ASTM G170 - 06(2012)

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

    Active Standard ASTM G170 | Developed by Subcommittee: G01.05

    Book of Standards Volume: 03.02

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    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).6

    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).

    Flow Regimes for Vertical Upward Multiphase Flow
    Note 1ρG and ρL are gas and liquid densities and UL and UG are superficial velocities or the volume of flow rates of the liquid and gas per unit cross-sectional area of the channel (2).
    FIG. 1 Flow Regimes for Vertical Upward Multiphase Flow
    Flow Regimes for Vertical Downward Flow
    FIG. 2 Flow Regimes for Vertical Downward Flow (2)
    Flow Regimes for Horizontal Flow
    Note 1Boundary conditions given by two studies are presented.(2)
    FIG. 3 Flow Regimes for Horizontal Flow

    5.3 Depending on the flow regime, the pipe may undergo various forms of corrosion, including general, localized, flow-induced, and erosion-corrosion. One of the predominant failure mechanisms of multiphase systems is pitting corrosion.

    5.4 The performance of a corrosion inhibitor is influenced primarily by the nature of inhibitor, operating conditions of a system, and the method by which it is added. Two types of inhibitors are used in the oil field, continuous and batch. Water-soluble and oil-soluble, water-dispersible inhibitors are added continuously. Oil-soluble inhibitors are, in general, batch treated. The test methods to evaluate the inhibitors for a particular field should be carried so that the operating conditions of the system are simulated. Thus during the evaluation of a corrosion inhibitor, an important first step is to identify the field conditions under which the inhibitor is intended to be used. The environmental conditions in the field locations will dictate the laboratory conditions under which testing is carried out.

    5.5 Various parameters that influence corrosion rates, and hence, inhibitor performance in a given system are (1) composition 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 particular system, it should be possible to control the combined effects of various parameters that influence corrosion in that system. A test method is considered to be predictive if it can generate information regarding type of corrosion, general and localized corrosion rates, nature of inhibition, and life of inhibitor film (or adsorbed layer). Rather than try to perfectly reproduce all the field conditions, a more practical approach is to identify the critical factors that determine/impact inhibitor performance and then design experiments in a way which best evaluates these 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. Laboratory experiments are carried out at the temperature of the field using coupons or electrodes made out of the field material (for example, carbon steel). The effect of pressure is simulated by using a gas mixture with a composition similar to the field for atmospheric experiments and by using partial pressures similar to those in the field for high pressure experiments.

    5.7 In multiphase systems there are three phases, oil, aqueous (brine water), and gas. Corrosion occurs at places where the aqueous phase contacts the material (for example, steel). The corrosivity of the aqueous phase is influenced by the composition and the concentration of dissolved gases (for example, H2S and CO2). In evaluating corrosion inhibitors in the laboratory, aqueous phase is usually used with a positive pressure of gas mixture to simulate the gaseous phase. The oil may have a major effect on the corrosion rate and inhibitor efficiency. The presence of oil phase in the test environment can have significantly different effects (4). The primary effect of the oil phase is apparently on the protectiveness of the corrosion inhibitor. The oil phase may have the following effects: (1) partitioning of inhibitor between phases (2) changing the contact time of the aqueous phase on the pipe (3) changing the wetting behaviour of the pipe surface (4) introducing protective compounds that are naturally occurring in the oil.

    5.7.1 Inhibitor evaluation in the absence of the oil phase cannot give an accurate picture of the behaviour of steel in multiphase environments. Ideally, the oil phase should be present when testing the inhibitor in the laboratory.

    5.8 Flow is an indirect variable, and simulation of flow in the laboratory is not direct. For this reason, the hydrodynamic flow parameters are determined, and then the laboratory corrosion tests are conducted under the calculated hydrodynamic parameters. The fundamental assumption in this approach is that, when the hydrodynamic parameters of different geometries are the same, then the corrosion mechanism will be the same. Under these conditions, the corrosion rate and the efficiency of corrosion inhibition in the laboratory and in the field are similar. The commonly used hydrodynamic parameters are wall shear stress, Reynolds number, and mass transfer coefficient (3, 5).

    5.9 Neither the flow rate (m/s) nor dimensionless parameters can be directly related to the local hydrodynamic forces at the material surface that may be responsible for accelerated localized attack. Local hydrodynamic forces are influenced by several factors including pipe inclination, position (that is, 3, 6, 9 o'clock), presence of bends, deposits, edges, welds, expansion, and contraction. The flow rate and dimensionless parameters describe only bulk, or average, properties of the dynamic system. Thus the wall shear stress and mass transfer coefficient can be calculated only as averages at the surface with an average surface roughness.

    5.10 Inhibitors are first screened in the laboratory, then evaluated in the field, and finally used in engineering operations. The laboratory methodologies, therefore, should be carried out in a compact system with the capacity to evaluate various products quickly with the flow pattern and regime characterized. The results obtained should be relevant to field operation, should be predictive of field performance in terms of inhibitor efficiency, and should be scalable, that is, the experiments can be carried out at various hydrodynamic conditions.

    5.11 Flow loops are used to evaluate corrosion inhibitors either in the laboratory or by attaching to a live pipe. The loop simulates the flow regime, but the apparatus is relatively sophisticated, and experiments are expensive and time consuming. The loop is considered sophisticated to be an ideal laboratory methodology under the scope of this guide.

    5.12 This guide discusses test facilities and considers the necessary elements which need to be built into a laboratory strategy for testing corrosion inhibitors for multiphase systems. The emphasis is on those methodologies that are compact and scalable, hydrodynamically well characterized, and relatively inexpensive to use. The laboratory methodologies are (1) rotating cylinder electrode (RCE) (2) rotating cage (RC) and (3) jet impingement (JI). These methodologies can be used under both atmospheric and high pressure conditions. Detailed description of RCE and JI are presented in NACE-5A195.

    5.13 Laboratory tests for inhibitor evaluation consist of two main components–laboratory methodology and measurement technique. The combinations of laboratory methodology and measurement technique for inhibitor evaluation for multiphase systems are presented in Table 1.

    TABLE 1 Laboratory Methodologies and Measurement Techniques for Corrosion Inhibitor Evaluation



    Gas Phase



    mass loss,

    aqueous phase

    specimen is a cylinder


    mass loss

    aqueous/oil phase

    specimen is a cylinder


    mass loss,

    aqueous phase

    specimen is a disc


    mass loss

    aqueous/oil phase

    specimen is a disc



    aqueous phase

    specimen is a ring


    mass loss

    aqueous phase or
    aqueous/oil phase

    measurements cannot
    be carried out

    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.

    1. 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.

    2. Referenced Documents (purchase separately) The documents listed below are referenced within the subject standard but are not provided as part of the standard.

    ASTM Standards

    D1141 Practice for the Preparation of Substitute Ocean Water

    D4410 Terminology for Fluvial Sediment

    G1 Practice for Preparing, Cleaning, and Evaluating Corrosion Test Specimens

    G3 Practice for Conventions Applicable to Electrochemical Measurements in Corrosion Testing

    G5 Reference Test Method for Making Potentiostatic and Potentiodynamic Anodic Polarization Measurements

    G15 Terminology Relating to Corrosion and Corrosion Testing

    G16 Guide for Applying Statistics to Analysis of Corrosion Data

    G31 Guide for Laboratory Immersion Corrosion Testing of Metals

    G46 Guide for Examination and Evaluation of Pitting Corrosion

    G59 Test Method for Conducting Potentiodynamic Polarization Resistance Measurements

    G96 Guide for Online Monitoring of Corrosion in Plant Equipment (Electrical and Electrochemical Methods)

    G102 Practice for Calculation of Corrosion Rates and Related Information from Electrochemical Measurements

    G106 Practice for Verification of Algorithm and Equipment for Electrochemical Impedance Measurements

    G111 Guide for Corrosion Tests in High Temperature or High Pressure Environment, or Both

    NACE Standards

    NACE-TM0196 Standard Test Method Chemical Resistance of Polymeric Materials by Periodic Evaluation, Houston, TX, NACE International Publication, Item No. 21226, 1996

    ISO Standards

    ISO6614 Petroleum Products -- Determination of Water Separability of Petroleum Oils and Synthetic Fluids

    ICS Code

    ICS Number Code 75.020 (Extraction and processing of petroleum and natural gas)

    UNSPSC Code

    UNSPSC Code

    DOI: 10.1520/G0170-06R12

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