1、Designation: G170 06 (Reapproved 2012)Standard Guide forEvaluating and Qualifying Oilfield and Refinery CorrosionInhibitors in the Laboratory1This standard is issued under the fixed designation G170; the number immediately following the designation indicates the year oforiginal adoption or, in the c
2、ase of revision, the year of last revision. A number in parentheses indicates the year of last reapproval. Asuperscript epsilon () indicates an editorial change since the last revision or reapproval.1. Scope1.1 This guide covers some generally accepted laboratorymethodologies that are used for evalu
3、ating corrosion inhibitorsfor oilfield and refinery applications in well defined flowconditions.1.2 This guide does not cover detailed calculations andmethods, but rather covers a range of approaches which havefound application in inhibitor evaluation.1.3 Only those methodologies that have found wid
4、e accep-tance in inhibitor evaluation are considered in this guide.1.4 This guide is intended to assist in the selection ofmethodologies that can be used for evaluating corrosioninhibitors.1.5 This standard does not purport to address all of thesafety concerns, if any, associated with its use. It is
5、 theresponsibility of the user of this standard to establish appro-priate safety and health practices and determine the applica-bility of regulatory requirements prior to use.2. Referenced Documents2.1 ASTM Standards:2D1141 Practice for the Preparation of Substitute OceanWaterD4410 Terminology for F
6、luvial SedimentG1 Practice for Preparing, Cleaning, and Evaluating Corro-sion Test SpecimensG3 Practice for Conventions Applicable to ElectrochemicalMeasurements in Corrosion TestingG5 Reference Test Method for Making Potentiostatic andPotentiodynamic Anodic Polarization MeasurementsG15 Terminology
7、Relating to Corrosion and Corrosion Test-ing (Withdrawn 2010)3G16 Guide for Applying Statistics to Analysis of CorrosionDataG31 Guide for Laboratory Immersion Corrosion Testing ofMetalsG46 Guide for Examination and Evaluation of Pitting Cor-rosionG59 Test Method for Conducting Potentiodynamic Polari
8、za-tion Resistance MeasurementsG96 Guide for Online Monitoring of Corrosion in PlantEquipment (Electrical and Electrochemical Methods)G102 Practice for Calculation of Corrosion Rates and Re-lated Information from Electrochemical MeasurementsG106 Practice for Verification of Algorithm and Equipmentfo
9、r Electrochemical Impedance MeasurementsG111 Guide for Corrosion Tests in High Temperature orHigh Pressure Environment, or Both2.2 NACE Standards:4NACE-5A195 State-of-the-Art Report on Controlled-FlowLaboratory Corrosion Test, Houston, TX, NACE Interna-tional Publication, Item No. 24187, December 19
10、95NACE-ID196 Laboratory Test Methods for Evaluating Oil-Field Corrosion Inhibitors, Houston, TX, NACE Interna-tional Publication, Item No. 24192, December 1996NACE-TM0196 Standard Test Method “Chemical Resis-tance of Polymeric Materials by Periodic Evaluation,”Houston, TX, NACE International Publica
11、tion, Item No.21226, 19962.3 ISO Standards:5ISO 696 Surface Active Agents Measurements of Foam-ing Power Modified Ross-Miles MethodISO 6614 Petroleum Products Determination of WaterSeparability of Petroleum Oils and Synthetic Fluids3. Terminology3.1 Definitions of Terms Specific to This Standard:1Th
12、is guide is under the jurisdiction of ASTM Committee G01 on Corrosion ofMetals and is the direct responsibility of Subcommittee G01.05 on LaboratoryCorrosion Tests.Current edition approved Nov. 1, 2012. Published November 2012. Originallyapproved in 2001. Last previous edition approved in 2006 as G1
13、70 06. DOI:10.1520/G0170-06R12.2For referenced ASTM standards, visit the ASTM website, www.astm.org, orcontact ASTM Customer Service at serviceastm.org. For Annual Book of ASTMStandards volume information, refer to the standards Document Summary page onthe ASTM website.3The last approved version of
14、this historical standard is referenced onwww.astm.org.4Available from National Association of Corrosion Engineers (NACE), 1440South Creek Dr., Houston, TX 77084-4906, http:/www.nace.org.5Available from American National Standards Institute (ANSI), 25 W. 43rd St.,4th Floor, New York, NY 10036, http:/
15、www.ansi.org.Copyright ASTM International, 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA 19428-2959. United States13.1.1 atmospheric pressure experimentan experiment con-ducted at the ambient atmospheric pressure (typically less than0.07 MPa (10 psig), using normal laboratory glassware.3
16、.1.2 batch inhibitoran inhibitor that forms a film on themetal surface that persists to effect inhibition.3.1.3 batch treatmenta method of applying a batch inhibi-tor. Batch inhibitors are applied as a plug between pigs or asslugs of chemical poured down the well bore. The batchinhibitor is dissolve
17、d or dispersed in a medium, usuallyhydrocarbon and the inhibited solution is allowed to be incontact with the surface that is to be protected for a fixedamount of time. During this period, the inhibitor film is formedon the surface and protects the surface during the passage ofmultiphase flow, for e
18、xample, oil/water/gas.3.1.4 continuous inhibitoran inhibitor that is continuouslyinjected into the system in order to effect inhibition. Since thesurface receives full exposure to the inhibitor, the film repair iscontinuous.3.1.5 emulsification-tendencya property of an inhibitorthat causes the water
19、 and hydrocarbon mixture to form anemulsion. The emulsion formed can be quite difficult to removeand this will lead to separation difficulties in the productionfacilities.3.1.6 film persistencyability of inhibitor film (usuallybatch inhibitor) to withstand the forces (for example, flow) thattend to
20、destroy the film over time.3.1.7 flow loopan experimental pipe that contains variouscorrosion probes to monitor corrosion rates.Aflow loop can beconstructed in the laboratory or attached to an operatingsystem.3.1.8 foaming tendencytendency of inhibitor in solution(water or hydrocarbon) to create and
21、 stabilize foam when gasis purged through the solution.3.1.9 gas to oil ratio (GOR)ratio of the amount of gas andoil transported through a pipe over a given time.3.1.10 high-pressurea pressure above ambient atmo-spheric pressure that cannot be contained in normal laboratoryglassware. Typically, this
22、 is greater than 0.07 MPa (10 psig).3.1.11 high-temperaturetemperatures above ambientlaboratory temperature where sustained heating of the environ-ment is required.3.1.12 laboratory methodologya small laboratory experi-mental set up, that is used to generate the corrosion. Examplesof laboratory meth
23、odologies include rotating cylinder electrode(RCE), rotating cage (RC), and jet impingement (JI) underflowing conditions.3.1.13 live wateraqueous solution obtained from a pipe-line or well. Usually live water is protected from atmosphericoxygen.3.1.14 mass transfer coeffcient (k, m/s)the rate at whi
24、chthe reactants (or products) are transferred to the surface (orremoved from the surface).3.1.15 measuring techniquetechnique for determining therate of corrosion and the inhibitor efficiency. Examples ofmeasuring techniques are mass loss, linear polarization resis-tance (LPR), electrochemical imped
25、ance spectroscopy (EIS),electrical resistance (ER), and potentiodynamic polarization(PP) methods.3.1.16 multiphase flowsimultaneous passage or transportof more than one phase, where the phases have different states(gas, liquid, and solid) or the same state (liquid), but differentfluid characteristic
26、s (viscosity, density, and specific gravity).3.1.17 synthetic watera synthetic solution prepared in thelaboratory using various chemicals. The composition is basedon the composition of fluid found in an oil production system.3.1.18 Schmidt Number (Sc)a measure of the ratio of thehydrodynamic boundar
27、y layer to the diffusion boundary layer.This dimensionless parameter is equal to kinematic viscositydivided by diffusion coefficient.3.1.19 wall shear stress (, N/m2)a force per unit area onthe pipe due to fluid friction.3.2 The terminology used herein, if not specifically definedotherwise, shall be
28、 in accordance with Terminology D4410 orG15. Definitions provided herein and not given in TerminologyD4410 or G15 are limited only to this guide.4. Summary of Guide4.1 Inhibitor evaluation in the laboratory consists of twosteps (1) evaluation of inhibitor efficiency and (2) evaluation ofsecondary in
29、hibitor properties.4.2 Four laboratory methodologies, flow loop, rotating cyl-inder electrode (RCE), rotating cage (RC), and jet impinge-ment (JI) are available to evaluate the inhibitor efficiency in thelaboratory. All four methodologies can be operated at atmo-spheric and high pressure conditions.
30、 The corrosion rates canbe measured using mass loss or electrochemical methods.Using the methodologies, several variables, compositions ofmaterial, composition of environment (gas and liquid),temperature, pressure, and flow, that influence the corrosionrate in the field can be simulated in the labor
31、atory. Rotatingcylinder electrode (RCE), rotating cage (RC), and jet impinge-ment (JI) methodologies are compact, inexpensive, hydrody-namically characterized, and scalable; that is, can be carriedout at various flow conditions.4.3 Several secondary properties of the inhibitor are evalu-ated before
32、the inhibitor is applied in the field. They arewater/oil partitioning, solubility, emulsification tendency, foamtendency, thermal stability, toxicity, and compatibility withother additives/materials. Laboratory methods to evaluate thesecondary properties are described.5. Significance and Use5.1 Corr
33、osion inhibitors continue to play a key role incontrolling internal corrosion associated with oil and gasproduction and transportation. This results primarily from theindustrys extensive use of carbon and low alloy steels, which,for many applications, are economic materials of constructionthat gener
34、ally exhibit poor corrosion resistance. As aconsequence, there is a strong reliance on inhibitor deploymentG170 06 (2012)2for achieving cost-effective corrosion control, especially fortreating long flowlines and main export pipelines (1).65.2 For multiphase flow, the aqueous-oil-gas interphases cant
35、ake any of an infinite number of possible forms. These formsare delineated into certain classes of interfacial distributioncalled flow regimes. The flow regimes depend on the inclina-tion of the pipe (that is, vertical or horizontal), flow rate (basedon production rate), and flow direction (that is,
36、 upward ordownward). The common flow regimes in vertical upwardflow, vertical downward flow, and horizontal flow are pre-sented in Figs. 1-3 respectively (2, 3).5.3 Depending on the flow regime, the pipe may undergovarious forms of corrosion, including general, localized, flow-induced, and erosion-c
37、orrosion. One of the predominant failuremechanisms of multiphase systems is pitting corrosion.5.4 The performance of a corrosion inhibitor is influencedprimarily by the nature of inhibitor, operating conditions of asystem, and the method by which it is added. Two types ofinhibitors are used in the o
38、il field, continuous and batch.Water-soluble and oil-soluble, water-dispersible inhibitors areadded continuously. Oil-soluble inhibitors are, in general,batch treated. The test methods to evaluate the inhibitors for aparticular field should be carried so that the operating condi-tions of the system
39、are simulated. Thus during the evaluation ofa corrosion inhibitor, an important first step is to identify thefield conditions under which the inhibitor is intended to beused. The environmental conditions in the field locations willdictate the laboratory conditions under which testing is carriedout.5
40、.5 Various parameters that influence corrosion rates, andhence, inhibitor performance in a given system are (1) com-position of material (2) composition of gas and liquid (3)temperature (4) flow and (5) pressure.5.5.1 In order for a test method to be relevant to a particularsystem, it should be poss
41、ible to control the combined effects of6The boldface numbers in parentheses refer to the list of references at the end ofthis standard.NOTE 1Gand Lare gas and liquid densities and ULand UGare superficial velocities or the volume of flow rates of the liquid and gas per unitcross-sectional area of the
42、 channel (2).FIG. 1 Flow Regimes for Vertical Upward Multiphase FlowFIG. 2 Flow Regimes for Vertical Downward Flow (2)G170 06 (2012)3various parameters that influence corrosion in that system. Atest method is considered to be predictive if it can generateinformation regarding type of corrosion, gene
43、ral and localizedcorrosion rates, nature of inhibition, and life of inhibitor film(or adsorbed layer). Rather than try to perfectly reproduce allthe field conditions, a more practical approach is to identify thecritical factors that determine/impact inhibitor performanceand then design experiments i
44、n a way which best evaluatesthese factors.5.6 Composition of material, composition of gas and liquid(oil and water), temperature, and pressure are direct variables.Simulation of them in the laboratory is direct. Laboratoryexperiments are carried out at the temperature of the field usingcoupons or el
45、ectrodes made out of the field material (forexample, carbon steel). The effect of pressure is simulated byusing a gas mixture with a composition similar to the field foratmospheric experiments and by using partial pressures similarto those in the field for high pressure experiments.5.7 In multiphase
46、 systems there are three phases, oil, aque-ous (brine water), and gas. Corrosion occurs at places wherethe aqueous phase contacts the material (for example, steel).The corrosivity of the aqueous phase is influenced by thecomposition and the concentration of dissolved gases (forexample, H2S and CO2).
47、 In evaluating corrosion inhibitors inthe laboratory, aqueous phase is usually used with a positivepressure of gas mixture to simulate the gaseous phase. The oilmay have a major effect on the corrosion rate and inhibitorefficiency. The presence of oil phase in the test environmentcan have significan
48、tly different effects (4). The primary effectof the oil phase is apparently on the protectiveness of thecorrosion inhibitor. The oil phase may have the followingeffects: (1) partitioning of inhibitor between phases (2) chang-ing the contact time of the aqueous phase on the pipe (3)changing the wetti
49、ng behaviour of the pipe surface (4) intro-ducing protective compounds that are naturally occurring in theoil.5.7.1 Inhibitor evaluation in the absence of the oil phasecannot give an accurate picture of the behaviour of steel inmultiphase environments. Ideally, the oil phase should bepresent when testing the inhibitor in the laboratory.5.8 Flow is an indirect variable, and simulation of flow inthe laboratory is not direct. For this reason, the hydrodynamicflow parameters are determined, and then the laboratorycorrosion tests are conducted under the
