Challenges In The Flow Measurement Engineering Study Phases
Author(s): Liv Marit Henne, Jean Monnet, Aker Kvaerner Stavanger
Abstract/Introduction:
Offshore development of marginal Oil and Gas fields can often be economically profitable if they can be tied in to existing platforms. This usually requires execution of comprehensive feasibility studies, which can often be a long and costly process. Close cooperation in a multidiscipline engineering team is necessary to assure that all possibilities and aspects of the design task have been evaluated. Integration of a new flow measurement module on an existing installation is often the simplest solution, yielding low total cost as the module can be assembled and fully tested on shore. However on many installations one is required to integrate the new equipment in existing modules. Flow measurement is a crucial element in the development of marginal fields which has to be evaluated, taking into consideration all critical aspects such as: available space, weight, location accessibility, maintenance and integration to existing metering systems. In particular, special attention should be given to the possible use of new flow measurement technologies and principles.
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Document ID:
6385BC5B
Flow Disturbances And Flow Conditioners: The Effect On Multi-Beam Ultrasonic Flowmeters
Author(s): Jankees Hogendoorn, Andre Boer, Dick Laan
Abstract/Introduction:
Over the past years a lot of experience with the five beam ultrasonic flowmeters on fiscal applications has been obtained 1, 2, 3. Ultrasonic flowmeters have gained full acceptance and customers are using the five beam ultrasonic flowmeters in a growing number of fiscal transfer metering applications worldwide. More recently, three path ultrasonic flowmeters have been introduced for custody transfer applications 4. The success of ultrasonic flowmeters can be attributed to their inherent benefits: no moving parts, no wear, low pressure drop, wide rangeability and minimal maintenance. Many National Weights and Measures Authorities worldwide have approved the use of ultrasonic flowmeters for fiscal metering. An important step forward in the acceptance of ultrasonic flowmeters is the release of a standard by the American Petroleum Institute (API) Measurement of Liquid Hydrocarbons by Ultrasonic Flow Meters in February 2005 5,6. Now that custody transfer flow measurement with multi path ultrasonic flow meters are increasingly accepted in the market, further development has been focussed on increasing robustness of installation and on simplifying calibration, commissioning and operating procedures. We have found that proper flow conditioning is an essential part of this development.
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Document ID:
C72D3DB5
Liquid Ultrasonic Flow Meters For Crude Oil Measurement
Author(s): Raymond J. Kalivoda, Per Lunde
Abstract/Introduction:
Liquid ultrasonic flow meters (LUFMs) are gaining popularity for the accurate measurement of petroleum products. In North America the first edition of the API standard Measurement of liquid hydrocarbons by ultrasonic flow meters using transit time technology was issued in February 2005. It addresses both refined petroleum products and crude oil applications. Its field of application is mainly custody transfer applications but it does provide general guidelines for the installation and operation of LUFMs other applications such as allocation, check meters and leak detection. As with all new technologies performance claims are at times exaggerated or misunderstood and application knowledge is limited. Since ultrasonic meters have no moving parts they appear to have fewer limitations than other liquid flow meters. Liquids ultrasonic flow meters, like turbine meters, are sensitive to fluid properties. It is increasingly more difficult to apply on high viscosity products then on lighter hydrocarbon products. Therefore application data or experience on the measurement of refined or light crude oil may not necessarily be transferred to measuring medium to heavy crude oils. Before better and more quantitative knowledge is available on how LUFMs react on different fluids, the arguments advocating reduced need for in-situ proving and increased dependency on laboratory flow calibration (e.g. using water instead of hydrocarbons) may be questionable. The present paper explores the accurate measurement of crude oil with liquid ultrasonic meters. It defines the unique characteristics of the different API grades of crude oils and how they can affect the accuracy of the liquid ultrasonic measurement. Flow testing results using a new LUFM design are discussed. The paper is intended to provide increased insight into the potentials and limitations of crude oil measurement using ultrasonic flow meters.
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Document ID:
6743DA37
Multiphase Flow Metering: 4 Years On
Author(s): G.Falcone, G.F.Hewitt, C.Alimonti, B.Harrison
Abstract/Introduction:
Since the authors last review in 2001 1, the use of Multiphase Flow Metering (MFM) within the oil and gas industry continues to grow apace, being more popular in some parts of the world than others. Since the early 1990s, when the first commercial meters started to appear, there have been more than 1,600 field applications of MFM for field allocation, production optimisation and mobile well testing. As the authors predicted, wet gas metering technology has improved to such an extent that its use has rapidly increased worldwide. A whos who of the MFM sector is provided, which highlights the mergers in the sector and gives an insight into the meters and measurement principles available today. Cost estimates, potential benefits and reliability in the field of the current MFM technologies are revisited and brought up to date. Several measurements technologies have resurfaced, such as passive acoustic energy patterns, infrared wavelengths, Nuclear Magnetic Resonance (NMR) and Electrical Capacitance Tomography (ECT), and they are becoming commercial. The concept of virtual metering, integrated with classical MFM, is now widely accepted. However, sometimes the principles of the MFM measurements themselves are forgotten, submerged in the sales and marketing hype.
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Document ID:
ED420DB7
Is It A Must To Add Upstream Devices For High Gvf Multiphase?
Author(s): Jianwen Dou, Jason Guo, Gokulnath R.
Abstract/Introduction:
High accuracies in measurement of the gross liquid and net oil flow rates at high GVF levels in the multiphase flow is identified as one of the most demanding needs of the industry, especially in high watercut environments. The underlying factor that decides the accuracy of the net oil flow rate measurement is the accuracy at which the gross liquid & watercut are measured and the prevailing watercut in the flow. It is an established fact that accuracies falter with increasing GVF in the multiphase flow. The purpose of this paper is to present the performance results of a newly developed Compact High GVF Haimo multiphase meter that addresses the above needs, without having to use an Upstream Separation Device for high GVF application while retaining the accuracies within +2% absolute for watercut and 10% relative for liquid and gas flow rates at 90% confidence level. while also optimising the footprint, the cost, the weight of the solution Further developmental work and trials are in progress to achieve the targeted accuracy levels under very high GVF conditions as well.
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Document ID:
0FEF188E
Reciprocity And Its Utilization In Ultrasonic Flow Meters
Author(s): Per Lunde, Magne Vestrheim, Reidar B, Skule Smrgrav, Atle K. Abrahamsen
Abstract/Introduction:
In ultrasonic transit time flow meters for gas and liquid (USMs), the flow direction, the flow velocity and the sound velocity are estimated from the measured up- and downstream transit times. At no-flow conditions, the up- and downstream transit times of such meters should ideally be the same, or the difference should be negligible. This may not be the case unless special precautions are made. In order to reduce the possibility of the meter to detect a false flow at no-flow conditions, USMs are typically dry calibrated before being installed in the field. Dry calibration (which may be made in different ways), in general involves measurement of (a) the time delays due to electronics, cables and transducers, (b) the socalled ?t-correction (for each acoustic path, also denoted zero flow offset factor), and (c) geometrical parameters. Various ?t-correction approaches may be used by different manufacturers, but these are basically similar and have the same purpose: to reduce the false flow detection and improve the accuracy at low and no-flow conditions (zero flow adjustment), without significantly affecting the accuracy at the high velocity measurements. The AGA-9 report and the API MPMS Ch. 5.8 standard both prescribe need for zero flow verification test (zero test) or zeroing the meter, for gas and liquid USMs, respectively. Advances in USM technology based on the electroacoustic reciprocity principle have provided methods for reduction or even neglection of the need for ?t-correction of USMs. That means, if the USM measurement system is reciprocal, and operated in a sufficiently reciprocal way, the ?t-correction may be negligibly small over the operational range of pressure and temperature, and irrespective of whether the transducers are equal or not. Thus, dry calibration may be simplified, since reciprocal operation may provide possibilities for auto-zeroing of the USM. However, reciprocal operation is not an obvious property of an USM. Even though the USM measurement system consisting of two transducers, electronics, etc. (e.g. an acoustic path), may be reciprocal, it may not necessarily be reciprocally operated. Control and careful design is essential to realize reciprocal operation at no-flow conditions in an acoustical measurement system such as a USM.
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Document ID:
E3D81EB9
The Use Of An Ultrasonic Transfer Reference Meter To Investigate Differences Of Two Gas Meters In Series In Fiscal Natural Gas Measurement.
Author(s): Volker Herrmann, Peter Stoll
Abstract/Introduction:
Custody transfer meter station design often requires the use of two gas flow meters: The duty meter, and the reference meter. Both meters have to meet custody transfer requirements and therefore have a low measurement uncertainty. These type of installations ensure availability, redundancy and the on-line verification of the measurement. The standard installation procedure for such meter stations includes a high-pressure calibration for both meters that normally should provide a zero difference between the readings. Even at proper station design in a few cases unacceptable deviations can be found directly after field installation of the meter. If there is not a simple reason, often the only appropriate measure is nowadays to check the high pressure calibration of the meters in an official laboratory. Even this extremely expensive and time consuming measure does not always guarantee success since possible installation effects will not be detected this way. Another possibility is to define a transfer reference meter package, using one or two different state-of-the-art gas flow meters. A transfer reference meter is considered to be a calibrated meter with the highest achievable insensitivity to installation effects and long term stability.
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Document ID:
8E4453B3
Wet Gas Metering With The V-Cone And Neural Nets
Author(s): Haluk Toral, Shiqian Cai
Abstract/Introduction:
The paper presents analysis of extensive measurements taken at NEL, K-Lab and CEESI wet gas test loops. Differential and absolute pressure signals were sampled at high frequency across V-Cone meters. Turbulence characteristics of the flow captured in the sampled signals were characterized by pattern recognition techniques and related to the fractions and flow rates of individual phases. The sensitivity of over-reading to first and higher order features of the high frequency signals were investigated qualitatively. The sensitivities were quantified by means of the saliency test based on back propagating neural nets. A self contained wet gas meter based on neural net characterization of first and higher order features of the pressure, differential pressure and capacitance signals was proposed. Alternatively, a wet gas meter based on a neural net model of just pressure sensor inputs (based on currently available data) and liquid Froude number was shown to offer an accuracy of under 5% if the Froude number could be estimated with 25% accuracy.
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Document ID:
6B618871
Three Years Of Experience Of Wet Gas Allocation On Canyon Express
Author(s): Aditya Singh, James Hall, Winsor Letton
Abstract/Introduction:
In September 2002, production was begun from the three fields that together form the Canyon Express System- Kings Peak, Aconcagua, and Camden Hills. The 9 wells from these fields are connected to a pair of 12-inch flow lines carrying the commingled wet gas a distance of approximately 92 kilometers back to the Canyon Station platform for processing. At the 21st NSFMW in October 2003, an initial report was given on the status of Wet Gas Allocation for the Canyon Express project 1. As discussed in that paper, dualdifferential, subsea wet gas meters were chosen for the task of allocating gas and liquids back to individual wells. However, since the gas from all three fields was very dry (Lockhart-Martinelli parameter 0.01) and because the operating pressures were quite high (250 bar), application of the dual-differential function of the meters yielded errors in both liquid and gas flow rates. Furthermore, as these problems were being uncovered, scale was beginning to collect inside some of the meters. Taken together, these problems produced system imbalances as great as 20%. To address the problems, one of the individual flow metering elements within each wet gas meter was chosen as the allocation meter, operating as a single-phase gas meter. Using a multi-point flow testing methodology, the response of the individual meters was characterized, with the result that a much improved system flowline balance has been maintained since its application. This methodology was approved by the U.S. Mineral Management Service for the Canyon Express field development.
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Document ID:
E6552FAC
Wet Gas Measurement In The Southern North Sea
Author(s): David S. Geach, Andrew W. Jamieson
Abstract/Introduction:
ConocoPhillips has some 18 wet gas Venturi meters currently in use in the UK sector of the North Sea. The paper covers:- The experience gained in operating these meters: The importance of gas flow calibration. Flow calibration of these meters clearly shows that the discharge coefficient value given in ISO 5167 is clearly not applicable and the discharge coefficient can vary by 2%. The effect damage has had on the discharge coefficient of one meter arising from a broken choke impinging on the meter convergent section. Calibration repeatability over time The methods used to correct the over-reading (namely Murdock, Chisholm and de-Leeuw). Flow verification tests carried out on two meters installed in the Southern North Sea. First, a sub sea meter located some 34km from the host platform. This not only demonstrated applicability of using a correct wet gas correlation but also gave valuable information on how gas, condensate and water flow along a pipeline Second, a topside meter installed on an unmanned satellite, where verification was conducted over about a year. This showed very good agreement between the Venturi meter readings and high quality separator gas and condensate meters it was tested against.
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Document ID:
B9FB101F
Lessons From Wet Gas Flow Metering Systems Using Differential Measurement Devices: Testing And Flow Modelling Results
Author(s): Cazin, Couput, Escande, Gajan, Lupeau, Strzelecki
Abstract/Introduction:
[Abstract Not Available]
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Document ID:
8FC990A4
ISO 3171 Production Hydrocarbons Allocation Sampling For Challenging Tie-Ins?? With Pressures Close To Rvp Breakout.
Author(s): Mark Jiskoot
Abstract/Introduction:
There are an increasing number of applications where sampling is required for crude oils and condensates at close to vapour breakout in production environments. These are typified where the quality measurement must be extracted/made in the ?oil? leg of a separator. The exertion of back pressure (pressure loss) on the liquid leg to expand the operating envelope is generally not acceptable due to the effect that this will have on the separator efficiency and this frequently precludes the use of normal metering technologies.
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Document ID:
6A3CFE1A
The Effects Of Water In Oil On The Performance Of Afour Path Chordal Ultrasonic Flow Meter In A Horizontal Flow Line
Author(s): T. Cousins, D. Augenstein, S. Eagle
Abstract/Introduction:
A series of flow tests were performed at the Ohio University multiphase test facility to evaluate the performance of a four path ultrasonic flow meter (UFM) in the presence of water in oil. The tests used a clear Perspex flow meter and piping, so that the flow behaviour could be observed and correlated with UFM performance. Tests were initially carried out at a wide range of water-cut (water volume fraction), in order to verify meter operation. These tests showed that at higher velocities the water was fully dispersed and UFM operation appeared normal, although the true flow rate performance of the meter could not evaluated due the the lack of a suitable reference measurement. At lower velocities, water separated and formed a river along the pipe bottom. Under some circumstances the bottom acoustic paths could fail to operate due to refraction and dispersion effects when the ultrasound encounters the oil/water interface region. Further tests were then carried out to attempt to quantify the UFM performance with water-cut in the range of 1% and 7%. For these tests, more of an attempt was made to quantify the uncertainty in flow rate measurement. At higher velocities, the combined oil and water volumetric flowrate measured by the UFM was within the experimental uncertainty of the test method. At lower flow rates, the performance of the flowmeter was degraded by water drop out affecting the lower path velocity measurement. This paper describes the hydraulic behavior and gives advice on operational limits for good flow measurement in oil/water flows. The test data shows that the conditions in which good measurement can be obtained correspond well with the API4 guidelines for good mixing in sampling applications.
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Document ID:
276B011D
Uncertainties In Pipeline Water Percentage Measurement
Author(s): Bentley N. Scott
Abstract/Introduction:
Measurement of the quantity, density, average temperature and water percentage in petroleum pipelines has been an issue of prime importance. The methods of measurement have been investigated and have seen continued improvement over the years. Questions are being asked as to the reliability of the measurement of water in the oil through sampling systems originally designed and tested for a narrow range of densities. Today most facilities sampling systems handle vastly increased ranges of density and types of crude oils. Issues of pipeline integrity, product loss and production balances are placing further demands on the issues of accurate measurement. Water percentage is one area that has not received the attention necessary to understand the many factors involved in making a reliable measurement. A previous paper1 discussed the issues of uncertainty of the measurement from a statistical perspective. This paper will outline many of the issues of where the errors lie in the manual and automatic methods in use today. A routine to use the data collected by the analyzers in the on line system for validation of the measurements will be described.
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Document ID:
357FE4CB
Well Testing Using Multiphase Meters
Author(s): Karl Herman Frantzen
Abstract/Introduction:
This paper describes one of the first major roll-outs of multiphase meters in the Middle East area. The project started in 1998 and after trial installations and technology evaluation it was decided to install a series of multiphase meters on unmanned wellhead platforms. A total of 9 meters have been installed and has presently been in service for up to 2 years. Another 7 meters will be put in service on new-built platforms. The background for considering multiphase meters as an alternative to well testing by traditional methods is The selected technology and measurement principles is described. The main experiences for the project is presented and discussed. Of particular interest is the collaboration model applied for the commissioning phase and the continuous follow-up of well test results by use of a field wide model of the production system. The most important achievements in the project has been that the frequency of well testing has been dramatically increased and the amount of oil lost due to well testing is greatly reduced.
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Document ID:
EC765048
Specification Of Wet Gas Measurement Equipment For Fiscal Allocation
Author(s): Max Rowe, Rod Bisset, Anthony Alexander
Abstract/Introduction:
In the UK North Sea new developments are increasingly utilising existing infrastructure for processing and transportation of hydrocarbons. Utilising existing infrastructure for such developments brings challenges as to how to cost-effectively allocate the produced hydrocarbons (as well as water, fuel usage, and emissions) back to each field - particularly where these fields are under different ownership. When a new field is to be accepted by a host, it is necessary to define a functional specification for the measurement equipment. This is usually documented as part of the allocation agreement. The question that needs to be addressed is: What is an acceptable measurement specification?. The ultimate answer will be one which meets standards set by relevant Government authorities and is acceptable to all parties who approve the allocation agreement. One approach, often used, is to apply standard guidelines derived from industry best practice, e.g. 1% uncertainty for a gas fiscal flow measurement. This approach has the advantage of being simple to apply, but may involve some measurements being made with an unnecessary degree of accuracy. Another approach is to undertake modelling of uncertainty in the measurement system to establish the criticality of each measurement (See for example 1). Scheers and Wolff (2) point out the need to consider the whole measurement system through to allocated revenue and propose that the optimum uncertainty of each measurement should be established by evaluating the trade-off between measurement costs and the losses and risks of uncertainty in the measurement. In this paper an extension of these approaches is applied to the Britannia facilities in which uncertainty modelling was applied to the propagation of uncertainty through the whole measurement and allocation system and was used to establish the impact on each company or fields revenue stream.
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Document ID:
BFCA5C36
Allocation - The Howe Measurement Challenges.
Author(s): Jim Tierney, Paul Ove Moksnes
Abstract/Introduction:
The Howe Field is located in the Central North Sea Block 22/12a approximately 160km east of Aberdeen in a water depth of 85m. The reservoir lies some 12 km east of the Shell operated Nelson Platform, which is situated in adjacent Block 22/11. The Howe project was initiated by Shell Exploration and Production to augment the operating life and production capacity of the Nelson platform, involving the development of an additional subset infrastructure and the installation of topside facilities. The owners of the Howe Field are Enterprise Oil PLC , Intrepid Energy and OMV . The Howe well fluids are commingled with Nelson fluids. Therefore, it is required to measure the Howe well fluids to differentiate between the fields and to determine how much money each partner is allocated. The commercial agreements have stipulated that the measurements of Howe fluids are required to be measured within an accuracy of +/- 5% of reading. In addition to accuracy constraints, it was important to minimise capex to ensure the development was economically viable. Given this, multiphase metering was considered to be a solution for allocation between the different ownerships, as opposed to traditional separator metering. This paper will present the journey of the project activity through the selection criteria, flow loop test, installation, commissioning and the first 3 months of operation of the MPFM including verification with the Nelson test separator. Detailing with careful management and engineering support how to succeed with this type of application.
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Document ID:
9883F571
Development Of Recommended Practices And Guidance Documents For Upstream Oil And Gas Flow Measurement
Author(s): Eivind Dahl, Frank Ting, Chip Letton
Abstract/Introduction:
Commercial multiphase and wet gas flow meters have come a long way in their accuracy, reliability, and versatility since their introduction fifteen years ago. Furthermore, considerable experience has been gained in how to select, test, verify, implement, maintain and use these devices in various applications. Particularly in applications that are located offshore, either subsea or topside, the use of multiphase or wet gas flow meters in some cases may be the only practical method of individual phase flow rate measurement. While the maturity and acceptance of the techniques and products has steadily improved during this period, they are sufficiently different from the traditional methods of measurement that their introduction and acceptance has at times been slow. Even experienced personnel who might use them must learn not just the distinctly new technology, but also a whole new set of concepts and terminology describing the complexities of multiphase fluid flow dynamics, and the technologies used to measure the individual flow rates. Within the major oil and gas production companies this problem has been addressed by developing courses, manuals, seminars, and other training materials. All this will bring the measurement engineers and other staff, who should have an interest in the production data, up to date with regard to how the meters work, what are their flow measurement uncertainties and limitations, what vendor companies can offer, what advantages and disadvantages are provided by each, and so on. Nowadays, as perhaps never before, producing companies and governments worldwide are working in partnership together in the production of hydrocarbons, leading to more complex infrastructures and to questions on ownership of the various oil and gas streams. In those applications which are most likely to make use of multiphase or wet gas flow meters, it is rare that a single entity is the sole owner and completely responsible for measurement. Consequently it is not sufficient that multiphase flow measurement be well understood inside one company, but that throughout the industry this understanding is the norm rather than the exception. The most common method for developing this kind of understanding through the industry is by the creation of documentation that discusses at length the various issues that must be confronted. Typically this has been done through the publication of white papers, technical reports, recommended practices, and standards.
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Document ID:
09E276C4
Estimation Of The Measurement Error Of Eccentrically Installed Orifice Plates
Author(s): Neil Barton, Edwin Hodgkinson, Michael Reader-Harris
Abstract/Introduction:
An inspection of the fiscal metering station on a large Middle Eastern gas field revealed that the orifice plates in all three 16-inch metering runs had been incorrectly inserted in their carriers and O-rings sealing the plates had been damaged. As a consequence, all of the orifice plates were eccentric within their carriers. This paper describes the subsequent investigation into this problem and the estimation of the resultant flow-measurement error.
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Document ID:
15A783F5
Density And Calorific Value Measurement In Natural Gas Using Ultrasonic Flow Meters
Author(s): Kjell-Eivind Frysa, Per Lunde
Abstract/Introduction:
Multipath ultrasonic transit time flow meters (USMs) are today extensively used by industry for volumetric flow metering of natural gas, for fiscal measurement, check metering, etc. As natural gas is typically sold on basis of mass or energy, the density and/or calorific value (GCV) of the gas is measured in addition. In current fiscal metering stations this is typically made using additional instrumentation like e.g. densitometers, calorimeter or gas chromatographs. In addition to the flow velocity and the volumetric flow rate, USMs give measurement of the velocity of sound (VOS) in the gas. The VOS is a quality parameter which contains valuable information about the gas. For example, under certain conditions the density and GCV of the gas can be derived from the VOS. This provides a potential for mass and energy flow rate measurements by the USM itself. Various approaches in this respect have been presented over the recent years, by various research groups. The present paper describes a new method for calculation of density and GCV of natural gas, from measurements of the pressure, temperature and the VOS only. That is, in the present method, no instrumentation is needed in addition to the USM itself and the pressure and temperature sensors. The method can thus be used on existing USM metering stations with only a software upgrade. Such a feature may be of interest for fiscal metering stations (e.g. for backup and redundancy) as well as simpler metering station (where density and GCV are not measured today, but where such information may be of interest e.g. for monitoring). Results for different real natural gas compositions are presented, and contributions to the measurement uncertainty discussed. The paper is intended to provide insight into the potentials and limitations of methods for calculating gas density and GCV from VOS also on a more general basis.
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Document ID:
9166E8FC
How Todays Usm Diagnostics Solve Metering Problems
Author(s): John Lansing
Abstract/Introduction:
This paper discusses both basic and advanced diagnostic features of gas ultrasonic meters (USM), and how capabilities built into todays electronics can identify problems that often may not have been identified in the past. It primarily discusses fiscal-quality, multi-path USMs and does not cover issues that may be different with non-fiscal meters. Although USMs basically work the same, the diagnostics for each manufacturer does vary. All brands provide basic features as discussed in AGA 9 Ref 1. However, some provide advanced features that can be used to help identify issues such as blocked flow conditioners and gas compositional errors. This paper is based upon the Daniel USM design and the information presented here may or may not be applicable to other manufacturers.
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Document ID:
34608454