Selecting flowmeters for natural gas

Different parts of the natural gas delivery chain require different instruments, such as differential pressure (DP), ultrasonic, and Coriolis flowmeters.


Figure 1: The Federal Energy Information Agency predicts that by 2035, shale gas will account for nearly half of all U.S. gas production. Courtesy: Federal Energy Information AgencyDuring the last few years, there has been a tremendous increase in U.S. production of natural gas, much of it derived from fracking plays. According to the federal Energy Information Administration (EIA), dry natural gas shipments increased from 1 trillion ft3 in 2000 to 5 trillion ft3 in 2010, and production increased by a factor of 12 in one decade's time. EIA predicts that by 2035, shale gas will account for nearly half of all U.S. gas production (see Figure 1).

Flow measurement is critical at all points of the supply chain. Both fiscal and custody transfer measurements are needed in many of these points, but the appropriate instruments to make those measurements vary.

Figure 2: This graph shows financial risk versus measurement uncertainty. Courtesy: Emerson Process ManagementFiscal measurement versus custody transfer

Custody transfer is one of two forms of fiscal measurement. The other is allocation, defined as "the transfer of goods between two points generally not governed by a buy/sell contract," while custody transfer is done under a contractual obligation between buyer and seller that may require adherence to accuracy, repeatability, linearity, or uncertainty standards defined by measurement standards such as American Gas Association (AGA), American Petroleum Institute (API), International Organization for Standardization (ISO), GOST (Russian equivalent to API), and so on.

All forms of fiscal measurement can be affected by product quality, fluid properties and composition, operating parameters, maintenance practices, and technology type.

While gas custody-transfer flow measurement can take place anywhere along the process value chain from the wellhead to delivery or sale location, for the lowest uncertainty in measurement, it generally takes place at stable, predictable single-phase locations or physically discrete hand-over points (e.g., platform/production exit location, pipeline entry/exit, terminal entry, etc.). These locations generally provide the favorable conditions in which most flow measurement devices can operate with some degree of predictability and repeatability. 

Penalties for uncertainty in fiscal measurement

The enormous value of gas involved makes accuracy essential. At current gas prices, an error of 1% in measuring 300 million ft3 of gas per day can lead to a difference of about $2 million per year (see Figure 2).

Available technologies

Here, three technologies: differential pressure (DP), ultrasonic (both of which measure volumetric flow), and Coriolis, which directly measures mass flow are discussed. Simple volumetric flow measurement technology is not the only consideration because the ultimate measurement-and what the customer pays for-is energy delivered. For this reason, accurate and repeatable measurement of natural gas flow requires simultaneous measurement of several other variables, including pressure, temperature, density, and gas composition. 

DP meters

DP meters measure volumetric flow through a calibrated orifice (generally a flow plate), are inexpensive, and simple in concept. They are accepted broadly and are not limited in line size. While not the most accurate instruments available, they are acceptable for the purposes for which they are used, and the calculations for correcting to standard conditions are widely known.

DP meters measure only differential head. To measure either mass or volumetric flow, they must be corrected for density (mass) or temperature, pressure, and gas composition to obtain a standard reading. They have low turndown unless the orifice plate is changed. In addition, they are subject to fouling, which can partially obstruct the orifice plate and cause the meter to read high. The only way to counter fouling in a DP meter is to send someone out periodically to inspect the orifice plate, which is expensive in terms of labor and can mean an interruption in production. In addition, DP meters are sensitive to flow profile and require either a fairly long straight run or an upstream flow conditioner. They also generate a medium-to-large pressure loss, and they are not as accurate as other technologies, such as gas turbine, ultrasonic, or Coriolis meters. The use of DP meters for custody transfer is governed by API 14.3/AGA3 in North America and ISO 5167 globally. 

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Jeff , PA, United States, 06/21/16 01:59 PM:

Great article! I teach (theory and Hands-On)Coriolis meters, DP Flow with Flow Computers Ultrasonic Flow, and Gas Chromatographs in reference to the O&G industry.
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