Midstream oil and gas operations depend on accurate measurements to transport, process and store crude oil, natural gas, natural gas liquids and related products safely and efficiently. Flow and differential pressure measurements support applications ranging from pipeline monitoring and terminal operations to filtration, compression, storage and utility steam systems.
Selecting the right instrument requires more than choosing a measurement range. The fluid’s properties, operating envelope, required accuracy, installation conditions and purpose of the measurement all affect which technology will perform reliably.
This guide explains how to evaluate differential pressure transmitters and flow meters for liquid, gas and steam applications across midstream facilities.
Begin with the measurement objective
Before comparing instruments, define what the measurement needs to accomplish. A meter used for operational monitoring may have different accuracy, diagnostics and documentation requirements from one used for inventory control, allocation or custody transfer.
Typical midstream measurement objectives include:
- Process control
- Pipeline balancing
- Pump or compressor performance monitoring
- Filter and strainer condition monitoring
- Leak detection
- Storage-tank level measurement
- Terminal loading and unloading
- Fuel-gas monitoring
- Steam and utility energy management
- Allocation or custody transfer
For custody-transfer or regulated measurement, the complete metering system must meet the applicable contractual, regulatory and industry requirements. A standard process flow meter should not automatically be assumed suitable for fiscal measurement.
Once the objective is clear, establish the allowable uncertainty, required turndown, response time, output signals and maintenance expectations.
Define the complete process envelope
A flow meter or pressure transmitter should be selected for every credible operating condition, not only the normal flow rate.
Document the following:
- Minimum, normal and maximum flow
- Minimum, normal and maximum pressure
- Design pressure and potential pressure surges
- Minimum, normal and maximum temperature
- Fluid composition and density
- Viscosity and conductivity, where relevant
- Vapor pressure and potential for flashing
- Gas compressibility
- Solids, wax, scale or entrained liquid
- Corrosive or sour-service components
- Single-phase or multiphase conditions
- Required pressure-drop limit
Composition matters because crude oil, refined products, natural gas and NGLs can behave very differently. Changes in temperature, pressure or composition can alter density and other properties used to calculate mass or standard volumetric flow.
For steam, determine whether the service is saturated or superheated. Also establish the expected pressure, temperature, steam quality and likelihood of condensate. A meter designed for dry saturated steam may not provide reliable results in wet-steam conditions.
When to use differential pressure measurement
Differential pressure, or DP, measurement is one of the most established methods for measuring flow in pipelines and process facilities. A primary element, such as an orifice plate, flow nozzle or Venturi, creates a restriction. The transmitter measures the resulting pressure difference, which is related to the square of the flow rate.
DP technology can be applied to liquids, gases and steam. Its strengths include:
- Broad industry familiarity
- Availability across many pipe sizes and pressure classes
- Suitability for high-temperature and high-pressure service
- No moving parts in the transmitter
- Established calculation and installation standards
- Flexibility in primary-element design and materials
DP measurement is especially attractive where operators already have standardized primary elements, manifolds, impulse piping and maintenance procedures.
Its limitations should also be considered. A restriction creates permanent pressure loss, and the square-root relationship between differential pressure and flow can limit usable turndown. Accuracy depends on the primary element, piping geometry, process data, transmitter performance and installation quality, not on the transmitter alone.
Select the DP range around actual flow conditions
The transmitter must resolve the differential pressure generated at low flow while safely handling the maximum differential and line pressure.
Because flow is proportional to the square root of differential pressure, a system operating at 50% of its maximum flow produces only about 25% of the maximum DP. At 10% flow, the signal falls to approximately 1% of maximum DP. An unnecessarily broad DP range can therefore reduce useful low-flow resolution.
Work with the primary-element supplier to determine:
- DP at minimum, normal and maximum flow
- Required beta ratio or restriction geometry
- Permanent pressure loss
- Reynolds-number range
- Gas expansion factor, where applicable
- Discharge coefficient
- Temperature effects on the pipe and primary element
- Required upstream and downstream straight runs
- Overall calculated uncertainty
ASME PTC 19.5 addresses differential-pressure-class flow measurement for liquids, gases and vapors, including discharge coefficients, expansion factors and thermal effects.
The final selection should be based on the transmitter’s calibrated-span performance rather than its maximum available range.
Do not overlook static pressure
A DP transmitter may be measuring a relatively small differential while both sides of its sensor are exposed to very high line pressure. This is common in natural-gas pipelines, compressor stations and other high-pressure services.
Confirm:
- Maximum allowable working pressure
- Static-pressure rating
- Overpressure limit on either side
- Zero shift caused by static pressure
- Pressure cycling and surge conditions
- Required process-connection rating
Fuji Electric offers high-static-pressure differential transmitters for oil and gas applications. Specialized FCX designs can measure small differential pressures while operating at static pressures up to 20,000 psi, depending on the configuration.
A high line-pressure rating alone is not enough. The transmitter must maintain the required accuracy and stability under the expected combination of static pressure, differential pressure and temperature.
Match wetted materials to the process
Every component exposed to the process must be chemically and mechanically compatible with the fluid. This includes diaphragms, flanges, gaskets, impulse tubing, manifolds, seals and the primary flow element.
Potential concerns include:
- Hydrogen sulfide and sour gas
- Carbon dioxide
- Chlorides and produced water
- Corrosion inhibitors and treatment chemicals
- Aromatic hydrocarbons
- Hydrogen permeation
- Erosion from entrained solids
- Low-temperature NGL service
Possible wetted materials include stainless steel, Hastelloy, Monel, tantalum and other specialty materials. The appropriate choice depends on the process composition and operating conditions. Compliance with project-specific sour-service requirements should be verified separately.
Fuji Electric’s FCX pressure-transmitter portfolio provides a range of wetted-material options for corrosive and demanding process services.
A diaphragm seal may be appropriate when the process is corrosive, viscous, prone to plugging, sanitary or extremely hot or cold. However, seals and capillaries can affect response time and temperature performance. Seal size, fill fluid, capillary length and ambient-temperature exposure must be evaluated as a complete system.
Design the impulse-piping arrangement correctly
Many apparent transmitter problems originate in the impulse lines rather than the sensor. Poor routing can trap gas in liquid service, collect liquid in gas service or create unequal hydrostatic heads.
As a general practice:
- For clean liquid service, mount the transmitter below the pressure taps so trapped gas can return to the process.
- For clean gas service, mount it above the taps so condensate can drain back to the pipe.
- For steam service, use condensate pots or equivalent arrangements and maintain equal liquid heads.
- Keep high- and low-pressure impulse lines as short, direct and symmetrical as practical.
- Protect impulse lines from freezing, excessive heat, vibration and mechanical damage.
- Provide an appropriate manifold for isolation, equalization and calibration.
ASME MFC-8M describes practices for transmitting pressure signals from a primary flow device to the secondary instrument without introducing unnecessary uncertainty.
For remote seals, matched capillary lengths and similar ambient exposure help reduce differential temperature effects.
Choosing a flow-meter technology for liquids
No single flow-meter technology is best for every midstream liquid application. Selection depends on fluid properties, accuracy requirements, pressure-drop limits and whether the pipe can be modified.
Clamp-on ultrasonic meters
Clamp-on ultrasonic flow meters attach to the outside of an existing pipe. They require no process penetration and typically produce no additional pressure loss.
They can be a strong choice for:
- Flow surveys
- Temporary verification
- Energy assessments
- Leak investigations
- Applications where shutting down or cutting the pipe is undesirable
- Retrofitting existing systems
Successful application depends on pipe material, wall thickness, liner condition, pipe condition, acoustic properties and the availability of a fully developed flow profile. The pipe must normally remain full of liquid, and heavy deposits or aeration can weaken the ultrasonic signal.
Spool-piece ultrasonic meters
Inline ultrasonic meters can provide higher performance and repeatability through a controlled meter body and defined acoustic paths. Fuji Electric’s three-path FST spool-piece ultrasonic meter, for example, is specified for accuracy of up to ±0.2% of rate in supported configurations, with hazardous-area versions and digital communications available.
These meters may suit refined products, compatible hydrocarbons and other clean-liquid services when their materials, pressure rating and fluid-property requirements are satisfied.
Electromagnetic meters
Electromagnetic flow meters provide no obstruction and minimal pressure loss, but they require an electrically conductive liquid. They are therefore suitable for produced water, utility water and many water-based chemical streams, not most refined hydrocarbons, crude oils or other nonconductive petroleum products.
Differential-pressure meters
DP meters remain useful for a wide range of liquid duties, particularly at high pressure or temperature. Their principal tradeoffs are permanent pressure loss and more limited turndown than some ultrasonic technologies.
The decision should be based on lifecycle performance rather than purchase price alone. Installation labor, shutdown requirements, pumping energy, calibration and long-term maintenance can outweigh the initial cost of the instrument.
Choosing a meter for natural gas and process gas
Gas measurement requires accurate pressure, temperature, composition and compressibility information. A volumetric flow value at actual line conditions cannot be compared directly with a value referenced to standard conditions unless the appropriate compensation is applied.
Evaluate:
- Actual and standard volumetric flow
- Gas composition and molecular weight
- Operating pressure and temperature
- Compressibility factor
- Required turndown
- Gas cleanliness
- Entrained liquid or mist
- Pulsation from compressors or regulators
- Required flow conditioning
- Allocation or custody-transfer requirements
DP measurement is widely used for gas flow and can be effective across demanding pressure classes. A multivariable calculation may use DP, static pressure and temperature to determine compensated flow.
Wet gas, slugging or multiphase flow requires specialized analysis. A meter designed for clean, single-phase natural gas should not be expected to retain its stated performance when liquid loading is significant.
Choosing a steam flow meter
Steam measurement presents several challenges: high temperature, changing density, condensation and the need to minimize energy loss.
Common choices include DP, vortex and ultrasonic technologies.
Differential-pressure steam measurement
DP systems are established and suitable for high-pressure and high-temperature applications. Correct impulse-piping design is essential. Both transmitter legs should contain stable, equal condensate columns to prevent false differential pressure.
Pressure and temperature compensation may be required to calculate mass flow when steam density changes.
Vortex flow meters
Vortex meters are often used for general saturated and superheated steam service. They have no moving parts and can provide a practical balance of performance and maintenance requirements. They do, however, require adequate straight piping and can be affected by low flow, vibration and wet steam.
Clamp-on ultrasonic steam meters
Clamp-on ultrasonic technology enables saturated-steam measurement without cutting the pipe or introducing an obstruction. It can eliminate meter-induced pressure loss and simplify retrofit installation.
Fuji Electric’s FSJ ultrasonic steam flow meter is designed for clamp-on saturated-steam measurement. It requires no process penetration, has no moving parts and can support steam-energy monitoring without adding pressure loss.
Confirm that the steam pressure, temperature, pipe size, pipe material, wall thickness and steam condition fall within the selected meter’s published limits. Superheated or wet steam should not be assumed compatible with an instrument specified only for saturated steam.
Evaluate installation effects
Even a highly accurate meter can produce poor results if installed in a disturbed flow profile.
Review:
- Required upstream and downstream straight-pipe lengths
- Proximity to elbows, tees, valves and reducers
- Multiple out-of-plane elbows
- Control-valve location
- Pump or compressor discharge pulsation
- Swirl and asymmetric velocity profiles
- Pipe vibration
- Whether the pipe remains full
- Sensor orientation
- Accessibility for calibration and maintenance
Where adequate straight pipe is unavailable, a flow conditioner or a technology less sensitive to profile distortion may be needed. Avoid treating catalog accuracy as installed-system accuracy. Total uncertainty includes the meter, transmitter, process-property inputs, installation and any compensation calculations.
Specify hazardous-area and functional requirements
Midstream instruments commonly operate in classified locations. The selected model and complete installation must carry the required approvals for the gas group, temperature class, protection method and area classification.
Also define:
- 4–20 mA and HART requirements
- Digital communication protocols
- Local display and configuration
- High- or low-failure alarm behavior
- Environmental enclosure rating
- Electromagnetic compatibility
- Surge and lightning protection
- Functional-safety requirements
- Cybersecurity requirements for connected instruments
- Calibration certificates and material traceability
Fuji Electric’s FCX-AIV pressure and DP transmitters combine 4–20 mA/HART communication with a fast measurement cycle, long-term stability and IEC 61508 SIL 2/SIL 3 certification in applicable configurations.
Functional-safety certification does not, by itself, make an instrument suitable for a safety instrumented function. The complete loop must be designed and verified against the project’s safety requirements.
Look at lifecycle cost, not just instrument cost
The lowest-priced meter is not necessarily the lowest-cost solution. A lifecycle comparison should include:
- Installation and piping modifications
- Required shutdown time
- Permanent pressure loss
- Pumping or compression energy
- Calibration frequency
- Impulse-line maintenance
- Exposure to erosion or fouling
- Spare-parts strategy
- Diagnostic capability
- Local technical support
- Expected service life
A clamp-on meter may reduce installation cost and avoid a shutdown. A DP system may offer familiarity and robust high-pressure performance. A spool-piece ultrasonic meter may provide higher accuracy with little pressure loss. The right answer depends on the application’s priorities.
A practical selection checklist
Before finalizing a differential pressure transmitter or flow meter, confirm that the specification answers these questions:
- What fluid or steam condition will be measured?
- Is the process consistently single phase?
- What are the minimum, normal, maximum and design conditions?
- Is the measurement for control, monitoring, allocation or custody transfer?
- What installed-system uncertainty and turndown are required?
- How much permanent pressure loss is acceptable?
- Are all wetted materials compatible with the process?
- Can the instrument withstand the maximum static pressure and overpressure?
- Are adequate straight pipe and mounting access available?
- What compensation for pressure, temperature, density or composition is needed?
- What hazardous-area approvals and communications are required?
- How will the device be isolated, verified and maintained?
- What is the expected lifecycle cost?
Select the measurement system, not only the instrument
Reliable midstream measurement depends on the interaction of the sensor, process connections, primary element, piping, compensation data and control system. Selecting each part independently can produce a system that appears correct on paper but fails to deliver the required performance in operation.
Fuji Electric provides differential pressure transmitters and flow-meter technologies for liquid, gas and steam applications across upstream and midstream operations. Its portfolio includes FCX pressure and DP transmitters, clamp-on and spool-piece ultrasonic liquid meters, and clamp-on ultrasonic steam measurement solutions.Engaging a measurement specialist early can help validate the operating envelope, materials, installation geometry and uncertainty requirements, before they become costly field problems.