Moving Toward Real Time
Natural Gas Flow
Measurement In The 21st Century
by Edgar C. Bowles, Jr.
Section Manager,
Metering Research Facility At Southwest Research Institute
San Antonio, Texas
The traditional business arrangement between natural gas producers and transporters
experienced a fundamental change in the 1990s due to government deregulation of the
industry. Long-term agreements between gas producers and transporters were superceded by a
commodity-based, supply-and-demand business. This paradigm shift placed greater importance
on accurate, timely, and cost-effective gas measurement by gas transporters.
Accurate gas measurement by gas transmission pipeline operators has always been important
to ensure fair and equitable transactions at custody transfer points, to allow efficient
management of gas supplies and deliveries, to control inventory, to minimize
unaccounted-for gas volumes, to avoid custody transfer disputes, and to provide customer
satisfaction. Now, there is also a growing emphasis on the timeliness and
cost-effectiveness of this measurement information. It is becoming necessary for gas
measurement data to be provided instantaneously (or in “real time”) so that gas
transporters can optimize pipeline operations, maximize system throughput and respond to
rapidly changing market opportunities. Availability of this information to all departments
of a company is also critical because nearly all aspects of a transporter’s business
are affected, in some way, by gas measurement.
The cost of acquiring gas measurement data is a significant issue because capital costs
associated with the installation of measurement systems and operating costs associated
with the maintenance and upkeep of these systems can be quite high. For instance, a new,
large-volume gas meter station may cost a million dollars or more to install. Today’s
market pressures demand that capital and operating expenses be kept to a minimum. This
includes gas measurement costs. One way gas transportation companies are trying to control
costs is by applying new or improved gas measurement technology that offers the prospect
of reduced capital or operating costs.
As the competitive market for natural gas continues to develop, what changes or
improvements in measurement technology can we expect? It is apparent that the gas
transportation companies that are quickest to acquire, process, and analyze gas
measurement data in a cost-effective way will gain a distinct business advantage. What gas
measurement technology will be available in the coming years to help companies gain this
business advantage? Following is a brief preview of what we can expect.
Orifice Flow Meters
The number of orifice flow meters installed in the gas transmission pipeline network in
the United States is in the tens of thousands and accounts for approximately 80 percent of
the total. Therefore, we cannot ignore the importance of this measurement method as we
look toward the future. Although this is a mature technology, advancements and
improvements are still needed and are being made.
The primary focus of recent advancements has been the identification and elimination of
measurement bias errors. There has been substantial research at the Gas Research Institute
(GRI) Metering Research Facility (and elsewhere) on the effect of upstream piping
configuration on orifice meter accuracy. The effects of flow conditioners have also been
studied extensively. A flow conditioner is a device placed upstream of a flow meter that
mitigates any adverse effects created by the upstream piping configuration. Some example
flow conditioners are pictured in Photo 1.
Recent research has given us a better understanding of how measurement bias errors can be
caused by the meter station installation configuration. We also have a better
understanding of how different types of flow conditioners affect meter performance. This
work has led to the pending revision of the American standard for orifice flow meters
— the American Petroleum Institute (API) Manual of Petroleum Measurement Standards
(MPMS), Chapter 14.3, Part 2. The revised standard[1] will provide more comprehensive
guidance on orifice meter installation configuration. The revised standard is currently
out for ballot by the API and is expected to be published later this year.
Future improvements in orifice metering will probably come via the secondary
instrumentation systems — the pressure and temperature sensors and the data
acquisition and storage system. With micro-sensor and microcomputer technology becoming
more advanced, the pressure and temperature transducers and the data acquisition, storage,
and transmission systems will become smaller, more capable, and less expensive. Integrated
systems in which the measurement sensors and the data acquisition, storage, and
transmission electronics are all contained in a single module may become the norm in the
next few years. One example of how improvements in sensor technology may affect orifice
meter configuration and performance is a new design developed under the auspices of the
Gas Machinery Research Council. With this new meter design, differential pressure across
the orifice is measured using small sensors embedded in the face of the orifice plate.
Compared to conventional orifice meters, this new design provides superior responsiveness
to fluctuations in gas flow rate. In addition, there are no gage line pressure effects to
deal with, since the gage lines to an outboard pressure transducer have been eliminated.
Several other orifice meter designs have been proposed recently, although they have not
yet gained broad acceptance. These alternate designs[2],[3] are all similar in that the
orifice plate has multiple holes or slots, rather than a single hole in the center of the
plate. The multiple-hole patterns are designed to make the flow element much less
susceptible to errors caused by the upstream installation configuration.
Turbine Flow Meters
As with orifice meters, there are many turbine meters installed in gas transmission
pipelines in the United States and this technology is relatively mature. Turbine meters
account for approximately 5 percent to 10 percent of the total. However, there have been
some recent developments in turbine flow meter technology. Meter manufacturers have
recently expanded meter flow range, improved meter self-diagnostic capability, and
improved wear life and durability of the rotating components.[4],[5] Changes in rotor
geometry have resulted in extended flow range. Features such as onboard microprocessors
and modems now allow meters to monitor their functionality and indicate when a problem
develops. Sealed bearings and improved bearing materials have helped extend the useful
life of the rotating components that are susceptible to wear failures. Further refinements
in meter performance, self-diagnostics, and wear life may be forthcoming in the next few
years.
New Flow Meter Technologies
Several new gas metering technologies have either recently come into the marketplace or
are expected to come into the marketplace in the next few years. The most commercially
successful new technology is the ultrasonic gas flow meter. An example of a multi-path
ultrasonic meter is shown in Photo 2. The conventional ultrasonic meter design utilizes a
time-of-flight measurement technique. It has only been within the past five years that
ultrasonic meters have gained acceptance by gas transmission pipeline operators in the
United States. Pipeline operators first used ultrasonic meters only as check meters.
Ultrasonic meters are now being used in some custody transfer applications. The first
reference document for ultrasonic gas flow meters[6] was a recommended practice published
by the American Gas Association (A.G.A.) in June 1998.
Although ultrasonic gas metering technology continues to experience a growth in
popularity, it is still a maturing technology. Meter manufacturers and researchers are
working to better define the performance envelope of these meters. As manufacturers learn
more about the operational characteristics of these meters and accumulate more field
experience, they update component designs and improve manufacturing processes. The result
is usually a meter with better performance characteristics and improved reliability. It is
expected that this development trend will continue for several more years. Additional
improvements are anticipated in the design and performance of the ultrasonic transducers,
the self-diagnostic capabilities of the meter, and the manufacturing precision of the
meter body and transducer mounting points. Consideration is also being given to designing
ultrasonic meters with integral flow conditioners. The flow conditioner would properly
shape the flow profile at the meter and minimize the number of ultrasonic transducers
required to produce an accurate measurement. This approach could produce a meter that is
less costly than conventional designs.
Currently, most ultrasonic meter users prefer to flow calibrate their meters before
installation. Flow calibration helps correct for any measurement bias error not accounted
for by dimensional measurements and static calibration. These errors may be introduced by
the meter fabrication process (i.e., dimensional tolerance issues) or by the electronic
timing circuitry in the meter (i.e., timing circuit tolerance issues). In the future,
tighter control of manufacturing tolerances and better understanding of the interaction
between the flow and the ultrasonic pulses may minimize the need for flow calibration.
Coriolis gas flow meters are just beginning to generate some interest as an alternative
metering technology. Coriolis flow meters have a long and successful history in liquid
flow measurement, but there is less experience in gas transmission pipeline flow
measurement. There are two basic meter configurations—straight tube and curved tube.
The most likely niche for Coriolis flow meters in transmission pipelines appears to be
high-pressure, low-volume applications. At present, there are few field meter
installations in transmission pipelines in the United States. However, Coriolis meter
manufacturers are conducting laboratory tests in the United States and Canada. Some field
tests are also ongoing, primarily in other countries, such as Australia. In May 1999, the
A.G.A. Transmission Measurement Committee agreed to initiate development of a gas industry
standard for Coriolis gas flow meters.
Several other alternative gas flow measurement techniques are in various stages of
development. Some of these techniques are proprietary and details cannot be divulged at
this time, while others are so early in the development process that their future is
uncertain. One measurement approach that deserves at least some mention is the laser-based
optical method. Two different techniques that utilize this technology have been proposed
to date. One proposal is to use a holographic approach to map the flow field in the
pipeline. The other proposal is to use an array of micro-laser-Doppler velocimeters
(configured in back-scatter mode) to measure gas velocity at many discrete points
throughout the pipe cross-section.
The second approach is a byproduct of technology being developed by NASA’s Jet
Propulsion Laboratory.[7] Both techniques are non-intrusive (only requiring optical access
to the gas flow inside the pipe) and are made from low-cost components (e.g., laser-diodes
or distributed feedback micro-lasers). The significance of this approach is that the flow
field can be measured in greater detail than with other methods. This means there is
potential for better measurement accuracy, even if significant distortions in the flow
field (e.g., velocity profile asymmetry or swirl) exist.
One other pending development that may be significant in the not too distant future is the
possible emergence of technologies that provide lower cost alternatives to gas
chromatography for determining gas composition and heating value. Natural gas is bought
and sold based on energy delivered per unit time (e.g., Btus per hour). Historically,
energy flow rate has been determined by combining independent measurements of flow rate
and heating value. A composition assay by gas chromatography is often performed to
calculate heating value and gas properties (required to determine flow rate). A recent
study funded by the U.S. Department of Energy[8] reviewed a number of energy rate
measurement concepts and concluded that it may be possible to accurately characterize
natural gas composition by the measurement of a small number of inferential variables
(e.g., gas sound speed, carbon dioxide concentration, nitrogen concentration, etc.). This
conclusion was based, in part, on previous GRI-funded research on the development of a new
equation-of-state model for natural gas mixtures [9]. This approach, if successful, could
be much less costly than conventional gas chromatography.
Other Considerations
Now that we have highlighted some of the recent or pending improvements in gas flow
meters, let’s look at the bigger picture. The flow meter is only part of a system
that provides gas measurement data. In addition to the flow meter, there is secondary
instrumentation (e.g., pressure sensors, temperature sensors, gas
densitometers, gas
chromatographs, etc.) that provides supplemental measurements; a computerized data
acquisition and transmission system that typically records, stores, and transmits the
measured data; and a computer network that distributes the data throughout the company.
Expect future system improvements to allow more gas measurement information to be
delivered more quickly. Also, expect greater use of embedded microprocessors in
measurement systems to help improve measurement accuracy, to speed the
transfer/distribution of the measured data, and to expand self-diagnostic capability of
the measurement equipment.
A potential benefit of improved information availability is that measurement data could be
made available to both the gas transporter and the transporter’s customers. This
scenario could reduce the likelihood of custody transfer disputes and eliminate the
requirement for redundant measurement systems (i.e., check metering) at custody transfer
points. Significant cost savings to transporters and their customers would result.
One limiting aspect of pipeline gas measurement is that the measurements are made at
relatively few points on a gas transmission pipeline network. Measurements are typically
made at custody transfer stations and other selected locations, such as near compressor
stations. Measurement sites can be many miles apart. To better understand what is
occurring in the pipeline between measurement sites, gas transmission companies are
beginning to rely on computer modeling to supplement field measurement data. These
computer models simulate the gas flow in pipelines by using numerical modeling techniques.
Measurement data acquired from the field are input as boundary conditions to the model.
These predictive models can provide a more thorough understanding of system status. This
additional information provided by the computer model can help pipeline operators increase
operational efficiency, maximize system throughput, reduce operating costs, and ensure
safe operation. Pipeline simulation codes continue to improve over time. It is anticipated
that pipeline simulation modeling will become more commonplace as the computer codes
become more powerful and easier to use.
Another critical aspect of gas measurement is industry standardization. Standardization of
measurement equipment helps minimize equipment costs, provides improved interchangeability
and commonality of hardware and software, and allows sharing of information between gas
suppliers, transporters, and consumers. Standardization can also help new technology
establish itself in the marketplace, as exemplified by ultrasonic flow meters and the
recent publication of A.G.A. Report No. 9. Expect increased emphasis on gas measurement
equipment standardization in the future.
Economic Impact Of New Or Improved Technology
The economic impact of new or improved gas measurement technology is difficult to quantify
because there are not only direct benefits, but also many indirect benefits derived from
good gas measurement. However, a 1999 GRI survey[10] of 10 interstate gas transmission
pipeline companies operating in the United States reported that the companies expected to
derive a tangible economic benefit of at least $14 million per year over the time period
from 1997-2005 from GRI-supported research and development in gas measurement technology.
Although the results of this survey do not represent the benefits to the industry as a
whole, the findings do indicate that the value of technological advancement will be
substantial.
Conclusions
In summary, as natural gas transmission pipelines continue to improve their operations, we
can expect improvements in existing gas measurement technologies and the introduction of
new measurement technologies. The focus will be on more cost-effective, accurate, and
reliable measurement systems. Real-time measurement data will also be a goal of most gas
transportation companies. Greater reliance on computer technology will be seen. Expanded
use of embedded microprocessors in measurement systems should improve measurement
accuracy, speed the transfer/distribution of the measured data, and enhance the
self-diagnostic capabilities of the measurement equipment. Computer modeling of gas flow
through transportation networks will supplement field measurement data and provide a more
accurate view of system status/performance/safety.
All of these improvements should increase operational efficiency, maximize system
throughput, reduce operating costs, and help ensure safe operation. Also, expect greater
emphasis on industry standardization. This will help minimize equipment costs, provide
improved interchangeability and commonality of hardware and software, and allow sharing of
information between gas transporters and their consumers.
We have given a general preview of the changes that are expected in gas measurement
technology in the coming years. Upcoming editions of P&GJ will present a series of
articles featuring detailed information on specific technological advancements and new gas
measurement devices. P&GJ References
Manual of Petroleum Measurement Standards,
Chapter 14.3, Part 2 - “Specification and Installation Requirements for Concentric,
Square-Edged Orifice Meters,” American Petroleum Institute, 1996.
Morrison, G.L., et al., “Comparison of
Orifice and Slotted Plate Flowmeters,” Flow Measurement Instrumentation, Vol. 5, No.
2, 1994.
Laws, Elizabeth M., and Abdel K.
Ouazzane,
“Integrated Flow Conditioning and Flow Metering,” American Society of Mechanical
Engineers, Fluids Engineering Division, Fluid Measurement and Instrumentation, Vol. 211,
1996.
Peace, Daniel W., “Turbine Meters in
Dirty Gas Applications,” Proceedings from the American Gas Association Operations
Conference, Cleveland, OH, May 1999.
Schieber, William M., “The
Accutest, A
Self-Proving Gas Turbine Meter,” Proceedings from the American Gas Association
Operations Conference, Cleveland, OH, May 1999.
“Measurement of Gas by Multipath
Ultrasonic Meters,” Transmission Measurement Committee Report No. 9, American Gas
Association, June 1998
Hoenk, Michael E., et al., “Microlaser
Doppler Anemometers,” NASA Tech Briefs, August 1997.
Behring, Kendricks A., et al., “A
Technology Assessment and Feasibility Evaluation of Natural Gas Energy Flow Measurement
Alternatives,” Final Report, Tasks A and B, U.S. Department of Energy Cooperative
Agreement No. DE-FC21-96MC33033, January 1999.
Savidge, Jeffrey L., “GRI Extended
Thermodynamic Properties Computer Program,” Gas Research Institute, Chicago, IL,
March 1989.
“Impact Derived from GRI Technologies
by Ten Interstate Gas Pipeline Companies,” Radian International LLC, Gas Research
Institute Report No. GRI-99/0021, 1999.
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Originally Posted July 9,1999
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Pipeline & Gas Journal July
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