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ASTM G170-06

(Guide)

Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory

Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory

SCOPE
1.1 This guide covers some generally accepted laboratory methodologies that are used for evaluating corrosion inhibitors for oilfield and refinery applications in well defined flow conditions.
1.2 This guide does not cover detailed calculations and methods, but rather covers a range of approaches which have found application in inhibitor evaluation.
1.3 Only those methodologies that have found wide acceptance in inhibitor evaluation are considered in this guide.
1.4 This guide is intended to assist in the selection of methodologies that can be used for evaluating corrosion inhibitors.
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 and health practices and determine the applicability of regulatory requirements prior to use.

General Information

Status
Historical
Publication Date
31-Oct-2006
ICS
75.020 - Extraction and processing of petroleum and natural gas
Technical Committee
G01 - Corrosion of Metals
Drafting Committee
G01.05 - Laboratory Corrosion Tests
Current Stage
Ref Project

Relations

Replaces
ASTM G170-01a - Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory
Effective Date
01-Nov-2006
Referred By
ASTM G185-06(2020)e1 - Standard Practice for Evaluating and Qualifying Oil Field and Refinery Corrosion Inhibitors Using the Rotating Cylinder Electrode
Effective Date
01-Nov-2006
Referred By
ASTM G208-12(2020) - Standard Practice for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors Using Jet Impingement Apparatus
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
01-Nov-2006
Referred By
ASTM G202-12(2020) - Standard Test Method for Using Atmospheric Pressure Rotating Cage
Effective Date
01-Nov-2006
Referred By
ASTM G184-06(2020)e1 - Standard Practice for Evaluating and Qualifying Oil Field and Refinery Corrosion Inhibitors Using Rotating Cage
Effective Date
01-Nov-2006
Referred By
ASTM G31-21 - Standard Guide for Laboratory Immersion Corrosion Testing of Metals
Effective Date
01-Nov-2006
Referred By
ASTM G111-21a - Standard Guide for Corrosion Tests in High Temperature or High Pressure Environment, or Both
Effective Date
01-Nov-2006

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ASTM G170-06 - Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the LaboratoryASTM G170-06 - Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory
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ASTM G170-06 - Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory
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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
Designation:G170 −06
StandardGuide for
Evaluating and Qualifying Oilfield and Refinery Corrosion
1
Inhibitors in the Laboratory
This standard is issued under the fixed designation G170; the number immediately following the designation indicates the year of
original adoption or, in the case of revision, the year of last revision. A number in parentheses indicates the year of last reapproval. A
superscript epsilon (´) indicates an editorial change since the last revision or reapproval.
3
1. Scope ing (Withdrawn 2010)
G16 Guide for Applying Statistics to Analysis of Corrosion
1.1 This guide covers some generally accepted laboratory
Data
methodologies that are used for evaluating corrosion inhibitors
G31 PracticeforLaboratoryImmersionCorrosionTestingof
for oilfield and refinery applications in well defined flow
Metals
conditions.
G46 Guide for Examination and Evaluation of Pitting Cor-
1.2 This guide does not cover detailed calculations and
rosion
methods, but rather covers a range of approaches which have
G59 Test Method for Conducting Potentiodynamic Polariza-
found application in inhibitor evaluation.
tion Resistance Measurements
G96 Guide for Online Monitoring of Corrosion in Plant
1.3 Only those methodologies that have found wide accep-
tance in inhibitor evaluation are considered in this guide. Equipment (Electrical and Electrochemical Methods)
G102 Practice for Calculation of Corrosion Rates and Re-
1.4 This guide is intended to assist in the selection of
lated Information from Electrochemical Measurements
methodologies that can be used for evaluating corrosion
G106 Practice for Verification of Algorithm and Equipment
inhibitors.
for Electrochemical Impedance Measurements
1.5 This standard does not purport to address all of the
G111 Guide for Corrosion Tests in High Temperature or
safety concerns, if any, associated with its use. It is the
High Pressure Environment, or Both
responsibility of the user of this standard to establish appro-
4
2.2 NACE Standards:
priate safety and health practices and determine the applica-
NACE-5A195 State-of-the-Art Report on Controlled-Flow
bility of regulatory requirements prior to use.
Laboratory Corrosion Test, Houston, TX, NACE Interna-
tional Publication, Item No. 24187, December 1995
2. Referenced Documents
NACE-ID196 Laboratory Test Methods for Evaluating Oil-
2
2.1 ASTM Standards:
Field Corrosion Inhibitors, Houston, TX, NACE Interna-
D1141 Practice for the Preparation of Substitute Ocean
tional Publication, Item No. 24192, December 1996
Water
NACE-TM0196 Standard Test Method “Chemical Resis-
D4410 Terminology for Fluvial Sediment
tance of Polymeric Materials by Periodic Evaluation,”
G1 Practice for Preparing, Cleaning, and Evaluating Corro-
Houston, TX, NACE International Publication, Item No.
sion Test Specimens
21226, 1996
5
G3 Practice for Conventions Applicable to Electrochemical
2.3 ISO Standards:
Measurements in Corrosion Testing
ISO 696 Surface Active Agents — Measurements of Foam-
G5 Reference Test Method for Making Potentiostatic and
ing Power Modified Ross-Miles Method
Potentiodynamic Anodic Polarization Measurements
ISO 6614 Petroleum Products — Determination of Water
G15 Terminology Relating to Corrosion and CorrosionTest-
Separability of Petroleum Oils and Synthetic Fluids
3. Terminology
1
This guide is under the jurisdiction ofASTM Committee G01 on Corrosion of
3.1 Definitions of Terms Specific to This Standard:
Metals and is the direct responsibility of Subcommittee G01.05 on Laboratory
Corrosion Tests.
Current edition approved Nov. 1, 2006. Published December 2006. Originally
3
approved in 2001. Last previous edition approved in 2001 as G170 – 01a. DOI: The last approved version of this historical standard is referenced on
10.1520/G0170-06. www.astm.org.
2 4
For referenced ASTM standards, visit the ASTM website, www.astm.org, or Available from National Association of Corrosion Engineers (NACE), 1440
contact ASTM Customer Service at service@astm.org. For Annual Book of ASTM South Creek Dr., Houston, TX 77084-4906, http://www.nace.org.
5
Standards volume information, refer to the standard’s Document Summary page on Available fromAmerican National Standards Institute (ANSI), 25 W. 43rd St.,
the ASTM website. 4th Floor, New York, NY 10036, http://www.ansi.org.
Copyright © ASTM International, 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA 19428-2959. United States
1

---------------------- Page: 1 ----------------------
G170−06
3.1.1 atmosphericpressureexperiment—anexperimentcon- tance (LPR), electrochemical impedance spectroscopy (EIS),
ducted at the ambient atmospheric pressure (typically less than electrical resistance (ER), and potentiodynamic polarization
0.07 MPa (10 psig)), using normal laboratory glassware. (PP) methods.
3.1.2 batch inhibitor—an inhibitor that forms a film on the
3.1
...

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ASTM G170-06(2020)e1(Guide)
Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory

SIGNIFICANCE AND USE
5.1 Corrosion inhibitors continue to play a key role in controlling internal corrosion associated with oil and gas production and transportation. This results primarily from the industry’s extensive use of carbon and low alloy steels, which, for many applications, are economic materials of construction that generally exhibit poor corrosion resistance. As a consequence, there is a strong reliance on inhibitor deployment for achieving cost-effective corrosion control, especially for treating long flowlines and main export pipelines (1).5  
5.2 For multiphase flow, the aqueous-oil-gas interphases can take any of an infinite number of possible forms. These forms are delineated into certain classes of interfacial distribution called flow regimes. The flow regimes depend on the inclination of the pipe (that is, vertical or horizontal), flow rate (based on production rate), and flow direction (that is, upward or downward). The common flow regimes in vertical upward flow, vertical downward flow, and horizontal flow are presented in Figs. 1-3 respectively (2, 3).  
5.14 To develop an inhibitor selection strategy, in addition to inhibitor efficiency, several other key performance factors need to be evaluated: (1) water/oil partitioning, (2) solubility, (3) emulsification tendency, (4) foaming tendency, (5) thermal stability, (6) toxicity, and (7) compatibility with other additives/materials.
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1.1 This guide covers some generally accepted laboratory methodologies that are used for evaluating corrosion inhibitors for oilfield and refinery applications in well defined flow conditions.  
1.2 This guide does not cover detailed calculations and methods, but rather covers a range of approaches which have found application in inhibitor evaluation.  
1.3 Only those methodologies that have found wide acceptance in inhibitor evaluation are considered in this guide.  
1.4 This guide is intended to assist in the selection of methodologies that can be used for evaluating corrosion inhibitors.  
1.5 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.6 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 requirements 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 G170-06(2020)e1(Guide)
Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory

SIGNIFICANCE AND USE
5.1 Corrosion inhibitors continue to play a key role in controlling internal corrosion associated with oil and gas production and transportation. This results primarily from the industry’s extensive use of carbon and low alloy steels, which, for many applications, are economic materials of construction that generally exhibit poor corrosion resistance. As a consequence, there is a strong reliance on inhibitor deployment for achieving cost-effective corrosion control, especially for treating long flowlines and main export pipelines (1).5  
5.2 For multiphase flow, the aqueous-oil-gas interphases can take any of an infinite number of possible forms. These forms are delineated into certain classes of interfacial distribution called flow regimes. The flow regimes depend on the inclination of the pipe (that is, vertical or horizontal), flow rate (based on production rate), and flow direction (that is, upward or downward). The common flow regimes in vertical upward flow, vertical downward flow, and horizontal flow are presented in Figs. 1-3 respectively (2, 3).  
5.14 To develop an inhibitor selection strategy, in addition to inhibitor efficiency, several other key performance factors need to be evaluated: (1) water/oil partitioning, (2) solubility, (3) emulsification tendency, (4) foaming tendency, (5) thermal stability, (6) toxicity, and (7) compatibility with other additives/materials.
SCOPE
1.1 This guide covers some generally accepted laboratory methodologies that are used for evaluating corrosion inhibitors for oilfield and refinery applications in well defined flow conditions.  
1.2 This guide does not cover detailed calculations and methods, but rather covers a range of approaches which have found application in inhibitor evaluation.  
1.3 Only those methodologies that have found wide acceptance in inhibitor evaluation are considered in this guide.  
1.4 This guide is intended to assist in the selection of methodologies that can be used for evaluating corrosion inhibitors.  
1.5 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.6 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 requirements 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 E1675-20(Practice)
Standard Practice for Sampling Two-Phase Geothermal Fluid for Purposes of Chemical Analysis

SIGNIFICANCE AND USE
4.1 The objective of this practice is to obtain representative samples of the steam and liquid phases as they exist in the pipeline at the sample point, without allowing steam condensation or additional liquid flashing in the separator. A significant feature of the practice is the use of a cyclone-type separator for high-efficiency phase separation which is operated at flow rates high enough to prevent significant heat loss while maintaining an internal pressure essentially the same as the pipeline pressure.  
4.2 Another significant feature of the practice is to locate the sampling separator at a point on the pipeline where the two-phase flow is at least partially stratified to aid in the separation process. It is neither necessary nor possible to pass representative proportions of each phase through the sampling separator to obtain representative samples. The separator is usually attached to an appropriately oriented port to collect each specific phase – normally on top of the line for steam and at the bottom for liquid. In some cases, piping configurations can generate unusual flow regimes where the reverse is required. If the ratio of one phase to another is not extreme, it may be possible to obtain representative samples of each phase from a horizontal port on the side of the pipeline.  
4.3 This practice is used whenever liquid or steam samples, or both, must be collected from a two-phase discharge for chemical analysis. This typically includes initial well-testing operations when a well is discharged to the atmosphere or routine well production when a well discharges to a fluid gathering system and power plant. The combined two-phase flow of several wells producing through a common gathering system may also be sampled in accordance with this practice.  
4.4 This practice is not typically employed when individual wells produce to dedicated production separators. In these cases, the separated steam and liquid at the outlet of the production separator is samp...
SCOPE
1.1 The purpose of this practice is to obtain representative samples of liquid and steam as they exist in a pipeline transporting two-phase geothermal fluids.  
1.1.1 The liquid and steam samples are collected and properly preserved for subsequent chemical analysis in the field or an off-site analytical laboratory.  
1.1.2 The chemical composition data generated from the analysis of liquid and steam samples may be used for many applications important to geothermal energy exploration, development, and the long-term managed exploitation of geothermal resources. These applications include, but are not limited to, resource evaluations such as determining reservoir temperature and the origin of reservoir fluids, tracer-based measurements of production flow and enthalpy (TFT), compatibility of produced fluids with production, power generation and reinjection hardware exposed to the fluids (corrosivity and scale deposition potential), long-term reservoir monitoring during field exploitation, and environmental impact evaluations including emissions testing.
1.1.2.1 To fully utilize the chemical composition data in the applications stated in 1.1.2, specific physical data related to the two-phase discharge, wellbore, and geothermal reservoir may be required. Mathematical reconstruction of the fluid chemistry (liquid and steam) to reservoir conditions is a primary requirement in many applications. At a minimum, this requires precise knowledge of the total fluid enthalpy and pressure or temperature at the sample point. Fluid reconstruction and computations to conditions different from the sample collection point are beyond the scope of this practice.  
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ASTM D7964/D7964M-19(Test Method)
Standard Test Method for Determining Activity of Fluid Catalytic Cracking (FCC) Catalysts in a Fluidized Bed

SIGNIFICANCE AND USE
5.1 The fluidized bed test provides data to assess the relative performances of FCC catalysts. Because results are affected by catalyst pretreatment, feedstock characteristics, and operating parameters, this test method is written specifically to address the accuracy and precision when a common catalyst and oil are tested under the same conditions but at different sites, using Kayser Technologies Advanced Catalytic Evaluation (ACE) unit.4,5 Analytical procedures may vary among the sites. However, significant variations are not expected.
Note 1: ASTM International takes no position respecting the validity of any patent rights asserted in connection with any item mentioned in this standard. Users of this standard are expressly advised that determination of the validity of any such patent rights, and the risk of infringement of such rights, are entirely their own responsibility.  
5.2 The standard reaction temperature for purposes of the accuracy and precision statement is 532 °C [990 °F]. Other reaction temperatures can be used in practice; however, yield data developed at temperatures other than 532 °C [990 °F] will not be the same. Also, test precision may be different at other reaction temperatures.
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1.1 This test method covers determining the activity and coke selectivity of either equilibrium or laboratory deactivated fluid catalytic cracking (FCC) catalysts. The activity is evaluated on the basis of mass percent conversion of gas oil feed in a fluidized bed reactor. The coke yield is defined as the mass of carbon laid down on the catalyst, also expressed as a percent of the gas oil feed. The scope of the round robin will be limited to the determination of activity and coke. All other analyses are thus beyond this scope and should be noted as “optional.”  
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4.1 This guide is meant to aid local and regional spill response teams during spill response planning and spill events.
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1.1 This guide addresses in-situ burning as a response tool for oil spills occurring on waters with ice present.  
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1.3 The purpose of this guide is to provide the user with general information on in-situ burning in ice conditions as a means of controlling and removing spilled oil. It is intended as a reference to plan an in-situ burn of spilled oil.  
1.4 This guide outlines procedures and describes some equipment that can be used to accomplish an in-situ burn in ice conditions. The guide includes a description of typical ice situations where in-situ burning of oil has been found to be effective. Other standards address the general guidelines for the use of in-situ burning (Guide F1788), the use of ignition devices (Guide F1990), the use of fire-resistant boom (Guide F2152), the application of in-situ burning in ships (Guide F2533), and the use of in-situ burning in marshes (Guide F2823).  
1.5 In making in-situ burn decisions, appropriate government authorities should be consulted as required by law.  
1.6 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.7 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 precautionary information is given in Section 8. Guide F1788 addresses operational considerations.  
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 D8053-18(Guide)
Standard Guide for Data Management and Reporting Associated with Oil and Gas Development Involving Hydraulic Fracturing

SIGNIFICANCE AND USE
5.1 Limitations of Guide—This guide is for use by stakeholders involved with collecting, managing, reporting, and delivering data during oil and gas development operations using hydraulic fracturing. Some data collected for operational and business concerns regarding hydraulic fracturing is classified as proprietary and can be classified as such by individual operators based on state regulatory conditions. Accordingly, this guide will not address the collection, management, and reporting of proprietary operator data other than to note that significant benefits may be achieved by narrowing the classification of proprietary data, and standardizing the definition of “proprietary data” between regulators. Regulators’ interests in data vary widely based upon a specific agency’s charter, statutory/legislative mandates, legacy requirements, and considerations relating to operator compliance. Depending upon jurisdictional boundaries, multiple regulatory agencies generally have statutory responsibilities regarding oil and gas development operations. These agencies properly determine what information will be collected based on agency specific responsibilities. Accordingly, this guide will not address the selection of data elements to be collected by regulatory agencies other than to note that significant efficiencies may be achieved by using integrated or common, interagency, data management processes, protocols, systems, and best practices and by reviewing data collection activities against those of sister agencies to minimize gaps and overlaps.  
5.2 Oil and gas development operations include the entire well life cycle, as shown in Fig. 1.
FIG. 1 Phases of Oil and Gas Development Operations Well Life Cycle  
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SCOPE
1.1 This guide presents a series of options regarding data collection, data management, and information delivery and reporting associated with oil and gas development involving hydraulic fracturing. Options presented for data management and reporting are intended to improve the transparent information exchange between three primary stakeholder groups: operators, regulators, and the public. Improved information exchange is expected to enhance public understanding of oil and gas development.  
1.2 Suggestions contained in this guide may not be applicable in all circumstances. This guide is not intended to represent or replace the standard of care by which the adequacy of a given professional service should be judged, nor should this guide be applied without consideration of a project’s many unique aspects. The word “Standard” in the title of this document means that the document has been approved through the ASTM process.  
1.3 Units—The values stated in inch-pound units are to be regarded as the standard. The values given in parentheses are mathematical conversions to SI units that are provided for information only and are not considered standard.  
1.4 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory limitations prior to use.  
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Standard Test Method for Phosphonate in Brines

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5.1 This test method is useful for the determination of trace level phosphonate residues in brines. Chemical treatment which contain phosphonates are used as mineral scale and corrosion inhibitors in gas and oil drilling and production operations; and other industrial applications. Often, the decision for treatment is based on the ability to measure low phosphonate concentration and not upon performance criteria. Phosphonate concentrations as low as 0.16 mg/L have been shown effective in carbonate scale treatment. This test method enables the measurement of sub-mg/L phosphonate concentration in brines containing interfering elements.  
5.2 The procedure includes measuring total (see 12.3.8) and free orthophosphate (see 12.4.3) ions and the difference in concentration is the phosphonate concentration. The sample could contain orthophosphate naturally, or from decomposition of the phosphonate during processing or well treatment or from treating compounds containing molecular dehydrated phosphates.
SCOPE
1.1 This test method covers the colorimetric determination of phosphonate (PNA) in brines from gas and oil production operations in the range from 0.1 to 5 mg/L.  
1.2 This phosphonate method is intended for use to analyze low concentration of phosphonate in brine containing interfering elements. This test method is most useful for analyzing phosphonate at 0.1 to 1 mg/L range in brines with interfering elements; however, it requires personnel with good analytical skill.  
1.3 This test method has been used successfully with reagent water and both field and synthetic brine. It is the user's responsibility to ensure the validity of this test method for waters of untested matrices.  
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 and health practices and determine the applicability of regulatory limitations prior to use. For specific hazard statements, see 9.1.3.

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ASTM F1210-23(Guide)
Standard Guide for Ecological Considerations for the Use of Oil Spill Dispersants in Freshwater and Other Inland Environments, Lakes and Large Water Bodies

SIGNIFICANCE AND USE
3.1 This guide is meant to aid response teams who may use it during spill response planning and spill events.  
3.2 This guide should be adapted to site specific circumstance.
SCOPE
1.1 This guide covers the use of oil spill dispersants to assist in the control of oil spills. The guide is written with the goal of minimizing the environmental impacts of oil spills; this goal is the basis on which the recommendations are made. Aesthetic and socioeconomic factors are not considered, although these and other factors are often important in spill response.  
1.2 Spill responders have available several means to control or clean up spilled oil. Chemical dispersants should be given equal consideration with other spill countermeasures.  
1.3 This is a general guide only. Oil, as used in this guide, includes crude oils and refined petroleum products. Differences between individual dispersants or between different oil products are not considered. The dispersibility of the oil with the chosen dispersant should be evaluated.  
1.4 The guide is organized by habitat type, for example, small ponds and lakes, rivers and streams, and land. It considers the use of dispersants primarily to protect habitats from impact (or to minimize impacts).  
1.5 This guide applies only to freshwater and other inland environments. It does not consider the direct application of dispersants to subsurface waters.  
1.6 In making dispersant use decisions, appropriate government authorities should be consulted as required by law.  
1.7 This guide does not address getting regulatory approval.  
1.8 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.9 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.  
1.10 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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4.1 This test method establishes a selected set of conditions of temperature, relative humidity and rate of evaporation of the environment to which a mortar specimen of stated composition shall be subjected for a specified period of time during which its change in length is determined and designated “drying shrinkage.”  
4.2 The drying shrinkage of mortar as determined by this test method has a linear relation to the drying shrinkage of concrete made with the same cement and exposed to the same drying conditions.4 Hence this test method may be used when it is desired to develop data on the effect of a hydraulic cement on the drying shrinkage of concrete made with that cement.
SCOPE
1.1 This test method determines the change in length on drying of mortar bars containing hydraulic cement and graded standard sand.  
1.2 The values stated in SI units are to be regarded as standard. When combined standards are referenced, the selection of measurement system is at the user’s discretion subject to the requirements of the referenced 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. Warning—Fresh hydraulic cementitious mixtures are caustic and may cause chemical burns to skin and tissue upon prolonged exposure).2  
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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Standard Specification for Preformed Expansion Joint Filler for Concrete Paving and Structural Construction (Nonextruding and Resilient Asphalt Types)

SCOPE
1.1 This specification covers preformed expansion joint filler having relatively little extrusion and substantial recovery after release from compression.  
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Note 1: Attention is called to Specifications D1752 and D994/D994M.  
1.3 The text of this standard references notes and footnotes which provide explanatory material. These notes and footnotes (excluding those in tables and figures) shall not be considered as requirements of the standard.  
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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