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ASTM D4377-00e1

(Test Method)

Standard Test Method for Water in Crude Oils by Potentiometric Karl Fischer Titration

Standard Test Method for Water in Crude Oils by Potentiometric Karl Fischer Titration

SCOPE
1.1 This test method covers the determination of water in the range from 0.02 to 2 % in crude oils. Mercaptan and sulfide (S or H2S) sulfur are known to interfere with this test method (see Section 5).
1.2 This test method is intended for use with standard Karl Fischer reagent or pyridine-free Karl Fischer reagents.
1.3 The values stated in SI units are to be regarded as the 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 and health practices and determine the applicability of regulatory limitations prior to use. Specific precautionary statements are given in Section 7.

General Information

Status
Historical
Publication Date
09-Aug-2000
ICS
75.040 - Crude petroleum
Technical Committee
D02 - Petroleum Products, Liquid Fuels, and Lubricants
Drafting Committee
D02.02 - Hydrocarbon Measurement for Custody Transfer (Joint ASTM-API)
Current Stage
Ref Project

Relations

Replaces
ASTM D4377-00 - Standard Test Method for Water in Crude Oils by Potentiometric Karl Fischer Titration
Effective Date
10-Aug-2000
Replaced By
ASTM D4377-00(2006) - Standard Test Method for Water in Crude Oils by Potentiometric Karl Fischer Titration
Effective Date
01-Nov-2006
Referred By
ASTM G205-16 - Standard Guide for Determining Emulsion Properties, Wetting Behavior, and Corrosion-Inhibitory Properties of Crude Oils
Effective Date
10-Aug-2000
Referred By
ASTM D7785-21 - Standard Practice for Water in Lint Cotton by Oven Evaporation Combined with Volumetric Karl Fischer Titration
Effective Date
10-Aug-2000
Referred By
ASTM D6470-99(2020) - Standard Test Method for Salt in Crude Oils (Potentiometric Method)
Effective Date
10-Aug-2000
Referred By
ASTM D4052-22 - Standard Test Method for Density, Relative Density, and API Gravity of Liquids by Digital Density Meter
Effective Date
10-Aug-2000
Referred By
ASTM D5002-22 - Standard Test Method for Density, Relative Density, and API Gravity of Crude Oils by Digital Density Analyzer
Effective Date
10-Aug-2000
Referred By
ASTM D6448-16(2022) - Standard Specification for Industrial Burner Fuels from Used Lubricating Oils
Effective Date
10-Aug-2000
Referred By
ASTM F3337-19 - Standard Guide for Taking Property and Behavior Measurements on Weathered Fractions of Oil
Effective Date
10-Aug-2000
Referred By
ASTM D7829-13(2018) - Standard Guide for Sediment and Water Determination in Crude Oil
Effective Date
10-Aug-2000

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ASTM D4377-00e1 - Standard Test Method for Water in Crude Oils by Potentiometric Karl Fischer TitrationASTM D4377-00e1 - Standard Test Method for Water in Crude Oils by Potentiometric Karl Fischer Titration
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ASTM D4377-00e1 - Standard Test Method for Water in Crude Oils by Potentiometric Karl Fischer Titration
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Standards Content (Sample)

NOTICE: This standard has either been superseded and replaced by a new version or withdrawn.
Contact ASTM International (www.astm.org) for the latest information
AnAmerican National Standard
e1
Designation:D4377–00
Designation: Manual of Petroleum Measurement Standards (MPMS), Chapter 10.7
Designation: 356/99
Standard Test Method for
1
Water in Crude Oils by Potentiometric Karl Fischer Titration
This standard is issued under the fixed designation D4377; the number immediately following the designation indicates the year of
original adoption or, in the case of revision, the year of last revision.Anumber in parentheses indicates the year of last reapproval.A
superscript epsilon (e) indicates an editorial change since the last revision or reapproval.
This standard has been approved for use by agencies of the Department of Defense.
1
e NOTE—Footnote 1 and the Referenced Documents were corrected editorially to comply with theASTM-API joint standard
contract in October 2002.
1. Scope E203 TestMethodforWaterUsingVolumetricKarlFischer
4
Reagent
1.1 This test method covers the determination of water in
5
2.2 API Standards:
therangefrom0.02to2%incrudeoils.Mercaptanandsulfide
−
MPMS Chapter 8.1 Manual Sampling of Petroleum and
(S or H S) sulfur are known to interfere with this test method
2
Petroleum Products (ASTM Practice D4057)
(see Section 5).
MPMS Chapter 8.2 Automatic Sampling of Petroleum and
1.2 This test method is intended for use with standard Karl
Petroleum Products (ASTM Practice D4177)
Fischer reagent or pyridine-free Karl Fischer reagents.
MPMS Chapter 10.2 Determination of Water in Crude Oil
1.3 The values stated in SI units are to be regarded as the
by Distillation (ASTM Test Method D4006)
standard.
1.4 This standard does not purport to address all of the
3. Summary of Test Method
safety concerns, if any, associated with its use. It is the
3.1 After homogenizing the crude oil with a mixer, an
responsibility of the user of this standard to establish appro-
aliquot of the crude, in a mixed solvent, is titrated to an
priate safety and health practices and determine the applica-
electrometric end-point using Karl Fischer reagent.
bility of regulatory limitations prior to use. Specific precau-
tionary statements are given in Section 7.
4. Significance and Use
4.1 A knowledge of the water content of crude oil is
2. Referenced Documents
important in the refining, purchase, sale, or transfer of crude
2.1 ASTM Standards:
2 oils.
D1193 Specification for Reagent Water
D4006 Test Method for Water in Crude Oil by Distillation
5. Interferences
3
(API MPMS Chapter 10.2)
5.1 A number of substances and class of compounds asso-
D4057 Practice for Manual Sampling of Petroleum and
3 ciated with condensation or oxidation-reduction reactions in-
Petroleum Products (API MPMS Chapter 8.1)
terfere in the determination of water by Karl Fischer. In crude
D4177 Practice for Automatic Sampling of Petroleum and
3 oils, the most common interferences are mercaptans and
Petroleum Products (API MPMS Chapter 8.2)
sulfides. At levels of less than 500 µg/g (ppm) (as sulfur) the
interference from these compounds is insignificant. For more
informationonsubstancesthatinterfereinthedeterminationof
1
This test method is under the jurisdiction of ASTM Committee D02 on
waterusingthe(KarlFischerreagent)titrationmethodseeTest
Petroleum Products and Lubricants and theAPI Committee on Petroleum Measure-
Method E203.
ment, and is the direct responsibility of Subcommittee D02.02 /COMQ, the joint
ASTM-API Committee on Static Petroleum Measurement.
Current edition approved Aug. 10, 2000. Published October 2000. Originally
4
published as D4377–84. Last previous edition D4377–93a. Annual Book of ASTM Standards, Vol 15.05.
2 5
Annual Book of ASTM Standards, Vol 11.01. Published as Manual of Petroleum Measurement Standards.Available from the
3
Annual Book of ASTM Standards, Vol 05.02. AmericanPetroleumInstitute(API),1220LSt.,NW,Washington,DC20005-4070.
Copyright ©ASTM International, 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA19428-2959, United States.
1

---------------------- Page: 1 ----------------------
e1
D4377–00
6. Apparatus of water)—Fresh Karl Fischer reagent must be used. Must be
used with solvent in 7.6.1.(Warning—Combustible. Harmful
6.1 Karl Fischer Apparatus, using electrometric end-point.
if swallowed, inhaled, or absorbed through the skin.)
A suggested assembly of the apparatus is described in Annex
7.4.2 Pyridine-Free Karl Fischer (one-component) reagent
A2.
diluted with xylene—Dilute three parts pyridine-free Karl
6.1.1 Presently there is available on the market commercial
8
Fischer (one-component) reagent (1 mL=5 mg water) to 1
Karl Fischer titration assemblies, some of which automatically
part xylene. Fresh Karl Fischer reagent must be used.
stop the titration at the end-point. Instructions for operation of
(Warning—See 7.4.1) Must be used with solvent in 7.6.2.
these devices are provided by the manufacturer and not
7.5 Methano
...

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ASTM D2892-23(Test Method)
Standard Test Method for Distillation of Crude Petroleum (15-Theoretical Plate Column)

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.
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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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ASTM D8252-23(Test Method)
Standard Test Method for Vanadium and Nickel in Crude and Residual Oil by X-ray Spectrometry

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.
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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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ASTM D7829-23(Guide)
Standard Guide for Sediment and Water Determination in Crude Oil

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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ASTM D7691-23(Test Method)
Standard Test Method for Multielement Analysis of Crude Oils Using Inductively Coupled Plasma Atomic Emission Spectrometry (ICP-AES)

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.
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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.  
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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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ASTM D8045-17(2023)(Test Method)
Standard Test Method for Acid Number of Crude Oils and Petroleum Products by Catalytic Thermometric Titration

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.  
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ASTM D7157-23(Test Method)
Standard Test Method for Determination of Intrinsic Stability of Asphaltene-Containing Residues, Heavy Fuel Oils, and Crude Oils (n-Heptane Phase Separation; Optical Detection)

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.
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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.  
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ASTM D5863-22(Test Method)
Standard Test Methods for Determination of Nickel, Vanadium, Iron, and Sodium in Crude Oils and Residual Fuels by Flame Atomic Absorption Spectrometry

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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ASTM D8003-22(Test Method)
Standard Test Method for Determination of Light Hydrocarbons and Cut Point Intervals in Live Crude Oils and Condensates by Gas Chromatography

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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ASTM D4310-22a(Test Method)
Standard Test Method for Determination of Sludging and Corrosion Tendencies of Inhibited Mineral Oils

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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ASTM
ASTM D8150-22(Test Method)
Standard Test Method for Determination of Organic Chloride Content in Crude Oil by Distillation Followed by Detection Using Combustion Ion Chromatography

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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