D02.02 - Hydrocarbon Measurement for Custody Transfer (Joint ASTM-API)

SIGNIFICANCE AND USE
5.1 Density and API gravity are used in custody transfer quantity calculations and to satisfy transportation, storage, and regulatory requirements. Accurate determination of density or API gravity of crude petroleum and liquid petroleum products is necessary for the conversion of measured volumes to volumes at the standard temperatures of 15 °C or 60 °F.  
5.2 Density and API gravity are also factors that indicate the quality of crude petroleum. Crude petroleum prices are frequently posted against values in kg/m3 or in degrees API. However, this property of petroleum is an uncertain indication of its quality unless correlated with other properties.  
5.3 Field of Application—Because the thermohydrometer incorporates both the hydrometer and thermometer in one device, it is more applicable in field operations for determining density or API gravity of crude petroleum and other liquid petroleum products. The procedure is convenient for gathering main trunk pipelines and other field applications where limited laboratory facilities are available. The thermohydrometer method may have limitations in some petroleum density determinations. When this is the case, other methods such as Test Method D1298 (API MPMS Chapter 9.1) may be used.  
5.4 This procedure is suitable for determining the density, relative density, or API gravity of low viscosity, transparent or opaque liquids, or both. This procedure, when used for opaque liquids, requires the use of a meniscus correction (see 9.2). Additionally for both transparent and opaque fluids the readings shall be corrected for the thermal glass expansion effect and alternate calibration temperature effects before correcting to the reference temperature. This procedure can also be used for viscous liquids by allowing sufficient time for the thermohydrometer to reach temperature equilibrium.
SCOPE
1.1 This test method covers the determination, using a glass thermohydrometer in conjunction with a series of calculations, of the density, relative density, or API gravity of crude petroleum, petroleum products, or mixtures of petroleum and nonpetroleum products normally handled as liquids and having a Reid vapor pressures of 101.325 kPa (14.696 psi) or less. Values are determined at existing temperatures and corrected to 15 °C or 60 °F by means of a series of calculations and international standard tables.  
1.2 The initial thermohydrometer readings obtained are uncorrected hydrometer readings and not density measurements. Readings are measured on a thermohydrometer at either the reference temperature or at another convenient temperature, and readings are corrected for the meniscus effect, the thermal glass expansion effect, alternate calibration temperature effects and to the reference temperature by means of calculations and Adjunct to D1250 Guide for Use of the Petroleum Measurement Tables (API MPMS Chapter 11.1).  
1.3 Readings determined as density, relative density, or API gravity can be converted to equivalent values in the other units or alternate reference temperatures by means of Interconversion Procedures (API MPMS Chapter 11.5) or Adjunct to D1250 Guide for Use of the Petroleum Measurement Tables (API MPMS Chapter 11.1), or both, or tables as applicable.  
1.4 The initial thermohydrometer reading shall be recorded before performing any calculations. The calculations required in Section 9 shall be applied to the initial thermohydrometer reading with observations and results reported as required by Section 11 prior to use in a subsequent calculation procedure (measurement ticket calculation, meter factor calculation, or base prover volume determination).  
1.5 Annex A1 contains a procedure for verifying or certifying the equipment of this test method.  
1.6 The values stated in SI units are to be regarded as standard.  
1.6.1 Exception—The values given in parentheses are for information only.  
1.7 This standard does not purport to address all o...

SIGNIFICANCE AND USE
5.1 The vapor pressure parameters of volatile motor fuels are regulated by federal and state air pollution control agencies. In order to meet the letter of these regulations, it is necessary to sample, handle, and test these products in the precise manner as prescribed in this practice.
Note 1: This practice is not limited to dry vapor pressure equivalent testing for volatility. Dry vapor pressure equivalent is used to define the range for the sample matrix.
SCOPE
1.1 This practice covers procedures and equipment for obtaining, mixing, and handling representative samples of volatile fuels for the purpose of testing for compliance with the standards set forth for volatility related measurements applicable to light fuels.  
1.2 The applicable dry vapor pressure equivalent range of this practice is 13 kPa to 110 kPa (2 psia to 16 psia).  
1.3 This practice is applicable to the sampling, mixing, and handling of reformulated fuels including those containing oxygenates. This practice is not applicable to crude oil. For the sampling of crude oil, refer to Practice D4057/API MPMS Chapter 8.1, Practice D4177/API MPMS Chapter 8.2, and Practice D8009/API MPMS Chapter 8.5.  
1.4 The values stated in SI units are to be regarded as the standard except in some cases where drawings may show inch-pound measurements, which are customary for that equipment.  
1.5 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.6 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
4.1 Theoretically, all of the sediment and water determination methods are valid for crude oils containing from 0 % to 100 % by volume sediment and water; the range of application is specified within the scope of each method. The round robins for all methods were conducted on relatively dry oil. All precision and bias statements included in the methods are based upon the round robin data. Analysis becomes more challenging with crude oils containing higher water contents due to the difficulty in obtaining a representative sample, and maintaining the sample quality until analysis begins.  
4.2 Currently, Karl Fischer is generally used for dry crude oils containing less than 5 % water. Distillation is most commonly used for dry and wet crude oils and where separate sediment analysis is available or in situations where the sediment result is not significant. The laboratory centrifuge methods allow for determination of total sediment and water in a single analysis. The field centrifuge method is used when access to controlled laboratory conditions are not available.  
4.3 In the event of a dispute with regard to sediment and water content, contracting parties may refer to the technical specifications table to determine the most appropriate referee method based upon knowledge of and experience with the crude oil or product stream.
SCOPE
1.1 This guide covers a summary of the water and sediment determination methods from the API MPMS Chapter 10 for crude oils. The purpose of this guide is to provide a quick reference to these methodologies such that the reader can make the appropriate decision regarding which method to use based on the associated benefits, uses, drawbacks and limitations.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.4 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 A knowledge of the water content of petroleum products is important in the refining, purchase, sale, and transfer of products.  
5.2 The amount of water as determined by this test method (to the nearest 0.05 % or 0.1 % by volume, depending on the trap size used) may be used to correct the volume involved in the custody transfer of petroleum products and bituminous materials.  
5.3 The allowable amount of water may be specified in contracts.
SCOPE
1.1 This test method covers the determination of water in the range from 0 % to 25 % by volume in petroleum products, tars, and other bituminous materials by the distillation method.  
Note 1: Volatile water-soluble material, if present, may be measured as water.  
1.2 The specific products considered during the development of this test method are listed in Table 1. For bituminous emulsions refer to Test Method D244. For crude oils, refer to Test Method D4006 (API MPMS Chapter 10.2).
Note 2: With some types of oil, satisfactory results may be obtained from Test Method D1796 (API MPMS Chapter 10.6).  
1.3 The values stated in SI units are to be regarded as standard. The values given in parentheses after SI units are provided for information only and are not considered standard.  
1.4 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use. For specific hazard statements, see Section 6.  
1.5 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 Coal tar pitch is shipped or stored, or both, at various temperatures, consequently a means is required to correct volume to a specified temperature.
SCOPE
1.1 This practice covers calculation of the amount of expansion or contraction of a volume of liquid coal-tar pitch due to a change of temperature.  
1.2 The values stated in inch-pound units are to be regarded as standard. The values given in parentheses are mathematical conversions to SI units that are provided for information only and are not considered standard.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.4 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 Accurate determination of the gravity of petroleum and its products is necessary for the conversion of measured volumes to volumes at the standard temperature of 60 °F (15.56 °C).  
5.2 This procedure is most suitable for determining the API gravity of low viscosity transparent liquids. This test method can also be used for viscous liquids by allowing sufficient time for the hydrometer to reach temperature equilibrium, and for opaque liquids by employing a suitable meniscus correction. Additionally for both transparent and opaque fluids the readings shall be corrected for the thermal glass expansion effect before correcting to the reference temperature.  
5.3 When used in connection with bulk oil measurements, volume correction errors are minimized by observing the hydrometer reading at a temperature as close to reference temperature as feasible.  
5.4 Gravity is a factor governing the quality of crude oils. However, the gravity of a petroleum product is an uncertain indication of its quality. Correlated with other properties, gravity can be used to give approximate hydrocarbon composition and heat of combustion.  
5.5 Gravity is an important quality indicator for automotive, aviation and marine fuels, where it affects storage, handling and combustion.
SCOPE
1.1 This test method covers the determination by means of a glass hydrometer in conjunction with a series of calculations of the API gravity of crude petroleum and petroleum products normally handled as liquids and having a Reid vapor pressure (Test Method D323) of 14.696 psi (101.325 kPa) or less. Values are determined at existing temperatures and corrected to values at 60 °F (15.56 °C), or converted to values at 60 °F, by means of Adjunct to D1250 Standard Guide for the Use of the Joint API and ASTM Adjunct for Temperature and Pressure Volume Correction Factors for Generalized Crude Oils, Refined Products, and Lubricating Oils (API MPMS Chapter 11.1). These tables are not applicable to nonhydrocarbons or essentially pure hydrocarbons such as the aromatics.  
1.2 The initial values obtained are uncorrected hydrometer readings and not density measurements. Values are measured on a hydrometer at either the reference temperature or at another convenient temperature, and readings are corrected for the meniscus effect, the thermal glass expansion effect, alternate calibration temperature effects and to the reference temperature by means of the petroleum measurement tables; values obtained at other than the reference temperature being hydrometer readings and not density measurements.  
1.3 The initial hydrometer readings determined shall be recorded before performing any calculations. Then the calculations required in Section 9 shall be performed and documented before using the final result in a subsequent calculation procedure (measurement ticket calculation, meter factor calculation, or base prover volume determination).  
1.4 The values stated in inch-pound units are to be regarded as standard. The values given in parentheses are mathematical conversions to SI units that are provided for information only and are not considered standard.  
1.5 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use. For specific warning statement, see 8.5.  
1.6 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 A knowledge of the water content of crude oil is important in the refining, purchase, sale, or transfer of crude oils.  
5.2 This test method may not be suitable for crude oils that contain alcohols that are soluble in water. In cases where the impact on the results may be significant, the user is advised to consider using another test method, such as Test Method D4928 (API MPMS Chapter 10.9).
SCOPE
1.1 This test method covers the determination of water in crude oil by distillation.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use. For specific warning statements, see 7.1 and A1.1.  
1.4 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 The water and sediment content of fuel oil is significant because it can cause corrosion of equipment and problems in processing. A determination of water and sediment content is required to measure accurately net volumes of actual fuel oil in sales, taxation, exchanges, and custody transfers.  
5.2 This test method may not be suitable for products that contain alcohols that are soluble in water. In cases where the impact on the results may be significant, the user is advised to consider using another test method, such as Test Method D6304.
SCOPE
1.1 This test method describes the laboratory determination of water and sediment in fuel oils in the range from 0 % to 30 % volume by means of the centrifuge procedure.
Note 1: With some types of fuel oils such as residual fuel oils or distillate fuel oils containing residual components, it is difficult to obtain water or sediment contents with this test method. When this situation is encountered, Test Method D95 (API MPMS Chapter 10.5) or Test Method D473 (API  MPMS Chapter 10.1) may be used.
Note 2: API MPMS Chapter 10.6 (Test Method D1796) along with API MPMS Chapter 10.3 (Test Method D4007) formerly superseded API Standard 2548.  
1.2 The values stated in SI units are to be regarded as the standard. The values given in parentheses are for information only.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use. For a specific precautionary statement, see 7.1.  
1.4 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 The water and sediment content of crude oil is significant because it can cause corrosion of equipment and problems in processing. A determination of water and sediment content is required to measure accurately net volumes of actual oil in sales, taxation, exchanges, and custody transfers. It is not anticipated that this test method, which is written with a dedicated laboratory facility in mind, is likely to be used in field test rooms or sample rooms due to safety concerns for proper ventilation and handling.  
5.2 This test method may not be suitable for crude oils that contain alcohols that are soluble in water. In cases where the impact on the results may be significant, the user is advised to consider using another test method, such as Test Method D4928 (API MPMS Chapter 10.9).
SCOPE
1.1 This test method describes the laboratory determination of water and sediment in crude oils by means of the centrifuge procedure. This centrifuge method for determining water and sediment in crude oils is not entirely satisfactory. The amount of water detected is almost always lower than the actual water content. When a highly accurate value is required, the revised procedures for water by distillation, Test Method D4006 (API MPMS Chapter 10.2) (Note 1), and sediment by extraction, Test Method D473 (API MPMS Chapter 10.1), shall be used.  
Note 1: Test Method D4006 (API MPMS Chapter 10.2) has been determined to be the preferred and most accurate method for the determination of water.  
1.2 The values stated in SI units are to be regarded as standard.  
1.2.1 Exception—The values given in parentheses are for information only.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use. Specific warning statements appear in 7.1, 9.3, and A1.5.4.  
1.4 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 This practice allows the collection of a representative sample of crude oil and/or condensate that may contain trace volatile dissolved components such as methane, ethane, propane, and fixed gases that would normally be lost using conventional atmospheric sampling methods. These highly volatile components can result in vapor pressure conditions above atmospheric pressure. This practice is recommended whenever accurate determination of vapor pressure, flash point, or other properties are required and where loss of volatile components can affect the test results.  
5.2 This practice is intended for capturing samples of crude oil and/or condensate for testing for the purpose of classification for transportation of dangerous goods as UN Class 3 Flammable Liquids, but is not limited to classification testing. Other test methods with sensitivities to light end loss may also utilize this sampling practice.  
5.3 Practice D3700 using a floating piston cylinder is recommended whenever true vapor pressures greater than 300 kPa at 50 °C are anticipated.
SCOPE
1.1 This practice includes the equipment and procedures for obtaining a representative sample of “live” or high vapor pressure crude oils, condensates, and/or liquid petroleum products from low pressure sample points, where there is insufficient sample point pressure to use a Floating Piston Cylinder (FPC) as described in Practice D3700.  
1.2 This practice is intended for use with sample types, such as UN Class 3 Flammable Liquids, that might have been collected and transported using open containers. The use of a manual piston cylinder in place of open containers is intended to prevent the loss of volatile (light end) components, which can impact subsequent test results.  
1.3 This practice is suitable for sampling crude oils, condensates, and/or liquid petroleum products having true vapor pressures less than 300 kPa (43 psia nominal) at 50 °C. This practice applies to samples that will typically fall between Practices D4057 (API MPMS Chapter 8.1) and D3700. This practice shall not be used for materials classified as UN Class 2 Gases2 (“…having a vapor pressure greater than 300 kPa at 50 °C or is completely gaseous at 20 °C at 101.3 kPa.”).  
1.4 This practice allows for sampling of crude oils that flow freely at the conditions of sampling.  
1.5 It is the responsibility of the user to ensure that the sampling point is located so as to obtain a representative sample.  
1.6 The values stated in SI units are to be regarded as standard.  
1.6.1 Exception—The values given in parentheses are for information only.  
1.7 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.8 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 A knowledge of the sediment content of crude oils and fuel oils is important both to the operation of refining and the buying or selling of these commodities.
SCOPE
1.1 This test method covers the determination of sediment in crude oils and fuel oils by extraction with toluene. The precision applies to a range of sediment levels from 0.01 % to 0.40 % mass, although higher levels may be determined.
Note 1: Precision on recycled oils and crankcase oils is unknown and additional testing is required to determine that precision.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use. For specific warning statements, see 6.1.1.6 and 7.1.  
1.4 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
4.1 Representative samples of petroleum and petroleum products are required for the determination of chemical and physical properties, which are used to establish standard volumes, prices, and compliance with commercial terms and regulatory requirements. This practice does not cover sampling of electrical insulating oils and hydraulic fluids. This practice does not address how to sample crude at temperatures below the freezing point of water.
PART I—General
This part is applicable to all petroleum liquid sampling whether it be crude oil or refined products. Review this section before designing or installing any automatic sampling system.
SCOPE
1.1 This practice describes general procedures and equipment for automatically obtaining samples of liquid petroleum and petroleum products, crude oils, and intermediate products from the sample point into the primary container. This practice also provides additional specific information about sample container selection, preparation, and sample handling. If sampling is for the precise determination of volatility, use Practice D5842 (API MPMS Chapter 8.4) in conjunction with this practice. For sample mixing and handling, refer to Practice D5854 (API MPMS Chapter 8.3). This practice does not cover sampling of electrical insulating oils and hydraulic fluids.  
1.2 Table of Contents:    
Section  
INTRODUCTION  
Scope  
1  
Referenced Documents  
2  
Terminology  
3  
Significance and Use  
4  
PART I–GENERAL  
Representative Sampling Components  
5  
Design Criteria  
6  
Automatic Sampling Systems  
7  
Sampling Location  
8  
Mixing of the Flowing Stream  
9  
Proportionality  
10  
Sample Extractor Grab Volume  
11  
Containers  
12  
Sample Handling and Mixing  
13  
Control Systems  
14  
Sample System Security  
15  
System Proving (Performance Acceptance Tests)  
16  
Performance Monitoring  
17  
PART II–CRUDE OIL  
Crude Oil  
18  
PART III–REFINED PRODUCTS  
Refined Products  
19  
KEYWORDS  
Keywords  
20  
ANNEXES  
Calculations of the Margin of Error based on Number of Sample Grabs  
Annex A1  
Theoretical Calculations for Selecting the Sampler Probe Location  
Annex A2  
Portable Sampling Units  
Annex A3  
Profile Performance Test  
Annex A4  
Sampler Acceptance Test Data  
Annex A5  
APPENDIXES  
Design Data Sheet for Automatic Sampling System  
Appendix X1  
Comparisons of Percent Sediment and Water versus Unloading Time Period  
Appendix X2  
Sampling Frequency and Sampling System Monitoring Spreadsheet  
Appendix X3  
Sampling System Monitoring—Additional Diagnostics  
Appendix X4  
1.3 Units—The values stated in either SI units or US Customary (USC) units are to be regarded separately as standard. The values stated in each system may not be exact equivalents; therefore, each system shall be used independently of the other. Combining values from the two systems may result in non-conformance with the standard. Except where there is no direct SI equivalent, such as for National Pipe Threads/diameters, or tubing.  
1.4 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.5 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 The density or relative density of light hydrocarbons and liquefied petroleum gases is used in custody transfer quantity calculations or to satisfy transportation, storage, and regulatory requirements.
SCOPE
1.1 This test method covers the determination of the density or relative density of light hydrocarbons including liquefied petroleum gases (LPG) having Reid vapor pressures exceeding 101.325 kPa (14.696 psi).  
1.2 The prescribed apparatus should not be used for materials having vapor pressures higher than 1.4 MPa (200 psi) at the test temperature. This pressure limit is dictated by the type of equipment. Higher pressures can apply to other equipment designs.  
1.3 The initial pressure hydrometer readings obtained are uncorrected hydrometer readings and not density measurements. Readings are measured on a hydrometer at either the reference temperature or at another convenient temperature, and readings are corrected for the meniscus effect, the thermal glass expansion effect, alternate calibration temperature effects and to the reference temperature by means of calculations and Adjunct to D1250 Guide for Petroleum Measurement Tables (API MPMS Chapter 11.1) or API MPMS Chapter 11.2.4 (GPA TP-27), as applicable.  
1.4 Values determined as density or relative density can be converted to equivalent values in the other units or alternative reference temperatures by means of Interconversion Procedures API MPMS  Chapter 11.5, or Adjunct to D1250 Guide for Petroleum Measurement Tables (API MPMS Chapter 11.1) or API MPMS Chapter 11.2.4 (GPA TP-27), as applicable.  
1.5 The calculations required in Section 11 shall be applied to the initial pressure hydrometer reading with observations and results reported as required by Section 11 prior to use in a subsequent calculation procedure (measurement ticket calculation, meter factor calculation, or base prover volume determination).  
1.6 Annex A1 contains a procedure for verifying or certifying the equipment for this test method.  
1.7 The values in SI units are to be regarded as the standard. US Customary values shown in adjacent parentheses are for information only and may not be exactly equivalent. Both SI and customary units have been rounded so that they may not be exactly equivalent.  
1.8 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.9 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
4.1 Samples of petroleum and petroleum products are obtained for many reasons, including the determination of chemical and physical properties. These properties may be used for: calculating standard volumes; establishing product value; and often safety and regulatory reporting.  
4.2 There are inherent limitations when performing any type of sampling, any one of which may affect the representative nature of the sample. As examples, a spot sample provides a sample from only one particular point in the tank, vessel compartment, or pipeline. In the case of running or all-level samples, the sample only represents the column of material from which it was taken.  
4.3 Based on the product, and testing to be performed, this practice provides guidance on sampling equipment, container preparation, and manual sampling procedures for petroleum and petroleum products of a liquid, semi-liquid, or solid state, from the storage tanks, flowlines, pipelines, marine vessels, process vessels, drums, cans, tubes, bags, kettles, and open discharge streams into the primary sample container.
SCOPE
1.1 This practice covers procedures and equipment for manually obtaining samples of liquid petroleum and petroleum products, crude oils, and intermediate products from the sample point into the primary container are described. Procedures are also included for the sampling of free water and other heavy components associated with petroleum and petroleum products.  
1.2 This practice also addresses the sampling of semi-liquid or solid-state petroleum products. For the sampling of green petroleum coke, see Practice D8145. For the sampling of calcined petroleum coke, see Practice D6970.  
1.3 This practice provides additional specific information about sample container selection, preparation, and sample handling.  
1.4 This practice does not cover sampling of electrical insulating oils and hydraulic fluids. If sampling is for the precise determination of volatility, use Practice D5842 (API MPMS Chapter 8.4) in conjunction with this practice. For sample mixing and handling, refer to Practice D5854 (API MPMS Chapter 8.3).  
1.5 The procedures described in this practice may also be applicable in sampling most non-corrosive liquid industrial chemicals provided that all safety precautions specific to these chemicals are followed. Also, refer to Practice E300. The procedures described in this practice are also applicable to sampling liquefied petroleum gases and chemicals. Also refer to Practices D1265 and D3700. The procedure for sampling bituminous materials is described in Practice D140. Practice D4306 provides guidance on sample containers and preparation for sampling aviation fuel.  
1.6 Units—The values stated in SI units are to be regarded as the standard. USC units are reflected in parentheses.  
1.7 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.8 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
4.1 A knowledge of the sediment content of crude oil is important both in refinery operations and in crude oil commerce.
SCOPE
1.1 This test method covers the determination of sediment in crude oils by membrane filtration. This test method has been validated for crude oils with sediments up to approximately 0.15 % by mass.  
1.2 The accepted unit of measure for this test method is mass %, but an equation to convert to volume % is provided (see Note 6).  
1.3 The values stated in SI units are to be regarded as the standard. The values given in parentheses are for information only.  
1.4 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use. For specific warning statements, see 6.1 and Annex A1.  
1.5 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 The expanded limits of the Adjunct for VCF are defined in a mixture of terms of customary and metric units. Table 1 shows the defining limits and their associated units in bold italics. Also shown in Table 1 are the limits converted to their equivalent units (and, in the case of the densities, other base temperatures).  
5.2 Note that only the precision levels of the defining values shown in Table 1 are correct. The other values showing converted units have been rounded to the significant digits shown; as rounded values, they may numerically fall just outside of the actual limits established by the defining values.  
5.3 Table 2 provides a cross-reference between the historical table designations and the corresponding section in the Adjunct for VCF. Note that procedure paragraphs 11.1.6.3 (U.S. customary units) and 11.1.7.3 (metric units) provide methods for correcting on-line density measurements from live conditions to base conditions and then to compute CTPL factors for continuous volume corrections to base conditions.  
5.4 When a glass hydrometer is used to measure the density of a liquid, special corrections must be made to account for the thermal expansion of the glass when the temperature is different from that at which the hydrometer was calibrated. The 1980 CTL Tables had generalized equations to correct glass hydrometer readings, and these corrections were part of the printed odd-numbered tables. However, detailed procedures to correct a glass hydrometer reading are beyond the scope of the Adjunct for VCF. The user should refer to the appropriate sections of API MPMS Chapter 9 or other appropriate density/hydrometer standards for guidance.  
5.5 The set of correlations given in the Adjunct for VCF is intended for use with petroleum fluids comprising either crude oils, refined products, or lubricating oils that are single-phase liquids under normal operating conditions. The liquid classifications listed here are typical terms used in the industry, ...
SCOPE
1.1 This guide provides information related to the algorithm and implementation procedure but does not contain the full set of algorithms. The algorithms, instructions, procedures, and examples are located in the associated supplementary adjuncts. The Adjunct for Volume Correction Factors (VCF) for temperature and pressure volume correction factors for generalized crude oils, refined products, and lubricating oils provides the algorithm and implementation procedure for the correction of temperature and pressure effects on density and volume of liquid hydrocarbons. Natural gas liquids (NGLs) and liquefied petroleum gases (LPGs) are excluded from consideration in this standard but may be found in API MPMS Chapter 11.2.4/GPA 8217 Temperature Correction for NGL and LPG. As this Adjunct for VCF will be applied to a variety of applications, the output parameters of CTL, Fp, CPL, and CTPL may be used as specified in other standards.  
1.2 Including the pressure correction in the Adjunct for VCF represents an important change from the “temperature only” correction factors given in the 1980 Petroleum Measurement Tables. However, if the pressure is one atmosphere (the standard pressure), then there is no pressure correction and the standard/adjunct(s) will give CTL values consistent with the 1980 Petroleum Measurement Tables.  
1.3 The Adjunct for VCF covers general procedures for the conversion of input data to generate CTL, Fp, CPL, and CTPL values at the user-specified base temperature and pressure (Tb, Pb). Two sets of procedures are included for computing volume correction factor: one set for data expressed in customary units (temperature in °F, pressure in psig); the other for the metric system of units (temperature in °C, pressure in kPa or bar).
Note 1: In contrast to the 1980 Petroleum Measurement Tables, the metric procedures require the procedure for customary units be used first to compute density at 60 °F. This va...

SIGNIFICANCE AND USE
4.1 Representative samples of petroleum and petroleum products are required for the determination of chemical and physical properties used to establish standard volumes, prices, and compliance with commercial and regulatory specifications. The handling of samples from the time of collection until they are analyzed requires care and effort to maintain their compositional integrity. Samples of high RVP (unstabilized) hydrocarbons are required at many measurement points, for example offshore production, at the outlets of test separators or to allow calibration of a flowmeter. This practice also describes requirements associated with handling and mixing samples held within pressurized cylinders.  
4.2 Practice D4057 (API MPMS Chapter 8.1), Practice D4177 (API MPMS Chapter 8.2), Practice D5854 (API MPMS Chapter 8.3), Practice D5842 (API MPMS Chapter 8.4), and Practice D8009 (API MPMS Chapter 8.5). The primary purpose of this suite of standards, is to ensure proper sampling and handling for custody transfer applications. There are a significant number of test methods that may be used to analyze the samples taken by techniques described in API MPMS Chapter 8.1 and 8.2. For samples that are taken for test methods outside the general scope of custody transfer covered by this practice, the personnel assigned to take the sample are responsible to refer to the test methods for additional critical information that may impact the sampling process, that is, specific container selection, transport methods, storage times, etc. Those requirements should be found in the appropriate test method.
SCOPE
1.1 This practice covers handling, mixing, and conditioning procedures that are required to ensure that a representative sample of the liquid petroleum or petroleum product is delivered from the primary sample container or container or both into the analytical apparatus or into intermediate containers.  
1.2 Appendix X1 details the background information on the development of Table 1 used in performance testing. Appendix X2 provides guidance in the acceptance testing for water in crude oil. Appendix X3 provides a guide for materials of sample containers. Appendix X4 provides a summary of recommended mixing procedures. Appendix X5 provides a flow chart for sample container/mixing system acceptance test.  
1.3 For sampling procedures, refer to Practices D4057 (API MPMS Chapter 8.1) and D4177 (API MPMS Chapter 8.2). Practice D5842 (API MPMS Chapter 8.4) covers sampling and handling of light fuels for volatility measurement, and D8009 (API MPMS Chapter 8.5).  
1.4 It is recommended that the users of this practice perform the tests in Practice D4177 (API MPMS Chapter 8.2) before performing the test in this practice.  
1.5 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.6 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 The accurate analysis of a crude oil sample to determine the water content is important in the refining, purchase, sale, or transfer of crude oils.
SCOPE
1.1 This test method covers the determination of water in the range from 0.02 to 5.00 mass or volume % in crude oils. Mercaptan (RSH) and sulfide (S− or H2S) as sulfur are known to interfere with this test method, but at levels of less than 500 μg/g [ppm(m)], the interference from these compounds is insignificant (see Section 6).  
1.2 This test method can be used to determine water in the 0.005 to 0.02 mass % range, but the effects of the mercaptan and sulfide interference at these levels has not been determined. For the range 0.005 to 0.02 mass %, there is no precision or bias statement.  
1.3 This test method is intended for use with standard commercially available coulometric Karl Fischer reagent.  
1.4 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.5 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use. For specific warning statements, see Section 8.  
1.6 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 Accurate determination of the density, relative density (specific gravity), or API gravity of petroleum and its products is necessary for the conversion of measured volumes to volumes or masses, or both, at the standard reference temperatures of 15 °C or 60 °F during custody transfer.  
5.2 This procedure is most suitable for determining the density, relative density (specific gravity), or API gravity of low viscosity transparent liquids. This procedure can also be used for viscous liquids by allowing sufficient time for the hydrometer to reach temperature equilibrium, and for opaque liquids by employing a suitable meniscus correction. Additionally for both transparent and opaque fluids the readings shall be corrected for the thermal glass expansion effect and alternative calibration temperature effects before correcting to the reference temperature.  
5.3 When used in connection with bulk oil measurements, volume correction errors are minimized by observing the hydrometer reading at a temperature close to that of the bulk oil temperature.  
5.4 Density, relative density, or API gravity is a factor governing the quality and pricing of crude petroleum. However, this property of petroleum is an uncertain indication of its quality unless correlated with other properties.  
5.5 Density is an important quality indicator for automotive, aviation and marine fuels, where it affects storage, handling and combustion.
SCOPE
1.1 This test method covers the laboratory determination using a glass hydrometer in conjunction with a series of calculations, of the density, relative density, or API gravity of crude petroleum, petroleum products, or mixtures of petroleum and nonpetroleum products normally handled as liquids, and having a Reid vapor pressure of 101.325 kPa (14.696 psi) or less. Values are determined at existing temperatures and corrected to 15 °C or 60 °F by means of a series of calculations and international standard tables.  
1.2 The initial hydrometer readings obtained are uncorrected hydrometer readings and not density measurements. Readings are measured on a hydrometer at either the reference temperature or at another convenient temperature, and readings are corrected for the meniscus effect, the thermal glass expansion effect, alternative calibration temperature effects and to the reference temperature by means of the Petroleum Measurement Tables; values obtained at other than the reference temperature being hydrometer readings and not density measurements.  
1.3 Readings determined as density, relative density, or API gravity can be converted to equivalent values in the other units or alternative reference temperatures by means of Interconversion Procedures (API MPMS Chapter 11.5), or Adjunct to D1250 Guide for Petroleum Measurement Tables (API MPMS Chapter 11.1), or both, or tables, as applicable.  
1.4 The initial hydrometer readings determined in the laboratory shall be recorded before performing any calculations. The calculations required in Section 10 shall be applied to the initial hydrometer reading with observations and results reported as required by Section 11 prior to use in a subsequent calculation procedure (ticket calculation, meter factor calculation, or base prover volume determination).  
1.5 Annex A1 contains a procedure for verifying or certifying the equipment for this test method.  
1.6 The values stated in SI units are to be regarded as standard.  
1.6.1 Exception—The values given in parentheses are provided for information only.  
1.7 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.  
1.8 This international standard was developed in accordance with internationally recognized principles on standardization established in th...

SIGNIFICANCE AND USE
5.1 The density or relative density of light hydrocarbons and liquefied petroleum gases is used in custody transfer quantity calculations or to satisfy transportation, storage, and regulatory requirements.
SCOPE
1.1 This test method covers the determination of the density or relative density of light hydrocarbons including liquefied petroleum gases (LPG) having Reid vapor pressures exceeding 101.325 kPa (14.696 psi).  
1.2 The prescribed apparatus should not be used for materials having vapor pressures higher than 1.4 MPa (200 psi) at the test temperature. This pressure limit is dictated by the type of equipment. Higher pressures can apply to other equipment designs.  
1.3 The initial pressure hydrometer readings obtained are uncorrected hydrometer readings and not density measurements. Readings are measured on a hydrometer at either the reference temperature or at another convenient temperature, and readings are corrected for the meniscus effect, the thermal glass expansion effect, alternate calibration temperature effects and to the reference temperature by means of calculations and Adjunct to D1250 Guide for Petroleum Measurement Tables (API MPMS Chapter 11.1) or API MPMS Chapter 11.2.4 (GPA TP-27), as applicable.  
1.4 Values determined as density or relative density can be converted to equivalent values in the other units or alternative reference temperatures by means of Interconversion Procedures API MPMS  Chapter 11.5, or Adjunct to D1250 Guide for Petroleum Measurement Tables (API MPMS Chapter 11.1) or API MPMS Chapter 11.2.4 (GPA TP-27), as applicable.  
1.5 The calculations required in Section 11 shall be applied to the initial pressure hydrometer reading with observations and results reported as required by Section 11 prior to use in a subsequent calculation procedure (measurement ticket calculation, meter factor calculation, or base prover volume determination).  
1.6 Annex A1 contains a procedure for verifying or certifying the equipment for this test method.  
1.7 The values in SI units are to be regarded as the standard. US Customary values shown in adjacent parentheses are for information only and may not be exactly equivalent. Both SI and customary units have been rounded so that they may not be exactly equivalent.  
1.8 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.9 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
4.1 Representative samples of petroleum and petroleum products are required for the determination of chemical and physical properties, which are used to establish standard volumes, prices, and compliance with commercial terms and regulatory requirements. This practice does not cover sampling of electrical insulating oils and hydraulic fluids. This practice does not address how to sample crude at temperatures below the freezing point of water.
PART I—General
This part is applicable to all petroleum liquid sampling whether it be crude oil or refined products. Review this section before designing or installing any automatic sampling system.
SCOPE
1.1 This practice describes general procedures and equipment for automatically obtaining samples of liquid petroleum and petroleum products, crude oils, and intermediate products from the sample point into the primary container. This practice also provides additional specific information about sample container selection, preparation, and sample handling. If sampling is for the precise determination of volatility, use Practice D5842 (API MPMS Chapter 8.4) in conjunction with this practice. For sample mixing and handling, refer to Practice D5854 (API MPMS Chapter 8.3). This practice does not cover sampling of electrical insulating oils and hydraulic fluids.  
1.2 Table of Contents:    
Section  
INTRODUCTION  
Scope  
1  
Referenced Documents  
2  
Terminology  
3  
Significance and Use  
4  
PART I–GENERAL  
Representative Sampling Components  
5  
Design Criteria  
6  
Automatic Sampling Systems  
7  
Sampling Location  
8  
Mixing of the Flowing Stream  
9  
Proportionality  
10  
Sample Extractor Grab Volume  
11  
Containers  
12  
Sample Handling and Mixing  
13  
Control Systems  
14  
Sample System Security  
15  
System Proving (Performance Acceptance Tests)  
16  
Performance Monitoring  
17  
PART II–CRUDE OIL  
Crude Oil  
18  
PART III–REFINED PRODUCTS  
Refined Products  
19  
KEYWORDS  
Keywords  
20  
ANNEXES  
Calculations of the Margin of Error based on Number of Sample Grabs  
Annex A1  
Theoretical Calculations for Selecting the Sampler Probe Location  
Annex A2  
Portable Sampling Units  
Annex A3  
Profile Performance Test  
Annex A4  
Sampler Acceptance Test Data  
Annex A5  
APPENDIXES  
Design Data Sheet for Automatic Sampling System  
Appendix X1  
Comparisons of Percent Sediment and Water versus Unloading Time Period  
Appendix X2  
Sampling Frequency and Sampling System Monitoring Spreadsheet  
Appendix X3  
Sampling System Monitoring—Additional Diagnostics  
Appendix X4  
1.3 Units—The values stated in either SI units or US Customary (USC) units are to be regarded separately as standard. The values stated in each system may not be exact equivalents; therefore, each system shall be used independently of the other. Combining values from the two systems may result in non-conformance with the standard. Except where there is no direct SI equivalent, such as for National Pipe Threads/diameters, or tubing.  
1.4 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.5 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
4.1 Representative samples of petroleum and petroleum products are required for the determination of chemical and physical properties, which are used to establish standard volumes, prices, and compliance with commercial terms and regulatory requirements. This practice does not cover sampling of electrical insulating oils and hydraulic fluids. This practice does not address how to sample crude at temperatures below the freezing point of water.
PART I—General
This part is applicable to all petroleum liquid sampling whether it be crude oil or refined products. Review this section before designing or installing any automatic sampling system.
SCOPE
1.1 This practice describes general procedures and equipment for automatically obtaining samples of liquid petroleum and petroleum products, crude oils, and intermediate products from the sample point into the primary container. This practice also provides additional specific information about sample container selection, preparation, and sample handling. If sampling is for the precise determination of volatility, use Practice D5842 (API MPMS Chapter 8.4) in conjunction with this practice. For sample mixing and handling, refer to Practice D5854 (API MPMS Chapter 8.3). This practice does not cover sampling of electrical insulating oils and hydraulic fluids.  
1.2 Table of Contents:    
Section  
INTRODUCTION  
Scope  
1  
Referenced Documents  
2  
Terminology  
3  
Significance and Use  
4  
PART I–GENERAL  
Representative Sampling Components  
5  
Design Criteria  
6  
Automatic Sampling Systems  
7  
Sampling Location  
8  
Mixing of the Flowing Stream  
9  
Proportionality  
10  
Sample Extractor Grab Volume  
11  
Containers  
12  
Sample Handling and Mixing  
13  
Control Systems  
14  
Sample System Security  
15  
System Proving (Performance Acceptance Tests)  
16  
Performance Monitoring  
17  
PART II–CRUDE OIL  
Crude Oil  
18  
PART III–REFINED PRODUCTS  
Refined Products  
19  
KEYWORDS  
Keywords  
20  
ANNEXES  
Calculations of the Margin of Error based on Number of Sample Grabs  
Annex A1  
Theoretical Calculations for Selecting the Sampler Probe Location  
Annex A2  
Portable Sampling Units  
Annex A3  
Profile Performance Test  
Annex A4  
Sampler Acceptance Test Data  
Annex A5  
APPENDIXES  
Design Data Sheet for Automatic Sampling System  
Appendix X1  
Comparisons of Percent Sediment and Water versus Unloading Time Period  
Appendix X2  
Sampling Frequency and Sampling System Monitoring Spreadsheet  
Appendix X3  
Sampling System Monitoring—Additional Diagnostics  
Appendix X4  
1.3 Units—The values stated in either SI units or US Customary (USC) units are to be regarded separately as standard. The values stated in each system may not be exact equivalents; therefore, each system shall be used independently of the other. Combining values from the two systems may result in non-conformance with the standard. Except where there is no direct SI equivalent, such as for National Pipe Threads/diameters, or tubing.  
1.4 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.5 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 Accurate determination of the gravity of petroleum and its products is necessary for the conversion of measured volumes to volumes at the standard temperature of 60 °F (15.56 °C).  
5.2 This procedure is most suitable for determining the API gravity of low viscosity transparent liquids. This test method can also be used for viscous liquids by allowing sufficient time for the hydrometer to reach temperature equilibrium, and for opaque liquids by employing a suitable meniscus correction. Additionally for both transparent and opaque fluids the readings shall be corrected for the thermal glass expansion effect before correcting to the reference temperature.  
5.3 When used in connection with bulk oil measurements, volume correction errors are minimized by observing the hydrometer reading at a temperature as close to reference temperature as feasible.  
5.4 Gravity is a factor governing the quality of crude oils. However, the gravity of a petroleum product is an uncertain indication of its quality. Correlated with other properties, gravity can be used to give approximate hydrocarbon composition and heat of combustion.  
5.5 Gravity is an important quality indicator for automotive, aviation and marine fuels, where it affects storage, handling and combustion.
SCOPE
1.1 This test method covers the determination by means of a glass hydrometer in conjunction with a series of calculations of the API gravity of crude petroleum and petroleum products normally handled as liquids and having a Reid vapor pressure (Test Method D323) of 101.325 kPa (14.696 psi) or less. Gravities are determined at 60 °F (15.56 °C), or converted to values at 60 °F, by means of Adjunct to D1250 Guide for Petroleum Measurement Tables (API MPMS Chapter 11.1). These tables are not applicable to nonhydrocarbons or essentially pure hydrocarbons such as the aromatics.  
1.2 The initial values obtained are uncorrected hydrometer readings and not density measurements. Values are measured on a hydrometer at either the reference temperature or at another convenient temperature, and readings corrected for the meniscus effect, the thermal glass expansion effect, alternate calibration temperature effects and to the reference temperature by means of volume correction tables.  
1.3 The hydrometer readings determined shall be recorded before performing any calculations. Then the calculations required in Section 9 shall be performed and documented before using the final result in a subsequent calculation procedure (measurement ticket calculation, meter factor calculation, or base prover volume determination).  
1.4 The values stated in inch-pound units are to be regarded as standard. The values given in parentheses are mathematical conversions to SI units that are provided for information only and are not considered standard.  
1.5 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use. For specific warning statement, see 8.3.  
1.6 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 The vapor pressure parameters of volatile motor fuels are regulated by federal and state air pollution control agencies. In order to meet the letter of these regulations, it is necessary to sample, handle, and test these products in the precise manner as prescribed in this practice.
Note 1: This practice is not limited to dry vapor pressure equivalent testing for volatility. Dry vapor pressure equivalent is used to define the range for the sample matrix.
SCOPE
1.1 This practice covers procedures and equipment for obtaining, mixing, and handling representative samples of volatile fuels for the purpose of testing for compliance with the standards set forth for volatility related measurements applicable to light fuels.  
1.2 The applicable dry vapor pressure equivalent range of this practice is 13 kPa to 110 kPa (2 psia to 16 psia).  
1.3 This practice is applicable to the sampling, mixing, and handling of reformulated fuels including those containing oxygenates. This practice is not applicable to crude oil. For the sampling of crude oil, refer to Practice D4057/API MPMS Chapter 8.1, Practice D4177/API MPMS Chapter 8.2, and Practice D8009/API MPMS Chapter 8.5.  
1.4 The values stated in SI units are to be regarded as the standard except in some cases where drawings may show inch-pound measurements, which are customary for that equipment.  
1.5 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.6 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
4.1 Samples of petroleum and petroleum products are obtained for many reasons, including the determination of chemical and physical properties. These properties may be used for: calculating standard volumes; establishing product value; and often safety and regulatory reporting.  
4.2 There are inherent limitations when performing any type of sampling, any one of which may affect the representative nature of the sample. As examples, a spot sample provides a sample from only one particular point in the tank, vessel compartment, or pipeline. In the case of running or all-level samples, the sample only represents the column of material from which it was taken.  
4.3 Based on the product, and testing to be performed, this practice provides guidance on sampling equipment, container preparation, and manual sampling procedures for petroleum and petroleum products of a liquid, semi-liquid, or solid state, from the storage tanks, flowlines, pipelines, marine vessels, process vessels, drums, cans, tubes, bags, kettles, and open discharge streams into the primary sample container.
SCOPE
1.1 This practice covers procedures and equipment for manually obtaining samples of liquid petroleum and petroleum products, crude oils, and intermediate products from the sample point into the primary container are described. Procedures are also included for the sampling of free water and other heavy components associated with petroleum and petroleum products.  
1.2 This practice also addresses the sampling of semi-liquid or solid-state petroleum products. For the sampling of green petroleum coke, see Practice D8145. For the sampling of calcined petroleum coke, see Practice D6970.  
1.3 This practice provides additional specific information about sample container selection, preparation, and sample handling.  
1.4 This practice does not cover sampling of electrical insulating oils and hydraulic fluids. If sampling is for the precise determination of volatility, use Practice D5842 (API MPMS Chapter 8.4) in conjunction with this practice. For sample mixing and handling, refer to Practice D5854 (API MPMS Chapter 8.3).  
1.5 The procedures described in this practice may also be applicable in sampling most non-corrosive liquid industrial chemicals provided that all safety precautions specific to these chemicals are followed. Also, refer to Practice E300. The procedures described in this practice are also applicable to sampling liquefied petroleum gases and chemicals. Also refer to Practices D1265 and D3700. The procedure for sampling bituminous materials is described in Practice D140. Practice D4306 provides guidance on sample containers and preparation for sampling aviation fuel.  
1.6 Units—The values stated in SI units are to be regarded as the standard. USC units are reflected in parentheses.  
1.7 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.8 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 The expanded limits of the Adjunct for VCF are defined in a mixture of terms of customary and metric units. Table 1 shows the defining limits and their associated units in bold italics. Also shown in Table 1 are the limits converted to their equivalent units (and, in the case of the densities, other base temperatures).  
5.2 Note that only the precision levels of the defining values shown in Table 1 are correct. The other values showing converted units have been rounded to the significant digits shown; as rounded values, they may numerically fall just outside of the actual limits established by the defining values.  
5.3 Table 2 provides a cross-reference between the historical table designations and the corresponding section in the Adjunct for VCF. Note that procedure paragraphs 11.1.6.3 (U.S. customary units) and 11.1.7.3 (metric units) provide methods for correcting on-line density measurements from live conditions to base conditions and then to compute CTPL factors for continuous volume corrections to base conditions.  
5.4 When a glass hydrometer is used to measure the density of a liquid, special corrections must be made to account for the thermal expansion of the glass when the temperature is different from that at which the hydrometer was calibrated. The 1980 CTL Tables had generalized equations to correct glass hydrometer readings, and these corrections were part of the printed odd-numbered tables. However, detailed procedures to correct a glass hydrometer reading are beyond the scope of the Adjunct for VCF. The user should refer to the appropriate sections of API MPMS Chapter 9 or other appropriate density/hydrometer standards for guidance.  
5.5 The set of correlations given in the Adjunct for VCF is intended for use with petroleum fluids comprising either crude oils, refined products, or lubricating oils that are single-phase liquids under normal operating conditions. The liquid classifications listed here are typical terms used in the industry, ...
SCOPE
1.1 This guide provides information related to the algorithm and implementation procedure but does not contain the full set of algorithms. The algorithms, instructions, procedures, and examples are located in the associated supplementary adjuncts. The Adjunct for Volume Correction Factors (VCF) for temperature and pressure volume correction factors for generalized crude oils, refined products, and lubricating oils provides the algorithm and implementation procedure for the correction of temperature and pressure effects on density and volume of liquid hydrocarbons. Natural gas liquids (NGLs) and liquefied petroleum gases (LPGs) are excluded from consideration in this standard but may be found in API MPMS Chapter 11.2.4/GPA 8217 Temperature Correction for NGL and LPG. As this Adjunct for VCF will be applied to a variety of applications, the output parameters of CTL, Fp, CPL, and CTPL may be used as specified in other standards.  
1.2 Including the pressure correction in the Adjunct for VCF represents an important change from the “temperature only” correction factors given in the 1980 Petroleum Measurement Tables. However, if the pressure is one atmosphere (the standard pressure), then there is no pressure correction and the standard/adjunct(s) will give CTL values consistent with the 1980 Petroleum Measurement Tables.  
1.3 The Adjunct for VCF covers general procedures for the conversion of input data to generate CTL, Fp, CPL, and CTPL values at the user-specified base temperature and pressure (Tb, Pb). Two sets of procedures are included for computing volume correction factor: one set for data expressed in customary units (temperature in °F, pressure in psig); the other for the metric system of units (temperature in °C, pressure in kPa or bar).
Note 1: In contrast to the 1980 Petroleum Measurement Tables, the metric procedures require the procedure for customary units be used first to compute density at 60 °F. This va...

SIGNIFICANCE AND USE
4.1 Representative samples of petroleum and petroleum products are required for the determination of chemical and physical properties used to establish standard volumes, prices, and compliance with commercial and regulatory specifications. The treatment of samples from the time of collection until they are analyzed requires care and effort to maintain their compositional integrity. Samples of high RVP (unstabilized) hydrocarbons are required at many measurement points, for example offshore production, at the outlets of test separators or to allow calibration of a flowmeter. This practice also describes requirements associated with handling and mixing samples held within pressurized cylinders.  
4.2 Practice D4057 (API MPMS Chapter 8.1), Practice D4177 (API MPMS Chapter 8.2), Practice D5854 (API MPMS Chapter 8.3), Practice D5842 (API MPMS Chapter 8.4), and Practice D8009 (API MPMS Chapter 8.5). The primary purpose of this suite of standards, is to ensure proper sampling and handling for custody transfer applications. There are a significant number of test methods that may be used to analyze the samples taken by techniques described in API MPMS Chapter 8.1 and 8.2. For samples that are taken for test methods outside the general scope of custody transfer covered by this practice, the personnel assigned to take the sample are responsible to refer to the test methods for additional critical information that may impact the sampling process, that is, specific container selection, transport methods, storage times, etc. Those requirements should be found in the appropriate test method.
SCOPE
1.1 This practice covers handling, mixing, and conditioning procedures that are required to ensure that a representative sample of the liquid petroleum or petroleum product is delivered from the primary sample container or container or both into the analytical apparatus or into intermediate containers.  
1.2 Appendix X1 details the background information on the development of Table 1 used in performance testing. Appendix X2 provides guidance in the acceptance testing for water in crude oil. Appendix X3 provides a guide for materials of sample containers. Appendix X4 provides a summary of recommended mixing procedures. Appendix X5 provides a flow chart for sample container/mixing system acceptance test.  
1.3 For sampling procedures, refer to Practices D4057 (API MPMS Chapter 8.1) and D4177 (API MPMS Chapter 8.2). Practice D5842 (API MPMS Chapter 8.4) covers sampling and handling of light fuels for volatility measurement, and D8009 (API MPMS Chapter 8.5).  
1.4 It is recommended that the users of this practice perform the tests in Practice D4177 (API MPMS Chapter 8.2) before performing the test in this practice.  
1.5 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.6 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
4.1 Coal tar pitch is shipped or stored, or both, at various temperatures, consequently a means is required to correct volume to a specified temperature.
SCOPE
1.1 This practice covers calculation of the amount of expansion or contraction of a volume of liquid coal-tar pitch due to a change of temperature.  
1.2 The values stated in inch-pound units are to be regarded as standard. The values given in parentheses are mathematical conversions to SI units that are provided for information only and are not considered standard.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.4 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 A knowledge of the water content of petroleum products is important in the refining, purchase, sale, and transfer of products.  
5.2 The amount of water as determined by this test method (to the nearest 0.05 % or 0.1 % by volume, depending on the trap size used) may be used to correct the volume involved in the custody transfer of petroleum products and bituminous materials.  
5.3 The allowable amount of water may be specified in contracts.
SCOPE
1.1 This test method covers the determination of water in the range from 0 % to 25 % by volume in petroleum products, tars, and other bituminous materials by the distillation method.  
Note 1: Volatile water-soluble material, if present, may be measured as water.  
1.2 The specific products considered during the development of this test method are listed in Table 1. For bituminous emulsions refer to Test Method D244. For crude oils, refer to Test Method D4006 (API MPMS Chapter 10.2).
Note 2: With some types of oil, satisfactory results may be obtained from Test Method D1796 (API MPMS Chapter 10.6).  
1.3 The values stated in SI units are to be regarded as standard. The values given in parentheses after SI units are provided for information only and are not considered standard.  
1.4 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use. For specific hazard statements, see Section 6.  
1.5 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
3.1 Theoretically, all of the sediment and water determination methods are valid for crude oils containing from 0 % to 100 % by volume sediment and water; the range of application is specified within the scope of each method. The round robins for all methods were conducted on relatively dry oil. All precision and bias statements included in the methods are based upon the round robin data. Analysis becomes more challenging with crude oils containing higher water contents due to the difficulty in obtaining a representative sample, and maintaining the sample quality until analysis begins.  
3.2 Currently, Karl Fischer is generally used for dry crude oils containing less than 5 % water. Distillation is most commonly used for dry and wet crude oils and where separate sediment analysis is available or in situations where the sediment result is not significant. The laboratory centrifuge methods allow for determination of total sediment and water in a single analysis. The field centrifuge method is used when access to controlled laboratory conditions are not available.  
3.3 In the event of a dispute with regard to sediment and water content, contracting parties may refer to the technical specifications table to determine the most appropriate referee method based upon knowledge of and experience with the crude oil or product stream.
SCOPE
1.1 This guide covers a summary of the water and sediment determination methods from the API MPMS Chapter 10 for crude oils. The purpose of this guide is to provide a quick reference to these methodologies such that the reader can make the appropriate decision regarding which method to use based on the associated benefits, uses, drawbacks and limitations.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.4 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
4.1 Samples of petroleum and petroleum products are obtained for many reasons, including the determination of chemical and physical properties. These properties may be used for: calculating standard volumes; establishing product value; and often safety and regulatory reporting.  
4.2 There are inherent limitations when performing any type of sampling, any one of which may affect the representative nature of the sample. As examples, a spot sample provides a sample from only one particular point in the tank, vessel compartment, or pipeline. In the case of running or all-level samples, the sample only represents the column of material from which it was taken.  
4.3 Based on the product, and testing to be performed, this practice provides guidance on sampling equipment, container preparation, and manual sampling procedures for petroleum and petroleum products of a liquid, semi-liquid, or solid state, from the storage tanks, flowlines, pipelines, marine vessels, process vessels, drums, cans, tubes, bags, kettles, and open discharge streams into the primary sample container.
SCOPE
1.1 This practice covers procedures and equipment for manually obtaining samples of liquid petroleum and petroleum products, crude oils, and intermediate products from the sample point into the primary container are described. Procedures are also included for the sampling of free water and other heavy components associated with petroleum and petroleum products.  
1.2 This practice also addresses the sampling of semi-liquid or solid-state petroleum products.  
1.3 This practice provides additional specific information about sample container selection, preparation, and sample handling.  
1.4 This practice does not cover sampling of electrical insulating oils and hydraulic fluids. If sampling is for the precise determination of volatility, use Practice D5842 (API MPMS Chapter 8.4) in conjunction with this practice. For sample mixing and handling, refer to Practice D5854 (API MPMS Chapter 8.3).  
1.5 The procedures described in this practice may also be applicable in sampling most non-corrosive liquid industrial chemicals provided that all safety precautions specific to these chemicals are followed. Also, refer to Practice E300. The procedures described in this practice are also applicable to sampling liquefied petroleum gases and chemicals. Also refer to Practices D1265 and D3700. The procedure for sampling bituminous materials is described in Practice D140. Practice D4306 provides guidance on sample containers and preparation for sampling aviation fuel.  
1.6 Units—The values stated in SI units are to be regarded as the standard. USC units are reflected in parentheses.  
1.7 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.8 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 Accurate determination of the density, relative density (specific gravity), or API gravity of petroleum and its products is necessary for the conversion of measured volumes to volumes or masses, or both, at the standard reference temperatures of 15 °C or 60 °F during custody transfer.  
5.2 This procedure is most suitable for determining the density, relative density (specific gravity), or API gravity of low viscosity transparent liquids. This procedure can also be used for viscous liquids by allowing sufficient time for the hydrometer to reach temperature equilibrium, and for opaque liquids by employing a suitable meniscus correction. Additionally for both transparent and opaque fluids the readings shall be corrected for the thermal glass expansion effect and alternative calibration temperature effects before correcting to the reference temperature.  
5.3 When used in connection with bulk oil measurements, volume correction errors are minimized by observing the hydrometer reading at a temperature close to that of the bulk oil temperature.  
5.4 Density, relative density, or API gravity is a factor governing the quality and pricing of crude petroleum. However, this property of petroleum is an uncertain indication of its quality unless correlated with other properties.  
5.5 Density is an important quality indicator for automotive, aviation and marine fuels, where it affects storage, handling and combustion.
SCOPE
1.1 This test method covers the laboratory determination using a glass hydrometer in conjunction with a series of calculations, of the density, relative density, or API gravity of crude petroleum, petroleum products, or mixtures of petroleum and nonpetroleum products normally handled as liquids, and having a Reid vapor pressure of 101.325 kPa (14.696 psi) or less. Values are determined at existing temperatures and corrected to 15 °C or 60 °F by means of a series of calculations and international standard tables.  
1.2 The initial hydrometer readings obtained are uncorrected hydrometer readings and not density measurements. Readings are measured on a hydrometer at either the reference temperature or at another convenient temperature, and readings are corrected for the meniscus effect, the thermal glass expansion effect, alternative calibration temperature effects and to the reference temperature by means of the Petroleum Measurement Tables; values obtained at other than the reference temperature being hydrometer readings and not density measurements.  
1.3 Readings determined as density, relative density, or API gravity can be converted to equivalent values in the other units or alternative reference temperatures by means of Interconversion Procedures (API MPMS Chapter 11.5), or Adjunct to D1250 Guide for Petroleum Measurement Tables (API MPMS Chapter 11.1), or both, or tables, as applicable.  
1.4 The initial hydrometer readings determined in the laboratory shall be recorded before performing any calculations. The calculations required in Section 10 shall be applied to the initial hydrometer reading with observations and results reported as required by Section 11 prior to use in a subsequent calculation procedure (ticket calculation, meter factor calculation, or base prover volume determination).  
1.5 Annex A1 contains a procedure for verifying or certifying the equipment for this test method.  
1.6 The values stated in SI units are to be regarded as standard.  
1.6.1 Exception—The values given in parentheses are provided for information only.  
1.7 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.  
1.8 This international standard was developed in accordance with internationally recognized principles on standardization established in th...

SIGNIFICANCE AND USE
5.1 Density and API gravity are used in custody transfer quantity calculations and to satisfy transportation, storage, and regulatory requirements. Accurate determination of density or API gravity of crude petroleum and liquid petroleum products is necessary for the conversion of measured volumes to volumes at the standard temperatures of 15 °C or 60 °F.  
5.2 Density and API gravity are also factors that indicate the quality of crude petroleum. Crude petroleum prices are frequently posted against values in kg/m3 or in degrees API. However, this property of petroleum is an uncertain indication of its quality unless correlated with other properties.  
5.3 Field of Application—Because the thermohydrometer incorporates both the hydrometer and thermometer in one device, it is more applicable in field operations for determining density or API gravity of crude petroleum and other liquid petroleum products. The procedure is convenient for gathering main trunk pipelines and other field applications where limited laboratory facilities are available. The thermohydrometer method may have limitations in some petroleum density determinations. When this is the case, other methods such as Test Method D1298 (API MPMS Chapter 9.1) may be used.  
5.4 This procedure is suitable for determining the density, relative density, or API gravity of low viscosity, transparent or opaque liquids, or both. This procedure, when used for opaque liquids, requires the use of a meniscus correction (see 9.2). Additionally for both transparent and opaque fluids the readings shall be corrected for the thermal glass expansion effect and alternate calibration temperature effects before correcting to the reference temperature. This procedure can also be used for viscous liquids by allowing sufficient time for the thermohydrometer to reach temperature equilibrium.
SCOPE
1.1 This test method covers the determination, using a glass thermohydrometer in conjunction with a series of calculations, of the density, relative density, or API gravity of crude petroleum, petroleum products, or mixtures of petroleum and nonpetroleum products normally handled as liquids and having a Reid vapor pressures of 101.325 kPa (14.696 psi) or less. Values are determined at existing temperatures and corrected to 15 °C or 60 °F by means of a series of calculations and international standard tables.  
1.2 The initial thermohydrometer readings obtained are uncorrected hydrometer readings and not density measurements. Readings are measured on a thermohydrometer at either the reference temperature or at another convenient temperature, and readings are corrected for the meniscus effect, the thermal glass expansion effect, alternate calibration temperature effects and to the reference temperature by means of calculations and Adjunct to D1250 Guide for Use of the Petroleum Measurement Tables (API MPMS Chapter 11.1).  
1.3 Readings determined as density, relative density, or API gravity can be converted to equivalent values in the other units or alternate reference temperatures by means of Interconversion Procedures (API MPMS Chapter 11.5) or Adjunct to D1250 Guide for Use of the Petroleum Measurement Tables (API MPMS Chapter 11.1), or both, or tables as applicable.  
1.4 The initial thermohydrometer reading shall be recorded before performing any calculations. The calculations required in Section 9 shall be applied to the initial thermohydrometer reading with observations and results reported as required by Section 11 prior to use in a subsequent calculation procedure (measurement ticket calculation, meter factor calculation, or base prover volume determination).  
1.5 Annex A1 contains a procedure for verifying or certifying the equipment of this test method.  
1.6 The values stated in SI units are to be regarded as standard.  
1.6.1 Exception—The values given in parentheses are for information only.  
1.7 This standard does not purport to address all o...

SIGNIFICANCE AND USE
5.1 The density or relative density of light hydrocarbons and liquefied petroleum gases is used in custody transfer quantity calculations or to satisfy transportation, storage, and regulatory requirements.
SCOPE
1.1 This test method covers the determination of the density or relative density of light hydrocarbons including liquefied petroleum gases (LPG) having Reid vapor pressures exceeding 101.325 kPa (14.696 psi).  
1.2 The prescribed apparatus should not be used for materials having vapor pressures higher than 1.4 MPa (200 psi) at the test temperature. This pressure limit is dictated by the type of equipment. Higher pressures can apply to other equipment designs.  
1.3 The initial pressure hydrometer readings obtained are uncorrected hydrometer readings and not density measurements. Readings are measured on a hydrometer at either the reference temperature or at another convenient temperature, and readings are corrected for the meniscus effect, the thermal glass expansion effect, alternate calibration temperature effects and to the reference temperature by means of calculations and Adjunct to D1250 Guide for Petroleum Measurement Tables (API MPMS Chapter 11.1) or API MPMS Chapter 11.2.4 (GPA TP-27), as applicable.  
1.4 Values determined as density or relative density can be converted to equivalent values in the other units or alternative reference temperatures by means of Interconversion Procedures API MPMS  Chapter 11.5, or Adjunct to D1250 Guide for Petroleum Measurement Tables (API MPMS Chapter 11.1) or API MPMS Chapter 11.2.4 (GPA TP-27), as applicable.  
1.5 The calculations required in Section 11 shall be applied to the initial pressure hydrometer reading with observations and results reported as required by Section 11 prior to use in a subsequent calculation procedure (measurement ticket calculation, meter factor calculation, or base prover volume determination).  
1.6 Annex A1 contains a procedure for verifying or certifying the equipment for this test method.  
1.7 The values in SI units are to be regarded as the standard. US Customary values shown in adjacent parentheses are for information only and may not be exactly equivalent. Both SI and customary units have been rounded so that they may not be exactly equivalent.  
1.8 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.  
1.9 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
5.1 Density and API gravity are used in custody transfer quantity calculations and to satisfy transportation, storage, and regulatory requirements. Accurate determination of density or API gravity of crude petroleum and liquid petroleum products is necessary for the conversion of measured volumes to volumes at the standard temperatures of 15 °C or 60 °F.  
5.2 Density and API gravity are also factors that indicate the quality of crude petroleum. Crude petroleum prices are frequently posted against values in kg/m3 or in degrees API. However, this property of petroleum is an uncertain indication of its quality unless correlated with other properties.  
5.3 Field of Application—Because the thermohydrometer incorporates both the hydrometer and thermometer in one device, it is more applicable in field operations for determining density or API gravity of crude petroleum and other liquid petroleum products. The procedure is convenient for gathering main trunk pipelines and other field applications where limited laboratory facilities are available. The thermohydrometer method may have limitations in some petroleum density determinations. When this is the case, other methods such as Test Method D1298 (API MPMS Chapter 9.1) may be used.  
5.4 This procedure is suitable for determining the density, relative density, or API gravity of low viscosity, transparent or opaque liquids, or both. This procedure, when used for opaque liquids, requires the use of a meniscus correction (see 9.2). Additionally for both transparent and opaque fluids the readings shall be corrected for the thermal glass expansion effect and alternate calibration temperature effects before correcting to the reference temperature. This procedure can also be used for viscous liquids by allowing sufficient time for the thermohydrometer to reach temperature equilibrium.
SCOPE
1.1 This test method covers the determination, using a glass thermohydrometer in conjunction with a series of calculations, of the density, relative density, or API gravity of crude petroleum, petroleum products, or mixtures of petroleum and nonpetroleum products normally handled as liquids and having a Reid vapor pressures of 101.325 kPa (14.696 psi) or less. Values are determined at existing temperatures and corrected to 15 °C or 60 °F by means of a series of calculations and international standard tables.  
1.2 The initial thermohydrometer readings obtained are uncorrected hydrometer readings and not density measurements. Readings are measured on a thermohydrometer at either the reference temperature or at another convenient temperature, and readings are corrected for the meniscus effect, the thermal glass expansion effect, alternate calibration temperature effects and to the reference temperature by means of calculations and Adjunct to D1250 Guide for Use of the Petroleum Measurement Tables (API MPMS Chapter 11.1).  
1.3 Readings determined as density, relative density, or API gravity can be converted to equivalent values in the other units or alternate reference temperatures by means of Interconversion Procedures (API MPMS Chapter 11.5) or Adjunct to D1250 Guide for Use of the Petroleum Measurement Tables (API MPMS Chapter 11.1), or both, or tables as applicable.  
1.4 The initial thermohydrometer reading shall be recorded before performing any calculations. The calculations required in Section 9 shall be applied to the initial thermohydrometer reading with observations and results reported as required by Section 11 prior to use in a subsequent calculation procedure (measurement ticket calculation, meter factor calculation, or base prover volume determination).  
1.5 Annex A1 contains a procedure for verifying or certifying the equipment of this test method.  
1.6 The values stated in SI units are to be regarded as standard.  
1.6.1 Exception—The values given in parentheses are for information only.  
1.7 This standard does not purport to address all o...

SIGNIFICANCE AND USE
5.1 The vapor pressure parameters of volatile motor fuels are regulated by federal and state air pollution control agencies. In order to meet the letter of these regulations, it is necessary to sample, handle, and test these products in the precise manner as prescribed in this practice.
SCOPE
1.1 This practice covers procedures and equipment for obtaining, mixing, and handling representative samples of volatile fuels for the purpose of testing for compliance with the standards set forth for volatility related measurements applicable to light fuels.  
1.2 The applicable dry vapor pressure equivalent range of this practice is 13 kPa to 110 kPa (2 psia to 16 psia).  
1.3 This practice is applicable to the sampling, mixing, and handling of reformulated fuels including those containing oxygenates. This practice is not applicable to crude oil. For the sampling of crude oil, refer to Practice D4057/API MPMS Chapter 8.1, Practice D4177/API MPMS Chapter 8.2, and Practice D8009/API MPMS Chapter 8.5.  
1.4 The values stated in SI units are to be regarded as the standard except in some cases where drawings may show inch-pound measurements, which are customary for that equipment.  
1.5 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
1.6 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
4.1 A knowledge of the sediment content of crude oils and fuel oils is important both to the operation of refining and the buying or selling of these commodities.
SCOPE
1.1 This test method covers the determination of sediment in crude oils and fuel oils by extraction with toluene. The precision applies to a range of sediment levels from 0.01 % to 0.40 % mass, although higher levels may be determined.
Note 1: Precision on recycled oils and crankcase oils is unknown and additional testing is required to determine that precision.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use. For specific warning statements, see 5.1.1.6 and 6.1.  
1.4 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
4.1 A knowledge of the sediment content of crude oils and fuel oils is important both to the operation of refining and the buying or selling of these commodities.
SCOPE
1.1 This test method covers the determination of sediment in crude oils and fuel oils by extraction with toluene. The precision applies to a range of sediment levels from 0.01 % to 0.40 % mass, although higher levels may be determined.
Note 1: Precision on recycled oils and crankcase oils is unknown and additional testing is required to determine that precision.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use. For specific warning statements, see 5.1.1.6 and 6.1.  
1.4 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
4.1 Representative samples of petroleum and petroleum products are required for the determination of chemical and physical properties, which are used to establish standard volumes, prices, and compliance with commercial terms and regulatory requirements. This practice does not cover sampling of electrical insulating oils and hydraulic fluids. This practice does not address how to sample crude at temperatures below the freezing point of water.
PART I—General
This part is applicable to all petroleum liquid sampling whether it be crude oil or refined products. Review this section before designing or installing any automatic sampling system.
SCOPE
1.1 This practice describes general procedures and equipment for automatically obtaining samples of liquid petroleum and petroleum products, crude oils, and intermediate products from the sample point into the primary container. This practice also provides additional specific information about sample container selection, preparation, and sample handling. If sampling is for the precise determination of volatility, use Practice D5842 (API MPMS Chapter 8.4) in conjunction with this practice. For sample mixing and handling, refer to Practice D5854 (API MPMS Chapter 8.3). This practice does not cover sampling of electrical insulating oils and hydraulic fluids.  
1.2 Table of Contents:    
Section  
INTRODUCTION  
Scope  
1  
Referenced Documents  
2  
Terminology  
3  
Significance and Use  
4  
PART I–GENERAL  
Representative Sampling Components  
5  
Design Criteria  
6  
Automatic Sampling Systems  
7  
Sampling Location  
8  
Mixing of the Flowing Stream  
9  
Proportionality  
10  
Sample Extractor Grab Volume  
11  
Containers  
12  
Sample Handling and Mixing  
13  
Control Systems  
14  
Sample System Security  
15  
System Proving (Performance Acceptance Tests)  
16  
Performance Monitoring  
17  
PART II–CRUDE OIL  
Crude Oil  
18  
PART III–REFINED PRODUCTS  
Refined Products  
19  
KEYWORDS  
Keywords  
20  
ANNEXES  
Calculations of the Margin of Error based on Number of Sample Grabs  
Annex A1  
Theoretical Calculations for Selecting the Sampler Probe Location  
Annex A2  
Performance Criteria for Portable Sampling Units  
Annex A3  
Profile Performance Test  
Annex A4  
Sampler Acceptance Test Data  
Annex A5  
APPENDIXES  
Design Data Sheet for Automatic Sampling System  
Appendix X1  
Comparisons of Percent Sediment and Water versus Unloading Time Period  
Appendix X2  
1.3 Units—The values stated in either SI units or US Customary (USC) units are to be regarded separately as standard. The values stated in each system may not be exact equivalents; therefore, each system shall be used independently of the other. Combining values from the two systems may result in non-conformance with the standard. Except where there is no direct SI equivalent, such as for National Pipe Threads/diameters, or tubing.  
1.4 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.

SIGNIFICANCE AND USE
4.1 Representative samples of petroleum and petroleum products are required for the determination of chemical and physical properties, which are used to establish standard volumes, prices, and compliance with commercial terms and regulatory requirements. This practice does not cover sampling of electrical insulating oils and hydraulic fluids. This practice does not address how to sample crude at temperatures below the freezing point of water.
PART I—General
This part is applicable to all petroleum liquid sampling whether it be crude oil or refined products. Review this section before designing or installing any automatic sampling system.
SCOPE
1.1 This practice describes general procedures and equipment for automatically obtaining samples of liquid petroleum and petroleum products, crude oils, and intermediate products from the sample point into the primary container. This practice also provides additional specific information about sample container selection, preparation, and sample handling. If sampling is for the precise determination of volatility, use Practice D5842 (API MPMS Chapter 8.4) in conjunction with this practice. For sample mixing and handling, refer to Practice D5854 (API MPMS Chapter 8.3). This practice does not cover sampling of electrical insulating oils and hydraulic fluids.  
1.2 Table of Contents:    
Section  
INTRODUCTION  
Scope  
1  
Referenced Documents  
2  
Terminology  
3  
Significance and Use  
4  
PART I–GENERAL  
Representative Sampling Components  
5  
Design Criteria  
6  
Automatic Sampling Systems  
7  
Sampling Location  
8  
Mixing of the Flowing Stream  
9  
Proportionality  
10  
Sample Extractor Grab Volume  
11  
Containers  
12  
Sample Handling and Mixing  
13  
Control Systems  
14  
Sample System Security  
15  
System Proving (Performance Acceptance Tests)  
16  
Performance Monitoring  
17  
PART II–CRUDE OIL  
Crude Oil  
18  
PART III–REFINED PRODUCTS  
Refined Products  
19  
KEYWORDS  
Keywords  
20  
ANNEXES  
Calculations of the Margin of Error based on Number of Sample Grabs  
Annex A1  
Theoretical Calculations for Selecting the Sampler Probe Location  
Annex A2  
Performance Criteria for Portable Sampling Units  
Annex A3  
Profile Performance Test  
Annex A4  
Sampler Acceptance Test Data  
Annex A5  
APPENDIXES  
Design Data Sheet for Automatic Sampling System  
Appendix X1  
Comparisons of Percent Sediment and Water versus Unloading Time Period  
Appendix X2  
1.3 Units—The values stated in either SI units or US Customary (USC) units are to be regarded separately as standard. The values stated in each system may not be exact equivalents; therefore, each system shall be used independently of the other. Combining values from the two systems may result in non-conformance with the standard. Except where there is no direct SI equivalent, such as for National Pipe Threads/diameters, or tubing.  
1.4 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.  
1.5 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

SIGNIFICANCE AND USE
4.1 A knowledge of the water content of crude oil is important in the refining, purchase, sale, or transfer of crude oils.  
4.2 This test method may not be suitable for crude oils that contain alcohols that are soluble in water. In cases where the impact on the results may be significant, the user is advised to consider using another test method, such as Test Method D4928 (API MPMS Chapter 10.9).
SCOPE
1.1 This test method covers the determination of water in crude oil by distillation.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use. For specific warning statements, see 6.1 and A1.1.

SIGNIFICANCE AND USE
4.1 The water and sediment content of crude oil is significant because it can cause corrosion of equipment and problems in processing. A determination of water and sediment content is required to measure accurately net volumes of actual oil in sales, taxation, exchanges, and custody transfers. It is not anticipated that this test method, which is written with a dedicated laboratory facility in mind, is likely to be used in field test rooms or sample rooms due to safety concerns for proper ventilation and handling.  
4.2 This test method may not be suitable for crude oils that contain alcohols that are soluble in water. In cases where the impact on the results may be significant, the user is advised to consider using another test method, such as Test Method D4928 (API MPMS Chapter 10.9).
SCOPE
1.1 This test method describes the laboratory determination of water and sediment in crude oils by means of the centrifuge procedure. This centrifuge method for determining water and sediment in crude oils is not entirely satisfactory. The amount of water detected is almost always lower than the actual water content. When a highly accurate value is required, the revised procedures for water by distillation, Test Method D4006 (API MPMS Chapter 10.2) (Note 1), and sediment by extraction, Test Method D473 (API MPMS Chapter 10.1), shall be used.  
Note 1: Test Method D4006 (API MPMS Chapter 10.2) has been determined to be the preferred and most accurate method for the determination of water.  
1.2 The values stated in SI units are to be regarded as standard.  
1.2.1 Exception—The values given in parentheses are for information only.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use. Specific warning statements appear in 6.1, 8.3, and A1.5.4.

SIGNIFICANCE AND USE
4.1 The water and sediment content of crude oil is significant because it can cause corrosion of equipment and problems in processing. A determination of water and sediment content is required to measure accurately net volumes of actual oil in sales, taxation, exchanges, and custody transfers. It is not anticipated that this test method, which is written with a dedicated laboratory facility in mind, is likely to be used in field test rooms or sample rooms due to safety concerns for proper ventilation and handling.  
4.2 This test method may not be suitable for crude oils that contain alcohols that are soluble in water. In cases where the impact on the results may be significant, the user is advised to consider using another test method, such as Test Method D4928 (API MPMS Chapter 10.9).
SCOPE
1.1 This test method describes the laboratory determination of water and sediment in crude oils by means of the centrifuge procedure. This centrifuge method for determining water and sediment in crude oils is not entirely satisfactory. The amount of water detected is almost always lower than the actual water content. When a highly accurate value is required, the revised procedures for water by distillation, Test Method D4006 (API MPMS Chapter 10.2) (Note 1), and sediment by extraction, Test Method D473 (API MPMS Chapter 10.1), shall be used.  
Note 1: Test Method D4006 (API MPMS Chapter 10.2) has been determined to be the preferred and most accurate method for the determination of water.  
1.2 The values stated in SI units are to be regarded as standard.  
1.2.1 Exception—The values given in parentheses are for information only.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use. Specific warning statements appear in 6.1, 8.3, and A1.5.4.

SIGNIFICANCE AND USE
4.1 A knowledge of the water content of crude oil is important in the refining, purchase, sale, or transfer of crude oils.  
4.2 This test method may not be suitable for crude oils that contain alcohols that are soluble in water. In cases where the impact on the results may be significant, the user is advised to consider using another test method, such as Test Method D4928 (API MPMS Chapter 10.9).
SCOPE
1.1 This test method covers the determination of water in crude oil by distillation.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use. For specific warning statements, see 6.1 and A1.1.

SIGNIFICANCE AND USE
4.1 The water and sediment content of fuel oil is significant because it can cause corrosion of equipment and problems in processing. A determination of water and sediment content is required to measure accurately net volumes of actual fuel oil in sales, taxation, exchanges, and custody transfers.  
4.2 This test method may not be suitable for products that contain alcohols that are soluble in water. In cases where the impact on the results may be significant, the user is advised to consider using another test method, such as Test Method D6304.
SCOPE
1.1 This test method describes the laboratory determination of water and sediment in fuel oils in the range from 0 % to 30 % volume by means of the centrifuge procedure.
Note 1: With some types of fuel oils such as residual fuel oils or distillate fuel oils containing residual components, it is difficult to obtain water or sediment contents with this test method. When this situation is encountered, Test Method D95 (API MPMS Chapter 10.5) or Test Method D473 (API  MPMS Chapter 10.1) may be used.
Note 2: API MPMS Chapter 10.6 (Test Method D1796) along with API MPMS Chapter 10.3 (Test Method D4007) formerly superseded API Standard 2548.  
1.2 The values stated in SI units are to be regarded as the standard. The values given in parentheses are for information only.  
1.3 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use. For a specific precautionary statement, see 6.1.

SIGNIFICANCE AND USE
A knowledge of the water content of lubricating oils, additives, and similar products is important in the manufacturing, purchase, sale, or transfer of such petroleum products to help in predicting their quality and performance characteristics.
For lubricating oils, the presence of moisture could lead to premature corrosion and wear, an increase in the debris load resulting in diminished lubrication and premature plugging of filters, an impedance in the effect of additives, and undesirable support of deleterious bacterial growth.
SCOPE
1.1 This test method covers the direct determination of water in the range of 10 to 25 000 mg/kg entrained water in petroleum products and hydrocarbons using automated instrumentation. This test method also covers the indirect analysis of water thermally removed from samples and swept with dry inert gas into the Karl Fischer titration cell. Mercaptan, sulfide (S  or H2S), sulfur, and other compounds are known to interfere with this test method (see Section 5).
1.2 This test method is intended for use with commercially available coulometric Karl Fischer reagents and for the determination of water in additives, lube oils, base oils, automatic transmission fluids, hydrocarbon solvents, and other petroleum products. By proper choice of the sample size, this test method may be used for the determination of water from mg/kg to percent level concentrations.
1.3 The values stated in SI units are to be regarded as standard. No other units of measurements are included in this standard.
This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.
WITHDRAWN RATIONALE
This test method covers the direct determination of water in the range of 10 to 25 000 mg/kg entrained water in petroleum products and hydrocarbons using automated instrumentation. This test method also covers the indirect analysis of water thermally removed from samples and swept with dry inert gas into the Karl Fischer titration cell. Mercaptan, sulfide (S− or H2S), sulfur, and other compounds are known to interfere with this test method.
Formerly under the jurisdiction of Committee D02 on Petroleum Products, Liquid Fuels, and Lubricants, this test method was withdrawn in April 2016 in accordance with section 10.5.3.1 of the Regulations Governing ASTM Technical Committees, which requires that standards shall be updated by the end of the eighth year since the last approval date.

SIGNIFICANCE AND USE
5.1 This practice allows the collection of a representative sample of crude oil and/or condensate that may contain trace volatile dissolved components such as methane, ethane, propane, and fixed gases that would normally be lost using conventional atmospheric sampling methods. These highly volatile components can result in vapor pressure conditions above atmospheric pressure. This practice is recommended whenever accurate determination of vapor pressure, flash point, or other properties are required and where loss of volatile components can affect the test results.  
5.2 This practice is intended for capturing samples of crude oil and/or condensate for testing for the purpose of classification for transportation of dangerous goods as UN Class 3 Flammable Liquids, but is not limited to classification testing. Other test methods with sensitivities to light end loss may also utilize this sampling practice.  
5.3 Practice D3700 using a floating piston cylinder is recommended whenever true vapor pressures greater than 300 kPa at 50 °C are anticipated.
SCOPE
1.1 This practice includes the equipment and procedures for obtaining a representative sample of “live” or high vapor pressure crude oils, condensates, and/or liquid petroleum products from low pressure sample points, where there is insufficient sample point pressure to use a Floating Piston Cylinder (FPC) as described in Practice D3700.  
1.2 This practice is intended for use with sample types, such as UN Class 3 Flammable Liquids, that might have been collected and transported using open containers. The use of a manual piston cylinder in place of open containers is intended to prevent the loss of volatile (light end) components, which can impact subsequent test results.  
1.3 This practice is suitable for sampling crude oils, condensates, and/or liquid petroleum products having true vapor pressures less than 300 kPa (43 psia nominal) at 50 °C. This practice applies to samples that will typically fall between Practices D4057 (API MPMS Chapter 8.1) and D3700. This practice shall not be used for materials classified as UN Class 2 Gases (“…having a vapor pressure greater than 300 kPa at 50 °C or is completely gaseous at 20 °C at 101.3 kPa.”).  
1.4 This practice allows for sampling of crude oils that flow freely at the conditions of sampling.  
1.5 It is the responsibility of the user to ensure that the sampling point is located so as to obtain a representative sample.  
1.6 The values stated in SI units are to be regarded as standard.  
1.6.1 Exception—The values given in parentheses are for information only.  
1.7 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.

SIGNIFICANCE AND USE
4.1 Representative samples of petroleum and petroleum products are required for the determination of chemical and physical properties, which are used to establish standard volumes, prices, and compliance with commercial terms and regulatory requirements. This practice does not cover sampling of electrical insulating oils and hydraulic fluids. This practice does not address how to sample crude at temperatures below the freezing point of water.
PART I—General
This part is applicable to all petroleum liquid sampling whether it be crude oil or refined products. Review this section before designing or installing any automatic sampling system.
SCOPE
1.1 This practice describes general procedures and equipment for automatically obtaining samples of liquid petroleum and petroleum products, crude oils, and intermediate products from the sample point into the primary container. This practice also provides additional specific information about sample container selection, preparation, and sample handling. If sampling is for the precise determination of volatility, use Practice D5842 (API MPMS Chapter 8.4) in conjunction with this practice. For sample mixing and handling, refer to Practice D5854 (API MPMS Chapter 8.3). This practice does not cover sampling of electrical insulating oils and hydraulic fluids.  
1.2 Table of Contents:    
Section  
INTRODUCTION  
Scope  
1  
Referenced Documents  
2  
Terminology  
3  
Significance and Use  
4  
PART I–GENERAL  
Representative Sampling Components  
5  
Design Criteria  
6  
Automatic Sampling Systems  
7  
Sampling Location  
8  
Mixing of the Flowing Stream  
9  
Proportionality  
10  
Sample Extractor Grab Volume  
11  
Containers  
12  
Sample Handling and Mixing  
13  
Control Systems  
14  
Sample System Security  
15  
System Proving (Performance Acceptance Tests)  
16  
Performance Monitoring  
17  
PART II–CRUDE OIL  
Crude Oil  
18  
PART III–REFINED PRODUCTS  
Refined Products  
19  
KEYWORDS  
Keywords  
20  
ANNEXES  
Calculations of the Margin of Error based on Number of Sample Grabs  
Annex A1  
Theoretical Calculations for Selecting the Sampler Probe Location  
Annex A2  
Performance Criteria for Portable Sampling Units  
Annex A3  
Profile Performance Test  
Annex A4  
Sampler Acceptance Test Data  
Annex A5  
APPENDIXES  
Design Data Sheet for Automatic Sampling System  
Appendix X1  
Comparisons of Percent Sediment and Water versus Unloading Time Period  
Appendix X2  
1.3 Units—The values stated in either SI units or US Customary (USC) units are to be regarded separately as standard. The values stated in each system may not be exact equivalents; therefore, each system shall be used independently of the other. Combining values from the two systems may result in non-conformance with the standard. Except where there is no direct SI equivalent, such as for National Pipe Threads/diameters, or tubing.  
1.4 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.

SIGNIFICANCE AND USE
4.1 Representative samples of petroleum and petroleum products are required for the determination of chemical and physical properties, which are used to establish standard volumes, prices, and compliance with commercial terms and regulatory requirements. This practice does not cover sampling of electrical insulating oils and hydraulic fluids. This practice does not address how to sample crude at temperatures below the freezing point of water.
PART I—General
This part is applicable to all petroleum liquid sampling whether it be crude oil or refined products. Review this section before designing or installing any automatic sampling system.
SCOPE
1.1 This practice describes general procedures and equipment for automatically obtaining samples of liquid petroleum and petroleum products, crude oils, and intermediate products from the sample point into the primary container. This practice also provides additional specific information about sample container selection, preparation, and sample handling. If sampling is for the precise determination of volatility, use Practice D5842 (API MPMS Chapter 8.4) in conjunction with this practice. For sample mixing and handling, refer to Practice D5854 (API MPMS Chapter 8.3). This practice does not cover sampling of electrical insulating oils and hydraulic fluids.  
1.2 Table of Contents:    
Section  
INTRODUCTION  
Scope  
1  
Referenced Documents  
2  
Terminology  
3  
Significance and Use  
4  
PART I–GENERAL  
Representative Sampling Components  
5  
Design Criteria  
6  
Automatic Sampling Systems  
7  
Sampling Location  
8  
Mixing of the Flowing Stream  
9  
Proportionality  
10  
Sample Extractor Grab Volume  
11  
Containers  
12  
Sample Handling and Mixing  
13  
Control Systems  
14  
Sample System Security  
15  
System Proving (Performance Acceptance Tests)  
16  
Performance Monitoring  
17  
PART II–CRUDE OIL  
Crude Oil  
18  
PART III–REFINED PRODUCTS  
Refined Products  
19  
KEYWORDS  
Keywords  
20  
ANNEXES  
Calculations of the Margin of Error based on Number of Sample Grabs  
Annex A1  
Theoretical Calculations for Selecting the Sampler Probe Location  
Annex A2  
Performance Criteria for Portable Sampling Units  
Annex A3  
Profile Performance Test  
Annex A4  
Sampler Acceptance Test Data  
Annex A5  
APPENDIXES  
Design Data Sheet for Automatic Sampling System  
Appendix X1  
Comparisons of Percent Sediment and Water versus Unloading Time Period  
Appendix X2  
1.3 Units—The values stated in either SI units or US Customary (USC) units are to be regarded separately as standard. The values stated in each system may not be exact equivalents; therefore, each system shall be used independently of the other. Combining values from the two systems may result in non-conformance with the standard. Except where there is no direct SI equivalent, such as for National Pipe Threads/diameters, or tubing.  
1.4 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.

SIGNIFICANCE AND USE
4.1 A knowledge of the sediment content of crude oil is important both in refinery operations and in crude oil commerce.
SCOPE
1.1 This test method covers the determination of sediment in crude oils by membrane filtration. This test method has been validated for crude oils with sediments up to approximately 0.15 mass %.  
1.2 The accepted unit of measure for this test method is mass %, but an equation to convert to volume % is provided (see Note 6).  
1.3 The values stated in SI units are to be regarded as the standard. The values given in parentheses are for information only.  
1.4 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use. For specific warning statements, see 6.1 and Annex A1.