1、Designation: G 170 06Standard Guide forEvaluating and Qualifying Oilfield and Refinery CorrosionInhibitors in the Laboratory1This standard is issued under the fixed designation G 170; the number immediately following the designation indicates the year oforiginal adoption or, in the case of revision,
2、 the year of last revision. A number in parentheses indicates the year of last reapproval. Asuperscript epsilon (e) indicates an editorial change since the last revision or reapproval.1. Scope1.1 This guide covers some generally accepted laboratorymethodologies that are used for evaluating corrosion
3、 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 wide accep-tance i
4、n 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 theresponsibil
5、ity 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:2D 1141 Practice for the Preparation of Substitute OceanWaterD 4410 Terminology for Fluvial Sedime
6、ntG1 Practice for Preparing, Cleaning, and Evaluating Cor-rosion Test SpecimensG3 Practice for ConventionsApplicable to ElectrochemicalMeasurements in Corrosion TestingG5 Reference Test Method for Making Potentiostatic andPotentiodynamic Anodic Polarization MeasurementsG15 Terminology Relating to Co
7、rrosion and CorrosionTestingG16 Guide forApplying Statistics toAnalysis of CorrosionDataG31 Practice for Laboratory Immersion Corrosion Testingof MetalsG46 Guide for Examination and Evaluation of PittingCorrosionG59 Test Method for Conducting Potentiodynamic Polar-ization Resistance MeasurementsG96
8、Guide for On-Line Monitoring of Corrosion in PlantEquipment (Electrical and Electrochemical Methods)G 102 Practice for Calculation of Corrosion Rates andRelated Information from Electrochemical MeasurementsG 106 Practice for Verification ofAlgorithm and Equipmentfor Electrochemical Impedance Measure
9、mentsG 111 Guide for Corrosion Tests in High Temperature orHigh Pressure Environment, or Both2.2 NACE Standards:3NACE-5A195 State-of-the-Art Report on Controlled-FlowLaboratory Corrosion Test, Houston, TX, NACE Interna-tional Publication, Item No. 24187, December 1995NACE-ID196 Laboratory Test Metho
10、ds 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 Publication, Item No.21226, 19962.3 ISO S
11、tandards:4ISO 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:3.1.1 atmospheric pressure experiment
12、an experimentconducted at the ambient atmospheric pressure (typically lessthan 0.07 MPa (10 psig), using normal laboratory glassware.3.1.2 batch inhibitoran inhibitor that forms a film on themetal surface that persists to effect inhibition.1This guide is under the jurisdiction of ASTM Committee G01
13、on Corrosion ofMetals and is the direct responsibility of Subcommittee G01.05 on LaboratoryCorrosion Tests.Current edition approved Nov. 1, 2006. Published December 2006. Originallyapproved in 2001. Last previous edition approved in 2001 as G 170 01a.2For referenced ASTM standards, visit the ASTM we
14、bsite, 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.3Available from National Association of Corrosion Engineers (NACE), 1440South Creek Dr., Houston, TX 77084-490
15、6, http:/www.nace.org.4Available from American National Standards Institute (ANSI), 25 W. 43rd St.,4th Floor, New York, NY 10036, http:/www.ansi.org.1Copyright ASTM International, 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA 19428-2959, United States.3.1.3 batch treatmenta method of app
16、lying 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 dissolved or dispersed in a medium, usuallyhydrocarbon and the inhibited solution is allowed to be incontact with the surface that is to be protected
17、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 example, oil/water/gas.3.1.4 continuous inhibitoran inhibitor that is continuouslyinjected into the system in order to effect inhibition. Since
18、 thesurface receives full exposure to the inhibitor, the film repair iscontinuous.3.1.5 emulsification-tendencya property of an inhibitorthat causes the water and hydrocarbon mixture to form anemulsion. The emulsion formed can be quite difficult to removeand this will lead to separation difficulties
19、 in the productionfacilities.3.1.6 film persistencyability of inhibitor film (usuallybatch inhibitor) to withstand the forces (for example, flow) thattend to destroy the film over time.3.1.7 flow loopan experimental pipe that contains variouscorrosion probes to monitor corrosion rates.Aflow loop can
20、 beconstructed in the laboratory or attached to an operatingsystem.3.1.8 foaming tendencytendency of inhibitor in solution(water or hydrocarbon) to create and 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 pip
21、e over a given time.3.1.10 high-pressurea pressure above ambient atmo-spheric pressure that cannot be contained in normal laboratoryglassware. Typically, this is greater than 0.07 MPa (10 psig).3.1.11 high-temperaturetemperatures above ambientlaboratory temperature where sustained heating of the env
22、iron-ment is required.3.1.12 laboratory methodologya small laboratory experi-mental set up, that is used to generate the corrosion. Examplesof laboratory methodologies include rotating cylinder electrode(RCE), rotating cage (RC), and jet impingement (JI) underflowing conditions.3.1.13 live wateraque
23、ous 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 whichthe reactants (or products) are transferred to the surface (orremoved from the surface).3.1.15 measuring techniquetechnique for determining
24、therate of corrosion and the inhibitor efficiency. Examples ofmeasuring techniques are mass loss, linear polarization resis-tance (LPR), electrochemical impedance spectroscopy (EIS),electrical resistance (ER), and potentiodynamic polarization(PP) methods.3.1.16 multiphase flowsimultaneous passage or
25、 transportof more than one phase, where the phases have different states(gas, liquid, and solid) or the same state (liquid), but differentfluid characteristics (viscosity, density, and specific gravity).3.1.17 synthetic watera synthetic solution prepared in thelaboratory using various chemicals. The
26、 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 boundary layer to the diffusion boundary layer.This dimensionless parameter is equal to kinematic viscositydivided by diffusion coefficient.3.1.19 wa
27、ll shear stress (t, 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 in accordance with Terminology D 4410 orG15. Definitions provided herein and not given in Terminol-ogy D 4410 or G15are limited only to this
28、 guide.4. Summary of Guide4.1 Inhibitor evaluation in the laboratory consists of twosteps (1) evaluation of inhibitor efficiency and (2) evaluation ofsecondary inhibitor properties.4.2 Four laboratory methodologies, flow loop, rotating cyl-inder electrode (RCE), rotating cage (RC), and jet impinge-m
29、ent (JI) are available to evaluate the inhibitor efficiency in thelaboratory. All four methodologies can be operated at atmo-spheric and high pressure conditions. The corrosion rates canbe measured using mass loss or electrochemical methods.Using the methodologies, several variables, compositions of
30、material, composition of environment (gas and liquid), tem-perature, pressure, and flow, that influence the corrosion rate inthe field can be simulated in the laboratory. Rotating cylinderelectrode (RCE), rotating cage (RC), and jet impingement (JI)methodologies are compact, inexpensive, hydrodynami
31、callycharacterized, and scalable; that is, can be carried out at variousflow conditions.4.3 Several secondary properties of the inhibitor are evalu-ated before the inhibitor is applied in the field. They arewater/oil partitioning, solubility, emulsification tendency, foamtendency, thermal stability,
32、 toxicity, and compatibility withother additives/materials. Laboratory methods to evaluate thesecondary properties are described.5. Significance and Use5.1 Corrosion inhibitors continue to play a key role incontrolling internal corrosion associated with oil and gasproduction and transportation. This
33、 results primarily from theindustrys extensive use of carbon and low alloy steels, which,for many applications, are economic materials of constructionthat generally exhibit poor corrosion resistance. As a conse-quence, there is a strong reliance on inhibitor deployment forachieving cost-effective co
34、rrosion control, especially for treat-ing long flowlines and main export pipelines (1).55.2 For multiphase flow, the aqueous-oil-gas interphases cantake any of an infinite number of possible forms. These formsare delineated into certain classes of interfacial distributioncalled flow regimes. The flo
35、w regimes depend on the inclina-tion of the pipe (that is, vertical or horizontal), flow rate (basedon production rate), and flow direction (that is, upward or5The boldface numbers in parentheses refer to the list of references at the end ofthis standard.G170062downward). The common flow regimes in
36、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-corrosion. One of the predominant failuremechanis
37、ms 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 oil field, continuous and batch.Water-soluble and
38、 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 are simulated. Thus during the evaluation ofa co
39、rrosion 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.5.5 Various parameters that influence corrosion r
40、ates, 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 possible to control the combined effects ofvarious p
41、arameters that influence corrosion in that system. Atest method is considered to be predictive if it can generateinformation regarding type of corrosion, general and localizedcorrosion rates, nature of inhibition, and life of inhibitor film(or adsorbed layer). Rather than try to perfectly reproduce
42、allthe field conditions, a more practical approach is to identify thecritical factors that determine/impact inhibitor performanceand then design experiments in a way which best evaluatesthese factors.5.6 Composition of material, composition of gas and liquid(oil and water), temperature, and pressure
43、 are direct variables.Simulation of them in the laboratory is direct. Laboratoryexperiments are carried out at the temperature of the field usingcoupons or electrodes made out of the field material (forNOTErGand rLare gas and liquid densities and ULand UGare superficial velocities or the volume of f
44、low rates of the liquid and gas per unitcross-sectional area of the channel (2).FIG. 1 Flow Regimes for Vertical Upward Multiphase FlowFIG. 2 Flow Regimes for Vertical Downward Flow (2)G170063example, carbon steel). The effect of pressure is simulated byusing a gas mixture with a composition similar
45、 to the field foratmospheric experiments and by using partial pressures similarto those in the field for high pressure experiments.5.7 In multiphase systems there are three phases, oil, aque-ous (brine water), and gas. Corrosion occurs at places wherethe aqueous phase contacts the material (for exam
46、ple, steel).The corrosivity of the aqueous phase is influenced by thecomposition and the concentration of dissolved gases (forexample, H2S and CO2). In evaluating corrosion inhibitors inthe laboratory, aqueous phase is usually used with a positivepressure of gas mixture to simulate the gaseous phase
47、. The oilmay have a major effect on the corrosion rate and inhibitorefficiency. The presence of oil phase in the test environmentcan have significantly different effects (4). The primary effectof the oil phase is apparently on the protectiveness of thecorrosion inhibitor. The oil phase may have the
48、followingeffects: (1) partitioning of inhibitor between phases (2) chang-ing the contact time of the aqueous phase on the pipe (3)changing the wetting behaviour of the pipe surface (4) intro-ducing protective compounds that are naturally occurring in theoil.5.7.1 Inhibitor evaluation in the absence
49、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 calculated hydrody-namic parameters. The fundamental assumption in this ap-proach is that, when the hydrodynamic parameters of differentgeometries are the sam
