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ASTM D4928-12(2018)

(Test Method)

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

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

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.

General Information

Status
Published
Publication Date
30-Jun-2018
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

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ASTM D4928-12(2018) - Standard Test Method for Water in Crude Oils by Coulometric Karl Fischer TitrationASTM D4928-12(2018) - Standard Test Method for Water in Crude Oils by Coulometric Karl Fischer Titration
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ASTM D4928-12(2018) - Standard Test Method for Water in Crude Oils by Coulometric Karl Fischer Titration
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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.
Designation: D4928 − 12 (Reapproved 2018)
Manual of Petroleum Measurement Standards (MPMS), Chapter 10.9
Standard Test Method for
1
Water in Crude Oils by Coulometric Karl Fischer Titration
This standard is issued under the fixed designation D4928; 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 (´) indicates an editorial change since the last revision or reapproval.
This standard has been approved for use by agencies of the U.S. Department of Defense.
1. Scope 2. Referenced Documents
2
1.1 This test method covers the determination of water in
2.1 ASTM Standards:
the range from 0.02 to 5.00 mass or volume % in crude oils.
D1193Specification for Reagent Water
−
Mercaptan (RSH) and sulfide (S or H S) as sulfur are known
D4057Practice for Manual Sampling of Petroleum and
2
to interfere with this test method, but at levels of less than
Petroleum Products (API MPMS Chapter 8.1)
500µg⁄g [ppm(m)], the interference from these compounds is
D4177Practice for Automatic Sampling of Petroleum and
insignificant (see Section 6).
Petroleum Products (API MPMS Chapter 8.2)
D5854Practice for Mixing and Handling of Liquid Samples
1.2 This test method can be used to determine water in the
of Petroleum and Petroleum Products (API MPMS Chap-
0.005 to 0.02 mass % range, but the effects of the mercaptan
ter 8.3)
and sulfide interference at these levels has not been deter-
E203Test Method for Water Using Volumetric Karl Fischer
mined. For the range 0.005 to 0.02 mass %, there is no
Titration
precision or bias statement.
3
2.2 API Standards:
1.3 This test method is intended for use with standard
MPMS Chapter 8.1Practice for Manual Sampling of Petro-
commercially available coulometric Karl Fischer reagent.
leum and Petroleum Products (ASTM Practice D4057)
1.4 The values stated in SI units are to be regarded as
MPMS Chapter 8.2Practice for Automatic Sampling of
standard. No other units of measurement are included in this
Petroleum and Petroleum Products (ASTM Practice
standard.
D4177)
1.5 This standard does not purport to address all of the
MPMS Chapter 8.3Practice for Mixing and Handling of
safety concerns, if any, associated with its use. It is the
Liquid Samples of Petroleum and Petroleum Products
responsibility of the user of this standard to establish appro-
(ASTM Practice D5854)
priate safety, health, and environmental practices and deter-
mine the applicability of regulatory limitations prior to use.
3. Terminology
For specific warning statements, see Section 8.
3.1 The following terms are used with respect to sampling
1.6 This international standard was developed in accor-
(see Section 9).
dance with internationally recognized principles on standard-
3.2 Definitions of Terms Specific to This Standard:
ization established in the Decision on Principles for the
Development of International Standards, Guides and Recom- 3.2.1 aliquot, n—asmallportionofalargersamplewhichis
mendations issued by the World Trade Organization Technical analyzed and assumed to represent the whole sample.
Barriers to Trade (TBT) Committee.
3.2.2 sample, n—portion extracted from the contents of any
pipe,tank,orothersystem,andintendedtoberepresentativeof
that system, placed in a primary sample container for analysis.
1
This test method is under the jurisdiction of ASTM Committee D02 on
Petroleum Products, Liquid Fuels, and Lubricants and the API Committee on
Petroleum Measurement, and is the direct responsibility of Subcommittee D02.02
2
/COMQ, the joint ASTM-API Committee on Hydrocarbon Measurement for For referenced ASTM standards, visit the ASTM website, www.astm.org, or
Custody Transfer (Joint ASTM-API). This test method has been approved by the contact ASTM Customer Service at service@astm.org. For Annual Book of ASTM
sponsoring committees and accepted by the Cooperating Societies in accordance Standards volume information, refer to the standard’s Document Summary page on
with established procedures. the ASTM website.
3
Current edition approved July 1, 2018. Published August 2018. Originally Published as Manual of Petroleum Standards. Available from American
approved in 1989. Last previous edition approved in 2012 as D4928–12. DOI: Petroleum Institute (API), 1220 L. St., NW, Washington, DC 20005-4070, http://
10.1520/D4928-12R18. www.api.org.
© Jointly copyrighted by ASTM International, 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA 19428-2959, USA and the American Petroleum Institute (API), 1220 L Street NW, Washington DC 20005, USA
1

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ASTM D7691-23(Test Method)
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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.  
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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.  
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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.  
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Standard Test Method for Determination of Intrinsic Stability of Asphaltene-Containing Residues, Heavy Fuel Oils, and Crude Oils (n-Heptane Phase Separation; Optical Detection)

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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.  
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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.  
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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.  
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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.
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SIGNIFICANCE AND USE
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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.  
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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.  
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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).  
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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.  
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ASTM D4929-22(Test Method)
Standard Test Method for Determination of Organic Chloride Content in Crude Oil

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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ASTM
ASTM D4007-22(Test Method)
Standard Test Method for Water and Sediment in Crude Oil by the Centrifuge Method (Laboratory Procedure)

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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