Manual of Petroleum Measurement Standards Chapter 6.1A

Manual of Petroleum Measurement Standards Chapter 6.1A Metering Assemblies General Considerations DRAFT EDITION, Xxxxxx 2017

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1 Scope This standard is part of a set of documents which detail the minimum requirements for Metering Systems in single phase liquid applications; Chapter 6.1A is common to all sections of Chapter 6 and specifies the common requirements for system criteria. 1.1 Application Sections of chapter 6 describe metering system design. This section describes general considerations which are applicable to all metering systems. This series of documents detail the minimum requirements for the design, installation, calibration, and operation of a single phase liquid metering system used for custody transfer. The system shall determine volume (or mass) and quality, provide for fail-safe and tamperproof operation, and meet requirements of uncertainty and dependability as agreed by all concerned parties. Many aspects of instrumentation in a metering system for single phase liquids are considered at length in other Chapters of this manual and are referenced in Section Error! Reference source not found.. 1.2 Order of precedence In the event of a conflict between this and other API MPMS Chapter 6 sections, section 6.1A shall take precedence. 2 Normative References The following referenced documents are indispensable for the application of this document. For dated references, only the edition cited applies. For undated references, the latest edition of the referenced document (including any amendments) applies. API MPMS Chapter 4, Provers (All Sections) API MPMS Chapter 5, Metering (All Sections) API MPMS Chapter 8, Sampling (All Sections) API MPMS Chapter 8.1, Manual Sampling of Petroleum and Petroleum Products API MPMS Chapter 8.2/ASTM D4177, Automatic Sampling of Petroleum and Petroleum Products API MPMS Chapter 8.3/ASTM D5854, Mixing and Handling of Liquid Samples of Petroleum and Petroleum Products API MPMS Chapter 9, Density Determination (All Sections) API MPMS Chapter 10, Sediment and Water (All Sections) API MPMS Chapter 11, Physical Properties Data (Volume Correction Factors) API MPMS Chapter 11.5, Density/Weight/Volume Intraconversion Tables API MPMS Chapter 12, Calculation of Petroleum Quantities (All Sections) API MPMS Chapter 12.2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods & Volumetric Correction Factors API MPMS Chapter 14.1, Collecting and Handling of Natural Gas Samples for Custody Transfer API MPMS Chapter 21.2, Electronic Liquid Volume Measurement Using Positive Displacement and Turbine Meters GPA 2186-14, Method for the Extended Analysis of Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Temperature Programmed Gas Chromatography ASME PTC 19.3, Thermowells, 2010

3 Terms and Definitions For the purposes of this document, the most recent definitions from API MPMS Ch. 1 apply. Terms of more general use may be found in the API MPMS Chapter 1 Online Terms and Definitions Database. 3.1 Correction for Pressure on Liquid (CPL) Compensates for the effect of pressure on a liquid. 3.2 Correction for Temperature on Liquid (CTL) Compensates for the effect of temperature on a liquid. 3.3 Gross Volume (GV) The actual volume of fluids at flowing temperature and pressure. 3.4 Gross Standard Volume (GSV) The gross volume (GV) or gross observed volume (GOV) corrected to base temperature and pressure conditions. 3.5 Indicated Volume (IV) The transferred quantity, in indicated (uncorrected) volume units, at operating conditions, that occurs between opening and closing gauges on a tank, during a meter proving with each run, or that occurs from start to stop of a receipt or delivery being measured by a flow meter. 3.6 LPG A gas that is predominantly propane, butane, propylene or butylene, either separately or in mixtures, with limited amounts of hydrocarbons and inert gases, which are maintained in a liquid state under pressure and/or at reduced temperature. 3.7 Meter Factor (MF) A factor used to correct the indicated volume (IV) of the meter at operating conditions to the gross volume (GV) of the meter at operating conditions. 3.8 Net Standard Volume (NSV) The gross standard volume (GSV) corrected to exclude non-merchantable components such as sediment and water (S&W). 3.9 Resistance Thermometer (RTD) A temperature measuring device that operates on the principle of a change in electrical resistance in wire as a function of temperature. 3.10 Sediment and Water (S&W) Material that coexists with, yet is foreign to, a petroleum liquid. S&W may include dissolved water, free water, and sediment, and emulsified water and entrained or suspended sediment and water. 4 Unit of measure 4.1 General Metering systems can utilize different types of units of measure. The International System of Units (SI) and US Customary (USC) units are commonly used within the petroleum industry..

Whichever units of measure are used, all calculations of quantities shall conform to the appropriate sections of API MPMS Ch. 11 and API MPMS Ch. 12. Note in particular, API MPMS Ch. 11.5 details criteria for the calculation of quantities and qualities requiring unit conversions. 4.2 Base conditions Since volumes change with differences in temperature and pressure, common reference conditions are defined for custody transfer volumes. These reference conditions may be at standard temperature and pressure (standard conditions), base conditions defined by contract or regulation such as standard temperature and liquid equilibrium vapor pressure, or some other defined reference conditions. As noted in 4.1 above, all calculations of quantities and qualities shall conform to the appropriate sections of API MPMS Ch. 11 and API MPMS Ch. 12. For fluids whose vapor pressure at the reference temperature is greater than atmospheric, the reference pressure shall be the equilibrium vapor pressure at the reference temperature. See API MPMS Ch. 12. 5 Measurement Ticket Essentials 5.1 General How a ticket (also called Quantity Transaction Record, Batch Ticket, or Measurement Ticket) is calculated is dependent upon the type of meter used (volumetric or mass) and the quantity units used on the ticketing. The method determines the required equipment. 5.2 Calculation of Petroleum Quantities Electronic liquid measurement, where used, shall be in accordance with API MPMS Ch. 21.2. The primary output of flow meters is expressed as pulses per unit of measurement, either volume or mass. Metering systems should be configured so as to provide the information required for proper ticketing and such other information as the user may require. Tables 1 and 2 detail the inputs/equipment that would be necessary to provide the information. For each section marked for the particular application, refer to the appropriate sections below in this document. Table 1 Volumetric Meter (Pulse per Unit Volume) Quantity to be S&W (Crude) Meter Temp Meter Press Density Prover Calculated Gross Mass required required required required Net Mass required required required required required (API MPMS Ch.12) Gross Volume required Gross Standard required required required required Volume (API MPMS Ch. 12) Net Standard Volume (API MPMS Ch. 12) required required required required required

Table 2 Mass Meter (Pulse per Unit Mass) Quantity to be S&W Meter Temp Meter Press Base Prover ** Calculated Density Gross Mass required Net Mass required required (API MPMS Ch. 12) Gross Standard required required Volume Net Standard Volume required required required ** Prover requirements for accessories (pressure, temperature and density) are detailed in API MPMS Ch. 4. 5.2.1 Component Breakdown If the total quantity transferred is required to be split into component quantities then additional analysis of the composition will be required. Composition shall be determined using the samples obtained from the techniques described in API MPMS Ch. 8 and API MPMS Ch. 14.1. The samples shall be analyzed in accordance with the appropriate API, GPA or ASTM test method (e.g. GPA 2186, GPA 2177) 5.3 Volume/Mass Primary measurement devices A means shall be provided to determine the quantity of commodity transferred. This section describes the benefits of the selection of either volume or direct mass measurement for metering system applications. Details of specific applications can be found in the other sections of API MPMS Chapter 6. Details of the description of volume or mass meters, in addition to their strengths and weakness, are included in the relevant sections of API MPMS Ch. 5. 5.3.1 Volume Primary Measurement Volumetric methods of measurement are generally used where physical property changes in temperature and pressure are known and correction factors can be applied to correct the measurement to standard conditions. Readers are referred to API MPMS Ch. 11 for more specific guidance regarding volume correction factors for these commodities. Inferred Mass method of measurement uses a volumetric meter with flowing density to arrive at a mass measurement. Like direct mass measurement, inferred mass measurement is likely to be considered when the PVT relationship is not understood, refer to paragraph 5.2.2 on Mass primary measurement devices for discussion of benefits. 5.3.2 Mass Primary Measurement Mass measurement is likely to be considered when the PVT relationship is not well understood, there are no accepted industry standards for volume corrections and where volumes are highly sensitive to changes in pressure, temperature or both. It has been recognized that measuring Liquefied Petroleum Gas (LPG) mixture, such as: NGL, Ethane Propane Mix or Refinery Grade Propylene, using mass measurement techniques is important. The volume at standard conditions of each component of an LPG mixture may be accurately derived from the mass measurement process because, unlike volumetric measurement, the mass measurement process is not sensitive to the effect of pressure, temperature, intermolecular adhesion, and solution mixing have on the measured stream. Refer to API MPMS Ch. 5.6 for guidance on the use of Coriolis meters and the requirements for pressure and temperature compensation of the meter mechanics. Volumetric shrinkage can occur when smaller molecules fill in the spaces between the larger molecules in the solution.

Temperature and pressure can affect the volumetric shrinkage. Due to these behaviors, the sum of the volumes of individual components in their pure state is greater than the volume of the mixture. Refer to API MPMS Ch. 12.3 for further discussion and calculation guidance on volumetric shrinkage. Readers are referred to API MPMS Ch. 14.7 (GPA 8182) for more specific instruction and guidance regarding mass measurement of mixed LPG s and conversion of measured mass to equivalent volume, refer to API MPMS Ch. 14.4 (GPA 8173). 5.3.3 Output Signal Meter output shall be in alignment with API MPMS Ch. 5. 5.3.4 Operating Flow Range Each type of meter has design considerations which limit the flow range across which the meter should be operated. Refer to API MPMS Ch. 5 for the limitations of each. A metering system with a required flow range that exceeds the capacity of a single meter should be equipped with multiple meter runs. In some cases, the additional capital and operational costs associated with additional meter runs may be outweighed by the benefit of a smaller sized prover. 5.3.5 Accuracy Meters that are chosen, installed, operated, and maintained in accordance with API MPMS Ch. 5 as well as proved in accordance with API MPMS Ch. 4 are considered meeting the accuracy requirements for custody transfer. 5.3.6 Location The meter shall be installed away from items which affect meter performance. To determine if flow conditioning is recommended refer to API MPMS Ch. 5. The meter shall also be located such that the pressure is maintained above the liquid equilibrium vapor pressure. The requirements are detailed in API MPMS Ch. 5. 5.3.7 Meter Proving A meter in service should be periodically proved to confirm its accuracy. A prover shall only be used to prove one meter at a time. Proving devices, methods and operations shall be in accordance with API MPMS Ch. 4. An improper pairing of a prover and meter may result in proving issues. Proper pairing requires consideration of repeatability and its effects on prover volume requirements. Meter response time also affects prover pre-run requirements. Failure to properly pair a prover to a meter may result in reproducible and repeatable meter factors which are inaccurate. For guidance on the location of the prover in relation to the meter under test, and other specific requirements for proving refer to the relevant API MPMS Chapter 6 sections for specific requirements. Refer to API MPMS Ch. 4.8 for determination of proving frequency, method and accuracy. In addition, the meter and all of its associated equipment (such as gear trains, registers, compensators, and counters) should be maintained in good working order, both mechanically and electrically. The meter should also be inspected whenever its performance is in question, if mechanical or electrical problems exist, or as required by contract or regulations.

The meter should be operated in the linear portion of its performance curve and the prover should be operated within its flow rate limitations. The meter should be proved as close as practical to the same conditions under which it normally operates. Meter performance is dependent upon flow rate for a given fluid and operating condition. Therefore, during proving it is essential that flow rate be maintained as steady as possible. Including a proving device in the flow path will increase the pressure loss along the route. Flow rate may decrease depending on the pumping capacity. The conditions under which a meter is proven are listed in API MPMS Ch. 4.8. The meter factor of a flowmeter may be dependent on temperature, pressure, composition, flow rate or other process factors. To reduce external temperature effect on meter performance, insulation of the prover and metering sections may be necessary. For additional information, refer to API MPMS Ch. 4.2. The variation of the meter factor as a function of mentioned parameters may be significant; hence, it may be necessary to prove the meter at the changed process conditions. Usually, meters which will be operated outside of their linear range will require proving at more than one flow rate to ensure the meter factor represents the flow conditions observed. The method of applying multiple meter factors, table method or meter factor linearization, to a measurement ticket is further discussed within the relevant API MPMS Chapter 6 sections and the calculation method is discussed in API MPMS Ch. 21.2. While there are benefits from applying an applicable factor for the current flowing conditions, the ability to audit the ticket calculations will be lost. Further, a meter which is used for multiple commodities should be proved for each commodity and the meter factor per commodity used in calculation of flow. Using a single meter factor in process conditions which vary can result in higher uncertainty in measurement. For specific meter considerations for proving refer to API MPMS Ch. 5. The result of the meter proving is the meter factor which is incorporated into a ticketed quantity. The calculation of meter factor shall be in accordance with API MPMS Ch. 12.2. 5.4 Secondary Measurement Devices As discussed above in 5.2, temperature, pressure, density and S&W measurements may be required. 5.4.1 Temperature A volumetric measurement ticket requires fluid temperature at the meter so that changes in the fluid density may be corrected to base conditions by calculation. 5.4.1.1 Design The device used for temperature determinations should be based on measuring conditions and operating requirements. The most commonly used temperature sensor is an RTD, which may be wired directly into a flow computation device or to a temperature transmitter. Refer to API MPMS Ch. 7 for further details. The recorded temperature on a ticket should be indicative of the weighted average temperature over the batch. There are numerous method/options for recording temperature in dynamic metering systems, but the recommended method or system is to have a live electronic based indicator with "flow weighted average" temperature recorded for the transaction (Refer to API MPMS Ch. 21.2 and Ch. 12). Other options, such as Electronic Live Measurement of the temperature with time based average (Refer to API MPMS Ch. 21.2 and Ch. 12) and Mechanical Live Measurement of the temperature, can be used but may result in increased uncertainty. Time based averaging will introduce error with changes in flow rate. 5.4.1.2 Output Signal The output of the device may be either analog or digital. Refer to API MPMS Ch. 7 for guidance on the output method.

5.4.1.3 Span Temperature devices shall be ranged to accommodate all operating temperatures throughout a batch. 5.4.1.4 Accuracy Temperature devices used for metering shall be the highest practical accuracy as recommended in API MPMS Ch. 7. 5.4.1.5 Location The temperature recorded on a meter ticket should be indicative of the temperature at the meter. An incorrect temperature probe location that results in a value just 1 F different than the temperature at the meter will bias a crude or refined product volume by 0.05 %.. The ideal location is dependent upon the meter type and the application. The location along the pipe relative to the meter is defined by relevant sections of API MPMS Chapter 6. The location relative to the prover is defined by API MPMS Ch. 4.2, Ch. 4.4, and Ch. 4.5. The placement of the temperature sensor within the cross section of the flowing stream is critical to accurate temperature measurement. Refer to API MPMS Ch. 7. Caution should be taken to minimize the effects of ambient temperature on the thermowell and sensor. The temperature difference between ambient and flowing conditions will have an adverse effect on the determination of measurements. The impact is greater for low velocity and smaller diameter flows. Increasing the surface area within the flowing stream reduces the impact, such as using angle thermowells. Insulating the thermowell from ambient conditions also reduces the impact. To provide the fastest thermal response: 1. The thermowell should be filled with an appropriate amount of heat-conducting material, and 2. Spring-loaded RTD probes (typically 316 SS) that maintain contact between the probe tip and the thermowell, which improves heat transfer, should be used. For further details Refer to API MPMS Ch. 7. The design of the thermowell shall not induce a wake frequency which will excite its own natural vibration frequency. Refer to ASME PTC 19.3 TW. 5.4.1.6 Calibration/Verification The requirements for the verification and calibration of temperature instruments used on measurement tickets are defined by API MPMS Ch. 7. A test thermowell, filled with an appropriate amount of heat-conducting material, should be located immediately adjacent to the temperature instrument (typically no more than 18 in.) 5.4.2 Pressure A volumetric measurement ticket requires fluid pressure at the meter so that changes in the fluid density may be corrected to base conditions by calculation. 5.4.2.1 Design The pressure measuring device should be selected based on measuring conditions and operating requirements. The pressure used for compensation calculations in a transaction should be indicative of the weighted average pressure of the batch. Options for compensation, in order of best practice are: 1. Electronic Live Measurement (Refer to API MPMS Ch. 21.2 and Ch. 12)

a. Flow weighted average b. Time based average 2. Fixed Value a. Fixed CPL value b. Composite Meter Factor (CMF) c. Over-ride value in flow computer For locations with stable pressure a fixed value may be used. The fixed value may be applied by applying a CMF or by forcing a value into the computations, see API MPMS Ch. 12. The error introduced in the final ticketing determination from using a fixed value for pressure should be reviewed. For example, for pentane, a 50 psi error will result in a 0.042 % change in the volume determination. For ethane at 40 F, a 5 psi error will result in a 0.063 % change in the volume determination, and 0.64% for a 50 psi error. For crude, a 5 psi error will result in a 0.002 % change in the volume determination. Refer to API MPMS Ch. 12.2 for the equation of CMF. When the pressure varies, the pressure compensation shall make use of a live measurement. A weighted average pressure shall be used for post-batch calculations. The weighted average pressure may be calculated using either the time or flow weighting method. If the flow rate varies, the flow weighted method shall be used. See API MPMS Ch. 12. 5.4.2.2 Output Signal The output of the transmitter may be either analog or digital. 5.4.2.3 Span Pressure devices shall be ranged to accommodate all operating pressures throughout a batch. Excessively spanned instruments will negatively impact measurement accuracy. 5.4.2.4 Accuracy For fixed measurements the maximum allowable error introduced to the final ticketing determination shall be per agreement of the buyer and seller. For live measurements a Pressure Transmitter shall be used and shall be the highest practical accuracy. 5.4.2.5 Location The ideal location is dependent upon the meter type and the application. The location along the pipe relative to the meter is defined within the relevant sections of API MPMS Chapter 6. The location relative to the prover is defined by API MPMS Ch. 4.2, Ch. 4.4 and Ch. 4.5. 5.4.2.6 Calibration/Verification The pressure transmitter installation shall provide a means for calibration/verification; for example through the use of manifolds and/or valves. For guidance on accuracy of calibration/verification devices refer to API MPMS Chapter 21.2. For guidance on frequency of calibration/verification refer to API MPMS Chapter 21.2.

5.4.3 Density Changes in density of the fluid will change the calculated base volume. The impact of changing density on the base volume varies with the type of fluid. The following methods can be used for the determination of observed density and can be used to calculate base density. Refer to API MPMS Ch. 11 and 12.2 for guidance on the calculation method.. Additionally, density is not only important in the calculation of quantity, but is also used in the determination of quality. 5.4.3.1 Design The density measuring device should be selected based on measuring conditions and operating requirements. The method of determination of density over the batch should be in alignment with API MPMS Ch. 9. The methods shown in Table 3 can be used for the determination of observed density and can be used to calculate base density. Table 3 Method options to obtain base density Density determination method Sampling Observed Temp Observed Press Mass Observed Density Calibration Online density meter API MPMS Ch. 9 required required required required Coriolis Meter Density Pycnometer Hydrometer from sample Digital density meter from sample API MPMS Ch. 9 API MPMS Ch. 9.4 API MPMS Ch. 9 ASTM D1250, D4052, D4805, D5002, D5931, D7777 API MPMS Ch. 9.4 API MPMS Ch. 8.1/8.2 ASTM D3700 required required required required required required required required required required required required required required required required EOS (Equation of State) Fixed value assumed API MPMS Ch. 14.5, 14.2 Assumed or known composition Sampled sometime in past required required required required For any application where the density is measured at conditions other than the reported conditions the temperature and pressure of the density measurement shall be noted. The requirements for pressure and temperature determinations for the purposes of density are the same as those for the primary measurement. See Table 3.

When samples are used to determine the density then the sample shall be obtained in accordance with either: a. Spot manual sample (API MPMS Ch. 8.1) b. Automatic sample (API MPMS Ch. 8.2) And be in alignment with API MPMS Ch. 8.3 for sample handling and mixing. 5.4.3.2 Accuracy The overall density accuracy is affected by the quality of the sample, the accuracy of the density test method and the accuracy of the pressure and temperature determinations of the observed conditions. The overall density uncertainty used for volumetric measurement tickets should be better than ± 0.5%. The overall density uncertainty used for inferred mass tickets should be better than ± 0.1%. Relative densities in the units of degrees API cannot use a percentage accuracy tolerance. 5.4.3.3 Location The location of a density meter for the measurement of continuous density is defined by API MPMS Ch. 9.4. The location of density determinations by sample shall be indicative of the batch. The location is defined by API MPMS Ch. 8 5.4.3.4 Calibration/Verification Online density meters calibration and verification is defined by API MPMS Ch. 9.4 The calibration and verification of density determinations by sample shall be done in conformance with API MPMS Ch. 9 and API MPMS Ch. 8. API MPMS Ch. 9 defines the calibration and verification of the density determination method. API MPMS Ch. 8 defines procedure for correct sampling methods. 5.4.4 S&W For calculation of Net Standard Volume, S&W shall be subtracted from the Gross Standard Volume. This subtraction is typical in crude oil applications. In refined product applications concentrations of water are typically too low to require the subtraction of sediment or water. The determination of S&W requires that a sample be analyzed. The sample shall be obtained in accordance with API MPMS Ch. 8. For obtaining samples of volatile (higher vapor pressure) crude oils refer to ASTM D3700. The sample shall be analyzed in accordance with one of the methods available in API MPMS Ch. 10. The accuracy of the water determination shall be verified in accordance with API MPMS Ch. 8 and API MPMS Ch. 10. The accuracy of the sediment determination shall be verified in accordance API MPMS Ch. 10. The ideal location of the sample point is dependent upon the application. Refer to the relevant section of API MPMS Chapter 6 for application specifics and refer to API MPMS Ch. 8.2 for requirements. 5.5 Tertiary Measurement Devices (Flow Computers) A tertiary device is an electronic device that receives data from primary and secondary devices and uses this information to calculate the custody transfer quantity. The tertiary device can receive data via frequency signals, analog signals, digital signals or digital communication protocol.

For further information on tertiary devices, refer to API MPMS Ch. 21.2. 6 System Design Considerations 6.1 General In addition to the measurements and calculations which directly affect a measurement ticket, or a meter factor calculation, there are multiple design considerations which can also have an effect. This section discusses these effects. 6.2 Construction The equipment and materials selected for a metering system shall conform to applicable codes, e.g. pressure and temperature ratings, corrosion resistance, and area classifications. 6.3 Validation of Performance Criteria 6.3.1 Sizing and Process Conditions Should operating conditions change from the original design conditions, care shall be taken to ensure that all metering system components are suitable. 6.3.2 Uncertainty The system uncertainty, as defined by the user, drives the specifications and required performance of the primary, secondary and tertiary devices. If an uncertainty analysis is desired, reference API MPMS Ch. 13 and NIST Technical Note 1297. 6.4 Integrity The integrity of metering system components shall be evaluated to ensure integrity is sufficient to both parties prior to operating the system. 6.4.1 Bypasses The system design shall include means to prevent or detect any addition or removal of fluid that could adversely impact the measured quantity received or delivered. Specifically, the integrity of any bypass around the meter and/or prover shall be verifiable. Methods of verifying the integrity of a by-pass may include: a. Monitoring the pressure or discharge of liquid from a cavity (e.g. spool piece) located between an upstream valve and a downstream valve, b. Monitoring the pressure or discharge of liquid from the cavity located between the upstream and downstream seals of a single valve (e.g. double block and bleed (DBB) valve), c. Monitoring the discharge of liquid downstream of a valve, such as into a sump tank, or d. A paddle blind or a spectacle blind. The integrity of any means to add or remove liquid between the meter and the prover shall be verifiable or the means eliminated. The integrity of any valves, when a leak through the valve allows unregistered flow through the meter due to flow rate being below the minimum ability of the meter to register or detect flow, shall be verifiable.

6.4.2 Security Any component which can affect the accuracy of the meter ticket quantity shall have security measures in place. Components of the metering system which can affect the accuracy of the meter ticket quantity include: 1. Wiring disconnect, false signals 2. Electronics configuration changes, board replacements, factor changes (Refer to API MPMS Ch. 21) 3. Upstream configurations - positions of valves or other potential disturbances to affect the performance of the meters 4. Device isolation remove temperature device, isolate pressure device 5. Valve positions bypassing the meter or prover 6. Gear trains decouple Security measures may include but not limited to security seals, limited personnel access, locked doors or gates, cameras, audit trail logs. 6.4.3 Redundancy Custody quality measurement system reliability is important for a number of reasons, including, but not limited to, transaction tracking and pipeline integrity. A company should assess its needs for redundancy in these and other situations. Evaluating redundancy needs should not be limited to the number of meters installed. A redundancy evaluation should look at all aspects of the installation, including, but not limited to, meters, transmitters, power, controls and communications. The plan for redundancy should consider the available options in the case of component failure: a. include the necessary redundancy so that operations may continue, b. have a means to recognize the downtime period so that an agreeable assumed value may be used for the period, or c. discontinue the transfer. 6.4.4 Auditable Components of the system that require periodic calibration and/or inspection shall have calibrations and inspections documented. In addition to the API MPMS Ch. 4.8 procedures for proving a meter, the components or piping that require periodic calibration and/or inspection include but are not limited to: a. temperature devices, from device to flow computer b. pressure devices, from device to flow computer c. replication of meter ticket calculations d. meter head check, when (1) proving calculations are performed in a separate device from the batch calculations, and (2) proving using a direct pulse output from the meter e. bypasses covered in section 6.4.1 f. relief or vent connections installed through which undetected flow can occur 6.5 Additional Metering System Considerations There are additional system components which are specific to each application. For details refer to the relevant section of API MPMS Chapter 6.

6.5.1 System Pressure Loss Metering systems can add considerable pressure loss to a piping system. The effects of normal metering and proving operations on pumping capacity should be reviewed. Pumping capacity and piping hydraulics shall be sufficient to permit proper operation of the meter system. Piping should be sized to prevent significant change from the normal flow rate when proving a meter. 6.5.2 Hydraulic shock Care should be taken to prevent hydraulic shock on the metering system components induced by rotating equipment or valve operations. Hydraulic shock can cause system component damage and/or measurement error. 6.5.3 Back Pressure Control It is essential that the meter station be designed such that the operating pressure is higher than the equilibrium vapor pressure of the liquid to prevent cavitation. Cavitation may cause measurement error and/or damage to the flow meter. Specific concern should be given to locations between the meter and prover where the flow velocity is increased. Restrictions causing a localized velocity increase will allow a corresponding pressure decrease. It is necessary that back pressure be maintained such that all locations between the meter and prover are maintained in a single phase liquid condition. This requires that the back pressure control be located downstream of all metering or metering and proving components. In a bi-directional pipeline, consideration shall be given to the potential for cavitation when selecting control valves. In addition, the pressure on meters and provers shall be maintained in accordance with the relevant sections of API MPMS Ch. 4 and API MPMS Ch. 5. 6.5.4 Strainers Strainers are utilized to reduce entrained solids from entering the flow meter and/or the prover. Design is dependent on the size of the expected particles and fluid properties. Refer to the relevant sections of API MPMS Chapter 6 for additional details on strainer design. 6.5.5 Air Eliminators Air eliminators are required in systems where air can be introduced into the system and will adversely affect measurement or cause damage. Air eliminators are used to remove air from the process prior to it passing through the meter and the prover. The air eliminator may be a horizontal vessel, vertical vessel or a combination strainer with air eliminator. If needed, then it shall be installed upstream of the meter and prover. Horizontal or vertical air eliminators operate by significantly reducing the fluid velocity by expanding the cross sectional area of the pipe. This feature allows entrained gases and air slugs to escape upwards towards the top of the vessel where the air will escape. Vertical air eliminators can also operate by using tangential nozzles that promote natural centrifugal forces that allow the liquid to move towards the vessel wall and downward while the air or gas moves towards the center of the vessel and upwards towards the top of the vessel where the air will escape. Combination strainer with air eliminators operate by reducing the fluid velocity by expanding the cross sectional area of the pipe. This combination allows entrained gases and air slugs to escape upwards towards the top of the vessel where the air will escape. Removal of air becomes more difficult as viscosity increases. A larger capacity vessel may be required with higher viscosity liquids.

If a system is designed so that air will not enter the system, an air eliminator may not be required. For specific applications, refer to the relevant section of API MPSM Chapter 6 sections 6.5.6 Insulation or heat tracing Unique properties of the petroleum or petroleum product(s) being measured may require the individual components or the entire system to be insulated and/or heated. The purpose of the insulation or heat trace is to preserve the process conditions. For example, high viscosity crude oil which is heated to improve transportability may require insulation or heat tracing to reduce heat loss, maintain Reynolds Number, and to reduce temperature variations in the measurement system. Another example could be a low temperature commodity such as LPG, cooled below vapor pressure. Measurement of such commodities outside their desired state may impact measurement performance. 6.5.7 Vapor control Liquid metering system measurements are affected by vapor. Vapor in liquid metering systems shall be removed or avoided. Refer to relevant sections of API MPMS Chapter 6 for details on specific installations. 6.5.8 Pressure relief Pressure relief systems are required to prevent the possible over-pressurization of the metering system. Over pressure could result from increase in pressure or thermal expansion. Any section of the piping affecting the metering system that can be isolated by the closing of control valves, block valves, check valves, etc. shall be protected by pressure relief. The integrity of the relief system shall be verified periodically because of their potential to impact measurement. Pressure relief lines should be located to minimize the potential for product bypass around the meter. Product bypass will affect measurement accuracy. To minimize the impact of potential leakage from pressure relief valves on meter provings, such valves are recommended to be positioned upstream of the meter and/or downstream of the prover. Any pressure relief that can affect measurement accuracy or cause a difference between the quantity transferred and the ticketed quantity shall be equipped with a means to verify that no undetected flow occurs. 6.5.9 Vents Liquid metering systems shall be designed with the necessary facilities to handle vapors and noncondensable gases ( gases ); (1) when they are trapped within the piping, (2) when they are introduced from the incoming flowing stream and (3) formed due to flashing of the liquid. When not addressed, gases within a liquid metering system may cause equipment damage as well as inaccurate measurement and calibration. When trapped gases are made evident by issues such as poor proving repeatability or oscillating flow, they shall be removed from within the piping by either using taps at the high points in the piping or, when downstream equipment can handle, sufficiently high liquid velocity to remove trapped gas. Metering system designs shall include taps at all high point locations where gases could become trapped. Vent taps have potential for leakage when they are not in use and liquid spill-over when they are in use. When vent taps are located between the meter and prover, and there are leaks or spill over, then the measurement accuracy will be affected due to erroneous calibrations. Any vent that can affect measurement accuracy or cause a difference between the quantity transferred and the ticketed quantity shall be equipped with a means to verify that no leaks exist. When gases are introduced from the incoming flowing stream, a high point tap will not provide a solution unless it is combined with an air eliminator to trap the gas and a valve to release it based on liquid level. Refer to 6.5.5.

High point vents should not be used as a solution to gases formed from flashing or cavitation. Gases formed by flashing or cavitation should be solved by adding adequate backpressure. Refer to 6.5.3. 6.5.10 Drains Metering system designs should include taps at low point locations such that liquids may be drained before maintenance. Drain taps have the potential for leakage when not in use. When drain taps are located between the meter and prover, and there are leaks or spill over, then the measurement accuracy will be affected due to erroneous calibrations. Any drain that can affect measurement accuracy or cause a difference between the quantity transferred and the ticketed quantity shall be equipped with a means to verify that no leaks exist. 7 Electrical Design and Signal Integrity 7.1 Area Classification Metering systems are typically designed to be located within a hazardous area. Hazardous areas may be created by external influences or created internally. Dip pans, tundishes, strainer closures, prover closures and hose connections are example of locations internal to a metering system which may influence the hazardous area requirements. The electrical rules which govern the project will dictate how this evaluation is conducted. Classified areas may vary depending on the location, conditions, equipment, and substances involved in any given situation. Users of this Standard should consult with the appropriate regulator having jurisdiction and review applicable standards such as the following: RP 500 NFPA 70 OCIMF Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I Division I and Division II National Electrical Code International Safety Guide for Oil Tankers and Terminals (ISGOTT) 7.2 Grounding and Bonding Grounding and bonding have different aspects for marine, pipeline, truck applications which are discussed in the relevant sections of API MPMS Chapter 6. The flow of fluid inside the piping can generate static. To limit these static concerns, designs and operations should be in accordance with documents such as API RP 2003 and NFPA 77. 7.3 Signal Integrity Equipment and cabling installed in the field may be susceptible to external influences. These external influences must be mitigated to ensure signals convey only the data which is intentionally transmitted. Means of mitigation may include grounding, bonding, metal enclosures, metal conduit, an overall shielded cable, shielded conductors within the cable, non-conductive cabling (fiber), quadrature, insulating gaskets, and transmission protocol. For further guidance on fidelity and security of pulsed-data transmission systems refer to API MPMS Ch. 5.5. For further guidance on data transmission for temperature measuring devices refer to API MPMS Ch. 7. Many of the considerations detailed in Chapter 7 may apply to other measurement system components.

7.3.1 Stray current Stray current may be created by induction from other electric equipment or wiring in the vicinity of the measurement accessory equipment. Stray current may be from sources such as a grounding loop, power wiring, or cathodic protection system. 7.3.2 Radio Frequency Radio frequency interference can be created by wireless transmission equipment, which can include network equipment and commercial equipment (cell phone towers or radio towers). 7.3.3 Electromagnetic Interference Electromagnetic interference may be created by current-carrying conductors in the vicinity of the measurement accessory equipment. Local instrument power, solenoids, motors, transformers, or overhead power lines are among the possible sources for electromagnetic interference.

Bibliography [1] API MPMS Chapter 4.2, Displacement Provers [2] API MPMS Chapter 4.4, Tank Provers [3] API MPMS Chapter 4.5, Master Meter Provers [4] API MPMS Chapter 4.6, Pulse Interpolation [5] API MPMS Chapter 4.8, Operation of Proving Meters [6] API MPMS Chapter 5.5, Fidelity and Security of Flow Measurement Pulsed-Data Transmission Systems [7] API MPMS Chapter 7, Temperature Determination [8] API MPMS Chapter 9.4, Continuous Density Measurement Under Dynamic (Flowing) Conditions [9] API MPMS Chapter 12.3, Calculation of Volumetric Shrinkage From Blending Light Hydrocarbons with Crude Oil [10] API MPMS Chapter 13, Statistical Aspects of Measuring and Sampling [11] API MPMS Chapter 7/GPA 8182, Temperature Determination [12] API MPMS Chapter 14.5, Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer (GPA 2172-09) [13] API MPMS Ch. 14.7, Mass Measurement of Natural Gas Liquids [14] API MPMS Chapter 21, Flow Measurement Using Electronic Metering Systems (All Sections) [15] API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at [16] Petroleum Facilities Classified as Class I Division I and Division II [17] API RP 2003, Protection Against Ignitions Arising out of Static, Lightning, and Stray Currents, Seventh Ed. [18] ASME PTC 19.3 TW, Thermowells [19] ASTM D 1250, Standard Guide for Use of the Petroleum Measurement Tables [20] ASTM D 3700, Standard Practice for Obtaining LPG Samples Using a Floating Piston Cylinder [21] ASTM D 4052, Standard Test Method for Density, Relative Density, and API Gravity of Liquids by Digital Density Meter [22] ASTM D4805, Standard Terminology for Plastics Standards (Withdrawn 2002) [23] ASTM D5002, Standard Test Method for Density and Relative Density of Crude Oils by Digital Density Analyzer [24] ASTM D5931, Standard Test Method for Density and Relative Density of Engine Coolant Concentrates and Aqueous Engine Coolants by Digital Density Meter [25] ASTM D7777, Standard Test Method for Density, Relative Density, or API Gravity of Liquid Petroleum by Portable Digital Density Meter [26] NFPA 70, National Electrical Code [27] NIST Technical Note 1297, Guidelines for Evaluating and Expressing the Uncertainty of NIST Measurement Results [28] OCIMF, International Safety Guide for Oil Tankers and Terminals (ISGOTT)