19th international north sea flow measurement workshop 2001

Scope and Target GroupThe workshop is an vital event forpersonnel working within the field ofoil and gas measurement in the NorthSea as well as other parts of the worlddealing with petroleum technology.

With emphasis on the exchange of up-to-date flow measurement experiencewe urge to meet the needs of users,manufacturers of instrumentation andservice engineers as well as those withinterest in accurate measurement sys-tems and procedures.

The workshop is an annual event andalternates between UK and Norway.

Exihibition/SponsorsThere are today 15 registered exhbi-tors. Should you be interested tosponsor the event as an exhibitor,please contact the Secretariat forapplicable conditions.

Monday 22.10.0117.00

Exhibition rigging

18.00 Registration / Get Together

DinnerDinner is served from 1930 to 2130.

19th International North Sea Flow Measurement Workshop 2001

Program

Tuesday 23.10.01

MULTIPHASE METERING

09.00 Opening AddressChairman of Programme Committee:Øyvind Isaksen, Roxar Flow Measurement AS,Norway

Chairman: Øyvind Isaksen,Roxar Flow Measurement AS, Norway

09.05 KEY NOTE - Status and Trends onTechnology and ApplicationsEivind Dykesteen, Roxar Flow Measurement AS,Norway

09.45 1. Operational Experience withCommercial Multiphase MetersA.Mazzoni, ENI Agip Division, Italy

10.15 2. Conversion of Multiphase MeterFlowratesN.Lindeloff and K. Kreijbjerg,Calsep A/S, Denmark,H.Berentsen and V.R.Midttveit, Statoil, Norway

10.45 Coffee-Tea / Visiting the Exhibition

11.00 3. Implementation of a Multiphase Meteron AnasuriaR.Rowe, B. Elsinger and A. Hutton, Shell Expro, UK

11.30 4. Multiphase Meter and SeparatorCombination for Overall EnhancedPerformenceJ.D. Marelli,Texaco,USA

12.00 5. Operational Experiences in MultiphaseMetering ImplementationJean Paul Couput,TotalFinaElf, France

12.30 Lunch

WETGAS METERING

Chairman: Svein Neumann,Phillips Petroleum Co. Norway

13.45 KEY NOTE - Status and Trends on Technology and ApplicationsAndy Jamieson, Shell Expro, UK

14.30 6.Wet Gas Metering using Venturi Metersin the Upstream Area - A New Model for the Correction FactorJ-P.Couput,TotalFinaElf, France,P.Gajan, ONERA, France,V.de Laharpe, Gaz de France and A. Strzelecki, ONERA,France


15.30 7.Test Results of a New DesignUltrasonic Gas Flow MeterF. Huijsmans, Intromet Ultrasonics,The Neterlands,D.Vieth, Ruhrgas, Germany

16.00 8. Flow Testing a USM Outside itsPerformance EnvelopeG.J.Stobie Phillips Petroleum Company UK Ltd

16.30 9.An Ultrasonic Meter for Stratified WetGas ServiceK.J.Zanker, Daniel, USA

17.15 Social EventVisiting the car museum “Monte Carlo or Go-Carting. See reg. form.

20.00 Dinner

Wednesday 24.10.01

GAS METERING

Chairman:Trond Folkestad,Norsk Hydro ASA, Norway

09.00 KEY NOTE - Status and Trends onTechnology and ApplicationsR.Sakariassen, MetroPartner, Norway

09.40 10. On-line Comparison of the Speed ofSound at Four Dutch Metering StationsEquipped with Ultrasonic Gas FlowMetersH.J. Panneman, N.V.Netherlandse Gasunie,The Netherlands

10.10 11. Field Experience with MultipathUSMs - Ultrasonic Meter vs TurbineMeter TrailA.Niazi, Advantica Technologies Ltd, UK


11.10 12. Experience with Installations ofUltrasonic Gas Flow Meters under SevereConditionsS.E. Smørgrav,FMC Kongsberg Metering AS, Norway and Harald Denstad, Statoil, Norway

11.40 13.Temperature Changes Across OrificeMetersA. Niazi, Advantica Technologises Ltd, UK

12.10 14. Flare Gas Metering - MeasurementChallenges at HandA.A. Johannessen,Roxar Flow Measurement AS, Norway

12.45 Lunch

LIQUID METERING AND SAMPLING

Chairman:Ulf Kommedal,IKM Laboratorium AS, Norway

14.00 15.Testing a 12 Krone 5-path Altosonic VUltrasonic Liquid Flow MeterT.Folkestad, Norsk Hydro ASA, Norway

14.30 16. Experience with Installations ofSampling and Analyser Systems inSpecial ApplicationsS.K.Olson, FMC Kongsberg Metering AS, Norway

15.00 Coffe-Tea / Visiting the Exhibition

15.30 17.What is the Uncertainty of yourQuality Measurement System?J.Moreau, Jiskoot Autocontrol Ltd, UK

16.00 18. Handbook of Water FractionMeteringE.O.Dahl, R.A. Albrechtsen, Christian MichelsensResearch AS, Norway and E.Malde, PhillipsPetroleum Co. Norway

19.30 Cocktail

20.00 Workshop DinnerToastmaster: Jan Bosio

Thursday 25.10.01

ANALYSIS AND NEW CONCEPTS

Chairman: Steinar Fosse, NPD, Norway

09.00 19. Benefits and Limitation of UltrasonicMeters for Upstream Oil & GasProductionG.J.Brown, National Engineering Laboratory, UK

09.30 20. Optimisation of Flow Measurementsin a Pulsating FlowE.van Bokhorst nad M.C.A.M. Peters,TNO Institute of Applied Physics,The Netherlands

10.00 21.A Ray Theory Approach to Investigatethe Influence of Flow Velocity Profiles onTransit Times in Ultrasonic Flow Metersfor Gas and LiquidK-E.Frøysa and P.Lunde,Christian Michelsens Research AS, Norway and M.Vestrheim, University of Bergen, Norway

10.30 Coffee -Tea / Visiting the Exhibition

Chairman: Richard Paton,National Engineering Laboratory, UK

11.00 22. Using Computational Fluid Dynamicsto Investigate the Flow trough anOffshore Gas Metering StationP.Wilcox, SGS Redwood, N.Barton, NationalEngineering Laboratory,UK and K. Laing, BP, UK

11.30 23.An Experimental Derivation of anExpansibility Factor for the V-Cone MeterR.J.W.Peters, McCrometer, M.Reader-Harris and D. Stewart, National Engineering Laboratory, UK

12.00 24. Utilization of an Inline RotarySeparator as a Wet Gas MeterV.C.Ting, Chevron Petroleum Technology Co, USA

12.30 25.Wet Gas Measurement with theDualstream II - From Laboratory to FieldA.Downing and P.Daniel, Solartron ISA, UK

13.00 Closing RemarksRichard Paton, National Engineering Laboratory, UK

13.05 Lunch

14.00 Departure from Hotel to Airport

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ENI Agip Division - Operational experience with commercial multiphase meters

by

Agostino Mazzoni

ENI Agip Division 1.0 Introduction ENI Agip Division has been deeply involved in the development, testing and implementation of the multiphase technology (pumps, metering, computer codes, fluid problems) since the early 90,s. Several multiphase meters and pumps has been tested in the Trecate test loop and applied for the production, as well as one of the main transient computer codes (OLGA) has been qualified and used for the multiphase transportation system design and process analysis. At the present, in addition to the identification of the standard applications of the above mentioned components, new application fields and a more integration among the several multiphase components are evaluated. This is performed in order to optimise globally the production, with the goal to reduce the operative costs (OPEX) as well as the capital costs (CAPEX). In this view the multiphase meters play a very important role since they supply data that can be used not only to perform the reservoir management (well testing), how it occurs normally today, but also to optimise the transportation line and well management. Linking, through a iterative process, the tools (computer codes) applied to simulate these two main parts of the production plant (reservoir/transportation line), the whole production system can be optimise and a close loop, able to control the whole process, may be developed. To reach this goal the design limits, related to the slug length, hydrate formation, corrosion, erosion and wax deposition, have to be defined and the physical laws relating these fluid problems to the fluid dynamic and the fluid composition have to be known. 2.0 Summary This paper gives a synthetic description of all the main commercial multiphase meters applied world wide by ENI Agip Division, given particular emphasis to those applications quite different from the standard ones performed for well testing. For the well testing applications, two different measurement situations are reported. Indications of how the multiphase meters can be used to improve the transportation flow line and more in general the overall production plant management are also given. 3.0 Field Applications In this chapter are described the main installations of the commercial multiphase meters performed, for well testing scope and non, by ENI Agip Division up today. Others two multiphase meters prototypes (not described in this paper) have been installed for well testing in Sicily. One is installed topside on Prezioso platform and the other one on shore in the Ponte Dirillo field. The two meters have been developed in collaboration with CPR/TEA (Centro Pisa Ricerche/TEA Systems).

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3.1 Trecate Villafortuna field (Italy)

The Trecate Villafortuna field is developed mainly with three satellite areas: Trecate 2, Trecate 4 and Villafortuna 1, as it is shown in Fig. 1. A cluster with production and test manifolds, air coolers banks (production and test) and test separator is installed in each area. The average length of the well flow lines (4” and 6 “) is about 2 Km. A multiphase test loop has been built in the years 1991-92 in the Trecate 2 area to test with real fluids, multiphase meters, pumps, ejectors, novel separators and to collect fluid dynamic data for the multiphase code qualifications. A schematic configuration of the loop is reported in Fig. 2. The loop has been used to test several of the above mentioned components and at the present two ROXAR multiphase meters are installed in the loop for well testing and research scope. After an initial qualification campaign against the reference measurements the two meters has been used for the well testing. Being the two meters installed in the loop, it has been possible to verify the long term performance of them in the full operative range. For well testing scope and now also to control a multiphase pump, has been installed in the Trecate 4 area a FRAMO multiphase meter. The two applications are described more in detail in the following sections.

3.1.1 Trecate 2 The two ROXAR multiphase meters installed in the Trecate test loop have a size of 2 and 3 inches respectively. Both the meters are equipped with the standard MFI components (microwave and gamma) and venturi. The 3” meter has been installed in the December 1997, while the 2” one in May 1998. The 2” meter, after some qualification tests alone, has been integrated in a flow conditioner as is shown in Fig. 3. The two metering systems are installed in the loop in the two locations identified in Fig. 2. They can be used alone or in series for well testing as well as for fluid dynamic data collection for the multiphase codes qualification. Figs. 4-7 show standard well testing measurements performed with the 3” meter. Fig. 4 and 5 report the main measured parameters with an intermittent flow having small gas and liquid slugs. Fig. 6 and 7 report the same parameters but with a flow having large slugs. In the first case it is possible to see that the water cut (WC) is mainly constant, while in the second case the WC is fluctuating as well as the flow temperature. These WC trends are quite important for the flow lines management since they allow to collect information concerning the water behaviour along the flow line. Being, in the first case, the WC mainly constant, there is no water separation and water and oil are travelling in emulsion. Instead in the second case there is a water separation with some accumulation of the water along the flow line. Consequently in this last case there are more corrosion problems than in the first one. Figs. 8-10 report measurements performed with both the 3” and 2” meter when they were used in series, with the flow going from the 3” to the 2” meter. Fig. 8 reports the measurements performed with the 3” one and Fig. 9 those performed with the 2” meter. Fig. 10 reports the total flow rates measured by the two meters. As is possible to see from this last figure the two trends have about the same shape. This means that the perturbations at the flow line inlet are propagated through the flow line itself, about in the same way how they are generated. The discrepancy between the two measured values of Fig. 10 is mainly due to the gas flashing and gas expansion connect to the line pressure drops. These flow measurements as well as the pressure drop measurement between the two meters has been largely used to qualify the OLGA multiphase code. In Fig. 11 and 12 are reported some measurements performed with the integrated system, 2”meter/Flow Conditioner (see Fig. 3). The main function of the Flow Conditioner (FC) is to remove a sufficient amount of gas to the multiphase meter, located on the liquid stream, to assure a GVF at the meter inlet, inside its upper limit. This limit has been identify, for mostly of the commercial on line multiphase meters as well as for the 2” ROXAR meter, to be in the range 90-95%. In the FC of Fig. 3 the separated gas flow rate is measured with an orifice installed in the gas stream. The total gas flow rate of the integrated system is calculate adding to the gas measured with the orifice the gas flow rate measured by the 2”

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meter. Fig. 11 shows the measurements performed with the instrumentation in the FC, while Fig. 12 reports the measurements performed with the 2” meter during the test performed in date 25.06.1999. In Fig. 11 is also reported the reference gas flow rate measured in the loop with a turbine. The test was performed delivering only gas to the FC, with the control valve in the liquid stream close. As is possible to see from the gas flow rates comparison, there is a very good agreement between the two measurements. In Fig. 13 and 14 are reported essentially the same measurements of the two figures before, but with the test performed in date 29.06.1999. In Fig. 14 is shown the level increasing in the FC due to the gas condensation through the flow line. Since the FC free volume is a know parameter, on the base of the level increasing and time, it has been possible to calculate the condensation flow rate. This resulted to be around .35 m3/h and the GVF about 98.5% (gas flow rate about 22 m3/h; see Fig. 13). These results have shown the 2”meter/FC integrated system to be an useful tool for well testing of high GVF streams. Fig. 15 and 16 show respectively a comparison of the gas and liquid flow rates, measured with the integrated 2”meter/FC system, and the same flow rates measured with the 3” meter. The two systems were used in series and the test was performed in date 10.06.1999. The total gas flow rate measured with the integrate system has been not reported in Fig. 15 and so, a direct comparison of the measurements performed with this system against the 3” meter, is not immediate. However, from the Fig. 15 as well as from Fig. 16 is quite easy to see that in the first part of the test, until the liquid flow rate was decreased to 10 m3/h from about 30 m3/h, both the gas and liquid measurements performed with the integrated system were not in good agreement with the flow rates measured with the 3” meter. Instead after then the liquid flow rate was decreased to 10 m3/h (see Fig. 16) both the two measurements were in quite good agreement. This is an indication that the integrated flow meter is working quite well down to GVF of about 70%. 3.1.2 Trecate 4 A 4” FRAMO meter has been installed in the TR4 satellite area in the March 1997 mainly to perform the well testing of some wells having a flow rate exceeding the separator capacity. Problems with the gamma detector occurred just from the beginning and after about one year from the installation was needed to replace the gamma detector. With the new detector the meter performance was quite good up to now. Since the meter can be used in series with the test separator it has been possible to verify its performance, time by time. In the year 2000 the meter has been integrated also with a multiphase buster system to bust a well (TR19) that has not a sufficient pressure to enter into the main transportation line with an acceptable production. This integration as well as the connections to the production plants are shown schematically in Fig. 17. Since the used screw pump has a limitation on the inlet GVF (about 90-92%) and the GVF at well head was expected to exceed this limit, the multiphase meter was applied mainly to verify the gas fraction at the pump inlet. On the base of the multiphase meter measurements was possible to verify, during the commissioning tests, that the GVF at the pump inlet was inside the limit and that the oil flow rate increasing, due to the pump, was too low to justify the continuous running of the pump (see Fig. 18). In Fig. 18 as well as in Fig. 19 are reported some multiphase meter measurements connected to a plant transient due, first to the air cooler start up and then to the start up and shut down of the pump. From the two figures is quite easy to identify the several events. In this integration the meter is mainly used to define the liquid flow rate from the test separator that it is necessary to add to the well flow in order to maintain the GVF at the pump inlet into the limit. In the future, to maximise the pump efficiency, the multiphase meter should be used to control automatically the recircolation liquid flow rate.

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3.2 Ashrafi field (Egypt) This field is developed with two platforms, South West (SW) and Main Platform (MPA). From the SW platform the flow is delivered to the MPA platform through a 3 flow lines (6”, 4”1/2, 4”1/2) having a length of about 6 Km. On the MPA platform all the field production is combined and delivered to the oil centre on shore through a 16” flow line, about 17 Km long. The test separator installed on this last platform is used to perform the well testing of the entire field. In the normal operation the production of the SW is split freely among the three flow lines and the lines pressure drop is minimised. During the well testing with the test separator one of the two 4”1/2 flow lines have to be used only for the well to be tested and this brings to a flow increasing in the others two lines with a consequent increasing of their pressure drop. Due to the wells back pressure increasing there is a production reduction on the SW platform. In August 2000, a 3” FLUENTA meter was installed on the SW platform. The meter was pre-calibrated in the Trecate test loop, where the acceptance tests were performed. The field commissioning tests, to calibrate and to verify against the test separator the multiphase meter, were completed in about one week. During these tests a very important operative result was immediately achieved. In fact the real WC of the SW2 well was verified to be around 15% instead of 70% how it was measured through sampling before. This allowed, after a further verification, to stop a work over already scheduled on the well, with a lot of money saving. Given the installation configuration of the meter on the SW platform, the flow distribution among the transportation lines remains, during the well testing, about the same as in the normal operation. This allows a production gain compared to the well testing performed with the test separator. 3.3 Portfouad field (Egypt) The field is developed with two mono pod platforms, Portfouad 1 and 2. They are without test separator and a ROXAR multiphase meters has been installed on each of them for well testing. The produced flows from the two platforms are commingled through a sub sea Tie-in to a 16” sea line of about 12 Km long and delivered to the Portfouad main platform. On this last platform production and test separators are installed, but due to the high field production, also the test separator is now used as production separator. The two separators perform a three phase separation (condensate, water and gas) and the three separated phases are then delivered to the treatment plant onshore, each through a dedicated flow line having a length of about 50 Km. The wells to be tested have a quite high GVF and for this reason a venturi meter has been added to the ROXAR basic components (microwave and gamma) to improve the meter performance. The two meters have been installed since the spring 2000, but due to energy problems on the platforms their utilisation started only in spring this year. For these two applications a direct comparison with the separator is not possible, for the reason mentioned above, but comparisons with the total flow measured by the two separators are showing an acceptable agreement. 3.4 Karachaganak (Kazakstan) In this field a 6” ROXAR multiphase meter has been installed this spring. Since the meter is in series with the test separator, it is possible to verify its performance against the test separator. These comparisons are showing not a very good agreement between the two measurements and now an investigation is performed on both the measuring systems.

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3.5 Zatchi (Congo) This field is developed with three platforms (ZAP, ZAF 2, and ZAF 4). The meter is located on the ZAF 4 platform after the production manifold to measure the total multiphase flow. The ZAF 4 platform is producing through 4 wells with ESP pumps. The pressure at the multiphase meter is about 13 bar. The gas produced through the casings of the 4 wells is commingled and delivered alone to the ZAF 2 platform through a 4” sea line of about 730 m. The total pumped multiphase flow, measured by the meter, is delivered to the ZAF 2 platform through a 8” sea line. In ZAF 2 platform the wells are producing with ESP pump like in the ZAF 4 and there is a production separator used to separate the pumped flow of both the platforms. The separated gas, the gas coming from ZAF 4 as well as the gas produced through the casings in ZAF 2 are commingled to a flare on ZAF 2 without to be measured. The separated liquid (oil, water) is busted with single phase pumps and delivered to the ZAP platform where a three phase production separator is installed. The liquid phases are measured with PD meters. The distance between the ZAF 2 and ZAP platforms is of about 1.5 Km. The total liquid production as well as the oil and water production of the ZAF 2 platform are obtained as difference between the total production measured in ZAP and the liquid flow rates measured with the multiphase meter in ZAF 4. Since all the wells of the ZAF4 platform are producing with ESP pumps, the gas at the multiphase meter is quite low. The 3” ROXAR meter selected at the beginning did not give good results since the initial production rates was much lower than the minimum design rates. The original meter has been replaced with a 2” meter that now it gives quite good results. The initial verification/calibration tests of this new meter were performed with a Schlumberger mobile test separator. During these tests the meter has also allowed to set up the right speeds of the ESP pumps, with a significant energy save. This was due to the fact that the optimum pump speeds (maximum production) were lower than the originals ones.

3.6 Gabon A 3” ROXAR multiphase flow meter is installed on a platform producing with 4 wells. The meter is in series with a test separator also installed on the same platform. The GVF is quite high 70-90% and the WC quite low (5-10%). The pressure at the meter is about 13 bar. The meter performance, compared with the test separator, is not in very good agreement and a factor 0.7-0.8 is applied to the meter liquid flow rates to meet the separator liquid flow rates. At the present the meter is not in operation due to computer configuration problems. A supplier intervention is required for the next future. 4.0 Transportation flow line management improvement In addition to the applications mentioned above the multiphase flow meters can useful be used, in combination with multiphase computer codes, to perform the diagnosis and the control of the transportation flow lines. The wells flow rates, measured, possibly continuously, by multiphase meters on each well and the pressure at the flow line outlet, can be used as input to a transient multiphase computer code (OLGA) to simulate, mostly in real time, the fluid dynamic of the transportation line. From this simulation it is possible to identify the pressure and temperature profile along the transportation line as well as the flow regimes. Since the operative limits of the transportation line (hydrate formation, corrosion, erosion, maximum slug length) are depending by these parameters, it is possible to verify in real time if the flow line is operating inside the operative domain or not. If not, and some operative limits are exceeding the allowed limits, the operator can modify some boundary conditions to the transportation line (production, back pressure etc.) to maintain the flow line inside the allowed domain. When the plant operations, required to keep the flow line inside the operative domain, will be very well known, a close loop able to control automatically the flow line will be possible to develop.

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6.0 Conclusions On the base of ENI Agip Division experience acquired with the application of several commercial multiphase meters for the production, as well as with the performance tests performed in the Trecate test loop, the following conclusions can be drown: 1. The actual commercial multiphase meters can be applied with an acceptable accuracy for the

well testing measurements, if they are properly selected in type and size. 2. The actual “on line” commercial multiphase meters have accuracy limitation at gas void

fractions above 90-95% and to apply them above this range some improvements are required. 3. A possible solution to apply the “on line” commercial meters to high GVF well testing

measurements can be the integration of these meters with flow conditioners able to perform a partial gas separation, enough to keep the GVF at the multiphase meter inlet inside the limit.

4. The field calibration/verification is required not only to define the meter calibration parameters that have to be measured in field (gamma counting), but also to define the right fluid property data, required for the meter calibration. Very good PVT data are required especially at high GVF.

5. A direct measurement, with the multiphase meter itself, of the fluids (oil, water, and gas) parameters required for the meter calibration, is an auspicious.

6. To reach the above goal the multiphase meter installation configuration and the consequent steady state flow condition are very important.

7. The multiphase meters measurements, especially if update with the above mentioned fluid property measurements and possibly with the oil/water viscosity measurement, can be very important for the flow line management.

8. The multiphase meters can be useful integrate with the actual multiphase buster system to control the flow conditions at the inlet of the pump, allowing an improvement of the whole buster system efficiency.

9. For fields operating with ESP (Electrical Submersible Pump) or with gas lift, the multiphase meters could help to set up respectively, the right pump speed and gas flow rate in order to maximise the efficiency of the producing systems.

10. Flow blockages problems, quite often encountered using test separators at high WCs and relatively low temperatures, can be avoided using multiphase meters.

11. The multiphase flow meters have to be operated by qualified personnel in order to guaranty not only reliable well testing data, but also to picked up those information related to the continuous on line measurements that can be very useful for the well/flow line management (corrosion and slug control)

12. To extend the multiphase meters applications it is very important to avoid negative feedback from the field operators. For this, it is fundamental a continuous exchange of information between the operative people and the people that have the responsibility to maintain update the technology in the company as well as it is very important the quick and satisfactory support of the suppliers.

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Conversion of multiphase meter flowrates

Kristian Krejbjerg and Niels Lindeloff,Calsep A/S, Gl. Lundtoftevej 1C, DK-2800 Kgs. Lyngby, Denmark

Hans Berentsen and Vidar Rune MidttveitSTATOIL, N-4035 Stavanger, Norway

Abstract

This paper outlines the principles behind conversion of multiphase meter flowrates from meterconditions to standard conditions. It is described how the configuration of the topside separationprocess should be taken into account in the calculations. It is furthermore discussed how compositionalvariations due to fluctuations in GOR can be accounted for. This technology can also be used for onlinecalibration of the meter.

Introduction

Multiphase metering (MPM) has become technically feasible and in widespread use. The volumetricflow rates are usually required, not at the pressure and temperature conditions at the meter, but atstandard conditions. Mass transfer will take place between the phases on their way through the topsideseparation process, and the phase densities will change as a result of pressure and temperature changes.For the purpose of fiscal reporting and allocation, it is essential that the measured flow rates can beconverted accurately to standard conditions.

Simple correlations and conversion factors are insufficient, as the meter pressure and temperature inmany cases vary significantly. Furthermore the overall composition of the mixture let to the meter mayalso fluctuate, which further complicates the problem. A combination of a reliable calculation modeland access to online data is required in order to properly convert the MPM measurements.

Fluid densities and fluid phase behavior are in the petroleum industry most often calculated using thethermodynamic models referred to as equations of state (EoS). Combined with a set of mass balancesgenerally known as flash equations, the EoS models may be used to calculate phase densities anddistribution of hydrocarbons, water and production chemicals between the phases present. The requiredinput for these calculations is pressure, temperature and chemical composition of the overall mixture.The approaches discussed in the paper are based on this technology.

Flash calculation and recombination

The flash calculation distributes the components between the different phases given the overallcomposition z, pressure and temperature:

P, TOverall composition z

y, �g

x, �l

Figure 1 Input and output from a two-phase flash calculation

The output from the calculation is the molar phase amounts �g and �l and the phase compositions y andx. For each component i, in an N component mixture, the mass balance must be fulfilled:

Nixyz ligii ,1 �� (1)

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The phase densities may also be calculated using an EoS permitting the volumetric GOR to becalculated

gll

lgg

MM

GOR��

�� (2)

where Mg and Ml are the average molecular weights of the gas and liquid phases and �g and �l thephase densities. The calculated GOR may not correspont to the GOR measured, but this may be takencare of by adjusting the relative amounts of gas and liquid in Figure 1. If the phase compositions aremaintained, the system will still be in equilibrium. This means that the phase amounts can be changedto match a given GOR, as long as the phase compositions are the same as in Figure 1.

Consider Figure 2 below, where the original flash result is the molar phase amounts �g and �l. If themeasured GOR is smaller than the one calculated, one can readily tune the overall composition tomatch this GOR by adding more of the liquid phase, with the same composition as the original liquidcomposition from the flash calculation. The new phase mole fractions are:

glglmeasuredlg

glmeasuredg MGORM

MGOR��

��

��

�

� 1 and (3)

and the new overall composition can be calculated from equation 1.

y, �g

x, �l

x, �additional

Figure 2 Addition of liquid phase to match GOR

The flash calculation and recombination for a given GOR is the very basis of carrying out conversionof flow rates to standard conditions. Recombination to a measured GOR gives the correct overallcomposition, which is used as input to a sequence of flash calculations describing the topsideseparation process. Figure 3 shows two possible sequences of flash calculations to standard conditions.One is a single stage flash and the second one a six stage separator train. For both separations theproblem is to determine the volumetric flow rates of oil and gas at standard conditions with theflowrates at meter conditions as input. In Figure 3 the volumetric flow rates of oil at meter conditions isnamed MC

OV� and the volumetric flow rate of oil at standard conditions is called SCOV� .

Classical table conversion approach

The classical way of handling the description of mass transfer between phases is the black oilnomenclature as it is applied for reservoir engineering purposes. Three components are considered:

oil: May exist in the oil and the gas phasesgas: May exist in the gas and the oil phaseswater: May exist only in the water phase

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For this purpose the following black oil parameters are needed. Two sets of pressure and temperatureconditions are considered, the Meter Conditions (MC) and Standard Conditions (SC)

BO : Oil volume factor SCO

MCO

o VVB � (4)

Rs : Gas in oil solubility factor MCO

SCOinG

S VV

R � (5)

Bg : Gas volume factor SCG

MCG

g VVB � (6)

Rv : Oil in gas solubility factor MCG

SCGinO

V VV

R � (7)

Bw : Water volume factor SCW

MCW

w VVB � (8)

The volumes used in these definitions are calculated internally in the software based on the fluidcomposition and the specified temperatures and pressures. Conversion of volumetric flowrates fromMC to SC makes use of these coefficients in the following way:

Gas volume flow rate at SC:g

MCG

SMC

OSC

G BVRVV�

�� * (9)

Oil volume flow rate at SC: VMC

Go

MCOSC

O RVB

VV *��

�� (10)

Water volume flow rate at SC: w

MCWSC

W BVV�

�� (11)

Exactly how the black oil conversion factors should be generated, depends on the design of the facilityin which the multiphase meter is installed. The conversion factors will reflect the separation efficiencyof the topside separation train, and for that reason conversion factors obtained by a single stage flashfrom meter conditions to standard conditions may differ significantly from factors obtained from asimulation of a series of flash drums.

Single stage flash

Separator train

MCOV�

SCOV�

MCOV�

SCOV�

1.01 bar, 15 °C

1.01bar,15°C

1.01bar,15°C3 bar, 55°C

17 bar, 24°C

19 bar, 60°C

60 bar, 61°C

Figure 3 Single stage versus multistage separation

4

In spite of the added complexity, the separator train may be thought of as a box in which a single oilstream enters and an oil and a gas stream exit, similar to the single stage flash. This is illustrated by thedotted line in Figure 3. In both cases, a formation volume factor, BO, may be calculated using Equation(4). Consider a typical volatile oil phase from a well stream entering a multiphase meter at 100 bar and100°C. Calculating a BO factor for this fluid, taking either the single stage flash route or the separatortrain, very different BO values are obtained. The separator train keeps more components in the liquidphase, and a single stage flash may have a BO factor that is as much as twice the one from the separatortrain.

When using the table approach, the conversion factors are usuably made available to the meter as tablesin a file, where the different conversion factors are calculated in a given PT grid for MPM conditions.The meter software may use the tables to interpolate to arrive at values representative of the pressureand temperature at the meter conditions that prevail in that instance. Having chosen a reference fluidcomposition to work with, it is very important to note that such a table in principle only isrepresentative for one overall fluid composition, or, one GOR, since one GOR corresponds to exactlyone overall composition. If the meter experiences large fluctuations in the fluid mixture or the GOR,one table is needed for each overall composition to get a correct description of the flow rates. In thiscase it may be more appropriate to use an online approach as outlined the next section.

The customized Gullfaks MPM conversion procedure

The Gullfaks field is located in the northeren part of the Norwegian North Sea. A number of satellitefields have been developed with subsea wells remotely controlled from the Gullfaks platforms. Forcontinuous metering of the oil/gas/water production from the Gullfaks satelittes, multiphase metershave been installed topside at the Gullfaks A platform. 6 meters are installed for this purpose, each ofwhich is measuring the production rates from the following subsea production frames :

1. Gullfaks Sør/Brent2. Gullveig3. Rimfaks/Statfjord4. Gullfaks Sør/Statfjord B5. Rimfaks/Brent6. Gullfaks Sør/Statfjord A

The total oil production from the ‘Gullfaks satelitter’ is approximately 11000 Sm3/d. The mass flowrates reported from the multiphase meters at meter conditions are transferred to a FMC KOS centralmetering computer. This computer also handles the mass flow rates from the Gullfaks A test separator.A Calsep PVT software package installed on the computer makes it possible to calibrate a multiphasemeter against the test separator during a well test of the corresponding production frame. The testseparator mass flow rates are converted to multiphase meter conditions so that a comparison can bemade for calculation of multiphase meter correction factors.

The PVT software package initially also included a single stage flash routine for the conversion ofmass flow rates at multiphase meter/test separator conditions to standard conditions. At quite an earlystage it was, however, found that this routine did not give correct oil shrinkage factors compared tooffline quality check simulations. As a result the well test software, running on a second computer, waschanged so that the single flashed test separator standard flow rates from the FMC KOS meteringcomputer are not being used. Instead, offline calculated oil shrinkage factors have been incorporated.The standard flow rates from the multiphase meters were, somewhat unfairly, still reported using thesingle stage PVT routine. Hence, a “successful” calibration of a multiphase meter against the testseparator did not necessarily give acceptable results when looking at flow rates at standard conditions.To cope with this it was decided to replace the single stage flash routine with a multistage oneestablished based on process simulations.

The PVT software used at the Gullfaks A platform will be used as an example of an advanced onlinePVT package for calibrating multiphase meters and for converting meter flow rates to standardconditions. The PVT package is tied in with the Gullfaks process model and metering system softwareand it is therefore possible to feed information into the package and adjust the conversion calculationsto match measured data, such as a separator GOR. The PVT software includes a simplified

5

representation of the actual platform separation process. The setup furthermore allows the inputcompositions used for the conversion calculations to be adjusted on the fly to account for variations inthe GOR at the meter due to slugging. The meters are tested against the test separator on a regular basisand calibrated online based on these test separator data.

Verification of the simplified topside process

It was investigated how well the designed topside separation process described the conversion ofvolumes from meter conditions to standard conditions by comparing obtained BO values from theGullfaks algorithm with BO values obtained by simulating the whole topside processing plant inPRO/II. The simplified plan is similar to the lower one in Figure 3. Input for the PRO/II simulationswere compositional files generated with PVTsim from CALSEP A/S. The objective was to predict BOvalues within 2% deviation from the PRO/II calculations. In Table 1 below are given results for 11different fluids for BO values calculated from PRO/II, and the conversion algorithm using either asingle stage flash or a simplified process description.

Fluid No PRO/II(m3/sm3)

Single stageflash (m3/sm3)

TopsideProcess(m3/sm3)

1 1.132 1.133 1.1232 1.300 1.488 1.3203 1.178 1.214 1.1674 1.198 1.241 1.1865 1.133 1.132 1.1236 1.283 1.535 1.2827 1.100 1.087 1.0938 1.172 1.199 1.1629 1.145 1.396 1.12210 1.153 1.160 1.14111 1.168 1.186 1.158

Table 1 Bo factors for various fluids with different conversion methods to standard conditions

It is seen from Table 1, that considering the multistage separator train heavily improves the BO values,particularly for the condensates with high BO values. All the BO values are now predicted within adeviation of 2%.

The well described topside separation process could also be used in the calculation of a black oil tableas discussed above, but the online application can adjust the composition to a measured GORcontinuously.

Calibration of the multiphase meter

If measured GOR data are available from a test separator, it is possible to calculate calibration factorsfor the multiphase meter. The reference composition z is used as starting point for the calculation. Afteradjusting to the measured separator GOR by means of recombination as described above, the trueoverall composition ztrue is calculated from Equation (1).Using ztrue the true flow rates of the phases at meter conditions can be calculated given the pressure andtemperature at meter conditions. Comparing the true mass flow rates at meter conditions m� with theones measured gives the opportunity to calculate correction factors for the multiphase meter:

6

measuredgas

truegasgas m

mCFAC

,

,

�

�

� (12)

measuredliq

trueliqliq m

mCFAC

,

,

�

�

� (13)

This method is assuming the error in the measurement of the flowrates at meter conditions isproportional to the flowrate itself. The correction factors are used to correct measured meter flow rates,until next calibration.

Online calculations

Once the correction factors are known for each phase for the multiphase meter, they are used to convertthe measured flow rates at meter conditions to true flow rates:

measuredgasgastruegas mCFACm ,, �� (14)

measuredliqliqtrueliq mCFACm ,, �� (15)

The true flow rates give the GOR at meter conditions, and recombination can take place from theoverall starting composition z to give the true composition ztrue. The true composition is then used tocalculate flow rates at standard conditions considering the topside separation process.

Calibration of measured separator densities

Being able to predict phase densities at elevated pressure and temperature is essential for theconversion between mass and volume flow rates. The BO values in Table 1 are calculated fromEquation (4), showing that the conversion factors are directly dependent on densities at meterconditions. The phase densities calculated from the EoS are output from the flash calculation, anddepend on pressure, volume and composition. Liquid densities will depend on a good compositionaldescription of the heavy end of the fluid, but given the difficulties above in describing the true overallcomposition ztrue to be used in the flash calculation, the separator densities may be difficult to predictaccurately.

An accurate prediction of the density of the separator liquid requires a correct liquid composition aswell as an accurate model. The EoS contains an empirical correction term usually referred to as avolume shift parameter. If measured densities are available for the separator liquid the volume shiftparameter can be selected to match this density. If this requires an unrealistic volume shift parameter, itis seen as an indication that the assumed liquid composition deviates considerably from the actual oneand a composition tuning is performed. It essentially consists in shifting the ratio between heavier andlighter components.

In Table 2 the first column gives the oil density at separator conditions using the original compositionand the standard EoS parameters. The flash result also gives a gas density, which is kept constant,while adjusting the liquid density. Columns 3 and 4 give the lowest and highest possible liquiddensities with the tuning algorithm. The result from the tuning is an overall composition z, which at thegiven temperature and pressure splits into a gas and liquid phase in equilibrium with the desireddensities.

7

Fluid No Calculated density(kg/m3)

Lowest possibledensity (kg/m3)

Highest possibledensity (kg/m3)

1 791.1 ~710 ~8702 667.5 ~600 ~7803 760.4 ~660 ~8604 759.0 ~650 ~8705 795.6 ~710 ~8706 661.7 ~610 ~7407 827.0 ~730 ~9208 762.9 ~660 ~8809 709.4 ~650 ~79010 792.7 ~690 ~91011 756.4 ~670 ~860

Table 2 Density of oil at separator conditions (63 °C and 65 bara)

The customized conversion of flowrates from meter conditions to standard conditions, can besummarized as follows:

1. Initial reference composition from user.2. Separator test with GOR and density adjustment gives new reference composition.3. Flowrates at MPM conditions calculated from test separator flowrates.4. MPM calibration factors calculated from flowrates from 3. and MPM flowrates.5. Calibration factors used to adjust measured MPM flowrates until next separator test.6. GOR adjustment to calibrated MMP measurement carried out continuously.7. Flowrates at standard conditions from GOR adjusted MPM composition. Flash to standard

conditions through Gullfaks process plant.

Conclusion

Flow rates of a well defined composition measured at meter conditions can accurately be converted tostandard conditions. It is important to take into consideration the complexity of the topside processplant. Variations in GOR e.g. due to slugging may be accounted for by modifying the total compositointo match the GOR. Composition variations with time in the produced liquid can be dealt with byadjusting the composition of the separator liquid to match a measured density.

8

Notation

B Formation volume factorCFAC Correction factor for MPM flow ratesGOR Gas-oil ratiom� Mass flow rateN Number of componentsP PressureRS Gas in oil solubility factorRV Oil in gas solubility factorT TemperatureV VolumeV� Volumetric flow ratexi mole fraction of component i in liquid phasex liquid compositionyi mole fraction of component i in gas phasey gas compositionzi mole fraction of component i in total compositionz total composition� phase mole fraction� density

Subscripts

g gasi component il liquido oilw water

Superscripts

MC Meter conditionsSC Standard conditions

Implementation of Multiphase Metering on Anasuria 1

Implementation and Operational Experienceof a Multiphase Meter

by Rosalind Rowe, Bob Elsinger, Allister Hutton,

Shell UK Exploration & Production1

SummaryThis paper presents experience gained in the use of a Fluenta multiphase meter (MPM) on Anasuria.Initially verification was achieved by comparison with the first stage separator and testing bydifference. Following the introduction of a new third party field, Cook, separator constraints preventedthe use of testing by difference and an alternative method of verification was required. The paper goesthrough the lessons learnt in developing an MPM for use on a platform and explains how reservoirmanagement is achieved using the MPM, geochemical fingerprinting and allocation metering. Inaddition, an operational example of using the meter for well monitoring is described.

1. IntroductionThe Anasuria is a purpose built FPSO monohull vessel specifically designed to produce the Guillemot,Teal South and Teal fields in the North Sea (Figure 1). The hull was built by Mitsubishi heavyindustries in Nagasaki Japan and towed to the Amec yard at Wallsend where the topside processequipment was installed. Production commenced 5th October 1996. The vessel was designed for atwenty-year service life and it is currently projected that the vessel will remain on station for at leastten years before returning inshore for a major survey and inspection.

A Fluenta multiphase meter (MPM) was installed on the Anasuria FPSO in the rigid piping upstream ofthe swivel stack in place of a test separator for well testing purposes. The saving to the project resultingfrom using a multiphase meter in place of a test separator was £4M in Capex. The MPM was seen as ameans of introducing the latest metering as a cost-effective option on a state of the art vessel. At thetime the multiphase meter was installed on Anasuria, the technology was very new. During theconceptual design phase of the project the metering philosophy was developed and appropriate featuresdesigned into the system to provide alternative methods of well testing and for verification of theMPM. During the detailed design phase a number of minor cost reduction modifications were madewhich reduced the facility to prove and verify the MPM. The system installed is shown in Figure 2.

The meter is provided as a common facility, with each flowline capable of being manifolded to it viathe test header. As Teal South can only be routed up the test header and this is the only access route tothe MPFM, it is necessary to close in Teal South and sustain a deferment if individual wells are to betested. The only alternative is testing by difference with Teal South.

2. Operating HistoryWhen production started on 5th October 1996, there was a tremendous appetite for informationregarding well performance from Reservoir Engineering, Production Technology and ProductionProgramming. As the MPFM was new technology to everyone concerned, the performance of themeter was monitored closely by a wide cross section of disciplines within Shell including the guaranteeteam, which had been formed to shake down the post start-up problems and consisted of project teammembers.

After the first suite of well tests had been completed, several issues emerged which prevented detailedanalysis of the data.

1 Shell U.K. Exploration and Production (Shell Expro) is operator in the U.K. sector of the North Seaon behalf of Shell, Esso and co-venturers.


Figure 1. Location of Anasuria


The sheer volume of data downloaded from the meter was extremely confusing and raised morequestions than answers. As the operating conditions at the meter were different to those at the 1st stageseparator, it was not apparent what conditions the measurements were being converted into e.g.standard conditions @ 1st stage separator. In addition, errors in flow and associated parameters fromthe Fluenta MPM were investigated and it was found that the MPM had not been set up correctly forthe wells flowing through the meter on Anasuria.

Once these initial problems were rectified the flow and associated parameters from the Fluenta MPMwere used for reservoir management. However, these values did not agree with and could not bereconciled with those obtained from other metering systems on the FPSO. The MPM then failedmechanically and was taken out of service. When the MPM was re-instated on Anasuria a testprogramme was developed in conjunction with Fluenta. In January 1998 after the meter was reinstalledit was agreed that the separator metering would be reviewed to determine whether it provided a reliablebasis for checking the MPM.

Reviewing the separator metering it was found that the gas metering system was not reading correctly.The differential pressure measurement across the orifice plate was handled by an algorithm in the DCSwhich was incorrectly set up for calculating the flow at operating conditions.

A new algorithm was developed and input to the DCS for the gas metering resulting in considerableimprovement in the gas readings. Prior to a preliminary set of tests being run to compare the MPM andmetering on the separators in August 1998, all associated instrumentation on the oil, gas and watermetering on the separators was calibrated. The results showed that the huge discrepancies between theseparator metering and the MPM had reduced, the liquid results were within 15-20% and the gasbetween 10-15%. The differences between the measurements from the two first stage separators wereabout the same as those between the multiphase meter and either of the separators.

Separator A

Separator B

FE

FE

FE

FE

FE

FE

Gas Processing

Oil Processing

Produced WaterProcessing

MPM

GuAP2

GuAP43

GuAP1

TLS P1 TL P1

Swivel

Water Line

JC80157 Anasuria Well Test Schematic

Key DescriptionTLP1 Teal Production Well P1TLSP1 Teal South Production Well P1GuAP1 Guillemot Production well P1GuAP2 Guillemot Production well P2GuAP4 Guillemot Production well P4

�Copyright to FLOW Ltd all rights reserved.

Figure 2. Schematic of Anasuria (pre-Cook)


In October 1998, having established that the MPM was giving reasonable results, a more extensive testprogramme was carried out. In the tests, wells were swung between the two separators and thecorresponding increase and decrease in flows compared with the flows obtained from the MPM.

Based on the results of this well test programme an uncertainty study was carried out. This confirmedthat there were major uncertainties in the well test results due to inadequate conventional meteringequipment and the procedure of testing by difference. It was recognised that comparison between theexisting conventional metering systems and the Fluenta MPM may therefore never be very good. Asummary of the uncertainties is given in Table 1. The uncertainties associated with testing of each ofthe wells was considerably larger than users of the data had believed they would be, for example theuncertainty in the oil flow of testing Teal South by difference was +/-25%.

In verifying and understanding the accuracy of the MPM, the flow rates had to be compared with theseuncertain results obtained from the separators. Thus, it was very difficult to establish how well theMPM was performing. As a result of the confidence gained through this extensive test programme itwas agreed that the MPM would be used for well testing. However, the results of the next well testcarried out in December were inconclusive and did not agree with the separators. The meter wasremoved from the platform and returned to Fluenta. The meter was stripped down and on inspectionFluenta found that the meter had failed mechanically.

Between January and July 1999 the internals of the meter were redesigned with support from theinstrument, materials, mechanical and electrical disciplines in Shell Expro. In addition, Fluentaimproved the electronics and associated software for watercut measurement during this period. Whenthe meter was ready for assembly Shell staff went to Fluenta to witness assembly of the meter. Themeter was tested at the Christian Michelson Test rig and witnessed by the metering engineer andoperations prior to the meter being sent to Anasuria.

The meter was re-commissioned on Anasuria by Fluenta in August 1999. It was agreed withOperations that the wells flowing on the test/production header would flow through the meter for amonth prior to the well test programme scheduled for September when the accuracy and reliability ofthe meter would be assessed. During this four-week period the aim was to ensure that the flow readingsfrom the MPM were consistent and repeatable and to observe any potential system failures. The aim ofthe well testing in September 1999 was to establish whether the Fluenta MPM would be suitable foruse on the forthcoming Cook project. A summary of the operating history is given in Table 2.


Teal (dry well) Teal South Guillemot P1 Guillemot P2 Guillemot P4

Quantity m3/day 4428.00 252.61 805.06 1327.38 373.08Oil

Relative Uncertainty +/-% 1.00 25.07 26.35 10.63 50.49

Quantity m3/day 1306.74 2624.64 77.62 2473.87Water

Relative Uncertainty +/-% 6.45 9.53 193.53 9.33

BS&W Current Value % 83.8 76.53 5.52 86.90

Quantity m3/day 9887.00 1290.60 1038.25 814.45 337.05Gas

Relative Uncertainty +/-% 5.27 53.81 97.83 123.80 296.57

Table 1. A summary of the uncertainties in the oil, gas and water measurements when testing the wells using the first stage separator (results obtained following thetest programme carried out in October1998).

October 1996 First oil from Anasuria FPU

April 1997 Errors in flow and associated parameters from the Fluenta MPM investigated and it was found that the MPM had not been set up forthe wells flowing through the meter on Anasuria.

July 1997 The liner on the MPM failed and meter could no longer measure water cut

August 1997 Fluenta meter returned to Norway for the liner to be replaced.

January 1998 Fluenta meter returned to Anasuria

January 1998 Fluenta personnel visited Anasuria to check the meter, separator and MPM. The readings were not in agreement. Programme devisedto determine the conventional system uncertainties and to check the conventional metering systems were operating correctly

August 1998 Further MPM tests against separators. Reasonable results but some inconsistencies

December 1998 Fluenta advised Shell of the results from their analysis. Request to return the meter for investigation

January - July 1999 Meter examined and problems reported. Redesigned with Shell support and re-installed

August – October 1999 Meter in operational service. Two visits by Fluenta to support commissioning. Best results to date obtained

Table 2: Summary of key dates during the development of the Fluenta MPM


3. Cook ProjectIn 1999, agreements were made to process the Cook fluids. In order to process these fluids one of thefirst stage separators was to be dedicated to Cook, with all of the Shell/Esso wells producing throughthe other first stage separator (i.e. Teal, Teal South, Guillemot P1 and P2), see Figure 3. As a result amethod was required to manage the Shell/Esso wells. A study was carried out with the aim ofdeveloping a metering system to provide data for each of the Shell/Esso wells on Anasuria for reservoirmanagement. A number of options were considered for managing the Shell/Esso wells includingtracers but with slugging wells this was unsuitable. After carrying out a study to assess the options itwas recommended that the Fluenta MPM be retained for reservoir management of the Shell/Esso wellswhen Cook was in place. The purchase of an alternative MPM was considered but the results fromanother MPM would not be significantly better and we had been through considerable developmentwith Fluenta and a lot had been learnt. In addition, the results obtained from the testing in August 1999showed that the Fluenta MPM was now mechanically sound and providing consistent results.

The situation on Anasuria (a number of different wells of varying production and water cut and somewith very high water cut) was very demanding to be metered by one MPM. An additional method ofmeasurement was required to both verify the meter and understand the flow from each well.Geochemical fingerprinting had started to be used in Shell Expro to provide the percentage split ofwells by mass, this method was then considered for verification of the meter. The final result was touse the Fluenta MPM with geochemical fingerprinting and the allocation metering on the first stageseparator for verification. As part of the Cook project the first stage separator metering was alsoimproved to measure oil and gas to 3%, water to 5% providing better metering for comparison with theMPM.

Separator A

Separator B

FE

FE

FE

FE

FE

FE

Gas Processing

Oil Processing

Produced WaterProcessing

PM

GuAP2

GuAP43

GuAP1

TLS P1 TL P1

Swivel

Water Line

JC80157 Anasuria Well Test Schematic

Key DescriptionTLP1 Teal Production Well P1TLSP1 Teal South Production Well P1GuAP1 Guillemot Production well P1GuAP2 Guillemot Production well P2GuAP4 Guillemot Production well P4

Modified from FLOW Ltd. report, 1998.

Figure 3. Schematic of Anasuria (post-Cook)

Cook

M


3.1 MPM Improvements

Once the decision to use the Fluenta MPM had been made a number of improvements were identifiedby engineering and operations in order to overcome some of the problems encountered in the precedingthree years. Shell worked closely with Fluenta to ensure a satisfactory system was achieved. Inaddition, Fluenta improved the mechanical design of the meter to ensure the mechanical failures wouldnot recur.

The meter installed on Anasuria went through a rigorous set of hardware modifications, includingupdated electronics and associated software for improved watercut measurement. A well testprogramme was carried out in September 1999, which was successful in proving the meter wasoperational and the results were reliable and consistent. However, a number of additional items wereidentified to ensure effective operation once Cook was producing. These were carried out inconjunction with Fluenta and Shell and completed in time for Cook coming on line.

The following items were added to improve operator interface and operability of the meter:

• An operations procedure was developed for the MPM including input of conductivity andtemperature for each well combination.

• A procedure for periodic well tests by difference possibly on an opportunistic basis was agreed asback-up to the MPM and to ensure periodic calibration.

• Communication between the DCS and the MPM was improved so that the conductivity andtemperature could be input and a well test initiated from the console in the control room.

• A data link to PI was made available so that data from the MPM could be accessed on the beach.

• The operating envelope for the meter was established and the flow regimes where the metercannot be used were determined.

• The DP range required for the meter was identified and the DP transmitter was re-ranged.

• A service contract was set up for support of the meter to ensure immediate assistance could beobtained from Fluenta as required.

• A link was set up between Fluenta and Anasuria enabling Fluenta to see exactly what the meter isseeing offshore so that immediate support for the meter could be obtained without mobilisingpersonnel offshore.

In view of the demanding role for the MPM on Anasuria it was identified that a resource should beavailable onshore in order to analyse the data and assess the ongoing performance of the meter. It wasalso recommended that the meter be online at all times so that trending data can be obtained to help inproving the meter and to build up confidence in the meter.

3.2 Geochemical Fingerprinting

Fingerprinting of oil samples using gas chromatographic techniques has been used by geochemists formany years to help understand reservoir compartmentalisation in producing fields (Kaufman et al.,1990). The technique is based on the observation that oils from the same reservoir compartment havenearly identical fingerprints, while oils from a separate compartment usually have a differentfingerprint. The fingerprints generated from high resolution gas chromatographs (HRGC) or multi-dimensional gas chromatographs (MDGC) (Ganz et al., 1999) are usually displayed graphically aspolar starplots using peak height ratios or concentrations (Figure 4). The use of a starplot displayprovides a simple visual evaluation of the differences between oil samples. Figure 5 shows thestarplots for oils from the four wells being produced on the Anasuria FPSO. These oils were analysedusing MDGC of the aromatic compounds between C8 and C10. Various ratios of eleven aromaticcompounds are used to create the starplots.


Figure 4. Starplot fingerprints of oils are generated from aromatic compound concentration ratios in the C8-C10 rangeMulti-Dimensional Gas

1

2

37

8

6 45

3

1

24 5

6 7

8

AromaticsSaturates

H 2

ValveCARRIER GAS

AIR

FLAME IONIZATIONDETECTOR

AIR

FLAME IONIZATIONDETECTOR

Modified from Ganz et al., 1999

C8

C10


Teal South and GUA-P2Laboratory Mixes

MDGC StarplotPeak Ratios

0.90

0.95

1.00

1.05

1.10

1/1+2

1/1+3

2/2+3

3/3+4

4/4+5

5/5+7

7/7+9

7/7+8+9

8+9/8+9+10

10/10+11

10/10+12

11/11+12

100% TS

20% P2

40% P2

60% P2

80% P2

100% P2

0.85

0.90

0.95

1.00

1.05

1.10

1/1+2

1/1+3

2/2+3

3/3+4

4/4+5

5/5+7

7/7+9

7/7+8+9

8+9/8+9+10

10/10+11

10/10+12

11/11+12

Guillemot P1

Guillemot P2

Teal

Teal South

Anasuria FPSOEnd Member OilsMDGC Starplot

Peak Ratios

Figure 5. MDGC Starplots for the endmember oil samples from Anasuria. Note that thestarplots from oil samples from the Guillemot P1 and P2 are nearly identical and cannot bedistinguished.

Figure 6. MDGC Starplots for laboratory mixes using Teal South and Guillemot P2 as endmembers. Note how the mixture starplots always fall in the same order for each ratiovalue.


Of the four oils being produced at Anasuria there are three distinct starplots. The two samples from theGuillemot P1 and P2 are nearly identical to each other, while the oils from Teal and Teal South areunique. Because there are differences in these oils we can use the starplot data to help determinerelative contributions of each well in a commingled sample. Kaufman et al, 1990, showed that if twooils with different starplots are mixed together, the resulting starplot of the mixture is intermediate tothe starplots of the two oils. They utilised this conservative mixing property to determine relativecontributions of end-members in a commingled oil sample.

Figure 6 shows the starplots of a series of laboratory mixtures (by weight) using the oils from TealSouth and Guillemot P2 as end-members. At most of the ratios, the starplots of all of the mixtures fallbetween the end-members in an orderly progression reflecting the relative proportions of each mixture.Those ratios that appear to provide good mixing trends are further tested to see how well they couldpredict the relative contributions of the end-members in some additional laboratory mixes. Figure 7 isan example of one of the calibration lines from one of the ratios. The absolute peak ratio data for eachlaboratory mix sample is plotted against the relative proportion of the Guillemot P2 oil. The best-fitline used is a polynomial because the mixing of ratios is generally not linear. Because the MDGCtechnique is very reproducible the R2 of the best-fit lines is very high (>0.98) when there are largeenough differences in the absolute ratio values of the end-members. To determine the relativeproportion of an “unknown” mixture, the ratio values are plotted along the best-fit line and theproportions are read off the y-axis. In the example in Figure 7 the commingled production containsabout 60% Guillemot P2. All of the ratios are evaluated for their ability to accurately predict a seriesof ‘known” laboratory mixes and in this case seven of the ratios appeared to provide satisfactorypredictions. The average and standard deviation of all seven mixing lines is used to determine therelative proportions in a commingled production sample. Errors are generally less than 5 %.

GUA-P2 and Teal-South Two End Member Mixing LineFor one of the Starplot ratios

y = -88.2700x2 + 84.5962x - 18.7300R2 = 0.9994

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0.34 0.35 0.36 0.37 0.38 0.39 0.40 0.41Ratio Value (11/(11+12))

Mixingpercentage(%P2)

Lab Mixes

Comingled Production

Poly. (Lab Mixes)

Figure 7. Calibration mixing line for peak ratio 11/(11+12). The equation of the best fitpolynomial line is used to predict relative proportions in a commingled sample.

To determine relative mixes of a three end-member mixture, partial least squares analysis is used.Similar to the two end-member calibration a series of laboratory mixes are made and analysed.Calibration equations and coefficients for each ratio are determined and a series of ‘known” laboratorymixes are used to determine how well the model can accurately predict the correct relative proportion.Figure 8 is a display that shows how well the partial least square model predicts the relative proportionof the Teal oil in a series of laboratory mixes between Teal, Teal South, and combined Guillemot P1and P2 oils. The errors are larger in the three end-member mixtures than the two end-member mixturesbut they are generally <10%.


Prediction of Teal in the Three End-member Mixing ModelBased on Laboratory Mixes

-30

-20

-10

0

10

20

30

40

50

60

70

80

90

100

110

0 10 20 30 40 50 60 70 80 90 100 110

Actual % Teal in Lab Mixture

Predicted%TealinLabMixture

1:1 Line

Figure 8. The predicted vs actual proportion of Teal oil in the laboratory mix samplesusing partial least square analysis. The predicted values are generally within 10% of theactual values.

The Anasuria FPSO commingling provided an interesting test case to apply the geochemicalproduction allocation technique. The final commingled production was a mixture of four differentwells, but there were only three unique fingerprints among these oils. But the manner in which thesewells were commingled and the available sampling locations provide us with a way to solve for all fourwells. Figure 9 is a schematic of the flow lines and sampling locations. Since the oils from the twoGuillemot wells could not be distinguished, two different allocations had to be determined to providean answer. The allocation determined at the location #5 (Separator Outlet) would be a three end-member relative proportion of Teal, Teal South, and Guillemot P1and P2. The allocation determined atlocation #2 would be a two end-member relative proportion of Teal South and Guillemot P2commingled production. The ratio of production of these two wells can be used to back out theproportion of Guillemot P2 determined at the Separator Outlet (#5) and the amount of Guillemot P1can be determined.

Samples were collected and geochemical production allocation determined at two different times in2000. The results of these predictions are found in Table 3. The values are the averages and standarddeviations for oils collected over five days. The results compare very well to the allocation determinedby the separator well testing and Multiphase Flow Meter well testing. The errors for the Guillemot P1production are a larger percentage of the actual production than the other wells because the productionfor this well is very small and the P1 production is determined indirectly. But in general it appears thatgeochemical production allocation can be used to help determine the relative amounts of commingledoil production. One important advantage of geochemical production allocation is that it does notrequire any deferment of production, samples can be collected at any time and the results can be usedto help plan when conventional well testing is required.


Anasuria Production SchemeGeochemical Fingerprinting Sampling

Sampling Locations

#1 - Production Riser#2 - Production/Test Riser#3 - Teal Riser#4 - Separator Inlet#5 - Separator Outlet#6 - Commingle Point

GuillemotP1

GuillemotP2

Teal South

Teal

#2#5“A”

Separator

#16in. Production Riser

6in. Production/Test Riser

#38 in. Teal Riser

SeparatorInlet

SeparatorOutlet

MPFM

#6

Downstream of6 in. Prod & TestCommingle Pt.

#4

Figure 9. Schematic of the flow lines and geochemical sampling locations on theAnasuria FPSO. Sample locations #2 and #5 were used to determine the masspercentage split by geochemical fingerprinting.

4. ResultsAn extensive well test programme was carried out in September 2000 to assess the functionality of themeasurement system developed for Anasuria post Cook. During the well test programme the followingresults were used to monitor the wells.

• Results from a Shell proprietary statistical package, “Welldone”, were used during well testing todetermine the well parameters. This software reduces the well test time.

• Flow through the MPM.

• Individual oil, gas and water flows at the outlet of each phase of the first stage separator.

• Results from geochemical fingerprinting.

The final results given in Table 3 were obtained by using the results from the Teal well test and thensubsequent well test results were obtained by difference. The flow rate for Teal was obtained fromWelldone as this provides the most accurate result as a baseline. In order to compare the flow valuesfrom the MPM and the separator these needed to be converted to the same conditions, as the MPM onlyprovides flow at operating conditions at the MPM. For comparison all results were converted to thesame conditions by applying shrinkage factors determined by process modelling. The separatorprovides flow values at standard conditions and at first stage separator operating conditions.

The results from the MPM were within the accuracy of the meter. For Teal, the major producer and adry well the results for the separator and MPM were within 2%.


Separator MPM Geochemical Fingerprinting

Gross RiserBS&W

NetOil

%Split

Gross RiserBS&W

NetOil

%Split

June 2000 September 2000

Teal 5579 0% 5579 84% 5691 0% 5691 82% 80% +/- 1 81% +/- 4

TealSouth

4400 95% 220 3% 4245 95% 212 3% 8% +/- 1 6% +/- 1

Gu P1 3713 92% 297 4% 4030 92% 322 5% 1% +/- 1 3% +/- 3

Gu P2 661 21% 522 8% 868 21% 686 10% 11% +/- 1 10% +/- 1

Total 14353 6618 14834 6911

All flows given in m3 @ standard conditions

Table 3: Results of the Well Test Programme Carried Out in September 2000


5. DiscussionA number of learning points have been identified as a result of the MPM installation on Anasuria, theseinclude general learning points applicable to any new technology as well as the more specific learningpoints from the installation on Anasuria.

When a new technology is installed, co-operation between the design and operations teams is requiredto ensure it is installed in an effective manner. In addition, during the conceptual and design phases it isimportant that the specification and design philosophy are fully defined to ensure the new technology isfit for purpose. During the conceptual phase the support required to prove the technology should beidentified so that this is allowed for during commissioning and operation, additional support may berequired over and above that needed for normal operation. In order to prove a new technologyconsideration should be given to providing a means of verification. However, if an alternative means ofmeasurement is available then the new technology may cease to be used for measurement especially ifthere are teething problems.

The implementation of the MPM on Anasuria was meant to be straightforward, however, it turned outto be a development project. Firstly, rectifying the mechanical problems of the liner and subsequentlythe sealing problems. Secondly, improving the software to provide realistic water cut readings. Inaddition, the reduction of pipework in the initial stages reduced the ability to verify the MPM readingsand build up confidence in the meter. Also the effect of reducing the pipework and the addition of theTeal South well meant that apart from the Teal South well all other wells could only be tested bydifference with Teal South unless this well was closed in. Testing by difference introduces additionalerrors. The MPM has mainly been used during well testing, however, if the normal configuration ofTeal South and Guillemot P2 were continuously flowed through the MPM then some of the problemswith the meter failing would have been picked up quicker. The arrangement on Anasuria means that thedemands on the MPM are a challenge for any MPM, as there is both a combination of wells and hencewidely varying flowrates and high watercut. The MPM therefore needs to operate over a large range.

Good documentation and onshore support to the operation teams is key for successful implementationof any new device or technology. The MPM by its nature has many parameters and it is important thatthese are not changed either inadvertently or otherwise unless through a controlled environment. In theinitial stages the documentation provided for setting up and operating the MPM was inadequate. Aspart of the Cook project this has been improved and an Operations and Maintenance manualspecifically for the Anasuria installation has been provided to the platform and onshore operationsteams. In addition, in the course of development of the MPM the software was upgraded. Goodmanagement of software is of paramount importance especially during the development and updatingstages. In an offshore environment the only software available should be the operating software notprevious versions because if the system goes down there will be confusion as to which software to loadespecially with the changing shifts. These were problems encountered during the development.

Geochemical fingerprinting has been developed through the course of this work to provide masspercentage split of production for four wells, in the past this technique had only been used on twowells. Advantages of geochemical fingerprinting are:

− it can be used to indicate whether a well is still producing oil when the water cut is very high andpossibly increasing.

− If the requirement for a well test is identified because of changing production from wells,geochemical fingerprinting can be carried out to confirm this whilst authority for carrying out awell test is organised without any loss of production.

A disadvantage of geochemical fingerprinting is the delay in obtaining the results, normally the resultsare available 2 weeks from taking the sample.

The MPM has now been in routine operation for a year. Recently the meter has been used to monitorperformance of the Teal well by continuously flowing this well through the MPM. The gross liquidflowrate is being monitored to identify any decline in the flowrate which will indicate whether the wellis starting to scale. This in turn optimises the frequency of squeezing the well.


In using a MPM, it is important not to concentrate solely on absolute flowrates for each of the threephases but to look at the wider use of the information available to improve reservoir management. Indesigning a multiphase metering system, location of the meter and configuration of pipework are key tomaximising potential benefits from the meter.

6. ConclusionsIn conclusion, the installation of the MPM on Anasuria has been successful but it has requiredcommitment from both Shell and Fluenta to get a fully working system. The measurement system nowincludes the MPM as one form of measurement, the geochemical fingerprinting and the first stageseparator also form part of the measurement system and must be used as such. This measurementsystem minimises deferment whilst obtaining well test results.

The number of wells to be tested by the MPM and the widely varying water cuts and well flows place ahigh demand on the MPM, nevertheless the final measurement system has been successful.

Although the MPM implementation was meant to be straightforward it became a development projectwhich then needed to be resourced accordingly. Further work is ongoing to improve the water cutreadings.

For a dry well, Teal, the MPM and separator oil flow measurements were within 2%.

7. ReferencesKaufman, R.L., A.S. Ahmed, and R.J. Elsinger, “Gas chromatography as a development andproduction tool for fingerprinting oils from individual reservoirs: applications in the Gulf Of Mexico,”in D. Schumacher and B.F. Perkins, eds., Gulf Coast oil and gases - their characteristics, origin,distribution and exploration and production significance: 9th Annual Research conference, Gulf CoastSection, SEPM Foundation Proceedings, pp. 263-282, 1990.

Ganz, H.H., Hempton, M., Knowles, W., van der Veen, F., and Kreulin, R.,: “Integrated ReservoirGeochemistry: Finding Oil by Reconstructing Migration Pathways and Paleo Oil-Water-Contacts,”Society of Petroleum Engineers, SPE 56896, Aberdeen, Scotland 7-9 September 1999.

Jean Paul CouputTotalFinaElf

Introduction

From 91 to 96, TotalFinaElf supported and tested multiphase meter prototypes.These were qualified on onshore fields.. Since 1997 multiphase meters are considered byprojects and installed for direct multiphase flows both for well metering and fieldmetering . Several multiphase meters are now in operation in TotalFinaElf operated unitsboth on onshore & offshore locations This technology is also subsea deployed in highwater depths developments

The key issues are for such a new technology to get acceptance by projects butalso to develop long term confidence from users compared to conventional technology

Through the description of two different operational experiences withinTotalFinaElf , this paper brings users , designers and manufacturers some guidelines toapply successfully multiphase metering on field .

Four years experience with a meter 1997 - 2001

General

In this first application , the field layout comprises wells that are clustered on a wellheadplatform. The production is sent on shore through a 40 Km line. After separation, the oilis metered before custody transfer, which yields an excellent reference measurement.

The platform is unmanned. It has minimum facilities: Production manifold, testmanifold and the multiphase flowmeter. The local operator interface of the meter ishoused in the electrical room. The readings from the meter are also available on shore,through a low baudrate communication that carries all the control signals for theplatform. The valves of the test manifold are not equipped with actuators.

Multiphase meter system

The decision to use a multiphase meter was made back in 1994/1995.The multiphase meter is a Fluenta MPFM 1900VI, which consists of a

capacitance sensor, an inductive sensor, a gamma densitometer, a venturimeter and aflow computer. The velocity of the flow is determined both by cross-correlation betweendifferent electrode pairs in the capacitance sensor and by the venturi meter, whichextends the range of the multiphase meter to cover single phase liquid and annular flow,and also add redundancy to the velocity measurement in the intermediate range of gasvelocity flow (GVF). The meter is basically an instrumented pipe section, approximately1.4 m long, and with an internal diameter of 3”.

The meter has been supplied as skid mounted, complete with inlet and returnpiping, and drain, vent and drip tray for ease of calibration.

In order to limit any potential for clogging by wax, etc. within the meter itself, orin the pressure and differential pressure impulse lines, the complete instrumented pipesection has been heat-traced and lagged.

The measurement principle is first to measure the density of the flow using agamma densitometer. In oil-continuous flow (i.e. up to approx. 60 – 70% water cut), thedensity measurement is combined with a measurement of the dielectric constant of theflow using the non-intrusive, surface plate, and capacitance sensor. At higher water cut,when water is the continuous liquid phase, the mixture conductivity is measured using aninductive type sensor.

.

Operational experience gained so far

• The MPFM 1900VI was offshore commissioned in early 1997. with assistancefrom manufacturer and in-house specialists, especially for fluid parameters (oil &water density) determination. The duration of the commissioning / start up phasewas about 10 days including training for the operators.

• As no test separator was available on the offshore platform for testing andverification; a static calibration procedure has been defined and implemented.This has been successfully applied to the meter to check the meter and makediagnostics. The procedure involves isolating the meter, emptying it and filling itwith air, oil & seawater. Since the fluid properties are known, this makes itpossible to check the static response and calibration of the capacitance sensors,inductance sensor and gamma meter.

• The MPFM is continuously in operation. During the weekly visit, wells to betested are switched through the meter. A well test takes about one hour, and allthe tests are validated before being entered into the database.In between weekly visits, the MPFM is left under flowing conditions with onewell producing through the meter.The man machine interface allows simple operation of the system; operators havebeen very satisfied by the simplicity of use.

• No systematic maintenance is carried out under normal operation; verification ofperformance is done through regular follow up and comparison between wellfigures and total production.The manufacturer has been called out one times a year for calibration andreplacement of a display monitor and an electronic card on the inductive sensor.In 4 years time, 3 interventions have been carried out by the manufacturer, mainlyfor capacitance & inductance sensors calibration.

• The system has been operated successfully during 4 years without any problem.No failure has been recorded on sensors. The availability has been 100 % sincethe start up. The meter has been used during a short period of time only for liquidand gas measurements; this was due to a bias in the water cut measurementgenerated by incorrect water cut setting. This indicates that care must be takenwhen calibrating MPFM with field measurements, which are not necessarilyrepresentative. This also indicates that even in such a case, the system stillcontinues to provide data before reconfiguration or recalibration of some sensors.

• The meter has been used for continuous recording of flowrates, gas fraction, andwater hold up of wells for well behavior monitoring or for individual well test forreservoir management.

Accuracy of the meter has been checked by both daily and monthly comparisonwith terminal figures. MPFM figures for oil and water have been in goodagreement (average less than +/-5 % for oil, and +/-10 % relative for water) withfiscal figures.Yearly figures show a difference of less than 1% between reference figures andmultiphase meter figures.

A step towards multiphase metering standardization in offshore West Africa 1998 -2000

ApplicationsSix multiphase meters are now in operation on recent Congo offshore well platform bothfor well testing ( 4 wellhead platforms ) and also for field metering ( 2 platforms ) .

Each wellhead platform is unmanned. Most of them have a simplified design withminimum facilities: production manifold, test manifold , multiphase flowmeter for welltesting and in some cases a multiphase meter to measure the total production of eachplatform

Multiphase meter system

The multiphase meters concepts which have been selected are based on the MFItechnology with a very limited number of components ; the measuring part consistsbasically on microwave sensors and a gamma densitometer. The velocity of the flow isdetermined by cross-correlation in the microwave section of the meter .( Only one meteramong the six was equipped with a redundant flowrate measurement based on a venturimeter )

The meters are very small ( 0.6 m long ) ; they are installed in a vertical ( internaldiameter of 2 " and 3” )

They have been installed to by passed in order to do some static checks ifnecessary .

..

Operational experience gained so far

• Well tests are started from a Digital Control System based on each platform

• In the first months of operation , differences have been noticed between water cutmeasured by multiphase meter and laboratory results ; this problem has been solvedboth by implementation of accurate values for water conductivity .

NA302TEST

flaring

TBEM 104 - variation BSW MFI - 9/04/2000

30

35

40

45

50

55

60

11:24:00 11:31:12 11:38:24 11:45:36 11:52:48 12:00:00 12:07:12 12:14:24

labo = 46%

labo = 53%

After configuration with correct conductivity figures obtained in laboratory ,agreement between water cut determined from multiphase meter and sampling hasbeen found satisfactorily ( 90.5 % for MPFM compared to 91% for sampling )

• Cross correlation has been found to be inoperable for a limited number of wells withGVF < 10 % , flow rate cannot be determined ; one solution was to test the wells incombination with high GVF wells ( up to 90 % ) . it has to be pointed out that even ifflowrate is not available , instantaneous water and Gas fractions are still measuredand displayed .In such a case , a venturi should extend the range of the multiphase meter to coversingle phase liquid and annular flow, and add redundancy to the cross correlationvelocity measurement in the intermediate range of gas velocity flow (GVF)

Benefits• Multiphase meters without flow conditioning systems have been applied to

multiphase streams with water cut up to large range of flow conditions : WLRup to 90 % and GVF up to 90 %

• Monitoring of the multiphase flow at the wellhead eliminates the need fordedicated test lines from remote wellhead completions, as well as the need fora dedicated test separator at the processing facility. The meter replaces a testseparator in its functionality.

• Multiphase meters can be used successfully for total field metering of amultiphase flow with an acceptable accuracy

• A MPFM at the wellhead allows improved well control, and hence betterreservoir monitoring and well performance management. Extra informationcan be gained from the instantaneous feature of the measurement. Forexample, water slugs and gas slugs appear clearly in the readings of theremote wells.

• Continuous readings, instead of accumulated quantities given by testseparator, will allow diagnostics of well behavior, and total recovery wouldprobably be increased.

• The high CAPEX savings have been evaluated for each platform to somethingaround 800KUS$, compared to a test separator solution. In this application,the main savings came from the fact that the device saved the flare: theplatform has no vessels to blow down.

• This device helps in cutting OPEX as well. Despite the manually operatedvalves of the manifolds, it is possible during a one-day visit to test 2 or 3wells, thanks to the short stabilization time of the meter. When leaving, theoperator launches a « long » test that will last until the next visit. A remotedisplay allows for further analysis of the behavior of a given well.

• The Fluenta design multiphase meter has already demonstrated a highreliability ( good operation during 4 years without failure ) ; no failures aparthumidity influence on high frequency connectors have been recorded on theMFI meters themselves

• From a maintenance point of view, the meter themselves are generally lowmaintenance cost item as compared to a test separator..

Improvements & recommendations

• Due to the specificity ( " high tech " ) of multiphase meters , it is sometimesrequired to have a specific maintenance contract with the manufacturer ratherthan with a general maintenance contractor

• Detailed fluid and flow characteristics knowledge is required to select theappropriate design and implement the good parameters in the software

• In house resources are often necessary for detailed determination of fluidparameters and dedicated training of users .

• Environment ( saline humidity ) has to be considered ;technology shall bemade insensitive to such influences .

• Installation of MPFM in order to be able to carry static checks brings a lot ofinformation ( diagnostics ) in case of " troubles " ; it can be used also forperiodic validation .

• Standardization is not easy ; each case can be different ; they are " easy cases"and " difficult cases"

• Good communication between specialists , users ,project people andmanufacturer is mandatory

• Investment cost is not so critical , life cycle cost including maintenance anddifferent assistance to operations has to be considered

Conclusions

Compared to the results we are used to getting from a test separator, the figures,which are delivered by this equipment, are in the same range of accuracy. for most ofGVF ( < 90 % ) and WLR ( < 80% ) . Nevertheless higher water cut require a good

knowledge of water properties ( conductivity ) and subsequent follow up of water salinityis required Furthermore , the detailed analysis of the gas/water/oil fraction distributionallows better knowledge of the flow conditions in the gathering system and in theflowlines. During transient operations (mainly start-up operations), the increase of thewatercut allows us to improve our understanding of the well near the well bore.

Implementation of multiphase meters on field export allow to meter multiphasefield production for allocation .

This experiences demonstrates that the MPFM can be reliable solutions for welltesting , well monitoring and field metering

Four and a half years life time without failure for some meters shows thatmultiphase metering is now compatible with very demanding subsea and high waterdepths applications:

These first success in our company have been possible through a positiveinvolvement of all people ( project people, specialists, users) from design anddetailed studies to operations . But further standardization do require repeatablesuccessfully cases and .a strong confidence of users based on a number of variousapplications .

In TotalFinaElf , we try to develop such confidence through a rigorous selectionof technology and applications . Long term reliability , simplicity and operabilityincluding understanding are mandatory

Support of manufacturers and common understanding of problems will also becritical

Acknowledgements

The author would like to thank all people who have contributed directly or indirectly toimplementation and improvement of multiphase meters .Thanks are particularly due toHubert Prouvost , Michel Douat and Michel Deixonne .

1RUWK�6HD�)ORZ�0HDVXUHPHQW�:RUNVKRS��2FWREHU��

1

Wet Gas Metering with Venturi meters in the upstream area :Further results for the correction factor.

J. BOKO1, J.P. COUPUT2, J. ESCANDE3, P. GAJAN1, A. STRZELECKI1,

1 Office National d'Etudes et de Recherches Aérospatiales (ONERA),Département Modèles pour l'Aérodynamique et l'Energétique (DMAE),Toulouse, France@mail : [email protected], [email protected]

2 TOTALFINAELF, Pau, France,@mail : [email protected]

3 Gaz de France (GDF), Direction de la Recherche(DR), Pôle Métrologique et Matérieldes Réseaux (MMR),Alfortville, France@mail : [email protected]

Abstract : Since a few years now, the need for accurate and reliable on line metering of wetgas is arising for fiscal and allocation purposes when different partners sharesubsea or topside installations. TOTALFINAELF, Gaz de France and ONERAhave been collaborating on that topic for 4 years. Basic researches were performedon a Venturi meter in order to improve the knowledge of the flow phenomenawhich take place between the upstream and downstream taps. This paperdescribed the analysis of results obtained at atmospheric pressure which point outthe influence of the flow patterns on the metering accuracy. From these results afirst law is deduced which takes into account the size of the droplets and thedistribution of the liquid phase between mist and annular.

1 Introduction

In a previous paper [ 1 ], we defined the applications of the wet gas metering and theiraccuracy requirements. This presentation showed that a need for a direct two phase flowmetering exists in order to reduce the costs of production and/or to be applied for high waterdepth subsea applications. In parallel, this analysis indicated that the new equipments shouldbe designed to be reliable, tractable and that, in some domains (allocation, subsea metering),their accuracy on gas flowrate would be around 5% and in some cases as low as 1.5%.

In the last decade, a lot of meters already used for dry gas like vortex meters, ultrasonicsystems and differential pressure systems have been tested and used in wet gas environments.Today Venturi meters are evaluated in more details because the technology has been alreadyused for topside and subsea applications.

In this paper, we present the new results obtained by ONERA , TOTALFINAELF andGDF on the metering of wet gas with a Venturi meter. We analyse the influence of the twophase flow characteristics on the correction factor used to deduce the true gas flow rate fromthe ∆P measurements.

2 Flow rate measurement of a wet gas by means of a Venturi meter.

For the measurement of two-phase flows by means of Venturi systems, the mainapproach is to define a correction factor depending on the flow characteristics in order to


2

calculate the actual flow rate of gas and liquid in the pipe. These corrections use empiricalcorrelations derived from orifice or Venturi measurements.

If W3∆ is the actual differential pressure measured on the flow meter with a two-phase

flow, then the total mass flow rate PW

4 will be :

WWWW'PW 3=3G

&4 ∆=∆−

= ρρβ

επ��

�

�

� �

�

The apparent mass flow rate of gas will be :

tgmgs P2ZQ ∆= ρ

In fact, the actual mass flow rates of gas are :

mtggmg QxP2ZQ ⋅=∆= ρ

Thus, we can define the multipliers :

g

mgsmg

g

t

mg

mgsg

QQ

P

P

Q

Q

Φ=

∆∆

==Φ i.e

Different correlations can be found in the literature. For an orifice plate in a horizontalpipe, Murdock[ 2 ] obtained the following correlation :

�� +=Φ ;J

where X is the Lockhart-Martinelli parameter defined by :

O

J

O

J

[

[;

ρρ−=

Φ

Φ= �

In this expression, the mass flow ratio x is defined by :

POPJ

PJ

44

4[

+=

Chisholm[ 3 ] gives another expression obtained from wet steam measurements withorifice :

�� ;;J ++=Φ

More recently, De Leeuw[ 4 ] has developed a new expression from the analysis of a database collected in full-scale multiphase flow test facility with Venturi meters. In these tests, thepressure varied from 15 bar to 90 bar and the Gas Volume Fraction from 90% to 100%. Intheses conditions, the Lockhart-Martinelli parameter varies from 0 to 0.3. He observed that

the correlation depends on the Froude number Frg (= gl

gg

gD

U

ρρρ−

) and he proposed the

following expression for the multiplier parameter, derived from the Chisholm expression.


3

( ) ��H��Q

��Q

&

;;&�

J)U��

Q

O

J

Q

J

O

��

J

..

....

��DERYH�QXPEHU�)URXGH�IRU�

��WR��EHWZHHQ�QXPEHU�)URXGH�IRU�

��H[SUHVVLRQ�WKLV�,Q

��:LWK

−⋅=

=

+

=

+⋅+=Φ

ρρ

ρρ

In these different expressions, the flow patterns upstream of the meter is only indirectlytaken into account in the De Leeuw correlation through the Froude number variations.

3 Study methodology

The level of uncertainty associated with the use of wrong correction factors lead us todevelop some knowledge and understanding of Venturi behaviour in presence of differentflow patterns [ 1 ].

Experiments and numerical simulations have been developed with ONERA todetermine influence of the flow pattern characteristics (liquid phase distribution, droplet size,liquid film thickness) on metering errors and available correlation.

The work is organised in three steps :

• Low pressure investigations (experiments + simulation)

• Extrapolation to field conditions by simulation

• Validation of simulation results through tests on an industrial site or on highpressure loops.

The first step that is useful is to perform a detailed analysis of the phenomena with aprecise measurement of the flow characteristics. In parallel, these experimental results allowvalidation of the flow simulation approach.

In the second step, the numerical approach allows the prediction of the behaviour of themeter submitted to the actual flow conditions.

In the last step, tests performed in high pressure conditions validate the results obtainedduring the second step.

In this paper we present the on going work performed from the experimental andnumerical approaches at low pressure.

4 Experimental set up and flow conditions

4.1 ONERA wet gas loop

The wet gas tests are carried out on the ONERA experimental flow loop[ 5 ].The gas flow (air)is produced by means of high pressure tanks. The gas flow rate is controlled by a sonic nozzlelocated upstream the test section. It varies from 0 to 650 Nm3/h. The mass flow rate of liquid(water) can be varied from 0 to 250 l/h. This loop can be used from atmospheric pressure to5 bar.


4

The flow loop is composed of:

• an horizontal section ( 25 pipe diameters (D = 100 mm) long ),• a flow conditioner,• a liquid injector which can produce different types of two-phase flows,• a test section where the device under test ( venturi meter or other systems ) is located• a separator to recover the liquid.

The test section can be placed following three different pipe work orientations, i.e. horizontal,vertical upwards or vertical downwards.

A Venturi meter with a beta ratio equal to 0.6 has been tested. The upstream internaldiameter is equal to 100 mm. Two models have been designed, one in metal for pressuremeasurements, and the other in Perspex for flow visualisation or optical measurements.

4.2 Flow pattern

Several flow configuration and flow rates can be used to vary the liquid fraction, thedensity ratio, the droplet size and the ratio droplet/film.

The two first parameters are fixed either by controlling & measuring individual flowrates of gas and liquid or by controlling the pressure.

Flow pattern morphology is measured in situ upstream the meter under test on theONERA gas loop. The main flow characteristics are size and velocity distribution of droplets,liquid flow rate and repartition between dispersed and annular flow.

The repartition factor f (f = mass of liquid droplets/mass of liquid) is determined fromthe simultaneous measurement of liquid mass flow rate injected in the pipe and liquid massflow rate flowing on the wall.

For the disperse phase, the measurements are performed with a granulometer based onthe Phase Doppler Analysis (Aerometrics) which provides at different points, the histogramsof velocity and droplet size. In our case, the measurements are performed at 22 points locatedon two orthogonal diameters (horizontal and vertical respectively). From this size histogram,it is possible to calculate some average values. For the droplet size distribution, differentaveraged diameters can be deduced representative of surface exchange, mass interaction etc…In our case, we use a d30 mean diameter defined as follows :

3

1N

1i

3i30 d

N

1d

= ∑

=

where di corresponds to the diameter of the individual droplets.

For this study, the flow characterisation has been performed for three gas looparrangements which permit to obtain, for the same gas and liquid mass flow rate, differentflow characteristics.

In Figure 1, we plot an example of droplet velocity profile obtained upstream of theVenturi meter. This profile is compared with a power law describing the velocity distributionin a fully developed turbulent pipe flow. We can observe that, in this case the flow issymmetric and that the droplet velocity profile follows quite well the fully developedconditions. Note that, in some configuration the accordance between the droplet velocityprofile and the power law is not so good. In particular in some pipe configurations a flow


5

asymmetry can be observed. Figure 2 shows the radial distribution of the droplets size for oneflow case (Qvg = 360 Nm3/h, Qvl = 54 l/h).

2nd configuration :650 Nm3/h

0

0.2

0.4

0.6

0.8

1

1.2

1.4

-0.5 0 0.5

r/D

Up/

Uo

54l/h 156l/h 258l/h Power law

Figure 1 : Droplet velocity profile obtained for the second pipe arrangement.

360 Nm3/h ; 54 l/h

0

25

50

75

100

125

150

175

200

-0.5 0 0.5

r/D

dg(

m)

1st configuration 2nd configuration 3rd configuration

Figure 2 : Radial distribution of the droplet size obtained for different pipe arrangements.


6

In previous papers, we have noted that the momentum exchange between the dropletsand the gas flow is defined by a non dimensional number, the Stoke number which comparesthe response time of the droplet τd with a characteristic time τg of the air flow.

g

dStoττ

=

If the droplets are only submitted to drag forces, their response time is :

µρ

τ⋅

⋅=

18

d 2dl

d

In our case the characteristic time of the flow corresponds to the time need for a gasparcel for flowing through one pipe diameter :

0g U

D=τ

In figure 3, we plot the variation range of our installation in term of Stoke number andf factor.

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Figure 3 : Stoke number versus f factor obtained on the ONERA loop.

5 Influence of the two phase flow characteristics on the flow ratemeasurements

The raw data obtained during this study are plotted in Figure 4. We notice that, for asame flow condition, a variation of 5% of the effective correction factor has been measuredbetween the different pipe arrangements. By comparing these results we observe that thesevariations depends on the gas mass flow rate. In particular, they become less important whenthe bulk velocity increases.

In order to interpret these results, it is necessary to take into account the correspondingvariations of the f factor and the Stoke number. From this analysis, we deduce that thecorrection factor is higher when the amount of liquid flowing as droplets increases. Atcontrary, we observed that this factor augments when the Stoke number decreases. Thistendency was yet obtained from flow simulation presented in a previous paper[ 5 ].


7

These conclusions are clearly illustrated by the Figure 5 where we plot the Φg factorwith respect to the f.X product for different ranges of the Stoke number. In this figure, the f.Xproduct is the Lockhart Martinelli coefficient calculated only on the liquid mass flow rateflowing as droplets. This figure shows that for Stoke number greater than 2, the correctionfactor is not greatly influence by this parameter.

In order to collapse these different curves, we looked for a relation which permits todescribe these observations. In Figure 6, we compare the expression found to ourexperimental results. We can observe that most of the point follows the curve. Neverthelessthe tendency obtained during this study must be confirmed. In particular the influence of thepressure must be taken into account.

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Figure 4 : Raw data obtained for the different flow cases

6 Conclusions

This paper presents the new results obtained on basic researches focussed on theinfluence of liquid phase on a Venturi meter. This work permits to link the flowcharacteristics to the ∆P variations observed on the meter.

In a first step, we analyse the inlet two phase flow in terms of droplet size and velocityand distribution of the liquid phase between the mist and annular regions. During theseexperiments, we modify the pipe arrangement in order to obtained for a same flow condition(mass flow rates of gas and liquid) different flow patterns (droplet size and liquiddistribution).

In a second step, we measure for the different cases the ∆P variations induced by theliquid phase.

The analysis of these results shows that the ∆P variations are linked to the amount ofliquid in the mist zone. In parallel, we notice that the influence of the droplet increases whentheir response time is low compared to a characteristic time of the gas flow. From theseobservations, we looked for an expression which takes into account the dynamic response ofthe droplet characterised by a Stoke number and the liquid distribution in the pipe. Themathematical expression obtained permits to collapse our results with an accuracy better than2 % for most of the points. Nevertheless, it is deduced from a limited number of resultsobtained at the atmospheric pressure and it is now necessary to extend its validity domain tohigher pressure.


8

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Figure 5 : Φg coefficient with respect to the X.f product. Influence of the Stoke number

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Figure 6 : New relation obtained from our experimental results

7 References

[ 1 ] Couput J.P., Gajan P., De Laharpe V, Strzelecki A., Wet gas metering in the upstream area, Needs,applications & developments, 18th North Sea Flow Measurement Workshop, Perthshire, Scotland, 2000

[ 2] Murdock J.W. : Two-phase flow measurements with orifices, Journal of basic engineering, Trans. ofASME, pp. 567-582, 1962.

[ 3] Chisholm D. : Two-phase flow through sharp edged orifices, Journal of Mechanic Engineering Sciences,vol. 19, N°3, pp. 128-130, 1977.

[ 4 ] DeLeeuw H. : Venturi meter performances in wet gas flow, B.H.R. Group 1997 multiphase, pp.. 567-582,1997

[ 5 ] Couput J.P., De Laharpe V, Gajan P , Strzelecki A., Behaviour of Venturi meters in two-phase flows -17th North Sea Flow Measurement Workshop - October 1999

1

TEST RESULTS OF A NEW DESIGN ULTRASONIC GAS FLOW METER

Dr. Detlef Vieth, Ruhrgas AG, Essen, Germany Geeuwke de Boer, Anton Buijen van Weelden, Floris Huijsmans, Instromet Ultrasonics,

Dordrecht, The Netherlands

Abstract These days, ultrasonic gas flow meters are readily accepted for custody transfer measurement. Successful application of these kind of meters in turn drives the technology, resulting in new design concepts being implemented. As part of various new designs aiming to improve meter performance and the economics of fabrication, Instromet have developed a new meter featuring – among other characteristics – a reduced bore. In addition, a special variant was designed for wet gas measurement. In order to verify the performance of the new design concepts, Instromet teamed up with Ruhrgas AG for a series of perturbation tests with distorted flow profiles. These tests were carried out at the “HDV Lintorf” test facility in Germany, owned by Ruhrgas. This paper discusses the results of these tests and compares them to results obtained with the conventional design of this meter. In addition, there is a short description of the techniques used in high-pressure gas metering at Ruhrgas along with an overview of present and possible future needs for ultrasonic gas meters in large high-pressure networks. Introduction Ruhrgas AG is Germany’s leading gas merchant company. As a private-sector enterprise, it provides secure, economic gas supplies from foreign (83%) and domestic (17%) sources based on long-term purchase contracts. Customers include foreign and German gas merchant companies, local distribution companies, power stations and industry. Last year’s total gas sendout was 50.6 billion m³. The company’s supply infrastructure comprises more than 10,700 km of pipeline (including pipelines owned by joint venture companies), 26 compressor stations and numerous company-owned and rented underground storage facilities with a total working gas volume of around 4.8 billion m³. Together with third-party pipelines, Ruhrgas monitors a network totalling some 12,000 km. These figures indicate the importance of gas metering for Ruhrgas. Together with the services provided to other companies, Ruhrgas monitors more than 2,000 gas metering stations for their metrological performance. At larger metering stations there are often two independent meters installed in series. The philosophy behind this ‘back-up metering’ is to have two meters employing different measuring principles to detect long-term changes of the main meter. So far, back-up meters have been mostly vortex meters, but more and more ultrasonic meters are now being used at new stations and in station retrofits. Back-up metering is the most likely installation case for USM in the Ruhrgas network. One interesting example of a different philosophy is Gasunie’s delivering station “Oude Statenzijl” on the Dutch/German

2

border, which is used for supplies to Ruhrgas. This station will be equipped with several meter runs each with two USM installed in series to allow bi-directional measurements. Since the same measuring principle is employed in this special case, extensive experimental investigations were performed at the high-pressure test facility in Westerbork to ensure that possible influences caused by the upstream piping are kept to a minimum. Generally, all meter types eligible for installation in the Ruhrgas network – i.e. meters which either have PTB approval for fiscal metering or are about to obtain approval – are tested at Ruhrgas for internal approval. The investigations focus mainly on meter sensitivity to upstream flow perturbations. The meters are tested with high-pressure natural gas downstream of bend configurations or regulators. The criterion for Ruhrgas approval is essentially the criterion for turbine meters according to ISO 9951, which requires the additional errors due to flow perturbation to be within 1/3 of the maximum permissible error (i.e. within +/-0.66% below 20% of meter capacity and +/-0.33% above 20% of meter capacity). These tests are performed in close co-operation with the manufacturers. High-pressure test facility “HDV Lintorf” Apart from the well known pigsar test facility, which has been the German national standard for a cubic metre of high-pressure natural gas since October 1999, Ruhrgas operates a second high-pressure test facility known as “HDV Lintorf”. This facility is used for testing gas meters, valves and regulators at flow rates between 100m³/hr and 8,000 m³/h at pressures ranging from 10bar to 45bar using natural gas (with a maximum volume flow rate at reference conditions of approx. 100,000 m3/hr). The Lintorf facility is designed to simulate ideal flow conditions as well as flow conditions which are typical of fiscal metering stations such as multiple-bend configurations. The main activities concern R&D projects for Ruhrgas, internal meter type approvals and services for other companies. The test facility (Figure 1) is arranged in a bypass of a pressure regulating station. The pressure and flow rates are adjusted using a regulator and a flow control valve. The gas first enters the 5 parallel reference meter runs which are equipped with orifice plates. A turbine meter is installed upstream of the orifice meter runs for comparison purposes. For the tests presented here, a second turbine meter was installed downstream of the test section. The orifice meters are individually calibrated at the Delft Hydraulics Laboratory water test facility. Thus for each meter run and each orifice plate, individual calibration curves for the discharge coefficient, Cd, are used, giving a maximum uncertainty for Cd of eCd = �0.22% (2�). The combined measurement uncertainty of the test meter installed in the test section and the reference meter, i.e. the uncertainty of the meter deviation or meter error, strongly depends on the differential pressure and the number of orifice lines in operation. It is between eQt = �0.26% and �0.4% (2�, the latter value represents the rare situation in which one metering line is in operation and flow rates are low). As part of the recent GERG intercomparison campaign [1] of the European high-pressure test facilities, it was shown that the repeatability and reproducibility of the HDV Lintorf facility are as good as those of the other European facilities. The metering differences between Lintorf and the other test rigs are well within the above-mentioned metering uncertainties.

3

Figure 1: The HDV Lintorf high-pressure test facility

Test Meter The meter under investigation was a 8’’ Instromet Q.Sonic-3 Compact. This meter is a relatively new variant of the existing Instromet Q.Sonic-3 with the following two major improvements:

- Modified meter body: no welded transducer pockets, newly designed transducers are installed in special casings directly on the meter body; see Figure 2. The operating frequency of the transducers has been changed to 200 kHz.

- The inner diameter of the meter has been reduced in order to minimise possible influences of perturbed flow profiles through the acceleration of the flow within the meter; see Figure 2. A contraction and expansion at the inlet and the outlet of the meter ensure smooth inward and outward flow. (Figure 2 also shows the configuration of the three paths: The two double-reflection paths, also called “swirl-paths”, cover the near wall region of the flow profile, the single bouncing path leads through the pipe center line).

A more detailed description of the new meter and first test results was given in [5]. The first improvement should make manufacturing of the meter easier and thus to make the meter less costly.

4

Bottom line

y

xz

Bottom line

y

xz

Figure 2: New design of the Instromet Q.Sonic-3 USM with its path configuration, co-

ordinate system as in Figures 3, 4 The second improvement should make the meter less sensitive to flow perturbations. This was demonstrated by CFD calculations. The flow downstream of a single 90° bend was simulated using the CFD software Fluent. 10D downstream of this perturbation, the deviation in the new Q.Sonic-3 design was lower than in the old design; see Figure 3. One can see that the dent, which is typical of 90° perturbations, becomes smaller in the accelerated flow. Moreover, the transverse velocity components, i.e. the secondary flow, become smaller. This effect indeed has a positive effect on the metering behaviour, as will be shown below. Instromet are planning to make further improvements to this meter for wet gas metering. These will include a slight change to the path configuration in order to avoid effects of liquid deposits on the path reflections. However, it is unlikely that these changes will in any way influence the conclusions resulting from the tests described below.

5

Figure 3: Effect of flow acceleration inside the meter on the perturbed flow profile

downstream of a 90° bend as shown in Figure 4, left side, calculated via CFD simulations with Fluent; left: without contraction; right: with contraction. Top graphs: profiles in main flow direction; bottom graphs: transverse velocity components looking against the flow. Co-ordinate system according to Figure 4.

Test Programme The meter was tested under the following conditions:

1. Basic test (25D undisturbed upstream length) on pigsar at 17 and 30bar. The meter was calibrated with respect to the 17bar results of pigsar.

2. Basic test (43D undisturbed upstream length) on Lintorf at 10, 25 and 40bar,

3. Test 11D, 15D and 20D downstream of a single 90° bend configuration,

4. Test 11D and 20D downstream of a double-bend-out-of-plane configuration. The configurations are shown in Figure 4. Figure 5 shows the perturbation test configuration involving the double bend out of plane. Most perturbation tests were performed at 10bar, but some were also performed at 40bar to investigate the Reynolds number influence. The radius of curvature of the bends used was 1.5D.

6

xz

y

xz

y

Figure 4: Test configuration; Left: Basic tests and single 90°-bend tests;

Right: double-bend-out-of-plane configuration The tests at 11D were also performed with the meter turned 90°, 180° and 270° around its axis in order to investigate the influence of the meter’s azimuthal position with respect to the perturbation. After meter calibration on pigsar, the parameters of the USM remained constant. Log files were taken for all cases. The pulse output of the meter was used for all tests. Although the test meter has an maximum flow capacity of 2,500m³/hr, which corresponds to a mean gas velocity of 27m/s, the meter was treated as a G1000 during the tests with a maximum capacity of 1600m³/hr, which corresponds a to mean gas velocity of 15m/s at the meter inlet. The reason for this was that the maximum flow velocity in Ruhrgas facilities is in the order of 15m/s. Secondly, as already indicated above, the most common installation position of this meter is the back-up position upstream of a gas turbine meter, which has the aforementioned maximum flow rate.

Figure 5: Test set-up for the double-bend-out-of-plane configuration

7

Results Figures 6 to 10 show most of the test results. In these graphs, the term ‘deviation’ describes the relative difference between the test meter indication and the facility’s reference meter indications. The reference value for the abscissa is Qmax = 2,500m³/hr. Tests under basic conditions Figures 6 and 7 show the meter deviations. The results can be summarised as follows:

- The basic tests for 10 and 25bar were performed at the beginning and at the end of the test programme with a time period of about 1 month in between. Figure 6 shows the good agreement between both curves, i.e. the meter remained stable during the tests.

- The deviations between the tests on pigsar and at Lintorf in the order of magnitude of 0.2% are well within the measurement uncertainties. This value is only slightly different to the usual test rig difference obtained in numerous intercomparisons between pigsar and Lintorf. This small difference is due to the different installation conditions at both facilities: At pigsar a tube bundle flow straightener was installed 25D upstream of the meter.

- Figure 7 shows the results for different operating pressures. The pressure influence becomes larger at lower flow rates. The mean difference between the maximum and minimum pressure is in the order of 0.3%. The influence of the operating pressure is actually lower due to the fact that normally the meter is calibrated and parameterised on the calibration facility for the scheduled pressure range. In this case this was done on pigsar for pressures around 10bar. Setting the parameters according to the high pressure would have led to lower differences between the 10bar and the 40bar error curve.

Basic ("undisturbed") configuration

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Figure 6: Deviation curves for the configuration with more than 40D undisturbed pipe flow

upstream of the meter: Lintorf vs. pigsar results and initial vs. final curves at Lintorf.

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Figure 7: Deviation curves for the configuration with more than 40D undisturbed pipe flow

upstream of the meter at different operating pressures Perturbation tests Figures 8 to 10 show the differences between the meter deviations obtained under basic conditions and those obtained under perturbed conditions (“deviation from basic = Fperturbed - Fbasic”). The main results are:

- Most test points are within the +/-1/3 limits of the maximum permissible error. For the slightly higher deviations shown in Figure 8, further investigations are underway to obtain a complete picture.

- The influence of the double-bend-out-of-plane perturbation is negligible; see Figure 9. Due to the two swirl paths of the meter, the corrections for the swirl perturbations work just as well as for the Q.Sonic-5 meter, which has two single reflecting paths more.

- Figure 10 shows the results for the meter positioned 10D downstream of the perturbations, and turned around its axis by 90°, 180° and 270° (clockwise against direction of flow, with the piping as shown in Figure 4). The left graph shows a significant shift of about -0.5% for the 90° rotation of the meter with respect to the undisturbed condition. In this case the single bouncing path leads exactly between the two vorticies where the secondary flow is very large; see Figures 2 and 3. Moreover, the transducers of the single-bouncing paths are close to the main flow perturbation, the “dent” in the profile. This configuration is a very rare installation condition, and this effect can easily be avoided by positioning the meter with an offset angle.

- For the double-bend-out-of-plane perturbation (right graph in Figure 10) all installation conditions lead to error shifts that are within the limits.

The CFD-results presented in [3] already indicated, that the influence of the azimuthal position of USM on the meter reading is not negligible and might in certain positions be larger for the single 90°-bend perturbation than for the double-bend-out-of-plane perturbation.

9

90°-configuration, 10bar

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Figure 8: Deviations from undisturbed conditions for single 90° bend configurations for

10bar and 40bar

double bend out of plane configuration, 10bar

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Figure 9: Deviations from undisturbed conditions for double-bend-out-of-plane

configurations for 10bar and 40bar

90°-configuration, 10D, 10bar, clockwise rotation

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Figure 10: Deviations from undisturbed conditions for different positions of the meter relative

to the perturbation at 10D downstream of a single 90° bend and a double-bend-out-of-plane configuration

10

Comparison of test results with the conventional meter design The conventional design of this Q.Sonic-3 meter (6’’) was tested at the Lintorf facility under similar conditions. The results were presented in [2]. As part of those tests, the influence of the meter’s azimuthal position relative to the single 90° perturbation (10D upstream of the meter) was also analysed in detail. The results show that the flow perturbation has a strong influence when the meter is turned between 30° and 150° (clockwise against direction of flow, with the piping as shown in Figure 4). This behaviour is similar to that of the new meter design, but the bias at 90° is much lower for the new design, which shows that area reduction in the new meter is an improvement. For all other positions, the additional error in those tests was acceptable. Detailed USM results It is well known that one major advantage of USMs are their diagnostic features. Values such as relative path velocities, velocity of sound, relative velocity of sound, gain factors, etc. can be used to check the meter’s long-term performance and generally detect possible metering errors. Some examples are given in Figures 11 and 12:

- Figure 11 shows the single-path data for a complete test run under undisturbed conditions. The single path velocities relative to the mean velocity are as expected for a fully developed turbulent flow. The relative velocity of the single bouncing path (path no. 2) is approximately 1.025, the relative velocities of the swirl paths (paths 1 and 3) are around of 0.99. At lower flow rates one can already detect some deviations from the fully developed flow profile.

- The comparison of the measured VOS for the three paths with the calculated VOS via AGA 8 gives maximum differences of 0.3%, which is acceptable for a meter of this size. The good agreement between all three VOSs shows that all three paths are working well.

- In contrast to Figure 11, Figure 12 shows the detailed data for the perturbed conditions. For both kind of perturbations the relative velocity of path no. 2 is reduced to approximately 1 due to the more homogeneous flow profile in the direction of flow. As is typical for the double-bend-out-of-plane perturbation, the swirl paths (no. 1 and 3) change drastically in opposite directions. In case of the 90° perturbation all relative path velocities are close to 1.

On the basis of these log file data from the calibration and from the field installation one can easily detect influences caused by flow perturbations or incorrect path lengths. The gain factor was within the accepted limits in all cases, which shows that there was no noise influence. Also, the number of accepted measurements was always near 15, which is the upper limit.

Figure 11: USM diagnostics: Single-path information for the tests without flow perturbation (43D upstream length, 10bar)

Figure 12: USM diagnostics: Single-path information for the tests 10D downstream of the 90° bend (top) and double-bend-out-of-plane configuration (bottom)

velocity for each path relative to mean velocity

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12

Conclusions The Q.Sonic-3 Compact

- The behaviour of this meter in perturbed conditions compared to the conventional design is better due to the area reduction in the meter.

- The new, simpler design of the transducer pockets has no effect on meter accuracy, i.e. the transducers mounted in these casings work equally well in the welded pockets.

- Compared to the Q.Sonic-5, there may be higher uncertainties downstream of special larger flow perturbations because the two single bouncing paths are missing in the Q.Sonic-3; this has to be considered when planning the meter run.

- For flow perturbations involving swirl the meter works well and there is no additional uncertainty.

- Hence, meter installation 10D downstream of a perturbation is generally acceptable, if the perturbation is not too strong.

- A comparison with the tests conducted by SwRI with the conventional design of this meter, presented in [4], shows that the meter tested here is less sensitive downstream of the double-bend-out-of-plane perturbation.

General remarks on USM metering

In the past Ruhrgas investigated the behaviour of several types of ultrasonic meters from different manufacturers for their sensitivity to flow perturbations. Generally speaking, ultrasonic meters are very promising types of flow meters. Nevertheless it must be stated that – for low flow perturbations such as those shown in Figure 4 – all types of meters tested so far do need at least the 10D straight inlet lengths required by PTB. In some cases the meters were only just within the limit of “1/3 of the allowed maximum permissible error (+/-1% above 20%, +/-2% below 20% of the meter capacity)” when installed 10D downstream of flow perturbations. But most of the test results were within the +/-1% accuracy band. Where very low metering uncertainties are desired, i.e. to make sure that flow perturbations have an minimum impact on metering, 20D upstream straight lengths are recom-mended, especially if larger flow perturbations must be expected. It is therefore recommended to as-sess the risks resulting from flow perturbations on a case-by-case basis. Analysis of the single path velocities can give some indication as to whether or not the flow is perturbed. The tests at Lintorf on the new gas turbine meters featuring integrated flow straighteners have shown that USMs are not yet able to provide the same level of insensitivity to flow perturbation as these GTMs. However, in con-trast to USMs, which have negligible pressure loss, these GTMs have the disadvantage of large pres-sure losses. Moreover, USMs are suited much better for wet gas metering, e.g. in offshore applica-tions and storage facilities. References [1] M. Tedeschi et al.: Intercomparison exercise of high presure test facilities within GERG,

GERG Technical Monograph No. 12, 2001 [2] G. de Boer, M. Kurth: Investigations regarding installation effects for small Ultrasonic gas

flow metering packages, NSFMW 1999 [3] A. Hilgenstock, Th. Hüwener, B. Nath: Kalibra: A fast numerical method for determining

installation effects in ultrasonic flowmeters, FLOMEKO 1998 [4] T. A. Grimley: Performance testing of ultrasonic flow meters, NSFMW 1997 [5] G. de Boer: New design concepts with UFM, NSFMW 2000

1

An Ultrasonic Meter for Stratified Wet Gas Service

Klaus J. Zanker Daniel division of Emerson

Abstract Recent tests of ultrasonic meters in wet gas service have shown that the most consistent connection between internal parameters of a 4-path SeniorSonic meter and LVF (Liquid Volume Fraction) is seen in mist flow. However, it has proved difficult to achieve this flow regime in practice. Mist flow is seen at high gas velocities and high pressure, and is found only at the edge of the operating envelope of all available wet gas test facilities. The most common flow regime encountered during testing has been stratified. It can be expected that natural gas/condensate systems will also operate to a large extent in this flow regime. An ultrasonic meter capable of giving gas and liquid flow rates in stratified flow is therefore essential if this type of metering is to be applicable over the full range of wet gas operating conditions. A 2-path JuniorSonic meter was adapted to measure in stratified flow. Level was measured using a vertical beam reflected from the liquid surface. Actual gas velocity was obtained using a horizontal beam across the centre of the pipe, which remained free of liquid under all test conditions. Using the assumption that the surface of the liquid stream is horizontal, the level can be related to the area occupied by the liquid. This leads directly to the relationship: Equivalent dry gas flow rate = actual gas velocity x (pipe area – liquid area). A simple slip model, based on density ratio, can give an estimate of the liquid velocity and hence the LVF and liquid flowrate. Tests were conducted in the wet gas test facility at NEL (Ref. 3) with two components, Nitrogen/Exxsolve, to simulate the two-phase flow. The text matrix covered pressures of 25 and 50 bar, velocity from 2 to 12 m/s and LVF from 0.1 to 5%. Results show that this simple meter performed well over this complete range. The dry gas flow rate could be obtained with an uncertainty of 3 % of reading, and LFV to within 0.5% LVF absolute, even with liquid hold-up (area) in excess of 25%, This work was undertaken by a JIP, with members from BG International, BP, Conoco, Elf, Phillips Petroleum, Statoil and Daniel, to investigate the performance of ultrasonic meters in wet gas service. Introduction The aim of the Ultraflow project is to develop an ultrasonic wet gas flow meter which, making use of existing hardware, can measure both liquid content and gas flow rate in a wet gas service. It was anticipated that the internal parameters of a conventional ultrasonic gas flow meter would provide the additional information required to measure both phases simultaneously. This expectation was built on the observation during trials at Bacton (Ref. 1) that parameters such as Gain, Standard Deviation, Signal to Noise Ratio and Velocity of Sound all reacted in different ways to an

2

increase in LVF. It was hoped that a model (in software) could be found to fit the changes in internal parameters to the LVF, enabling the liquid content to be measured and used to correct the gas flow rate to an “equivalent” dry gas flow rate. Various tests at British Gas, CEESI (Colorado) and NEL (Ref. 2 & 3) confirmed the reaction of the internal parameters to changes in gas LVF. However, it has proved difficult to construct a universal model relating this behaviour directly to liquid content. The tests at each site showed consistent behaviour, but unrelated to the parameter changes seen at the other sites. Other factors, such as meter design, density, viscosity, surface tension, drop size, pipe geometry and ambient temperature, were apparently of sufficient influence to prevent a simple universal relationship between ultrasonic meter parameters and liquid content to emerge. The last conclusion in (Ref. 3) stated “If it is difficult to achieve mist flow in practice, it might be better to ensure stratified flow and design a meter suitable for stratified two-phase flow measurement” This suggestion forms the basis of the present paper. Measurements The measurements were carried out using a 6” Daniel JuniorSonic ultrasonic meter. This is a two-path reflection device, normally installed in a horizontal pipe such that both beams are at 45° to the vertical, to avoid the pipe bottom. For these tests the meter was rotated by 45°, resulting in one beam being horizontal and the other vertical. The vertical beam reflects off the surface of the liquid film flowing along the bottom of the pipe. The ultrasonic path length decreases as the height of the liquid film increases. This gives a shorter transit time and an apparent increase in the measured velocity of sound that can be used to calculate the film thickness (Fig. 1) and hence the liquid hold-up (Fig.2). The horizontal beam sees only dry gas, providing a reference velocity of sound to compare with the vertical value and also a direct measurement of the actual gas velocity in the pipe. The meter was mounted in the NEL wet gas test facility, which has been adequately described elsewhere (Ref. 3). Test conditions covered a wide range of liquid volume fractions and gas velocities and took place at two line pressures, 25 bar and 50 bar. The nominal test matrix requested was: Gas velocity (m/s) 2, 5, 8, 12 Liquid volume fraction (%) 0.1, 0.2, 0.5, 1, 2, 3, 5 In practice the maximum gas velocity and maximum LVF that could be achieved were determined by loss of the vertical signal, caused by the interface becoming indistinct. At gas velocities up to 5 m/s it was possible to measure up to the maximum 5% LVF, at 8 m/s up to 2% LVF and at 12 m/s up to only 0.3% LVF. This practical limitation appeared to coincide with the onset of mist flow so the entire stratified flow envelope is covered by this technique. Note, however, that the onset of mist flow was deduced from visual observation. The horizontal beam (at h/D = 50%) showed no change under conditions where the vertical beam stopped responding, at 25% area, (h/D = 30%). Thus any mist must have remained close to the stratified interface.

3

The 25 bar tests were completed first. This identified some anomalies around the 5 m/s measurements, which were then further investigated with additional test points at 4 m/s and 6 m/s. This extended test matrix was also applied at 50 bar. Results As with previous tests, the ultrasonic flow meter, an actual volume meter, gives an over-reading of the gas flow that increases with increasing LVF. In this case only the horizontal beam could be used to measure gas velocity. For the vertical beam, the irregular surface of the liquid flowing in the pipe caused such large fluctuations in the difference between the upstream and downstream transit times, that a reliable gas velocity measurement was not possible. Note, however, that this has little effect on the velocity of sound measurement, since this uses the total transit time and not the small difference in transit times required for the gas velocity. This is important since the vertical velocity of sound value leads directly to liquid hold-up by applying simple trigonometry and assuming the liquid level is horizontal (Fig.1 & 2). The calculations are complex and resource consuming in real time, however a simple curve fit can give sufficient accuracy. The over-reading, called the wet error, is shown in Figures 3 and 4 for 25 bar and 50 bar respectively. In both cases, the wet error increases smoothly with increasing LVF, reaching values up to 25% at the highest achievable LVF of 5%. The wet error is caused by the liquid holdup; the greater the restriction in the pipe, the higher the wet error. By measuring the holdup, the wet error can be corrected. The resulting residual error, obtained by subtracting the area % (i.e. holdup) from the wet error, is the final error in the “effective” dry gas flow rate. The residual error at 25 bar and 50 bar respectively is shown in Figures 5 and 6. To estimate the LVF or liquid flow (Qliq) requires a slip model to estimate S = Vgas / Vliq, the ratio of gas to liquid velocity. The test results can be use to give a reasonable estimate of slip based on S = Area/LVF. The JIP project manager, Dave Brown, made use of a Shell model to predict the slip, and the author proposed a very simple model based on gas and liquid density (App 1). All three of these slip values are shown on Figures 7 and 8, for the 25 bar and 50 bar results respectively. The LVF based on this model (App 1) is shown in Figure 9, compared to the actual value, together with the errors. Analysis

Measurements A comparison of Figures 3 and 4, wet error, with Figures 5 and 6, residual error, shows that the area correction is capable of correcting wet gas errors of up to 25% down to residual errors of generally less than 3%. The main aim of the JuniorSonic tests was to provide a convincing demonstration that this correction is possible. For a given LVF, the residual errors first increase with increasing gas velocity and then decrease. Maximum values occur at an LVF of 3%, around 5 m/s at 25 bar and 4 m/s at 50 bar. Extra attention was paid to these particular flow conditions, with

4

measurements being repeated and additional points investigated. The anomalous residual error values are real and repeatable. Clearly some sort of flow transition is indicated. This has also been seen in previous tests. However, no proper explanation is available since there is no evidence of a flow regime transition under these conditions. From Figures 5 and 6 it can be seen that, with very few exceptions, residual errors are positive. A small depression along the center of the liquid stream compared to the edges could produce this result. The assumption of a horizontal surface, which was used to convert the liquid film thickness to the area, is probably not justified. It is possible that a better model for the liquid cross-section, taking curvature, waves, surface roughness and gas and liquid entrainment into account, could reduce the residual errors further and even offer an explanation for the anomalous results discussed above. It was hoped, before these tests, that the vertical beam could be used not only for the film thickness measurement but also for a second gas velocity measurement as a check on the horizontal value. This proved impossible since the fluctuations in transit time (Standard Deviation) caused by the uneven liquid surface far outweigh the small transit time difference between the upstream and downstream directions required for the gas velocity measurement. These fluctuations remain small compared to the total transit time, so the velocity of sound measurement and subsequent film thickness calculation is not affected. Figures 7 & 8 show that in general the Shell slip values are high, while the Area/LVF are low compared with the density ratio model. Figure 9 shows the LVF calculated using the density ratio model, and it is seen that the errors are reasonably random. The average error is less than 0.5% LVF for these relatively short term tests, thus longer time averages would probably yield better results. The slip model could be improved by taking into account the liquid area and gas velocity, low values tending to higher slip than that given by the simple density ratio. Further improvement in both the liquid and gas flow could come by considering velocity profile effects in both fluids.

Modelling Many multi-phase models exist, for example: Shell, PLAC, and Taitel & Duckler. All these models use gas and liquid flow rates as input to calculate liquid hold-up and flow regime. They are useful as a check on the measurements but cannot be applied directly to wet gas flow metering. The density ratio model shows the best agreement with the ultrasonic measurements over the full range of test conditions. This is also the only model where the measured variables can be used as input to calculate gas and liquid flow rates, as shown in Appendix 1. The Shell model shows good agreement with the JuniorSonic values up to a film thickness of around h/D =25 %. For thicker films, the calculated height is lower than the measured value. This is because the Shell model switches from a calculation based on stratified flow to one based on annular mist flow where slip and hence liquid holdup are lower. The criteria in this Shell model for switching from one flow regime

5

to another unfortunately cannot be adjusted. It is clear that the flow regime change is not appropriate in the present case. Referring to Appendix 1, the model implies a velocity profile in the liquid film since the velocity at the base of the film is reduced by friction with the pipe wall while the velocity at the interface is increased by interaction with the faster gas stream. Thus some form of velocity profile correction should be able to improve the accuracy of the calculated liquid flow above that of the simple density ratio model. The same is true of the gas flow, which could also be improved by a velocity profile correction. It is possible that a better model for liquid cross-section, and gas velocity profile, could reduce the gas residual errors and perhaps explain the anomalous results. The liquid flow rate calculation would also be made more robust and general purpose with a physical model that includes surface curvature, waves, gas and liquid properties and a liquid velocity profile. Conclusions 1. Two direct measurements, Liquid level and Gas velocity, allow the area occupied by the gas (pipe-liquid) and hence the gas flow rate to be calculated. 2. A simple slip model, based on the liquid to gas density ratio, allows the liquid velocity, liquid flow rate and LVF to be calculated 3. The uncertainty is better than 3% for the gas flow rate and 0.5% absolute for the LVF, over the range 25 – 50 bar, 2 - 12 m/s gas velocity, and 0.1 – 5% LVF, which lead to liquid hold-up in excess of 25%. 4. The results could be improved by considering:

• The interface is curved and wavy, not flat • The velocity profile in the gas • The velocity profile in the liquid • The effects of hold-up and gas velocity on slip

Acknowledgements The permission of the JIP, with members from BG International, BP, Conoco, Elf, Phillips Petroleum, Statoil and Daniel, to publish this paper is gratefully acknowledged. The JIP project manager, Dave Brown, took an active part in the collection and analysis of the experimental data and made the Shell model calculations available, and his guidance was invaluable to the success of the project. References [1] K. J. Zanker & W. R. Freund Jr. Developments of multi-path transit time ultrasonic gas flow meters, NSFMW 1994 [2] G. J. Stobie & K. J. Zanker. Ultrasonic wet gas measurement – Dawn gas metering – A Real world system, NSFMW 1998

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[3] K. J. Zanker & G. J. Brown, The performance of a multi-path ultrasonic meter with wet gas. NSFMW 2000 Appendix 1: Density Ratio Model If we assume the shear stress is the same on either side of the interface we have

Qgas = Vgas * (100 - A) where Vgas and A are measured directly Qliq = Vliq *A = (Vgas / S) * A

Typical values for these tests are shown below:

22 )( liqgasgasliqliq VVV −×=× ρρgas

liq

liq

gas

V

VS

ρ

ρ+== 1Giving

( ) ( )AA

SAVAV

Q

QLVF

gas

lia

gas

liq

−×=

−××

×=×=100

100100

100100%

P Den Gas Den Liq Dliq/Dgas SqRt 1+bar kg/m3 kg/m3 S

25 30.1 802.4 26.66 5.16 6.1650 58.3 802.4 13.76 3.71 4.71

V gas – V liq

V

V gas

Interfac

A

100 - A

A

7

Figure 2. Hold-up (Area) - Delta VOS

y = -0.0013x3 + 0.0542x2 + 0.2972x

0

2

4

6

8

10

12

14

16

0 2 4 6 8 10 12 14 16 18

Delta Vos %

Are

a %

L

Area

Figure 1. Bounce off the Stratified Liquid Surface

0

2

4

6

8

10

12

14

0 2 4 6 8 10 12 14 16

h/D %

Del

taV

OS

%

0

2

4

6

8

10

12

14

Are

a %

DeltaC % % Area

h

D

8

Figure 4. Wet Error v LVF at 50 bar

0

5

10

15

20

25

0 1 2 3 4 5 6LVF %

Wet

Err

or

%

2

4

5

6

8

12

15

Gas Vel m/s

Figure 3: Wet error v LVF at 25 bar

0

5

10

15

20

25

0 1 2 3 4 5 6

LVF %

Wet

Err

or

%

2

4

5

6

8

12

15

gas vel m/s

9

Figure 5: Residual Error v LVF at 25 bar

-3

-2

-1

0

1

2

3

4

5

6

0 1 2 3 4 5 6

LVF %

Res

idu

al E

rro

r %

2

4

5

6

8

12

15

gas vel m/s

Figure 6. Residual Error v LVF at 50 bar

-3

-2

-1

0

1

2

3

4

5

6

0 1 2 3 4 5 6

LVF %

Res

idu

al E

rro

r %

2

4

5

6

8

12

15

Gas Vel m/s

10

Figure 7. Slip models for 25 bar

0

2

4

6

8

10

12

14

16

0 1 2 3 4 5 6

Actual LVF %

Vg

as /

Vliq

uid

desity ratioShell holdupArea/LVF

Figure 8. Slip models for 50 bar

0

2

4

6

8

10

12

14

16

0 1 2 3 4 5 6

Actual LVF %

Vg

as /

Vliq

uid

desity ratioShell holdupArea/LVF

11

Figure 9. Calculated LFV and Error

-1

0

1

2

3

4

5

6

0 1 2 3 4 5 6

Actual LVF %

Cal

cula

ted

LV

F %

LVFAvg Errorerror

1

On-line comparison of the speed of sound at four Dutch metering stations equipped with ultrasonic gas flow meters.

Henk Jan Panneman, N.V. Nederlandse Gasunie, The Netherlands.

1. Introduction Ultrasonic gas flow meters are increasingly used for the fiscal flow measurement of natural gas. Advantages of ultrasonic gas flow meters are their rangeability, low pressure drop and the possibility of carrying out bi-directional measurements. Another advantage is the ability to measure the speed of sound of gas flowing through the ultrasonic flow meter. By comparing the speed of sound measured using the ultrasonic flow meter with the speed of sound calculated from gas properties, one can check the performance of the ultrasonic gas flow meter periodically or continuously. Letton et al. [1] previously showed that it is possible to compare the measured and calculated speed of sound. They used ultrasonic flow meters, which were initially calibrated using nitrogen. For these ultrasonic flow meters the measured speed of sound on all chords agreed within 0.1%. In their tests the deviation between the speed of sound measured with an ultrasonic flow meter and the speed of sound calculated with the AGA8 equation of state was less than 0.15%. The reproducibility of the measured speed of sound values was better than 0.03%. However, Letton et al. reported no values for the reproducibility of the On-Line Comparison of the Speed of Sound (OLC-SOS), which is defined as the relative deviation between the measured and calculated speed of sound. Based on the data in their figures, the reproducibility of the deviation between the measured and calculated speed of sound appears to be 0.1 – 0.2%. In their conclusions Letton et al. proposed that deviations of about ±0.3% between the measured and calculated speed of sound should be cause for alarm. This paper presents the results of field tests at four Dutch metering stations. Measurements at these four stations were carried out using Q.Sonic-5 ultrasonic gas flow meters manufactured by Instromet Ultrasonics b.v. The purpose of the field test was to determine the reproducibility of both the measured and calculated speed of sound, which are necessary to determine the reproducibility of the OLC-SOS system and estimate the alarm limits. The impact of gas composition, gas flow and meter type on the OLC-SOS were also investigated as part of the field tests. Finally, the changes in both speed of sound and gas flow resulting from deviations in the gas flow determining parameters of an ultrasonic flow meter were calculated during a sensitivity study.

2. Principle of On-Line Comparison of the Speed of Sound (OLC-SOS) The principle of an ultrasonic gas flow meter has been explained in previous papers [1,2]. It is based on the time difference between ultrasonic pulses (≈100khz) travelling downstream

2

and upstream in the presence of a gas flow (tdown < tup). The flow velocity is proportional to the reciprocal difference between these two transit times:

V = L/(2cosϕ) ⋅ (1/tdown – 1/tup) (1)

Where ϕ is the angle between the direction of the sound pulse and the gas flow and L is the length of the acoustic path between the two transducers. The speed of sound is proportional to the average of both transit times:

SOS = L/2 ⋅ (1/tdown + 1/tup) (2) Current generation ultrasonic gas flow meters output both the gas velocity and the speed of sound while readings are updated every second. The speed of sound can be calculated using a computer program based on the AGA8 equation of state. The required input data comprise a detailed gas composition, the pressure and the temperature. The metering stations where the field tests were conducted are equipped with Daniel process gas chromatographs. Accurate pressure and temperature measurements are also available at these stations. The continuous determination of the relative deviation between the measured and calculated speed of sound is called OLC-SOS (On-Line Comparison of the Speed Of Sound) and is given by:

OLC-SOS = (SOSmeasured – SOScalculated)/SOScalculated (3)

In the current set-up, the gas analysis is the most time consuming input parameter for OLC-SOS with a cycle time of 15 minutes. The other input parameters (measured speed of sound, pressure and temperature) are updated every few seconds. Therefore, OLC-SOS can be carried out with a frequency of approximately 4 times per hour.

3. Performance of an OLC-SOS field test at a metering station The OLC-SOS field test was carried out during normal operation of the station and using the existing instruments present at the station. At these stations the ultrasonic flow meters have sufficient straight pipe length (>20D) upstream to ensure a well developed flow profile. Figure 1 shows the field test set-up. The ultrasonic flow meter sends volume flow data to the flow computer. The flow under normal conditions ( 0 °C, 1,01325 bar) is calculated on the basis of this flow, the pressure, the temperature and data for the compressibility calculation. The Daniel field GC calculates the calorific value under normal conditions. The energy flow, which is the product of the calorific value and the flow rate, is calculated and stored in a second computer-system (see Figure 1). For the OLC-SOS field test, the speed of sound data were taken directly from the ultrasonic flow meters, while the pressure and temperature and the gas composition were taken from the flow computer and the Daniel process GC respectively . Quality data synchronisation is a prerequisite for a proper comparison of the measured and calculated speed of sound. This particularly applies if changes in the gas composition can be

3

expected. The speed of sound, the pressure and the temperature have to be measured at the same moment as the gas sample for GC analysis is retrieved from the pipe.

Q.SONICQ.SONIC--55USUS--metermeter

FlowFlowComputerComputer

DanielDanielprocess GCprocess GC

P,TP,T

OLCOLC--SOSSOSComputerComputer

EnergyEnergymetermeter

QQ

SOSSOS

P,TP,T

XXii

HHSS

QQNN

Figure 1. OLC-SOS set-up during field tests at Gasunie metering stations

The Daniel field GC analyses CO2, N2, hydrocarbons up to C5 separately and C6+. To determine the calorific value, C6+ is handled as a (pseudo)-component. An average composition of C6+ is derived at following extensive laboratory analyses of many gas samples. This composition was also used for the speed of sound calculations, as part of which minor components were treated according to ISO 12213-2 [3], e.g. neo-pentane and cyclo-pentane are treated as n-pentane.

4. Uncertainty and repeatability of the input parameters Before the OLC-SOS measurements were carried out, data were collected in relation to the individual input parameters. This data were necessary to gain insight into their uncertainty and repeatability. 4.1 Uncertainty and reproducibility of the measured speed of sound All ultrasonic flow meters used during the field tests were Q.Sonic-5 QL multi-path flow meters manufactured by Instromet Ultrasonics b.v. These meters have 5 ultrasonic paths; path 1,3,and 5 are single reflection paths, while path 2 and 4 are double reflection paths. The repeatability (2σ) of the SOS measurement and the maximum difference in the measured speed of sound between the chords is presented in Table 1. The gas velocity during the determination of 2σ(SOS) is also shown. From Table 1 it can be concluded that the repeatability of the SOS measurement is always less than 0.01%. It is well-known that speed of sound measurements are influenced by

4

Table 1. The repeatability (2σσσσ) of the measured speed of sound of the individual chords (1 to 5) and maximal difference in speed of sound.

Station A Station B Station C Station D

Diameter US meter, m 0.4777 0.4777 0.4777 0.303

Gas velocity, m/s 0.7 1.2 7.5 12

2σ, SOS-1, % 0.0024 0.0024 0.0076 0.0084

2σ, SOS-2, % 0.0026 0.0024 0.0072 0.0088

2σ, SOS-3, % 0.0018 0.0022 0.0078 0.0084

2σ, SOS-4, % 0.0016 0.0026 0.0074 0.0092

2σ, SOS-5, % 0.0012 0.0026 0.0078 0.0082

(SOSmax – SOSmin) % 0.24 0.25 0.1 0.09

the gas velocity. High gas velocities induce large turbulences in the pipe, resulting in a distortion of the acoustic path [4]. In turn, this results in both a small systematic deviation between the measured and “true” speed of sound, which can be accounted for, and a small increase in the random deviation of the measured speed of sound. Indeed, the repeatability increases slightly with the gas velocity. No significant difference in repeatability has been found between the single and double reflection paths during the tests. The acoustic path lengths of the Q.Sonic meters are directly derived from the pipe diameter, D, and the acoustic path angle. As a result, they are not corrected for uncertainties in the manufacturing process. The length of the three single reflection paths is identical and equals 2D/sin(ϕ). The length of the two double reflection paths is also identical and equals 3Dsin(π/3)/sin(ϕ). Instromet claims an uncertainty of ± 0.05% in the inner diameter of the pipe [5]. The uncertainty in time measurement is negligible for the purpose of determining the speed of sound. The uncertainty in the speed of sound measurement should therefore be within ±0.12% for a single reflection path. The maximum difference in the measured speed of sound using a given meter’s 5 measuring paths varied between 0.09% and 0.25%, which is in agreement with the uncertainty analysis. The comparison of the measured and calculated speed of sound is especially suitable for a continuous check during normal operations but can be used for an initial check of the deviations in the individual chords of the ultrasonic flow meter as well. For a continuous check, the somewhat larger differences in the speed of sound measurements of the individual chords are not important. The differences in the measured speed of sound of the individual chords do not influence the flow measurement; a meter factor is determined after flow calibration, which corrects the errors caused by all parameters and variables involved.

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4.2 Uncertainty and reproducibility of the calculated speed of sound The uncertainty in the pressure and temperature measurement is less then 0.1%. The repeatability (2σ) of the pressure measurement was ±0.01 bar, which results in a contribution of 0.0005% to the repeatability of the calculated speed of sound. The repeatability (2σ) of the temperature measurement was ±20 mK, resulting in a contribution of 0.005% to the repeatability of the calculated speed of sound. The uncertainty in the calorific value determined by a Daniel process gas chromatograph is 0.25%. However, it is difficult to relate the uncertainty in the calorific value to uncertainties in the component concentrations and, subsequently, to an uncertainty in the calculated speed of sound. Moreover, the average composition of the C6+-fraction used in the procedure for calculating the speed of sound was kept identical during the four tests, even though differences in the composition of C6+ are possible. The uncertainty in speed of sound due to uncertainties in the gas composition was estimated at 0.1%. The repeatability of the gas analysis was better than 0.03%, resulting in a contribution of 0.02% to the repeatability of the calculated speed of sound. Laboratory measurements of the speed of sound of known gas mixtures using highly accurate speed of sound meters showed that the uncertainty in the AGA8-based computer program that is used to calculate the speed of sound was 0.05% [6]. In summary: the uncertainty and repeatability of the measured speed of sound are 0.3% and 0.01% respectively. The uncertainty of the calculated speed of sound is difficult to determine: the main contributors are the AGA8 E.O.S. (0.05%), the temperature (0.05%) and the gas analysis (0.1%), resulting in a total uncertainty of approximately 0.15%. The repeatability of the calculated speed of sound is approximately 0.02%, and is almost entirely determined by the repeatability of the gas analysis. Therefore, from a theoretical viewpoint, the repeatability for the OLC-SOS should be: 2σOLC-SOS ≤ 0.02%.

5. Results of OLC-SOS. Tests were conducted at four different metering stations. All stations were equipped with the same type of temperature and pressure measurement and a Daniel process gas chromatograph for the analysis. Some parameter properties of relevance to the field test are summarised in Table 2. From Table 2 it is clear that the experimental conditions varied considerably during the field tests. Ultrasonic flow meters of two diameters were tested and the gas velocity varied between 0 and 13.5 m/s. The gas composition showed large variations, both during tests and between the consecutive tests, resulting in large variations in the speed of sound.

6

Table 2. Properties and parameters during the field tests

Station A Station B Station C Station D

Diameter US meter 20” 20” 20” 12”

Flow, m3(n)/hr 0 – 140.000 0 – 117.000 200.000 –525.000

180.000 – 235.000

Gas velocity, m/s 0 – 1.3 0 – 1.5 4.5 – 13.5 11 - 13

Methane range, mol% 86.5 – 92.2 86.7 – 89.3 82.7 – 84.4 81.24 – 81.29

Temperature range, K 287.6 – 288.6 288.1 – 288.7 287.7 – 286.4 286.2 – 287.1

VOS range, m/s 378 – 401 380 – 391 391 – 396.5 397.5 – 398.5

OLC-SOS, 2σ, % 0.02% 0.02% 0.02% < 0.01%

Despite these large variations, the reproducibility of OLC-SOS was always within 0.02%. This value is in good agreement with the expected values, based on the repeatability of the input parameters. The deviations between the measured and calculated speed of sound for the individual chords are shown in Figure 2.

-0,3

-0,2

-0,1

0

0,1

0,2

0,3

Meter Number

(SO

S mea

sure

d - S

OS c

alc.

) / S

OS c

alc.

%

L1,Ax L2,Sw L3,Ax L4,Sw L5,Ax

A B C D

Figure 2. The differences between measured and calculated speed of sound for the

individual chords of 4 different ultrasonic flow meters. Meters A, B and C, which were all 20” in diameter, showed a measured speed of sound that is slightly lower than the calculated speed of sound. The fourth meter, D, which was 12” in

7

diameter, showed a measured speed of sound that was slightly higher than the calculated speed of sound. This deviation could be attributable to the ultrasonic flow meter manufacturing process. Alternatively, it may be the result of the uncertainty in the calculated speed of sound (0.15%). The deviations evident in respect of chord 2 from meter A and of chord 5 from meter B are significant compared to the other chords. However, the results are within the uncertainty limits discussed earlier. The results of the speed of sound measurements for station B are shown in Figure 3. For clarity’s sake only the measured speed of sound of a single chord and the calculated speed of sound are shown.

379

381

383

385

387

389

391

14-9 15-9 16-9 17-9

Date

SOS

(m

/s)

87

88

89

90

Met

hane

(m

ol%

)

measuredcalculatedmethane

Figure 3. The measured and calculated speed of sound and methane concentration

collected during 3 days at Station B. High calorific gas with relatively large differences in composition is measured by station B. The large changes in speed of sound are mainly caused by changes in gas composition. The change in methane concentration shown in Figure 3 follows the same trend as the speed of sound. The OLC-SOS of measurements by station B are shown in Figure 4. Results for each of the 5 chords are shown. Chord 1 and 4 nearly coincidence. It can be concluded from the graph that all five chords behave identically. The results shown in Figure 4 can roughly be divided into two parts: the measurements taken on 14 September and the first hours of 15 September show a reproducibility that is significantly higher (2σ = 0.05%) than the subsequent measurements taken on 15 and 16 September (2σ = 0.02%).

8

The lower reproducibility corresponds to periods during which fast changes in gas composition occurred (see Figure 3). Further investigation at the metering station showed that the residence time taken for the gas sample to reach the GC was not correctly estimated. This resulted in a discrepancy in time between (a) the moment the gas sample used for the GC analysis was retrieved from the pipe and (b) the moment the speed of sound, pressure and temperature were measured. This discrepancy only resulted in differences in the OLC-SOS if the gas composition changed between these measurements. It can be concluded that measurements must be synchronised properly and that the residence time of the gas in the sample line to the GC must be calculated correctly.

-0.4

-0.2

0

0.2

0.4

14-9 15-9 16-9 17-9

Date

measu

red

calc

.ca

lc.

L1 L2

L3 L4

L5

Figure 4. The On-Line Comparison of the Speed of Sound determined at station B. Figure 4 shows a large deviation in the OLC-SOS shortly after the start of the measuring process. Figure 3 demonstrates that this large deviation is caused by a sudden decrease in the calculated speed of sound. The large deviation in OLC-SOS also coincided with a fall in the methane concentration by approximately 0.6%. It transpired that the GC had been tested with a calibration gas during this period, which gas had a slightly different composition. A decrease of 0.6 mol% in methane and 0.55 mol% in carbon dioxide and an increase of 1.15 mol% ethane results in a change of 0.2% in OLC-SOS. A larger change in OLC-SOS is possible if a decrease in methane (high speed of sound) is compensated by an increase in nitrogen or carbon dioxide (low speed of sound). A deviation in OLC-SOS can again be observed at the end of 16 September. This deviation coincided with an period of no flow. If the gas flow is zero, the gas temperature near the pipeline wall will be affected by the ambient temperature. As a result, the temperature measured with the PT100 deviated from the average gas temperature in the ultrasonic flow meter, which, in turn, caused the OLC-SOS to deviate.

9

The field test at station B showed that OLC-SOS easily detects deviations in the GC analysis and temperature. It also showed that synchronisation appears to be important. During tests at station B, the gas flow varied between 0 and 1.5 m/s. At station D the gas flow was almost 10 times higher. Before comparing the measured and calculated speed of sound, the measured speed of sound was corrected for deviations caused by the high gas velocity.

397

397.5

398

398.5

21-9 22-9 23-9 24-9 25-9 26-9 27-9 28-9

Date

286

287

288

289measuredcalculatedtemperature

temperature

measured SOS

Figure 5. The measured and calculated speed of sound and the measured

temperature, data collected over 7 days (Station D). The results of the speed of sound measurements obtained from station D are shown in Figure 5. Low calorific gas with an almost constant gas composition is measured at station D. During the test, gas velocity varied between 11 and 13 m/s. The variation in the speed of sound measured at station D was approximately 20 times lower than the variations at station B. In this instance, the variation in the speed of sound is primarily caused by changes in the gas temperature. The results of the temperature measurements are also shown in Figure 5. During the first three days the temperature showed a distinct variation between day and night. This temperature variation was less obvious during the final three days. There is a very good resemblance between the measured and calculated speed of sound. The results of the OLC-SOS obtained at station D are shown in Figure 6. The reproducibility is both very good, 2σ < 0.01%, and identical for all 5 chords. The small variations in OLC-SOS are present in all 5 chords. In other words, the variations are most probably caused by the

10

calculated speed of sound. Again, the small variations between measured and calculated speed of sound may be attributable to a small synchronisation error.

-0.15

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21-9 22-9 23-9 24-9 25-9 26-9 27-9 28-9Date

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L5

Figure 6. The On-Line Comparison of the Speed of Sound determined at station D.

6. Sensitivity analysis of the speed of sound and gas velocity measurement with an ultrasonic gas flow meter

From the experimental results obtained it may be concluded that the reproducibility of the On-Line Comparison of the speed of sound is better than 0.02%. The results also show that small deviations in temperature and gas composition are detected by OLC-SOS. The on-line comparison of the speed of sound is primarily developed to check the quality of the gas flow measurements by an ultrasonic gas flow meter. As a second step it was therefore necessary to investigate how small deviations in gas flow measurement performance are reflected in the measured speed of sound. Modern ultrasonic gas flow meters have a number of self-diagnostics tools, such as a signal quality monitor, a detection window with warning limits for some parameters, a pulse quality check and of course the speed of sound itself [7]. Except for the speed of sound, these diagnostics tools will not detect small deviations in the parameters, which are influencing the gas flow measurement. These parameters are: the path length, L, between the two sonic

11

transducers; the transit time measurement, ti; the electronic delay-time, td; the transducer’s angle, ϕ and contamination of the transducers and/or the pipe wall by oil, grease or solids. The sensitivity analysis was carried out for an ultrasonic flow meter with an axial measuring chord and a single reflection. A realistic path length of 1 m was taken, the speed of sound was set at 400 m/s and the gas velocity was fixed at 10 m/s unless indicated otherwise. Table 3 gives the changes in the speed of sound and the measured gas velocity for small changes in the relevant parameters. The last column indicates whether or not the change in parameter is detected by OLC-SOS. Table 3. Sensitivity of speed of sound and gas velocity with respect to the flow

determining parameters of an ultrasonic gas flow meter.

parameter ∆∆∆∆(parameter) ∆∆∆∆VOS %

∆∆∆∆V %

OLC-VOS

Detection

L + 1% -1% -1% Yes

tab (+10ns), V=10 m/s +8⋅10-4% -4⋅10-4% -0.033% No

tab (+10ns), V=1 m/s +8⋅10-4% -4⋅10-4% -0.33% No

tab and tba (+ 5 µs) ½λ shift -0.2% -0.2% Yes

time delay, td +1% -0.01% -0.02% Yes

ϕ (- 0.1°) -0.17% -0.1% +0.2% Yes

Wax (on transducer) 0.5 mm +0.08% +0.08% Yes

Oil (on transducer) 0.5 mm +0.07% +0.07% Yes

Wax (transd. + wall) 0.5 mm +0.16% +0.16% Yes Deviation in the path length L: A +1% deviation in the path length of a chord gives a different transit time, which causes the gas velocity and the speed of sound to be determined incorrectly. If, for example, a transducer of a slightly different length is mounted, and OLC-SOS is used, the error in length will be easily detected. Based on the reproducibility of the OLC-SOS, it may be concluded that changes of 0.05% in the length of the sonic path will be detected. Deviation in the measurement of the transit time, tab and tba: The uncertainty in the travel time measurement is at most 10 ns [2]. The corresponding uncertainty in the gas velocity is strongly flow-dependent. A deviation of +10 ns in the transit time results in deviations of –0.033% and –0.33% for gas velocities of 10 m/s and 1 m/s respectively. The deviation in the speed of sound is negligible.

12

The transit time is measured by detecting a predetermined zero crossing in the voltage signal received. Under unfavourable conditions, the determination of the zero crossing of both transit times (tab and tba) can shift by half a wavelength. A shift of +½λ results into a deviation of –0.2% in both the measured gas velocity and speed of sound, which deviation is easily detected by OLC-SOS. Deviation in the electronic time delay: The transit times measured also contain delays on account of the electronics, the cables, the transducers, and diffraction effects. A +1% change in the time delay will affect the gas velocity by –0.02% and the speed of sound by –0.01%. The effect of changes in the time delay on the gas velocity and the speed of sound depends on the absolute value of the transit times and the absolute value of the time delay. Significant deviations in the time delay, due to changes in the electronics for example, will be detected by OLC-SOS.

Deviation in the inclination angle: The inclination angle between the direction of the sonic wave and the direction of the gas flow is determined by the position of the transducers on the meter body. Deviations in the angle of the acoustic path will affect both the gas velocity and the speed of sound measurement. A –0.10° deviation in the angle of the acoustic path results in a +0.2% deviation in the gas velocity and –0.1% deviation in the speed of sound. During normal operations changes in the inclination angle are unlikely. However a small change in the angle of the acoustic path might occur following the mounting of new transducers. Wax or liquid deposits: During the transport of natural gas heavy hydrocarbons (condensate), compressor and seal oil and/or fine solid particles can be deposited inside the gas flow meter. Depending on the nature of the contamination and the total amount of contamination present, a thin layer of grease or wax can be present on the transducer surface and/or on the inner surface of the meter body. Contamination on the transducer and meter body surface causes the path length of the sound wave in the gas phase to be reduced in comparison to the original path length. Furthermore, the speed of sound in liquid or solid contamination is significantly higher than it is in natural gas. Therefore, the resulting transit times will be smaller when contamination is evident. If the transducers and the surface of the meter body are covered with a grease layer of 0.5 mm, the deviation in the gas velocity and speed of sound amounts to 0.16%. Based on the results obtained in the field tests, OLC-SOS will thus detect deposit layers of 0.2 mm and above. Therefore, contamination will be detected before significant deviations in the gas velocity are obtained. The sensitivity analysis showed that small deviations in the parameters, which are relevant for the determination of the gas flow, will be detected by OLC-SOS. An exception is the random uncertainty in the transit time measurement. A disturbed flow profile will not be detected by

13

OLC-SOS as well. To detect this phenomenon, the velocity measurements of the individual chords may be used.

7. Field implementation On-Line Comparison of the Speed of Sound

For economical and practical reasons, ultrasonic gas flow meters are not frequently recalibrated. Consequently, a number of deviations may arise between two calibrations. These have a negative impact on the measuring characteristics of an ultrasonic gas flow meter. Possible sources of deviation include the contamination of transducers and/or pipe walls, changes in delay times, an exchange of transducers or electronics and changes in gas properties. A sensitivity analysis showed that OLC-SOS will detect almost all effects that occurr during the normal operation of an ultrasonic gas flow meter. A first indication of alarm limits will be given next. AGA-9 [8] recommends that the ultrasonic gas flow meter must meet specific minimum measurement performance requirements before a calibration factor adjustment can be applied. These requirements are a meter deviation (from reference) of at most ±0.7% and a reproducibility of ±0.2% or less for flow rates between 10% and 100%. The experimental results presented in this paper show that the OLC-SOS has a reproducibility of within 0.02%. The sensitivity analysis showed that changes in the relevant parameters result in changes of the same magnitude in gas flow and speed of sound, except for the inclination angle and the time delay. For the latter parameters the change in speed of sound is only half of the change in gas flow. Evidently, OLC-SOS detects deviations up to 10 times faster than an on-line flow comparison. The warning limits should be set at a level that avoids false alarms. In practice, a CUSUM (Cumulative Sum) or a EWMA (Exponentially Weighted Moving Average) control chart including a spike filter can be used. It is also possible to use OLC-SOS for checking the performance of the process gas chromatograph and temperature measurement. It is shown that a 0.3% deviation in gas composition or 0.3K in temperature corresponds with a 0.1% change in OLC-SOS. A practical operational limit for initial warning alarms could be set at ±0.05% in the OLC-SOS, which corresponds to ±5σ. Assuming these values are used, the number of false alarms is minimal, while deviations of 0.15% in the gas composition and a change of 0.15K in the temperature are nevertheless detected. If an alarm occurs, the deviation in gas composition and temperature are much larger than the reproducibility of the process gas chromatograph (0.03%) and the temperature measurement (0.02K).

14

8. Conclusions

Speed of sound data were collected at four metering stations using Q.Sonic-5 ultrasonic flow meters. Although the experimental conditions, e.g. gas velocity and gas composition, varied strongly, the repeatability (2σ) of the measured speed of sound was always within 0.01%. The mutual differences between the individual paths were always within ±0.12%. Differences will be caused by the uncertainty in the meter dimensions. The speed of sound was also calculated, on the basis of gas composition (measured using a Daniel process gas chromatograph), temperature and pressure. The uncertainty and repeatability of the calculated speed of sound were within 0.15% and 0.02% respectively. The difference between measured and calculated speed of sound (OLC-SOS) was always within 0.3% and showed a reproducibility that was at all times better than 0.02%. The reproducibility (a) appears to be path independent (b) is the same for the 4 meters tested and (c) does not dependent on the gas composition, the gas flow and the pipeline conditions. The difference between measured and calculated speed of sound will be caused by deviations in the dimensions of the flow meter and the uncertainty in the gas analysis used to calculate the speed of sound. During the implementation of OLS-SOS specific attention must be paid to proper synchronisation. The residence time of the gas in the sample line leading to the GC must be know. Speed of sound, pressure and temperature must be measured at the exact moment that the gas sample is retrieved from the pipe line. Small deviations (0.05%) in the temperature (on account of zero gas flow) and the gas composition (GC is calibrated using a slightly different gas composition) could easily be detected easily with OLC-SOS (during the field tests). A sensitivity analysis showed that small deviations in nearly all parameters that influence the performance of the flow measurement lead to changes of the same magnitude in both the gas velocity and the speed of sound. These parameters are: the diameter of the flow meter, the path length between the sonic transducers, the manner in which the transit time is determined, the electronic delay-time, the transducer’s angle and contamination of the transducers and pipe wall on account of oil, grease or solids. Variations in the random error in time measurement and a disturbed flow profile are not detected by OLC-SOS. Based on the field tests and the sensitivity analysis, it can be concluded that OLC-SOS detects small changes in the performance (dimensions, electronics, contamination) of the ultrasonic flow meter. OLC-SOS additionally detecs small changes in (a) the performance of the GC, (b) pressure or temperature measurements. Therefore, OLC-SOS offers higher reliability of all fiscal measurements, without using additional instrumentation.

15

The measurements taken during the field tests made it clear that the reproducibility of speed of sound measurements is roughly 500 to 1000 times better than the reproducibility of the gas velocity measurements. Therefore, small deviations in the gas flow, which are caused by small changes in the flow determining parameters (except random errors in the transit time measurement ti), will be detected far more easily by comparing speed of sound than by comparing the gas flow using a second gas flow meter. Assuming equipment for the determination of gas composition, pressure and temperature is present, the OLC-SOS method is much cheaper than the latter method. The practical usability of OLC-SOS is mainly determined by the repeatability of the measured speed of sound data and the repeatability of the input data for the calculated speed of sound. Systematic deviations are of lesser importance, on the assumption that the systematic deviations are small and remain constant.

Literature

1. C. Letton, D. Pettigrew, B. Renwick, J. Watson, An ultrasonic gas flow measurement system with integral self checking. Proc. of The 16th North Sea Flow Measurement workshop, 1998.

2. G. de Boer, J. Lansing, Dry Calibration of Ultrasonic Gas Flow Meters, Proc. of The 15th North Sea Flow measurement Workshop, 1997.

3. ISO 12213-2, Natural Gas – Calculation of compression factor, Part 2: Calculation using molar-composition analysis.

4. P. Lunde, K. Froysa, M. Vestrheim, GERG Project on Ultrasonic Gas Flow Meters, Phase II, GERG Technical Monograph TM11, Fortschr. Ber. VDI Reihe 8 Nr. 854, 2000, Chapter 3.

5. J.G. Drenthen, G. de Boer, The manufacturing of ultrasonic gas flow meters, Flow Measurement and Instrumentation, 12 (2001), 89 –99.

6. H.J. Panneman, C.W. Koreman, A. Kroon, H. Horstink, M. Jaeschke, J.A. Schouten and J.P.J. Michels, A Fast energy Measurement System Suitable for Process Control and Off-shore Metering Applications, To be published in the Proceedings of the 2001 International Gas Research Conference, Amsterdam, 2001

7. J.G. Drenthen, F.J.J. Huijsmans, Ultrasonic gas flow measurement, Sales brochure, Instromet International N.V., Belgium

8. AGA report No.9, Measurement of Gas by Multipath Ultrasonic Meters, American Gas Association, Transmission Measurement Committee (June 1998).

1

19th NORTH SEA FLOW MEASUREMENT WORKSHOP

Field Experience With Multipath USMs � Ultrasonic Meter Vs Turbine Meter Trial

Mr. Ali Niazi, Advantica Technologies Ltd.

Mr. Peter Hutchinson, Advantica Technologies Ltd. 1 INTRODUCTION In recent times Advantica Technologies Ltd, in close collaboration with Transco and Ultrasonic Meter manufacturers, have carried out short and long term studies and experiments on multipath ultrasonic meters1. The aims of these exercises were to identify installation effects on the meters and to gain a better understanding and confidence of their performance against ’other± metering systems. As part of this work, examination of the effect of noise generation by three of the most popular pressure regulators used by Transco at metering stations was studied. Long-term performance of one of the multipath ultrasonic meters was also undertaken as part of the same exercise2. An 18-inch multipath USM was installed at an operational site upstream of an existing orifice plate metering system to monitor its long term operation and compare its performance with the orifice plate system. During this work, issues such as correction methods and compatibility of multipath ultrasonic meters with currently available flow computers were also addressed. During 2000 and 2001, a metering system comprising of a different multipath ultrasonic meter and an Instromet SM-RI turbine meter was commissioned and installed at one of the metering stations, upstream of a multistage pressure regulator. The aim of this exercise was to understand calibration methods between different multipath ultrasonic meters, identify best possible correction methods, compare the long term performance with a very accurate and stable flow meter and gain experience with the installation, commissioning and operation of the multipath ultrasonic meter using one of the most popular flow computers in the market. This paper presents calibration results, installation details and long term comparison results between the turbine and the ultrasonic meter. Interpretation of various diagnostics data obtainable from the flow computer and the comparison of diagnostic data received from the ultrasonic meter with a conventional gas property calculation package (GasVLe3) is also presented. 2 CALIBRATION 2.1 Meter and Spool Details A 12 inch SM-RI turbine meter with a claimed accuracy of ” 0.5% with the new X4X built-in flow straightener and a 12-inch five-path Q.Sonic ultrasonic flow meter were purchased from Instromet together with the upstream and downstream spool pieces.

2

A photograph capturing the configuration details is shown in Figure 1 below. The turbine meter is installed 10D downstream of a full bore ball valve and 10D upstream of the USM. A further 10D straight pipe length is installed downstream of the USM. Two Honeywell pressure transducers were installed directly, one on the USM and the other on the turbine meter, to provide pressure readings for both meters. Temperature readings were provided by two platinum resistant thermometers installed 3D downstream of each meter.

Figure 1 Ultrasonic Meter and Turbine Meter Installation

2.2 Calibration The two meters were calibrated at the Bishop Auckland Test Facility using the configuration described above. The meters and meter spools were transported to the test facility where they were assembled prior to calibration. The Bishop Auckland calibration facility is UKAS accredited for volume flow measurement and utilises a series of 4„, 6„, 8„ and 12„ turbine meters as reference meters giving a maximum accredited flow rate of 19,500 acmh. The facility is connected to the UK National Transmission System (NTS) and it operates in two flow modes, dependent upon the pressure and flow rates required. Typically the site operates in the range 50 to 60 bar pressure, providing extremely good reliability and stability of flow. More details of the facility were described in a previous paper2. The turbine meter was calibrated in the normal way, logging frequency readings from both the reference and the test meter for a period of 100 seconds. Both the pressure and the temperature readings for the reference and the test meter were also recorded and averaged at 10 second intervals. This procedure was repeated twice more, averaging all three calibration data for each flow rate through the meters. If the meter errors indicated by the three test runs were not within the test facilities expected tolerance limits, additional test point(s) were taken to minimise the effect of any random errors associated with the data points obtained. Calibration details of the turbine meter are shown in Figure 2 below.

3

The ultrasonic meter was connected to the site flow computer in the frequency mode and calibrated just like a turbine meter. Calibration details of the meter are also shown in Figure 2. The meter±s serial output was also connected to a computer where the manufacturer±s system software enabled the meter configuration details to be confirmed and the diagnostics data to be monitored during the calibration period.

Figure 2. Turbine and Ultrasonic Meter Details at Calibration

After the calibration, a new meter adjust factor (normally 1.0000) was calculated, but it was not updated in the meter diagnostics, instead multiple ’k± factor correction (linear interpolation) was later employed on the flow computer. It should be noted that multiple ’k± factor corrections or multiple linearisation within certain flow computers are only possible if the ultrasonic meters are calibrated in the frequency (pulse) output mode. This will be covered in detail under the flow computer section. 3 INSTALLATION 3.1 Hardware Installation The site where the two meters were installed is an operational site and therefore careful configuration of the two meters and the secondary instrumentation was necessary to keep the site operational as well as to allow monitoring and comparison between the two meters continuously. The two metering systems used flow computers, which were kept independent from each other when carrying out the necessary flow computations. Both flow computers were connected to a remote data collection and storage system, via a data logging system especially designed for this site. Pressure and temperature data was received from two separate pressure transmitters, positioned on the meter bodies and two independent temperature sensors, positioned downstream of each meter.

Turbine Meter Vs Ultrasonic Meter at Calibration

-1-0.8-0.6-0.4-0.2

00.20.40.60.8

1

0 1000 2000 3000 4000 5000 6000 7000

Flow Rate acmh

Erro

r %

4

Two flow computers of the same make were employed on the site; one was connected to the turbine metering system frequency output and the other to the USM frequency as well as the serial output. The flow computers were connected to each other, using the peer-to-peer facility. A gas chromatograph, installed on the upstream of the two meters, provided gas composition data to the turbine meter flow computer, which was shared with the ultrasonic meter flow computer. Two 4-inch multistage Jetstream pressure regulators, installed downstream of the two meters, provided pressure cut from 70 bar to 55.2 bar and then from 55.2 bar to 37.2 bar. 3.2 Flow Computer Details Both flow computers operate independently, calculating turbine and USM actual and standard flow rates simultaneously. Density, relative density and calorific value calculations are also performed to the relevant standards. Full gas composition is obtained from the gas chromatograph, where the line density and the relative density are calculated. Both flow computers are capable of using linear interpolation technique to carry out multiple ’k± factor corrections. From the meter calibration certificates it was possible to calculate the relevant ’k± factors for both the USM and the turbine meters and input these into the flow computers. For turbine meters, straightforward interpolation within the flow computer using multiple ’k± factors is possible. For ultrasonic meters, this will be very much dependent on the flow computer capability. Some flow computers, including the ones on this site, are only capable of carrying out multiple ’k± factor correction using the pulse output from the ultrasonic meter. In this case the USM was calibrated using the pulse output from the meter and therefore it was possible to treat the meter similar to a turbine meter. Diagnostic data from the ultrasonic meter was obtained through the serial RS-485 output. This output provided gas velocities, actual flow rates, speed of sound, etc., to enable monitoring of the meters performance during its operation. The ultrasonic meter flow computer accepts frequency pulses direct from the meter, and gas velocity and flow rate through the serial connection. If a pulse signal is available, the flow computer will use this for calculations, as long as the calculated flow rate is within a user defined ’flow rate deviation percentage± of the flow transmitted serially by the ultrasonic meter. If a pulse signal is not available, failed or user-inhibited, the flow computer will use the gas velocity transmitted by the ultrasonic meter. The flow rate calculated by this method must also be within the ’flow rate deviation percentage± of the flow transmitted serially by the ultrasonic meter. 3.3 Frequency Vs Serial Issue with USMs It is claimed that the most accurate way of transmitting the ultrasonic meter flow measurement to a supervisory system (e.g. flow computer) is via the serial link. This is because the ultrasonic meter calculates the actual flow rate and converts it to frequency. It is also claimed that over a long period of time, the accuracy of the flow

5

measurement using the frequency mode is as good as the serial link, however over a short period of time the frequency output from the ultrasonic meter may not be equal to the flow rate calculated by the meter. Some flow computers are capable of using serial and/or pulse output from multipath ultrasonic meters to carry out multiple ’k± factor interpolation. It is therefore important to select flow computers to suit ultrasonic meters or vice versa. It should be noted that if the flow computer is only capable of using the pulse option, then preferably the high pressure calibration of the meter is conducted in the pulse output mode. This will enable the ’k± factor data to be included in the flow computer configuration. If however the ultrasonic meter is calibrated in the serial mode and the flow computer is not capable of carrying out ’k± factor corrections using this mode, then a new meter factor and a new zero offset value is calculated and entered into the ultrasonic meter drive unit. From these two new values, it is possible to adjust the calibration error curve, using ’least mean square± correction to produce a new set of error values. 4 COMMISSIONING The turbine meter was commissioned in the usual way, making sure that the system was pressurised slowly, following the manufacturers commissioning guidelines. Turbine meter details, such as the ’k± factors, were entered into the flow computer to make sure that multiple ’k± factor correction is carried out. The ultrasonic meter pulse-output connection to the flow computer is similar to a turbine meter. With the serial connection, it was necessary to check the meter details, such as speed of sound, flow velocities, meter factors etc. It was noticed at this stage that the meter individual cord velocities and the individual speed of sound readings were not obtainable from the meter. The electronics board on the meter was then replaced to enable these readings to be accessed also. Recording of the meter diagnostics before and after the electronics board change was made to make sure that there were no significant changes. 5 FIELD OPERATION AND RESULTS Some difficulty was experienced with the ultrasonic meter pulse output during the commissioning. Maximum frequency obtainable from the meter was limited to 1250 Hz due to the capacitance effect of the interconnecting cable. This was resolved by reducing the time constant of the connection. It was also noticed that although the site gas flow was shut off and the turbine meter was showing zero frequency output, the ultrasonic meter was still registering erratic frequencies of between zero and 50 Hz. Remote monitoring of the two meters was carried out using the existing telephone lines. A dedicated data logger was installed, connected to the two independent flow computers and configured remotely to access and log the following information, in order to make sure that metrological comparison between the two metering systems can be carried out and the health of the ultrasonic meter can be monitored:

6

Turbine meter flow computer data logged Actual flow rate - m3/h Stream pressure - barg Reference flow rate - m3/h Stream temperature - degC Actual volume - m3 Stream density - kg/m3 Actual 0.5 hourly volume - m3 Meter frequency - Hz Reference volume - m3 Meter K-factor in use - pulses/m3 Reference 0.5 hourly volume - m3 Ultrasonic meter flow computer data logged Comms. Actual Flow Rate - m3/h Stream pressure - barg Actual flow rate - m3/h Stream temperature - degC Reference flow rate - m3/h Meter K-factor in use - pulses/m3 Actual volume - m3 Stream density - kg/m3 Actual 0.5 hourly volume - m3 Meter frequency - Hz Reference volume - m3 Reference 0.5 hourly volume - m3 Calorific value i-Butane � mol% Relative density n-Butane � mol% Methane - mol% i-Pentane - mol% Nitrogen � mol% n-Pentane - mol% Carbon dioxide - mol% Hexane - mol% Ethane - mol% Propane � mol% In addition, the majority of the serial data provided by the ultrasonic meter was also logged and remotely transferred. These included: Calculated velocity of sound - m/s Comms lost Error between calculated and measured VoS Pulse lost USM VoS � m/s FloRateDelta USM gas velocity - m/s VoSalarm Path 1 - 5 VoS - m/s AGCalarm Path 1 - 5 Gas Velocity - m/s Sample 1-5 alarms Path1 - 5 performance Path1a � 5 b AGC ratios During field operation, the performance of the USM transducers and their associated timing circuitry and metrology was assessed by comparing the speed of sound on each chord and secondly by comparing the measured, average speed of sound with a

7

theoretical value calculated from the gas composition, temperature and pressure. Using the gas composition data from the gas chromatograph together with the measured pressure and temperature, a theoretical value of the speed of sound was calculated, using the Advantica programme GasVLe. An example of comparing the two values (GasVLe Vs USM speed of sound) is shown below (Figure 3).

Figure 3. Speed of sound comparison between the GasVLe and Ultrasonic Meter It can be seen here that the two different methods of deriving the speed of sound varies by a maximum of ” 0.2%. This comparison confirms that there are no obvious errors in the operation of the timing or in the dimensional data in the ultrasonic meter. This technique was used through out the trial to confirm the validity of the speed of sound readings from the ultrasonic meter. At the start of the trial, the ultrasonic meter flow computer was configured to operate normally, i.e. it was allowed to choose the flow rate for calculations (pulse, serial or gas velocity). The flow computer first tries the pulse signal, then the transmitted gas velocity and finally the transmitted flow rate as explained in section 3.2. Daily comparisons between the turbine and the ultrasonic meters half hourly actual volumes in this mode of operation are plotted below (Figure 4).

Speed of Sound error%

-1

-0.5

0

0.5

1

0 2 4 6 8 10 12 14 16 18 20 22 24

Time (hr)

Spee

d of

Sou

nd e

rror

(%)

8

Figure 4. % Difference in the actual volumes passed between the turbine and the ultrasonic meters (with the flow computer operating normally) This is a typical example of how the two meters compare with each other over a 24-hour period. Majority of the time the two meters agree with each other to an accuracy of well within ”0.1%. Only occasionally this difference extended up to ”1%. If the two meters± outputs were averaged over 24-hours, the maximum deviation between the two was ”0.1%. This trend was found throughout the trial. Taking into account the uncertainty of the test facility, this difference lies well within the calibration results of the two meters. In order to check the effect of using just one source of flow rate, the flow computer was forced to use frequency-derived flow. Data logged over a 24-hour period is shown in Figure 5 below. A significant difference between the two meters can be seen here. The ultrasonic meter is registering volumes up to 5% lower than the turbine meter. Average deviation between the two meters over a 24-hour period was increased to around 4%.

Actual 0.5hr Volume Flow Error %

-1.50

-1.00

-0.50

0.00

0.50

1.00

1.50

0 2 4 6 8 10 12 14 16 18 20 22 24

Time (hr)

Volu

me

Flow

Err

or (

%)

9

Figure 5. % Difference in the actual volumes passed between the turbine and the

ultrasonic meters with the flow computer operating in frequency flow rate Further investigation was carried out to establish this deviation between different modes of operation of the flow computer. To do this, the frequency input from the ultrasonic meter to the flow computer was inhibited and the flow computer was forced to use the gas velocity-derived flow only. Comparison results between the turbine and the ultrasonic meter from this exercise are plotted below (Figure 6).


ultrasonic meters with the flow computer operating in velocity flow rate mode A further exercise was carried out such that only the serial flow rates are taken into account and used for calculations. To do this, the ultrasonic meter pipe diameter details within the flow computer were increased by 50% (inhibiting velocity flow) and the frequency input was also left inhibited. The two meters± volume flows in this

Actual 0.5hr Volume Flow Error %Frequency flow rate

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Time (hr)

Volu

me

Flow

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or (

%)

Actual 0.5hr Volume Flow Error %Gas velocity flow rate

-1.00

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me

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mode of operation were logged and a sample 24-hour results are plotted below (Figure 7).


ultrasonic meters with the flow computer operating in serial flow rate mode These results are very similar to the results obtained when the system was operated in the velocity mode. Again, the two meters agree with each other to an accuracy of ”0.1%. Interesting to note however that in this mode of operation, if the difference is not 0.1% between the two meters, the ultrasonic meter is permanently over reading the turbine meter by 0.5%. A further test was carried out to see if the results of the first exercise (normal mode of operation) could be repeated. The flow computer was configured back to its original set-up and further data was collected in this mode of operation. The results of this test are shown below (Figure 8). The agreement between the two meters is back to normal, i.e. they are in agreement to an accuracy of ”0.1%, with occasional difference of up to ”0.5%.

Actual 0.5hr Volume Flow Error %Serial flow rate

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me

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%)

11


ultrasonic meters (with the flow computer back to operating normally again) Flow Rate Influence on Ultrasonic Meter Accuracy The two meters were operated at different flow rates representing sites 20%, 40%, 80% and 90% of maximum flow rates to establish if the flow disturbance created by the turbine meter would influence the ultrasonic meter accuracy. This was monitored during the different modes of operation of the ultrasonic meter. An example of this is shown below (Figure 9 & 10).

Figure 9. Flow rate changes through the turbine and ultrasonic meters

Actual 0.5hr Volume Flow ErrorNormal after

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Reference Volume Flow-rate - day 18Serial flow rate until 09:30 then back to normal

0

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100

0 2 4 6 8 10 12 14 16 18 20 22 24Time (hr)

% o

f Qm

ax

12

Figure 10. % Difference in the actual volumes passed between the turbine and the ultrasonic meters during change over from serial to normal operation.

Figure 9 shows the increase of flow rates in time. At the start, the flow computer was operating in the ’serial± mode, with the flow rate set to 20% of maximum flow. This was changed to the ’normal± mode of operation and at the same time, flow rates were increased from 20% to 40% and gradually to 80% of maximum flow. Figure 10 shows the results between the two meters during this time. The error between the turbine and the ultrasonic meters varies between 0.1% and1% up and until the flow computer mode of operation changes from serial to normal (9:30). After this time, the error between the two meters reduces to 0.1%, with occasional difference of 0.5%. 6 CONCLUSIONS An Instromet multipath ultrasonic meter and an SMR-I turbine meter operate successfully with very small error (”0.1%) between the two meters. This error increased to 4% when the flow computer was forced to calculate flow rates using the pulse output from the ultrasonic meter. From this trial, it was established that the most accurate way to operate the ultrasonic meter is to let the flow computer decide the mode of operation for flow rate calculations. It is not yet fully understood if the flow computer uses the ultrasonic meter calibration ’k± factors for flow rate linearisation. Better understanding of the flow computers is necessary to establish correct operation with ultrasonic meters. Although there is a very large pressure cut through the pressure regulators on the downstream of the metering systems, this did not influence the operation of the ultrasonic meter. Turbine meter positioned upstream of the ultrasonic meter did not adversely effect the ultrasonic meter operation also.

Actual 0.5hr Volume Flow Error - day 18Serial flow rate until 09:30 then back to normal

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or (

%)

13

Comparison between the ultrasonic meter speed of sound and the speed of sound calculated from gas composition, pressure and temperature shows a very small deviation of ”0.2%. 7 REFERENCES 1. Marshall, D., Niazi A. and Burrows, M.: Multipath Ultrasonic Meter Performance. Effect of Ultrasonic Noise Generated by Control Valves, August 1998. 2. Niazi, A. and Gaskell M. Building Confidence with Multipath Ultrasonic Meters.18th NORTH SEA FLOW MEASUREMENT WORKSHOP 2000 3. Laughton, A. GasVLe (Version 4.1). Advantica Technologies Ltd. 8 ACKNOWLEDGEMENTS The authors wish to thank Gerard McGuinness of Transco (part of Lattice Group Plc) for his continuing support throughout this trial. The authors also wish to thank Instromet UK and Omni for their much appreciated technical support.

Denstad & Smørgrav, “Experience with Installations of Ultrasonic Gas Flow Meters under severe conditions”North Sea Flow Measurement Workshop, October 22-25, 2001, Kristiansand, Norway

Page 1 of 22

Paper 12:

Experience with Installation of Ultrasonic Gas Flow Metersunder severe conditions

North Sea Flow Measurement WorkshopOctober 22-25, 2001 Kristiansand, Norway

Authors:

Harald Denstad StatoilSkule E. Smørgrav FMC Kongsberg Metering AS

Reprints are prohibited unless permitted by the authors and the organizers


Page 2 of 22

SUMMARY:

Ultrasonic gas flow meters, primarily of the multipath kind, have gained a largeportion of the world market for custody transfer metering since the technology wasintroduced in the early 1990s. Over the last 4-6 years numerous papers havedescribed the features of ultrasonic meters, highlighted their advantages over moretraditional metering technologies such as orifice and turbines, and presentedoperational experiences.

This paper will discuss experiences from one permanent installation and two testinstallations where the FMC Kongsberg Metering’s FMU 700/MPU 1200 technologyhas been subjected to severe conditions. At the Statoil operated Åsgard B platform inthe North Sea two 20” FMU 700s were installed in 2000 and were faced with suchlevels of ultrasonic noise that they would not function properly. Through cooperationwith the technical people in Statoil and the ultrasonic group at FMC KongsbergMetering this situation was solved by installing analogue filters in the FMU 700s.Varying operational conditions such as pressure and temperature has also proved to beitems which need to be considered when setting up and commissioning ultrasonicmeters.

Installation effects caused by upstream piping configurations have always been animportant part of the discussion of ultrasonic technology. This paper will show anddiscuss results from tests performed at the Verbundnetz Gas and Ruhrgas, Lintorffacilities in Germany where an 8” MPU 1200 were exposed to a number of pipingarrangements. Some of which pushed the MPU beyond its capabilities.

As is showed here, the ultrasonic technology has a very bright future in gas meteringwhen used right. USMs have limitations and it is important to know what they areand to take these into account when designing metering stations where USMs are thesource of measurement.

ABBREVIATIONS AND SYMBOL LIST:

VNG Verbundnetz Gas AGFMU Fiscal Meter UltrasonicMPU MultiPath UltrasonicUSM UltraSonic MeterFMU 700 FMC Kongsberg Metering’s first generation ultrasonic gas flow

meterMPU 1200 FMC Kongsberg Metering’s second generation ultrasonic gas flow

meterRTR parameters Reference Transient Response parametersLL Low LevelHL High LevelISO International Organization for StandardizationIPU ISO Perturbation Unit


Page 3 of 22

1. INTRODUCTION

The operational experience from the above mentioned sites will be described as fourdifferent situations.

2. SITUATION 1: SET–UP

2.1. INSTALLATION

As can be seen in figure 1 below, the two FMU 700s on Åsgard B are installed inseries with 9D straight upstream pipe to the flow conditioner and an additional 7Dbetween the flow conditioner and the upstream 90º bend. Downstream meter 1 is a5D section before meter 2 and then a 13D section containing dual pressure andtemperature outlets as well as an annubar check meter.

The closest control valve, and possible ultrasonic noise source is more than 50 meters(110 D) upstream and more than 25 meters (55 D) downstream.

The installation is done according to normal specifications for an ultrasonic basedapplication and the upstream lengths and use of a flow conditioner prevents themeters from being affected by any special secondary flow profile effects.

Figure 1: Åsgard B metering section

Prior to installation the entire metering skid, as shown in figure 1 including flowcomputers, pressure transmitters, temperature transmitters and the annubar, was testedat K-Lab with different pressure and temperature combinations. And it was after thatsent to Advantica, the former BG Technology calibration facility in Bishop Auckland,England, for flow calibration.

No noise or other problems were observed during the flow calibrations. The resultsfrom the flow calibrations with calibration factors implemented is shown in figure 2below.

Flow Direction

FMU 1 FMU 2

Instrument spool

K-Lab flow conditioner

3190 mm (7 D) 4101 mm (9 D) 1850 mm 1850 mm2280 mm (5 D) 5900 mm (13 D)


Page 4 of 22

Åsgard B Flow Calibration Results 1999

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0 2000 4000 6000 8000 10000 12000 14000

Flow Rate (m3/h)

Dev

iati

on

(%

)

Calculation Meter 1

Verification Meter 1

Calculation Meter 2

Verification Meter 2

Figure 2: Åsgard B Flow Calibration

2.2. OBSERVATIONS

Calibration of Ultrasonic Meters

Statoil has two offshore installations in the area Halten – Nordland, Åsgard B andHeidrun, which both have gas metering stations based on two serial mountedultrasonic meters from two different suppliers. The main supplier at Heidrun isDaniel Europe while Åsgard B’s station is delivered by FMC. Both stations delivergas to the same gas pipeline and experiences more or less the same operationalconditions:

Mean gas velocity: 5 – 15 m/sTemperature: 40 – 60 oCPressure: 150 – 200 bar

Calibrations of both stations were very similar. The FMC metering skid was tested intwo steps; first at Statoil’s K-lab facility at Kårstø and finally at the BG Technology,now Advantica, test facility in Bishop Auckland, England. The Heidrun meteringskid was shipped from factory directly to Bishop Auckland.

The K-lab test was done to expose the USMs to temperature and pressure conditionsclose to the actual operating conditions. With K-Lab’s capacity these tests were withlow gas flow velocity. Because of compressor problems at K-Lab during the test thetest was done with a pressure far below later operational pressure. No results willtherefore be presented.


Page 5 of 22

At Bishop Auckland the tests were performed with actual operational conditions forgas flow velocity but very low gas temperature and pressure compared to later normaloperational conditions. The calibration was done with the two USMs in series withthe instrument spool piece. That is, the whole metering stations were shipped toBishop Auckland for calibration of the complete skids that were to be placed onÅsgard B and Heidrun.

The calibration was performed as an individual calibration of each meter against thereference gas flow velocity and a Certificate of Calibration were issued by BGTechnology for both Åsgard B and Heidrun ultrasonic meters. Based on thesecertificates calibration factors/curves were calculated for all USMs. FMC use acalibration curve equation of 1st degree polynomial. Daniel Senior Sonic use acalibration curve equation of 3rd order polynomial.

Both metering skids with serial mounted ultrasonic meters were calibrated againstreference on an individual basis. Deviation between the two serial mounted meterswas not taken into consideration during calibration.

Ultrasonic meters in operation

Åsgard B

Gas export from Åsgard B was started in October 2000. Early in operation strangebehavior was detected. Logging of signals from the FMU 700s showed results whichindicated that problems were due to ultrasonic noise disturbing the signals, this isdiscussed further in chapter 3.

Before implementation of analogue filters there was an internal deviation between thetwo meters varying between 0.3 % to up to 2 %. For Åsgard B this was not anacceptable situation and FMC was asked to do something about it.

Before implementation of filters Åsgard B also experienced sudden trips in themeters. This was due to a rise in export pressure in the meters. Initially the metershad been set up to switch between different RTR parameters dependent oftemperature level only. It was believed that the pressure would not influence theoperation to the same degree and that RTR parameters were mostly dependent ontemperature. Trips in the meters made the meters indicate zero flow through thestation even if there was a considerable export rate.

FMC reconfigured their software so that the meters switched between different RTRparameters depending on both temperature and pressure. Initially the pressure wasabout 130 bar when the first set of RTR parameters were found. The meters tripped atabout 175 bar. It was then concluded that an interval of about 30 bar was maximum ofwhat could be accepted as range before using a new set of RTR parameters. The newsoftware, therefore, includes a table of RTR parameters dependent of bothtemperature and pressure, that is a 4 x 2 matrix of RTR parameters as shown below.


Page 6 of 22

∆T1 ∆T2 ∆T3 ∆T4∆P1 RTR1 RTR2 RTR3 RTR4∆P2 RTR5 RTR6 RTR7 RTR8

Matrix 1.

The influence of noise seemed to be more damaging to the measurement to one of themeters than to the other. Therefore, Åsgard B had to disqualify one of the meters inthe time between startup and date for implementation of filters (see chapter 3 below)and new software with RTRs for different pressure levels. The last job with the meterswas done in June 2001. This means that the Åsgard B gas export metering station didnot behave to Statoil’s satisfaction for a period of 8 months of operation.

The succeeding 2 months from mid June to mid August the meters were in operationwith no problems and with an average internal deviation of about 0.22 %.

Figure 3 shows the deviation between the two FMU 700s in the period from June toAugust 2001.

Deviation Between Åsgard Meter 1 & Meter 2

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16.06.01 21.06.01 26.06.01 01.07.01 06.07.01 11.07.01 16.07.01 21.07.01 26.07.01 31.07.01 05.08.01 10.08.01

De

via

tio

n (

%)

Deviation M1 & M2

Figure 3: Deviation between Åsgard B meter 1 and meter 2

Heidrun:

Gas export from Heidrun was started in February 2001. Early in operation strangebehavior was detected on this installation as well. Previous experiences from ÅsgardB made us investigate if there was ultrasonic noise present that disturbed the signals.It was quickly concluded that this was not the problem. The problem was finallyfound to be faulty transducers. After less than two months of operation two sets of


Page 7 of 22

transducers had to be dismounted and shipped back to factory for repair andcalibration.

Alarms have also been detected from the flow computers, which indicated problemswith transducers. After a lot of investigation both from Heidrun personnel and Danielpersonnel, this problem was found to be caused by a software bug in the flowcomputer.

After 8 months of operation the Heidrun gas export metering skid has, therefore, notbehaved to Statoil’s satisfaction.


Page 8 of 22

3. SITUATION 2: ULTRASONIC NOISE

3.1. OBSERVATIONS

There have been several issues with the FMU 700 ultrasonic meters on Åsgard B.Apart from the issues discussed above, FMC could see from measurement data loggedwith the FMU 700 meters, that additional issues were due to noise disturbing theultrasonic signals. To verify this, and to try to localize the source of noise, FMCprocured two ultrasonic clamp-on transducers that had a sensitivity well suited forsuch type of external measurements.

From the measurements done 17.10.00 with one of these clamp-on transducers atÅsgard B, it was found that the strongest noise was at 9 kHz and that it waspropagating through the construction which the pipe with the two FMU 700 meterswas resting on. Noise with this frequency can propagate over very long distances,especially in steel.

Figure 4 below show the frequency spectrum measured with the external clamp-ontransducers. The Frequency scale is 0 – 200 kHz.

Figure 4: Frequency spectrum with external clamp-on transducers, 0-200 kHz.


Page 9 of 22

Figure 5 below show the frequency spectrum measured with the external clamp-ontransducers. Now with a frequency scale of 0 – 20 kHz.

Figure 5: Frequency spectrum with external clamp-on transducers, 0-20 kHz.

Measurements were also done with the transducers on the FMU 700 meters. Fromthese measurements it became evident that there was considerable noise at about 70kHz as well. This noise was very difficult to detect with the clamp-on transducers dueto the extremely high amplitude of the noise at 9 kHz. The noise at 9 kHz wereseveral hundred times higher in amplitude than the signal from the transducers.


Page 10 of 22

The frequency spectrum as recorded by the FMU 700 prior to installing any filters canbe seen in figure 6a below. Figure 6b shows the actual signal recorded.

0

50

100

150

200

250

300

0 50 100 150 200 250

Freq kHz

Figure 6a: Frequency spectrum recorded by the FMU 700 before installing filter

Path 4 Original received signal

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99

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Figure 6b: Received signal on path 4 by the FMU 700 before installing filter

Measurements of noise on the gas pipe at different levels of mean gas velocityshowed that the source of noise and the noise frequency were not dependent on exportrate.


Page 11 of 22

From all the measurement results, it was decided to solve the problems by usinganalogue filters. To decide which parameters the final filters were going to have, anadjustable filter was to be tested at Åsgard B.

Testing was started at Kongsberg before being installed at Åsgard B. The aspects ofhow the installation of a filter like this was going to affect the performance of themeter was checked. From theoretical evaluations it was shown that the performancewas going to be unaffected. The preliminary tests at Kongsberg confirmed this.

From simulations and testing at Kongsberg, it was found that the best solution wouldbe to use an 8. order Butterworth high pass filter. The corner frequency was found tobe optimal at 110/120 kHz. At Åsgard it was found that the most optimal frequencywould be 110 kHz.

The frequency spectrum as recorded by the FMU 700 after installing analogue filtersis shown in figure 7a below. Figure 7b shows the actual signal recorded.

0

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100

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300

0 50 100 150 200 250

Freq kHz

Figure 7a: Frequency spectrum recorded by the FMU 700 after installing filters


Page 12 of 22

Path 4 Filtered with 8.Order Butterwort High pass filter at fc = 110 kHz

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Figure 7b: Received signal on path 4 by the FMU 700 after installing filter

As can be seen in figures 7a and 7b the amplitude of the noise level recorded by theFMU transducers is actually higher than the ultrasonic signal transmitted by the FMUitself.

To get an impression of how the sensitivity of the clamp-on transducers affects theresult seen in the snapshots if figures 4 and 5, one must look at the calibration curveof these transducers. At 30 kHz the sensitivity of the clamp-on transducer is –60 dB.At 70 kHz this value is –48 dB and at 160 kHz the value is –22 dB. So when the noseat 70 kHz and the signal at 160 kHz are not evident, this tells us how strong the noiseat 9 kHz is.


Page 13 of 22

3.2. CONCLUSIONS

Conclusion after nearly one year of operation:

Fiscal ultrasonic metering of gas under severe condition is still an area where thereseems to be a need for more knowledge for both manufacturers and customers. To geta satisfactory operation, there has to be a high degree of cooperation between the twoparts and a will from both sides to make it work satisfactory and to increase theknowledge about the details in the metering principles of USMs. Without a thoroughknowledge it seems to be difficult to maintain a high quality of wanted results.Mounting two USMs in series may be extra challenging if you do not have a basicunderstanding of the principles.

Up until today the source of noise has not been discovered, but the problem wassolved effectively by installing analog filters on the receiver electronics.When the next generation USM electronics was developed by FMC such conditionswere taken into account and provisions were made to be able to solve it in software inthe MPU 1200. This would be done by software filtering.


Page 14 of 22

4. SITUATION 3: FLOW PROFILES – LOW VELOCITY

4.1. INSTALLATION

An 8” MPU 1200 was tested at the Verbundnetz Gas AG (VNG) facility inKircheilingen, Germany during the fall of 2000. VNG’s primary purpose was to testthe MPU in a situation which would be typical for many of their locations. As asecondary purpose they also wanted to see the meter’s performance under even moreadverse conditions. The reference used was turbine meters previously calibrated atPigsar.

The MPU was installed downstream an above ground header as can be seen in figure8 below. The piping goes vertically from the header, through two 90º large radiusbends in the vertical plane, one 90º normal bend in the horizontal plane, and then thetwo bends out of plane immediately upstream the MPU.

Figure 8: Installation at VNG

4.2. OBSERVATIONS

During the installation the following tests were carried out:

1. A basis or reference test, where the meter was placed with more than 100Dstraight upstream length. This is the curve marked “Basis-vergleich” in figure 11and “BASIS” in figure 13.

2. The meter placed 7D downstream of the second of the two out of plane bends.This is the curve marked “RK” in figure11.


Page 15 of 22

3. The meter placed 7D downstream of the second of the two out of plane bends witha high perturbation device or a “swirl-amplifier” installed between the two out ofplane bends. This is the curve marked “RK+HB” in figure 11. The “half-moonplate” can be seen in figure 9.

4. The meter placed 7D downstream of the second of the two out of plane bends witha high perturbation device or a “swirl-amplifier” installed between the two out ofplane bends, and a flow conditioner immediately downstream the second bend.This is the curve marked “RK+HB+GR” in figure 2. The flow conditioner usedcan be seen in figure 10.

Figure 9: “Half-Moon-Plate” Figure 10: Flow Conditioner

Vergleich von USZ (Kongsberg) und TRZ (Elster)USZ 7xD nach Raumkrümmer

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eic

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i

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RK + HB 15.09.00

RK 14.09.00

RK + HB + GR 18.09.00

Basis-Vergleich 20.09.00

Verkehrsfehlergrenzen

Eich-Fehlergrenzen

05.10.2000 gh

GWT-TU DredenVNG AG Leipzig /UGS - KirchheilingenFMC -Kongsberg

Figure 11: VNG 7D results

The y-axis in figure 11 above and figure 13 below is the percent difference from thereference. The x-axis is the actual flowrate in percent of the maximum flowrate. This


Page 16 of 22

resulted in that 25% was approximately 3,5 m/s and 50% was approximately 7,0 m/sgas flow velocity.The screen below shows a typical picture from the MPU WinScreen program whenthe MPU 1200 is subjected to similar swirl conditions as on VNG.

Figure 12: MPU WinScreen showing typical swirl conditions

After the first series of tests with the meter installed 7D downstream of the doublebend were completed, the MPU was moved to a position 3D downstream of thedouble bend and the following tests were carried out:

5. The meter placed 3D downstream of the second of the two out of plane bends.This is the curve marked “RK” in figure 13.

6. The meter placed 3D downstream of the second of the two out of plane bends witha high perturbation device or a “swirl-amplifier” installed between the two out ofplane bends. This is the curve marked “RK+HB” in figure 13. The “half-moonplate” can be seen in figure 9.

7. The meter placed 3D downstream of the second of the two out of plane bends witha high perturbation device or a “swirl-amplifier” installed between the two out ofplane bends, and a flow conditioner immediately downstream the second bend..This is the curve marked “RK+HB+GR” in figure 13. The flow conditioner usedcan be seen in figure 10.


Page 17 of 22

Vergleich von USZ (Kongsberg) und TRZ (Elster)USZ 3xD nach Raumkrümmer

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lati

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eic

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ng

i

n %

RK

RK+HB

RK+HB+GR

BASIS

Verkehrsfehlergrenzen

Eichfehlergrenzen

GWT-TU DredenVNG AG Leipzig /UGS - KirchheilingenFMC -Kongsberg 05.10.2000 gh

Figure 13: VNG 3D results

4.3. CONCLUSIONS

The meter had previously been flow calibrated at the Ruhrgas Pigsar facility and thelinear correction factors A and B, in the form Q = A*Qο + B, had been implemented.The base test results from test 1 show that the offset of the meter is less than 0,5%from the reference.

With the meter placed 7D downstream of the double bends in test 2, the offset isapproximately within 0,2% of the base results which also is within the repeatability ofthe meter.Test 3 however, where the “half-moon-plate” is also placed upstream, the MPUperformance shifts about 1% from the base test.Test 4 shows that a flow conditioner is able to bring the extreme conditions in test 3 toconditions easily measured by the MPU.

Similar results can be seen in tests 5-7 with the meter 3D from the out of plane bends,with the difference that test 5 also shifts the MPU results to approximately 0,6%above the base results. Again, with the flow conditioner the results are practically thesame as for the base test.

One interesting observation was made during the extreme tests with the “half-moon-plate”. The turbine meter placed immediately downstream of the MPU (yellow spoolin picture 1) showed more than 3% offset from the reference when the MPU was lessthan 1% offset.

These tests were all done at fairly low flow velocities and the next chapter shows thatthe performance at low velocities is not necessarily reflected at higher velocities.


Page 18 of 22

5. SITUATION 4: FLOW PROFILES – HIGH VELOCITY

5.1. INSTALLATION

The same 8” MPU 1200 that was tested at VNG was also tested by Ruhrgas at theirLintorf test facility during the summer of 2000. Ruhrgas got the meter flow calibratedat their Pigsar facility before the meter was shipped to Lintorf. Here they exposed themeter to a large number of different tests, two of which were similar to the onesperformed by VNG.

The MPU 1200 was installed downstream of two double bends out of plane with andwithout an ISO HL High Level perturbation device placed between the two bends.The installation at Lintorf can be seen in figure 14 below.

Figure 14: Installation for ISO LL and HL perturbation tests, top and side view

The ISO perturbation units (IPU) were initially designed to test turbine meters underdisturbed conditions, see e.g. ISO 9951 and CEN prEN 12261. The so called low


Page 19 of 22

level (LL) version consists of two elbows out of plane with a downstream diffuser inthe form of an enlargement in pipe diameter, in this case from 175 mm to 200 mm, asdefined in e.g. ISO 9951. High swirl and axial profile deformations are produced bythe IPU LL. The high level version (HL) consists additionally of a half-moon-plateinstalled between the two bends. The axial profile deformations are higher and alsoinstationary effects are higher due to flow separation. The IPU HL simulates flowperturbations produced by regulators and valves.Below is a picture from Lintorf with the USM in the 18.5D position.

Figure 15: Lintorf installation

5.2. OBSERVATIONS

Included here are results from two of the tests performed by Ruhrgas. These testswere all completed with an operational pressure of approximately 10 bar andtemperature of approximately 10ºC. During the test period a number of tests werecompleted with different setups of the meter. All the results shown below are with asetup done by FMC personnel.

The x-axis in all graphs is the volume flow Qv through the meter as percent of amaximum Q of 3470 m³/h. This volume flow gave a maximum gas flow velocity of30 m/s through the 8” MPU 1200, which is the maximum velocity the meter isspecified to.

1. IPU Low Level perturbation at 18.5D.The MPU was installed 18.5D downstream of the two out of plane bends and thediffuser. The results can be seen below in figure 16.


Page 20 of 22

HDV Lintorf IPU Low Level Perturbation 18.5 D, 10 bar

-2

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-1

-0,5

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0,5

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0 20 40 60 80 100 120

Flow Qv(%)

Err

or

(%)

FMC Parameters/SW

Figure 16: Lintorf LL results

2. IPU High Level perturbation at 18.5D.The MPU was installed 18.5D downstream of the two out of plane bends and thediffuser. During this test the “half-moon-plate” was installed between the twoupstream out of plane bends as shown in figure 14. The results can be seen belowin figure 17.


Page 21 of 22

HDV Lintorf High Level Perturbation 18.5D, 10 bar

-10

-8

-6

-4

-2

0

2

4

6

8

10

0 20 40 60 80 100 120 140

Flow Qv(%)

Err

or

(%)

FMC Parameters/SW

Figure 17: Lintorf HL results

5.3. CONCLUSIONS

The results in figure 16 show solid performance of the USM when placed 18.5Ddownstream of the two bends out of plane, as was also shown in the VNG tests above.

The results in figure 17 however, show that placing the MPU 18.5D downstream of adouble out of plane bend with a high level perturbation device, or any other partproducing similar disturbances, is pushing the MPU beyond its limits.

When comparing the Lintorf results in figure 17 with the ones from the VNG figures11 and 13 above they give us reason to conclude that the secondary flow patternscreated by the high level perturbation device increase with the flow velocity. TheMPU is able to compensate for the effects up to the approximate 7 m/s velocity atVNG but not with the higher velocities at Lintorf.

Individual path data from the MPU shows that the transverse velocity components arehigher than 100% of the actual mean flow velocity and this is really an extreme swirlcondition. The MPU has simply not been designed to cope with such specialconditions.

It can also be noted that the MPU actually measures even though the velocities go upto more than 115% of the maximum specified range of the meter.


Page 22 of 22

6. CONCLUSIONS

The ultrasonic technology is excellent and provides the users with a lot of valuableinformation. It is a cost-effective technology with easy and superior performance in alarge number of areas to other technologies.However, USMs do have limitations, and it is important that users know them and usethe USMs right.

It is also important that manufacturers, contractors and users work together. By doingso most, if not all, limitations can be overcome either during the design andmanufacturing stage or during the installation and operation stage.

The final conclusion is that although ultrasonics has come a long way since thebeginning in the late 1980s and early 1990s, there are still challenges ahead. Thetechnology will develop to further increase the performance in areas and one will alsosee that ultrasonics will continue to find new applications.

7. ACKNOWLEDGEMENTS

The authors would like to thank the following for their contribution with results andexperience for this paper:

Dr. Detlef Vieth, RuhrgasDr. Gehlhaar, VNGTore Magne Skar, Skar TechnologiesMorten Marstein, FMC Kongsberg Metering ASAtle Abrahamsen, FMC Kongsberg Metering ASTon Heistad, FMC Kongsberg Metering AS

1


Temperature Changes Across Orifice Meters

Mr. Ali Niazi, Advantica Technologies Ltd. Mr. Sahan Thalayasingam, Advantica Technologies Ltd.

1 INTRODUCTION When a real gas flows through an orifice plate, an irrecoverable pressure loss occurs downsteam due to the expansion of the gas, which results in a temperature drop. Knowledge of the density of the gas at upstream conditions is necessary for accurate calculation of flow rate. If density is measured, a density cell is normally installed at a tapping downstream of the orifice-plate meter, as shown in Figure 1 below. Densitometers incorporate their own temperature sensor but if density is calculated from the gas composition, a temperature sensor is installed in a downstream thermowell. The measurement is made some 8D downstream of the orifice plate in order to avoid flow disturbances. Whichever method is used, the measurement needs to be corrected to upstream conditions. While temperature correction is applicable to both methods, the density measurement also requires pressure correction, since the pressure used in the density calculation method is that taken at the upstream pressure tapping. For some time now, the industry has been raising the question as to whether National and International standards use the correct method for determining the temperature drop. The internationally recognised standards for orifice-plate metering, such as ISO 51671, consider the process that produces the temperature drop to be isentropic. This paper describes a theoretical analysis of the process that governs the nature and magnitude of the temperature drop due to the gas expansion, which occurs when gas flows through an orifice plate. The analysis considers both isentropic and isenthalpic processes. Experiments carried out are also described, which support the theory that the expansion process is isenthalpic.

2

Figure 1. Orifice-plate Metering System with Pressure Recovery Method of Installation of Density Cell 2 THEORY Figure 2 below shows the flow patterns through an orifice-plate meter.

3

According to the draft ISO 5167 the pressure loss, ω∆ , for orifice plates is approximately related to the differential pressure ˚ p by:

( )( )24

24

11

11

C

C

−−

−−=∆

β

βω p

CC

∆+−

2

2

ββ

This pressure loss is the difference between the static pressure measured on the upstream side of the orifice plate, and that measured on the downstream side, where the static pressure recovery is considered to be complete (Figure 2). Assuming the expansion process is isenthalpic, the corresponding temperature drop between the two points can be evaluated using the Joule Thomson coefficient:

µ JT = HP

T

∂∂

The isenthalpic expansion is expressed as:

PPH TZ

PCRT

PT

∂∂

=

∂∂ 2

In the region of most interest (0 ‘C to 40 ‘C, up to 70 bar), the simple equation for the calculation of compressibility factor, Z, for ’Mean Bacton Gasβ may be expressed as a simple function of pressure and temperature: Z = 1 + bP + cP 2

Where, b = ( ) 52 1003.05.33.264 −×−+− TT c = ( ) 82 10093.02.1120 −×++ TT Therefore,

( ) 51003.025.3 −××−=

∂∂ TTb

and,

( ) 810093.022.1 −××+=

∂∂ TTc

Hence, with the following nominal values for mean Bacton Gas at 70 bar and 10‘C, T = 283.15‘K

4

P = 70 bar R = 8.31434 J/(mol ‘K) CP = 0.04732 MJ/(kmol ‘K) Z = 0,8451

∂∂

+

∂∂

=

∂∂

TcP

TbP

TZ

P

2

= 2.18 × 10 3− /�K

and HP

T

∂∂ = 0.4377 �K/bar

For isentropic expansion however, with Z = 0.8451 ,

PHS PCZRT

PT

PT

+

∂∂

=

∂∂

= 1.037 �K/bar Both the above formulae assume that the process is adiabatic. 3 EXPERIMENTAL ARRANGEMENT A series of experiments was carried out at our Low Thornley Test Facility in order to determine the correct formula to be used for the temperature drop. A 200 mm pipe was set up as shown in Figure 3 below. A Daniel Junior orifice-plate carrier was installed 30D downstream of a Zanker flow straightener and 20D upstream of a straight pipe. The meter run was insulated for 20D upstream and 10D downstream of the orifice plate in order to provide environmental protection during the experiments. Four platinum resistance thermometers, 4 mm diameter were installed on the straight pipe directly into the gas stream, 1.87D upstream of the orifice-plate carrier on a PCD of 120 mm. A further four thermometers were installed 6D downstream of the orifice-plate carrier on the same PCD. A pressure tapping was also installed at this location. Orifice-plate temperature was recorded at the plate itself by using the spare set of 13 mm flange tappings and installing two thermometers on a PCD of 180 mm. All of the temperature sensors were calibrated using an oil bath prior to installation. KDG pressure transmitters were used to measure the upstream static pressure and the differential pressure, as well as the overall pressure loss. Four orifice plates, with – ratios of 0.2, 0.4, 0.6, and 0.75, were manufactured and fully inspected to comply with ISO5167.

6

4 TEST METHOD An in-situ calibration check was carried out on the temperature sensors at the beginning of the experiments using the 0.4 – orifice-plate set-up. The test line was pressurised and allowed to ’floatβ at the upstream Bishop Auckland � Saltwick feeder line pressure (typically about 28 bar and 5‘C) in order to reduce any temperature variations at the orifice plate, which would otherwise occur due to Joule-Thomson cooling effect at the test siteβs regulators. The flow rate through the set-up was increased until the orifice-plate pressure differential (˚ P) was 50 mbar. All ten temperature sensors were sampled twenty times over a period of 10 minutes in order to observe any differences between the temperature readings at very low ˚ P. It was expected that at this low pressure differential all of the temperature sensors would read approximately the same. Flow rate was then increased until the differential pressure was 250 mbar and then in steps of 250 mbar up to a maximum of 1.5 bar. Data for pressures, differential pressures and temperatures were recorded at each step. At the end of these tests, the flow rate through the orifice plate was reduced so that the ˚ P was 50 mbar for a final test, to ensure that no drift had occurred in the sensors or the data logging circuitry. The remaining three plates were then tested in turn. During the experiments with the 0.6 – and 0.75 – plates the test method had to be changed. This was due to the operational restrictions on the flow rates available through the site. For these two plates, the flow rate through the system was slowly increased from 50 mbar differential to maximum differential over a period of approximately 16 minutes, logging all of the pressure and temperature sensors every 18 seconds. For each test,

gas samples were analysed and values for the gas properties Z, M, Cp and

∂∂TZ were

calculated, using the Advantica programme GasVLe2. Gas composition ranges, together with test conditions, are shown in Table 1 below:

Table 1 – RATIO0.2 0.4 0.6 0.75

Temperature Range (oK) 9.7 - 11.1 2.1 - 4.2 4.4 - 8.3 9.0 - 23.0Pressure Range (Bar) 30.9 - 31.4 27.5 - 29.8 27.8 - 32.0 32.4 - 37.2

GAS COMPOSITION RANGEComponent Mol %

Methane 94.137 - 95.568Ethane 3.041 - 4.194Propane 0.146 - 0.38n-Butane 0.011 - 0.044i-Butane 0.008 - 0.028n-Pentane 0.003 - 0.007i-Pentane 0.001 - 0.006Hexanes 0.011 - 0.03Carbon Dioxide 0.415 - 0.446Nitrogen 0.699 - 0.746Molecular Weight 16.748 - 17.008

7

5 RESULTS AND DISCUSSION The temperature drop between upstream and 6D downstream of the orifice plate is shown in Figures 4 & 5.The temperature drop has been calculated as the difference between the means of the four upstream and the four downstream thermometers. It can be seen from these two graphs that the consistency in the results for the two smaller – ratio plates, 0.2 and 0.4, was very good and the same results were obtained for the individual temperature sensors rather than plotting the average values. For the two larger – ratio plates, 0.6 and 0.75, the results were much more scattered. This was due to the way the tests were conducted which prevented the use of a 10 minute averaging period. During the commissioning of the system, i.e. when the flow rate was zero, differences of up to 0.08 ‘K between the upstream and downstream sets of thermometers were observed. This was attributed to scatter arising form the calibration of the thermometers. These offsets are shown in Table 2, second row, below:

These offsets were then corrected for in Figures 4 and 5 below, assuming that the temperature difference is zero. It can be seen that the temperature drop for each plate is proportional to the pressure loss and that the agreement between the experimental and the theoretical isenthalpic values is extremely good.

Table 2: OFFSETS OBSERVED AT ZERO FLOW ON DOWNSTREAM THERMOMETERS

(RELATIVE TO UPSTREAM THERMOMETERS)

– RATIOLOCATION

0.2 0.4 0.6 0.75

Downstream Flange Tap -0.4 0.08 -0.46 0.05

6 Diameters -0.07 0 0.03 -0.05Downstream

8

Figure 4

9

Figure 5

One of the reasons for carrying out the experiments at a low pressure of 28 bar was that at this pressure, assuming Mean Bacton Gas composition and the following values:

10

T = 278.15 ‘K (5 ‘C) P = 28.6 bar abs Cp = 0.0397 MJ/Kmol ‘K R = 8.31434 J/(mol ‘K)

3109326.0 −×=

∂∂

PTZ ‘K-1

Therefore,

528.0=

∂∂

HPT ‘K/bar

and with Z = 0.9298

422.2=

∂∂

SPT ‘K/bar

The large difference between the predictions of the two formulae at this pressure makes the interpretation of the results very straightforward. Stagnation Temperature Rise A secondary effect, which could cause errors in the measured temperatures, is the stagnation temperature rise which occurs when flowing gas is brought to rest in front of a probe. This is given by:

=∆

MC

VTP

STAG

2

2

With the exception of the downstream flange probe, it was expected that, where the gas velocity is very low, all of the probes would be affected to some extend. Table 3 below shows that the maximum stagnation temperature rise for the upstream thermometers was 0.38 ‘K with Cp = 47430 J/(kmol ‘K) and M = 17 (approx.). With the exception of the downstream flange tap probe, all probes would have been affected by virtually the same amount.

11

There will be a difference in upstream and downstream stagnation rises due to the change in density across the orifice plate. Since the density decreases by approximately 4% across the plate, the downstream stagnation temperature rise will be greater than the upstream one by approximately 8%, i.e. 0.03 ‘K for the 0.75 – plate. This is a very small rise in the stagnation temperature and therefore this effect can be neglected. Whilst not essential to the experiment, the thermometers installed in the spare flange taps have shown interesting results. With the exception of the 0.75 – plate tests, the upstream sensor effectively remained at the temperature of the other four upstream sensors. The downstream sensor showed an offset of up to 0.46 ‘K at zero flow (Table 2). It was suspected that this might have been due to the close proximity of the large thermal mass of the orifice-plate carrier. During the tests with the 0.75 – plate, the two flange-tap sensors showed erratic behaviour relative to the upstream and downstream sets. The difference between the two flange tap sensors, however, was consistent and varied linearly with the flow. The slopes of the temperature drop/differential pressure graphs for the downstream sensor varied with – ratio and ranged from 0.5 ‘K/bar for the 0.2 – plate to 0.8 ‘K/bar for the 0.6 – plate, Figures 6 & 7 shown below. This variation can only partly be attributed to stagnation temperature differences between the downstream flange tap and the downstream set of thermometers (the downstream flange tap probe will read cold due to this effect relative to all the other probes). The variation in slope may have resulted from the combination of low gas velocity in this re-circulation zone together with the thermal mass of the orifice-plate carrier. Further work is needed to confirm the gas temperature in this region.

Table 2: STAGNATION TEMPERAURE RISE

– V (m/s) ˚ TSTAG

0.2 2.8 0.0020.4 11.2 0.0220.6 23.8 0.102

0.75 46.3 0.384

12

Figure 6

13

Figure 7

14

6 CONCLUSIONS The temperature change across orifice plates from upstream to a plane 6D downstream of the plate were found to be approximately 0.54 ‘C/bar at pressures and temperatures in the ranges 27 � 32 bar and 2 � 12 ‘C. All four – ratio orifice plates tested (0.2, 0.4, 0.6 and 0.75) showed the same behaviour. The experimental results agreed extremely closely with the assumption that the expansion across an orifice plate is isenthalpic. 7 REFERENCES 1 ISO 5167-1 1991. Measurement of fluid flow in close conduits. Part 1. Pressure differential devices. 2 Laughton, A. GasVLe (Version 4.1). Advantica Technologies Ltd. 8 ACKNOWLEDGEMENTS The authors wish to acknowledge both the practical and theoretical studies carried out by Dr Roger Norman which form the basis of this paper. (Dr Roger Norman is no longer employed by Advantica Technologies Ltd).

1


Temperature Changes Across Orifice Meters

Mr. Ali Niazi, Advantica Technologies Ltd. Mr. Sahan Thalayasingam, Advantica Technologies Ltd.

1 INTRODUCTION When a real gas flows through an orifice plate, an irrecoverable pressure loss occurs downsteam due to the expansion of the gas, which results in a temperature drop. Knowledge of the density of the gas at upstream conditions is necessary for accurate calculation of flow rate. If density is measured, a density cell is normally installed at a tapping downstream of the orifice-plate meter, as shown in Figure 1 below. Densitometers incorporate their own temperature sensor but if density is calculated from the gas composition, a temperature sensor is installed in a downstream thermowell. The measurement is made some 8D downstream of the orifice plate in order to avoid flow disturbances. Whichever method is used, the measurement needs to be corrected to upstream conditions. While temperature correction is applicable to both methods, the density measurement also requires pressure correction, since the pressure used in the density calculation method is that taken at the upstream pressure tapping. For some time now, the industry has been raising the question as to whether National and International standards use the correct method for determining the temperature drop. The internationally recognised standards for orifice-plate metering, such as ISO 51671, consider the process that produces the temperature drop to be isentropic. This paper describes a theoretical analysis of the process that governs the nature and magnitude of the temperature drop due to the gas expansion, which occurs when gas flows through an orifice plate. The analysis considers both isentropic and isenthalpic processes. Experiments carried out are also described, which support the theory that the expansion process is isenthalpic.

2

Figure 1. Orifice-plate Metering System with Pressure Recovery Method of Installation of Density Cell 2 THEORY Figure 2 below shows the flow patterns through an orifice-plate meter.

3

According to the draft ISO 5167 the pressure loss, ω∆ , for orifice plates is approximately related to the differential pressure ˚ p by:

( )( )24

24

11

11

C

C

−−

−−=∆

β

βω p

CC

∆+−

2

2

ββ

This pressure loss is the difference between the static pressure measured on the upstream side of the orifice plate, and that measured on the downstream side, where the static pressure recovery is considered to be complete (Figure 2). Assuming the expansion process is isenthalpic, the corresponding temperature drop between the two points can be evaluated using the Joule Thomson coefficient:

µ JT = HP

T

∂∂

The isenthalpic expansion is expressed as:

PPH TZ

PCRT

PT

∂∂

=

∂∂ 2

In the region of most interest (0 ‘C to 40 ‘C, up to 70 bar), the simple equation for the calculation of compressibility factor, Z, for ’Mean Bacton Gasβ may be expressed as a simple function of pressure and temperature: Z = 1 + bP + cP 2

Where, b = ( ) 52 1003.05.33.264 −×−+− TT c = ( ) 82 10093.02.1120 −×++ TT Therefore,

( ) 51003.025.3 −××−=

∂∂ TTb

and,

( ) 810093.022.1 −××+=

∂∂ TTc

Hence, with the following nominal values for mean Bacton Gas at 70 bar and 10‘C, T = 283.15‘K

4

P = 70 bar R = 8.31434 J/(mol ‘K) CP = 0.04732 MJ/(kmol ‘K) Z = 0,8451

∂∂

+

∂∂

=

∂∂

TcP

TbP

TZ

P

2

= 2.18 × 10 3− /�K

and HP

T

∂∂ = 0.4377 �K/bar

For isentropic expansion however, with Z = 0.8451 ,

PHS PCZRT

PT

PT

+

∂∂

=

∂∂

= 1.037 �K/bar Both the above formulae assume that the process is adiabatic. 3 EXPERIMENTAL ARRANGEMENT A series of experiments was carried out at our Low Thornley Test Facility in order to determine the correct formula to be used for the temperature drop. A 200 mm pipe was set up as shown in Figure 3 below. A Daniel Junior orifice-plate carrier was installed 30D downstream of a Zanker flow straightener and 20D upstream of a straight pipe. The meter run was insulated for 20D upstream and 10D downstream of the orifice plate in order to provide environmental protection during the experiments. Four platinum resistance thermometers, 4 mm diameter were installed on the straight pipe directly into the gas stream, 1.87D upstream of the orifice-plate carrier on a PCD of 120 mm. A further four thermometers were installed 6D downstream of the orifice-plate carrier on the same PCD. A pressure tapping was also installed at this location. Orifice-plate temperature was recorded at the plate itself by using the spare set of 13 mm flange tappings and installing two thermometers on a PCD of 180 mm. All of the temperature sensors were calibrated using an oil bath prior to installation. KDG pressure transmitters were used to measure the upstream static pressure and the differential pressure, as well as the overall pressure loss. Four orifice plates, with – ratios of 0.2, 0.4, 0.6, and 0.75, were manufactured and fully inspected to comply with ISO5167.

6

4 TEST METHOD An in-situ calibration check was carried out on the temperature sensors at the beginning of the experiments using the 0.4 – orifice-plate set-up. The test line was pressurised and allowed to ’floatβ at the upstream Bishop Auckland � Saltwick feeder line pressure (typically about 28 bar and 5‘C) in order to reduce any temperature variations at the orifice plate, which would otherwise occur due to Joule-Thomson cooling effect at the test siteβs regulators. The flow rate through the set-up was increased until the orifice-plate pressure differential (˚ P) was 50 mbar. All ten temperature sensors were sampled twenty times over a period of 10 minutes in order to observe any differences between the temperature readings at very low ˚ P. It was expected that at this low pressure differential all of the temperature sensors would read approximately the same. Flow rate was then increased until the differential pressure was 250 mbar and then in steps of 250 mbar up to a maximum of 1.5 bar. Data for pressures, differential pressures and temperatures were recorded at each step. At the end of these tests, the flow rate through the orifice plate was reduced so that the ˚ P was 50 mbar for a final test, to ensure that no drift had occurred in the sensors or the data logging circuitry. The remaining three plates were then tested in turn. During the experiments with the 0.6 – and 0.75 – plates the test method had to be changed. This was due to the operational restrictions on the flow rates available through the site. For these two plates, the flow rate through the system was slowly increased from 50 mbar differential to maximum differential over a period of approximately 16 minutes, logging all of the pressure and temperature sensors every 18 seconds. For each test,

gas samples were analysed and values for the gas properties Z, M, Cp and

∂∂TZ were

calculated, using the Advantica programme GasVLe2. Gas composition ranges, together with test conditions, are shown in Table 1 below:

Table 1 – RATIO0.2 0.4 0.6 0.75

Temperature Range (oK) 9.7 - 11.1 2.1 - 4.2 4.4 - 8.3 9.0 - 23.0Pressure Range (Bar) 30.9 - 31.4 27.5 - 29.8 27.8 - 32.0 32.4 - 37.2

GAS COMPOSITION RANGEComponent Mol %

Methane 94.137 - 95.568Ethane 3.041 - 4.194Propane 0.146 - 0.38n-Butane 0.011 - 0.044i-Butane 0.008 - 0.028n-Pentane 0.003 - 0.007i-Pentane 0.001 - 0.006Hexanes 0.011 - 0.03Carbon Dioxide 0.415 - 0.446Nitrogen 0.699 - 0.746Molecular Weight 16.748 - 17.008

7

5 RESULTS AND DISCUSSION The temperature drop between upstream and 6D downstream of the orifice plate is shown in Figures 4 & 5.The temperature drop has been calculated as the difference between the means of the four upstream and the four downstream thermometers. It can be seen from these two graphs that the consistency in the results for the two smaller – ratio plates, 0.2 and 0.4, was very good and the same results were obtained for the individual temperature sensors rather than plotting the average values. For the two larger – ratio plates, 0.6 and 0.75, the results were much more scattered. This was due to the way the tests were conducted which prevented the use of a 10 minute averaging period. During the commissioning of the system, i.e. when the flow rate was zero, differences of up to 0.08 ‘K between the upstream and downstream sets of thermometers were observed. This was attributed to scatter arising form the calibration of the thermometers. These offsets are shown in Table 2, second row, below:

These offsets were then corrected for in Figures 4 and 5 below, assuming that the temperature difference is zero. It can be seen that the temperature drop for each plate is proportional to the pressure loss and that the agreement between the experimental and the theoretical isenthalpic values is extremely good.

Table 2: OFFSETS OBSERVED AT ZERO FLOW ON DOWNSTREAM THERMOMETERS

(RELATIVE TO UPSTREAM THERMOMETERS)

– RATIOLOCATION

0.2 0.4 0.6 0.75

Downstream Flange Tap -0.4 0.08 -0.46 0.05

6 Diameters -0.07 0 0.03 -0.05Downstream

8

Figure 4

9

Figure 5

One of the reasons for carrying out the experiments at a low pressure of 28 bar was that at this pressure, assuming Mean Bacton Gas composition and the following values:

10

T = 278.15 ‘K (5 ‘C) P = 28.6 bar abs Cp = 0.0397 MJ/Kmol ‘K R = 8.31434 J/(mol ‘K)

3109326.0 −×=

∂∂

PTZ ‘K-1

Therefore,

528.0=

∂∂

HPT ‘K/bar

and with Z = 0.9298

422.2=

∂∂

SPT ‘K/bar

The large difference between the predictions of the two formulae at this pressure makes the interpretation of the results very straightforward. Stagnation Temperature Rise A secondary effect, which could cause errors in the measured temperatures, is the stagnation temperature rise which occurs when flowing gas is brought to rest in front of a probe. This is given by:

=∆

MC

VTP

STAG

2

2

With the exception of the downstream flange probe, it was expected that, where the gas velocity is very low, all of the probes would be affected to some extend. Table 3 below shows that the maximum stagnation temperature rise for the upstream thermometers was 0.38 ‘K with Cp = 47430 J/(kmol ‘K) and M = 17 (approx.). With the exception of the downstream flange tap probe, all probes would have been affected by virtually the same amount.

11

There will be a difference in upstream and downstream stagnation rises due to the change in density across the orifice plate. Since the density decreases by approximately 4% across the plate, the downstream stagnation temperature rise will be greater than the upstream one by approximately 8%, i.e. 0.03 ‘K for the 0.75 – plate. This is a very small rise in the stagnation temperature and therefore this effect can be neglected. Whilst not essential to the experiment, the thermometers installed in the spare flange taps have shown interesting results. With the exception of the 0.75 – plate tests, the upstream sensor effectively remained at the temperature of the other four upstream sensors. The downstream sensor showed an offset of up to 0.46 ‘K at zero flow (Table 2). It was suspected that this might have been due to the close proximity of the large thermal mass of the orifice-plate carrier. During the tests with the 0.75 – plate, the two flange-tap sensors showed erratic behaviour relative to the upstream and downstream sets. The difference between the two flange tap sensors, however, was consistent and varied linearly with the flow. The slopes of the temperature drop/differential pressure graphs for the downstream sensor varied with – ratio and ranged from 0.5 ‘K/bar for the 0.2 – plate to 0.8 ‘K/bar for the 0.6 – plate, Figures 6 & 7 shown below. This variation can only partly be attributed to stagnation temperature differences between the downstream flange tap and the downstream set of thermometers (the downstream flange tap probe will read cold due to this effect relative to all the other probes). The variation in slope may have resulted from the combination of low gas velocity in this re-circulation zone together with the thermal mass of the orifice-plate carrier. Further work is needed to confirm the gas temperature in this region.

Table 2: STAGNATION TEMPERAURE RISE

– V (m/s) ˚ TSTAG

0.2 2.8 0.0020.4 11.2 0.0220.6 23.8 0.102

0.75 46.3 0.384

12

Figure 6

13

Figure 7

14

6 CONCLUSIONS The temperature change across orifice plates from upstream to a plane 6D downstream of the plate were found to be approximately 0.54 ‘C/bar at pressures and temperatures in the ranges 27 � 32 bar and 2 � 12 ‘C. All four – ratio orifice plates tested (0.2, 0.4, 0.6 and 0.75) showed the same behaviour. The experimental results agreed extremely closely with the assumption that the expansion across an orifice plate is isenthalpic. 7 REFERENCES 1 ISO 5167-1 1991. Measurement of fluid flow in close conduits. Part 1. Pressure differential devices. 2 Laughton, A. GasVLe (Version 4.1). Advantica Technologies Ltd. 8 ACKNOWLEDGEMENTS The authors wish to acknowledge both the practical and theoretical studies carried out by Dr Roger Norman which form the basis of this paper. (Dr Roger Norman is no longer employed by Advantica Technologies Ltd).

1

NORTH SEA FLOW MEASUREMENT WORKSHOP 2001

Flare Gas Metering – Measurement Challenges at Hand

Atle A. Johannessen, Roxar Flow Measurement AS Bergen, Norway

SUMMARY The paper gives a brief overview of the changing requirements from operators regarding flare gas measurement systems over the past 20 years. Some of the changes in requirements are initiated by governmental legislation, in addition to more awareness amongst operators regarding economical and environmental issues. A general presentation is given of how the properties of the flare gas meters have been affected by new regulations and operators’ requirements. In sum, this has led to the measurement challenges at hand as we experience today. Finally, conclusion regarding flare gas metering as today is drawn and future measurement challenges outlined. 1 INTRODUCTION Going 20 years back, a common sign of an offshore production platform or process plant was the ever-burning flare, to be seen from far distances. The burning flare was in a way the mark of the oil production age. However, few, if any, regarded the burning flare as an unwanted proof of unprofitable production and gas emissions. This has now changed, and there is an entirely different awareness amongst operators and oil companies about the effect of gas emission as both an environmental and an economical issue. Also, governmental legislation and regulatory in more and more countries are pushing the operators to reduce the emission of gases to a minimum. This yields also for the flare gas emission, and oil production platforms are nowadays both designed and rebuilt for zero-flare operation. This is not to say that the flare systems are superfluous, as they are activated due to an unexpected shutdown or when it becomes necessary to rapidly dispose large amounts of gas. This change in operation of the flare systems has also influenced on the requirements of the flare gas measurement systems. From a continuous, more or less steady flowing amount of flare gas, today’s picture is more binary in nature, with the gas flow either to be approximately zero, or at the specified maximum rate. 2 FLARE GAS METERING With the change in the operation of the flare systems, an adaptation of the flare gas metering systems has been imperative. With flare systems being installed primarily for safety purposes, the flare gas metering systems must cope with dramatically changes in the flow

2

velocity, gas composition and temperature over a very short time scale. Hence, the measurement challenges may vary a lot over a short time period. Due to the nature of e.g. a process shutdown, when all of the process gas is flared, the flow velocity may exceed 100 m/s. As a result of this extremely high flow velocity, unwanted particles and components such as oil, water, salt and scale may be transported along the flare pipeline. Knowing this, it is quite evident that any instrumentation that intrudes into the flare pipeline might get influenced, or at the worst get damaged, during such a shutdown. Accordingly, limitations of what metering systems that can be put in operation have arisen. 2.1 Flare Gas Measurement Methods In the early days of flare gas measurement, more or less well-proven methods like “flare spectacles”, “guesstimation” and estimation were utilised. Later, more conventional metering systems were used for flare gas measurements, like insertion turbines, thermal mass meters and annubars. Other metering types, such as positive displacement meters, vortex meters, hot-wire anemometers, coriolis mass flow meters and sonic nozzles have too limited flow range to be considered for such metering applications. In addition, some of these metering types introduce an unwanted pressure drop in the pipe. From mid 1980s, a metering technology that has gained more and more acceptances for flow measurements are the ultrasonic time-of-flight meters. 2.2 Ultrasonic time-of-flight flow meters The ultrasonic time-of-flight gas flow meter is based on measurement of contra-propagating ultrasonic pulses, in which the transit time of the acoustic signal is measured along one or more diagonal paths in both the upstream and downstream directions. The flow of gas causes the time for the pulse travelling in the downstream direction to be shorter than for the upstream direction, and this time difference is a measure for the rate of the gas flow, see Fig. 2.1. By utilising equations (2.1) – (2.3), the gas volume flow rate can be calculated. In equation (2.1), the axial flow velocity along the acoustic cord is calculated, and (2.2) gives the average flow velocity along the pipe axis. The volume flow rate at reference conditions is calculated from equation (2.3), where the input of line pressure and temperature are required.

1

2

DL

l

t21

t12

Figure 2.1 Basic time-of-flight flow velocity measurement principle, with two ultrasonic transducers transmitting acoustic pulses to each other.

3

2112

1221

cos2 ttttL

(2.1)

vKv (2.2)

3600ZTP

ZTPAQ

0

00V

v (2.3)

As can be seen from these equations, the flow velocity measured along the ultrasonic cord does not depend on pressure, temperature or any other process parameter. This is a very important characteristic of an ultrasonic flow meter, as it implies that no adjustment due to changes in e.g. gas composition is required. Accordingly, an ultrasonic flow meter should present valid measurements independent of the process conditions. That is, within the flow, pressure and temperature range specified for the meter in question. 3 FLARE GAS MEASUREMENT CHALLENGES AT HAND 3.1 Governmental Legislation In Norway, in 1993, regulations relating to measurement of fuel and flare gas for calculation of CO2 tax in the petroleum activities were resolved [1]. The regulation was stipulated by the Norwegian Petroleum Directorate (NPD) by virtue of Section 5 of Act of 21 December 1990 relating to CO2 tax in the petroleum activities on the Norwegian continental shelf. The purpose of the regulation was to ensure that the calculation and reporting of CO2 tax was based on accurate measurements. Inevitably, oil companies operating on the Norwegian continental shelf had to relate to this regulation. However, also manufacturers of flare gas metering systems operating in this market were forced to confirm that their instrumentation did comply with these regulations. In the current revision of [1], only three measurement methods are acknowledged for flare gas metering on the Norwegian continental shelf; Ultrasonic measuring, Insertion turbines with density measurement/density calculation, Thermistor method. However, a new revision of [1], still as a discussion document, but expected to be approved this year, states that the accepted standard is according to NORSOK1 STANDARD I-104 [2]. In [2], Section 7.1.3, regarding flare gas measurement equipment, it says, “the measurement method should be an ultrasonic transit time flow meter (USM)”. This is not only a clear indication of what the future flare gas metering technology is expected to be, but it states that it is, today, the only proven technology to be utilised for these demanding applications.

1 NORSOK: the competitive standing of the Norwegian offshore sector. The NORSOK standards are developed by the Norwegian petroleum industry as part of the NORSOK initiative and supported by OLF (The Norwegian Oil Industry Association) and TBL (Federation of Norwegian Engineering Industries). NORSOK standards are administered and issued by NTS (Norwegian Technology Standards Institution).

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Further, the operating velocity range should be 0.2 – 100 m/s, still according to [2]. As today, the ultrasonic measurement technology is the only proven technology that has demonstrated ability to measure under these challenging conditions. As earlier stated, in order to fulfil the regularity requirements, the operators’ requirements regarding the flare gas metering systems have changed. Not only as a result of the mentioned governmental legislation, but also as a result of more focus on the environmental and economical aspects of the gas flaring. Further, other application areas for ultrasonic gas flow meters as mass balance and leak detection has added metering requirements beyond the direct flare gas metering requirements. Also, this has opened a new market within refineries and onshore process plants. 3.2 Process Related Challenges What is a very important feature of a flare gas meter at these conditions, with flow velocities up to and above 100 m/s, is that no meter parts intrude into the pipe cross-section. If this were the case, particles and droplets may deposit on the metering parts, affecting the meter performance. Deposits may affect the metering performance not only at the time of depositing, but also on a permanent basis if the deposits are not removed from the metering parts. At worst, the metering parts can be damaged, resulting in malfunction and erroneous readings. Generally, ultrasonic flare gas meters utilise transducers that are mounted flush with the inner pipe wall. The transducers of the Roxar Flow Measurement FGM 130 flare gas meter are mounted with the front centre point flush with the inner pipe wall for all pipe sizes from 6” to 72”, see Fig. 3.1 (A). However, some ultrasonic meters utilise other transducer mounting configurations, with the transducer intruding up to ¼ D into the pipe cross section. Depending on the application and the pipe size, this may be favourable, but the sensors will be more exposed to process debris. This is an evaluation that has to be done prior to installing the sensors; having the sensors intruding into the pipe, thus reducing the distance between the sensors. This will potentially increase the signal strength at the receiving transducer, enabling the flow meter to measure e.g. higher flow rates and under higher concentrations of CO2. However, at the same time the sensors are more exposed to debris.

A) B)

Figure 3.1 A standard transducer mounting is shown in A), whereas in B) an alternative method with sensor set back is shown.

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In Fig. 3.2, an ultrasonic transducer that has been exposed to high flare gas flow is presented. The sensor was mounted with the front centre point flush with the inner pipe wall, at an angle of 45 against the direction of flow. As can be noticed, the part that intruded into the pipe cross section is discoloured due to deposits. Remembering the upper velocity range for flare gas application, it is easy to imagine the effect of small particles that can be carried along with the gas flow. At worst, permanent damage to the sensor can be the outcome. In Fig. 3.1 (B), a configuration with the transducers set back is shown. This would potentially reduce the affect of debris in the flowing gas, but there are some considerations to be taken in evaluating this arrangement. First, the flow velocity equation 2.1 could not be utilised, as the set back arrangement introduces a part of the acoustic path where the flow velocity is assumed to be zero, ref. red coloured cavity area in Fig. 3.1 (B). Also, it is assumed that the velocity of sound is equal for the entire acoustic path between the transducer pair, that is, for the flowing fluid and the stationary fluid. Given this, it is readily to establish flow equations for this arrangement, [4]. Secondly, in order to cover a flow velocity range up to 100 m/s, the beam width of the transducers must be wide. If not, the carry-along effect of the signal due to high flow velocity would imply that the signal strength of the receiving signal would be too weak to be detected. But, a wide beam of a set back transducer could result in signal reflections in the conduit, distorting the transmitted signal. Accordingly, a set back arrangement may potentially reduce the flow velocity range of the meter.

Figure 3.2 An ultrasonic transducer after having been exposed to process in a flare line. Note the darker part of the transducer front (A) that has been in direct contact with the flowing gas. The lighter, upper, part of the transducer (B), has not been directly affected by the flowing gas and debris that has been carried along the flow. The transducer was positioned so that the front centre point was aligned flush with the inner pipe wall at a 45 angle against the direction of positive gas flow.

3.3 Operator Requirements Putting the specified upper flow velocity for flare gas meters in perspective; a hurricane is defined as wind speed of approximately 30-32 m/s. Thus, the required measurement range is more than three times the wind speed of a hurricane. Anyone having experienced a hurricane knows that both the carry along effect of voices in the wind and the general noise level is

A

B

6

dramatic. Bearing this in mind, it is obvious that both the ultrasonic signal propagating along the measurement cord and the signal processing system must be very robust in order to extract time-of-flight information under such conditions. At the same time, the meter must perform accurate measurements at the lowest flow velocities. Both the Norwegian CO2 tax regulation [1] and the NORSOK standard [2] state measurement uncertainty limits of 5 % of measured volume flow rate for flare gas meters. This applies for the entire measurement range. The measurement uncertainty of a meter for flare gas applications shall be verified by an uncertainty analysis within a 95 % confidence level. 3.4 Challenges Related to New Applications Flare Gas Recovery (FGR) systems are expected to become more and more significant in the process of decreasing emission of CO2 and greenhouse gases, [3]. The FGR system effectively closes the flare system, and any gas released to the flare header is recovered. FGR systems will generally be sized to recover background flaring with some space capacity. If the gas flow rate exceed the FGR capacity, a Fast Opening Valve (FOV) will ensure that the gas is released to the flare header. In order to recover the gas, it has to be reused in some way. If this is not possible, the gas, obviously, must be flared.

RecoveryCompressor

1

FOV

BurstingDisc

3

2

FlareTip

FlareHeader

Recycle to Process

Figure 3.3 Typical arrangement for Flare Gas Recovery (FGR) System, with 3 potential measurement points: (1) at Flare Header, (2) at Gas Recovery line, and (3) after the FOV where all the gas to the Flare Tip must pass.

In a FGR arrangement up to three measurement points can be identified; at the flare header Ref. Fig. 3.3 (1), at the gas recovery line (2), and after the FOV where all the gas to the flare tip must pass (3). During normal operation, with the FOV closed, a meter at (1) and (2) should read the same. With the FOV open, all the gas is flared, and a meter at (1) and (3) should read the same, except for a small contribution of Nitrogen at (3) if N2 purging is utilised. It is of course possible to install meters at (2) and (3) only, but with gas flow meters at all three locations, a redundant measurement system is achieved no matter the flare situation. Redundant measurements, or double transmitter solutions is in accordance with [2]. However, will the operators be willing to invest in three flow meters to have this process control, or redundant measurements? This is of course a question about having cost benefit of the investment. The challenge is inevitably to have a system covering all three measurement points, if possible, with a minimum of components at the lowest cost possible. That is, by e.g. using only one Flow Computer covering three measurement points. The

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advantage would of course be to have only one manufacturer for all three meters, which again would potentially reduce both investment and maintenance costs. 3.5 Self-checking and Diagnostics Capabilities New technology, more powerful signal- and microprocessors have increased the availability of measurement data from an ultrasonic gas meter. As more and more of the signal processing can be implemented in software, both raw data and processed data can be acquired and analysed. By having this information on a digital form, e.g. trough a serial communication line, no information is lost due to non-linearity, bit resolution, offset and gain errors found in digital-to-analog and analog-to-digital converters. By using e.g. RS-422 or RS-485 communication, data can be transmitted over long distances. Combined with the Modbus protocol, data can be transferred to and from a supervisory system with high data integrity. This information can be utilised for monitoring the meter performance and trending over longer time periods. An example of a trend plot that has been obtained by data from the Roxar Flow Measurement FGM 130 is given in Fig. 3.4. As can be noticed from Fig. 3.4, the emitted gas in a flare pipe can vary a lot. The total time span for the trend curve is approximately 30 minutes, with the flow velocity varying from approximately 0 m/s to almost 70 m/s. At one particular moment, the flow velocity varies over 50 m/s in less than 40 seconds (from approximately 0.5 m/s to approximately 52 m/s). Obviously, a highly dynamic system with fast response time is required for such applications. It should also be noted that the flare situation shown in Fig. 3.4 is not during a process shut-down, but merely pictures a general measurement situation that a flare gas meter is exposed to. With the measurement challenges a flare line clearly can represent, it is important to have a continuously verification of the measured parameters. Not only the calculated flow velocity, but e.g. also the measured transit times can be evaluated for system performance. By having all information about the meter’s status from the meter itself, the instrument fits into the scheme of condition based maintenance. However, as with all electronic equipment and devices, e.g. like PCs, the system it is not more intelligent than the manufacturer made it, and it is not capable of making any decisions without having evaluated a set of criteria to base the decision on. So also with an ultrasonic flare gas meter, incorporating state of the art electronics and signal processors with sophisticated signal analysis and software. A self-checking facility must be based some predetermined assumptions, and if one or more of these assumptions fail, the result can be false alarms or no alarms even if the situation qualifies for an alarm to be given. Alternatively, the evaluation of the data from the USM can be handed over to the supervisory system. But again, the evaluation at this level will also have to be based on a set of predetermined assumptions. And, is the manufacturer of the supervisory system better qualified for evaluation of data from an USM than the USM manufacturer himself? No matter which self-checking arrangement chosen, it is evident that as much as possible of the raw data from an USM should be available at the supervisory system. Then, an independent evaluation of the USM data could be carried out, possibly in parallel with the internal self-checking in the USM.

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HP Flare at Offshore Production Platform

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70

Time

Flo

w V

elo

city

[m

/s]

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Tim

e-o

f-F

ligh

t [µ

s]

Temperature

Flow Velocity

Upstream T-o-F

Downstream T-o-F

Pressure

Figure 3.4 Trend plot of measured transit times, temperature and flow velocity in a HP flare line at an offshore production platform. Notice the rapid changes in flow velocity (blue curve) and pressure (brown curve), and the increasing temperature (green curve) over the entire time span.

3.6 Automated Condition Based Maintenance Automated condition based maintenance implies that regular service intervals on e.g. a transmitter are omitted at the expense of service only on demand. This maintenance scheme requires direct information of the transmitter status, so that an evaluation of the transmitter can be carried out. If the transmitter status itself is not sufficient to give information of the transmitter condition, a duplicated transmitter solution might represent the required solution. In this setting, one transmitter is defined as master, and the other as secondary transmitter. The output from the master is used as transmitter values unless an alarm status is given. This of course would initiate a corrective action to be taken towards the master transmitter. Also, at this moment the output values from the master transmitter would be discarded, and the values from the secondary transmitter used. Also, if the output values from the two transmitters started to drift apart, without any error indications given from neither of the transmitters, a corrective action should be taken. The Roxar Flow Measurement FGM 130 has implemented an interface enabling up to twelve HART transmitters to be connected to one Flow Computer. For each of the maximum three measurement systems, up to two pressure and two temperature transmitters can be configured. The Flow Computer will continuously present both the measurement values and the communication status for each of the HART transmitters to the supervisory system through the Modbus serial communication link. By utilising duplicated transmitters, the supervisory system can compare the measurement values for each transmitter and give a warning if the measurement values are adrift or the transmitter status indicates an error.

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Incorporating the possibility for automated condition based maintenance, the Roxar Flow Measurement FGM 130 is aligned to the NORSOK standard [3], which states normative requirements in this respect. 4 CONCLUSION AND FUTURE TRENDS As of today, the proven technology for flare gas measurement is ultrasonic time-of-flight meters. The high turn-down ratio, the fast dynamic response, the non-intrusive design and the low maintenance costs represented by this technology substantiate this. The challenges ahead for flare gas measurement are more into verification and quality assurance of the flow measurements as to extending the velocity range of the meters. Self-checking capabilities and trend data analysis are features that will improve system integrity, enabling the operator to have a continuously updated status of the meter performance. However, at some installations it has been experienced flow velocities well above 100 m/s, and process estimates have indicated flow velocities close to 200 m/s. At these flow velocities no meter, as today, is capable to perform continuous valid flow measurements. Hence, a system for handling fall-outs of the ultrasonic measurements must be identified. Options of how to handle such situations are already implemented in existing meters, like “freezing” the output values to last valid measurement or setting the output to zero, but a more sophisticated approach for handling these situations needs to be addressed. Future trends point in the direction of more intelligent, “Smart” systems, that can communicate with a supervisory system through well-defined digital protocols. Further, remote diagnostics via e.g. Internet, satellite or mobile telephone communication are areas to be looked into. A future scenario might be that the end user, the operator, could sit at his desk and remotely monitor a number of installations for daily reporting and performance verification. Also, this open for the possibility that the manufacturer himself, given the permission by the operator, could sit at his desk and remotely monitor a single installation for status check, possibly saving a costly service trip for doing the same job. This feature could be possible with “intelligent” systems provided with self-diagnostics capabilities, given by the powerful hardware and sophisticated software available today.

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5 REFERENCES 1 NORWEGIAN PETROLEUM DIRECTORATE. Regulations to measurement of

fuel and flare gas for calculation of CO2 tax in the petroleum activities, August 1993. ISBN 82-7257-395-4.

2 NORSOK STANDARD. Fiscal Measurement Systems For Hydrocarbon Gas. I-

104. Rev. 2, June 1998. Norwegian Technology Standards Institution. 3 Miles, J.D., “A Flare Gas Recovery System”. Argo Environmental Engineering

Limited, 2001. Presented at Flare Gas Metering Seminar – Preparing For The Future, Aberdeen, June 4th 2001.

4 ISO/TC 30/WG 20 N 88 E, “Measurement of fluid flow in closed conduits –

Methods using transit times ultrasonic flow meters.” NOTATION A Pipe cross-sectional area m2

D Nominal pipe diameter m

L Distance between transducers m

P Pressure BarA

P0 Pressure at reference conditions BarA (1.01325)

QV Volumetric flow rate at reference conditions Sm3/h

T Absolute temperature K

T0 Absolute temperature at reference conditions K (288.15)

Z Compressibility factor

Z0 Compressibility factor at reference conditions

t12 Transit time from transducer 1 to 2 (downstream) s

t21 Transit time from transducer 2 to 1 (upstream) s

Inclination angle deg

Pharo, Sakariassen & Apeland, “Experience with Installation of Sampling system in special Application” North Sea Flow Measurement Workshop, October 22-25, 2001, Kristiansand, Norway

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Paper 16:

Experience with Installation of Sampling System in special Application

North Sea Flow Measurement Workshop October 22-25, 2001 Kristiansand, Norway

Authors: Gunnar Pharo FMC Kongsberg Metering AS Reidar Sakariassen Metropartner A/S Odd Inge Apeland Statoil ASA

Reprints are prohibited unless permission from the authors and the organizers


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1. INTRODUCTION At the Kårstø Gas Terminal, LPG and NGL products are loaded to ships via three different jetties. These products are propane, ISO-Butane, normal-Butane and Naphtha or Condensate C5+. Propane is loaded via jetty no. 1 and 2, ISO-Butane can be loaded via all jetties, normal-Butane can be loaded via jetty no.1 and 2 and Naphtha can be loaded via all jetties. There are two metering stations for propane and both can meter to jetty 1 and jetty 2. One of the stations has been in operation since start up of the Kårstø Gas Terminal in 1985. The second one was put in operation in 2000. They are both based on turbine meters and equipped with a piston prover and a compact prover respectively. In addition there is one metering station for ISO-butane, one for normal-butane, one for condensate and two metering stations for Naphtha. Not only is it required to meter the quantity in terms of mass, it is also required to check the quality of the products. Therefore all the metering stations are equipped with product samplers. Since a number of the quality checks have to be done at the laboratory, it has been decided not to install on-line analysers. It is therefore of outmost importance that the sampling systems are reliable and provide samples representing the average of the loads. This paper deals with problems experienced by sampling liquid propane for laboratory use, and how these problems were solved. 2 BACKGROUND Both the regulations from Norwegian Petroleum Directorate (NPD) as well as Transport and Sales Agreement require flow proportional sampling. If this is not possible for one reason or another, the fallback procedure is to take spot samples after 25 %, 50 % and 75 % during the ship loading. It is also a requirement that a part of the sample should be stored in case disputes between parties arise afterwards. The propane metering station set in operation in 1985 was equipped with a flow proportional sampler. However, despite many efforts from the vendor and the operating personnel, this system never functioned properly. So spot sampling has been the regular procedure ever since. In connection with the installation of a new propane metering station in 1999, it was decided to look for solutions for a successful sampling system.


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The phase envelope of propane is special, relative to the other products. Examples are shown in fig. 1.

a. Phase envelope for Propane Product b. Phase envelop for n-Butane Fig. 1 a. Phase envelope for Propane product: 0.8 mol % C2, 99 mol % C3, 0.2 mol % iC4 b. Phase envelope for n-Butane product: 0.8 mol % C3, 98 mol % nC4, 1 mol % iC4, 0.2 mol % C5. It appears from the phase envelopes from propane that at atmospheric pressure (100 kPa), the temperature has to be lower than ~231 K (-42°C) to be in liquid phase. On the other hand, at a normal ambient temperature of 17°C (290 K), the pressure has to be higher than 800 kPa (8 bar) to be in liquid phase. For n-Butane the temperature has to be lower that ~273 K (0°C) at atmospheric pressure to be in liquid phase, and at a normal ambient temperature of 17°C (290 K), the pressure has to be higher than 200 kPa (2 bar) to be in liquid phase. The line pressure of propane (at the metering stations) is approximately 8 bar and the operational temperature is ~231 K (-42°C). The problem experienced with the “old” sampling system arises from these conditions: Samples were taken at line pressure, but as soon as the temperature started to increase toward ambient, the liquid propane went to gas phase and apparently no liquid were sampled at all. So the “trick” with the new sampler system was to increase the pressure sufficiently to keep it at sufficient pressure in all parts of the sampling system to remain in the liquid phase. So, a rugged system was designed to sample the propane at a higher pressure than the line pressure, so high that it should not be a problem to maintain it in liquid phase all the way to the laboratory. Not only should the system be flow proportional, but the samples should also be maintained homogeneous since the amount of product used in the analysers is only a small part of the total sample. To achieve this, a liquid grab sampler together with a sampling system for transport and storing the samples of the load is necessary.


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3. FUNCTIONAL DESCRIPTION OF THE PROPANE SAMPLER A Sample system for liquid propane sampling is designed to extract a sample of the propane from a pipeline and store it in a sample container under fixed conditions. The sampler system consists of a grab sampler, transport tubing and a sample container with mixer. The sampling frequency is proportional to the flow rate. The sample container has a volume of 10 liters. With about 80 % of the container volume to fill and a cup volume at 4 ml, it will take 2000 samples to achieve 8 litters. If a load takes about 12 hours, the sampler takes a sample every 21 second. . The sample container is a piston cylinder with a pressure from an external gas bank to keep the piston forced at a pressure of 30 barg to keep the sample in liquid form. Included is also a mixer system. The mixer ensures homogeneous mix of the sample in the container.

Fig. 2 A simple schematic drawing of the sampling system


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Fig. 3 Grab sampler type Welker model LSSM-1F

The grab sampler used is the type Welker model LSSM-1F. A drawing is shown in figure 3. The grab sampler itself is actually in the pipe. (See drawing of the grab) This grab captures a fixed volume of propane, and an automatic pneumatic driven unit operates the grab in and out of the pipeline under full process conditions, and allows this volume of the product to be forced into the sampler system at 43 barg to the container. This provides the user to get a representative and accurate sample of his product. Fig. 4 Detail of the grab sampler


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The sampler is flow proportional. During the load, 2.000 samples will be taken. This ensures a good average measurement of the load.

Fig 5 Installation of the grab sampler at Kårstø


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The sample container and the mixing system are located inside a cabinet. Between the grab sampler and the sample container, is 10m tubing with inside diameter of 3 mm.

Fig. 6 Sampler cabinet The sampler cabinet consists of the sample container with piston and level monitoring, a mixing system with pump, and valves and gauges for operating the system when lab. samples are taken. It contains also equipment for operating the grab sampler, and for control of the backpressure on the piston in the sample container. To get sample from the grab sampler to the container, a higher pressure must be maintained on the sample than the backpressure in the system. Sample pressure can be read at the respective gauges. See fig.7. Grab sample pressure is read at the left gauge. This increases by the operation of the grab sampler until it reaches the set pressure of the relief valve, which is set to 43 bar in this case. At the picture, the sampler is not in operation and therefor the pressure is equal to line pressure. The gauge in the middle shows the backpressure. This is always set to 30 bar.


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Fig.7 gauge panel The mixing system consists of a pump, a static mixer and a jet mixer. The propane is forced in a closed loop by the pump through the static mixer, through the piston and then through the sample in the container. The cabinet is also constructed with facilities to purge the excessive propane from the container back to the pipeline.


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4. PROCEDURES Procedures have been established to ensure that the propane is kept at required homogeneous liquid phase conditions. Once the loading to ship starts, the sampler system starts to grab samples. The filling level (i.e. the position of the piston) is monitored continuously during the loading. Before lab-samples are taken to be analyzed in the laboratory, the filling level is checked and the mixing system is started. Normally, lab-samples from the 10-l sample containers are extracted when the ship is 90 % filled up. Three samples each of 300 ml are filled up after a careful purging of the tubing between the large sample container and the small sampler cylinder. Approximately 1.5 – 2 litters are taken out in this action. The remaining propane in the 10-litre cylinder is then returned into the line. This is possible because the pressure in the container is far above the line pressure. When sampling starts for a new load, the pressure in the tubing is kept at this high pressure so the sample provided from the 43 bar part over to the sample tubing will continue in liquid phase. No amount of propane from the new load is needed to pressurize the system for reaching its equilibrium pressure. The continuous piston position monitoring, quickly reveals any leakage or malfunction. Also, the final level will reveal problems with the grab sampler itself.


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5. EXPERIENCES The new installation was not put into operation without some start-up problems. The experience showed that the cup size is one of the keys to success. The first cup installed had a volume of 1ml. This volume was not enough to reach the necessary level in the sample container, and this forced the grab sampler to exceed its maximum frequency. The result was incomplete movements of the sampler. A cup size of 4 ml was installed last July, and no problem with the operation of the system has occurred later. The filling level when lab samples are taken for the laboratory at 90 % finished loading, should ideally be 7.2 litres. The recorded level has steadily been 6 litres. This means that the effective grab size is 3.3 ml instead of theoretically 4 ml. This is regarded as fully acceptable. The only complaint so far has been that the operation of the system by the laboratory personnel is inconvenient due to bad positioning of the cabinet.

Fig. 8 shows how the filling level develops during the loading.

Filing level of Propane Sampler at Kårstø

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6. CONCLUTION The former sample system for propane at Kårstø did not operate properly. Therefor a routine with manually sampling three times during a load was established. This was not according to the agreement between the partners. When a new export line for propane was built, a sampling system from FMC Kongsberg Metering was selected. The goal was to establish a flow proportional sampling system according to the regulations from The Norwegian Petroleum Directorate (NPD) and The Transport and Sales Agreement. The challenge was to keep the sample in liquid phase, and present a reliable result representing the average of the load. This was achieved with the application of the pressure above the piston in the sample container and correct size of the sample cup in the grab sampler.

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WHAT IS THE UNCERTAINTY OF YOUR QUALITY MEASUREMENT SYSTEM?

Mark A. Jiskoot

Summary The various standards applicable to sampling, density and on-line water content measurement have been developed concurrently with, and in some cases as a result of, the development of the North Sea. While sampling systems have always been a feature of the metering process, many metering systems installed on older platforms have been modified to incorporate density or water-in-oil monitors (OWD or On-line Water in petroleum Devices) or both. Integrated systems are now also titled QMS or “Quality Measurement Systems”. The designs used often fall outside the accuracy they are supposed to attain and shortcomings are generally overlooked because in some cases it is hard to confirm compliance. This paper will outline some of the key requirements and frequently discovered deficiencies.

Introduction North Sea fields are maturing and although there are restrictions in the quality (i.e. water content) of oil entering pipeline systems, production is getting “wetter”. Where production has been relatively dry, both sampling and density errors have been relatively easy to overlook because the errors in mis-measuring fractional percentages of water still allow on-line densitometers to remain within the uncertainties allowed by the standards. As production gets wetter the already prevalent errors in sampling and density measurement will become more obvious. There is also a move to produce “wetter” fields at lower production rates and with less separation. In these conditions the produced fluids tend to be at elevated vapour phase conditions (higher RVP’s). These conditions will also render higher errors in both density and water content measurement. Many sampling systems are now integrated with densitometers and OWD systems to form “quality” loops. Loops are preferred because of the premium on space (difficulties in locating in-line systems), the ability to simply isolate them for maintenance and their improved accuracy. To ensure that they are correctly designed it is important to understand the effects of water content and density to the current audit process.

Measurement Standards and references • Sampling (IP 6.2 July 1987) • Density (IP 7.2 September 1997) • OWD (API 10.11 draft standard November 2000) • Additional references

o API 8.2 1995 o ISO 3171 1988 o Roxar/MFI handbook version 1.5 o Phase Dynamics literature o Solartron Advanced Liquid Density Tranducers (technical manual issue B)

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Common ground There are several issues that are equally crucial to good sampling, on line water content and density measurement and as flowrates fall and water contents increase these become more significant. The whole purpose of metrology is to provide a uniform measurement method and in general the measurement standard is to record the useable mass of oil. To calculate mass a correct density and water content are required.

q The only density that can actually ever be measured on-line must be a “wet oil density” because the process is intrinsically “wet”.

q The only way to measure the correct wet oil density and the correct water content from

which dry oil density could be derived is to ensure accurate sampling and density measurement.

Therefore the only way to ensure the process ties together is to apply sampling knowledge to density measurement and to ensure that the fluids presented to the sampler and the densitometer are of the same physical composition. i.e. REPRESENTATIVE. This can best be achieved by locating the sampler and the densitometer in the same process stream or loop. Traditional sampling and metering systems were installed with the sampler upstream of the meter bank. Densitometers have later been added as loops taken off downstream of the meter bank. There is clearly scope for the water content at each point to be different.

It should be remembered that the IP density standard requires that all considerations of the IP 6.2, ISO 3171 be taken into account (for oil service). This means that the sampling process and the measurement of density must be considered simultaneously. The three steps to ensure compliance are:

1. Pipeline Mixing 2. Representative offtake and maintaining representivity in the offtake system through the

measurement devices 3. Sample handling and analysis (for the sampling function only)

SAMPLING SYSTEM

METERING SYSTEM

DENSITY SYSTEM

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Before consideration can be given to the overall uncertainty of mass measurement derived from the quality system, the main pipeline must be adequately mixed to prevent an offtake loop under-measuring the water content or the density. The uncertainty in this area is always negative (i.e. results in a loss of product).

1. Pipeline mixing

0 1 2 3 4 5 6

Thousands

Flowrate (M3/Hr)

0

0.2

0.4

0.6

0.8

1

C1/

C2

Pro

file

Rat

io

0

1

2

3

4

5

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7

8

9

10

Dro

plet

Sze

(m

m)

Straight Pipe

Droplet Size

For adequate Sampling C1/C2 >0.9Pipesize 19.25 ins, Density 811 Kg/m3, Viscosity 2.0 cSt.

Crude OilProfile Ratio vs Flowrate C1/C2 from ISO 3171 Annex A

For all measurements, even those employing a full-bore sensor (i.e. a spool) a well-mixed pipeline is a pre-requisite. The majority of densitometers, OWD’s and samplers are located in loops extracted from the main pipeline. The quality of the dispersion required is directly related to the measurement methodology, for example ISO 3171 requires that the diameter of the inlet to a “sample” (read quality) loop be 10 times the size of the expected water droplets. The water droplet size has a direct relationship to the rate of energy dissipation and the rate of gravitational fallout (segregation) also relates to the droplet size. Therefore there is clearly a relationship between pipeline mixing and the (diameter) size of any “quality” loop. Larger offtake sizes produce lower uncertainties in measurement systems for any given quality of pipeline mixing. This is also borne out in the IP 6.2 standard where the definition of Isokinetic sampling is widely extended as the size of the offtake loop is increased. It is imperative to minimising uncertainty that the pipeline mixing and the sample loop design are considered simultaneously. To put some numbers to this; North Sea pipelines are unlikely to be adequately mixed (without the use of static or power (jet) mixers) at velocities less than about 4 m/s and for condensates significantly higher velocities than these are required. There are significant

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problems with older production systems, in one recent example the daily flowrate related to a pipeline velocity of under 0.08 m/s! With inadequate pipeline mixing it becomes irrelevant to consider the uncertainties within a quality loop because the loop itself can at no point be representative.

2. Representative Offtake Loop (for a sampler or densitometer) While not all systems use loops, it is apparent that a correctly designed quality loop will consistently outperform an in-line device. The collated results of over 100 water injection tests (including “failures”) of sampling systems in a variety of configurations yielded the following results:

Type of System Average Proving Error Number of Tests In line probe (9 x 25mm inlet) -0.118 % 80 Fast Loop (33mm or bigger inlet) -0.035% 23

Once a representative stream has been created it is imperative that the quality loop maintains representivity; this requirement can produce two problems. The first to ensure the flowrate in the loop maintains the stream in an adequately “dispersed” state and the second to ensure that the stream properties are not changed due for example to pressure or temperature effects which can include RVP issues and cavitation.

3. Physical sampling, handling, mixing and laboratory analysis These issues apply of course only to “physical sampling” methodology and the requirements for collection, retention, sub-sampling and analysis. All of the steps must be given equal attention because uncertainty generated by any of the steps will yield uncertainty on the overall result.

Uncertainties There are several sources of uncertainty in the mass calculation outside of those created by the metering (volumetric) element itself. These relate to the correct measurement of density and the correct measurement of the water content in the batch. Poor pipeline mixing results in both poor sample water content measurement and poor measurement of density. In addition poor measurement of density through changes in the physical characteristics of the fluid compared to those metered volumetrically will cause further uncertainty.

Uncertainty created by poor pipeline mixing. The uncertainty in the overall mass will be reduced if the sampling and density measurements are taken from identical process stream. If the recorded density relates correctly to the recorded water content a correct balance can be achieved, however if the recorded density is lower, for example because the density loop has a lower water content than that produced by the sampling system then the total mass of oil will be understated.

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Uncertainty caused by poor density measurement Density measurement errors can be caused by a variety of sources; in the example above the density measurement system was separate from the sampling system and therefore subject to potential error. It is also possible to reduce the likelihood of a correct density reading by poor conditioning within the quality loop. For a metering system to totalise mass, the IP density standard requires that the density measurement be made at conditions close to the metering process. The uncertainty in density measurement is not only affected by the pipeline condition but also by physical changes that can occur in the quality loop which are simply overlooked. If the correct fluid enters the quality loop, the physical properties can be altered by changes in temperature and pressure. Section 7.3.4 states that for an overall density uncertainty of 0.1 % errors arising from pressure and temperature should not be greater than 0.03%. For crude oil with a nominal density of 850 Kg/M3 Parameter Units For 0.03 % uncertainty Temperature Sensitivity -0.7 Kg M3 per K 0.4 K Pressure Sensitivity 0.06 Kg/M3 per bar 4.2 bar

These figures can be adjusted if the density is correctly adjusted to process conditions (i.e. at the flowmeter) from local pressure and temperature measurements. These uncertainties can be influenced by further changes in the physical properties for which no compensation can be made. These would include a significant change in temperature or alternatively pressure or suction losses that may cause gassing of the oil.

The affects of density errors on OWD systems As there is an increasing tendency to use OWD systems, it is important to note that any water in oil monitor using dielectric constant upon which to base the water content will need compensation for the “dry oil” dielectric – this includes microwave-based techniques.

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Effect of Density (800-900 Kg/m3)

1.80

1.90

2.00

2.10

2.20

2.30

2.40

2.50

2.60

0 1 2 3 4 5 6 7 8 9

Estimated Percent Water

Die

lect

ric (

"dry

" at

zer

o)

Several vendors suggest that the dry oil dielectric constant can be ascertained by measuring the density of the process stream, but this a wet oil stream so the meter is compensated using the wrong density! While the errors in using an erroneous density for compensation may not be huge, they exist and have precluded the use of this technology for import terminals subject to a wide range of oil types.

Are there new issues? So why are these issues of more significance now than in the past? This is because the uncertainty in the overall measurement increases disproportionately to the changing water content and design failures become more evident as production rates fall.

Density loops in service It comes as a great surprise to see many densitometer loops installed with their takeoff from the side of the pipeline (with no due consideration of the representivity of the source), densitometers installed on the suction sides of pumped loops or in loops that have insufficient velocity to maintain process equilibrium.

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The manufacturers own suggestions pay no care in suggesting representivity:

Given that quality loops are convoluted designs, engineered into little space, often with long and undersized suction lines significant pressure and temperature offsets between the metering point and the densitometer would not be unusual. Due to restricted piping and the poor consideration of temperature losses and with low NPSH pumping conditions, local hotspots within pumps, a temperature offset of 0.2 K between the metering location and the densitometer is likely to be considered an extremely good result.

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So there are key components often overlooked in density measurement quality loop design:

1. The representivity of the quality loop in regard to accurate water content is frequently wrong.

2. The content of the quality loop does not maintain the process conditions adequately to represent the process at the measurement point (i.e. pressures and temperatures are offset).

Densitometer loop design The original intention in designing densitometer loops was to use a pressurised pyknometer as the proving method with two densitometers. One installed as the recording instrument and the second in parallel as a standby. Industry practice changed so that the preferred method was to use the substitution method i.e. the densitometer signals (one being the reference and the other comparator) are continuously compared and at a regular interval a unit is replaced with a “transfer standard” calibrated instrument. The problem with the change of operating methodology is that for this to be operated correctly the densitometers in question should be in series. No account has generally been taken in system design for the loop to be split and therefore inadequate flow may exist to maintain good temperature stability or to assure that the parallel streams are subject to the same water content.

These are the numbers, but in reality what is likely to happen? As fields are getting older and if no attention is paid to correct integration of quality measurement an uncertainty of 0.15% is probably unattainable. Practicality and theory, as always have a gulf to bridge, this gulf is to ensure that the density/sampling water in oil monitor loops are consistently referenced. If the density measurement is separated from the sampling function, then there must be some doubt as to whether the figures will tie up.

New production In an effort to reduce production costs there is now a tendency to produce over existing facilities with new fields, the characteristics of which may be significantly different from those envisaged for the original process train or to create new process systems with minimal separation (often single stage). The problem with single stage separation is that the measurement system is now being asked to cope with fluids at higher pressures but also with RVP, which is extremely close to the process condition. This yields little available operating

FLOW BIAS?

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envelope for creating adequate mixing or for pumping a loop. Extreme care is required to design quality loops and the necessary process mixing without destroying the ability to accurately measure the qualities of the process.

Conclusion There are significant uncertainties in the overall net oil results for offshore measurement systems caused by disparities in the measurement of water content and density, these result from poorly mixed pipelines, poor density measurement loops and poor application of sampling technology. Until due care and attention is paid to improving and integrating the quality process piecemeal improvement is unlikely to yield much improvement in uncertainty.

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References

IP 7.2 highlights Avoid hydraulic shock 6.7.2 …….density transducer should be installed at a position where a representative sample of the main flow is presented to it. To enable accurate conversion to reference conditions, line temperature and pressure should be measured at a point which most closely represents the conditions at the density sensor. 6.11.1 a) …..the uncertainty of density measurement should be better than 0.15% of the true density at the point of volume measurement……….. 6.11.2.2 b) all density meters in the system should be kept in continuous operation. 6.12.1 …….it is required to measure the density of oil that contains water in order to derive the density of the dry oil or to calculate the percentage water. ………special care is required to ensure that the fluid at the measurement transducer is truly representative of the total quantity of fluid of interest. 7.3 b) temperature or pressure differences between the liquid in the flow element and the liquid at the density transducer should be minimal and within specified limits (see table 1) 7.3.4 …for an overall density measurement uncertainty of 0.1% of reading, the errors arising from this source should not be greater than 0.03% of reading. For crude oil Temperature effect is –0.7 kg/m3 /K that INDIVIDUALLY relates to a maximum temperature difference of 0.4 K and a pressure effect 0.06 Kg/m3 /bar which would INDIVIDUALLY allow a maximum pressure difference of 4.2 bar. 8.4/8.5 Transfer Standard procedure and Substitution method.

Densitometer Installation Guidelines The liquid must always be at a pressure substantially above its vapour pressure. Cavitation, caused by pumping, should not generate bubbles from dissolved gases. If a pump is used it should “push” rather than “pull” the product through the transducer. A fast flowrate e.g. 3000 litres/hour, will help to achieve good temperature equilibrium and have a self-cleaning action.

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PRESENTATION OF THE HANDBOOK OF WATER FRACTION METERING

Eivind O. Dahl, Christian Michelsen Research AS, Bergen, Norway Ronny A. Albrechtsen, Christian Michelsen Research AS, Bergen, Norway1 Erik Malde, PPCoN, Stavanger, Norway

1. ABSTRACT

A new NFOGM publication, Handbook of Water Fraction Metering [1], for continuous measurement of water fraction in produced and transported hydrocarbon liquid is presented. The increased availability of Water Fraction Meters (WFM) for continuous measurement represents a new challenge. It is of utmost importance to acquire reliable data for fiscal measurements. The uncertainty of the water fraction measurement is a fundamental aspect of the total crude oil measurement and it is essential in assessing the quality aspects of the production. It is also of great importance to be able to continuously monitor and analyse the water content of the crude oil during the optimisation process for both operation and transportation. Until recently, a representative sample of crude oil and water has been used for calibration and adjustment of WFMs. Utilising sampling and analysis techniques as a reference has restricted the performance of the new technology, i.e. the applied technology in WFMs has a potential for less uncertainty than the reference techniques. The Handbook sets out recommendations for continuous determination of water fraction in hydrocarbon liquids. It describes the recommended installation, calibration and adjustment methods for both fiscal and allocation water fraction measurements.

2. BACKGROUND

The Norwegian Society for Oil and Gas Measurement (NFOGM) brings further the tradition of providing the members of the society and others with special interest publications. The first publication, Handbook of multiphase metering, were released in 1995 [2], which was later followed by the Handbook of uncertainty calculations - Fiscal metering stations [3], published in 1999. This was subject to a minor revision in 2000, and a new revision in 2002 is currently being discussed. This paper, however, presents the latest addition to the series, the Handbook of water fraction metering [1] which is now downloadable from the NFOGM web-pages. A workgroup for writing the handbook was established in 1999 with representatives from oil companies (PPCoN, BP Amoco, Norsk Hydro, Statoil), vendors (Roxar Flow Measurement – formerly Fluenta and Roxar, both participating as separate companies during this project) and Christian Michelsen Research AS (CMR). In this project, CMR has provided the workgroup with background and detail information regarding the uncertainty of the two in-line water fraction meters currently available, which also represent different technologies, and co-ordinated the work with the handbook.

1 Statoil Bygnes, Norway from September 1st, 2001.

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For the sake of completeness, we should also mention that a new handbook, Handboook of Uncertainty Calculations – Ultrasonic fiscal gas metering stations, is currently being developed by NFOGM and CMR. The work with this new handbook is carried out by CMR and was initiated in 2001. The intention is to release the first revision of this new handbook in 2002.

3. INTRODUCTION

The development of Water Fraction Meters (WFM)2 during the last two decades has now reached a level where the low uncertainty and high reliability of the meters are considered to be in the same order of, or even better than, the method involving sampling and analysis (e.g. Karl Fisher titration), which until recently has been used to calibrate the WFMs. In fact, the uncertainty of the calibration method itself, especially the sampling method, may introduce a higher uncertainty to the meters than what is achieved by the factory calibration. Thus, today’s reference techniques for calibration and adjustment are expected to limit the meter performance, and there is a need for improved and independent calibration and adjustment procedures for fiscal and allocation water fraction measurements. Water fraction measurements with as low uncertainty as possible is motivated not only from a fiscal point of view, but also with respect to process optimisation. Generally, the transport of water costs the same as the transport of oil, causing additional increased costs in terms of increased needs for water treatment facilities and water disposal at the receiving end. A project was therefore initiated with the following objectives:

a) Uncertainty evaluation of the available in-line WFMs: Fluenta WIOM-350 and MFI WaterCut Meter.

b) Establish a workgroup for developing a handbook for Water Fraction Meters. Detailed analytical and technical descriptions were made by CMR for the WFMs: Fluenta WIOM-350 [4] and MFI WaterCut Meter [5]. These two meters represent the state of the art of in-line meters, and have been subject to a theoretical evaluation of the combined uncertainty in accordance with the “Guide to the expression of uncertainty in measurement” [6]. The two reports have been reviewed by the workgroup, and the recommendations given in the Handbook of Water Fraction Metering are based on these reports. The Handbook sets out recommendations for continuous determination of water fraction in hydrocarbon liquids, covering e.g. installation, calibration and adjustment methods, simple means for qualitatively determining flow homogeneity and a recommended WFM performance specification. The procedures and installations given in the Handbook have been prepared for both fiscal and allocation water fraction measurements. On behalf of the NFOGM the workgroup issued a draft of the Handbook in March 2001 for comments and reviewing, and revision 1 was issued June 2001 [1]. The main findings and recommendations in the Handbook are described and discussed in this paper.

2 Water Fraction Meter: A device for measuring the phase area fractions of oil and water of a two-

phase oil/water flow through a cross-section of a conduit.

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4. TWO-PHASE OIL/WATER FLOW

The type of flow considered in the Handbook is oil continuous two-phase flow with water content in the range 0 - 10 %, generally less than 5%. The physical measurement principle of most of the known Water Fraction Meters require that the water concentration is the same over the entire pipe cross-section, i.e. homogeneous oil/water flow, with no velocity slip between the phases. This requires that the water phase be finely dispersed as small droplets in the continuous oil phase. In practice, however, a concentration gradient may exist, especially in horizontal lines, and ±5 % deviation from the mean can be considered as a homogeneous mixture [7]. As the flow homogeneity is important for the performance of the in-line WFMs, the Handbook gives a description of two prediction methods that can be used to determine whether a water-in-oil mixture is homogeneous or not in horizontal and vertical flow. One of the methods is based on a procedure given by the ISO 3171 standard [7], and it is applicable for horizontal lines. The other method is based on flow pattern models developed by Flores et al. [8]-[10] for vertical and inclined pipes, though it is claimed that the model is independent of inclination angle. Generally, the two methods predict that homogenisation of water in oil is promoted by high velocity, high oil viscosity, high oil density, low interfacial tension and small pipe diameter. The turbulence, which exists naturally in a pipeline, can be sufficient to provide adequate mixing of water in the oil phase. The minimum natural turbulent energy for adequate mixing depends on the fluid flow rates, pipe diameter, water concentration and fluid properties (density, viscosity and interfacial tension).

4.1 Horizontal pipes

This method is based on the ISO 3171 standard [7] for predicting the degree of homogenisation in horizontal water-in-oil dispersions. Adequate oil and water mixing is, according to ISO 3171, characterised by uniform dispersion. I.e., the water concentration at the top, C1, and the bottom, C2, in a horizontal pipe is approximately equal. A concentration profile in a horizontal pipe can be estimated by forming a simple equation that balances the downward flux of water droplets due to gravity with the upward flux due to turbulent diffusion. By applying models for the settling velocity of water droplets and the turbulence characteristics of the flow, which is given in the ISO 3171 standard3, it is possible to arrive at a single analytical expression for the minimum liquid velocity, cV , that will maintain an oil/water mixture with a given dispersion degree G:

3 The method described in the ISO 3171 standard for estimating homogeneous flow conditions is a

step procedure involving numerous calculations, which may be quite elaborate. Eq. (1) above has been derived to simplify the procedure for calculating the homogeneous flow conditions.

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( )

% 15-10

431.0

366.0

283.0

325.039.0325.0

1

<

⋅−

⋅⋅⋅=

β

µρρρσ

oo

owowc

DGKV (1)

where

( )21ln

1

CCG −=

21 CC is the ratio between the water concentration at the

top and the bottom of the pipe. (G = 10 ⇒ 21 CC = 0.9).

cV Critical (minimum) velocity for maintaining a dispersion degree G K1 Constant depending on unit system (K1= 2.02 for SI units)

owσ Interfacial (surface) tension between oil and water

oρ , wρ Oil and water density, respectively

D Inner pipe diameter

oµ Oil viscosity

β Volumetric water fraction in per cent

A 21 CC ratio of 0.9 to 1.0 indicates very good dispersion, which respectively correspond to G = 10 and G → ∞. A ratio of 0.4 or smaller indicates poor dispersion with a high potential for water stratification. By using Eq. (1) it is possible to calculate the critical (minimum) liquid velocity corresponding to a defined degree of dispersion when the fluid properties and the pipe diameter are known quantities. The value G = 10 gives a concentration ratio 0.9, and is recommended by ISO 3171 [7]. This corresponds to ±5 % deviation from the mean concentration and it is in practise considered as a homogeneous mixture. The handbook of water fraction metering contains diagrams where the critical velocity has been calculated and plotted for different values of the model parameters. Figure 1 shows one example where the variation in the critical velocity has been calculated and plotted as a function of the oil density for given values of the dispersion degree, pipe diameter, oil viscosity, water density and interfacial tension. The general trend is that the minimum liquid velocity required to maintain a dispersion corresponding to a concentration ratio of 0.9 (G = 10) decreases with the oil density (see Figure 1) and the oil viscosity, and increases with the interfacial tension and the inner pipe diameter.

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0

1

2

3

4

5

6

500 550 600 650 700 750 800 850 900 950 1000

Oil density [kg/m3]

Cri

tic

al

liq

uid

ve

loc

ity

[m

/s]

µo = 5 cP

σow = 25 mN/m

ρw = 1025 kg/m3

ID = 4"G = 10

Figure 1 Critical liquid velocity as a function of the oil density in order to maintain a concentration ratio of

0.9 (G = 10) between the bottom and the top of a horizontal pipe. The flow will be homogeneous as long as the actual liquid velocity is greater than the critical velocity given by the diagram. The model is only expected to be valid for water fractions below 10-15 %.

If additional turbulence is introduced to the system in form of bends, valves, contractions etc, the critical velocity may be reduced considerable. Confer the ISO 3171 standard [7] for procedures to handle such cases.

4.2 Vertical and inclined pipes In vertical pipes, the dispersion is normally better than in horizontal lines due the absence of a gravity component normal to the flow direction. In horizontal flows the gravity component in the transversal flow direction promotes stratification. In inclined pipes, the gravity plays a role depending on the inclination angle. The approach used in horizontal pipes can also be used for vertical and inclined pipes if a very conservative estimate is desired. However, a flow pattern model for vertical and inclined pipes has recently been developed and tested by Flores et al. [8]-[10] in the multiphase flow loop at the University of Tulsa. Flores et al. developed a mechanistic model to predict the transition to the flow regime Very Fine Dispersion of Water in Oil (VFD W/O). This flow regime is characterised by a flow with very small water droplets distributed in a continuous, fast moving, oil phase over the entire cross sectional area of the pipe. Hence, this flow can be considered as homogeneous mixture. The transition to VFD W/O occurs at relatively high flow rates of the oil phase and is essentially independent of inclination angle in the range 45° – 90° from the horizontal. The transition mechanism to the VFD W/O flow regime is following: The turbulent forces in the oil phase have to be sufficiently large to overcome the interfacial tension forces of the water droplets, with the restriction of a minimum droplet diameter to keep the spherical droplet shape. Based on these criteria Flores et al. [8]-[9] derived a single formula for the VFD W/O flow regime transition expressed in terms of superficial oil and water velocities.

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Expressing the model in terms of the mixture velocity and the water fraction instead of superficial velocities yields the following formula for the critical (minimum) velocity Vc that is required to maintain a homogeneous flow in a vertical, or inclined pipe (45° – 90° from the horizontal plane):

( )( )

% 25-20

100

111.0

444.0

278.0278.0

556.1

556.0

2

<

⋅

−⋅⋅

−⋅=

β

µρρρσ

ββ

oo

owowc

DKV (2)

where

cV Critical (minimum) velocity for maintaining homogeneous flow K2 Constant depending on unit system (K1= 2910 for SI units)

owσ Interfacial (surface) tension between oil and water

oρ , wρ Oil and water density, respectively

D Inner pipe diameter

oµ Oil viscosity

β Volumetric water fraction in per cent Eq. (2) are not expected to be valid beyond 20 - 25 % water content in oil, since the water droplets would not remain spherical, but forming larger droplets that causes the mixture to be inhomogeneous when the water fraction exceeds approximately 25 %. See Flores et al. [8] - [10] and the Handbook of water fraction metering [1] for more details about the derivation of the flow regime model. By using Eq. (2) it is possible to calculate the critical (minimum) liquid velocity for a given water fraction when the fluid properties and the pipe diameter are known quantities. Eq. (2) is plotted in diagrams in the Handbook of water fraction metering [1] for different values of fluid properties and pipe diameter with the water fraction as a parameter. Figure 2 shows an example where the varying parameter is the oil density and the water fraction. Generally, the critical (minimum) liquid velocity that can be allowed in order to maintain homogeneous flow decreases with increasing oil density (see Figure 2) and viscosity, and increases with increasing interfacial tension and pipe diameter. These trends are similar to the trends observed in horizontal flow, though the two models are based on different physical principles.

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0

0.5

1

1.5

2

2.5

3

3.5

500 550 600 650 700 750 800 850 900 950 1000

Oil density [kg/m3]

Cri

tica

l vel

oci

ty [

m/s

]

µo = 5

cP

σow = 25 mN/m

ρw = 1025 kg/m3

ID = 4"

β = 1 %

β = 5 %

β = 10 %

β = 15 %

β = 20 %

Figure 2 Critical liquid velocity for different water fractions β as a function of the oil density in vertical or inclined pipes (45° - 90° from the horizontal plane). For a given water fraction β, the flow will be homogeneous as long as the actual liquid velocity is greater than the critical velocity given by the diagram. The model is expected to be valid for water fractions below 20-25 %.

The models (Eqs. (1) and (2)) for predicting homogeneous water-in-oil mixtures in horizontal and vertical pipe flow can be applied to assess whether a water in oil mixture fulfils the requirement of WFMs regarding homogeneous flow. However, it is important to emphasise that both models are based on simplified and semi-theoretical models that may have restricted validity. A conservative approach is strongly recommended when estimating acceptable limits for adequate dispersion, i.e. use the worst-case conditions expected (lowest liquid velocity, lowest oil density, lowest oil viscosity and highest interfacial tension). 5. APPLICATIONS

The handbook contains a chapter where operational conditions typically experienced by on-line WFMs are discussed, with indication of the operational advantages that can be obtained by using this technology compared to traditional manual sampling and analysis. Two main areas are covered:

• Fiscal applications - sales & allocation measurement. • Test separator applications.

The Fiscal applications discussed are typically those subject to regulations, e.g. the Norwegian Petroleum Directorate (NPD) Regulation for fiscal measurement [11]. In addition, limits on allowable water fraction are normally stated in contracts between Seller, Pipeline operator and Buyer. The section is further divided in two main groups: sales metering and fiscal/allocation metering of petroleum products. The first is characterised by fiscal metering of stabilised crude oil, either continuous operation (pipeline) or batch loading (offshore/onshore tanker loading), and the second characterised by NGL and condensate

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applications with typically low water content, low density, low viscosity, high vapour pressure and high thermal expansion. 6. PERFORMANCE SPECIFICATION A recommended performance specification sheet is included in the handbook in order to provide a means for more uniform uncertainty specification of WFMs. Vendors are recommended to use this uncertainty specification format when quoting for fiscal applications, simplifying the comparison of different WFMs and securing that the required information is provided and documented. The recommended performance specification sheet is shown in Table 1 (The values in italic are sample values).

Table 1 Recommended performance specification sheet for fiscal WFMs.

Uncertainty @ 95 % confidence level (k = 2) 0 - 1 % Water ± 0.05 % abs.

1 - 10 % Water ± 5 % of readingRepeatability (assuming fixed Typical process data as suggested below) 0.01 % abs.Resolution 0.005 % abs.Sensitivity to errors in input parameters 1)

Input parameter Input type 2) Typical process data Input error 0,10 % 1 % 10 % Ref. Temperature Live 45 deg. C +/- 1 C -/+ 0.0055 -/+ 0.0054 -/+ 0.0065 Pressure Fixed 30 BARG +/- 10 BARG -/+ 0.000015 -/+ 0.00015 -/+ 0.0016 Dry oil density N/A 830 kg/m3 @ 15 C +/- 1 kg/m3 N/A N/A N/A Mixture density Live 810 kg/m3 @ TP +/- 1 kg/m3 -/+ 0.034 -/+ 0.034 -/+ 0.035 Water density N/A 1025 kg/m3 @ 15 C +/- 10 % N/A N/A N/A Water conductivity Fixed 50 mS/cm @ 20 C +/- 10 % -/+ 0.000039 -/+ 0.00048 -/+ 0.014

References (documentation of sensitivity to errors in input parameters)1234

Available output parameters1234567

Notes 1) Effect of Input error on % Water value at 3 different ranges (enter N/A if Input type is N/A ) 2) Input type may be one of the following:

Live - Continuous digital input signalFixed - Values entered in menues

N/A - Input parameter not used or calculated from other input parameter Furthermore, the handbook defines specific requirements for uncertainty evaluation of WFMs to be used in fiscal applications with respect to combined uncertainty in measured water fraction. Such an uncertainty evaluation must include the uncertainties of the quantities input to the WFM and the functional relationships used. This evaluation should also include the implementation of the models and measurement procedures in the WFM, in order to consider the meter as it really operates in a fiscal application. The uncertainty calculations must be performed according to the principles of the ISO-Guide [6]. In addition to traditional quantitative uncertainty evaluation, it is required to perform an evaluation (quantitative if possible, otherwise qualitative) of the suitability of the technology for use in fiscal applications, and to consider the influence on the WFM by different unwanted flow effects. Such unwanted effects may be free gas, salinity variations, in-homogeneity, scaling/wax, or other relevant factors.

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7. INSTALLATION

The main requirement for installation of WFMs is to achieve an automatic and continuous measure of the water content of the stream for all flow rates. In general, a WFM can be installed in horizontal or vertical pipes, and these two installation methods are in principle equal. However, the necessary fluid velocity required for adequate oil and water mixing is less with vertical installation than horizontal (see section 4). Field calibration routines have the possibility to have a simpler operation in vertical installations, but may require a platform for easy maintenance and service, as there shall be access to all instruments. Different philosophies regarding installation of instrumentation systems will be part of the basis for selection of installation type, e.g. whether emphasizing given types of maintenance or measurement comparison philosophies. However, the handbook describes a wide range of important issues to be regarded when installing a WFM in a fiscal application, and three types of general installations are discussed along with their advantages and disadvantages. These three general types are:

1. WFM installed up-/downstream of the metering station. 2. WFM installed up-/downstream of a flow meter in a meter run. 3. WFM installed in a fast loop.

The handbook describes three different configurations of the type WFM installed up-/downstream of a metering station: 1) Continuous comparison with by-pass loop, 2) Series installation for continuous metering and comparison and a 3) master solution. Sketches of these three configurations are shown in Figure 3 to Figure 5, respectively, while Figure 6 and Figure 7 show examples of the two other types of installations.

Figure 3 Water Fraction Meter upstream the metering station. Continuous comparison with by-pass loop.

Figure 4 Water Fraction Meters installed upstream the metering station for continuous metering and

comparison.

Figure 5 Water Fraction Meter upstream the metering station. Master solution.

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Figure 6 Water Fraction Meter in each meter run.

Figure 7 Water Fraction Meter downstream the metering station.

It should be emphasized that the installation type shown in Figure 7 is not in accordance with the recommendations for fiscal applications set out in NORSOK standard I-105, paragraph 6.1.3 [12]. For installations of the type shown in Figure 7 the by-pass sampling may cause an additional uncertainty. Hence, this type of installation may be considered for non-fiscal applications where slightly increased measurement uncertainty is acceptable. 8. FIELD CALIBRATION

As mentioned, the development of new improved and independent calibration and adjustment procedures for fiscal and allocation water fraction measurements has been one of the main targets of the workgroup. Hence, a new procedure for field calibration avoiding the use of water fraction determination by means of in-line sampling and analysis is presented. Manufacturers may recommend specific ways of field calibration and adjustment, and the handbook covers field calibration in general terms. During a calibration of a WFM the manufacturer or operator will perform certain operations in order to establish the relationship between measured response from the WFM and a set of certified reference materials. For WFM’s covered by this handbook certified reference materials will typically be non-conducting media with different permittivity values (air, oil or similar). The purpose of the field calibration is to verify that the performance of the WFM is still within the acceptable level of uncertainty. The manufacturer should establish a procedure that describes how this task can be performed with the WFM still installed in the field. The calibration certificate shall specify acceptance criteria for relevant parameters (primary variable, e.g. frequency or permittivity) and their corresponding uncertainty in terms of water fraction.

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This handbook recommends two levels of field calibration:

1. Intermediate Calibration - can be performed with short intervals, typically on a monthly basis.

2. Main Calibration - is in all respects a full calibration, identical or close to a factory calibration.

Historical data may form the basis for a decision on alternative intermediate calibration intervals, and it will typically be a one- or two-point calibration. It will enable the operator to determine if the performance of the WFM is acceptable or not. If the intermediate calibration is not acceptable, a main calibration should be performed. A main calibration will typically be performed on a yearly basis. Calibration in the field may be possible provided that the operator has access to calibration reference standards or materials (calibration oils or similar), and that the required traceability of these standards and supporting calibration equipment are met. 9. ADJUSTMENT

If the result from main calibration is not acceptable, this may indicate the need for adjustment. Adjustment of the meter may comprise software, mechanical and/or electrical modifications. For example this may require filling the sensor unit with liquids of known properties (reference materials). Traceable calibration certificates are required for equipment, reference standards or materials used during calibration and adjustment. 10. CONCLUSION

The major intention and motivation for starting the work with the Handbook of water fraction metering has been to arrive at new improved and independent procedures for calibration and adjustment of water fraction meters in fiscal applications. The work with, and release of, the handbook presented in this paper comprises a large step towards this goal, where new calibration and adjustment procedures and recommendations for continuous determination of water fraction in hydrocarbon liquids are published. 11. ACKNOWLEDGEMENTS

The authors would like to express great appreciation to the workgroup participants Eivind Dykesteen (Fluenta, now Roxar Flow Measurement AS), Endre Jacobsen (Statoil), Hallvard Tunheim (Norsk Hydro), Morten Brandt (Fluenta, now Roxar Flow Measurement AS), Sidsel E. Corneliussen (BP Norge), Ottar Vikingstad (Roxar, now Roxar Flow Measurement AS), for their important contributions to the handbook and financial support. The authors would also like to thank NFOGM and Svein Neumann (PPCon, Stavanger) for financial support for developing this handbook as part of the NFOGM handbook series.

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12. SYMBOLS The following symbols are used in the schematic drawings, where the symbol for the WFM is proposed as a new symbol for WFMs by the workgroup.

Flow meter

Valve

Static mixer

Water Fraction Meter

Pump

13. REFERENCES

[1] Norwegian Society for oil and Gas Measurement (NFOGM): Handbook of water fraction metering. Rev. 1., June 2001, http://www.nfogm.no/

[2] Norwegian Society for Oil and Gas Measurement: Handbook of Multiphase Metering, 1995

http://www.nfogm.no/ [3] Norwegian Society for Oil and Gas Measurement: Handbook of uncertainty calculations – Fiscal

metering stations, Rev. 1., 1999, ISBN 82-91341-28-1, http://www.nfogm.no/.

[4] Albrechtsen R. A., Dahl E. O.: Uncertainty evaluation, Fluenta WIOM 350, Christian Michelsen Research, Report No.: CMR-00-A10003, February 2001.

[5] Dahl E. O., Albrechtsen R. A.: Uncertainty evaluation, MFI WaterCut Meter, Christian Michelsen Research, Report No.: CMR-00-A10002, February 2001.

[6] ISO (International Organisation for Standardisation): Guide to the expression of uncertainty in measurement. On behalf of BIPM, IEC, IFCC, ISO, IUPAC, IUPAP, OIML. ISBN 92-67-10188-9, 1995.

[7] ISO 3171: Petroleum liquids – Automatic pipeline sampling. 2nd edition, 1988.

[8] Flores, J. G.: Oil-water flow in vertical and deviated wells. PhD thesis. University of Tulsa, USA, 1997.

[9] Flores, J. G., Chen, T., Sarica, C. & Brill, J. P.: Characterization of oil-water flow patterns in vertical and deviated wells. SPE 38810. Annual technical Conference and Exhibition, San Antonio, USA, 5-8 Oct 1997.

[10] Flores, J. G., Sarica, C., Chen, T. & Brill, J. P.: Investigation of holdup and pressure drop behaviour for oil-water flow in vertical and deviated wells. Journal of Energy Resources Technology, ASME, Vol. 120, pp 8-14, 1998.

[11] Norwegian Petroleum Directorate (1999), Regulations relating to fiscal measurement of oil and gas

etc.,47 pp., English and Norwegian text. ISBN 82-7257-598-1. [12] NORSOK Standard I-105 (1998): Fiscal measurement systems for hydrocarbon liquid, Rev. 2.

19th International North Sea Flow Measurement Workshop22-25 October 2001 – Kristiansand, Norway

OPTIMISATION OF FLOW MEASUREMENTS IN A PULSATING FLOW-EXPERIENCES FROM FIELD MEASUREMENTS-

E. van Bokhorst and M.C.A.M. Peters

TNO Institute of Applied Physics – Flow CentreDelft The Netherlands

1 ABSTRACT

Analyses of unsteady flow in pipe systems are normally applied in case periodic pulsations are to beexpected as a result of well known sources like reciprocating compressors or other positivedisplacement machinery. The API 618 Standard for reciprocating compressors recommends such apulsation and mechanical response analysis to prevent unacceptable vibration levels and cyclic stressesin the piping and connected instrumentation. However the impact of pulsating flow on flowmeteraccuracy is not considered and criteria for allowable pulsations at flowmeters in relation to meteringerrors are not specified in the present edition of the standard.Though it is well known that pulsations may have a considerable impact on traditional techniques likeorifice metering, turbine and vortex flowmeters, moreover recent investigations have shown that alsoultrasonic flowmeters may be influenced by pulsations.Flowmeter manufacturers do not often refer to uncertainties as a result of unsteady flow, nor do theydefine criteria with respect to allowable pulsation amplitudes or frequencies for their flowmeters.Amplitude thresholds can be defined for differential pressure type flowmeters and turbine flow meterswithout reference to pulsation frequency. In the case of a vortex flowmeter the pulsation frequencyrelative to the vortex frequency is a much more important parameter than the velocity pulsationamplitude. The impact on flowmeters differs considerably dependent on the measuring technique andthe amplitude and frequency of pulsations.

Little information is available so far on actual flow pulsations occurring in flow metering stations dueto excitation by compressors or induced by flow due to vortex shedding at T-joints, reducers or valves.This paper shows the results of three cases in which pulsation measurements on-site have beenperformed and analysed for different flow metering stations with and without compressors.

The first case describes the pulsating flow caused by a number of parallel-operating reciprocatingcompressors. We investigated the impact of modifications in the piping on the pulsation levels at theflow meters by means of our 1D-simulation software package PULSIM. The actual pulsation levels,determined by on-site measurements in the unmodified lay out, show that there is a considerableimpact on a 12-inch turbine and vortex flowmeter, placed in series on the suction inlet line.

In the second case on-site measurements prove that high frequency pulsations caused by centrifugalcompressors are damped effectively at a relatively short distance from the compressor stationdependent on the geometry of the piping. The on-site measurements convinced the parties involvedthat a flow metering station could be located at the same site as the compressors.The layout of the flow metering station, the gas flow velocity and density are important parameters inthe occurrence of flow induced pulsations.The impact of piping geometry and gas properties is illustrated on experiences described in casestudies 2 and 3.The cases described in this paper show that 1D-simulation can be an effective tool in predictingpulsation levels in flow metering stations and in optimising the lay out to obtain minimum flow andpressure pulsations in order to minimise the uncertainty in flowmeter readings. On the other hand a

continuous effort in flowmeter design and signal processing is necessary to improve flowmeteraccuracy in case of disturbances like pulsations and vibrations.

2 AN OVERVIEW OF PULSATION IMPACT ON FLOWMETERS

Systematic errors caused by a pulsating flow can be positive or negative and are in general related toflow or velocity pulsation amplitude and frequency. In contrast to the criterion of pressure pulsation asspecified in API 618 for pipe systems in relation to pulsation forces, the flow or velocity pulsationamplitude (and frequency) determines the error in reading.For purely sinusoidal pulsations the systematic error for orifices and turbine flowmeters can bequantified in direct relation with flow pulsation amplitude and frequency. This aspect should be takeninto account in a pulsation analysis according API 618 and errors in reading can be estimated based onthe flow pulsations, calculated in the analyses at the flowmeter location.In ISO/TR 33313 the threshold for differential pressure type flowmeters is defined as U’

rms/Umean≤0.05and for turbine flowmeters U’

rms/Umean≤0.035, corresponding to a systematic error less thanrespectively +0.125 % for orifice metering and +0.1% for a turbine flow meter.In those case were considerable pulsation levels are calculated the study may reveal that the flowmeterlocation should be altered or that additional measures are necessary to dampen pulsations to achieveacceptable levels by means of a pulsation damper, additional friction, pipe modifications or acombination of these. In most cases the pulsations caused by compressors are periodic, but notnecessarily sinusoidal, so that the relation between pulsation levels and misreading cannot bequantified accurately.An overview of the impact of pulsations on different metering techniques and references to standardsand published literature is shown in the table below:

FlowmeterTechnique

Origin ofSystematic Error

StandardforFlowmeter

StandardPulsationImpact

Criterion inISO/ TR3313

References

Dp:Orifice,Nozzle andVenturi

Square-root error andgauge line errors

ISO 5167AGA rep. 3(API 2530)

ISO/TR3313

Uall= 5 %rms

1,2

Turbine Inertia of the rotor andfluid

ISO 9951 ISO/TR3313

Uall= 3.5 %rms

3,4,5

Ultrasonic Aliasing error ISO TR 12765AGA rep.9

- - 8,9

Vortex Lock-in ISO TR 12764 ISO/TR3313

- 6,7

Coriolis Lock-in ISO 10790 - - 10,11,12ElectroMagnetic

Unknown ISO - -

Table 2.1 Overview of pulsation impact on various flowmeters

3 PULSATION IMPACT ON A TURBINE AND VORTEX FLOWMETER CLOSE TO ARECIPROCATING COMPRESSOR

A station for natural gas storage and transport is supplied with five similar reciprocating compressorswith a speed variation between 650 and 800 rpm. The station is extended with an additionalreciprocating compressor with a variable speed between 600 and 1000 rpm to obtain the maximumflow of approximately 60.000 Nm3/hr. The gas is compressed from a suction pressure between 2600

and 7100 kPa to be stored in an underground storage at a discharge pressure between 4500 and 8600kPa.A pulsation analyses according to the API618 standard is required, which should also include ananalyses of the pulsation impact on the flow metering station located in the suction piping. This studyshould reveal what measures are necessary to limit the maximum pulsations caused by paralleloperating compressors. A schematic layout of the gas compression and metering station is shown infig. 3.1

Fig.3.1 Schematic lay-out of compressor and metering station

The pulsation analyses are performed with our simulation package PULSIM, developed for thecalculation of plane-wave propagation in pipe systems and fluid machinery. The 1-D approach hasshown accurate results for low-frequency pulsations in pipe-systems restricted to a frequency f < 0.586c/D, in which c is the speed of sound in the gas and D is the pipe diameter.

The pulsation analyses show that considerable pressure pulsations, above API618 limits, andcorresponding pulsation induced vibration forces are caused by acoustic resonances between thecompressors, mainly on suction side. As a result of the parallel operating compressors, running atdifferent phase and/or speed, beating pulsations will excite the pipe system. The maximum amplitudeof the beating pulsation is found by adding the individual pulsation amplitude caused by eachcompressor.The flow pulsations at the flow metering station, upstream of the compressors on suction piping arevarying between 20 % peak-to-peak for one compressor up to 100 % peak-to-peak for 5 compressorsin parallel. This flow pulsation level will cause a considerable systematic error at the turbine andpossibly also at the vortex flowmeter. The pulsation amplitude and frequency determine the error inthe turbine flowmeter reading, which is due to rotor inertia. A best estimate based on the theory ofBonner and Lee [3,4] is that the turbine metering error ranges from +0.5 to +10%.The analyses reveal that pulsations cannot be damped effectively by simple means, such as individualorifice plates at the pulsation dampers, without causing excessive pressure losses at increasing flow.An additional damper volume, size 2.5 m length and diameter 0.65 m, is recommended to reduce theflow pulsation at the flowmeters to 2% pp for each individual compressor.The new-installed compressor could be supplied with an acoustical filter, which dampens pulsationlevels successfully over the entire operating envelope. Originally the filter consists of a two-chamberdamper with two cylinders on each side of the compressor, which reduces the pressure pulsationswithin the API 618 criteria. Further reduction is required as to reduce the maximum flow pulsation atthe flow meter, which is still 10 % pp. A secondary damper volume, size 2.5 x 0.55m, has beenrecommended to obtain a level of approximately 2 % pp.

An overview of the reduction in pulsation levels obtained with different recommendations is shown inthe table below.

Modification Maximum flow pulsations,U in % pp

Estimated systematic errorIn turbine meter

Original lay-out 110 % pp < 10 %Modification 1 with orificeplates at suction dampers (dP=1%)

50 % pp < 5 %

Additional volume bottle of 0.8m3 at each compressor plusorifice plates and modifiedpiping for new compressor

11.5 % pp < 0.5 %

Modification 2 with controlvalve on each suction line with apressure drop of 5 %

30 % pp < 1.0 %

Fig. 3.2 Table showing the simulation results of various modifications

In addition to the model analyses we have been requested by the operator to perform on-site pulsationmeasurements to be able to determine actual levels and corresponding systematic errors at the flowmeters.Pressure pulsation measurements have been performed on 5 different locations on the 12 inchmetering section (see fig. 3.3) at various conditions with1 up to 5 compressors running.

Fig.3.3. Locations for pulsation (P) and vibration measurement (V) at the flow metering station

One of the compressors is varied in speed, whilst the others run at a fixed speed of 750 rpm. Pressurepulsations vary slightly with speed: the maximum level measured is 40 kPa pp, which isapproximately 1 % pp of the line pressure of 4300-4500 kPa. The dominant frequency is 25 Hz,which is 2nd harmonic of the compressor speed. This is well in line with the simulation results, whichshow a 2nd harmonic resonance at 780 rpm.

We have calculated flow pulsations from the measured pressure pulsations by means of the “two-microphone method”. The analyses show a maximum flow velocity pulsation of 2.6 m/s pp (0.91 m/srms) at 25 Hz. This value is measured with 3 compressors running in parallel, with a mean flowvelocity in the 12-inch metering line of 6.0 m/s (60.000 Nm3/hr). An example of the (measured)pressure and (calculated) flow pulsation at turbine (P1) and vortex flowmeter (P3) is shown in fig. 3.4

Fig.3.4 Spectra of pressure and flow pulsation at turbine (P3) and vortex flowmeter (P2)

The corresponding systematic error at the turbine flow meter at this flow pulsation level is estimated at+ 2.1 %, based on the manufacturer’s data and assuming a sinusoidal pulsation.The systematic error at the vortex flowmeter cannot be determined simply as the relation between flowpulsation and error in reading depends on the individual meter design and the sensor used. Though anearlier investigation of different make vortex flowmeters has shown, that a pulsating flow affects thevortex shedding process, such that the vortex shedding frequency can lock to the pulsation frequency.The strongest lock in occurs, when fv/fp = 0.5, though lock-in also occurs at fv/fp = 0.25, .5, 1.0, 1.5,2.0Actual lock-in has not been noticed at the maximum flow pulsation occurring at 25 Hz of 2.6 m/speak-to-peak at 6.0 ms/ mean flow, which is 43 % pp.The relation between vortex frequency and bluff body diameter is presented as: fv = Str*v/D in which:

fv : vortex frequency in HzStr: Strouhal number 0.3v: flow velocity in m/sd bluff body diameter 0.3 pipe diameter

According to this expression the vortex frequency fv for a mean flow velocity of 6.0 m/s is 20 Hz,which is not far from the pulsation frequency of 25 Hz. For the total flow range of 1.500 – 120.000Nm3/h the vortex frequency for the 12–inch flowmeter varies between 5 and 40 Hz.

This is partially within the range of pulsation frequencies excited by the compressors running between600 and 1000 rpm (10 – 16.6 Hz) and exciting mainly 2nd harmonic of compressor speed. It shouldalso be noticed that fluctuation in pulsation and vibration levels occurs if compressors run at differentspeeds. The beating frequency of the pulsation is determined by the difference in compressor speed, asshown in the example fig. 3.5

Fig.3.5 Example of a beating pulsation as a function of time (left)

The pulsation errors on vortex flowmeters are found to be mainly negative, especially at lock-in,though also positive errors occur if vortex frequencies are approaching towards pulsation frequencies.The figures of actual flows of the flowmeters are only available as mean-hour flows, showing adeviation between turbine and vortex flowmeter of approximately +1.5 %. This confirms thetheoretical positive systematic error of the turbine meter assuming the error in the vortex flowmeter isnegative or neutral if no lock-in occurs.The client will now taken measure to decrease pulsation levels, as resulting from the simulationstudies. In this way systematic errors are reduced effectively to a level below 0.5 % over the entireoperating envelope of the compressors.

4 IMPACT OF PULSATIONS FROM A TURBOCOMPRESSOR AND ON AN ORIFICEMETERING STATION

A natural gas transport station at Olbernhau (Germany) is equipped with two identical centrifugalcompressors, operating single or parallel and running in a speed range of 5000-7200 rpm. The gasflow, which varies from 180.000 to 900.000 Nm3/h, is measured on the suction side, line pressure4200-5000 kPa, via a flow metering station provided with orifice plates.The flow is measured via 1 up to 5 parallel lines: four 16-inch and one 6-inch metering line dependenton the gas flow. The range of flows used for the 16-inch metering is between 100.000 and 300.000Nm3/h. A simplified flow scheme of the compressor station is shown in fig. 4.1.

Fig. 4.1 Simplified Flow scheme of compressor and metering station Olbernhau

The purpose of the on-site measurements and analyses is to investigate whether pulsations caused byturbo compressors can have an impact on an orifice flow metering station located nearby. The resultsare used to establish if a flow metering station can be located at relatively short distance from thecompressor(s) for the Yamal pipeline stations. The Olbernhau station is similar to the compressorstations to be located along this pipeline from the Yamal field to Germany and is therefore used forthis investigation.Transducers for pressure pulsation measurements are located on the suction inlet of the turbocompressors and on one out of four16-inch metering line at various locations:1) P1 up to P6 directly on the 16 inch metering line2) P7 and P8 close to the dP-transmitter at the end of the gauge lines (length 7 meter; diam. 9 mm)3) P9 and P10 on suction inlet of the compressorsSome transducer have a small connection line (150-500 mm) whilst other transducers (P1 and P3) onthe main lines are flush-mounted.

4.1 Pressure pulsations at the vane-passing frequency

The pressure pulsations measured near the compressor in-and outlet show a dominant component at the vane passing frequency, which corresponds to the running speed times the numberof vanes (15) An example of this measurement is shown in fig.4.2 with a level of 50 kPa (0.5 barpeak) for location P9 at a vane passing frequency of 1530 Hz (compressor speed 6122 rpm).Pulsations at the running speed or higher harmonics thereof are not present in the spectra.

Fig.4.1.2 Pressure pulsation spectrum at compressor outlet – dominant frequency 1530 Hz

Other frequencies shown in the spectrum are 250,750,1250 and 1750 Hz, which correspond tostanding waves in the 1 inch connecting line (1/4, 3/4, 5/4 and 7/4 wavelength) to the transducer,which has a length of 350 mm.The spectra of pressure pulsations in the metering section from P1 up to P8 at the same condition showconsiderable reduction, over a factor 100, from the vane-passing frequency component to amplitudes <1 kPa (or 10 mbar). The maximum level is 0.5 kPa (5*10-3 bar) at location P2 at 1600 Hz; an overviewof the spectra at P2 at different compressor speeds and corresponding vane passing frequencies from1500-1750 Hz are show in fig. 4.1.2. The flow induced pulsation in the measuring pipe is independentof running speed and remains at 500 Hz. The amplitudes at the pressure transmitter of the orifice (P7and P8) are even below 0.1 kPa.

fig.4.1.2. Pressure pulsation spectra at P2 on 16-inch metering line at various compressor speeds

In VDI 3733 the damping for acoustic waves in an ideal gas is expressed per unit of straight pipelength:Damping equals (0.15 f*T)/(D*P*293) dB per m, in which:D: line diameter in mf: frequency in HzT: temperature in degrees KelvinP: line pressure in Pascal

For a 24 inch line and a frequency of 1500 Hz the damping is approximately 0.004 dB/m. Thedamping across bends however is dominant as it varies between 0.5 and 0.3 dB, dependent onfrequency and bend radius. The flow metering station is at a distance of 150 meter (pipe length) fromthe compressors and the number of bends, tees and reducers/expanders is 20. The actual damping forthe vane passing frequencies measured is at least 40 dB, which is above the calculated level, based onthe formula mentioned above showing 10 dB.We conclude that pulsations caused by the centrifugal compressor are reduced effectively and do notinterfere with the orifice flow measurement.

4.2. Low-frequency pulsations

The measurements on the 16-inch flow metering section and especially those near the pressuretransmitter mainly show pulsations in the range below 200 Hz. It is likely that resonances in the gaugelines are excited due to vortex shedding. As a result of gauge line length (L=7 meter) standing wavesoccur at frequency f = c/4L or odd multiplies thereof, which is 14, 42, 70,…… Hz.This corresponds to the pressure pulsations measured at P7 and P8 and thus also in pressure differencedP as shown in fig 4.2.1 and fig.4.2.2Pressure difference 50 mbar

50505

Fig. 4.2.1. Pressure difference P7-P8 as a function of time [s]

The pressure difference P7-P8 shows a considerable dynamic pressure of 33 mbar pp on a static dP of25.4 mbar at a mean flow of 20.8 m3/s in the metering section.

An overview of the measurement results at various flow conditions is shown in the table in fig.4.3.3.Assuming a slow response dP sensor the time-mean differential pressure will be indicated. Thecorresponding flowrate than included the square root and temporal inertial effect errors.The estimated quare-root-error ET can be expressed as: ET = [1 + (Urms/Umean)2]0.5 - 1 [seeISO/TR3313]If we assume a slow-response sensor the estimated error due to pulsations is less than 0.1 % for almostall conditions, except for the lowest flow conditions 4 and 4a. The flow via metering line 5 at thiscondition is 75.000 Nm3/h or 20.8 Nm3/s and the maximum measuring error is +5% at condition 4a(hand-operated valve in 6-inch metering section closed and +2% at condition 4 (hand-operated valvein 6-inch metering section open).During all measurements the metering lines 1,2 and 5 are open, which is not a normal operatingcondition for the lowest flow of 233.000 Nm3/h over the station. The metering range for a single 16-inch metering ranges from 300.000 to 100.000 Nm3/h, so the total flow can pass via a single 16-inchmetering line.So obviously only at (too) low flows pulsations in the gauge-lines can disturb flowmeter readings dueto flow-induced resonances in the gauge lines.The connecting line-length between primary element (orifice plate) and secondary instrumentation(dP-transmitter) should be restricted to prevent resonance if the length equals a quarter wavelength orodd multiples thereof.

The on-site measurements have shown that the high frequency pulsations caused by a turbo-compressor are damped effectively and will not have an impact on flow metering close to thecompressors, assuming the distance is at least a 100 meter.Considerable low-frequency pulsations did occur at the flow transmitter due to resonances in thegauge-lines, which is excited by vortex shedding. Unsteady vortex shedding can be a strong source ofpulsations if the vortex shedding is coupled to an acoustic resonance in the system.The PULSIM package, in which the pulsation source resulting from the source is incorporated, can beused to analyse a flowmetering station. The package has been applied to analyse flow-inducedpulsations in a gas control station and give recommendations for the geometry to omit resonanceconditions [14]Guidelines for the design of flowmeter instrumentation are summarised in the ISO/TR 3313 and coverremarks with respect to both slow-response and fast-response dP-sensors for orifice metering.

5 FLOW-INDUCED PULSATIONS DUE TO VORTEX SHEDDING AND IMPACT ONA TURBINE FLOWMETER

The gas flow metering station concerned consists of two 16-inch streams A and B, each provided witha 16-inch turbine flow meter. TNO Institute of Applied Physics has been requested to perform

pulsation analyses to establish if flow pulsations are present and can have an impact on the accuracy ofthe flow meter. When the turbine meter is subjected to an unsteady flow the inertia of the rotor cancause the rotor speed to lag behind in an accelerating flow and to exceed it in a decelerating flow. Asthe impact of a decelerating flow exceeds that of an accelerating flow the error in reading of the flowmeter subjected to pulsation will always be positive.The total flow rate in the metering station varies between 5800 and 11000 m3/h at a line pressurebetween 1300 and 1600 kPa. Measurement locations are upstream and downstream of the turbineflowmeter and also on the reference pressure tapping as shown in the schematic lay out in fig.5.1.There are no compressors located on-site and there is no gas control or pressure reduction in thestation. The only sources are flow-induced pulsations due to vortex shedding at T-joints or at otherobstructions in the piping geometry.

Fig.5.1 Overview of piping lay out in turbine metering station

The pressure pulsations measured on-site are ranging from 2-24 mbar pp, which is rather low: in theorder of 0.01 to 0.15 % pp of the line pressure. Main frequencies occur in the range between 0-25 Hzwith dominant components at 6, 12 and 16 Hz. An example of the spectrum of the measured pressureand calculated flow pulsation is shown in fig. 5.2.

Fig.5.2 Measured pressure pulsations at P1 and P4 are used to calculate the flow pulsation or velocityat P4.

The recorded pressure pulsations are analysed to calculate the corresponding flow pulsations by thetwo-microphone method (2MM) as the amplitude of the flow-pulsation and frequency determines theerror as explained in chapter 2. In the 2MM a coherence analysis is performed: only those frequenciesfor which the coherence > 0.95 are plotted in fig. 5.2. (So lines of the spectrum are missing if thecoherence is less than 0.95)An overview of some results of the measurements for the various test cases are shown in table 5.2,measurements have been performed for stream A, for stream B only and for stream A and B inparallel. The maximum relative flow pulsation of 0.269 m/s rms or 6.6 % occurs for case 7 withstream A and B in operation at 3330 m3/h each.Meas. Density Flow velocity

Vmean, m/sPressure pulsation,mbar

Flow pulsation,m/s rms

Flow pulsation ofdominantfrequency in %

No. Kg/m3 VA VB P1 P2 V2 V4 V2 V41 10.12 10.03 11.94 1.7 1.7 0.014 - 0.2 -2 10.22 9.94 11.53 1.9 2.1 0.014 - 0.2 -5 11.45 6.12 7.24 2.7 1.6 0.068 0.063 2.0 1.96 11.45 13.36 closed 3.3 7.1 0.184 0.167 2.5 2.37 11.17 6.29 7.36 23.9 9.4 0.250 0.269 6.1 6.68 11.17 closed 13.76 11,9 9.3 0.396 0.439 5.2 5.8

We assumed a sinusoidal pulsation, with the dominant frequency in the pulsations at 12.5 Hz andbased our error analysis on the approach described in the latest edition of ISO/TR 3313. The

corresponding pulsation error for the turbine meter at 6.6% flow pulsation is + 0.2 %, whilst for allother measured operating conditions the error is lower.As compressors are not involved vortex shedding along a T-joint of a closed side-branch is most likelythe cause of these pulsations.The piping geometry of the flow metering station is such that standing waves in the low frequencyrange can be excited by vortices. Side branches to closed valves in stream C (not in use) and also toA/B streams if not in use are potential locations for the occurrence of resonances. Also the closedvalve to the filter stream II offers a potential location for vortex shedding.If we consider the case in which the 2nd filter stream B and the metering section A is closed aconfiguration with 2 closed side branches is present. Vortex shedding frequencies Fv are determinedby Fv = Str V/D in whichFv : Vortex frequency in HzStr: Strouhal number, for this configuration maximum source strength is obtained if Str=0.25 [13]V: Flow velocity in the main line, m/s

The range of vortex frequencies involved is 5-11 Hz or flow velocities Fv between 6 and 13 m/s,assuming Str=0.25 and D=0.3 meter.Strong resonance can occur if a vortex frequency coincides with an acoustic resonance in the pipingsystem, such as a standing wave between the closed valves in filter stream and metering section.For the distances involved (approx. 3 m between valve and header) the lowest standing waveresonance frequencies are approx. 29 Hz for a single closed side-branch (1/4 wave length) and 39 Hzfor 2 closed side branches (full wavelength 9 meter).Dependent on the configuration of the T-joint or the combination of flow direction with the acousticresonance the vortex shedding can result in a strong source of pulsation or even damping of unsteadyflow as described by Peters [13]. Further the effect of edge rounding is significant in determining thesource strength and the Strouhal number where the maximum source strength occurs.

It is recommended to omit long side branches with closed valves to prevent excitation of standingresonances by vortex shedding, which can have an strong impact on flow meters located nearby.In order to be able to predict the behaviour of such a gas metering station under various operatingconditions an analysis with the Pulsim package can be performed. Such an analysis includes:

• Building a simulation model of the gas piping involved from inlet header to outlet header,including volumes, control sections, side branches and assuming no reflection in the headers

• Calculation of the acoustic response of different piping configurations, thus enabling us todetermine resonance frequencies and standing wave patterns in the piping

• Analysis of flow-induced pulsation sources at T-joints, bends or reducers• Calculation of pressure and flow pulsation levels and frequencies in the pipe system caused

by these FIP sources as a function of flow rate and valve positions• Recommendations to modify and improve the piping design or to relocate flow meters in order

to prevent flow induced pulsations, which could have an impact of the flow meters

6 CONCLUSIONS AND RECOMMENDATIONS

The experiences from field measurements that high frequency pulsations from turbomachinery aredamped sufficiently and do not have an impact on flow meters located nearby. The reduction inpressure pulsations as observed in on-site measurements is approximately a factor 100 for the vane-passing frequencies involved.In case reciprocating compressors are applied strong flow pulsations can occur even if pressurepulsations fulfil the API618 requirements for reciprocating machinery, which are based on structuraland compressor integrity.The systematic error due to low frequency pulsations is determined by the flow pulsation amplitudeand independent of frequency when we consider dP devices and turbine flow meters. For vortex flow

meters the relation between pulsation and vortex frequency is much more important than theamplitude, due to lock-in effects. The amplitudes measured on-site are in excess of the criteria for flowpulsations at turbine meters defined in ISO/TR 3313. The impact of pulsations on flow meters close toreciprocating compressor should be evaluated in a pulsation analysis. The next edition of API618 willcontain recommendations with respect to the pulsation effects on flow meters.Low frequency pulsations due to vortex shedding in the main piping can be a strong source ofpulsations, which effect the flowmeter accuracy especially in case vortex frequencies coincide withacoustic pipe resonances.Evaluation of the lay out of a flow metering station in a simulation model is very effective in findingthe optimum lay out from pulsation point or to define the operating conditions, which can be runsafely.

REFERENCES

1. Mottram, R.C. “The behaviour of orifice and Venturi-nozzle meters in pulsating flow”Ph.D.Thesis, University of Surrey (1971)

2. Studzinski,W. et al. “ Pulsation effects on orifice meter performance” Flomeko’98 Lund Swedenpp. 417 – 422

3. Bonner , J.A. “Pulsation effects on turbine meters” American Gas Ass. Conf. Las Vegas (1976)4. Lee, W.F.Z. et al.“Gas turbine flowmeter measurement of pulsating flow”, J. of Eng for Power

(1975, pp. 531-539)5. Atkinson,K.N “A software tool to calculate the over-registration error of a turbine meter in

pulsating flow” Flow Meas. and Instr. 3 (3), 1992 pp. 167-1726. Peters.M.C.A.M. et al. “Impact of pulsations on vortex flowmeters” Flomeko’98, Lund, Sweden

June 19987. Bokhorst. E. van et al “Impact of pipe vibrations on vortex flowmeters under operating

conditions” IFFM, June 1999, Denver Colorado (CD-Rom proceedings)8. Hakansson E. and Delsing J. “Effects of pulsating flow on an ultrasonic gas flowmeter” Flow

Meas. and Instr. 5 (2), 1994, pp. 93-1029. Bokhorst E. van and M.C.A.M. Peters, “ The impact of low-frequency pulsations on a dual-beam

ultrasonic flowmeter” Flomeko 2000, Salvador June 200010. Vetter G. and Notzon S. “Effect of pulsating flow on Coriolis mass flow meters” Flow Meas.

Instr. 5 (4) , 1994, pp. 263-27311. Koudal O. et al “High frequency Coriolis meter performance under pulsating flow conditions”

Flomeko’98, Lund Sweden June 199812. Cheesewright. R. et al. “Understanding the experimental response of Coriolis massflow meters to

flow pulsations” Flow Meas. Instr. 10 (1999) pp.207-21513. Peters, M.C.A.M. and Bokhorst, E. van “Flow induced pulsation in pipe-systems with closed side

branches, impact of flow direction” , Proceedings 7th Int. Conference on Flow Induced VibrationConference pp.669-676, FIV2000/Lucerne Switzerland, 19-22 June 2000

14. Egas, G. “Building acoustical models and simulation of pulsations in pipe systems with PULSIM”Proceedings 3r Workshop “Kolbenverdichter” pp.81-108, 27-28 October, Rheine, Germany, 1999

Corresponding author:TNO TPDEvert van BokhorstP.O.Box 155, 2600AD Delft The NetherlandsPhone: + 31 15 2692346Fax: + 31 15 2692111 or e-mail: [email protected]

19th International North Sea Flow Measurement Workshop, Kristiansand, Norway, 22-25 October 2001

A ray theory approach to investigate the influence of flow velocity profiles on transit

times in ultrasonic flow meters for gas and liquid

Kjell-Eivind Frøysa a), Per Lunde a) and Magne Vestrheim b)

a) Christian Michelsen Research AS, P.O. Box 6031 Postterminalen, N-5892 Bergen, Norway b) University of Bergen, Dept. of Physics, Allégaten 55, N-5007 Bergen, Norway

ABSTRACT USM technology is today recognized as a competitive alternative for fiscal flow metering of gas, and is also considered for fiscal metering of oil and petroleum products. However, there are un-exploited potentials to reduce systematic errors, achieve higher accuracy, and to improve measurement traceability, giving perspectives for further development of the technology. The paper addresses the influences of flow velocity profile effects on transit times (sound refraction) and consequences for the measured flow velocity and sound velocity (VOS) in a USM. Systematic effects of axial and transversal flow velocity profiles at different Reynolds numbers and under various installation conditions are investigated using a ray propagation model with CFD calculated flow profiles as input. It has been found that for a wide range of axial and transversal profiles the measured flow velocity is not influenced significantly by sound refraction effects, except for relatively high flow velocities, assumed that compensation for uniform transversal flow is made (by configuration or software). Similarly, the measured VOS is not affected severely by sound refraction for a wide range of symmetrical and asymmetrical axial profiles, except for relatively high flow velocities. However, refraction effects due to transversal flow are significant also at more moderate velocities, and correction of current USM expressions may be needed for accurate VOS measurement. 1. INTRODUCTION Multipath ultrasonic flow meters (USM) have demonstrated their capabilities to provide accurate and reliable fiscal metering of gas and liquid, within national regulations. For natural gas, better than ±0.7 % uncertainty (of measured value) is being reported [1-3], as required for custody transfer in large commercial pipelines [4,5]. For USM measurement of oil and petroleum products, ±(0.15-0.25) % uncertainty is claimed [6], based on in-situ flow calibration (prover). Even within such high accuracy figures, demonstrated in flow testing, systematic errors may over time accumulate to significant economic values. Moreover, in service, conditions may be different from the test situation, and practical problems may occur so that occasionally it may be difficult to ensure that the above accuracy figures are actually reached. One challenge is now to be able to be confident of the in-service performance over a significant period of time and changing operational conditions [7]. USM technology is relatively young compared with more traditional flow metering technologies, and potentials and needs exist for further development, such as with respect to: • Improved robustness, reliability and cost/benefit ratio, • Improved understanding and exploitation the USM measurement principle (e.g. reduction of

systematic effects, improved accuracy and traceability to international standards), • Extended applications (density and calorific value measurement [8], wet gas metering [9], etc.). Such developments require improved solutions within several technology areas related to the USM. Table 1 gives an overview of some effects which may influence on USM fiscal metering of gas,

2

assumed that the meter otherwise functions according to manufacturer recommendations. Flow calibration of the USM may eliminate or reduce a number of the systematic effects, but, as indicated in the table, several effects may still be influent, despite flow calibration [10,11]. Table 1. Uncertainty contributions to USM in field operation, with respect to volumetric flow rate measurement.

Uncertainty group

Type of effect Uncertainty contribution (examples)

Eliminated by flow

calibration? a) Integration Systematic • Pipe bend configurations upstream USM (possible difference re. flow calibr) method • In-flow profile to upstream pipe bend (possible difference re. flow calibr.) (installation • Meter orientation relative to pipe bends (possible difference re. flow calibr. ) effects) • Possible use of flow conditioners (difference re. flow calibration) • Possible wall corrosion, wear, pitting (influence on flow profiles) • Possible wall deposits, contamination (influence on flow profiles) • Initial wall roughness (influence on flow profiles) Eliminated Meter body Systematic • Measurement uncertainty of dimensional quantities (at “dry calibration”) Eliminated • Out-of-roundness Eliminated • P & T effects on dimensional quantities (incl. possible P & T corrections) Transit times Systematic • Cable/electronics/transducer/diffraction delay (P, T & flow effects, drift) • ∆t-correction (P & T effects, drift) • Possible cavity delay correction • Possible deposits/liquid at transducer front • Sound refraction (flow profile effects on transit times) • Possible beam reflection at the pipe wall Eliminated Random • Turbulence (transit time fluctuations due to velocity & temperature fluct.) (repeata- • Incoherent noise (due to RFI, pressure control valves, etc.) bility) • Coherent noise (due to acoustic cross-talk, reverberation, etc.) • Finite clock resolution a) For flow calibrated USMs only uncertainties due to changes of conditions from flow calibration to field operation are in question.

For several of these effects, better control could be achieved if better understanding and a more solid theoretical basis for the USM methodology was available. The expressions forming the basis for present-day USMs are based on a number of assumptions which are not fulfilled in practice, such as uniform axial flow (i.e. infinite Reynolds number, Re), uniform or no transversal flow, interaction of infinitely thin acoustic beams (rays) with the flow, and simplified (if any) treatment of diffraction effects [10,12]. In reality, the axial flow profile will change both with Re and with the actual installation conditions (such as bend configurations, use of flow conditioner, wall corrosion, wear, pitting, deposits, etc.). Transversal flow is usually significant and non-uniform (swirl, cross-flow, etc.). Moreover, in reality the acoustic beam has a finite beam width, interacting with the flow over a finite volume, and with acoustic diffraction effects (due to finite transducer aperture). All of these factors influence on the USM integration method as well as the measured transit times. In order to further improve the USM theoretical basis, there is a need to investigate the significance of such factors on the USM performance, and - for the significant effects - to find methods to reduce or correct for such effects. In particular, in today’s USM transit time expressions, a simplified model is used to account for the flow profiles of Reynolds numbers to be met in practice, and the influence of asymmetrical axial and non-uniform transversal flow profiles found in typical metering stations. Systematic transit time effects due to refraction of sound propagating through the non-uniform fluid flow will influence both on the measured flow velocity and the sound velocity (VOS). Traditionally, the VOS measured by the USM has been used for self-check of the USM, and as possible input to the VOS correction of vibrating-element gas densitometers used in mass flow measurement. In addition, recent developments have shown that it can be used as a basis for calculation of density and calorific value of natural gas [8]. Through the VOS, therefore, a USM supplied with such (meter independent) software can be used (with more limited accuracy) as a mass flow meter and an energy flow meter,

3

in addition to its traditional use as a volumetric fiscal flow meter. In such new applications, a VOS measurement uncertainty of about ±0.25 m/s (±0.06 %) or better would be needed (among others) for sales metering of density or calorific value [13]. In less critical applications such as allocation and check metering, a less accurate VOS measurement is acceptable. This means that control with the accuracy of the VOS measurement made in the USM is now of even higher importance than a few years ago. As one step towards better understanding, control and an improved USM methodology, the present paper addresses the inaccuracies made when using the traditional USM transit time expressions in the range of flow profiles for Reynolds numbers relevant for liquid and gas flow, and under conditions of disturbed flow profiles (different pipe bend configurations). The accuracy of the traditional expressions used for measurement of flow velocity and VOS is investigated by use of acoustic ray theory, with respect to flow profile effects on transit times (sound refraction). Axial and transversal flow profiles calculated using computational fluid dynamics (CFD) modelling of pipe flow are used as input to the ray propagation model. The ray theory simulations are compared with the traditional transit-time expressions used in today’s USMs, derived for the simplified case of uniform axial and uniform or no transversal flow. The resulting deviations in flow velocity and VOS for the traditional USM functional relationships due to sound refraction, are evaluated and discussed. Limitations of the approach used here are addressed in Section 6. 2. CURRENT USM METHODOLOGY - THEORETICAL BASIS The present section summarizes the basic and well-known expressions used in current USMs, as a basis for the improved USM ray theory that is described and compared to in Sections 3-5. The description covers USMs with non-reflecting (cf. Fig. 1) [1,2,6] as well as reflecting path [3] configurations, in the same formalism. A USM measures the axial (x) component of the volumetric flow rate at line conditions (with respect to pressure, temperature and fluid quality), qv, defined as (for fixed time, t = t0) [12]

∫∫=A

00xv dydz)t,z,y,x(vq , (1)

where A is the cross sectional area of the pipe (in the y, z - plane, at x = x0 = constant), and vx is the axial (x) component of the flow velocity. For circular cross-section, the double integral in Eq. (1) can be written as a single integral, e. g. [12,14],

∫∫ ∫−−

−

−−

−==R

Rx

22R

R

yR

yR

00xv dy)y(vyR2dzdy)t,z,y,x(vq22

22

, (2)

where R = D/2 is the inner radius of the pipe and

∫−

−−−=

22

22

yR

yR

00x22x dz)t,z,y,x(vyR2

1)y(v (3)

4

is the average axial flow velocity (the line integral) over the chord with lateral position y. For calculation of qv by numerical integration, Eq. (2) is approximated by

∑=

≈CN

1j

cx,j

cj

2v vwRq π , (4)

where Nc is the number of chords (e.g. 4-5 and 9 for non-reflecting [1,2,6] and reflecting path USMs [3], respectively). c

jw is the integration weight factor of chord no. j, and )(, jxc

xj yvv = is the

average axial flow velocity over chord no. j, which is located at y = yj, j = 1,…, Nc.

Signalgenerator

Receivingcables &electronics

Transmittingcables &electronics

Pulsedetection

Transmittingtransducer

TOP VIEW FRONT VIEW

Receivingtransducer

2Ryi

z

xL pi

φi

Fig. 1. Schematic illustration of a single path (no. i) in a USM with non-reflecting paths (parallel chords) (for

downstream sound propagation). (Left: centre path example (yi = 0); Right: path at lateral chord position yi.). In USMs for fiscal metering, non-reflecting as well as reflecting-path configurations are in use [1-3,6]. The flow velocity is measured over N acoustic paths (typically 4-6), having inclination angles iφ to the axial flow direction of typically 40° to 60°, cf. Fig. 1 [12,14]. Note that the number

of chords is not necessarily the same as the number of acoustic paths, since two paths can have the same projection into the pipe cross section, and also since a reflecting path can correspond to more than one chord. For each path, transit times are measured electronically for high-frequency ultrasonic pulses propagating across the pipe, at an angle, iφ , with respect to the pipe axis, downstream with the

flow, and upstream against the flow. Ultrasonic transducers are used to transmit and receive the signals. For each acoustic path, the difference between the upstream and the downstream propagating transit times is proportional to the average flow velocity along the acoustic path. Multiple acoustic paths are used to sample the flow velocity profile in the pipe at a set of discrete chords, to improve the metering accuracy. The measured upstream and downstream transit times of path no. i, measured

i1t and measuredi2t , contain

possible time delays due to signal propagation in the transmit and receive cables, electronics, transducers, diffraction effects, and possible cavities in front of the transducers, cf. Fig. 1. For acoustic path no. i, the measured transit times may be written as [12]

cavityi

eltr0,i1i1

measuredi1 tttt ++= , (5a)

cavityi

corr0,i

eltr0,i1i2

cavityi

eltr0,i2i2

measuredi2 tttttttt +−+=++= ∆ , i = 1, …, N (5b)

5

where t1i and t2i are the upstream and downstream transit times along the interrogation length (cf. Fig. 2), eltr

0,i1t and eltr0,i2t are the cable/electronics/transducer/diffraction time delay for upstream and

downstream propagation, respectively, and eltr0,i2

eltr0,i1

corr0,i ttt −=∆ is the ∆t-correction. cavity

it is the cavity

delay of path no. i (if used), at line conditions. For transducers with the front centre point flush with the pipe wall, cavity

it is normally not used, i.e. cavityit = 0 is assumed.

2.1 “Traditional approach”; uniform axial flow and no transversal flow For the simplified case where the flow velocity profile is assumed to be uniform and purely axial (i.e. no transversal flow), the two transit times of path no. i for propagation over the interrogation length can be found by a simple geometrical approach as (see Fig. 2)

ix,ii

ii,refli2

ix,ii

ii,refli1 cosvc

L)1N(t,

cosvcL)1N(

tφφ +

+=

−+

= , (6)

where φi is the inclination angle of acoustic path no. i, xiv , is the average axial flow velocity over the

length Li of the path, and ci is the average sound velocity (VOS) over the length Li. i,reflN is the

number of reflections in path no. i. For USMs with non-reflecting paths ( i,reflN = 0), Li is the

interrogation length of path no. i (cf. Fig. 2a). For USM with reflecting paths ( i,reflN > 0), Li is the

portion of the distance from the transmitting transducer front to the first reflection point which is lying inside a cylinder formed by the meter body’s inner diameter, cf. Fig. 2b. (This length is

)1N(1 i,refl + of the the interrogation length of path no. i.) From Eqs. (6), ci can be eliminated, giving

( )

ii2i1

i2i1ii,reflx,i costt2

ttL)1N(v

φ−+

= . (7)

Alternatively, a more sophisticated and accurate ray tracing approach can be taken, as reported by McCartney et al. [15], leading to (when including the factor )1N( i,refl + for reflecting-path USMs)

ix,ii22

x,i2i

ii,refli2

ix,ii22

x,i2i

ii,refli1

cosvsinvc

L)1N(t,

cosvsinvc

L)1N(t

φφφφ +−

+=

−−

+= , (8)

as an extension to Eq. (6). Eqs. (8) are claimed by McCartney et al. to be valid also for non-uniform axial flow velocity profiles. However, an underlying assumption in their analysis is that the rays are straight lines. This is possible for the uniform axial flow profile only, and Eqs. (8) are therefore derived only for uniform axial and no transversal flow [14,12]. It is interesting to note that Eqs. (8) lead to exactly the same expression, given by Eq. (7), for the average flow velocity over the acoustic path, xiv , , as the simplified geometrical approach described

above (Eq. (6)) and illustrated in Fig. 2.

6

Eqs. (8) also lead to the well-known expression for the sound velocity, e.g. [12,14],

( ) ( )

ii2i1

i22

i2i1i22

i2i1ii,refli costt2

sinttcosttL)1N(c

φφφ −+++

= , (9)

which is “exact” (within the ray approximation) for uniform axial flow and no transversal flow. For transversal flow as well as for other axial profiles it represents an approximation (cf. Section 6).

L

φ

vi,xi

i

Flowx

z

y

z

yi

Ly x

z

zL

Lvi,xi

i

i

Flow

Fig. 2. Schematic illustration of the “traditional approach” for path no. i in the USM, accounting for uniform axial flow

and no transversal flow. (a) Non-reflecting path ( i,reflN = 0); (b) Reflecting path (example with i,reflN = 2).

2.2 “Extended traditional approach”, accounting for uniform transversal flow By a simple analysis, it is possible to extend the above analysis one step towards more realistic conditions, by including effects of uniform transversal flow. In a real flow metering situation, there will be transversal flow velocity components in addition to the axial flow velocity component. Such transversal flow velocity components influence on the transit times, and on the measured axial flow and VOS. In the simplest approximation, the axial and transversal flow profiles are both considered to be uniform. A simple, geometrical approach can again be taken, giving the following upstream and downstream transit times (see Fig. 3) [8]:

iT,iix,ii

ii,refli2

iT,iix,ii

ii,refli1 sinvcosvc

L)1N(t;

sinvcosvcL)1N(

tφφφφ ++

+=

−−+

= , (10)

where T,iv is the average transversal flow velocity component along the chord in question, i.e. in the

plane spanned by the path direction and the x-axis. For non-reflecting path USMs with parallel chords, this is the x-z plane, so that T,iv = z,iv , cf. Fig. 3a. For USMs with reflecting paths, this plane

changes along the path, cf. Fig. 3b. In both cases Eqs. (10) represent an extension to Eqs. (6) by accounting for uniform transversal flow through the term iT,i sinv φ . Note that in this traditional

USM theory, the small transversal-flow normal component to T,iv is neglected (i.e. y,iv for non-

reflecting path USMs). From Eqs. (10), ci can be eliminated, giving [8]

(a) (b)

7

( )

ii2i1

i2i1ii,reflT,iix,i costt2

ttL)1N(vtanv

φφ

−+=+ , (11)

as an extension and improvement relative to Eq. (7). In current fiscal flow meters, Eqs. (7) or (11) (for flow velocity) and Eq. (9) (for sound velocity) are expressions in use to obtain the average axial flow velocity and VOS at acoustic path no. i.

L

φ

v

v

i,x

i,T

i

i

Flowx

z

y

z

yi

x

z

L

L

Lvi,xi

i

i

Flowvi,T

y

z

Fig. 3. Illustration of the “extended traditional approach” for path no. i in the USM, accounting for uniform axial and

uniform transversal flow. (a) Non-reflecting path ( i,reflN = 0); (b) Reflecting path (example with i,reflN = 2).

2.3 Associating paths with chords, and path configuration In Eq. (4), the average axial flow velocity over chord no. j, c

xjv , , is needed, whereas in Eqs. (7) and

(11) the average axial flow velocity over the length Li of the inclined path no. i, xiv , , is involved. It is

usual to assume that these two quantities are approximately equal,

xic

xj vv ,, ≈ , (12)

for corresponding chords and acoustic paths. Hence, in this approximation it is assumed that the axial flow velocity profile is constant over the length of the USM. It is also usual to write Eq. (4) as

∑∑==

≈≈N

iii

N

j

cxj

cjv vwRvwRq

C

1

2

1,

2 ππ , (13)

where ( )

ii2i1

i2i1ii,refli costt2

ttL)1N(v

φ−+

= (14)

is the average axial flow velocity which is measured by the USM at path no. i, and iw is the

integration weight of the path. However, from Eq. (11) it appears that Eq. (14) does not in general yield the measurand x,iv . Two approaches are in use today to compensate for the error in iv which is

caused by e.g. transversal flow: (a) The geometrical path configuration (including φi, wi and Nrefl,i, i = 1, …, N) is chosen to reduce

the influence of the types of transversal flow of main interest in ultrasonic flow metering, on the integration method of the USM.

(a) (b)

8

(b) Approach (a), in combination with active use of Eq. (11) and an estimate of the average transversal flow at path no. i, T,iv , for paths without transversal flow cancellation by

configuration. In the case where there is one acoustic path per chord, so that N = Nc, the path weights wi are equal to the chord weights wj

c. In the case where there are 2 acoustic paths per chord (for all or some of the chords), the relation between the weights wi, i = 1, ..., N and wj

c, j = 1, ..., Nc will be more complex. It should also be noted that for non-reflecting paths, it is only when there are 2 acoustic paths per chord for every chord, i.e. N = 2Nc, that the transversal flow velocity component T,iv in Eq. (11) will

be cancelled for any transversal flow profile. For a smaller number of acoustic paths, only certain transversal flow velocity profiles will in general be cancelled. 3. RAY THEORY MODEL FOR SOUND PROPAGATION IN NON-UNIFORM PIPE FLOW The traditional expressions on which today’s USMs are based, given by Eqs. (7) or (11) (for flow velocity) and Eq. (9) (for VOS), are based on assumptions of uniform axial and uniform (or no) transversal flow velocity profiles, as explained above. In real flow, neither the axial nor the transversal flow profiles are uniform, and the traditional expressions represent approximations. To account for sound refraction caused by the non-uniform profiles at finite Re numbers and disturbed flow conditions, an improved ray theory model relative to McCartney et al.’s approach has been developed. In this theory, the influence of non-uniform as well as asymmetrical axial and transversal flow on the transit times can be investigated. The model is a further development of earlier work by the authors, cf. [14,16]. The model used here is based on the ray-tracing equations for a moving medium as formulated by Pierce [17] (which are equivalent to those given by Lighthill [18]):

cc

sv1vsvsdt

sd ∇⋅−−×∇×−∇⋅−= , sv1

scvdt

xd 2

⋅−+= , (15)

where s is the wave slowness vector, t is the time, x(t) describes the ray trajectory, and v(x) = (vx(x,y,z),vy(x,y,z),vz(x,y,z)) is the flow velocity vector. For simplicity in notation, the subscript “i” for path no. i is omitted here. In addition to the ray approximation, which in the present work is basically a high-frequency approximation where the beam is described as an infinitely thin ray, and diffraction effects are neglected (cf. Fig. 4), the following assumptions are made: (a) Constant velocity of sound, c, (b) 2-dimensional flow: vy = 0, and (c) vx and vz are independent of x and y: vx = vx(z), vz = vz(z).

None of these three assumptions represent severe limitations, cf. Section 6. Assumption (c) means that the flow profile is taken to be constant over the length of the USM.

Under these assumptions, Eqs. (15) reduce to the set of four coupled differential equations

2R

Flow

Ray path

Rx

Tx

z

x

Fig. 4. Principle sketch of the ray path from the transmitting transducer(Tx) to the receiving transducer (Rx), for downstreampropagation in acoustic path no. i.

9

0dt

dsx = , zvs

zvs

dtds z

zx

xz

∂∂

−∂∂

−= , (16a)

zzxx

xx szvszv

sczvdtdx

)()(1)(

2

−−+= ,

zzxx

zz szvszv

sczvdtdz

)()(1)(

2

−−+= . (16b)

In order to integrate Eqs. (16), initial conditions are specified at t = 0. For downstream propagation, these initial conditions are, for x = 0 and z = -R,

ϕϕϕ

sin)(cos)(

cos

RvRvcs

zxx −+−+

= , ϕϕ

ϕsin)(cos)(

sin

RvRvcs

zxz −+−+

= . (17)

For upstream sound propagation, modified but similar initial conditions are used (expressions not given here). From the set of differential equations given by Eqs. (16), with initial conditions given by Eqs. (17), the ray paths and transit times have been calculated numerically using a fourth order Runge-Kutta method. 3-dimensional numerical CFD calculations of vx, vy and vz (axial and transversal flow profiles, respectively) have been used as input to Eqs. (16), in combination with cubic spline interpolation between the CFD mesh points, cf. Section 4. An iteration procedure to determine the initial ray angle ϕ based on Newton's method has been used to ensure that the ray ends at the specified receiver point. A non-uniform time step along the path is used, with 3 regions, and a total of typically 30000 time steps per path. The time steps are typically 10-9 s close to the wall, and increase into the pipe. Note that the present approach gives the ray paths and transit times, t1i and t2i, but not ray amplitudes. 4. CFD FLOW PROFILE CALCULATIONS 3-dimensional flow velocity profiles have been calculated using the CFD-code MUSIC [19], for various USM installation conditions (pipe bends). The profiles are used in Section 5 as input to the numerical ray model described in Section 3. The following installation conditions have been used here:

• USM installed in long straight pipe, for various Reynolds numbers, see Fig. 5, • USM installed 10D downstream a single 90° bend, see Fig. 6a, • USM installed 10D downstream a double 90° bend out of plane, see Fig. 6b.

4.1 Straight pipe, Reynolds number variation

Fig. 5 shows 3-dimensional (symmetrical) axial flow profiles for a straight pipe with smooth wall, calculated for a series of Reynolds numbers in the range Re = 200-2.3⋅108 using the CFD model. For oil and gas, the relevant Reynolds number ranges are about Re = 102-106 and 5⋅105-108, respectively. In ideal straight pipe flow, the transversal flow vanishes, and the axial flow velocity profile is symmetrical. The well-known dependency of the profile flatness on the Reynolds number, which is demonstrated in the figure, means that

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1

Normalized radial distance

No

rmal

ized

axi

al f

low

vel

oci

ty

Re = 200

Re = 5.103

Re = 105

Re = 106

Re = 107

Re = 2.3.108

Fig. 5. Axial flow velocity profiles for a straight pipe, calculated for different Reynolds numbers using CFD.

10

a variety of different flow profiles have to be taken into account in the discussion of sound refraction effects on transit times, flow velocity and VOS, even for the "simple" case of a straight pipe. The CFD calculations of axial profiles have been compared with experimental profiles for fully developed flow, including (for the range Re = 7⋅103-107) published results from Princeton (Superpipe), Erlangen, Melbourne, Delft facilities and others, with reasonable agreement [19], similar to such comparisons published elsewhere. 4.2 Pipe with bends (installation effects) Fig. 6 shows 3-dimensional axial and transversal flow velocity profiles 10D downstream a single 90° bend and a double 90° bend out of plane, calculated using the CFD model. In these calculations the bend inlet-flow conditions were taken to be a power law axial profile with Re = 105 and no transversal flow. The axial profiles are typically asymmetrical downstream such bend configurations. The transversal profiles are typically of cross flow and swirl type for the single and double bend configurations, respectively. The CFD calculations of axial and transversal profiles have been compared with published experimental and CFD calculated profiles [19]. The largest transversal flow components are more than 10 % of the axial component (both averaged over the path).

Axial flow(asymmetric)

Transversalcross flow

Axial flow(asymmetric)

Transversalswirl

Fig. 6. 3-dimensional flow velocity profiles (axial and transversal) calculated 10D downstream a bend using CFD.

(a) Single 90o bend, (b) Double 90o bend out-of-plane. 5. RAY THEORY RESULTS IN NON-UNIFORM AND DISTURBED FLOW In the following, the traditional USM expressions, Eqs. (9) and (11), are tested for transit times calculated by ray theory, for more realistic axial and transversal flow than the uniform profiles for which they are derived. Using the CFD-calculated axial and transversal flow profiles for straight pipes (Fig. 5) and pipes with bends (Fig. 6) as input, numerical simulations of transit times have been made using the ray theory model for sound propagation described in Section 3. The following parameters have been used in the simulations: D = 0.3 m (≈ 12"), ci = 400 m/s and φi = 45°. The procedure used is as follows: Firstly, the reference values of x,iv and T,iv over path no. i are

calculated by numerical integration of the CFD calculated profiles. Path transit times i1t and i2t are

then calculated using the ray propagation model of Section 3. These transit times are inserted into Eq. (7) to obtain an estimate of x,iv , denoted ray

x,iv . With respect to the average axial flow velocity at

the path, two deviations are then calculated and plotted: between rayx,iv and x,iv (cf. Eq. (7)), and

(a) (b)

11

between )vtanv( T,iirayx,i φ− and x,iv (cf. Eq. (11)). With respect to VOS, i1t and i2t are inserted into

Eq. (9) to obtain an estimate of ic , denoted rayic . The deviation between ray

ic and ic is then

calculated and plotted. 5.1 Straight pipe: Symmetrical axial flow, effects of Reynolds number variation In the case of a uniform axial flow profile, and no transversal flow (as is an underlying assumption behind Eqs. (7) and (9)), the ray path between the transmitter and the receiver will be the straight line. Non-uniformity in the axial flow profile will cause the ray path to deviate from this straight line. In Fig. 7, the ray paths are shown for a flow velocity of 50 m/s, for a laminar (parabolic) axial flow profile (Re = 200, (a)) and a turbulent flow profile (Re = 5000, (b)). The two profiles are shown in Fig. 5. In the case of the laminar flow profile, the deviation of the ray path from the straight line is larger than for the turbulent flow profile. This is because the turbulent flow profile is closer to a uniform flow profile (which gives a straight line) than the laminar profile.

FLOW DIRECTION

Ax

ial

flo

w p

rofi

le

Upstream acoustic path

Downstream acoustic path

Traditional solution

FLOW DIRECTION

Axi

al f

low

pro

file

Upstream acoustic path

Downstream acoustic path

Traditional solution

Fig. 7. Calculated acoustic ray paths for upstream and downstream propagation, for two types of axial flow profiles in

an ideal straight pipe (no transversal flow), calculated using CFD. Here, φ = 45°, c = 400 m/s, D = 30 cm, and vx = 50 m/s. (a) Laminar (parabolic) axial flow profile (Re = 200), (b) Turbulent axial flow profile (Re = 5000).

The deviation of the ray path from a straight line (caused by sound refraction) will also influence on the upstream and downstream transit times of the path. This will again affect the flow velocity and VOS measured over the acoustic path, as shown in Fig. 8. The figure shows the deviation using Eq. (7) (or equivalently, Eq. (11)) (left part) and Eq. (9) (right part), for a centre path in a USM, when the transit times are calculated by ray theory using the non-uniform axial flow velocity profiles as input. The deviations are shown for the six Reynolds numbers in the range 200-2.3⋅108 given in Fig. 5 as well as 8.8⋅103, and flow velocities up to 50 m/s. However, it should be noted that not all combinations of Reynolds numbers and flow velocity shown in Fig. 8 are possible to obtain in practice in ultrasonic flow metering, but shown here for completeness. Today, multipath USMs for gas typically operate up to velocities in the range 30-40 m/s. This upper limit is continuously being pushed upwards, driven by market needs. Ultrasonic flare gas meters may operate at velocities approaching 150 m/s, tentatively. For the refraction effect on the measured axial flow velocity, Fig. 8 shows that the turbulent flow velocity profiles studied here give a systematic deviation which is significant only for the (relatively rare) combination of high flow velocities and low Reynolds numbers. For example, 0.1 % deviation is found for x,iv = 40 m/s and Re = 5000. The parabolic profile corresponding to laminar flow gives

significantly larger deviation to the uniform flow profile solution. However, the parabolic flow velocity profile is of most relevance for liquid flow metering of very low Reynolds numbers (less

(a) (b)

12

Average axial flow velocity for centre path

-0.6

-0.5

-0.4

-0.3

-0.2

-0.1

0

0 5 10 15 20 25 30 35 40 45 50

Flow velocity (m/s)

Dev

iati

on

fro

m u

nif

orm

flo

w m

od

el

(%)

Turbulent flow profiles

Laminar flow profile (Re = 200)

Re = 5000105

106

107

2.3.108

Average sound velocity for centre path

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0 5 10 15 20 25 30 35 40 45 50

Flow velocity (m/s)

De

via

tio

n f

rom

un

ifo

rm f

low

mo

de

l (

m/s

)

Turbulent flow profiles

Laminar flow profile (Re = 200)

Re = 5000105

106107

2.3.108

Average axial flow velocity for centre path

-0.6

-0.5

-0.4

-0.3

-0.2

-0.1

0

1.E+02 1.E+03 1.E+04 1.E+05 1.E+06 1.E+07 1.E+08 1.E+09

Reynolds number

Dev

iati

on

fro

m u

nif

orm

flo

w m

od

el (

%)

50 m/s

40 m/s

30 m/s20 m/s

10 m/s

Turbulent flow

Average sound velocity for centre path

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

1.E+02 1.E+03 1.E+04 1.E+05 1.E+06 1.E+07 1.E+08 1.E+09

Reynolds number

De

via

tio

n f

rom

un

ifo

rm f

low

mo

de

l (m

/s)

Turbulent flow

50 m/s

40 m/s30 m/s

20 m/s10 m/s

Fig. 8. The effect of non-uniform axial flow on the estimate of (left): the average axial flow velocity (deviation using Eq. (7) (or Eq. (11)), and (right): VOS (deviation using Eq. (9)), for a centre path, and for no transversal flow (ideal straight pipe flow). The upper and lower figures give the deviations plotted versus the average axial flow velocity and the Reynolds number, respectively.

than 103), for which high velocities are not so relevant unless for very high fluid viscosity and small pipe diameters. For the refraction effect on the estimated VOS, Fig. 8 shows that the turbulent flow velocity profiles studied here give a systematic VOS deviation which is significant only for the (relatively rare) combination of very high flow velocities and low Reynolds numbers. For example, 0.05 m/s deviation is found for x,iv = 40 m/s and Re = 5000. The parabolic profile gives significantly larger

deviation to the uniform flow profile solution. However, as discussed above, high flow velocities may not be so relevant for the low Reynolds numbers in question for laminar flow. From these straight pipe results, two parameters have been identified which, - for turbulent profiles, may be used as a quick and approximate evaluation of the importance of sound refraction due to symmetrical axial profiles on the measured flow velocity and VOS in a path, respectively:

( )2000Re

iv ln

M30P ≡ , ( )100Rei

c lnM

90P ≡ , (18)

where ix,ii cvM = is the Mach number at path no. i. Pv and Pc can only be applied for Re > 5000

(turbulent flow). The deviation in flow velocity ( x,iv ) from Eq. (7) (or Eq. (11)) is less than 0.01 %

(a)

(c)

(b)(d)

13

when Pv < 1. Similarly, the deviation in VOS ( ic ) from Eq. (9) is found to be less than 0.0025 %

when Pc < 1. 5.2 Single 90o bend - Effects of asymmetrical axial and transversal flow Fig. 9 shows the deviation from the reference values ( z,iv and ic ) by using Eqs. (7) and (11) (for

flow velocity) and Eq. (9) (for VOS), for various lateral chord positions (y/R) and two meter orientations, when the transit times are calculated by ray theory using the CFD calculated profiles shown in Fig. 6a as input to the ray model. 0o orientation is here taken to be normal to the inlet pipe of the last bend.

Flow velocity - 10D downstream single bend out of plane (0° orientation)

-15

-10

-5

0

5

10

15

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1

Lateral chord position

De

via

tio

n u

sin

g E

q.(

7)

(%

)

10, 20, 30, 40 and 50 m/s


-15

-10

-5

0

5

10

15

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1


De

via

tio

n u

sin

g E

q.(

7)

(%

)

10, 20, 30, 40 and 50 m/s


-0.1

-0.08

-0.06

-0.04

-0.02

0

0.02

0.04

0.06

0.08

0.1

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1


De

via

tio

n u

sin

g E

q.(

11

) (

%)

10 m/s

20 m/s

30 m/s

40 m/s

50 m/s


-0.1

-0.08

-0.06

-0.04

-0.02

0

0.02

0.04

0.06

0.08

0.1

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1


De

via

tio

n u

sin

g E

q.(

11

) (

%) 10 m/s

20

30 m/s

40

50 m/s

10D downstream single bend out of plane (0° orientation)

-1

-0.8

-0.6

-0.4

-0.2

0

0.2

0.4

0.6

0.8

1

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1


De

v. i

n v

elo

cit

y o

f s

ou

nd

(m

/s)

10, 20, 30, 40 and 50 m/s

10D downstream single bend out of plane (90° orientation)

-1

-0.8

-0.6

-0.4

-0.2

0

0.2

0.4

0.6

0.8

1

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1


De

v. i

n v

elo

cit

y o

f s

ou

nd

(m

/s)

10 m/s

20 m/s

30 m/s

40 m/s

50 m/s

Fig. 9. The effect of asymmetrical axial and transversal flow on the estimate of the average axial flow velocity and VOS, 10D downstream a single 90o bend, for various lateral chord positions (y/R). Left: 0o orientation of the USM rel. bend; right: 90o orientation.

(a) (d)

(b)

(c)

(e)

(f)

14

Several observations are made. Firstly, consider the ”measured” average axial flow velocity. A significant effect is found by using Eq. (7), cf. Fig. 9d (90o orientation of USM rel. to bend). It can be shown that this effect is caused by the transversal flow, and not the asymmetry of the axial flow profile. Fig. 9e shows that by subtracting an assumed uniform-flow transversal flow component (through the geometrical path configuration, or in software, using Eq. (11)), the remaining effect of sound refraction is comparable to the one at straight pipe, for the flow velocities of interest in fiscal metering. For the ”measured” VOS, significant effects are found above 20-30 m/s. These are important both for calculation of density from the measured VOS, and for meter testing by comparison of VOS at different paths. With respect to meter orientation, the refraction effect due to transversal flow is averaged out over the path at 0o orientation (Fig.9, left part). However, as illustrated and commented above, this is not the case for 90o orientation (Fig.9, right part). 5.3 Double 90o bend out-of-plane - Effects of asymmetrical axial and transversal flow Fig. 10 shows the deviation from the reference values ( z,iv and ic ) by using Eqs. (7) and (11) (for

flow velocity) and Eq. (9) (for VOS), for various lateral chord positions (y/R) and two meter orientations, when the transit times are calculated by ray theory using the CFD calculated profiles shown in Fig. 6b as input to the ray model. Again, a significant effect is found for the ”measured” average axial flow velocity by using Eq. (7), cf. Figs. 10a and 10d. It can also here be shown that this effect is caused by the transversal flow, and not the asymmetry of the axial flow profile. Figs. 10b and 10e show that by subtracting an assumed uniform-flow transversal flow component (through configuration or in software, using Eq. (11)), the remaining effect of sound refraction is comparable to the one at straight pipe, for the flow velocities of interest in fiscal metering. For the ”measured” VOS, the effects are even stronger than for the single-bend results shown in Fig. 9, cf. Figs. 10c and 10f. It can be shown that this is caused by the larger transversal flow components, and not the asymmetry of the axial flow profile. With respect to meter orientation, transversal flow effects are similar for 0o and 90o orientation, since the transversal flow is of swirl type. With respect to inclination angle, other results of the study (not included here) show that the refraction effects of transversal flow on the “measured” flow velocity increase significantly with angle, if compensation is not made in the USM (through the geometrical path configuration, or in software, using Eq. (11)). However, if such compensation is made the remaining refraction effects decrease by increasing angle. For the VOS, the error made by using Eq. (9) increases with increasing angle, so that for larger angles than 45o, these effects become dramatically more significant than in Figs. 9f, 10c and 10f. These results apply both to the single- and double-bend pipe configurations.

15

Flow velocity - 10D downstream double bend out of plane (0° orientation)

-15

-10

-5

0

5

10

15

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1


De

via

tio

n u

sin

g E

q.(

7)

(%

)

10, 20, 30, 40 and 50 m/s


-15

-10

-5

0

5

10

15

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1


De

via

tio

n u

sin

g E

q.(

7)

(%

)

10, 20, 30, 40 and 50 m/s


-0.1

-0.08

-0.06

-0.04

-0.02

0

0.02

0.04

0.06

0.08

0.1

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1


De

via

tio

n u

sin

g E

q.(

11

) (

%)

10 m/s

20 m/s

30 m/s

40 m/s

50 m/s


-0.1

-0.08

-0.06

-0.04

-0.02

0

0.02

0.04

0.06

0.08

0.1

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1


De

via

tio

n u

sin

g E

q.(

11

) (

%) 10 m/s

20 m/s

30 m/s

40 m/s

50 m/s

10D downstream double bend out of plane (0° orientation)

-1

-0.8

-0.6

-0.4

-0.2

0

0.2

0.4

0.6

0.8

1

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1


De

v. i

n v

elo

cit

y o

f s

ou

nd

(m

/s)

10 m/s

20 m/s

30 m/s

40 m/s

50 m/s

10D downstream double bend out of plane (90° orientation)

-1

-0.8

-0.6

-0.4

-0.2

0

0.2

0.4

0.6

0.8

1

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1


De

v. i

n v

elo

cit

y o

f s

ou

nd

(m

/s)

10 m/s

20

30 m/s

40

50 m/s

Fig. 10. The effect of asymmetrical axial and transversal flow on the estimate of the average axial flow velocity and VOS, 10D downstream a double 90o bend out-of-plane, for various lateral chord positions (y/R). Left: 0o orientation of the USM rel. bend; right: 90o orientation.

6. DISCUSSION AND CONCLUSIONS An improved theoretical description of sound propagation in moving media may form the basis for further development of USM technology, with reduced systematic errors (not eliminated by flow calibration) and extended application areas (e.g. calculation of gas density and calorific value from the measured sound velocity, VOS). In the present work a simplified ray theory sound propagation model has been developed and used to address the accuracy of the traditional expressions which are used in present-day USMs for

(a)

(b)

(c)

(d)

(e)

(f)

16

measurement of the average flow velocity and VOS. The ray tracing method has in addition the potential of improving these methods in current use. Improved expressions are derived which can be employed in the USM methodology (not presented here). Influences of sound refraction on the axial flow velocity ( x,iv ) and VOS have been investigated for

flow profiles related to smooth straight pipes (for Reynolds numbers in the range 200-2.3⋅108) and downstream single and double bends, all calculated using a CFD model. For the axial flow velocity at a single path ( x,iv ), the effects of Reynolds number variation in an ideal

straight pipe with symmetrical axial and no transversal flow has been found to be relatively small (e.g. less than 0.1 % for Mach numbers Mi < 0.1 and Re > 5000), except for the (relatively rare) combination of very low Reynolds numbers and moderate-to-high Mach numbers. Moreover, for pipes with bends the effects of asymmetrical axial flow are found to be small. Effects of non-uniform transversal flow are small, provided compensation for uniform transversal flow is made in the USM (either by configuration or software). Consequently, the results of the study indicates that Eq. (11), which has been derived for the simplified case of uniform axial and transversal flow, should be sufficiently accurate for measurement of the axial flow velocity along path no. i, for a wide range of symmetrical and asymmetrical axial and transversal flow profiles, at low and moderate flow velocities. For VOS, the effects of Reynolds number variation in an ideal straight pipe with symmetrical axial and no transversal flow have been found to be relatively small (e.g. less than 0.05 m/s for Mach numbers Mi < 0.1 and Re > 5000), except for the (relatively rare) combination of very low Reynolds numbers and high Mach numbers. Moreover, for pipes with bends the effects of asymmetrical axial flow is also found to be small, except for “high” flow velocities. In (hypothetical) applications with no transversal flow, thus, the “traditional approach” for VOS, derived for the simplified case of uniform axial and no transversal flow and given by Eq. (9), appears to be sufficiently accurate, for a wide range of axial flow profiles. However, refraction effects due to transversal flow on VOS are shown to be highly significant also at moderate flow velocities. If the average transversal flow velocity at path no. i changes from flow calibration to field operation (which may often be the case), this may be an important effect in applications where VOS measured by the USM is used. Methods to correct for such effects are not available in current USMs. The present work indicates that as no significant effect of non-uniformity of transversal profiles has been found, transversal flow profiles can be treated as being uniform. For this case, an improved VOS expression (relative to Eq. (9)) has been derived (not presented here), enabling correction for transversal-flow effects on VOS provided an estimate of the average transversal flow velocity over the path is available (which is the situation for some USMs [8]). One common application is the use of VOS for quality control of the USM. If the average transversal flow velocity changes from path to path (which may be the typical situation), the measured VOS will be different from path to path due to measurement error caused by transversal flow, unless the transversal flow effects on the transit times are corrected for. This may cause problems in the quality control of the USM, and may be misinterpreted e.g. to be caused by temperature gradient effects in the gas. VOS errors at individual paths will propagate into the average VOS calculated for the USM, with consequences for other applications, such as the use of VOS as input to VOS correction of vibrating

17

element densitometers. In more recent applications where the VOS is used to calculate the gas density and calorific value, a correction of the VOS for sound refraction effects due to transversal flow profile effects may be needed when high accuracy in these quantities is required. Two parameters (Pv and Pc) have been defined which, - for turbulent flow profiles in straight pipes, may be used to approximately evaluate the importance of the effect of symmetrical axial profiles on the measured flow velocity and VOS, cf. Eq. (18). The above results indicate that these parameters may also be used for asymmetrical axial flow profiles (e.g. for in pipes with bends), - and for the flow velocity also in case of transversal flow. The flow profile effects on transit times are demonstrated here for USM with non-reflecting paths ( i,reflN = 0 for all i). For USMs employing reflecting paths ( i,reflN > 0), it can be shown that the

transit time effects will be equal to those in a non-reflecting path USM, provided the axial profile is symmetrical, the transversal flow is a symmetrical swirl, and the flow profiles are constant over the length of the USM. However, such flow profiles are seldom met in practice. Consequently, for reflecting-path USMs, deviations from the above numerical calculations may be expected for realistic flow profiles. Whether these deviations will be higher or lower than in Figs. 8-10 has not been addressed in the investigation reported here. However, evaluation of the detailed influences on USMs with reflecting paths can be made for arbitrary axial and transversal flow profiles (analytical, CFD calculated or experimental) using the ray theory simulation program developed here. The present results are based on a 2-dimensional ray theory description of sound propagation (cf. Section 3). Preliminary investigations by the authors on extending the ray propagation model to a 3-dimensional description indicate that such an extension may not bring significantly new results into the discussion, so that within the limitations of the ray approach, the above results may be expected to be representative. More important may be the fact that ray theory description of sound propagation itself is restricted, due to the high-frequency approximation inherent in that methodology (cf. Section 3). Since ray propagation models are not able to account for finite-beam and diffraction effects, they represent a simplified treatment of the problem. To fully evaluate the systematic transit time effects discussed here, and other systematic effects (cf. Table 1 and e.g. [12,10]), a more comprehensive analysis based on wave theory will be needed, accounting for acoustic diffraction effects, finite beam interaction with the flow, transducer time delay, pressure and temperature effects on transducers, etc. On the other hand, the relatively simpler approach used here is still considered to represent an improvement relative to current USM methodology, and is motivated by the insight and improved analytical expressions which are obtained using this approach. ACKNOWLEDGEMENTS The CFD flow velocity profiles used as one input to the study were calculated using the MUSIC code developed by senior scientist Anders Hallanger, CMR. The work has been partially supported by the Research Council of Norway.

18

REFERENCES [1] “The Daniel SeniorSonic gas flow meter”, Brochure, Daniel Flow Products, USA (2000). [2] “MPU 1200 ultrasonic gas flow meter”, Brochure, Kongsberg Offshore AS, Norway (2000). [3] “Ultrasonic gas flow meters”, Brochure, Instromet International N.V., Belgium (2000). [4] “Regulations relating to fiscal measurement of oil and gas etc.”, Norwegian Petroleum

Directorate, Stavanger, Norway (January 20, 1997). [5] "Measurement of gas by multipath ultrasonic meters". Transmission Measurement Committee,

Report no. 9, American Gas Association (A.G.A.) (June 1998). [6] Boer, A. H.: “Testresults Krohne 8” ultrasonic flowmeter”, Proc. of the North Sea Flow

Measurement Workshop 1997, Kristiansand, Norway, 27-30 October 1997. [7] Kinghorn, F.: “Flow measurement research - Does it have a future?”, Opening address, Proc.

of 4th Int. Symposium on Fluid Flow Measurement, Denver, Colorado, USA, June 27-30, 1999 [8] Lunde, P., Frøysa, K.-E., Fossdal, J. B. and Heistad, T.: “Functional enhancements within

ultrasonic gas flow measurement”, Proc. of the 17th North Sea Flow Measurement Workshop, Oslo, Norway, 25-28 October 1999.

[9] Zanker, K. and Brown, G.: “The performance of an ultrasonic meter in wet gas service”, Proc. of the 18th North Sea Flow Measurement Workshop, Scotland, 24-27 October 2000.

[10] Lunde, P., Frøysa, K.-E. and Vestrheim, M.: “Challenges for improved accuracy and traceability in ultrasonic fiscal flow metering”, Proc. of the 18th North Sea Flow Measurement Workshop, Gleneagles, Scotland, 24-27 October 2000.

[11] Lunde, P. and Frøysa, K.-E.: ”Handbook of uncertainty calculations - Ultrasonic fiscal gas metering stations”, Prepared by the Norwegian Society of Oil and Gas Measurement, the Norwegian Petroleum Directorate and Christian Michelsen Research AS, Norway. (In preparation, to be available from the Norwegian Society of Chartered Engineers, Oslo.)

[12] GERG project on ultrasonic gas flow meters, Phase II. GERG Technical Monograph TM 11 2000, edited by Lunde, P., Frøysa, K.-E. and Vestrheim, M.. Groupe Européen de Recherches Gazières (VDI Verlag, Düsseldorf, 2000).

[13] Frøysa, K.-E., Furset, H. and Baker, A.: ”Density and ultrasonic velocity calculations for natural gas”, CMR report CMR-98-F1002, Christian Michelsen Research, Bergen (1998) (Confidential).

[14] Lunde, P., Frøysa, K.-E. and Vestrheim, M.: ”GARUSO - Version 1.0. Uncertainty model for multipath ultrasonic transit time gas flow meters". CMR Report No. CMR-97-F10014, Christian Michelsen Research AS, Bergen (August 1997).

[15] McCartney, M. L. Mudd, C. P. and Livengood, R. D.: "A corrected ray theory for acoustic velocimetry". J. Acoust. Soc. Am. 65, 50-55 (1979).

[16] Frøysa, K.-E. and Lunde, P.: ”A ray theory approach to investigate the influence of flow velocity profiles on transit times in ultrasonic flow meters for gas and liquid”, Proc. of 24th Scandinavian Symposium on Physical Acoustics, Ustaoset, Norway, January 28-31, 2001.

[17] Pierce, A.D.: Acoustics. An Introduction to Its Physical Principles and Applications (McGraw-Hill, New York, 1981).

[18] Lighthill, J.: Waves in Fluids (Cambridge University Press, 1978). [19] Hallanger, A., Frøysa, K.-E. and Lunde, P.: “CFD simulation and installation effects for

ultrasonic flow meters in pipes with bends”, In: Proc. of MekIT’01, First National Conference on Computational Mechanics, Trondheim 3-4 May 2001 (Tapir Akademisk Forlag, Trondheim, Norway), pp. 147-167. Extended version accepted for publication in International Journal of Applied Mechanics and Engineering (IJAME), 7(1), 2002.

USING COMPUTATIONAL FLUID DYNAMICS TO INVESTIGATE THE FLOW THROUGH AN OFFSHORE GAS METERING STATION Authors: Paul Wilcox (SGS Redwood), Neil Barton (NEL), Kenneth Laing (BP) Summary The gas metering station on BP Bruce platform consists of four 16” orifice meter runs, with gas flowing through any 3 meters at one time. The system was originally designed to comply with ISO 51671, but an auditor expressed concern with the physical upstream layout of the pipework leading up to the inlet header to the metering system. He pointed out that there were a number of twists and turns in the upstream header that could have produced swirl and flow asymmetry at the plane of the orifice plate in the metering runs. NEL was commissioned to run a series of computational fluid dynamics calculations to investigate the flow though the piping configurations. The results demonstrated, as would be expected, that the error in any one meter will depend on which streams are on line. The estimated total system error compared with a system complying entirely with ISO 5167 related to the different streams on line is given below: Streams online Total system error 1-2-3 +0.4% 1-3-4 +0.7% 1-2-4 +0.4% 2-3-4 +0.3% As can be seen, the flow measurement error is consistent positive and small in magnitude.

1 INTRODUCTION It is a known fact that asymmetric flow and swirl onto an orifice plate causes deviations from the flow predicted using ISO 5167. Although Bruce platform was originally designed to comply with ISO 5167, metering installations are usually designed taking no account of the real pipework configurations upstream of the metering installation. An auditor commented on the Bruce upstream pipework and suggested that its affect on the metering results be investigated. The National Engineering Laboratory was requested to perform a Computational Fluids Dynamics study to model the flow through the Bruce metering installation. The aim of the study was to estimate the error, if any, caused by the upstream pipework on the flow rate indicated by the installation’s orifice plate meters. A sketch of the flow metering installation is shown in Figure 1.

Figure 1. The Bruce Flow Metering Installation

Flow enters the pipework from three compressors at the inlets shown. The flow then passes through two 45o bends between points 1 and 2 into a straight vertical section. Between points 3 and 4 are a 90o elbow then an out-of-plane combination of 45o and 90o elbows. A second straight section follows leading to a 45o elbow in the horizontal (x-z) plane closely followed by a 90o elbow in the vertical plane and a second 90o elbow. There is then a third straight section between points 6 and 7 leading to a 90o elbow (in the horizontal plane) and a four-stream header. The header itself is 18” nominal bore, with each stream being 16” nominal bore. Each stream has an orifice plate ( = 0.6 and flange tappings) 31D downstream of the header. Three metering tubes are on-line at any one time, the fourth being shut off by a fully bore valve just downstream of the header. 2 FLOW MODELLING METHOD 2.1 Simulation Method & Parameters The flow of gas through the installation was modelled using Fluent 5.4 Computational Fluid Dynamics (CFD) software2. The pipework was modelled in sections as shown in Figure 1; the inlet conditions for each section being derived from the predicted outlet conditions of the previous (upstream) section. An unstructured hexahedral mesh was used for each section. A typical mesh used to simulate sections of the pipework is shown in Figure 2 and the mesh used to model the flowmeters is shown in Figure 3. The discretisation scheme used was the QUICK algorithm and turbulence effects were simulated using a Reynolds stress second order closure model.

Figure 2. A typical section of the computational mesh used to model the

pipework (between points 3 and 4 in figure 1)

Figure 3. The computational mesh used for modelling the orifice plate

flowmeters 2.2 Flow Parameters The operational conditions were specified as 135 barg and 35C. The flow rate through the installation was 17 million Sm3/day. The following flow parameters were set within the CFD simulations: Gas density = 140 kg/m3 Gas viscosity = 1.82 × 10-5 Pa s Gas flow rate = 1.196m3/s A uniform velocity profile was set at the inlets A, B and C (marked on figure 1) such that one third of the flow was supplied by each compressor. The turbulence intensity at the inlets was set to 10%. Simulations of the header used the flow splits shown in Table 1 to define the percentage flow through each stream. Operational experience from Bruce shows that these flow splits are quite repeatable and consistent.

Stream 1 Stream 2 Stream 3 Stream 4 39.4% - 30.8% 29.8%

- 39.2% 30.8% 30.0% 28.1% 38.2% 33.7% - 27.4% 37.2% - 35.4%

Table 3. Percentage flow through each stream with different combinations

of stream on-line

3 RESULTS OF THE SIMULATIONS 3.1 Predicted Flow Upstream of the Header Figure 4 shows the predicted flow behaviour at selected points upstream of the header. The arrangement of the separator outlets and the two subsequent 45o bends acted to generate and skewed velocity profile with a double vortex at point 2, similar to that seen downstream of a 90o elbow. By point 3 the swirl had decayed but some degree of skewness remained, as shown in figure 4.

Figure 4. Predicted Flow Behaviour Upstream of the Header The triple bend combination between points 3 and 4 caused a single vortex swirl that decayed to a magnitude of about 4o by point 5 (see figure 4). The triple bend combination downstream of point 5 caused further swirl that was sustained through the bend between points 7 and 8. The flow entering the header at point 8 was skewed towards the inside of the bend with single vortex swirl of a magnitude of about 14o. 3.2 Predicted Flow in the Header Two simulations were run of the header, the first with streams 1,3 and 4 on-line. The second with streams 1,2, and 3 on-line. Figure 5 shows the velocity vectors and

contours 1.5m downstream of the header with streams 1,3 and 4 on-line. On first inspection all of the streams show a similar behaviour, with the velocity profile skewed to one side and a double vortex swirl reminiscent of that seen downstream of a single bend. However, the swirl entering the header has distorted the swirl pattern in Stream 4, one vortex being marginally bigger than the other with the velocity profile twisted around about the pipe axis. Previous experience suggested that this indicated that single vortex swirl was likely to develop in Stream 4.

Figure 5. Predicted Flow Behaviour 1.5m Downstream of the Header with Streams 1, 3 and 4 on-line

Figure 6 shows vectors and contours downstream of the header with streams 1,2 and 3 on-line. The flow in stream 3 (figure 6) is very similar to that seen for stream 4 (figure 5). This implies similar behaviour will be seen in the upstream branch for other configurations. Stream 2 (figure 6) has similarities to streams 1 and 3 (figure 5), with a skewed axial velocity profile and weak double vortex swirl The flow pattern in stream 1 (figure 6) differs significantly from that in figure 10, with single vortex swirl (about 11o in magnitude) and a skewed axial velocity profile.

Figure 6. Predicted Flow Behaviour 1.5m Downstream of the Header with

Streams 1, 2 and 3 on-line 3.3 Predicted Flow in the Metering Streams The next step in the analysis was to model the flow from the header to the flowmeters and the flow through the meters themselves. The flow from the header to the flowmeters was modelled for three streams (designated Cases A, B and C). ISO 5167 states that the velocity profile entering an orifice plate flow meter should be within a +/-5% band of a fully developed profile and that the inlet flow swirl angle should be less than 2o. The predicted flow behaviour was compared against these criteria, as discussed below. Case A - Stream 3 with streams 1,3 and 4 on-line This stream was selected as the flow entering it shared common features with other streams, i.e. stream 1 (1,3 & 4 on-line, figure 10) and stream 2 (1,2 & 3 on-line, figure 6). The double vortex swirl entering stream 3 almost completely decayed by the time the flow reached the flowmeter. The velocity profile was slightly flattened but within the ISO 5167 +/-5% limit.

Case B - Stream 4 with streams 1,3 and 4 on-line This stream was selected because there were strong indications that further downstream of the header single vortex swirl was likely to develop. Single vortex swirl is known to persist for long distances and is detrimental to the accuracy of orifice plate flowmeters. This was indeed the case with swirl of about 4o being predicted at the flowmeter inlet. This exceeds the ISO 5167 limit of 2o. The velocity profile was also slightly distorted, but close to being fully developed and lay within the ISO 5167 limits. Case C - Stream 1 with streams 1,2 and 3 on-line This was also selected because single vortex swirling flow was predicted at the header. This swirl decayed to about 5o at the flowmeter inlet, again, this is in excess of the 2o limit. As in previous cases the axial velocity profile entering the flowmeter was close to being fully developed, just failing the ISO 5167 criteria for velocity profile. 3.4 Predicted Flow Metering Error Four simulations were run of flow through an orifice flowmeter: a baseline case with fully developed inlet conditions and three cases using the disturbed inlet conditions described in section 3.3. The difference between the baseline and disturbed flow cases was used to predict the installation error of individual flowmeters in the Bruce installation, as summarised in table 2.

Case Streams On-line

Flowmeter Predicted C

Shift in C

Measure-ment Error

Fully Developed

- 0.6249 - -

A 1-3-4 3 0.6187 -0.97% +0.97% B 1-3-4 4 0.6236 -0 .18% +0.18% C 1-2-3 1 0.6254 +0.11% -0.11%

Table 2. Predicted flow measurement error The predicted discharge coefficient for fully developed flow was 0.6249. This is 3.6% greater than the value given in ISO 5167 of 0.603. This confirms the findings of similar previous work3 that showed calculation errors of the order of 5% in the three-dimensional simulations of orifice plates. However, it has been shown that this calculation error is very similar in fully developed and disturbed cases, Thus, subtracting two predicted values of discharge coefficient (as in equations 2 or 3) effectively eliminates most of the calculation error associated with the CFD predictions.

4 DISCUSSION 4.1 Validity of the Predictions Case A The double vortex swirl and skewed velocity profile entering stream 3 (see figure 5) is very similar to that seen downstream of a single bend. A comparison of CFD predictions of an orifice plate downstream of a single bend with published test data (figure 7) suggests that the predicted error of +0.97% 31 diameters downstream of the header is likely to be a slight over-estimate.

-4.5

-4

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-3

-2.5

-2

-1.5

-1

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0

0.5

0 5 10 15 20 25 30 35 40 45

Distance (D)

Ref 4 (beta = 0.5)

Ref 5 (Beta = 0.5)

Ref 4 (Beta = 0.707)

CFD (beta = 0.54)

Figure 7. Comparison of Measured and Predicted Shifts in Discharge

Coefficient of an Orifice Plate Downstream of a Single Bend Cases B & C The single vortex flow pattern entering the flowmeters in Cases B and C is analogous to that seen downstream of twisted double bends. Examination of test data from orifice plates (such as that shown in figure 8) shows that flowmeters with a β ratio of about 0.6 at 31 diameters produce small measurement errors. This suggests that the estimated errors of +0.18% and –0.11% for Cases B and C are realistic.

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3

3.5

4

0 10 20 30 40 50 60

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Ref 5 (beta = 0.5)

Ref 6 (beta = 0.5)

Ref 7 (beta = 0.57)

Figure 8. Measured Shifts in Discharge Coefficient of an Orifice Plate

Downstream of a Twisted Double Bend 4.2 Estimation of Error in the Metering System The flow patterns generated at the header outlets depend on the combination of streams that are on-line, as can be seen when comparing figures 5 and 6. However, similarities can be seen between flow patterns generated by different combinations. For example, the flow pattern in Stream 4 shown in figure 5 is similar to that seen in Stream 3 in figure 6. As a first estimate, we could therefore say that the flowmeter on Stream 3, with streams 1, 2 and 3 on-line, is likely to be in error by about +0.18%. Using this general approach the metering error for the entire metering system was estimated, as summarised in Tables 3, 4 and 5. Initially streams that had not been modelled were equated to those that had been modelled (Table 3) and corresponding metering errors allocated to each stream (Table 4). These errors were then scaled to account for the flow splits given in Table 1 and a total system metering error calculated (Table 5).

Stream 1 Stream 2 Stream 3 Stream 4 c A B - A - a b C A - B - C A B

Table 3. Estimation of the flow conditions in different streams. Lower

case text shows values where conditions have been simulated using CFD, bold text shows estimated equivalents.

Stream 1 Stream 2 Stream 3 Stream 4 -0.11% +0.97% +0.18% - +0.97% - +0.97% +0.18% -0.11% +0.97% - +0.18%

- -0.11% +0.97% +0.18% Table 4. Estimation of the flow measurement errors in different streams.

Bold text shows estimated values.

Stream 1 Weighted

Stream 2 Weighted

Stream 3 Weighted

Stream 4 Weighted

Total Error

-0.031% +0.371% +0.061% - +0.400% +0.382% - +0.299% +0.054% +0.735% -0.030% +0.361% - +0.064% +0.394%

- -0.043% +0.299% +0.054% +0.310% Table 5. Estimation of the total flow measurement error of the metering

system based on values in table 4 weighted to account for the flow rate through each stream.

Table 5 suggests that the total error of the system is generally small in magnitude and depends on which streams are on-line. As most of the errors tend to be positive in sign, the meters with negative errors tend to act to cancel these errors out, reducing to the total error. 5 CONCLUSIONS The flow through Bruce flow metering installation has been simulated using CFD software. Predictions show that significant amounts of swirl and velocity profile distortion are generated by the pipe bends upstream of the header. Swirling flow enters the header. Two simulations of the header have been run. These show that the flow pattern in each outlet stream varies, depending on which combinations of streams are on-line. Consequently, the flow metering error in each of the orifice plate meters will vary depending on which streams are on-line. The flow through three of the flow meters has been modelled. Only one of these three cases (simulation A) the predicted inlet conditions complied with the requirements of ISO 5167 for velocity profile distortion and swirl. The predicted installation error for this meter was +0.97%. Comparison against published experimental data suggests that this prediction may be a slight over estimate. The two other flow meter simulations (B and C) failed the ISO 5167 criteria for suitable inlet flow conditions. In these two cases errors of +0.18% and –0.11% were predicted. Comparisons with experimental data suggest that these predictions are realistic.

Using the CFD error predictions a rough estimate of the installation error of the flow metering system has been calculated as being between +0.3% to +0.7% depending on which streams are on-line. Since these values lie within the ±1% uncertainty of a metering system built to ISO 5167, then no modifications will be performed on the present metering system. 6. REFERENCES 1 INTERNATIONAL ORGANISATION FOR STANDARDIZATION. 1991. ISO

5167-1. Measurement of fluid flow by means of orifice plates, nozzles and Venturi tubes inserted in circular cross-section conduits running full. International Organisation for Standardisation, Geneva.

2 Fluent 5 Users Guide, Fluent Europe Ltd, Sheffield Airport Business Park

Europa Link, Sheffield, S9 1XU, 1998. 3 BARTON N. A. & STEWART C. D., Use of CFD techniques to improve ISO

5167-1. National Engineering Laboratory Report No. 337/99, October 1999. 4 SPEARMAN E. P., SATTARY J. A., READER-HARRIS M. J., and RHODES

F. S. The effect of upstream installations on orifice meter discharge coefficients. Flow Measurement Memo FL/445, National Engineering Laboratory, July 1995.

5 IRVING S. J. Effect of system layout on the discharge coefficients of orifice

plates. Part 3: Experimental investigation into the effects of bend combinations. BHRA Report RR1462. Cranfield: BHRA, 1978.

6 MATTINGLY, G. E., and & YEH, T. T. Summary report of NIST's industry-

government consortium research program on flowmeter installation effects with emphasis on the research period February - December 1990:TEE, used as an elbow configuration. NISTIR 4753. Gaithersburg, USA: National Institute of Standards and Technology, 1992.

7 MOTTRAM, R. C., and SPENCER, E. A. Installation tests show orifice plate

coefficient deviations. Proc. of Flowmetering and Proving Techniques in the Offshore Oil Industry, Aberdeen 1983.

AN EXPERIMENTAL DERIVATION OF AN EXPANSIBILITY FACTOR FOR

THE V-CONE and WAFER-CONE METERS

Dr R J W Peters, McCrometer Inc Dr M R H Reader-Harris, NEL

Dr D G Stewart, NEL 1 INTRODUCTION The V-Cone meter is a differential pressure device that has been developed and tested since 1985 and is now well understood and accepted as a viable flow measurement device. It is widely used in many industrial applications to measure a variety of fluids over a wide range of temperatures and pressures. The choice of the V-Cone can be based on the relatively short upstream lengths required and the ease of operation over a wide turndown ratio relative to an orifice plate. Over the past 10 years the V-Cone has been increasingly accepted in the Gas Industry as a reliable metering device. Due to the fact that gas is a compressible fluid it is necessary to apply an expansibility correction factor, (or the Y factor in the USA), resulting in the well known mass flow equation:

pdCq dm

2

41

2

4 (1)

Kinghorn [1] in his 1986 paper on this subject stated, “The expansibility coefficient, , compensates for the fact that changes in the pressure of the gas as it flows through the meter result in changes in its density. For nozzles and Venturi meters this can be computed on the assumption that the flow is adiabatic since it is constrained by the walls of the meter. For orifice plates, however, the three-dimensional expansion which takes place requires an empirical determination of values of the expansibility coefficient”. The expansibility factor equations for Venturi meters/nozzles and orifice plates are given by ISO 5167-1:1991 as:

21

1

24

42

1

1

1

1

1

(venturi tubes) (2)

1

435.041.01pp

(orifice plates) (3)

There is currently a draft revision of ISO 5167 containing a revision of Eq. (3) by Reader-Harris [2]. The flow through the V-Cone was initially assumed to be adiabatic, similar to the Venturi meter. However, in 1994, Dahlstrom [3] presented the following empirical equation for the V-Cone expansibility factor based on only two V-Cone meters:

1

475.06.01pp

(4)

Consequently, it was decided that a more detailed examination to determine the expansibility factor for the V-Cone should be undertaken.

McCrometer asked NEL to perform a series of tests to determine the expansibility for a standard V-Cone meter and on an alternative design of the V-Cone meter, known as the Wafer-Cone. The principal difference is that, unlike the arrangement in the standard V-Cone, the wafer cone is not fixed into the meter, but is inserted as a separate section, enabling removal and replacement with a different beta value, as required, for changing flow conditions. Owing to the physical difference between the two designs, it was deemed necessary to determine whether or not the expansibility factor of the Wafer-Cone was the same as that of the standard V-Cone. NEL were chosen to carry out this work and to derive the applicable equation. This paper details the experimental process, the results obtained, and the final derived expansibility equation for the standard V-Cone (4) and for the Wafer-Cone. 2 OBJECTIVES The key objectives of these tests were as follows: 1. To determine the expansibility factor equation for the standard V-Cone meter. 2. To investigate any dependence of the expansibility factor on pipe diameter. 3. To investigate any dependence of the expansibility factor on Reynolds number. 4. To determine the expansibility factor for the Wafer-Cone meter. 3 EXPERIMENTAL METHOD To determine the expansibility factor it is necessary to carry out tests at constant Reynolds number (i.e. constant mass flowrate) whilst varying the static pressure and differential pressure at the meter. In order to achieve this constant flowrate a sonic nozzle was used as the reference meter upstream of the V-Cone. The static pressure and differential pressure at the V-Cone were varied using a valve downstream of the V-Cone. 3.1 Standard V-Cone To achieve the objectives stated above, the following tests were carried out: Three 6” V-Cones ( = 0.75, 0.55, and 0.45) were tested at 1 kg/s, giving an approximate

pipe Reynolds number, Repipe 0.5 * 106. These are test numbers 1, 2, and 3. Next, one of these 6” V-Cones ( = 0.45) was tested at a second flowrate of 0.5 kg/s, giving

a pipe Reynolds number, Repipe 0.25 * 106. This is test number 4. One 4” V-Cone ( = 0.55) was tested at flowrates of 0.33 kg/s and 0.66 kg/s, to give the

same approximate pipe Reynolds number as with the 6” tests. These are test numbers 5 and 6.

On completion of these tests it was felt that there was insufficient data from which to derive an equation for expansibility in a V-Cone, particularly at high beta values, with only one data set with > 0.55. Subsequently, it was decided to carry out the following additional tests: Another 4” V-Cone ( = 0.65) was tested at flowrates of 0.33 kg/s and 0.66 kg/s, to give the

same approximate pipe Reynolds numbers as with the 6” tests. These are test numbers 7 and 8.

A 3” V-Cone ( = 0.75) was tested at a flowrate of 0.5 kg/s, again to give the same

approximate pipe Reynolds number as with the 6” tests. This is test number 9. Details of the V-Cones and tests are summarised in Table 1.

Table 1 - Details of standard V-Cones and tests

Test No. Size

(inch) (-)

Flowrate (kg/s)

1 6 0.75 12 6 0.55 13 6 0.45 14 6 0.45 0.55 4 0.55 0.666 4 0.55 0.337 4 0.65 0.668 4 0.65 0.339 3 0.75 0.5

The V-Cones were installed one at a time in the NEL High Pressure Gravimetric Rig in the Gas Flow Lab with 3”, 4” or 6” pipework upstream and downstream of the V-Cone as appropriate to the meter size. The reference flowrate was measured using a sonic nozzle upstream of the V-Cone. The temperature and pressure were measured upstream of the sonic nozzle. The static pressure upstream of the V-Cone, and the differential pressure across it, were measured, as were the temperature downstream of the V-Cone and the barometric pressure. A control valve was located some distance downstream of the V-Cone to enable the static/differential pressure at the V-Cone to be varied. 3.2 Wafer-Cone A similar test procedure was used for the Wafer-Cone. The Wafer-Cones selected for testing were a set of four 4-inch meters, with beta values of 0.45, 0.55, 0.65, and 0.75. This selection was based on a desire to cover the same beta range as in the original tests with the standard V-Cone. The original tests on the standard V-Cone had shown that the expansibility factor was not dependent on pipe Reynolds number, and hence mass flowrate. The flowrate for the Wafer-Cone was therefore chosen to give sufficiently large p values for each Wafer-Cone, but not so large as to be unrepresentative of the conditions likely to be encountered in industrial application. Accordingly the Wafer-Cones with beta ratios of 0.45, 0.55, and 0.65 were tested at approximately 0.5 kg/s, giving an approximate pipe Reynolds number of 3.8 x 105, and the beta 0.75 Wafer-Cone was tested at approximately 0.68 kg/s, giving an approximate pipe Reynolds number of 5.1 x 105. Details of the Wafer-Cone tests are summarised in Table 2 below.

Table 2 - Details of Wafer-Cones and tests

Test No. Size

(inch) (-)

Flowrate (kg/s)

1 4 0.45 0.522 4 0.55 0.523 4 0.65 0.524 4 0.75 0.67

4 DISCUSSION OF RESULTS 4.1 Standard V-Cone In order to discuss the results in a satisfactory manner it is first necessary to describe the method used for determining the expansibility factor from the data collected. 4.1.1 Method of determining expansibility factor From the flow equation for a differential pressure device, Eq. (1), it can be seen that there are two unknowns from our test results, the discharge coefficient, Cd, and the expansibility factor, . Eq. (1) can be rearranged to give:

12

4

24

1

pd

qC m

d

(5)

The functional form of the equation for V-Cone expansibility factor must be decided before proceeding further with the analysis. If Eq. (2) is expanded for small p/p1 and small 4, then it, Eq. (3), and the revised orifice plate expansibility factor equation in ISO/DIS 5167-2 [2] are all of the form:

1

41ppba

(6)

Accordingly, Figures A.1 to A.9 (in Appendix A) show the experimental values of Cd plotted

against 1pp

. The resultant plot has a reasonably linear form, as can be seen in all the graphs.

It can be seen from Eq. (6) that as 1pp

tends to zero, the expansibility factor tends to unity.

Therefore, if a best fit linear curve is calculated through the data in the form y = mx + c, then the intercept c can be taken as the discharge coefficient Cd as will be unity. From the slope m, the term in brackets in Eq. (6) can be determined. In order to evaluate this term in brackets, i.e. constant and dependence on , there needs to be data over a wide enough range of values. After the additional two meters were tested, data was available for beta values of 0.45, 0.55, 0.65, and 0.75. This is sufficient to be able to develop a reliable equation for the expansibility factor. 4.1.2 Analysis of results Using the method described above, the resultant values for m and c are given in Table 3 below.

Table 3. Linear fits through data from standard V-Cone tests 1 to 9.

Test No. Size (inch)

Flow (kg/s)

m c

1 6 0.75 1 -0.6899 0.8255 2 6 0.55 1 -0.6275 0.8800 3 6 0.45 1 -0.6291 0.8778 4 6 0.45 0.5 -0.5599 0.8695 5 4 0.55 0.66 -0.5488 0.8361 6 4 0.55 0.33 -0.5808 0.8316 7 4 0.65 0.66 -0.6615 0.8306 8 4 0.65 0.33 -0.6981 0.8232 9 3 0.75 0.5 -0.6994 0.8085

The values of m and c give the linear fit through the Cd against p/p1 data for each test. The parameter c is the measured value of Cd, obtained by extrapolating the linear fit to the y-axis, where is unity. Dividing the m values by this Cd value gives the slope of the equation for the expansibility factor, . These slopes for each test are given below in Table 4:

Table 4. Slopes of derived expansibility equation for each test.


Flow (kg/s)

slope

1 6 0.75 1 -0.8357 2 6 0.55 1 -0.7131 3 6 0.45 1 -0.7167 4 6 0.45 0.5 -0.6439 5 4 0.55 0.66 -0.6564 6 4 0.55 0.33 -0.6984 7 4 0.65 0.66 -0.7964 8 4 0.65 0.33 -0.8480 9 3 0.75 0.5 -0.8651

The final expansibility equation must be derived from the results in Table 4 above. To achieve this, the slopes of the data from each test are shown below in Figure 1 plotted against 4.

Figure 1. Variation of expansibility slope of standard V-Cone with 4. Altering the power of yielded no significant improvement in the fit of the slopes from each test. By taking the best-fit line through the slopes from each test, the overall expansibility equation can be determined. This best-fit line is shown in Figure 1. Therefore the resultant equation for the expansibility factor in a standard V-Cone meter is:

1

4696.0649.01pp

(7)

4.1.3 Effect of Reynolds number and pipe diameter As described in Section 2, two key objectives of the tests were to show that the expansibility factor was not significantly affected by pipe diameter or by Reynolds number.

y = -0.6963x - 0.6485

R2 = 0.7684

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Slo

pe

of

exp

ansi

b

It can be seen from Figure 1 that this is the case. The two values for = 0.75 (4 = 0.32) are in good agreement, and come from a 6” V-Cone at 1 kg/s and a 3” V-Cone at 0.5 kg/s, both these tests giving a Reynolds number of approximately 0.5 x 106. Tests 2 and 5 were undertaken at the same Reynolds number for = 0.55 (4 = 0.09) but with 6” and 4” V-Cone respectively, and the trend as to which pipe diameter gives the higher value for the slope is the opposite to that for = 0.75. Equally there are three cases of the same meter having been tested at two different flowrates, and hence Reynolds numbers. Tests 3/4, 5/6, and 7/8 show reasonable agreement within their respective pairs and there is no trend as to which Reynolds number gives the higher value for the slope. This confirms the fact that the expansibility factor of the standard V-Cone is not affected by the pipe diameter or the Reynolds number. 4.1.4 Comparison with Dahlstrom’s equation As stated in the introduction, Dahlstrom [3] presented Eq. (4) as the expansibility factor for the standard V-Cone meter. Dahlstrom’s equation was derived from only five points from two meters. Figures A.10 to A.18 show the test results from the standard V-Cones along with the derived equation for expansibility, Eq. (6), compared with Dahlstrom’s equation, Eq. (4). The orifice plate and Venturi tube equations are also shown on the graph as a guide to how the V-Cone expansibility compares with both these devices. It can be seen that Dahlstrom’s equation is reasonably close to the new equation, Eq. (6), for many of the tests. However, the number of points and different meters used in the derivation of the new equation give rise to increased confidence in it. It is also evident that the V-Cone expansibility is somewhat different from that of the Venturi tube, and indeed lies in between the orifice plate and Venturi tube equations, slightly closer to the Venturi. 4.2 Wafer-Cone The four Wafer-Cones were tested in the same manner as the standard V-Cones. The same method (described in Section 4.1.1) was used to determine the Wafer-Cone expansibility factor. The test results are shown in Figures B.1 to B.4 in Appendix B. 4.2.1 Analysis of results Using the method described above, the resulting values for m and c are given in Table 5 below.

Table 5. Linear fits through data from Wafer-Cone tests 1 to 4.


Nominal Flow (kg/s)

m c

1 4 0.45 0.52 -0.6825 0.8888 2 4 0.55 0.52 -0.7228 0.8962 3 4 0.65 0.52 -0.8946 0.9169 4 4 0.75 0.67 -1.3070 0.9119

The values of m and c give the linear fit through the Cd against p/p1 data for each test. The parameter c is the measured value of Cd, obtained by extrapolating the linear fit to the y-axis, where is unity. Dividing the m values by this Cd value gives us the slope of the equation for the expansibility factor, . These slopes for each test are given below in Table 6.

Table 6. Slopes of derived expansibility equation for each test.

Test No. Size

(inch) Nominal Flow

(kg/s) Slope

1 4 0.45 0.52 0.7679 2 4 0.55 0.52 0.8065 3 4 0.65 0.52 0.9757 4 4 0.75 0.67 1.4333

The final expansibility equation must be derived from the results in Table 6 above. To achieve this, the slopes of the data from each test are plotted against raised to some power. In the case of the standard V-Cone – and the orifice plate expansibility in ISO 5167-1:1991 – this power is 4. Figure 2 shows the four slopes plotted against 4. It can be seen that there is a distinct curve with increasing 4, and that the linear fit does not represent this curve.

Figure 2. Variation of expansibility slope of Wafer-Cone with 4.

To try to improve the fit of the equation, different powers of were used. Indeed, it was found that by plotting the slopes against 8 the resulting linear fit was near perfect, as shown in Figure 3.

y = -2.4792x - 0.607

R2 = 0.959

-1.6

-1.4

-1.2

-1.0

-0.8

-0.6

-0.4

-0.2

0.0

0 0.05 0.1 0.15 0.2 0.25 0.3 0.35 0.4

4 (-)

Slo

pe

of

exp

ansi

b

Figure 3. Variation of expansibility slope of Wafer-Cone with 8.

By taking the best-fit line through the slopes from each test, the overall expansibility equation can be determined. This best-fit line is shown in Figure 3. Therefore the resulting equation for the expansibility factor in a Wafer-Cone meter, based on these four tests, can be taken as:

1

8787.6755.01pp

(8)

4.2.2 Comparison with standard V-Cone, orifice plate and Venturi It has been shown that the expansibility factor standard V-Cone lies between that of the orifice plate and the Venturi meters, slightly closer to the Venturi. Figures B.5 to B.8 (Appendix B) show the test results from the Wafer-Cone work compared against the derived equation, Eq. (8), and the standard V-Cone expansibility equation, Eq. (7). The orifice plate and Venturi expansibility equation are also shown for comparison. It can be seen that the expansibility factor for the Wafer-Cone is significantly different from that of the standard V-Cone. The slope of the expansibility factor for the Wafer-Cone is steeper than that for the standard V-Cone, and lies much closer to that for the Venturi meter. The slope form the = 0.45 test is less than that for the Venturi, whilst the slope from the = 0.55 test is much closer to the Venturi. The slope from the = 0.65 test is actually slightly higher than that for the Venturi equation, and the slope from the = 0.75 test is significantly higher than that for the Venturi. It is possible that this is due to the Wafer-Cone having wall tappings for both pressure measurements. 5 CONCLUSIONS Six standard V-Cone flowmeters were tested in air at NEL’s Flow Centre in order to determine the expansibility factor of a gas flowing through a V-Cone. By testing each meter at a nominally constant flowrate and by varying the static pressure and differential pressure at the meter, it was possible to obtain the necessary data to determine the recommended equation for the expansibility factor, Eq. (7). In addition, no significant effect on the expansibility factor could be attributed to a change in Reynolds number or pipe diameter.

y = -6.7872x - 0.7548

R2 = 0.9998

-1.6

-1.4

-1.2

-1.0

-0.8

-0.6

-0.4

-0.2

0.0

0 0.02 0.04 0.06 0.08 0.1 0.12

8 (-)

Slo

pe

of

exp

ansi

b

In addition, tests on four Wafer-Cones have shown that the expansibility factor for the Wafer-Cone is not the same as that for the standard V-Cone, and is closer to that for the Venturi, possibly due to the Wafer-Cone having wall tappings. The slope of the Wafer-Cone expansibility factor is much more dependent on and is in fact higher than the slope for the Venturi at = 0.65 and = 0.75. 6. LIST OF NOMENCLATURE a, b Coefficients in Eq. (5) Cd Discharge coefficient [-] d (Throat) diameter [m] p1 Static pressure [Pa] p Differential pressure [Pa] qm Mass flowrate [kg/s]

Repipe Pipe Reynolds number, 4

pipemRed

[-]

Effective diameter ratio [-] Expansibility factor [-] Isentropic exponent [-] Density [kg/m3]

Pressure ratio, 1

1

ppp

[-]

7 REFERENCES [1] F.C. Kinghorn. The expansibility correction for orifice plates: EEC data. In Proc. Int. Conf. on Flow Measurement in the Mid 80’s (Paper 5.2). National Engineering Laboratory, East Kilbride, Glasgow, June 1986. [2] International Standards Organisation. Measurement of fluid flow by means of pressure differential devices inserted in circular cross-section conduits running full, Part 2: Orifice plates. Geneva: International Standards Organisation. ISO/DIS 5167-2, May 2000. [3] M.J. Dahlstrom. V-Cone meter: Gas measurement for the real world. North Sea Flow Measurement Workshop, Peebles, Scotland, 1994. [4] D.G. Stewart, M.J. Reader-Harris, and R.J.W. Peters. Derivation on an Expansibility

Factor for the V-Cone Meter. Flow Measurement 2001, International Conference, Peebles, Scotland, May 2001.

APPENDIX A. DIAGRAMS OF RESULTS FOR THE STANDARD V-CONE Fig. A.1 - Results from standard V-Cone test 1.

Fig. A.2 - Results from standard V-Cone test 2.

Test No. 1 6 inch = 0.75 1kg/s

y = -0.6899x + 0.8255

R2 = 0.9423

0.75

0.76

0.77

0.78

0.79

0.80

0.81

0.82

0.83

0.84

0.85

0.000 0.005 0.010 0.015 0.020

p / p1

C d


y = -0.6275x + 0.88

R2 = 0.9878

0.80

0.81

0.82

0.83

0.84

0.85

0.86

0.87

0.88

0.89

0.90

0.00 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08

p / p1

C d




y = -0.6291x + 0.8778

R2 = 0.9964

0.75

0.77

0.79

0.81

0.83

0.85

0.87

0.89

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14 0.16

p / p1

C d

Test No. 4 6 inch = 0.45 0.5kg/s

y = -0.5599x + 0.8695

R2 = 0.9947

0.80

0.81

0.82

0.83

0.84

0.85

0.86

0.87

0.88

0.89

0.90

0.00 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08

p / p1

C d



Test No. 5 4 inch = 0.55 0.66kg/s

y = -0.5488x + 0.8361

R2 = 0.9992

0.70

0.72

0.74

0.76

0.78

0.80

0.82

0.84

0.00 0.05 0.10 0.15 0.20 0.25

p / p1

C d

Test No. 6 4 inch = 0.55 0.33kg/s

y = -0.5808x + 0.8316

R2 = 0.9922

0.75

0.76

0.77

0.78

0.79

0.80

0.81

0.82

0.83

0.84

0.85

0.00 0.02 0.04 0.06 0.08 0.10

p / p1

C d



Test No. 7 4 inch = 0.65 0.66kg/s

y = -0.6615x + 0.8306

R2 = 0.9969

0.70

0.72

0.74

0.76

0.78

0.80

0.82

0.84

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14

p / p1

C d

Test No. 8 4 inch = 0.65 0.33kg/s

y = -0.6981x + 0.8232

R2 = 0.9821

0.75

0.76

0.77

0.78

0.79

0.80

0.81

0.82

0.83

0.84

0.85

0.000 0.010 0.020 0.030 0.040 0.050

p / p1

C d


Fig. A.10 - Derived expansibility factor values from standard V-Cone test 1 compared with Eq. (7) along with Dahlstrom’s equation, and the orifice plate and Venturi tube equations.

0.97

0.98

0.99

1.00

0.000 0.005 0.010 0.015 0.020

p / p1 (-)

Test 1 data

V-Cone - Eq. (7)

Orifice plate

Venturi tube

Dahlstrom

Test No. 9 3 inch = 0.75 0.5kg/s

y = -0.6994x + 0.8085

R2 = 0.9993

0.70

0.72

0.74

0.76

0.78

0.80

0.82

0.84

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14

p / p1

C d



0.92

0.93

0.94

0.95

0.96

0.97

0.98

0.99

1.00

0.00 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08

p / p1 (-)

Test 2 data

V-Cone - Eq. (7)

Orifice plate

Venturi tube

Dahlstrom

0.86

0.88

0.90

0.92

0.94

0.96

0.98

1.00

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14 0.16

p / p1 (-)

Test 3 data

V-Cone - Eq. (7)

Orifice plate

Venturi tube

Dahlstrom



0.92

0.93

0.94

0.95

0.96

0.97

0.98

0.99

1.00

0.00 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08

p / p1 (-)

Test 4 data

V-Cone - Eq. (7)

Orifice plate

Venturi tube

Dahlstrom

0.76

0.80

0.84

0.88

0.92

0.96

1.00

0.00 0.05 0.10 0.15 0.20 0.25

p / p1 (-)

Test 5 data

V-Cone - Eq. (7)

Orifice plate

Venturi tube

Dahlstrom



0.90

0.92

0.94

0.96

0.98

1.00

0.00 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08 0.09

p / p1 (-)

Test 6 data

V-Cone - Eq. (7)

Orifice plate

Venturi tube

Dahlstrom

0.84

0.86

0.88

0.90

0.92

0.94

0.96

0.98

1.00

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14

p / p1 (-)

Test 7 data

V-Cone - Eq. (7)

Orifice plate

Venturi tube

Dahlstrom



0.94

0.95

0.96

0.97

0.98

0.99

1.00

0.000 0.005 0.010 0.015 0.020 0.025 0.030 0.035 0.040 0.045

p / p1 (-)

Test 8 data

V-Cone - Eq. (7)

Orifice plate

Venturi tube

Dahlstrom

0.82

0.84

0.86

0.88

0.90

0.92

0.94

0.96

0.98

1.00

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14

p / p1 (-)

Test 9 data

V-Cone - Eq. (7)

Orifice plate

Venturi tube

Dahlstrom

APPENDIX B. DIAGRAMS OF RESULTS FOR THE WAFER-CONE Fig. B.1 - Cd against p/p1 for Wafer-Cone test 1.

Fig. B.2 - Cd against p/p1 for Wafer-Cone test 2.

Fig. B.5 - Wafer-Cone results from Test 1 compared with Eq. (8), standard V-Cone expansibility equation, Eq. (7), and orifice plate and Venturi equations.


0.70

0.75

0.80

0.85

0.90

0.95

1.00

0.00 0.05 0.10 0.15 0.20 0.25 0.30

p/p1

Test 1 data

Wafer-Cone - Eq. (8)

Orifice plate

Venturi

Standard V-Cone - Eq. (7)

0.80

0.85

0.90

0.95

1.00

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14 0.16

p/p1

Test 2 data


Orifice plate

Venturi




0.90

0.92

0.94

0.96

0.98

1.00

1.02

0.00 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08

p/p1

Test 3 data


Orifice plate

Venturi


0.90

0.92

0.94

0.96

0.98

1.00

1.02

0.00 0.01 0.02 0.03 0.04 0.05 0.06

p/p1

Test 4 data


Orifice plate

Venturi


1

19th North Sea Flow Measurement Workshop 2001

UTILIZATION OF AN INLINE ROTARY SEPARATORAS A WET GAS METER

V. C. TingChevron Petroleum Technology Company

Houston, Texas, USA

ABSTRACT

Chevron Petroleum Technology Company evaluated the performance of an inline rotaryseparator in 2000 and during the evaluation tests, we discovered that the inline rotary separatorcould also be used as a wet gas meter to measure gas and liquid flow rates. The inline rotaryseparator, IRIS™ , is a commercial gas-liquid separation device manufactured by MultiphasePower and Processing Technologies, LLC. It is a compact, high quality, separation device thatcan be used in wellhead or pipeline applications.

The inline rotary separator removes gas and liquid phases from a wet gas stream and the gas flowrate can be interpreted by measuring the rotor speed at wet conditions. Hence, it can be used as awet gas meter by measuring the separated liquid phase and the rotor speed. Test results indicatedthat low liquid loading, up to 3% liquid/gas mass ratio (LGMR), has minimal affect on rotorspeed. Natural gas flow rates can be measured within ±5% accuracy using the dry gas speedcurve at high gas velocity. For LGMR greater than 3%, meter flow calibration and gas flow rateinteroperation are required.

This paper consists of the following topics:

• Review inline rotary separator operation principle.• Present field trail and flow loop test results.• Use inline rotary separator as a wet gas meter.• Measure gas flow rates at low and high liquid loading.• Conclusions and recommendations.

INTRODUCTION

Accurate and reliable wet gas metering technology is an important component of the natural gasproduction system. More gas will be produced in the future from remote and subsea fields whereproduction, capital investment, and operating costs must be optimized. For example, real timemeasurement of gas and liquid flow rate in a subsea production system will improve wellallocation, optimize reservoir production, and enhance flow assurance. Most commercialmultiphase meters have a higher measurement uncertainty in high gas void fraction (GVF) range,which is not suitable for wet gas applications. Therefore, wet gas metering technology hasreceived more attention by the industry and, consequently, several wet gas-metering systems

2

have been developed. In addition, joint industry projects have been formed to evaluate wet gasmeter performance.

The wet gas metering technology available generally falls into three categories:

• Commercial Gas Meters— Several studies(1-7) were conducted recently to determine the effectof liquid on gas flow measurement accuracy in orifice, venturi, v-cone, vortex, ultrasonic,coriolis, and turbine meters. When these types of meters are used for wet gas flowmeasurement, the liquid flow rate is required as a known input parameter for gas flow ratecorrections and calculations. The liquid flow rate can generally be determined or estimatedby using well tests, tracers or reservoir PVT predication methods. These methods willprovide a constant liquid flow rate estimate over a test period. The uncertainty of the gasflow rate measurement, therefore, depends on the uncertainty of the liquid flow rate inputvalue over that measuring period. If the liquid flow rates vary significantly, the gas flow ratemeasurement uncertainty will be large.

• Wet Gas Meters— There are commercial metering products for wet gas flow measurement,such as Venturi Dualstream, Agar, VEGA, Ultrasonic wet gas meter, and in-line multiphasemeters,(8-12) where gas and liquid flow rates are measured simultaneously. However, there arelimited third-party published performance evaluations on these new devices at this time.

• Separation/Metering— This method utilizes a gas/liquid separation device to produce a lowGVF multiphase stream and a gas stream. A multiphase meter is used to measure the lowGVF multiphase steam with better measurement uncertainty while a commercial gas meter isused to measure the gas stream.(13)

Chevron recently evaluated a compact 75 mm (3-inch) in-line gas-liquid rotary separator,IRIS™ , at Chevron's Laredo Gas Field and at the Colorado Engineering Experiment Station,Inc., (CEESI) Wet Gas Flow Facility. IRIS is a commercial gas-liquid separation devicemanufactured by Multiphase Power and Processing Technologies, LLC. The unit is 10% of thesize and weight of a conventional static separator.(14) During performance evaluation tests, wediscovered it could be used as a wet gas meter to measure gas and liquid flow rates.

INLINE ROTARY SEPARATOR OPERATING PRINCIPLES

The IRIS™ is an inline rotary gas-scrubbing device, which is compact in size with acceptableseparation features. It can operate at the wellhead or pipeline where space or accessibility islimited. Its assembly consists of three major components: an inlet housing, an exhaust housing,and a rotor/bearing system, as shown in Figure 1. The inlet housing contains the swirl generatingpassages, liquid collection belt, inlet pipe flange, and bearing housing. The exhaust housingcontains the diffuser/flow straightening section, the exit end bearing housing, and the exhaustpipe flange. The rotor assembly contains a rotor drum/wheel pressed onto the shaft. The thrustand journal bearings are ceramic ball bearings. The inlet and exhaust housings are boltedtogether to form a pressure containment vessel.

3

The general layout of IRIS™ is similar to an axial flow cyclone as show in Figure 2. It has anaxial arrangement consisting of a swirl generator, separation zone, diffuser section, and liquidcollection belt. A combination of viscous drag on the drum and momentum transfer from thefluid stream passing through axial spokes on the rotor provides the energy for rotation.

The inlet gas/liquid stream travels through a set of stator vanes in the swirl generator that directsthe flow to a larger radius while increasing the tangential velocity component. The stream thenenters a separation zone, which is an annular region with a static inner wall, and a rotating outerwall formed by the inside of the rotor drum. The rotational flow field subjects the fluid stream toa high gravity “g” field, which centrifuges the liquids to the outer wall forcing them to attach tothe moving wall. The outer wall and fluid are moving at approximately the same rotationalspeed, no significant fluid shear boundary forms. This results in a more distinct and smoothliquid layer compared to static-walled cyclones, and provides significantly improved separation.Finally, the moving wall actively forces the separated liquid to a drain location.

After traversing the separation zone, dry gas exit through a vane diffuser section to recover aportion of its kinetic energy and to minimize exit swirl. The separated liquid on the rotor drummoves axially upstream due to the conical shape of the drum. Liquid exits the rotor off a lip atthe inlet end of the drum. It spills outward in the radial direction into an annular collector band,which directs it toward a tangential drain opening.

SEPARATION PERFORMANCE EVALUATION

Prototype Unit Field Trail

A prototype In-Line Rotary Separator was tested from October 1999 to June 2000 at the ChevronF. Ramirez Gas Production Facility in Laredo, Texas, USA. The purpose of this test was toevaluate the mechanical reliability and separation characteristics in an actual production system.A skid was designed to handle a capacity of 340,000 Sm3/day (12 MMSCFD) of gas and32 m3/day (200 BPD) liquids at 9,928 kPa (1,440 psig). The skid includes a 7.6 cm (3-inch)prototype unit, gas and liquid metering system, and the bypass piping as shown in Figure 3.

The facility contains production wells, gathering manifolds, scrubber separator, liquid storagetanks, and gas custody transfer metering stations. Gas, water, and condensate are produced fromvarious wells in the area, and gathered into a manifold. High pressure and low pressure streamseach flow through dedicated horizontal scrubber vessels. Individual wells can also be bypassedto a test separator for well tests. Natural gas flows to sales lines while the removed liquids aresent to the storage tanks. The tanks are periodically gauged to measure water and condensatecontent.

The evaluation system was set up so that the test skid was installed upstream of the high-pressurescrubber vessel, directly on the outlet of the manifold. IRIS™ separates the multiphase fluidwhereas the liquid flow is metered. The scrubbed gas was also metered and flows to the testseparator to capture any liquid carryover. The amount of liquid carryover from the test separator

4

was used to determine the separation efficiency. Separation efficiency is defined as the ratio ofliquid removed from the IRIS™ over the total liquid input.

The unit operated at 76 bar (1,100 psig) inlet pressure and ambient temperature conditions withflow rate up to 11,800 Sm3/hr (10 MMSCFD). The liquid load is 0.33-0.66 m3/hr (50-100 bbl/day) with 75% water cut. The unit operating speed ranges from 5,000 to 8,000 rpm witha pressure drop between 1-1.4 bar (15-20 psi). The flow and separation characteristics variedwith the production rate with greater than 99% separation efficiency at near design conditions.Figure 4 shows IRIS™ speed and separation efficiency history plots. The field test wasconcluded when the gas flow rate was reduced to 20% of the design flow rate. A total of4,763 hours of operation was logged and no mechanical failure was detected over that time.

Commercial Unit Performance Tests

Further testing of a 7.6 cm (3-inch) commercial unit, shown in Figure 5, was undertaken at theColorado Engineering Experimental Station, Inc., (CEESI) Wet Gas Flow Loop to quantify theflow, pressure drop, and speed characteristics of the rotary separator. The wet gas flow facility isconstructed as a re-circulating flow loop where processed natural gas and liquid decane areselected as flowing fluid for the tests. The flow loop is designed to flow at pressures between 5.9and 82.7 bar (100 and 1200 psia) and temperature 2.7 to 27ºC (5 to 50ºF) above the ambienttemperature. The overall uncertainty of CEESI's wet gas flow system is estimated at 1%. A gasturbine flow meter is selected as the dry gas flow reference meter and a coriolis meter is alsoused to measure the liquid flow rate before it is injected into the gas stream. After liquid isinjected into the gas stream, wet gas with known liquid gas mass ratio (LGMR= mliquid/mgas)flows through a test section. In the performance evaluation tests, a mist removal vesseldownstream of the rotary separator was installed, as shown in Figure 6, to measure liquidcarryover by IRIS™ .

Figure 7 presents typical performance results showing the separation efficiency for LGMRranging from 0 to 1.0, and superficial gas velocity from 3-15 m/s (10-50 ft/sec) at 41 bar(600 psia). The separation efficiency varies from 96% to 100% depending on the superficial gasvelocity and LGMR. As shown in the figure, the tested unit performed best at 15-m/s.Performance curves such as these can be used to understand the rotary flow characteristics andimprove future separation design. Pressure drop across the rotary separator measured up to 3% ofthe inlet pressure.

IRIS SEPARATOR AS WET GAS METER

During the evaluation tests conducted at CEESI, it was discovered that the inline rotary separatorcould be used as a wet gas meter to measure gas flow rates. For low liquid injection tests, therotor speed is less sensitive to the liquid flowing rate which is shown in Figure 8. In this figure,superficial gas velocity is plotted over the rotary speed for dry gas at LGMR<3%. The dry gasspeed data points (n) are bounded by the ±5% accuracy dotted lines. The test data also show thatwet gas rotor speed date points (u) lie within the ±5% bounds at low LGMR and higher gas

5

velocity. This implies that the wet gas flow rate can be measured directly by using the dry gasspeed curve at higher gas velocity conditions. Combining with the liquid flow rate measuredseparately, the IRIS™ can be used as a wet gas meter.

At low LGMR, gas flow measurement accuracy can be improved further by using the wet gasspeed calibration curve at operating conditions. For example, a calibrated LGMR vs. Speed plot,shown in Figure 9, can be used to iterate gas flow rate calculations to improve gas flowmeasurement accuracy. Similarly, the liquid flow rate accuracy can be improved by consideringthe separation efficiency in flow rate calculations.

As the LGMR increases, the rotor begins reducing its speed due to additional loading andincreasing fluid drag. For a constant gas flow rate, the rotor speed reduction is proportional to theliquid loading, shown in Figures 10-12, at 6.6, 41.1, and 75.8 bar (100, 600, and 1100 psia)operating pressure respectively. In these figures, liquid loading (kg/hr) is plotted against rotorspeed. At higher liquid loading up to 100% LGMR, the gas flow rate can be estimated directlyby using liquid load and speed calibration curves. For a given set of liquid flow rates and rotorspeeds, the gas velocity can be interpolated from the family curves of various pressures as shownin the figures. The gas flow measurement uncertainty depends on the accuracy of the liner curveregression and the interpolation techniques. Because there were limited sample points in thesetests, the measurement uncertainty could be improved if additional test points were conductedand an accurate gas flow rate measurement model were developed.

CONCLUSIONS AND RECOMMENDATIONS

1. The rotary separator is a compact device, which is best for space- and accessibility-limitedapplications. In addition to compact separation applications, IRIS™ can be used as a wet gasmeter and/or well test allocation measurement system in a remote location, offshore platform,or subsea. An inline rotary separator was tested as a wet gas meter at liquid loading, LGMR,up to 100%.

2. For low LGMR up to 3%, the rotor dry gas speed curve is used to estimate gas flow ratewithin ±5% accuracy at higher gas velocity.

3. For higher LGMR, up to 100%, the rotary separator should be calibrated at flowingliquid/gas conditions to develop the wet gas speed curve. The wet gas speed curves are usedto interpolate gas flow rates.

4. A commercial wet gas metering flow computer algorithm using the rotary separator for wetgas metering applications is not available and should be developed.

ACKNOWLEDGEMENTS

The author would like to acknowledge the Management of Chevron Petroleum TechnologyCompany for their permission to publish this paper. Many thanks and appreciation are extended

6

to Hank Rawlins and Ted Bond of Multiphase Technologies for their dedication and cooperationin deploying the rotary separation technology. The expertise on measurement and his insight insetting up the wet gas flow loop for the evaluation tests of Charlie Britton of CEESI arerecognized.

REFERENCES

1. Couput, Jean-Paul, Pierre Gajan, Vincent de Laharpe and Alain Strzelecki, “Wet GasMetering in the Upstream Area: Needs, Applications and Developments”, 18 North Sea FlowMeasurement Workshop, 2000.

2. De Leeuw, Rick “Liquid Correction of Venturi Meter Readings in Wet Gas Flow”, North SeaFlow Measurement Workshop, 1997.

3. Ting, V. C. and G. P. Corpron, “Effect of Liquid Entrainment on the Accuracy of OrificeMeters for Gas Flow Measurement”, 1995 International Gas Research Conference.

4. Jones, E. and V. C. Ting, “Wet Gas Metering Performance”, 1996 OMAE, Volume V,Pipeline Technology, ASME 1996, pp. 297-303.

5. Hodges, D, A. R. W. Hall, and G. J. Brown, “Evaluation of Dry-Gas Meters in Wet-GasConditions: Turbine and Venturi Meters” Paper No. 13148, Offshore TechnologyConference, 2001.

6. Karnik, Umesh and J. Geerligs, “Effect of Pulsation and Liquid Contaminants on a Micro-Motion Coriolis Mass Flow Meter”, Flow Measurement 2001 International Conference.

7. Ifft, Stephen A., “Wet Gas Testing with the V-Cone Flowmeter” North Sea FlowMeasurement Workshop, 1997.

8. Andreussi, Pciandri, and Faluomi “Development of a Wet Gas Flowmeter”, BHR Group2000 Multiphase Technology.

9. Vedapuri, Demodaran, and Madan Gopal “Initial Studies on the Design of a Clamp-onUltrasonic Flowmeter for Wet Gas Pipelines”, ASME-ETCE, 2000.

10. Zanker, Klaus J. and Gordon J. Stobie, “Ultrasonic Wet Gas Measurement Dawn GasMetering a Real World System”, North Sea Flow Measurement Workshop, 1998.

11. Lund, J. S., A. R. Tait and S. Clark “A Wet Gas Meter for Gas/Condensate FlowMeasurement”, BHR Group 1999 Multiphase Technology.

12. Tuss, B., D. Perry, and G. Shoup, “Field Tests of the High Gas Volume Fraction MultiphaseMeter”, SPE Annual Technical Conference and Exhibition, Denver, October 6-9, 1996.

13. Cellos, Harry, “Multiphase Flow Measurement System of High-GOR Applications”, NorthSea Flow Measurement Workshop, 1998.

14. “In-line Rotary Separator (IRIS ) Technical Handout Version 3.0”, Kvaerner ProcessSystems US, March 21, 2001.

7

Internal View of Rotary SeparatorIRIS™

INLET HOUSING

EXHAUST HOUSING

ROTOR/ BEARINGSYSTEM

Inlet Flange

Exhaust Flange

ShaftBearing

Drum/ Wheel

O-ring Seal

Housing Bolts

Figure 1

Rotary Separator IRIS™ Flow Path

Stator Vanes

Liquid Collection Belt

Rotor Blades

Diffuser Vanes

INLET

Separation Zone

Liquid Discharge Lip

Liquid Drain

Rotor Drum

EXHAUST

Swirl Generator Diffuser Section

Figure 2

8

Field Trial at Chevron Laredo Gas Field

Figure 3

Rotary Separator Speed and SeparationEfficiency-- Chevron Field Trial

2000

3000

4000

5000

6000

7000

8000

9000

10000

24-Jan 8-Feb 23-Feb 9-Mar 24-Mar 8-Apr 23-Apr 8-May 23-May 7-Jun 22-Jun

Date, Year 2000

Spe

ed (

RP

M)

50%

55%

60%

65%

70%

75%

80%

85%

90%

95%

100%

Sep

arat

ion

Eff

icie

ncy

(%)

Speed (RPM)

Separation Efficiency (%)

Figure 4

9

In Line Rotary Separator IRIS™ Testingat CEESI

Figure 5

RotarySeparator

Test Set Upat CEESI

Figure 6

10

IRIS™ Separation Efficiency

92

94

96

98

100

102

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

Liquid Mass Flow Rate/Gas Mass Flow Rate

Sep

arat

ion

Eff

icie

ncy

(%)

Vg=15.2 m/s,41 bar10.7 m/s, 41bar15.2 m/s, 77bar10.1 m/s, 77bar

Figure 7

Effect of Low Liquid Gas Mass Ratio(<0.03) on Rotor Speed at 41.4 Bar

0

5

10

15

20

25

0 2000 4000 6000 8000 10000 12000Speed (rpm)

Sup

erfic

ial G

as V

eloc

ity (

m/s

)

Wet GasDry Gas

Figure 8

11

Rotor Speed at Low LGMR

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0 5000 10000 15000Speed (rpm)

Liqu

id G

as M

ass

Rat

io (

LGM

R)

Vg= 15.24 m/s, 41.4 bar

Vg= 9.14 m/s, 41.4 bar

Figure 9

IRIS™ Wet Gas Meter Performance at 6.6 Bar

500

700900

1100130015001700190021002300

2500

0 2000 4000 6000 8000 10000

Speed (rpm)

Liqu

id F

low

Rat

e (k

g/hr

)

Vg= 15.24 m/sVg= 9.14 m/s

Figure 10

12


50010001500200025003000350040004500500055006000

0 5000 10000 15000

Speed (rpm)

Liqu

id F

low

Rat

e (k

g/hr

)

Vg= 15.24 m/sVg= 12.19 m/sVg= 9.14 m/sVg= 6.10 m/sVg= 3.05 m/s

Figure 11


500

1500

2500

3500

4500

5500

6500

7500

8500

0 2000 4000 6000 8000

Speed (rpm)

Liqu

id F

low

Rat

e (k

g/hr

)

Vg= 12.19 m/sVg= 9.14 m/sVg= 6.10 m/sVg= 3.05 m/s

Figure 12

19th international north sea flow measurement workshop 2001

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