Annubar: Averaging Pitot Tube Flow Measurement in Oil and Gas
An annubar is a multi-port averaging Pitot tube flow meter inserted diametrically across a pipe to measure the volumetric or mass flow rate of gas, liquid, or steam by sensing the differential pressure between the stagnation pressure at multiple upstream-facing ports and the static pressure at one or more downstream-facing ports. Unlike a conventional single-point Pitot tube, which captures velocity at only one radial position and introduces significant error wherever the flow velocity profile is non-uniform, the annubar carries four to nine upstream pressure-sensing ports spaced radially across the full diameter of the pipe at positions calculated to sample the velocity profile in a statistically optimal way, then averages their individual stagnation pressures in a common high-pressure manifold. The resulting differential pressure between that average stagnation pressure and the measured static pressure is proportional to the square of the average fluid velocity through Bernoulli's equation: ΔP = (ρ x V̄2) / 2, where ρ is fluid density and V̄ is the average velocity. Flow rate is then calculated from Q = Kd x A x sqrt(2 x ΔP / ρ), where A is the pipe cross-sectional area and Kd is the dimensionless discharge coefficient calibrated for the specific meter geometry, pipe size, and Reynolds number. The name "Annubar" is a registered trademark of Emerson Electric Co. through its Rosemount Measurement division, but the term has entered general engineering usage as a generic descriptor for the class of averaging Pitot tube instruments manufactured under various trade names by Emerson, Yokogawa, ABB, and other instrument suppliers. In the oil and gas industry, annubars are widely used for gas metering at wellheads, compressor station measurement points, pipeline custody transfer check meters, flare gas monitoring, and any application where low permanent pressure loss, simple installation, and reliable operation with minimal maintenance are required.
Key Takeaways
- Operating principle and differential pressure measurement: The annubar operates on the same Bernoulli differential pressure principle as an orifice plate or Venturi meter, but achieves flow averaging in the sensor element itself rather than relying on the meter geometry to create a measurable pressure drop. Each upstream port stagnates the approaching flow to recover its kinetic energy as pressure (stagnation pressure Pstag = Pstatic + ρV2/2), while the downstream port measures static pressure Pstatic of the undisturbed stream at that cross-section. Because the upstream ports are arranged at isokinetic or Chebyshev-optimized radial positions, the average stagnation pressure they deliver to the high-pressure manifold closely approximates the true velocity-weighted average stagnation pressure of the entire flow cross-section. The differential pressure ΔP = PH minus PL driving the connected differential pressure transmitter is typically 10 to 500 inches of water column (2.5 to 125 kPa) at normal operating flow rates, within the range of standard industrial differential pressure transmitters with 0.1 to 0.075 percent accuracy class instruments from Rosemount, Yokogawa, or Honeywell.
- Standards and calibration for natural gas measurement: Natural gas measurement using averaging Pitot tubes in Canada is governed by the Canadian Standards Association standard CAN/CSA-Z341.3 for wellhead metering and by AGA Report No. 3 (Orifice Metering of Natural Gas) principles adapted for averaging Pitot devices. The annubar's discharge coefficient Kd is determined by laboratory flow calibration traceable to National Research Council (NRC) primary flow standards, covering Reynolds numbers from 10,000 to 10,000,000, which encompasses the full range of wellhead gas flow rates from 50 to 5,000 Mscf/d in the WCSB. Gas density at flowing temperature and pressure is calculated using the AGA-8 equation of state from gas chromatograph composition data, usually updated daily at each measurement point from a programmable gas chromatograph sampling the live stream. The combined uncertainty of an annubar gas metering system in pipeline-quality gas service, including transmitter accuracy, flow calibration uncertainty, gas composition uncertainty, and temperature measurement error, is typically 0.5 to 1.5 percent of reading for a well-maintained, properly installed system, compared to 0.25 to 0.75 percent for a properly installed orifice plate in the same service.
- Permanent pressure loss and installation advantages: The annubar's primary advantage over orifice plates in compression-sensitive or low-pressure applications is its dramatically lower permanent pressure loss. An orifice plate operating at a 50-inch water column (12.5 kPa) differential pressure at beta ratio 0.65 imposes a permanent pressure loss of approximately 40 to 50 percent of the differential, or 5 to 6 kPa. An annubar generating the same differential pressure imposes a permanent pressure loss of only 0.5 to 1.5 percent of the differential, or 0.06 to 0.19 kPa, because the bluff body of the annubar bar displaces only 2 to 4 percent of the pipe cross-section and recovers most of the stagnation pressure after the measuring ports. In a Montney gathering system operating at 4,000 kPa line pressure, this permanent pressure difference between orifice and annubar is 5 versus 0.15 kPa, trivial relative to the line pressure. But in low-pressure flare gas monitoring at 5 to 15 kPa, or in a coal seam gas gathering system at 200 to 500 kPa, the orifice plate's permanent pressure loss of 5 to 6 kPa is a meaningful fraction of the available pressure head and can reduce throughput; the annubar's 0.1 to 0.2 kPa loss is operationally negligible. Installation is also simpler: the annubar bar is inserted through a standard 2-inch coupling on the side of the pipe with a compression fitting, requiring no pipe break or flange installation, which reduces installation time from several days (orifice flange with flanged connections) to two to four hours.
- Application in wellhead gas metering at multi-well pads: Annubars are the standard flow metering device at individual wellhead ties on multi-well Montney and Duvernay pad sites in northeast British Columbia and west-central Alberta, where each horizontal well delivers sales gas at 3,500 to 7,500 kPa to a header that feeds a common meter station. At these measurement points, the annubar is installed in a 2-inch or 3-inch wellhead flow line downstream of the choke and test separator, downstream of minimum five diameters of straight pipe (no elbows or valves that could distort the flow profile), with a differential pressure transmitter, temperature transmitter, and wellhead flowing pressure transmitter all connected to a flow computer programmed with AGA-8 density calculations. A two-second scan rate on each transmitter provides effectively continuous flow totalization that is compared daily with the test separator measurement (used for individual well allocation) and monthly with the meter station fiscal check meter at the sales gas custody transfer point. Total annubar metering package cost for a single Montney wellhead at 3-inch line size is approximately CAD 18,000 to 28,000 installed, including the annubar element, transmitters, temperature well, flow computer, and tubing manifold.
- Limitations and maintenance considerations: Annubars are not suitable for all flow measurement applications in the oil and gas industry. In multiphase wellhead streams upstream of the test separator, liquid slugging and irregular gas-liquid flow regimes cause the differential pressure signal to fluctuate erratically, producing inaccurate flow totals; phase separation is required before annubar metering can be applied. In heavy oil service or any stream carrying wax, asphaltene, sand, or hydrate-forming components, the small-diameter pressure-sensing ports (typically 1 to 3 millimetres diameter on a 2-inch bar) can plug within hours or days of operation, requiring purge systems using instrument gas or glycol injection to maintain clear ports. In high-velocity gas streams with entrained liquid droplets, port erosion over 12 to 24 months of continuous service can shift the discharge coefficient by 0.5 to 2 percent per year, requiring periodic field verification against a clamp-on ultrasonic check meter. Regular port purging (automated nitrogen purge for 30 seconds every 24 to 48 hours in production service, or continuous glycol injection at 0.5 to 1.5 L/day in hydrate-prone service) and annual visual inspection of the annubar element are the primary maintenance requirements to sustain 0.5 to 1.0 percent measurement accuracy over a 10-year service life.
Annubar Flow Measurement in WCSB Gas Gathering Systems
In the Western Canada Sedimentary Basin gas gathering infrastructure, annubars are encountered at four distinct measurement points along the value chain from reservoir to sales. At the wellhead, annubars on individual well flow lines provide real-time production monitoring and well-to-well allocation within a multi-well pad sharing a common test separator. At the compressor station inlet and outlet, annubars on individual compressor suction and discharge headers allow per-unit throughput accounting and compression ratio verification. At third-party interconnects between gathering system operators, annubars function as check meters paired with fiscal orifice plates or ultrasonic meters to resolve allocation disputes. At processing plant inlet headers, annubars on individual receipt points provide the raw data for feed gas accounting before the plant's official fiscal meter performs the custody transfer measurement.
Sizing an annubar for a specific WCSB wellhead application requires specifying four key parameters: pipe size, maximum flow rate, minimum flow rate at which accuracy is required, and operating pressure and temperature range. The minimum differential pressure at minimum flow must exceed the turndown threshold of the connected differential pressure transmitter, which for a standard 50-inch water column (12.5 kPa) range transmitter corresponds to approximately 0.5 percent of range or 0.25 inches of water column (0.06 kPa). For a Montney wellhead producing 0.5 to 8.0 MMscf/d in a 3-inch flow line at 5,000 kPa and 10 degrees Celsius, the minimum differential pressure at 0.5 MMscf/d must be at least 5 to 10 inches of water column (1.25 to 2.5 kPa) to maintain accuracy across the full production range, which sets the annubar element's pitch (distance between sensing ports) and port diameter. An annubar manufacturer's sizing calculation for this service typically specifies a 3-inch Annubar 485 element at 100 to 125 mm insertion depth with a maximum differential pressure of 280 inches of water column (70 kPa) at 8.0 MMscf/d, within the 300-inch range of the paired transmitter.
Temperature and pressure compensation is critical for accurate annubar mass flow measurement in gas service, because gas density varies significantly with temperature and pressure: at 5,000 kPa and 10 degrees Celsius, Montney sales gas at specific gravity 0.68 has a flowing density of approximately 37 kg/m3, while at 4,500 kPa and 30 degrees Celsius the same gas has density of approximately 32 kg/m3, an 8.6 percent difference. Without temperature and pressure compensation applied in real time by the flow computer, seasonal temperature variations and well pressure decline over the production life would introduce systematic errors of 5 to 10 percent per season into the wellhead gas allocation. Modern Montney pad metering uses integrated flow computers (Emerson Daniel 1500, OMNI 6000, or equivalent) that read the differential pressure, flowing pressure, and temperature at 1-second intervals and apply AGA-8 density calculation every 60 seconds, compensating for density variation continuously throughout the well's producing life from initial 6,500 kPa wellhead pressure at first flow through the typical abandonment pressure of 1,500 to 2,500 kPa over a 15 to 20 year production horizon.