Api mpms 14 8 1997 (2011) (american petroleum institute)

14 8/E2 Text Manual of Petroleum Measurement Standards Chapter 14—Natural Gas Fluids Measurement Section 8—Liquefied Petroleum Gas Measurement SECOND EDITION, JULY 1997 REAFFIRMED, OCTOBER 2011 Copyri[.]

Provisions to Ensure That Fluids are in the Liquid Phase

To ensure accurate measurement of liquefied petroleum gas, it is essential that the conditions of temperature and pressure maintain the fluid entirely in the liquid phase Specifically, the pressure at the meter inlet should be at least 1.25 times the equilibrium vapor pressure at the measurement temperature, plus twice the pressure drop across the meter at the maximum operating flow rate Alternatively, the pressure should be 125 pounds per square inch higher than the vapor pressure at the maximum operating temperature, whichever is lower.

Elimination of Swirl

When using turbine or orifice meters, the installation shall comply with the requirements specified in chapters5.3 or 14.3, respectively.

Temperature Measurement

Use of a fixed temperature may be acceptable, in some cases, when it varies by only a small amount; however, a continuously measured temperature is recommended for maximum accuracy.

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The USA System defines standard temperature as 60°F, with standard pressure being either the vapor pressure at this temperature or 14.696 pounds per square inch absolute, depending on which is greater It is important to note that this pressure base standard differs from the one used for gas.

7 International System of Units (SI)—Standard temperature is 15°C and standard pressure is the vapor pressure at 15°C or 101.325 kilopascals, whichever is higher.

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S ECTION 8—L IQUEFIED P ETROLEUM G AS M EASUREMENT 3

For accurate temperature measurements, it is essential to take readings at a location that reflects the flowing conditions within the measuring device The precision of the instruments and the measurement methods utilized are detailed in Chapters 4, 5.2, 5.3, and 5.4.

Pressure Measurement

Use of a fixed pressure may be acceptable in some cases, where it varies by only a small amount; however, a continuously measured pressure is recommended for maximum accuracy

Pressure measurements must be taken at a location that accurately reflects changes in pressure conditions within the measuring device The precision of the instruments and the measurement methods employed should align with established standards.

Density or Relative Density Measurement

To accurately measure the density or relative density (specific gravity) of a liquid, the sample point must represent the varying conditions present at the meter It is essential that the densities used for mass measurement are obtained under the same flowing conditions as those at the meter The precision of the instruments and the measurement methods employed should align with the guidelines outlined in Chapters 9.2 and 14.6.

Location of Measuring and Sampling Equipment

Measuring and sampling equipment must be positioned according to Chapter 8 guidelines to reduce the impact of pulsation and mechanical vibrations from pumps or control valves It is essential to take special precautions against electrical interference that could affect the flow meter's pick-up coil circuit, and the use of a preamplifier is recommended to enhance performance.

Representative samples shall be obtained as required in

When utilizing automatic sampling systems for GPA 2166 and GPA 2174, it is crucial to ensure that samples are collected from the center one-third of the stream's cross-sectional area This ensures proper mixing at the sampling point, avoids dead legs, and prevents any bypassing of the meter in the sampling system.

Dynamic measurement of liquefied petroleum gas in its liquid phase is essential for custody transfer and can be achieved through various measurement devices The selection of the appropriate device is determined by the mutual agreement of the contracting parties involved.

Measurement by Orifice Meter

The measurement of liquefied petroleum gases using an orifice meter must adhere to the guidelines outlined in Chapter 14.3, Part 1, which includes specific orifice and line internal diameter ratios, as well as agreed-upon flow coefficients The equations and factors provided in this standard have a limited scope, and for a comprehensive understanding, one should refer to Chapter 14.3, Part 1 Additionally, a complete list of unit conversion factors (N 1) is available in Section 1.11.4 of the same chapter It is important to note that the orifice meter functions as a mass measurement device, governed by a fundamental flow equation.

The practical orifice meter flow equation used in this standard is a simplified form that combines the numerical constants and unit conversion constants in a unit conversion factor (N 1):

C d = orifice plate coefficient of discharge. d = orifice plate bore diameter calculated at flowing temperature (T f ).

N 1 = unit conversion factor. q m = mass flow rate. ρt,p = density of the fluid at flowing conditions (P f , T f ).

The expansion factor, Y, is included in the above equations because it is applicable to all single-phase, homogeneous Newtonian fluids For incompressible fluids, such as water at

60°F and atmospheric pressure, the empirical expansion factor is defined as 1.0000.

The following equations can be used to determine flow rate:

1 Flow rate in cubic feet per hour at flowing conditions:

2 Flow rate in pounds mass per hour: q m = C d E v Y(π / 4)d 2 2g c ρ t p , ∆P q m = N 1 C d E v Y d 2 ρ t p , ∆P

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4 C HAPTER 14—N ATURAL G AS F LUIDS M EASUREMENT

The measurement of high vapor pressure liquefied petroleum gas can be simplified by obtaining deliveries in mass units This is achieved by multiplying the volume under flowing conditions by the density, which is measured at the same flowing temperature and pressure as at the meter, along with the appropriate meter and density adjustment factors Subsequently, the volume at standard conditions can be calculated using the specified equations or GPA 8173.

3 Flow rate in cubic feet per hour at base conditions:

To determine the flow rate in cubic feet per hour under base conditions, utilize volume and compressibility correction tables This approach is applicable exclusively for measuring a pure product or a mixture with clearly defined fluid properties.

Where: d = orifice plate bore diameter in inches.

∆P = orifice differential pressure in inches of H2O at 60°F.

The mass flow rate, denoted as \$q_m\$, is calculated using the formula \$E-02 \times 3600\$, expressed in pound-mole per hour The density of the fluid under flowing conditions, represented as \$\rho_{t,p}\$, is measured in pound-mole per cubic foot at specific pressure and temperature conditions (\$P_f, T_f\$) In contrast, the density at base conditions, \$\rho_b\$, is also expressed in pound-mole per cubic foot, corresponding to base pressure and temperature (\$P_b, T_b\$) Additionally, the density of air-free pure water at 60°F and atmospheric pressure of 14.696 pounds per square inch is \$\rho_{w,b} = 62.3663\$ pound-mole per cubic foot.

G f = relative density at flowing conditions Ratio of the density of the liquid at flowing conditions to the density of water at 60°F.

G b = relative density at base conditions.

C tl = correction factor for temperature to correct the volume at flowing temperature to standard temperature See ASTM D 1250-80, Volume XII, Table 34, GPA 2142-57 or other agreed-upon tables.

C pl = correction factor for pressure to correct the volume at flowing pressure to standard conditions.

See Chapter 11.2.2 or other agreed-upon tables.

According to provision 4.1, it is essential to measure liquefied petroleum gas (LPG) fluids in a liquid state, with a standard value of 1.0000 This standard should be maintained unless the LPG is measured under conditions of temperature and pressure that could change its fluid properties.

The velocity of approach factor, E v, is calculated as follows: and,

Where: d = orifice plate bore diameter calculated at flowing temperature (T f ).

D = meter tube internal diameter calculated at flowing temperature (T f ).

The orifice plate bore diameter, d, is defined as the diameter at flowing conditions and can be calculated using the following equation:

Where: α1 = linear coefficient of thermal expansion for the orifice plate material (see Table 1). d = orifice plate bore diameter calculated at flowing temperature (T f ). d r = reference orifice plate bore diameter at T r

T f = temperature of the fluid at flowing conditions.

T r = reference temperature of the orifice plate bore diameter.

Note: α, T f , and T r must be in consistent units For the purpose of this standard T r is assumed to be at 68°F (20°C).

The orifice plate bore diameter, d r , calculated at T r is the diameter determined in accordance with the requirements Chapter 14.3, Part 2.

The meter tube internal diameter, D, is defined as the diameter at flowing conditions and can be calculated using the following equation:

Where: α 2 = linear coefficient of thermal expansion for the meter tube material (see Table 1).

D = meter tube internal diameter calculated at flowing temperature (T f ).

5.1.5 Empirical Coefficient of Discharge Equation for Flange-Tapped Orifice Meters.

The coefficient of discharge, $ C_d $, for concentric, square-edged flange-tapped orifice meters, developed by Reader-Harris/Gallagher, is formulated with distinct linkage terms to accurately reflect the current regression database This equation is applicable for nominal pipe sizes of 2 inches (50 millimeters) and larger, with diameter ratios ($ \beta $) ranging from 0.1 to 0.75, provided the orifice plate bore diameter ($ d_r $) exceeds 0.45 inches (11.4 millimeters) and the pipe Reynolds numbers ($ Re_D $) are 4000 or higher For cases with diameter ratios and Reynolds numbers below these thresholds, please refer to the relevant chapter.

14.3.1.12.4.1 The RG coefficient of discharge equation for an orifice meter equipped with flange taps is defined as follows:

C d (FT) = coefficient of discharge at a specified pipe

Reynolds number for flange-tapped orifice meter.

C i (FT) = coefficient of discharge at infinite pipe Reynolds number for flange-tapped orifice meter.

C i (CT) = coefficient of discharge at infinite pipe Reynolds number for corner-tapped orifice meter. d = orifice plate bore diameter calculated at T f

D = meter tube internal diameter calculated at T f e = Napierian constant.

L1 = dimensionless correction for the tap location.

The RG equation utilizes the pipe Reynolds number as a key parameter to illustrate how the orifice plate coefficient of discharge, $C_d$, varies in relation to the fluid's mass flow rate, density, and viscosity.

The pipe Reynolds number can be calculated using the following equation:

The pipe Reynolds number equation used in this standard is in a simplified form that combines the numerical constants and unit conversion constants:

For the Reynolds number equations presented above, the symbols are described as follows:

D = meter tube internal diameter calculated at flowing temperature (T f ). à = absolute viscosity of fluid.

N 2 = unit conversion factor. π = universal constant.

Table 1—Linear Coefficient of Thermal Expansion

Linear Coefficient of Thermal Expansion (α)

Material (in/in/°F) (mm/mm/°C)

For temperature conditions outside the specified range and for different materials, consult the American Society for Metals Metals Handbook For flowing conditions between -100°F and +300°F, refer to ASME PTC.

19.5. b For flowing conditions between –7°F and +154°F, refer to Chapter 12,

Measurement by Positive Displacement Meter

The manufacturer’s recommendations should be carefully considered in sizing positive displacement meters (see

Air eliminators should be used with caution, particularly where the line in which they are installed could be shut-in occasionally, and where complete vaporization could occur.

Vapor formation due to ambient temperature or heat tracing before the meter can lead to inaccuracies and potential damage, particularly during startup It is essential to exercise caution in these situations.

5.2.1 Volume at Standard or Base Conditions

Liquid measurement using positive displacement meters must adhere to the guidelines outlined in Chapter 5.2 It is essential to apply the correct correction factors to adjust the measured volume to standard conditions, accounting for temperature, pressure, and meter factor Detailed information on the applicable factors can be found in Chapters 11 and 12.

The positive displacement measurement equation is:

V b = volume at base or standard conditions.

V f = volume at flowing conditions, indicated by a measuring device.

M.F = meter factor, obtained by proving the meter according to Chapters 4 and 12.2.

C tl = correction factor for temperature to correct the volume at flowing temperature to standard temperature See ASTM D 1250-80, Volume XII, Table 34, GPA Standard 2142-57 or other agreed-upon tables.

C pl = correction factor for pressure to correct the volume at flowing pressure to standard conditions.

See Chapter 11.2.2 or other agreed-upon tables.

5.2.2 Volume at Flowing Conditions for Mass

The volume at flowing conditions (V m) multiplied by the meter factor equals the volume at those conditions Displacement meters utilized for volumetric measurement in calculating total mass must adhere to the specified standards.

Chapter 5.2 for the service intended Temperature or pressure compensation devices are not to be used on these meters, and the accessories used shall conform to Chapter 5.4.

Measurement by Turbine Meter

The manufacturer’s recommendations should be carefully considered in sizing turbine meters (see Chapter 5.3).

Air eliminators must be used carefully, especially in lines that may be shut-in intermittently, as this can lead to complete vaporization To prevent potential physical damage to the equipment, the installation of thermal relief valves may be necessary.

Vapor formation due to ambient temperature or heat tracing before the meter can lead to inaccuracies and potential damage, particularly during startup It is essential to exercise caution in these situations.

Liquid measurement using a turbine meter must adhere to the guidelines outlined in Chapter 5.3 When conducting volumetric measurements, it is essential to apply the correct correction factors to adjust the measured volume to standard conditions, accounting for temperature, pressure, and meter factor These necessary factors can be located in the relevant chapters.

The following equation is used when performing volumetric measurement by turbine meter:

V b = volume at base or standard conditions.

V f = volume at flowing conditions, indicated by a measuring device.

M.F = meter factor, obtained by proving the meter according to Chapters 4 and 12.2.

C tl = correction factor for temperature to correct the volume at flowing temperature to standard temperature See ASTM D 1250-80, Volume XII, Table 34, GPA Standard 2142-57 or other agreed-upon tables.

C pl = correction factor for pressure to correct the volume at flowing pressure to standard conditions. See Chapter 11.2.2 or other agreed-upon tables.

Turbine meters designed for volumetric measurement under flowing conditions must adhere to the specifications outlined in Chapter 5.3 for their intended service These meters should not utilize temperature or pressure compensating devices, and any accessories must comply with Chapter 5.4 The measured mass can be converted to equivalent component volumes at standard conditions in accordance with GPA 8173.

Measurement by Other Devices

Dynamic measurement of liquefied petroleum gas can be achieved through various equipment types, provided there is mutual agreement between the contracting parties The implementation of this standard necessitates the use of industry-recognized custody transfer devices.

Meter Proving

The primary measuring device must be compared to a known standard Comparison to a standard is accomplished

Section 8 focuses on the measurement of liquefied petroleum gas (LPG) using positive displacement and turbine meters, which should be calibrated with a conventional pipe prover or a small volume prover as outlined in Chapter 4 It is advised against using tank-type provers due to the potential vaporization of LPG, complicating accountability When measuring multiple products, meters must be proved at the specific flow rates, pressures, and temperatures relevant to the liquid being measured Variations in normal operations may necessitate multiple meter factors Additionally, the proving device should be installed to ensure that the temperature and pressure in both the prover and meter align closely, and all meter and prover volumes must be corrected to base conditions as specified in Chapters 4 and 11.

12 Factors shall be adjusted, as required, between proving dates as a result of significant changes in metering pressure, temperature, product, or flow rate since the last proving.

Sampling

Sampling must be conducted to obtain a sample that accurately reflects the characteristics of the flowing stream during the measurement period Proportional samplers collect small samples in accordance with the flow rate, ensuring that the sample is representative of the entire stream.

Time incremental sampling may be used only when the flow rate is constant Time proportional sampling systems must stop sampling when the flow stops.

The sample collection system must be engineered to keep the collected sample in a liquid state, utilizing either a piston cylinder or a bladder cylinder These systems typically employ inert gas vapor, such as helium, hydraulic oil, or pipeline fluid to counteract liquid injection and sustain a pressure that exceeds the vapor pressure of the sample.

To prevent vaporization in sample loop lines when operating close to the product's vapor pressure, it is essential to take precautions When dealing with volatile materials, insulating sample lines and containers or regulating the pressure and temperature of the sample containers may be necessary.

Sample loops should be short and have a small diameter, with sampling taken from the center one-third of the stream's cross-sectional area using a sample probe It is essential to maintain adequate flow rates in the sample loop to ensure fresh product reaches the sample valve and to reduce the time lag between the meter and the sampler Additionally, sample loops must not bypass the primary measurement element.

To prevent contamination or distortion of flowing samples, it is essential to purge or bleed all sample lines, pumps, and related equipment when sample collection cylinders are emptied Additionally, sampler systems should be engineered to reduce dead product areas that may compromise sample integrity.

To ensure compliance with GPA 2166 and GPA 2174, it is essential to obtain a representative sample using appropriately sized containers When shipping samples via common carrier, these containers must adhere to the latest hazardous materials regulations set by the United States Department of Transportation, as well as the manufacturer's recommendations or other relevant authorities.

To prevent vaporization in on-line sample systems or transfer containers, products with equilibrium vapor pressures above atmospheric pressure must be maintained at a pressure that avoids this issue For single cavity sample containers, it is essential to ensure at least a 20 percent outage in transfer containers, while all systems should accommodate thermal expansion to prevent overpressuring Utilizing sample collection and transportation containers with floating pistons or bladders can effectively prevent liquid-vapor separation, provided that precautions are taken to manage thermal expansion and avoid excessive pressure Additionally, sample handling procedures from GPA 2174, which involve immiscible fluid outage cylinders, can be employed, although using water in this method may lead to the removal of carbon dioxide or other water-soluble components from the sample.

A sampling system designed for proportional sampling over time must include an effective mixing mechanism to ensure thorough sample homogenization To achieve true representativeness, samples must be mixed prior to their transfer into portable containers It is crucial that product mixing occurs only after the sampler is isolated from the source Comprehensive procedures for mixing samples should be established to guarantee that the samples transferred to transportation cylinders accurately reflect the characteristics of the flowing stream during the specified measurement period.

After mixing, the product sample is transferred to a portable piston cylinder or a double-valved sample cylinder using the immiscible fluid displacement method This transfer follows the same procedure as taking spot samples Once the necessary number of portable cylinders is filled, any remaining product in the sampler must be vented back into the pipeline or properly disposed of before the sampler is returned to service.

To ensure accurate laboratory analysis, a representative sample of the liquid stream must be collected following GPA 2174 guidelines It is essential to account for thermal expansion during sampling, and only containers approved by the Department of Transportation should be utilized for transport.

Sample Analysis

Depending upon the composition of the stream, the liquid sample analysis shall follow the chromatographic procedures described in GPA Publications 2165, 2177, 2186, and 2261.

In cases involving liquefied petroleum gas mixtures, it is essential to accurately determine the molecular weight and density of the heaviest final combined peak eluted, such as the heptanes plus fraction or the last significant fraction agreed upon.

Mass measurement is essential for liquefied petroleum gas mixtures and components influenced by changes in composition, intermolecular adhesion, solution mixing, or extreme pressure and temperature conditions, particularly when precise physical correction factors are unavailable.

Mass measurement in a dynamic state normally utilizes

The article discusses three essential components for accurate fluid measurement: (a) a volumetric measuring device that operates under flowing conditions, (b) a density or relative density measuring device that assesses density or specific gravity under the same conditions, and (c) a representative fluid sample collected in proportion to the flow, as outlined in GPA 8182.

Mass measurement is calculated by multiplying the measured volume under flowing conditions by the flowing density at those same conditions, ensuring consistent units To determine the equivalent volume at standard conditions for each component in a mixture, a compositional analysis of a representative sample is conducted, along with the density of each component at 60°F and the equilibrium pressure at that temperature.

Liquids with relative densities below 0.350 and above

0.637 and cryogenic fluids are excluded from the scope of this document However, the principles can apply to these fluids with modified application techniques.

Various equipment is available that employs different principles to measure volume, sample products, and assess their composition and density This publication does not endorse any specific type of equipment and aims to encourage ongoing development and enhancement of measurement technologies.

Base Conditions

Density is defined as mass per unit volume:

Mass is an absolute measure of the quantity of matter.

Weight is the force exerted by gravity on a mass, and it varies based on the local acceleration due to gravity Consequently, differences in gravitational acceleration across different locations will influence the observed weight Measurements are made in accordance with the gravitational pull in each area.

In accordance with Section 8182, mass should be prioritized over weight, achieved through calibration procedures outlined in Chapter 14.6, which utilize weighing devices near the densitometer to account for local gravitational variations Weight observations for fluid density must be adjusted for air buoyancy and local gravity, as necessary, and can be used to calibrate density meters or verify equation of state correlations Additionally, mass measurement volumes and densities should be determined at the operating temperature and pressure to avoid temperature and compressibility corrections, with equivalent volumes calculated at 60°F (15.56°C) and a pressure of 14.696 psia (101.325 kPa) or the product's equilibrium pressure at that temperature, whichever is higher.

Mass Measurement Using Displacement Type or Turbine Meters

The equation for determining mass using displacement- type or turbine meters is:

Orifice Meters for Mass Measurement

The following is a sample calculation of the mass flow rate using an orifice meter to measure delivery of a liquefied petroleum gas (raw mix) from a gas processing plant.

1 Orifice meter station designed, installed, and operated in compliance with specifications in the API MPMS, Chapter 14, Section 3, Parts 1 and 2.

2 Product being delivered is de-methanized liquid (raw mix) from a gas processing plant having the following analysis:

Metered volume at meter operating conditions

Meter factor at meter operating conditions ×

Density at meter operating conditions ×

Densitomer correction factor (if applicable) ×

S ECTION 8—L IQUEFIED P ETROLEUM G AS M EASUREMENT 9 a Metering temperature - - - 80°F. b Viscosity - - - 0.095 centipoise. c Meter tube internal diameter (I.D.) 4.026" at 68°F. d Orifice plate 316 ss - - - 2.005" at 68°F. e Operating differential pressure ∆P - - - 50" H2O at 60°F. f Operating density of 29.47 pounds/feet 3

Calculate the mass flow rate in pounds mass per 24 hours and convert to volume at 60°F and equilibrium vapor pressure in gallons of each component.

Where: q m = pounds mass per second

C d = orifice plate coefficient of discharge. d = orifice plate bore diameter calculated at flowing temperature.

∆P = differential pressure across orifice plate Static pressure measured at upstream flange tap.

N 1 = unit conversion factor. t 1, ρ1 = indicates temperature and pressure at flowing conditions. a Calculate the I.D of the meter tube at 80°F.

D = D r [1 + α2 (T f –T r )] T f = Flowing temperature, T r Reference temperature, D r (reference temperature)

D = 4.026 [1 + 0.00000620(80-68)] = 4.02630". α2 = Coefficient of thermal expansion in carbon steel

(inch/inch/°F). b Calculate orifice bore diameter at flowing temperature of

80°F. d = d r [1 + 0.00000925(80–68)] = 2.00522". c Calculate, β, ratio of d/D = 2.00522/4.0630 = 0.498031. d Calculate E v —velocity of approach factor.

E v = 1/(1–β 4 ) 0.5 = 1/(1–0.061531) 5 = 1.032256. e Expansion factor Y = 1.0. f Calculated, C d (FT), coefficient of discharge for flange taps.

Calculating the mass flow rate allows for the straightforward determination of both the volumetric flow rate under flowing conditions and at base conditions This flow calculation requires an iterative process using a digital computer Given a specific set of conditions, the flow rate can be accurately determined.

Q m per day (24 hours) = 828,600 pounds mass

Density Determination

Density may be determined by empirical correlation, based on an analysis of the fluid or on a direct measurement of the flowing density.

Liquid density can be determined based on composition, temperature, and pressure, and it is ideal to apply this density measurement in real time to the flowmeter for optimal mass measurement accuracy This ensures that the incremental volume of the liquid measured corresponds directly to the density at that moment However, it is often standard to utilize the composition of a continuously taken sample during the delivery period, along with the average temperature and pressure for that timeframe.

Calculations can be performed using empirical correlations or generalized equations of state Empirical correlations are based on experimental data and are limited to specific ranges of compositions, temperatures, and pressures, which may lead to inaccuracies outside these ranges Examples include the GPA procedures TP-1 for ethane/propane mixtures and TP-2 for high ethane raw make streams, while TP-3 is a more theoretical approach designed for liquefied natural gas applications.

Generalized equations of state offer flexibility in their application across diverse systems without strict limitations on composition and conditions In contrast, empirical correlations provide greater accuracy when tailored to specific systems Notable examples include the Rackett equation, the Han-Starling modification of the BWR equation, and various modified Redlich-Kwong equations such as Soave, Mark V, and Peng-Robinson.

Contracting parties must ensure the validity and accuracy of the methods used for empirical density determination of the specific fluids being measured.

Inaccuracies in temperature and pressure measurement, recording, or integration can lead to significant errors Products with a relative density below 0.6 are especially vulnerable to these errors and necessitate a higher degree of precision For recommended precision levels of temperature and pressure, refer to Chapter 14.6.

Measured density of products having a relative density between 0.350 and 0.637 shall be determined using density meters installed and calibrated in accordance with Chapter 14.6. q m = N 1 C d E v Y d 2 ρ t 1 , p 1∆P

Density instruments or probes must be installed to ensure no adverse interactions between the flowmeter and the density transducer It is essential to minimize temperature and pressure differences among the fluid in the flowmeter, the density measuring device, and the calibration devices, keeping them within specified limits to maintain the required mass measurement accuracy Additionally, density meters can be positioned either upstream or downstream of primary flow devices as outlined in the relevant chapter.

14.6, but should not be located between flow straightening devices and meters and must not bypass the primary flow measurement device.

The accuracy of densitometers can be significantly compromised by the buildup of foreign materials from the flowing stream Therefore, it is crucial to account for potential accumulation when choosing density measurement equipment and to establish a regular schedule for calibration and maintenance of the density equipment.

Accuracy of the data recording, transmission, and computation equipment and methods should also be considered in system selection See Chapter 14.6 for further comments.

Conversion of Measured Mass to Volume

The conversion of determined mass into equivalent volumes of components must follow the latest revision of GPA 8173 This process involves using chromatographic analysis to ascertain the mass of each component within the total mass Subsequently, these individual component masses are converted to their corresponding liquid volumes at 60°F (15.56°C) and equilibrium vapor pressure at the same temperature, utilizing density values from GPA 2145 Additionally, the method and frequency for determining physical properties of combined component fractions, such as C7+, should be established and agreed upon by all relevant parties.

To ensure accurate measurement, the total mass flow must be continuously calculated using an appropriate device or through off-line integration of charts that record metered volume and density This process guarantees that the density always aligns with the measured volume.

The conversion of the specified mass into an equivalent volume of each component must adhere to standard conditions, specifically at an equilibrium vapor pressure of 60°F (15.56°C) or 14.696 pounds per square inch absolute (101.325 kilopascals), depending on which value is greater, as outlined in Chapter.

In this procedure, a chromatographic analysis of the delivered product is conducted to ascertain the mass of each individual component These masses are subsequently converted into their equivalent liquid volumes and equilibrium vapor pressures at 60°F (15.56°C) using component density values from Chapter 11 or GPA 2145 Example calculations are included in the appendix for reference.

7 Volumetric Measurement in Static Systems

The total fluid volume comprises the sum of the liquid state fluid volume and the equivalent liquid volume derived from the vapor state fluid.

Volumetric measurement involves using calibrated vessels or tanks equipped with gauging devices to accurately read liquid levels under operating pressures The volume of vapor above the liquid is calculated using the ideal gas law, adjusted for the gas compressibility factor Both liquid and vapor measurements are corrected for temperature and pressure to align with standard conditions Additionally, vapor volume can be converted to equivalent liquid volume using specific conversion factors It is crucial that pressure vessels or containers are designed to safely handle the vapor pressures of the contained product at maximum operating temperatures.

Tank Calibration

Procedures for calibrating tanks and vessels are presented in Chapter 2.

Tank Gauging of Liquefied Petroleum Gas

Chapter 3 outlines the procedures for measuring liquefied petroleum gas in storage tanks, emphasizing the importance of taking special precautions to accurately account for the vapors present above the liquid The composition and volume of these vapors are influenced by the temperature and pressure conditions of the liquid.

Temperature Measurement

Chapter 5.4 contains general requirements for temperature measurement Procedures for measuring the temperature of liquefied petroleum gas in storage vessels under static conditions are presented in Chapter 7.

Relative Density Measurement

The procedures for determining the relative density of liquefied petroleum gas are detailed in Chapters 9, 11, 12, 14.6, and 14.7 To ensure accuracy, the observed relative densities, or specific gravities, are adjusted to standard conditions using the tables provided in Chapter 11.1.

Water and Foreign Material

Liquefied petroleum gases (LPG) generally face less severe issues with water and sediment content compared to crude oil It is essential for custody transfer contracts to include a product quality section that specifies testing methods for propane, such as the freeze valve method (ANSI/ASTM D 2713-91), the cobal bromide method, or the Bureau of Mines method Additionally, other acceptable methods for assessing dryness may be utilized for high vapor pressure liquefied petroleum gases, including on-stream moisture monitors.

Sampling

Chapter 8 does not address the sampling of liquefied petroleum gases, but GPA 2140, also known as ASTM D 1835, provides guidelines for obtaining representative samples of these gases, including propane and butane, from containers that are not part of laboratory testing equipment.

A liquid sample is transferred from the source into a sample container by purging the container and filling it with liquid to

Obtaining a representative sample of liquefied petroleum gases can be challenging and requires careful consideration of several factors Samples should always be collected in the liquid phase If the material is predominantly one type of liquefied petroleum gas, a sample can be taken from any part of the vessel Similarly, if the mixture is uniform, sampling can occur from any location within the container However, due to the diverse construction of containers, establishing a standard method for sampling heterogeneous mixtures is difficult In cases where agitation for homogeneity is impractical, it is essential to follow a sampling procedure agreed upon by all contracting parties.

Sampling directions should be clear but often require additional judgment, skill, and experience It is crucial to exercise extreme care and good judgment to ensure that samples accurately reflect the general characteristics and average conditions of the material Due to the inherent hazards, sampling of liquefied petroleum gases should be conducted by or under the supervision of individuals knowledgeable about safety precautions Additionally, minimizing the number of times a sample is transferred and handled is essential, and considerations for the thermal expansion of the liquid must be taken into account.

Volumetric Calculation

When a product is added to or removed from a tank, the initial and final liquid levels, along with their respective temperatures and pressures, are recorded The volumes of both liquid and vapor are then calculated for these conditions, and the difference between the initial and final total volumes of vapor and liquid indicates the volume change within the vessel.

Total volume = (volume of product in the vessel as a liquid) + (vapor above the liquid converted to its liquid volume equivalent) Volume measured at standard conditions.

Volume of liquid at standard conditions = volume measured at standard temperature and vapor pressure of the liquid at standard temperature.

Volume of liquid at tank conditions = volume of vessel at liquid level determined by tank calibration and gauging device.

Volume of vapor above the liquid = volume of vessel above the liquid level determined by tank calibration and gauging device.

Volume correction factor = factor used to correct the liquid volume to standard temperature Refer to tables in ASTM

D 1250-80, Volume XII, Table 34 and Chapter 12.2.

Total volume at standard conditions

Volume of liquid at standard conditions

Volume of vapor above the liquid in equivalent liquid units at standard conditions

Volume of liquid at standard conditions

Liquid volume at ktan conditions ×

Volume correction factor for temperature and gravity

Volume of vapor above liquid in equivalent liquid units at base conditions

Volume of vapor above the liquid

Factor for liquid volume per vapor volume ×

P o = observed pressure, in absolute units.

P a = standard pressure, in absolute units.

T o = observed temperature, in kelvins (K) or degrees

T a = standard temperature in kelvins (K) or degrees

Factor for liquid volume per vapor volume = standard conversion unit for product being measured.

Mixture Calculation

The composition of liquid and vapor phases in mixtures varies with changes in temperature and pressure Each phase's composition can be accurately determined through sampling and analysis For detailed procedures on calculating the liquid equivalent of vapor volume above stored natural gas liquid mixtures, refer to GPA 8182.

8 Mass Measurement in Static Systems

Mass is determined by weighing the container or vessel before and after product movement The difference in weight provides the basis for total mass of the product transferred.

To calculate the volume using mass units:

V b = volume at standard temperature and vapor pressure of the product at standard temperature. Mass = difference in mass measured before and after product movement.

Density = density of liquid product at standard conditions in same units as mass.

Refer to ASTM D 1250-80, Volume XII, Table 34 to determine relative density at standard conditions.

Step 1—Calculate the weight (mass) fraction of each component Given: 828.000 = Total pounds mass.

Component Percent Weight Mole Weight Component

Step 2—Calculate the mass of each component as follows: Weight fraction times total pounds mass equals pounds mass each component:

Weight Fraction Total Pounds Mass

Component of Component Pounds Mass of Component

Step 3—Calculate the volume of each component at equilibrium pressure and 60°F as follows:

Component Pounds Mass (in vacuum) Gallons

Note: For this example, the C6+ mole % is: C6, 74%; C7, 18%; C8, 3%; C9, 3%; C10, 2%.

Figure 1—Calculations for Liquid Vapor Conversion

American Society for Testing and Materials 1

Correction factor 2, 4, 6, 8, 11 pressure 4, 6 temperature 2, 4, 6 D Density determination of 2, 9 empirical 9 measurement of 3, 9

Displacement meter 6, 8 Dynamic conditions 2 metering 3 systems 2

Manual of Petroleum Measurement Standards 1, 8 Mass conversion 1 determination 2, 6, 8 measurement 1–3, 8–10, 12

Orifice meter 3, 5 P Pressure, measurement of 3, 9 R

Sample 1, 3, 7, 8, 11 analysis 1, 8 container 7, 8, 11 equipment, location of 7

Samplers 7 floating piston 7 proportional 7 time incremental 7

Static 1, 2, 9, 10, 12 conditions 10 metering 10 systems 1, 10, 12 Swirl 2

Turbine meter 1, 6, 8 V Vapor, formation of 6

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This article discusses various methods for measuring liquid hydrocarbons, including displacement meters as outlined in MPMS Chapter 5.2 and turbine meters in Chapter 5.3 It also covers dynamic temperature determination in Chapter 7.2 and the pressure hydrometer test method for assessing density or relative density in Chapter 9.2.

MPMS Ch 14.6,Continuous Density Measurement MPMS Ch 14.7,Mass Measurement of Natural Gas Liquids

MPMS Ch 12.2,Calculation of Petroleum Quantities Using Dynamic Meas.,

MPMS Ch 11.2.2,Compressibility Factors for Hydrocarbons:

MPMS Ch 12.2,Calculation of Petroleum Quantities Using Dynamic Meas.,

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• Petroleum Test Laboratory Ph: 202-682-8064 Accreditation Program Fax: 202-962-4739

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Tiêu đề	Manual of Petroleum Measurement Standards Chapter 14—Natural Gas Fluids Measurement Section 8—Liquefied Petroleum Gas Measurement
Trường học	American Petroleum Institute
Chuyên ngành	Petroleum Measurement Standards
Thể loại	manual
Năm xuất bản	2011
Thành phố	Washington, D.C.

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Số trang	30
Dung lượng	227,21 KB