75.040 - Crude petroleum
ICS 75.040 Details
Crude petroleum
Rohol
Pétrole brut
Surova nafta
General Information
Frequently Asked Questions
ICS 75.040 is a classification code in the International Classification for Standards (ICS) system. It covers "Crude petroleum". The ICS is a hierarchical classification system used to organize international, regional, and national standards, facilitating the search and identification of standards across different fields.
There are 272 standards classified under ICS 75.040 (Crude petroleum). These standards are published by international and regional standardization bodies including ISO, IEC, CEN, CENELEC, and ETSI.
The International Classification for Standards (ICS) is a hierarchical classification system maintained by ISO to organize standards and related documents. It uses a three-level structure with field (2 digits), group (3 digits), and sub-group (2 digits) codes. The ICS helps users find standards by subject area and enables statistical analysis of standards development activities.
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This document specifies a method for the determination of arsenic content in crude oil pretreated by a closed microwave digestion method by atomic fluorescence spectrometry. The precision statement of this test method was determined in an interlaboratory study and is valid for samples with an arsenic content between 0,35 mg/kg and 3,57 mg/kg. The test method can also be applied to samples with either a higher or lower arsenic content, however, no precision data has been determined at levels outside of this range.
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This document specifies a method for the determination, using an oscillating U-tube density meter, of the density of crude petroleum and related products within the range 600 kg/m3 to 1 100 kg/m3, which can be handled as single-phase liquids at the test temperature and pressure.
This document is applicable to liquids of any vapour pressure as long as suitable precautions are taken to ensure that they remain in single phase. Loss of light components leads to changes in density during both the sample handling and the density determination.
This method is not intended for use with in-line density meters.
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SIGNIFICANCE AND USE
4.1 Identification of the source of a spilled oil is established by comparison with known oils selected because of their possible relationship to the spill, that is, potential sources. Generally, the suspected source oils are from pipelines, tanks, etc., and therefore pose little problems in sampling compared to the spilled oil. This practice addresses the sampling of spilled oils in particular, but could be applied to appropriate source situations, for example, a ship's bilge.
SCOPE
1.1 These practices describe the procedures to be used in collecting samples of waterborne oils (see Practice D3415), oil found on adjoining shorelines, or oil-soaked debris, for comparison of oils by spectroscopic and chromatographic techniques, and for elemental analyses.
1.2 Two practices are described. Practice A involves “grab sampling” macro oil samples. Practice B can be used to sample most types of waterborne oils and is particularly applicable in sampling thin oil films or slicks. Practice selection will be dictated by the physical characteristics and the location of the spilled oil. These two practices are:
Sections
Practice A (for grab sampling thick layers of oil, viscous oils or oil soaked debris, oil globules, tar balls, or stranded oil)
9 to 13
Practice B (for TFE–fluorocarbon polymer strip samplers)
14 to 17
1.3 Each of the two practices is designed to collect oil samples with a minimum of water, thereby reducing the possibility of chemical, physical, or biological alteration by prolonged contact with water between the time of collection and analysis.
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 hazards statements, see Section 7.
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.
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SIGNIFICANCE AND USE
5.1 In the absence of water, the crude oil is noncorrosive. However, trace amounts of water and sediment have the potential to create corrosive situations during crude oil handling or transport if such materials accumulate and persist on steel surfaces. Test Methods D473 and D4006 provide methods for determination of the water and sediment content of crude oil.
5.2 The potential for a corrosive situation to develop during the handling and transport of crude oil that contains water can be determined by a combination of three properties (Fig. 1) (1)6: the type of emulsion formed between oil and water, the wettability of the steel surface, and the corrosivity of water phase in the presence of oil.
FIG. 1 Predicting Influence of Crude Oil on the Corrosivity of Aqueous Phase
5.3 Water and oil are immiscible but, under certain conditions, they can form emulsion. There are two kinds of emulsion: oil-in-water (O/W) and water-in-oil (W/O). W/O emulsion (in which oil is the continuous phase) has low conductivity and is thus less corrosive; whereas O/W (in which water is the continuous phase) has high conductivity and, hence, is corrosive (2) (see ISO 6614). The percentage of water at which W/O converts to O/W is known as the emulsion inversion point (EIP). EIP can be determined by measuring the conductivity of the emulsion. At and above the EIP, a continuous phase of water or free water is present. Therefore, there is a potential for corrosion.
5.4 Whether water phase can cause corrosion in the presence of oil depends on whether the surface is oil-wet (hydrophobic) or water-wet (hydrophilic) (1, 3-5). Because of higher resistance, an oil-wet surface is not susceptible to corrosion, but a water-wet surface is. Wettability can be characterized by measuring the contact angle or by evaluating the tendency of water to displace oil from a multi-electrode array by measuring the resistance (or conductors) between the electrodes (spreading methodology).
5.4.1 In the con...
SCOPE
1.1 This guide covers some generally accepted laboratory methodologies that are used for determining emulsion forming tendency, wetting behavior, and corrosion-inhibitory properties of crude oil.
1.2 This guide does not cover detailed calculations and methods, but rather covers a range of approaches that have found application in evaluating emulsions, wettability, and the corrosion rate of steel in crude oil/water mixtures.
1.3 Only those methodologies that have found wide acceptance in the industry are considered in this guide.
1.4 This guide is intended to assist in the selection of methodologies that can be used for determining the corrosivity of crude oil under conditions in which water is present in the liquid state (typically up to 100 °C). These conditions normally occur during oil and gas production, storage, and transportation in the pipelines.
1.5 This guide is not applicable at higher temperatures (typically above 300 °C) that occur during refining crude oil in refineries.
1.6 This guide involves the use of electrical currents in the presence of flammable liquids. Awareness of fire safety is critical for the safe use of this guide.
1.7 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.
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.
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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...
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SIGNIFICANCE AND USE
5.1 This test method provides a rapid and precise elemental measurement with simple sample preparation. Typical analysis times are approximately 4 min to 5 min per sample with a preparation time of approximately 1 min to 3 min per sample.
5.2 The quality of crude oil is related to the amount of sulfur present. Knowledge of the vanadium and nickel concentration is necessary for processing purposes as well as contractual agreements.
5.3 The presence of vanadium and nickel presents significant risks for contamination of the cracking catalysts in the refining process.
5.4 This test method provides a means of determining whether the vanadium and nickel content of crude meets the operational limits of the refinery and whether the metal content will have a deleterious effect on the refining process or when used as a fuel.
SCOPE
1.1 This test method covers the quantitative determination of total vanadium and nickel in crude and residual oil in the concentration ranges shown in Table 1 using X-ray fluorescence (XRF) spectrometry.
1.2 Sulfur is measured for analytical purposes only for the compensation of X-ray absorption matrix effects affecting the vanadium and nickel X-rays. For measurement of sulfur by standard test method use Test Methods D4294, D2622 or other suitable standard test method for sulfur in crude and residual oils.
1.3 This test method is limited to the use of X-ray fluorescence (XRF) spectrometers employing an X-ray tube for excitation in conjunction with wavelength dispersive detection system or energy dispersive high resolution semiconductor detector with the ability to separate signals of adjacent and near-adjacent elements.
1.4 This test method uses inter-element correction factors calculated from XRF theory, the fundamental parameters (FP) approach, or best fit regression.
1.5 Samples containing higher concentrations than shown in Table 1 must be diluted to bring the elemental concentration of the diluted material within the scope of this test method.
1.6 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.
1.6.1 The preferred concentrations units are mg/kg for vanadium and nickel.
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.
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SIGNIFICANCE AND USE
5.1 This test method is one of a number of tests conducted on a crude oil to determine its value. It provides an estimate of the yields of fractions of various boiling ranges and is therefore valuable in technical discussions of a commercial nature.
5.2 This test method corresponds to the standard laboratory distillation efficiency referred to as 15/5. The fractions produced can be analyzed as produced or combined to produce samples for analytical studies, engineering, and product quality evaluations. The preparation and evaluation of such blends is not part of this test method.
5.3 This test method can be used as an analytical tool for examination of other petroleum mixtures with the exception of LPG, very light naphthas, and mixtures with initial boiling points above 400 °C.
SCOPE
1.1 This test method covers the procedure for the distillation of stabilized crude petroleum (see Note 1) to a final cut temperature of 400 °C Atmospheric Equivalent Temperature (AET). This test method employs a fractionating column having an efficiency of 14 to 18 theoretical plates operated at a reflux ratio of 5:1. Performance criteria for the necessary equipment is specified. Some typical examples of acceptable apparatus are presented in schematic form. This test method offers a compromise between efficiency and time in order to facilitate the comparison of distillation data between laboratories.
Note 1: Defined as having a Reid vapor pressure less than 82.7 kPa (12 psi).
1.2 This test method details procedures for the production of a liquefied gas, distillate fractions, and residuum of standardized quality on which analytical data can be obtained, and the determination of yields of the above fractions by both mass and volume. From the preceding information, a graph of temperature versus mass % distilled can be produced. This distillation curve corresponds to a laboratory technique, which is defined at 15/5 (15 theoretical plate column, 5:1 reflux ratio) or TBP (true boiling point).
1.3 This test method can also be applied to any petroleum mixture except liquefied petroleum gases, very light naphthas, and fractions having initial boiling points above 400 °C.
1.4 This test method contains the following annexes and appendixes:
1.4.1 Annex A1—Test Method for the Determination of the Efficiency of a Distillation Column,
1.4.2 Annex A2—Test Method for the Determination of the Dynamic Holdup of a Distillation Column,
1.4.3 Annex A3—Test Method for the Determination of the Heat Loss in a Distillation Column (Static Conditions),
1.4.4 Annex A4—Test Method for the Verification of Temperature Sensor Location,
1.4.5 Annex A5—Test Method for Determination of the Temperature Response Time,
1.4.6 Annex A6—Practice for the Calibration of Sensors,
1.4.7 Annex A7—Test Method for the Verification of Reflux Dividing Valves,
1.4.8 Annex A8—Practice for Conversion of Observed Vapor Temperature to Atmospheric Equivalent Temperature (AET),
1.4.9 Appendix X1—Test Method for Dehydration of a Sample of Wet Crude Oil, and
1.4.10 Appendix X2—Practice for Performance Check.
1.5 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.
1.6 WARNING—Mercury has been designated by many regulatory agencies as a hazardous substance that can cause serious medical issues. Mercury, or its vapor, has been demonstrated to be hazardous to health and corrosive to materials. Use Caution when handling mercury and mercury-containing products. See the applicable product Safety Data Sheet (SDS) for additional information. The potential exists that selling mercury or mercury-containing products, or both, is prohibited by local or national law. Users must determine legality of sales in their location.
1.7 This standard does not purport to address all of the safety concerns, if any, asso...
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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.
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SIGNIFICANCE AND USE
5.1 Most often determined trace elements in crude oils are nickel and vanadium, which are usually the most abundant; however, as many as 45 elements in crude oils have been reported. Knowledge of trace elements in crude oil is important because they can have an adverse effect on petroleum refining and product quality. These effects can include catalyst poisoning in the refinery and excessive atmospheric emission in combustion of fuels. Trace element concentrations are also useful in correlating production from different wells and horizons in a field. Elements such as iron, arsenic, and lead are catalyst poisons. Vanadium compounds can cause refractory damage in furnaces, and sodium compounds have been found to cause superficial fusion on fire brick. Some organometallic compounds are volatile which can lead to the contamination of distillate fractions, and a reduction in their stability or malfunctions of equipment when they are combusted.
5.2 The value of crude oil can be determined, in part, by the concentrations of nickel, vanadium, and iron.
5.3 Inductively coupled plasma-atomic emission spectrometry (ICP-AES) is a widely used technique in the oil industry. Its advantages over traditional atomic absorption spectrometry (AAS) include greater sensitivity, freedom from molecular interferences, wide dynamic range, and multi-element capability. See Practice D7260.
SCOPE
1.1 This test method covers the determination of several elements (including iron, nickel, sulfur, and vanadium) occurring in crude oils.
1.2 For analysis of any element using wavelengths below 190 nm, a vacuum or inert gas optical path is required.
1.3 Analysis for elements such as arsenic, selenium, or sulfur in whole crude oil may be difficult by this test method due to the presence of their volatile compounds of these elements in crude oil; but this test method should work for resid samples.
1.4 Because of the particulates present in crude oil samples, if they do not dissolve in the organic solvents used or if they do not get aspirated in the nebulizer, low elemental values may result, particularly for iron and sodium. This can also occur if the elements are associated with water which can drop out of the solution when diluted with solvent.
1.4.1 An alternative in such cases is using Test Method D5708, Procedure B, which involves wet decomposition of the oil sample and measurement by ICP-AES for nickel, vanadium, and iron, or Test Method D5863, Procedure A, which also uses wet acid decomposition and determines vanadium, nickel, iron, and sodium using atomic absorption spectrometry.
1.4.2 From ASTM Interlaboratory Crosscheck Programs (ILCP) on crude oils data available so far, it is not clear that organic solvent dilution techniques would necessarily give lower results than those obtained using acid decomposition techniques.2
1.4.3 It is also possible that, particularly in the case of silicon, low results may be obtained irrespective of whether organic dilution or acid decomposition is utilized. Silicones are present as oil field additives and can be lost in ashing. Silicates should be retained but unless hydrofluoric acid or alkali fusion is used for sample dissolution, they may not be accounted for.
1.5 This test method uses oil-soluble metals for calibration and does not purport to quantitatively determine insoluble particulates. Analytical results are particle size dependent and low results may be obtained for particles larger than a few micrometers.
1.6 The precision in Section 18 defines the concentration ranges covered in the interlaboratory study. However, lower and particularly higher concentrations can be determined by this test method. The low concentration limits are dependent on the sensitivity of the ICP instrument and the dilution factor used. The high concentration limits are determined by the product of the maximum concentration defined by the calibration curve and the sample di...
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SIGNIFICANCE AND USE
5.1 Crude oils and oil sands bitumen contain naturally occurring acidic species. Acidity of crude oil has been implicated in corrosion of distribution and process systems. The relative amount of these materials can be determined by titrating with bases. The acid number is a measure of this amount of acidic substance in the oil under the conditions of the test.
5.2 Acid number of crude and distilled petroleum fractions has been measured by Test Method D664. Test Method D664 was developed for the analysis of lubricants and biodiesel. The titration solvent used in Test Method D664 does not properly address dissolving difficult samples such as crude oil, bitumen, and high wax samples addressed in this test method. Refer to Appendix X1.
5.3 Test Method D974 is also not applicable to measuring acidity of crudes and highly colored samples because the indicator is not visible or it is difficult to discern a color change to detect the end point of the titration.
SCOPE
1.1 This test method covers the determination of acidic components in crude oil and petroleum products including waxes, bitumen, base stocks, and asphalts that are soluble in mixtures of xylenes and propan-2-ol. It is applicable for the determination of acids whose dissociation constants in water are larger than 10–9; extremely weak acids whose dissociation constants are smaller than 10–9 do not interfere. The values obtained by this test method may not be numerically equivalent to other acid value measurements. The range of KOH acid numbers included in the precision statement is 0.1 mg/g to 16 mg/g.
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. Some specific hazards statements are given in Section 7 on Safety Precautions.
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.
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SIGNIFICANCE AND USE
3.1 A standard procedure is necessary to measure the adhesive properties of oil to enable comparison between oils.
3.2 This procedure uses standardized equipment and test procedures.
3.3 This procedure should be performed at the stages of weathering corresponding to the spill conditions of interest.
SCOPE
1.1 This guide summarizes a method to measure the adhesion to a stainless-steel needle as means to compare the relative adhesion of the target oil.
1.2 This guide covers general procedures for measuring the adhesion of oils to stainless steel and does not cover all possible procedures that may be applicable to this topic.
1.3 The accuracy of this guide depends very much on the representative nature of the oil sample used. Certain oils can have different properties depending on their chemical contents at the time a sample is taken.
1.4 Units—The values stated in SI units are to be regarded as the 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.
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.
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SIGNIFICANCE AND USE
5.1 This test method describes a sensitive method for estimating the intrinsic stability of an oil. The intrinsic stability is expressed as S-value. An oil with a low S-value is likely to undergo flocculation of asphaltenes when stressed (for example, extended heated storage) or blended with a range of other oils. Two oils each with a high S-value are likely to maintain asphaltenes in a peptized state and not lead to asphaltene flocculation when blended together.
5.2 This test method can be used by petroleum refiners to control and optimize the refinery processes and by blenders and marketers to assess the intrinsic stability of blended asphaltene-containing heavy fuel oils.
SCOPE
1.1 This test method covers procedures for quantifying the intrinsic stability of the asphaltenes in an oil by automatic instruments using optical detection.
1.2 This test method is applicable to residual products from thermal and hydrocracking processes, to products typical of Specifications D396 Grades No. 5L, 5H, and 6, and D2880 Grades No. 3-GT and 4-GT, and to crude oils, providing these products contain 0.5 % by mass or greater concentration of asphaltenes (see Test Method D6560).
1.3 This test method quantifies asphaltene stability in terms of state of peptization of the asphaltenes (S-value), intrinsic stability of the oily medium (So) and the solvency requirements of the peptized asphaltenes (Sa).
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.
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.
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SIGNIFICANCE AND USE
5.1 When fuels are combusted, metals present in the fuels can form low melting compounds that are corrosive to metal parts. Metals present at trace levels in petroleum can deactivate catalysts during processing. These test methods provide a means of quantitatively determining the concentrations of vanadium, nickel, iron, and sodium. Thus, these test methods can be used to aid in determining the quality and value of the crude oil and residual oil.
SCOPE
1.1 These test methods cover the determination of nickel, vanadium, iron, and sodium in crude oils and residual fuels by flame atomic absorption spectrometry (AAS). Two different test methods are presented.
1.2 Procedure A, Sections 8–14—Flame AAS is used to analyze a sample that is decomposed with acid for the determination of total Ni, V, and Fe.
1.3 Procedure B, Sections 15–20—Flame AAS is used to analyze a sample diluted with an organic solvent for the determination of Ni, V, and Na. This test method uses oil-soluble metals for calibration to determine dissolved metals and does not purport to quantitatively determine nor detect insoluble particulates. Hence, this test method may underestimate the metal content, especially sodium, present as inorganic sodium salts.
1.4 The concentration ranges covered by these test methods are determined by the sensitivity of the instruments, the amount of sample taken for analysis, and the dilution volume. A specific statement is given in Note 1.
1.5 For each element, each test method has its own unique precision. The user can select the appropriate test method based on the precision required for the specific analysis.
1.6 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard, unless specifically stated. Other units that appear in this standard are included for information purposes only or because they are in embedded pictures that cannot be edited.
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. Specific warning statements are given in 8.1, 9.2, 9.5, 11.2, 11.4, and 16.1.
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.
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SIGNIFICANCE AND USE
5.1 This test method determines methane (nC1) to hexane (nC6), cut point carbon fraction intervals to nC24 and recovery (nC24+) of live crude oils and condensates without depressurizing, thereby avoiding the loss of highly volatile components and maintaining sample integrity. This test method provides a highly resolved light end profile which can aid in determining and improving appropriate safety measures and product custody transport procedures. Decisions in regards to marketing, scheduling, and processing of crude oils may rely on light end compositional results.
5.2 Equation of state calculations can be applied to variables provided by this method to allow for additional sample characterization.
SCOPE
1.1 This test method covers the determination of light hydrocarbons and cut point intervals by gas chromatography in live crude oils and condensates with VPCR4 (see Note 1) up to 500 kPa at 37.8 °C.
Note 1: As described in Test Method D6377.
1.2 Methane (C1) to hexane (nC6) and benzene are speciated and quantitated. Samples containing mass fractions of up to 0.5 % methane, 2.0 % ethane, 10 % propane, or 15 % isobutane may be analyzed. A mass fraction with a lower limit of 0.001 % exists for these compounds.
1.3 This test method may be used for the determination of cut point carbon fraction intervals (see 3.2.1) of live crude oils and condensates from initial boiling point (IBP) to 391 °C (nC24). The nC24 plus fraction is reported.
1.4 Dead oils or condensates sampled in accordance with 12.1 may also be analyzed.
1.5 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.
1.5.1 Exception—Where there is no direct SI equivalent such as tubing size.
1.6 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.
1.7 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.
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SIGNIFICANCE AND USE
5.1 Insoluble material may form in oils that are subjected to oxidizing conditions.
5.2 Significant formation of oil insolubles or metal corrosion products, or both, during this test may indicate that the oil will form insolubles or corrode metals, or both, during field service. However, no correlation with field service has been established.
SCOPE
1.1 This test method covers and is used to evaluate the tendency of inhibited mineral oil based steam turbine lubricants and mineral oil based anti-wear hydraulic oils to corrode copper catalyst metal and to form sludge during oxidation in the presence of oxygen, water, and copper and iron metals at an elevated temperature. The test method is also used for testing circulating oils having a specific gravity less than that of water and containing rust and oxidation inhibitors.
Note 1: During round robin testing copper and iron in the oil, water and sludge phases were measured. However, the values for the total iron were found to be so low (that is, below 0.8 mg), that statistical analysis was inappropriate. The results of the cooperative test program are available (see Section 16).
1.2 This test method is a modification of Test Method D943 where the oxidation stability of the same kinds of oils is determined by following the acid number of oil. The number of test hours required for the oil to reach an acid number of 2.0 mg KOH/g is the oxidation lifetime.
1.3 Procedure A of this test method requires the determination and report of the weight of the sludge and the total amount of copper in the oil, water, and sludge phases. Procedure B requires the sludge determination only. The acid number determination is optional for both procedures.
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 WARNING—Mercury has been designated by many regulatory agencies as a hazardous substance that can cause serious medical issues. Mercury, or its vapor, has been demonstrated to be hazardous to health and corrosive to materials. Use Caution when handling mercury and mercury-containing products. See the applicable product Safety Data Sheet (SDS) for additional information. The potential exists that selling mercury or mercury-containing products, or both, is prohibited by local or national law. Users must determine legality of sales in their location.
1.6 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 7 and X1.1.5.
1.7 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.
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SIGNIFICANCE AND USE
5.1 Organic chlorides do not occur naturally in crude oil. When present, they result from contamination in some manner, such as disposal of chlorinated solvent used in many dewaxing pipeline or other equipment operations.
5.1.1 Uncontaminated crude oil will contain no detectable organic chloride, and most refineries can handle very small amounts without deleterious effects.
5.1.1.1 Most trade contracts specify that no organic chloride is present in the crude oil.
5.1.2 Several pipelines have set specification limits at
5.1.2.1 To ensure Eq 3).
5.1.3 Organic chloride present in the crude oil (for example, methylene chloride, perchloroethylene, etc.) is usually distilled into the naphtha fraction. Some compounds break down during fractionation and produce hydrochloric acid, which has a corrosive effect. Some compounds survive fractionation and are destroyed during hydro-treating (desulfurization of the naphtha).
5.2 Other halides can also be used for dewaxing crude oil; in such cases, any organic halides will have similar impact on the refining operations as the organic chlorides.
5.3 Organic chloride species are potentially damaging to refinery processes. Hydrochloric acid can be produced in hydrotreating or reforming reactors and the acid accumulates in condensing regions of the refinery. Unexpected concentrations of organic chlorides cannot be effectively neutralized and damage can result. Organic chlorides are not known to be naturally present in crude oils and usually result from cleaning operations at producing sites, pipelines, or tanks. It is important for the oil industry to have common methods available for the determination of organic chlorides in crude oil, particularly when transfer of custody is involved.
SCOPE
1.1 The procedures in this test method cover the determination of organic chloride (above 1 μg/g organically-bound chlorine) in crude oils, using either distillation and sodium biphenyl reduction, distillation and microcoulometry, or distillation and X-ray fluorescence (XRF) spectrometry.
1.2 The procedures in this test method involve the distillation of crude oil test specimens to obtain a naphtha fraction prior to chloride determination. The chloride content of the naphtha fraction of the whole crude oil can thereby be obtained. See Section 6 regarding potential interferences.
1.3 Procedure A covers the determination of organic chloride in the washed naphtha fraction of crude oil by sodium biphenyl reduction followed by potentiometric titration.
1.4 Procedure B covers the determination of organic chloride in the washed naphtha fraction of crude oil by oxidative combustion followed by microcoulometric titration.
1.5 Procedure C covers the determination of organic chloride in the washed naphtha fraction of crude oil by X-ray fluorescence spectrometry.
1.6 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.
1.6.1 The preferred concentration units are micrograms of chloride per gram of sample, though milligrams of chloride per kilogram of sample is commonly used for Procedure C.
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.
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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.
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SIGNIFICANCE AND USE
5.1 Organic chlorides do not occur naturally in crude oil. When present, they result from contamination in some manner, such as disposal of chlorinated solvent used in many dewaxing pipeline or other equipment operations.
5.1.1 Uncontaminated crude oil will contain no detectable organic chloride, and most refineries can handle very small amounts without deleterious effects.
5.1.1.1 Most trade contracts specify that no organic chloride is present in the crude oil.
5.1.2 Several pipelines have set specification limits less than 1 μg/g organic chlorides in the whole crude, and less than 5 μg/g in the light naphtha, based on the yield of naphtha being 20 % of the original sample.
5.1.2.1 To ensure less than 1 μg/g organic chloride in the crude oil, the amount measured in the naphtha fraction shall be less than 1/f (where f is the naphtha fraction calculated with Eq 1). For example, a crude oil sample with 1 μg/g of organic chloride but a 10 % yield of naphtha would create a naphtha containing 10 μg/g organic chloride. Further, a crude containing 1 μg/g of organic chloride but a 40 % yield of naphtha would create a naphtha containing 2.5 μg/g organic chloride. Due to the difference in naphtha yields, the impact on refining operations can be significantly different.
5.1.2.2 Since crude oil deposits worldwide exhibit different yields of naphtha, the working range of detection for this method shall cover a broad range, possibly as high as 50 μg/g in a naphtha fraction.
5.1.3 Organic chloride present in the crude oil (for example, methylene chloride, perchloroethylene, etc.) is usually distilled into the naphtha fraction. Some compounds break down during fractionation and produce hydrochloric acid, which has a corrosive effect. Some compounds survive fractionation and are destroyed during hydro-treating (desulfurization of the naphtha).
5.2 Other halides can also be used for dewaxing crude oil; in such cases, any organic halides will have similar impact on ...
SCOPE
1.1 This test method covers the determination of organic chloride (above 1 μg/g organically-bound chlorine) in crude oils, using distillation and combustion ion chromatography.
1.2 This test method involves the distillation of crude oil test specimens to obtain a naphtha fraction prior to chloride determination. The chloride content of the naphtha fraction of the whole crude oil can thereby be obtained. See Section 6 regarding potential interferences.
1.3 The test procedure covers the determination of organic chloride in the washed naphtha fraction of crude oil by combustion ion chromatography. Other halides can be determined but are not included in the precision statement of the test method.
1.4 The values stated in SI units are to be regarded as standard. The preferred concentration units are micrograms of chloride per gram of sample.
1.4.1 Exception—The values given in parentheses are for information only.
1.5 Warning—Mercury has been designated by many regulatory agencies as a hazardous substance that can cause serious medical issues. Mercury, or its vapor, has been demonstrated to be hazardous to health and corrosive to materials. Use caution when handling mercury and mercury-containing products. See the applicable product Safety Data Sheet (SDS) for additional information. The potential exists that selling mercury or mercury-containing products, or both, is prohibited by local or national law. Users must determine legality of sales in their location.
1.6 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.
1.7 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision ...
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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.
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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.
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SIGNIFICANCE AND USE
5.1 Density is a fundamental physical property that may be used in conjunction with other properties to characterize the quality of crude oils.
5.2 The density or relative density of crude oils is used for the conversion of measured volumes to volumes at the standard temperatures of 15 °C or 60 °F and for the conversion of crude mass measurements into volume units.
5.3 The application of the density result obtained from this test method, for fiscal or custody transfer accounting calculations, may require measurements of the water and sediment contents obtained on similar specimens of the crude oil parcel.
SCOPE
1.1 This test method covers the determination of the density, relative density, and API gravity of crude oils that may be handled in a normal fashion as liquids at test temperatures between 15 °C and 35 °C utilizing either manual or automated sample injection equipment. This test method applies to crude oils with high vapor pressures provided appropriate precautions are taken to prevent vapor loss during transfer of the sample to the density analyzer.
1.2 This test method was evaluated in interlaboratory study testing using crude oils in the 0.75 g/mL to 0.95 g/mL range. Lighter crude oil may require special handling to prevent vapor losses.
1.3 The values stated in SI units are to be regarded as standard. Other units of measurement are included in this standard. The accepted units of measurement of density are grams per millilitre and kilograms per cubic metre.
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. Specific warning statements are given in 7.4, 7.5, and 7.6.
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.
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SIGNIFICANCE AND USE
5.1 Asphaltenes are the organic molecules of highest molecular mass and carbon-hydrogen ratio normally occurring in crude petroleum and petroleum products containing residual material. They may give problems during storage and handling if the suspension of asphaltene molecules is disturbed through excess stress or incompatibility. They are also the last molecules in a product to combust completely, and thus may be one indicator of black smoke propensity. Their composition normally includes a disproportionately high quantity of the sulfur, nitrogen, and metals present in the crude petroleum or petroleum product.
SCOPE
1.1 This test method covers a procedure for the determination of the heptane insoluble asphaltene content of gas oil, diesel fuel, residual fuel oils, lubricating oil, bitumen, and crude petroleum that has been topped to an oil temperature of 260 °C (see A1.2.1.1).
1.2 The precision is applicable to values between 0.50 % m/m and 30.0 % m/m. Values outside this range may still be valid but may not give the same precision values.
1.3 Oils containing additives may give erroneous results.
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.
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.
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SIGNIFICANCE AND USE
5.1 Methanol is used in production of crude oil to prevent formation of gas hydrates. The presence of residual methanol in crude oils can lead to costly problems in refinery operations.
SCOPE
1.1 This test method covers the determination of methanol in crude oils by direct injection multidimensional gas chromatography in the concentration range of 15 ppm (m/m) to 900 ppm (m/m). The pooled limit of quantification (PLOQ) is 15 ppm (m/m).
1.2 This test method is applicable only to crude oils containing less than or equal to 0.1 % (v/v) water.
1.3 This test method has not been tested with crude oil samples that are solid or waxy, or both, at ambient temperatures.
1.4 The values stated in SI units are to be regarded as standard. Alternate units, in common usage, are also provided to increase clarity and aid the users of this test method.
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.
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SIGNIFICANCE AND USE
5.1 This test method provides a guide for determining the water separation characteristics of oils subject to water contamination and turbulence. It is used for specification of new oils and monitoring of in-service oils.
SCOPE
1.1 This test method covers measurement of the ability of petroleum oils or synthetic fluids to separate from water. Although developed specifically for steam-turbine oils having viscosities of 28.8 mm2/s to 90 mm2/s at 40 °C, this test method may be used to test oils of other types having various viscosities and synthetic fluids at other test temperatures. It is recommended, however, that the test temperature be raised to 82 °C ± 1 °C when testing products more viscous than 90 mm2/s at 40 °C. For higher viscosity oils where there is insufficient mixing of oil and water, Test Method D2711 is recommended. Other test temperatures such as 25 °C may also be used. A 1 % sodium choloride (NaCl) solution or synthetic seawater may be used in place of distilled water when testing certain oils or fuels used in marine applications.
1.2 When testing synthetic fluids whose relative densities are greater than that of water, the procedure is unchanged, but it should be noted that the water will probably float on the emulsion or liquid.
1.3 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this 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 warning statements, see Section 7.
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.
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This document describes a method for the determination of the boiling range distribution of petroleum products by capillary gas chromatography using flame ionization detection. The standard is applicable to crude oils. The boiling range distribution and recovery to C100 or C120 can be determined.
Two procedures are described: single and dual analysis mode. The basis of each is the calculation procedure as described in Annex A.
Procedure A (or Single analysis mode) determines the boiling range through C100 or C120 in a single analysis.
Procedure B (or Dual analysis mode) combines procedure A with the boiling point distribution from C1 up to C9 using the Detailed Hydrocarbon Analysis (DHA) according EN 15199-4. The results of both analyses are merged into one boiling point distribution.
NOTE 1 There is no specific precision statement for the combined results obtained by procedure B. For the precision of the boiling range distribution according to procedure B the precision statements of procedure A and EN 15199-4 apply. No precision has been determined for the results after merging.
NOTE 2 For the purpose of this document, the terms "% (m/m)" and "% (V/V)" are used to represent the mass fraction, μ, and the volume fraction, φ, of a material respectively.
WARNING - Use of this document may involve hazardous materials, operations and equipment. This document does not purport to address all of the safety problems associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and to determine the applicability of regulatory limitations prior to use.
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SIGNIFICANCE AND USE
5.1 Knowledge of gas solubility is of extreme importance in the lubrication of gas compressors. It is believed to be a substantial factor in boundary lubrication, where the sudden release of dissolved gas may cause cavitation erosion, or even collapse of the fluid film. In hydraulic and seal oils, gas dissolved at high pressure can cause excessive foaming on release of the pressure. In aviation oils and fuels, the difference in pressure between take-off and cruise altitude can cause foaming in storage vessels and interrupt flow to pumps.
SCOPE
1.1 This test method covers a procedure for estimating the equilibrium solubility of several common gases in petroleum and synthetic lubricants, fuels, and solvents, at temperatures between 0 and 488 K.
1.2 This test method is limited to systems in which polarity and hydrogen bonding are not strong enough to cause serious deviations from regularity. Specifically excluded are such gases as HCl, NH3, and SO2, and hydroxy liquids such as alcohols, glycols, and water. Estimating the solubility of CO2 in nonhydrocarbons is also specifically excluded.
1.3 Highly aromatic oils such as diphenoxy phenylene ethers violate the stated accuracy above 363 K, at which point the estimate for nitrogen solubility is 43 % higher than the observation.
1.4 Lubricants are given preference in this test method to the extent that certain empirical factors were adjusted to the lubricant data. Estimates for distillate fuels are made from the lubricant estimates by a further set of empirical factors, and are less accurate. Estimates for halogenated solvents are made as if they were hydrocarbons, and are the least accurate of the three.
1.5 The values stated in SI units are to be regarded as the standard. The values in parentheses are for information only.
1.6 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.
1.7 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.
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SIGNIFICANCE AND USE
5.1 Accurate elemental analysis of petroleum products and lubricants is necessary for the determination of chemical properties, which are used to establish compliance with commercial and regulatory specifications.
5.2 Atomic Absorption Spectrometry (AAS) is one of the most widely used analytical techniques in the oil industry for elemental analysis. There are at least twelve Standard Test Methods published by ASTM D02 Committee on Petroleum Products and Lubricants for such analysis. See Table 1.
5.3 The advantage of using an AAS analysis include good sensitivity for most metals, relative freedom from interferences, and ability to calibrate the instrument based on elemental standards irrespective of their elemental chemical forms. Thus, the technique has been a method of choice in most of the oil industry laboratories. In many laboratories, AAS has been superseded by a superior ICP-AES technique (see Practice D7260).
5.4 Some of the ASTM AAS Standard Test Methods have also been issued by other standard writing bodies as technically equivalent standards. See Table 2. (A) Excerpted from ASTM MNL44, Guide to ASTM Test Methods for the Analysis of Petroleum Products and Lubricants, 2nd edition, Ed., Nadkarni, R. A. Kishore, ASTM International, West Conshohocken, PA, 2007.
SCOPE
1.1 This practice covers information on the calibration and operational guidance for elemental measurements using atomic absorption spectrometry (AAS).
1.1.1 AAS Related Standards—Test Methods D1318, D3237, D3340, D3605, D3831, D4628, D5056, D5184, D5863, D6732; Practices D7260 and D7455; and Test Methods D7622 and D7623.
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.
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SIGNIFICANCE AND USE
5.1 The emission of mercury during crude oil refining is an environmental concern. The emission of mercury may also contaminate refined products and form amalgams with metals, such as aluminum.
5.2 When representative test portions are analyzed according to this procedure, the total mercury is representative of concentrations in the sample.
SCOPE
1.1 This test method covers the procedure to determine the total mercury content in a sample of crude oil. This test method can be used for total mercury determination in natural and processed liquid and oil products (gasoline, naphtha, etc.).
1.2 This test method may be applied to samples containing between 5.0 ng/mL to 350 ng/mL of mercury. The results may be converted to mass basis.
1.3 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.
1.4 This work has been published in “Determination of Mercury in Crude Oil by Atomic Spectroscopy.”2
1.5 WARNING—Mercury has been designated by many regulatory agencies as a hazardous substance that can cause serious medical issues. Mercury, or its vapor, has been demonstrated to be hazardous to health and corrosive to materials. Use Caution when handling mercury and mercury-containing products. See the applicable product Safety Data Sheet (SDS) for additional information. The potential exists that selling mercury or mercury-containing products, or both, is prohibited by local or national law. Users must determine legality of sales in their location.
1.6 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.
1.7 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.
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SIGNIFICANCE AND USE
5.1 Vapor pressure of crude oil at various V/Ls is an important physical property for shipping and storage.
Note 2: A vapor-liquid ratio of 0.02:1 (X = 0.02) mimics closely the situation of an oil tanker.
5.2 Vapor pressure of crude oil is important to crude oil producers and refiners for general handling and initial refinery treatment.
5.3 The vapor pressure determined by this test method at a vapor-liquid ratio of 4:1 (VPCR4) of crude oil at 37.8 °C can be related to the vapor pressure value determined on the same material when tested by Test Method D323 (see Appendix X1).
5.4 Air saturation of crude oil shall not be done to avoid potential vapor loss. However air saturation of the chilled verification fluid is mandatory (see 7.2 and Section 11).
5.5 This test method can also be applied in online applications.
SCOPE
1.1 This test method covers the use of automated vapor pressure instruments to determine the vapor pressure exerted in vacuum of crude oils. This test method is suitable for testing samples that exert a vapor pressure between 25 kPa and 180 kPa at 37.8 °C at vapor-liquid ratios from 4:1 and 0.02:1 (X = 4 and 0.02).
Note 1: This test method is suitable for the determination of the vapor pressure of crude oils at temperatures from 0 °C to 100 °C and pressures up to 500 kPa, but the precision and bias statements (see Section 14) may not be applicable. The current precision of the method is limited at vapor-liquid ratios of 0.02 and 4. (Section 14 is inclusive of vapor-liquid ratios of 0.02 and 4).
1.2 This test method also allows the determination of vapor pressure for crude oil samples having pour points above 15 °C provided the proper sample handling, transfer, and analysis procedures are followed.
1.3 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this 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 warning statements, see 7.2.1 – 7.3.2.
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.
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SIGNIFICANCE AND USE
5.1 The emission of mercury during crude oil refining is an environmental concern. The emission of mercury may also contaminate refined products and form amalgams with metals, such as aluminum.
5.2 When representative test portions are analyzed according to this procedure, the total mercury is representative of concentrations in the sample.
SCOPE
1.1 This test method covers the procedures to determine the total mercury content in a sample of crude oil.
1.2 The test method may be applied to crude oil samples containing between 5 ng/mL to 400 ng/mL of mercury. The results may be converted to mass basis, and reported as ng/g of mercury.
1.3 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.
1.4 This work has been published in “Determination of Mercury in Crude Oil by Atomic Spectroscopy.”2
1.5 WARNING—Mercury has been designated by many regulatory agencies as a hazardous substance that can cause serious medical issues. Mercury, or its vapor, has been demonstrated to be hazardous to health and corrosive to materials. Use Caution when handling mercury and mercury-containing products. See the applicable product Safety Data Sheet (SDS) for additional information. The potential exists that selling mercury or mercury-containing products, or both, is prohibited by local or national law. Users must determine legality of sales in their location.
1.6 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.
1.7 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.
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SIGNIFICANCE AND USE
4.1 These test methods cover, in single procedures, the determination of Ni, V, and Fe in crude oils and residual oils. These test methods complement Test Method D1548, which covers only the determination of vanadium.
4.2 When fuels are combusted, vanadium present in the fuel can form corrosive compounds. The value of crude oils can be determined, in part, by the concentrations of nickel, vanadium, and iron. Nickel and vanadium, present at trace levels in petroleum fractions, can deactivate catalysts during processing. These test methods provide a means of determining the concentrations of nickel, vanadium, and iron.
SCOPE
1.1 These test methods cover the determination of nickel, vanadium, and iron in crude oils and residual fuels by inductively coupled plasma (ICP) atomic emission spectrometry. Two different test methods are presented.
1.2 Test Method A (Sections 7 – 11 and 18 – 22)—ICP is used to analyze a sample dissolved in an organic solvent. This test method uses oil-soluble metals for calibration and does not purport to quantitatively determine or detect insoluble particulates.
1.3 Test Method B (Sections 12 – 22)—ICP is used to analyze a sample that is decomposed with acid.
1.4 The concentration ranges covered by these test methods are determined by the sensitivity of the instruments, the amount of sample taken for analysis, and the dilution volume. A specific statement is given in 15.2. Typically, the low concentration limits are a few tenths of a milligram per kilogram. Precision data are provided for the concentration ranges specified in Section 21.
1.5 The values stated in SI units are to be regarded as standard.
1.5.1 Exception—The values given in parentheses are for information only.
1.6 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.
1.7 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.
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SIGNIFICANCE AND USE
4.1 A knowledge of water extractable inorganic halides in oil is important when deciding whether or not the oils need desalting. Excessive halide, especially in crude oil, frequently results in higher corrosion rates in refining units.
SCOPE
1.1 This test method covers the determination of salt in crude oils. For the purpose of this test method, salt is expressed as % (m/m) NaCl (sodium chloride) and covers the range from 0.0005 % to 0.15 % (m/m).
1.2 The limit of detection is 0.0002 % (m/m) for salt (as NaCl).
1.3 The test method is applicable to nearly all of the heavier petroleum products, such as crude oils, residues, and fuel oils. It may also be applied to used turbine oil and marine diesel fuel to estimate seawater contamination. Water extractable salts, originating from additives present in oils, are codetermined.
1.4 The values stated in SI units are to be regarded as the 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.
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.
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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.
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SIGNIFICANCE AND USE
5.1 This test method is used to determine the approximate chloride content of crude oils, a knowledge of which is important in deciding whether or not the crude oil needs desalting. The efficiency of the process desalter can also be evaluated.
5.2 Excessive chloride left in the crude oil frequently results in higher corrosion rates in refining units and also has detrimental effects on catalysts used in these units.
5.3 This test method provides a rapid and convenient means of determining the approximate content of chlorides in crude oil and is useful to crude oil processors.
SCOPE
1.1 This test method covers the determination of the approximate chloride (salts) concentration in crude oil. The range of concentration covered is 3.5 mg/kg to 500 mg/kg or 1.0 lb/1000 bbl to 150 lb/1000 bbl (PTB) as chloride concentration/volume of crude oil.
1.2 This test method measures conductivity in the crude oil due to the presence of common chlorides, such as sodium, calcium, and magnesium. Other conductive materials may also be present in the crude oil.
1.3 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.
1.3.1 Exception—Acceptable concentration units are g/m3 or PTB (lb/1000 bbl).
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 7.3, 7.4, and 7.11.
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.
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SIGNIFICANCE AND USE
4.1 This test method provides a means of calculating the mean relative molecular mass of petroleum oils from another physical measurement.
4.2 Mean relative molecular mass is a fundamental physical constant that can be used in conjunction with other physical properties to characterize hydrocarbon mixtures.
SCOPE
1.1 This test method covers the estimation of the mean relative molecular mass of petroleum oils from kinematic viscosity measurements at 100 °F and 210 °F (37.78 °C and 98.89 °C).2 It is applicable to samples with mean relative molecular masses in the range from 250 to 700 and is intended for use with average petroleum fractions. It should not be applied indiscriminately to oils that represent extremes of composition or possess an exceptionally narrow mean relative molecular mass range.
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.
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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.
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SIGNIFICANCE AND USE
3.1 This guide summarizes the test methods used in the elemental analysis of crude oils. Additional information on the significance and use of the test methods quoted in this guide can be found under discussion of individual test methods in Sections 8 through 15.
3.2 Crude oils are highly complex hydrocarbons also containing some organometallic compounds, inorganic sediment, and water. Nearly 600 individual hydrocarbons, over 200 separate sulfur compounds, and about 40 trace elements have been found in crude oils (1).6 Generally, sulfur and nitrogen are the two most abundant elements found in crude oils except for carbon and hydrogen. Most other inorganic elements are present at trace levels (mg/kg). Sulfur, nitrogen, vanadium, nickel, and iron are the most frequently determined elements in the crude oils. Ratios such as vanadium to vanadium + nickel, and iron to vanadium are suggested as being useful for oil type characterizations. Since organometallic compounds are concentrated in the heavy ends of petroleum, transition element concentrations and ratios can serve as excellent oil-oil correlation parameters. Generally, vanadium and nickel content increases with asphaltic content of crude oil (API gravity is an indicator). Lighter crude oils contain lesser amounts of metals (2, 3).
3.3 Metal complexes called porphyrins are a major component of metallic compounds in crude oils. The principal porphyrin complexes are Ni+2 and VO+2 compounds. There are also other non-porphyrin complexes and other metallic compounds present in crude oils (4, 5).
3.4 Some typical literature citations in this area are included in the reference section at the end of this guide.
SCOPE
1.1 This guide summarizes the current information about the test methods for elemental and associated analyses used in the analysis of crude oils. This information can be helpful in trade between the buyers and sellers of crude oil. Elemental analyses tests form an important part of quantifying the crude oil quality.
1.2 The values stated in SI units are to be regarded as the 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.
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SIGNIFICANCE AND USE
5.1 The pour point of a crude oil is an index of the lowest temperature of handleability for certain applications.
5.2 This is the only pour point method specifically designed for crude oils.
5.3 The maximum and minimum pour point temperatures provide a temperature window where a crude oil, depending on its thermal history, might appear in the liquid as well as the solid state.
5.4 The test method can be used to supplement other measurements of cold flow behavior. It is especially useful for the screening of the effect of wax interaction modifiers on the flow behavior of crude oils.
SCOPE
1.1 This test method covers two procedures for the determination of the pour point temperatures of crude oils down to −36 °C. Procedure A provides a measure of the maximum (upper) pour point temperature and is described in 9.1. Procedure B provides a measure of the minimum (lower) pour point temperature and is described in 9.2.
1.2 The use of this test method is limited to use for crude oils. Pour point temperatures of other petroleum products can be determined by Test Method D97.
1.3 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.
1.4 WARNING—Mercury has been designated by many regulatory agencies as a hazardous material that can cause central nervous system, kidney, and liver damage. Mercury, or its vapor, may be hazardous to health and corrosive to materials. Caution should be taken when handling mercury and mercury-containing products. See the applicable product Material Safety Data Sheet (MSDS) for details and EPA’s website—http://www.epa.gov/mercury/faq.htm—for additional information. Users should be aware that selling mercury and/or mercury containing products in your state or country may be prohibited by law.
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 hazard statements, see Section 7.
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.
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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...
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This European Standard defines the methods of tests for the determination of the characteristics of crude tar and crude benzole.
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ISO 3838:2004 specifies methods for the determination of the density or relative density of crude petroleum and of petroleum products handled as liquids.
The capillary-stoppered pyknometer method is also for use with solids and this method may also be used for coal tar products, including road tars, creosote and tar pitches, or for mixtures of these with petroleum products. This method is not suitable for the determination of the density or relative density of highly volatile liquids having Reid vapour pressures greater than 50 kPa according to ISO 3007 or having an initial boiling point below 40 degrees Celsius.
The graduated bicapillary pyknometer method is recommended for the accurate determination of the density or relative density of all except the more viscous products, and is particularly useful when only small amounts of samples are available. The method is restricted to liquids having Reid vapour pressures of 130 kPa or less according to ISO 3007 and having kinematic viscosities less than 50 mm2/s (50 centistokes (cSt)) at the test temperature.
Special precautions are specified for the determination of the density or relative density of highly volatile liquids.
- Standard20 pagesEnglish languagee-Library read for1 day
ISO 3838:2004 specifies methods for the determination of the density or relative density of crude petroleum and of petroleum products handled as liquids.
The capillary-stoppered pyknometer method is also for use with solids and this method may also be used for coal tar products, including road tars, creosote and tar pitches, or for mixtures of these with petroleum products. This method is not suitable for the determination of the density or relative density of highly volatile liquids having Reid vapour pressures greater than 50 kPa according to ISO 3007 or having an initial boiling point below 40 degrees Celsius.
The graduated bicapillary pyknometer method is recommended for the accurate determination of the density or relative density of all except the more viscous products, and is particularly useful when only small amounts of samples are available. The method is restricted to liquids having Reid vapour pressures of 130 kPa or less according to ISO 3007 and having kinematic viscosities less than 50 mm2/s (50 centistokes (cSt)) at the test temperature.
Special precautions are specified for the determination of the density or relative density of highly volatile liquids.
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This International Standard specifies a method for the determination of the vapour pressure of liquid petroleum
products consisting of essentially or wholly of hydrocarbon components, or containing oxygenated hydrocarbons of
specific types and at specified maximum concentrations. The method does not apply outside these concentration
levels, nor to any blends containing methanol or other oxygenated hydrocarbons not covered in note 1.
NOTE 1 The maximum concentration of ethers containing 5 or more carbon atoms is 15 % (V/V), and for ethanol is 10 %
(V/V). For higher alcohols, the maximum concentration is 7 % (V/V).
NOTE 2 For the purposes of this International Standard, the term "%(V/V)" is used to represent the volume fraction of a
material.
For petroleum products containing methanol, or other oxygenated hydrocarbons outside the scope of note 1, a dry
vapour-pressure test method should be used. For liquefied petroleum gases, ISO 4256 should be used. The test
method may be applied to volatile crude petroleum with a vapour pressure exceeding 10 kPa, although the
precision has not been evaluated.
Four procedures are described in this International Standard. Procedures A and B are alternative apparatus
configurations for products with a Reid vapour pressure up to 180 kPa, Procedure C is applied to liquid products
with a Reid vapour pressure above 180 kPa, and Procedure D applies to aviation gasolines with a Reid vapour
pressure of approximately 50 kPa.
Vapour pressure is an important physical property of volatile liquids, and has critical performance implications for
automotive and aviation gasolines. Vapour pressure is also one of the properties affecting atmospheric evaporation,
and is therefore increasingly used in regulations relating to emissions and air quality control. Vapour pressure is
also a critical property limiting the performance and safety of operation of equipment during transfer operations.
NOTE Because the external atmospheric pressure is counteracted by the atmospheric pressure initially in the vapour
chamber, the Reid vapour pressure is approximately the "absolute" vapour pressure at 37,8 °C. The Reid vapour pressure
differs from the true vapour pressure of the sample owing to slight vaporization of the sample and the pressure of water vapour
and air in the confined space.
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Migrated from Progress Sheet (TC Comment) (2000-07-10): Updating of existing EN implementations of ISO standards (standing resolution); ++ Will go to VA.
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Migrated from Progress Sheet (TC Comment) (2000-07-10): Revision of EN ISO 3675:1995
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Migrated from Progress Sheet (TC Comment) (2000-07-10): Updating of existing EN implementations of ISO standards (standing resolution); ++ Will go to VA.
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The precision data of this procedure have only been determined for water contents up to 1 % (V/V). Includes principle, apparatus, solvent, calibration and recovery test, sampling, procedure, expression of results, precision and test report. The distillation apparatus is shown in figures 1 and 2. The precision of the method is shown in figure 3. The sample handling is described in annex A.
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