Multiphase Flow Meters: Technology and Applications in Upstream Oiland Gas Industry

Coresponding Author: *Abbas Mohammad HosseiniSisakht,amh @gmail.com

Iranian Offshore Oil Company- Khark Production DistrictAmir ghasemzade , Gholam Abbas Safian

Room NO., rd floor, Petroleum Engineering Department, NISOC MainOffice, New Site

National Iranian South Oil CompanyAbstractMeasuring different phase fractions (Water Cut, GOR and liquid flow rate)in multiphase flow of each oil or gas well is cornerstone of field studies andoperations like Reservoir management, field development, productionallocation and optimization. Conventional method for measuring phasefractions is test separator which has some limitations. The use of MPFM(Multi Phase Flow meter) has great potential economic impact on oil andgas fields. This is the reason for drive in NISOC (National Iranian South OilCompany) to follow to use MPFM technology instead of conventional testseparators. Selection of suitable MPFM for its exclusive application iscritical. So in order to confident application of these tools, it is necessary tohave enough knowledge about MPFM different technologies. This paperreports on major fields of MPFMs applications and their advantages andlimitations.Key Words: Flow Assurance - Production Monitoring - Multiphase flow -Multiphase Flow MeterIntroductionDuring the late s the oil and gas industry started to realize that theavailability of multi-phase flow meters could have a large economic impact Gas Oil Ratio

on the infrastructure of oil and gas developments. This was the reason forthe development of multi-phase flow meters to be primarily driven by the oilindustry. The late s and the early s saw various research programsbeing initiated, both in-house with the oil companies and through JointIndustry Programs (JIPs). In comparison with the developments ofUltraSonic single phase flow meters, the development of multi-phase flowmeters is far more complex, both in terms of hardware and in terms of fluidflow dynamics [].For reservoir management, the single most important requirement ismonitoring the performance of its producing wells accurately. This providesinsight to the reservoir behavior, sustaining of the production capacity,knowledge on the remaining reserves and thus enhancing the maximumrecovery.Traditionally, metering of the multiphase flow is carried out utilizing two orthree phase test separators (full or partial separation) using single-phaseflow meters installed on the outlets of the oil, water and gas legs. Thesehave an acceptable accuracy limit, which depend on operators skills and itsmaintenance work. This varies for oil (min. +/ -% to max. +/- %), water(min. +/-% to max. +/-%) and gas (min. +/- % to max. +/-%). Thesewide ranges in the measurement accuracies are depended on variousfactors. This approach, i.e. the use of the test separators, is practical andthe accuracies acceptable during early production. However, as the fieldsmature and as the water cut increases, yielding changes in the flow regimeand the fluid characteristics, the test separators are less accurate in thatthey become non-adaptive to these changes. They also have trouble inhandling slugging flows, wide variations in water cut and physical changesin the fluid properties. The latter affect the performance and the accuracy ofthe measurements due to the gas under carry in the liquid and liquidcarryover in the gas. Multiphase flow meters, on the other hand do not relyon full separation (%) of the fluid and operate under various conditionsfor the multiphase flow measurement [].

Multiphase Flow Metering Philosophy []The need for multiphase flow metering arises when it is necessary ordesirable to meter well stream(s) upstream of inlet separation and/orcommingling. Multiphase flow measurement technology may be anattractive alternative since it enables measurement of unprocessed wellstreams very close to the well. The use of MPFMs may lead to cost savings

in the initial installation. However, due to increased measurementuncertainty, a cost-benefit analysis should be performed over the life cycleof the project to justify its application. Some general types of applicationsare briefly described as follows:

Single well surveillance or monitoringBy continuous monitoring using a MPFM, the time resolution of theinformation is higher compared with random well testing with a testseparator. Using an MPFM instead of a separator may therefore reduce thetotal uncertainty in well data.

Production optimizationMajor optimization considerations can be made for Gas lift operation,chemical injection, gas coning detection, water breakthrough detection, etc.[]

Flow AssuranceFlow assurance includes all aspects that are relevant to guarantee the flowof oil and gas from reservoir to the sales or custody transfer point. It ofteninvolves facility engineers, production technologists and operations staff,and they evaluate and study the hydraulic, chemical and thermal behaviorof multiphase fluids. By more frequent (or continuous) measurement withMPFMs it may be possible to identify potential blockages in the productionsystem (e.g. hydrates, asphaltenes, wax, sand, scale). Often the trendinghere is more important than providing numbers with absolute accuracy [].Multiphase Flow Meter Technology [], []The main advantage of the MPFM over the test separator will be thereduction in time to perform a measurement. While the separator must beallowed to fill and stabilize when changing wells for test, the MPFMresponds more quickly to changes in the well fluids and needs less time tostabilize.The MPFM might also replace the test separator completely. This may be asolution for fields in the decline phase where the production from the welldoes not match the size of the test separator any more.MPFMs Measuring Principles []A multiphase flow consists of the three phases: oil, gas and water. To workout the individual volumetric flow rate of these phases, the fractions andvelocities of each of the phases have to be found. An ideal flow meterwould have three measurements; phase fraction, phase velocity and phase

density. By means of these measurements the oil, gas and water mass flowrate can be calculated. In practice, the density of the oil, water and gas iscalculated by means of PVTdata.The MPFM is then set up to measure component velocities and two of thecomponent fractions, since the fractional sum should equal . The phasemass flow rates of oil, gas and water are found by combining the fractionalmeasurement, velocity measurement and density measurement.The most common principles used for measurement of phase velocities andphase fractions are described as follows.Phase velocities and volume flow rate measurement

Venturi meter is often used to determine the velocity of themultiphase flow. In a venturi meter the differential pressure across theupstream section and the throat section of the device is measured and canbe related to the mass flow rate through the Venturi.

Cross correlation Velocity measurements by cross-correlation is astandard signal processing method to determine the velocity of flows. Someproperty of the flow is measured by two identical sensors at two differentlocations in the meter, separated by a known distance. As the flow passesthe two sensors, the signal pattern measured by the first sensor will berepeated at the downstream sensor after a short period of time (dt)corresponding to the time it takes the flow to travel from the first to thesecond sensor. The signals from the two sensors can be input to a cross-correlation routine, which moves the signal trace of the second sensor overthe signal trace of the first sensor in time. The time-shift that gives the bestmatch between the two signals corresponds to the time it takes the flow totravel between the sensors. Knowing the distance between the sensors, itis therefore possible to calculate the flow velocity.Examples of technologies where cross-correlation techniques are oftenused are:

Gamma-ray (density) Electrical impedance principles Microwave Differential pressure measurements

Phase fractionsA number of technologies are used in MPFMs for measurement of phasefractions and some of the most common are briefly described in thefollowing.

Gamma ray methods: A number of different gamma ray methodsexist and that are applied in flow metering, and here we will only discussbriefly the more common single-, dual- gamma ray attenuation methods. Inprinciple a gamma ray attenuation measurement is applicable to allpossible combinations of two-and three-phase flows. There are fewmeasurement limitations and the measurement works in the whole rangefrom - % water cut and -% GVF applications.Single energy gamma ray attenuation measurement is based on theattenuation of a narrow beam of gamma- or X-rays of energy E. Note thatthe single energy gamma ray attenuation concept as a stand-alonemeasurement can only be applied in a two-phase mixture. In a pipe, withinner diameter d, containing two phases the attenuation is described with:

]).(.[).()( 2 1 deEXPeIeI iiivm ()Im (e) is the measured count rate, Iv (e) is the count rate when the pipe isevacuated and i represent the linear attenuation coefficients for the twophases. Apart from the fractions (i), the attenuation coefficients (i) arealso initially unknown. However, the latter can be found in a calibrationwhere the meter is subsequently filled with the individual fluids or they canbe entered in the software after they have been determined offline.Equation can be written for both phases. These two calibration pointstogether with the obvious relation that Water + Oil = can be rewritten as anexpression for the water fraction in a two phase liquid/liquid mixture (or thewater cut) as shown in Equation ():

)ln()ln()ln()ln(

wateroilmoil

water IIII

. ()

Single energy gamma ray attenuation can be used conveniently inliquid/liquid system (oil/water) or liquid/gas system.The basics of the Dual Energy Gamma Ray Absorption (DEGRA)measurement are similar to the single energy gamma ray attenuationconcept, but now two gamma- or X-rays of energies e and e are used.

Electrical impedance methods (capacitance and conductance)The main principle of electrical impedance methods for component fractionmeasurements is that the fluid flowing in the measurement section of thepipe is characterized as an electrical conductor. By measuring the electricalimpedance across the pipe diameter (using e.g. contact or non-contact

electrodes), properties of the fluid mixture like conductance andcapacitance can be determined.

Figure: A typical capacitance/Conductance measurement principleThe conductivity will typically be measured by injecting a known orcontrolled electrical current into the flow, and then measure the voltagedrop between to electrodes along an insulated section of the pipe. Thecurrent can be injected by contact electrodes or in a non-contacting modeby coils (inductive mode). Knowing the current and the voltage drop, theresistance (or conductance) can be calculated using Ohms law. Since alsothe distance between the detector electrodes is known, the measuredresistance can be converted into a conductivity measurement.MPFM Testing and Selecting Method [], []Factory test: The MPFM is tested in the vendor testing facility undercontrolled environment.Independent laboratory Test: The MPFM is tested in independentlaboratory also under controlled environment. The performance andlimitations of the MPFM are well identified.Field test: In this phase the MPFM is tested in the field. In the above twotypes of tests, being under controlled environment do not represent the fieldreality, where the flow regimes, the fluid characteristics, the fluidcompositions and the operating conditions are continuously changing andunpredictable. Thus the field test is fundamental for the evaluation of theperformance of the MPFM. Testing the MPFM in the field is morechallenging as there is no control on certain parameters, like water cut,GVF, salinity etc.Accuracy requirement in the oil producing fieldThe accuracyof a measurement are deemed the most important aspect forany process or equipment. The need for an accurate, reliable tool formeasuring the multi phase flow from oil producing well is a natural growth ofeffort by the oil industry in order to improve its operating efficiencies forbetter reservoir management.

For a proper reservoir management and to ensure a long term sustainableproduction with maximum recovery and taking into consideration thepresent technology performance, as guide line accuracy is required for anoil producing field is mentioned in table .Table. Flow Measurement Accuracies Required in Petroleum Industry []AccuracyRequirements

ReservoirSimulation

ReservoirMonitoring

FieldAllocation

ProcessControl

FiscalMeasurement

OilMeasurement

%5 %4 %2 %5.0 %05.0

WaterMeasurement

%5 %4 %1 %1 -

GasMeasurement

%6 %5 %2 %1 %25.0

Factors Affecting MPFMs Measurement Accuracy []Flow regime effects

The fluid flow from the reservoir passes the bubble point, flows throughvarious flow patterns (horizontal, vertical, inclined, horizontal) till it reachesthe MPFM. Over this journey, various flow regimes are generated, thus,where ever the MPFM is installed, it is subjected to all types of flowregimes. Depending on the type of the technology and the configuration, itwas observed that some MPFMs are more sensitive to flow regimesvariation than others.

Salinity effectIt was experienced that MPFMs using electromagnetic and nuclear sensorsexhibited changes in their oil, water gas readings when confronted with achange in water salinity, especially high salinity and high water cut. Thechange in salinity could change significantly in a short period, depending onthe water cut and could give an inaccurate calibration. Similarly water cutsensitivities to salinity for conductivity and gamma ray absorption methodsis significant. It was experience during the test, the change in water salinityhas tremendous effect on the water cut reading and on the others readings,depending on the type of sensor and the technology.

Fluids' properties effectIn assessing the MPFMs test results, it was apparent that the MPFMs staticand dynamic measurement characteristics are dependent on thetechnology and are affected by the fluid compositions changes and the flowregimes. It was experienced that MPFMs using nuclear sensors exhibitedchanges in their oil, water gas readings, when confronted with a change incertain mineral, which have high atomic number like HS, CO, K, Sr etc.Calibration of MPFMs [], []Most MPFMs are subjected to static calibration and adjustment at thefactory.. It is important to note that a calibration of a measuring instrumentis simply a verification of the meter performance versus (traceable)reference instrumentation.The calibration fluidThere are two alternatives for calibration fluid:

A model system using some sort of model oil, water and air ornitrogen. Most dynamic calibration facilities use a model fluid, for reasons ofcost, working environment, etc. One advantage with model calibration fluidsis that they are normally well behaved and their PVT properties are wellknown. That is, uncertainties regarding PVT properties are reduced to aminimum. The fluid is not representative of the fluid to be measured, interms of density, viscosity (and thus generation of flow regime), dielectricconstants, salinity, mass transfer between the phases, phase surface activecomponents, etc.

A system with live crude, formation water and hydrocarbon gas,with mass transfer between the oil phase and the gas phase. An issue ofusing oil products as calibration fluids is related to the availability of asuitable plant (the cost aspect) and the fact that such plants are built andoperated under a hazardous area regime. Since the properties of wellstreams differ, a specific product used as calibration fluid may not berepresentative of any other product or well stream.Static calibration does not require flowing conditions and is usually doneduring factory test and commissioning on site. Although the static tests willdiffer for each MPFM make, they will have in common that the purpose is toestablish a reference based on a known fluid inside the measurementsection of the MPFM. The factory calibration performed by themanufacturer may consist of measurements of geometric dimensions,gamma-meter count rates and static impedance measurements in

calibration fluids, etc., depending on the working principle of the primarymeasurement elements.Dynamic calibration can be done in different ways and at differentlocations. Regardless of the method, the purpose is to measure the oil,water and gas flow-rates from the MPFM and compare against referenceflow rates. The reference measurement systems used for dynamiccalibrations may vary in size and thus flow-rate capabilities.Factory calibration is a calibration performed by the manufacturer of theinstrument, and the calibration is usually carried out using facilities ownedor controlled by the manufacturer.Factory calibration may be carried out for several reasons: Investigation of the performance of a new type of meter during adevelopment phase.

Calibration (verification) of meters before delivery to customer/user.Field calibration: From a calibration point of view, the main differencebetween an independent laboratory calibration and a Field Calibration isthat representative fluid properties are more likely to be obtained in a fieldtest facility than in a laboratory.In-situ calibration is a calibration performed after the MPFM has beeninstalled at its final location in the field. The aim of in-situ Calibration is toverify the measurement performance of the MPFM compared against theresults from a factory calibration, an independent laboratory calibration or aField Calibration. Some meters may first require an initial static calibrationin-situ using actual well fluids before a dynamic calibration can beperformed.DiscussionDue to the changes in the reservoir behavior and characteristics, thereservoir models require regular updating and history matching. Due to thecomplexity of modeling in todays age, there is a requirement for a faster,accurate and reliable data, in order to adequately update, calibrate andtune. MPFMs are attractive for their fast response, fast deployment andshort duration tests, which provide acceptable data for an accurate andreliable reservoir forecast. In addition, the growing need to increaseproductivity and field development and tie-in of satellite fields to existingprocessing and export facilities (to reduce the capital and operating costs)are leading major operating companies to consider the use of multiphaseflow meters as a better alternative than the test separators.

A MPFM cannot be expected to return phase flow rates with an uncertaintyequivalent to what is obtained from test separator measurements, for allflow rates, from all wells producing to the process plant. This is certainly thecase if in-situ calibration of the MPFM is not available. The response time ofa MPFM, however, is significantly less (minutes) than that of a separator(hours), and more well tests may be carried out using the MPFM.Multiphase flow measurement technology may be an attractive alternativesince it enables measurement of unprocessed well streams very close tothe well. The use of MPFMs may lead to cost savings in the initialinstallation. MPFMs can provide continuous monitoring of well performanceand thereby better reservoir exploitation/drainage. However this technologyis complex and has its limitations; therefore care must be exercised whenplanning installations that include one or more MPFMs. One of thelimitations of the multiphase measurement technology is the uncertainty ofthe measurement. The main source for these higher measurementuncertainties of MPFMs in comparison to single-phase metering systems(for example) is the fact that they measure unprocessed and far morecomplex flows than what is measured by single-phase measurementsystems.ConclusionThe measurement accuracy of the MPFM against the three phase testseparator is satisfactory and met the requirements provided that tool iscalibrated properly.MPFMs are in third generation, their technologies are well established andthe limitations of each technology are well known. Today MPFMs can betailored to suit and meet the challenges of any application with the requiredaccuracy and performance.MPFMs have fast response which is good for transient analysis, providereal time data. They are also provide other opportunities such as welldiagnosis , well optimization, good field allocation, detect early water andgas break through. With all these advantages and benefits, MPFM isconsidered an accurate well testing tool to evaluate the well performanceand is recommended for field optimization requirements.This technologycan be a critical issue on smart field development and field automations.Acknowledgements

The authors thank National Iranian Oil Company (NIOC) and NationalIranian South Oil Company (NISOC) for their help and support during allstages of this project.References. Albusaidi K. H, . An investigation into multiphase flowmeteringtechniques. PhD thesis, University of Huddersfield, UK. . Bekkousha M. et al, , Multiphase flow meters (MFPM)- Field trials andtheir applications in fields; Abu Dhabi Company for Oil Operations (ADCO)UAE SPE , U.A.E., October .. Eivind Dahl, Christian Michelsen, HANDBOOK OF MULTIPHASE FLOWMETERING, The Norwegian Society for Oil and Gas Measurement,Revision , March , ISBN ---, -. Corneliussen, Sidsel, Production-Well-Testing Optimization WithMultiphase Flow meters, BP Norway, Journal of Petroleum Technology,Production Operations, March . Allan Browne, Laurence Abney, An Integrated Approach to CombatingFlow Assurance Problems, SPE Bergen,HALIBURTON, April . see Refference No., -. Busaidi K. and Bhaskaran H. , Petroleum Development Oman (PDO),Multiphase Flow Meters: Experience and Assessment in PDO; SPE was prepared for presentation at the SPE Annual Technical Conferenceand Exhibition held in Denver, Colorado, U.S.A, - October . See Refference No., Pages -. See Reference No., Pages -. See Reference No., Pages -. See Reference No., Pages -. See Reference No., Pages -. See Reference No., Pages -. Haimo Technologies Inc. A Decade at the forefront of Innovation ofMultiphase Well Testing Solutions, HAIMO MFM BROCHURE April