10790	Measurement of fluid flow - Coriolis meters	Coriolis meter specifications and testing
OIML R 117	Dynamic measuring systems for liquids other than water	Legal metrology (weights and measures)

Pro Tip

When specifying DP meters for natural gas custody transfer, cite AGA Report No. 3 specifically, not just “ISO 5167.” AGA 3 incorporates additional requirements for gas properties, compressibility calculations, and allowable tolerances that ISO 5167 alone does not cover. Your measurement uncertainty analysis must reference the correct standard, or the buyer’s auditors will reject it.

Gas vs. Oil Flow Metering

Gas and oil behave so differently that the same meter technology often requires fundamentally different design choices for each service:

Aspect	Gas Service	Oil Service
Compressibility	Gases are compressible; volume changes with pressure and temperature. Every measurement must be corrected to standard conditions (14.7 psia, 60°F or 1 atm, 15°C)	Oils are essentially incompressible; volume corrections are minor (thermal expansion only)
Density	Low density means low momentum; meters need higher sensitivity and may struggle at low velocities	Higher density provides strong signal; most meter types work well
Viscosity	Very low viscosity; Reynolds number is usually high, which helps DP and vortex meters	Viscosity varies widely with temperature and grade; high viscosity favors PD and Coriolis meters
Preferred meters	Ultrasonic (multi-path), DP (orifice per AGA 3), turbine (AGA 7), thermal, vortex	Coriolis, PD, turbine, ultrasonic (transit-time)
Custody transfer standard	Multi-path ultrasonic (AGA 9) or orifice (AGA 3) with online chromatograph	Coriolis or PD meter with pipe prover
P/T compensation	Always required; gas volume changes ~0.5% per 1 psi and ~0.2% per 1°F	Usually not required for process control; needed for custody transfer
Moisture/condensation	Wet gas and condensation cause errors in all meter types; use knock-out drums and trace heating	Water cut measurement is a separate discipline; requires multiphase meters or sampling
Safety	Leak prevention critical; must handle varying pressures; safety certification required	Corrosion and erosion are primary concerns; material compatibility essential

The bottom line: do not assume a flow meter rated for oil service will work on gas, or vice versa, without checking the manufacturer’s specifications for that specific medium. The internals, calibration, and rangeability can be entirely different.

Frequently Asked Questions

What are the main types of flow meters used in oil and gas?

The 8 main flow meter types are: Coriolis (mass flow, custody transfer), Ultrasonic (non-intrusive, large pipes), Electromagnetic (conductive liquids, slurries), Turbine (clean liquids), Differential Pressure (orifice plates, venturi, pitot tubes), Positive Displacement (viscous fluids, billing), Vortex (steam, low maintenance), and Thermal (gas mass flow). Selection depends on fluid type, accuracy requirements, pipe size, and whether the application involves custody transfer.

Which flow meter is best for custody transfer in oil and gas?

Coriolis flow meters are the preferred choice for liquid custody transfer because they measure mass flow directly, unaffected by temperature, pressure, or viscosity changes. For large-diameter gas pipelines, multi-path ultrasonic meters (per AGA Report No. 9) are preferred. Positive displacement meters are also common for liquid custody transfer, especially with viscous products like crude oil and heavy fuel oil.

What is the difference between transit-time and Doppler ultrasonic flow meters?

Transit-time meters measure the time difference of ultrasonic pulses sent with and against the flow, requiring clean, particulate-free liquids. Doppler meters measure the frequency shift of signals bouncing off suspended particles or bubbles, requiring particulates or aeration to function. Using the wrong type is a common field mistake: transit-time on dirty fluids gives errors, and Doppler on clean fluids gives no signal at all.

How much straight pipe run do flow meters need?

Straight run requirements vary by meter type: Coriolis needs 0-5 diameters (least sensitive), Electromagnetic needs 5-10D upstream, Ultrasonic needs 10-20D upstream, Vortex needs 15-20D upstream, and Orifice plates need 20-40D upstream. Positive displacement meters need zero straight run. Flow conditioners can reduce requirements in tight installations, but always design piping for adequate straight runs from the start.

What standards govern flow meter installation in oil and gas?

Key standards include ISO 5167 (differential pressure devices), AGA Report No. 3 (orifice metering of natural gas), AGA Report No. 7 (turbine meters for gas), AGA Report No. 9 (ultrasonic meters for gas), API MPMS Chapters 5-8 (petroleum measurement), and IEC 61511 (safety instrumented systems). Custody transfer applications must also comply with local weights and measures regulations (OIML R 117).