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  1. 1. Manual of Petroleum Measurement Standards Chapter 4-Proving Systems Section 6-Pulse Interpolation SECOND EDITION, MAY 1999 American Petroleum Institute Helping You Get The Job Done R. -”COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  2. 2. STD*API/PETRO MPMS 4.b-ENGL L999 W 0732290 ObLb598 8 7 1 b Manual of Petroleum Measurement Standards Chapter 4-Proving Systems Section &Pulse Interpolation Upstream Segment SECOND EDITION, MAY 1999 4 ’ American Petroleum Institute HelpingYou Get T e J o b h Done R.-”COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  3. 3. STD=API/PETRO MPMS 4.h-ENGL L999 m 0732290 0bLb599 708 b SPECIAL NOTES API publications necessarily address problems of a general nature. With respect to partic- ular circumstances, local, state, and federal laws and regulations should reviewed. be A P I is not undertaking to meet the duties of employers, manufacturers, or suppliers to warn and properly train and equip their employees, and others exposed, concerning health and safety risks and precautions,nor undertaking their obligations under local, state, fed- or eral laws. Information concerning safety and health risks and proper precautions with respect to par- ticular materials andconditions should be obtained from the employer, the manufacturer or supplier ofthat material, or the material safetydata sheet. Nothing contained in any A P I publication is to be construed as granting any right, by implication or otherwise, for the manufacture, sale, use of any method, apparatus, prod- or or uct covered by letters patent. Neither should anything contained in the publication be con- strued as insuring anyone against liability for infnngement of letters patent. Generally, API standards are reviewed and revised, reaffirmed, or withdrawn atleast every five years. Sometimes a one-time extension of upto two years will be addedto this review cycle. This publication will no longer bein effect five years after its publication date as an operative API standard or, where an extension has been granted, upon republication. Status of the publication can be ascertained from the API Upstream Segment [telephone (202) 682- 80001. A catalog of API publications and materials published annually and updated quar- is terly by API, 1220L Street, N.W., Washington, D.C. 20005. This document was produced under API standar&zation procedures that ensure appropri- ate notification and participation in the developmental process and is designated an API as standard. Questions concerning the interpretation of the content of this standard or com- ments and questions concerning the procedures under which this standard was developed should be directed in writing to the general manager of the Upstream Segment, American Petroleum Institute, 1220L Street, N.W., Washington, D.C. 20005. Requestsfor permission to reproduce or translate all or any part of the material published herein should also be addressed to the general manager. API standards are published to facilitate the broad availability of proven, sound engineer- ing and operating practices. These standardsare not intended to obviate theneed for apply- ingsoundengineeringjudgmentregardingwhenandwherethesestandardsshould be utilized. The formulation and publication of M I standards is not intended in any way to inhibit anyone from using any other practices. Any manufacturer marking equipment or materials in conformance with the marking requirements of an API standard is solely responsible complying with all the applicable for requirements of that standard. API does not represent, warrant,guarantee that such prod- or ucts doin fact conform to the applicableP I standard. A All rights reserved. No part of this work may reproduced, storedin a retrieval system, or be transmitted by any means, electronic, mechanical, photocopying, recording, or otherwise, without prior written permissionfrom the publishez Contact the Publishel; API Publishing Services, 1220 L Street, N. W , Washington, D.C. 2000.5. Copyright O 1999American PetroleumInstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  4. 4. STD.API/PETRO MPMS 4.b-ENGL L999 5 0732290 ObLbbOO M FOREWORD Chapter 4 of the Manual o Petroleum Measurement Standardswas prepared as a guide f for the design, installation, calibration, and operationof meter proving systems commonly used by the majority of petroleum operators. The devices and practices covered chap- in this ter may not be applicable to all liquid hydrocarbons under all operating conditions. Other types of proving devices that are not covered in this chapter may be appropriate for use if agreed upon by the parties involved. The information contained in this edition of Chapter 4 supersedes the information con- tained in the previous edition (First Edition, May 1978), which isno longer in print.It also supersedes the information on proving systems contained in I Standard 1101, Meusure- M ment o Petroleum Liquid Hydrocarbons by Positive Displacement Meter (First Edition, f 1960); API Standard 2531, Mechanical Displacement Meter Provers; API Standard 2533, Metering Vïscous Hydrocarbons; and API Standard 2534, Measurement o Liquid Hydrocar- f bons by Turbine-Meter System, which areno longer in print. This publication is primady intended for use in the United States and is related to the standards, specifications, and procedures the National Bureau of of Standards and Technol- ogy (NIST). When the information provided herein used in other countries, the specifica- is tions and procedures of the appropriate national standards organizations apply. Where may appropriate, other test codes and procedures for checking pressure and electrical equipment may be used. For the purposes of business transactions, limits on error or measurement tolerance are usually set by law, regulation, or mutual agreement between contracting parties. publi- This cation is not intended to set tolerances for such purposes; it is intended only to describe methods by which acceptable approaches to any desired accuracy can be achieved. MPMS Chapter 4 now contains the following sections: Section 1, “Introduction” Section 2, “Conventional Pipe Provers” Section 3, ‘‘Small Volume Provers” Section 4,‘TankProvers” Section 5, “Master-Meter Provers” Section 6, ‘‘Pulse Interpolation” Section 7, “Field-Standard Test Measures” Section 8, “Operation of Proving Systems” Section 9, “Calibration of Provers” A P I publications may be used anyone desiring to so. Every effort has been made by by do the Institute to assure the accuracy and reliability of the data contained in them; however, the Institute makes no representation, warranty, or guarantee in connection this publication with and hereby expressly disclaims any liability or responsibility for loss or damage resulting or from its use for the violation of any federal, state, or municipal regulation with which this publication may conflict. Suggested revisions are invited and should be submitted to the general manager of the Upstream Segment, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005. iiiCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  5. 5. STD-API/PETRO MPMS 4.b-ENGL Lqqq 1111 0732290 O b b b b O L &lb m Page O INTRODUCTION ...................................................... 1 1 SCOPE ............................................................... 1 2 DEFINITIONS......................................................... 1 3 REFERENCES ........................................................ 1 4 DOUBLE-CHRONOMETRY PULSE INTERPOLATION ..................... 1 4.1 ConditionsofUse ................................................. 2 4.2 FlowmeterOperatingRequirements ................................... 2 5 ELECTRIC EQUPMENT TESTlNG ...................................... 2 6 FUNCTIONALOPERATIONS TEST REQUIREMENTS ..................... 2 7 TEST ................................................ CERTIFICATION 2 8 MANUFACTURERSCERTIFICATION TESTS ............................ 3 APPENDIXAPULSE-INTERPOLATIONCALCULATIONS ...................5 Figures A-1 Double-ChronometryTiming Diagram .................................. 7 A-2 Certification Test Equipment for Double-Chronometry Pulse Interpolation Systems ........................................... 8 V Previous page is blankCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  6. 6. Chapter 4-Proving Systems Section 6-Pulse Interpolation O Introduction 2.5 meter pulse continuity: The deviation of the inter- pulse period of a flowmeter expressed as a percentage of a Toprovemetersthathavepulsedoutputs,a minimum full pulse period. number pulses of must be collectedduringtheproving period. The prover volume or the number of pulses that a 2.6 nonrotating meter: Any metering device for which flowmeter can produce per volume of throughput often unit is the meter pulse output is not derived from mechanical rota- limited by design considerations. Under these conditions it is tion as driven by the flowing stream. For example, vortex necessary to increase the readout discrimination of the flow- shedding,venturi tubes, orificeplates,sonicnozzles,and meter pulsesto achieve an uncertainty of 0.01%. ultrasonic electromagnetic and flowmeters metering are The electronic signal from a flowmeter can be treated so devices for which the output derived from some character- is thatinterpolationbetweenadjacentpulsescanoccur.The istic other than rotation thatproportional to flow rate. is technique of improving the discrimination of a flowmeter’s output is known as pulse interpolation. Although pulse-inter- 2.7 pulse period: The reciprocal of pulse frequency, i.e., polationtechniqueswereoriginallyintended for usewith a pulse frequency of 2 hertz, is equal to a pulse period ofl/2 small volume provers, they can be applied to other prov- also seconds. ing devices. 2.8pulsegenerator: An electronic devicethatcan be The pulse-interpolation method known as double- programmed to output voltage pulses of a precise frequency chronometry, described in this chapter, is an established or time period. technique used in proving flowmeters. As other methods of pulse interpolation become accepted industry practice, 2.9 pulse interpolation: Anyofthevarioustechniques they should receive equal consideration, provided that bywhichthewholenumber of meterpulses is counted they can meet the established verification tests and spec- between two events (such as detector switch closures); any ifications described in this publication. remaining fraction of a pulse betweentwo eventsis calcu- the lated. 1 scope 2.10 rotating meter: Any metering device for which the This chapter describes how the double-chronometry method meter pulse output is derived from mechanical rotation as ofpulseinterpolation,includingsystemoperatingrequire- driven by the flowing stream. For example, turbine and posi- ments and equipment testing,applied to meter proving. is tive displacement meters are thosemeteringdevices for which the output is derived from the continuous angulardis- 2 Definitions placement of a flow-driven member. 2.1 detector signal: Acontactclosurechange or other 2.11 signal-to-noise ratio: The ratio of themagnitude signal thatstarts or stops a prover counter timer and defines or of the electrical signal that of the electrical noise. to the calibrated volume of prover. the 3 References 2.2double-chronometry: A interpolation pulse tech- niqueusedtoincrease the readoutdiscriminationlevelof The current editions of the following standards are cited in flowmeter pulses detected between prover detector signals. this chapter: This is accomplished by resolving these pulsesinto a whole API number of pulses plus a fractional part of a pulse using two MPMS Chapter 4, Proving Systems Section 3, “Small Vol- high speed timers and associated gating logic, controlled by ume Provers” the detector signals and flowmeter pulses. the Chapter 5, Metering Section 4,“Instrumentation andAux- 2.3 flowmeter discrimination: A measure of the small- iliary Equipment for Liquid Hydrocarbon est increment of changein the pulses per unit volume the of MeteringSystems”,Section 5 , “Security volume being measured. and Fidelity of Pulse Data” 2.4 frequency: The number of repetitions, or cycles, of a periodic signal (for example, pulses, alternating voltage, or 4 Double-ChronometryPulse current) occurring in a 1-second time period. The number of Interpolation repetitions, or cycles, that occur ina1-secondperiod is Double-chronometry pulse interpolation requires counting expressed in hertz. the total integer (whole) number of flowmeter pulses, N,, 1COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  7. 7. 2 PROVING SYSTEMS MPMS CHAPTER generatedduring the proving run andmeasuring the time a. If the pulse repetition rate at constant flow rate cannotbe intervals, Tl and Tz. T1 is the time interval between the first maintained within the limits given in MPMS Chapter 4.3, flowmeter pulse after the first detector signal and the fìrst then the flowmeter can be used with a pulse-interpolation sys- flowmeter pulse after the last detector signal. T2 is the time tem only at a lower overall accuracy level. In this case, a interval between the first and last detector signals. revised calibration accuracy evaluated or multiple runs with The pulse counters,or timers, arestarted and stopped by the averaging techniques. signals from prover detector detectors. The time intervals the or b. The meter pulse continuity in rotating flowmeters should Tl, corresponding to Nm pulses, and Tz, corresponding to the be in accordance with MPMS Chapter 4.3. The generated interpolated number of pulses( N ] ) , are measured by an accu- flowmeter pulse can be observed by an oscilloscope, whose rate clock. The interpolated pulse count is given as follows: time base is set to a minimum of one full cycle, to verify meter pulse continuity the flowmeter. of be c. The repeatability of nonrotating flowmeters will a func- tion ofthe rate of change in pulse frequency at a constant flow The use of double-chronometry in meter proving requires rate. To apply pulse-interpolation techniques to nonrotating that the discrimination ofthe time intervalsT1 and T2 be bet- flowmeters, meter the pulsecontinuity the of flowmeter ter than 2 0.01%. The time periodsT1 and T2 shall therefore should be in accordance with MPMS Chapter 4.3 to maintain be at least 20,000 times greater than the reference period Tc of the calibration accuracy. the clock that used to measure the time intervals. The clock is d. The size and shape of the signal generated by the flow frequency Fc must be high enough to ensure that both the T1 meter should be suitable for presentation pulse-interpo- to the and T2 timers accumulateat least 20,000 clock pulses during lationsystem. I necessary, signal f the should undergo the prove operation.This is not difficult to achieve, current as amplification and shaping before enters the pulse-interpola- it electronics technology used for pulse interpolation typically tion system. uses clock frequencies the megahertz range. in 4.1CONDITIONS OF USE 5 ElectronicEquipmentTesting The proper operation of pulse interpolation electronics is Theconditionsdescribedin4.6.2.1.1through4.6.2.1.3 crucial to accurate meter proving. A functional field test of apply to double-chronometry pulse interpolation as described the total system should be performed periodically to ensure in this chapter. that the equipment is performing correctly. This may simply 4.1.1 The interpolated number of pulses, N I , will not be a be a hand calculation verifying that the equipment correctly whole number. N1 is therefore rounded off as described in calculates the interpolated pulses per 4.6.2, or if need be, a MPMS Chapter 12.2,Part 3. section 3.12 of complete certification test as described in 4.6.3.2. if a prob- lem is suspected. 4.1.2 Pulse-interpolation methods on are the based assumptions that actual flow rate does not change substan- 6 FunctionalOperationsTest tially during the period between successive meter pulses, and Requirements each pulse represents the same volume. To maintain the valid- ity of this assumption, the short period fluctuations flow in the Normal industry practiceis to use a microprocessor based rate during the proving operation shall be minimized. provercomputertoprovidethepulseinterpolationfunc- tions. The prover computer should provide diagnostic data 4.1.3 Because pulse interpolation equipment contains high displays or printed data reports which show the value of all speed counters and timers, it is important that equipment be parameters and variables necessary to verify proper operation installed in accordance with the manufacturer’s installation of the system by hand calculation. These parameters and vari- instructions, thereby minimizing the risk of counting spurious ables include, but are not limited to, timers T1 and T2, the pulses caused by electrical interference occurring during the number of whole flowmeter pulses N , and the calculated proving operation. The signal-to-noise ratio of the total sys- interpolated pulsesN I . tem shall be adequately high to ensure that typical levels of Using the diagnostic displays provided, the unit should be electricalinterferencearerejected.RefertoChapter5.4, functionally tested by performing a sequence of prove runs Chapter 5.5, and other sections of Chapter for more details. 4 and analyzing the displayed printed results. or 4.2FLOWMETEROPERATINGREQUIREMENTS 7 CertificationTest The flowmeter that is being proved and is providing the Certification tests should be performed the prover com- by pulses for the pulse-interpolation system shall meet the fol- puter manufacturer prior shipment of the equipment, and if lowing requirements: necessary, by the user on a scheduled basis, or as mutuallyCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  8. 8. STD.API/PETRO MPMS Ymb-ENGL L999 m 0732290 OblbbOY IT5 m &PULSE INTERPOLATION SECTION 3 agreed upon by all interested parties. The certification tests (K Flowmeter frequencyF, produced by flowmeter Factor provided in this chapter do not preclude the use other tests of lo00) at 3000 barrels per hour: that may be performed on an actual field installation. = 3000x1000/3600 A block diagram of the certification test equipmentpro- is vided in Figure A-2. F, = 833.33333 hertz. An adjustable, certified, and traceable pulse generator with an output uncertaintyequalto or lessthan 0.001% is in- The calculated interpolated flowmeter pulses NI are sim- stalled that provides an output signal of frequency simu- F,,,, ply the simulated flowmeter frequency F,,, times the simu- lating a flowmeterpulse train.This signal is connected to the lated volume time Tz. flowmeter inputof the prover flow computer. A second adjustable, certified, and traceable pulse genera- = 833.33333 X 0.676875 tor with an output uncertainty equal or less than0.001% is to N ] = 564.0625 installed that provides an output pulse signal separated by time period Tz, simulating the detector switch signals. This Verify the actual results displayedor printed by the prover signal is connected to the detector switchinputs of the prover are computer undertest, ensuring that they within & 0.01% of computer. the calculated value. The pulse interpolation function is more critical when there It is possible to select a simulation frequency F,,, above are fewer flowmeter pulses collected between the detector whose pulse period is an exact multiple of time period T i , switches. Set the output frequency of the first generator to therebysynchronizingthesimulatedflowmeterpulsesand produce a frequency equal the flowmeter thathas the low- to detector signals. If this is the case, it will be necessary to est number of pulses per unit volume to be proved with the modify either the simulated flowmeter frequency Fm, the or equipment, at the highest proving flowrate expected. simulated detector switch period T2 slightly to ensure thatthe also The pulse interpolation function is more critical when interpolated pulses will include a fractionalpart of a pulse. there are fewer clock pulses collected between the detector switches. Set the pulse period of the second generator to prcr 8 ManufacturersCertificationTests vide a volume time, T2, equal to that which would be pro- Certification tests should be performeda number of sim- at duced by the prover detectors at the fastest proving flowrate ulatedconditions.Theseconditionsshouldencompassthe expected. prover devices range of prover volume times, Tz, and flow- Example: A small volume prover with a waterdraw volume meter pulse frequencies,F,. The manufacturer must provide, of 0.81225 barrels will be used to prove a turbine meter (K on request, atest certificate detailingthe maximum andmini- Factor 1000 pulses per barrel) at a maximum 3000 barrels of mum values of prover volume time, Tz, and flowmeter fre- per hour. quency, F,, that the equipment is designed accept. to are If the pulse-interpolation electronics tested and verified Volume time T2 for 0.81225 barrels at 3000 barrels per using the equipment and procedures shown, they canused be hour: during a flowmeter proving operation with confidence that = 3000 x 0.81225 / 3600 they will contribute an uncertainty of less than 0.01% to the overall uncertainty of the proving operationswithin the pulse- T2 = 0.676875seconds signal-frequency range tested.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  9. 9. A.l General prover volume), in seconds = 2.43917 (Cm-Tz). The double-chronometry method of pulse interpolation is described in 4.6.2. Figure A-1 is a diagram of the electrical I the required pulse-interpolation uncertainty f is better than signals required for the technique. The technique provides the 2 0.01%. then numerical data r e q u i d to resolve a fractional portion of a 100,000 > (20,000/200 pulses)(520 hertz), singlewholeflowmeterpulse.Double-chronometrypulse interpolationrequiresusingthefollowingthreeelectrical > (100)(520), 52,000. counters: CTR-N, to count whole flowmeter pulses,CTR-T1 to count the time required to accumulate the whole flowmeterNote: Theperiod of the clock is the reciprocal of the frequency,T = pulses, and CTR-T2 to count the time between detector sig- /F. Theperiod of 1 clock pulse is therefore l / l ~ , m or hertz, nals, which define the displaced prover volume. O.oooO1 second.The discrimination of the clock is 2.43914, or O.o004%. The requirement for value of F, and thediscrimination the The double-chronometry technique reduces the total num- requirement in 4.6.2 are thereforesatisfied. ber of whole flowmeter pulses normally required for the dis- placed fewer volumeto than 10,000 to achieve a To calculate the interpolated pulses, discrimination uncertainty of 0.02% 0.01% of the average) (A N1 = (2.43917 / 2.43914)(200), for a proof run. The required timelpulse discrimination guidelines are pre- = (l.ooo01)(200), sented in 4.6.2 and shall used in conjunction witha prover be = 200.002. designed in accordance with the sizing parameters described in MPMS Chapter 4.3. A.23 EXAMPLE 2"CERTIFICATION The examples given in A.2, which conform to the guide- CALCULATION lines in 4.6.2, each represent single caseof defined data and a are not necessarily representativeof all available pulse-inter- Using equipment as shown in Figure A-2, the following polation methods. data applies: Simulated data: A.2 Examples F= , pulse frequency of generator number one simu- lating meter pulses, in hertz A.2.1 EXAMPLE 1-INTERPOLATED PULSE = 233.000. CALCULATION T2 = pulse period of generator number two simulat- The following data given: are ing detector signals, in seconds = 1.666667. F, = clock frequencyused to measure the time inter- Observed data at prover computer being tested > vals, in hertz (20,000/N1)Fm. N , = number of whole flowmeter pulses F, = flowmeter pulse output frequency (thex - m i a = 388. mum value for analysis), in hertz T1 = number of clock pulses accumulated during = 520. whole flowmeter counts , N Nm = total number of whole flowmeter pulses = 166,523. = 200 (CTR-Nd. T2 = number of clock pulses accumulated during NI = number of interpolated flowmeter pulses simulated prove volume = 166,666. = (T2/T1)Nm Note that both timers T1 and T2 accumulated > 20,000 T1 = time interval counted for the whole flowmeter clock pulses, satisfying the discrimination requirement pulses (N) in seconds detailed in 4.6.2. = 2.43914 (Cm-Tl). Comparison of results: T2 = time interval between the first and second vol- N1 = calculated interpolated pulses basedon certi- ume detector signals (that is, the displaced fied pulse generators, 5 Previous page is blankCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  10. 10. STD-API/PETRO MPMS 4 o h - E N G L lq7q H 0732290 O h l b h O b 778 m 6 MPMS CHAPTERPROVING SYSTEMS = F,xT2, agreement certification testThe required between N1 and NI, is betterthan 20.01%. then = 233 x 1.666667, = 388.33341. (N1 - N1 j/Nl< O.OOO1 interpolated pulses based on prover N1 = calculated (388.33341 - 388.33319)1388.33341 = 0.0000005 computer observations, The test device results agree with calculated results based = N m (T21Tl>, on traceable generator pulse data within O.ooOo5%. The certi- = 388 X 166666/166523, fication testrun is acceptable. = 388.33319.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  11. 11. STDeAPI/PETRO MPMS 4.b-ENGL L999 W 0732270 Ob16607 b04 W SECTION &PULSE lNTERPolATlON 7 Cu ò c $ c o" H - ò c V m c o" 1 Figure A-1-Double-Chronometry Timing DiagramCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  12. 12. 8 &PROVING CHAPTER MPMS SYSTEMS E L Figure A-2-Certification Test Equipment for Double-Chronometry Pulse Interpolation SystemsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  13. 13. The American Petroleum Institute providesadditional resources and programs to industry which are based on E I Standards. For more information, contact: Training and Seminars Ph: 202-682-8490 Fax: 202-682-8222 Inspector Certification Programs Ph: 202-682-5161 Fax: 202-962-4739 American Petroleum Institute Ph: 202-962-4791 Quality Registrar Fax: 202-682-8070 Monogram Licensing Program Ph: 202-962-4791 FLY: 202-682-8070 Engine Oil Licensing and Ph: 202-682-8233 Certification System FLY: 202-362-4739 Petroleum Test Laboratory Ph: 202-682-8064 Accreditation Program Fax: 202-962-4739 ln addition, petroleum industry techcal, patent, and business infomation is available online through API EnCompass”. Call 2 12-366-4040 or fax 212-366-4298 to discover more. To obtain a free copy of the API Publications, Programs, andServices 1T) American Petroleum Catalog, call 202-682-8375 or fax your 1 Institute request to 202-962-4776. Or see the online interactive version of the catalog Hebinel You on our World WideWeb site - G e f T ë Job h Done Right. http://www.api.org.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  14. 14. Additional copies available from API Publications and Distribution: (202) 682-8375 Informationabout Publications, API Programs Services and is available on the World Wide Web at: http://www.api.org American 1220 L Street, Northwest Petroleum Washington, D.G. 20005-4070 Institute 202-682-8000 Order No. H06042COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services

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