ASTM G170-01

NOTICE: This standard has either been superseded and replaced by a new version or discontinued.
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Designation: G 170 – 01
Standard Guide for
Evaluating and Qualifying Oilfield and Refinery Corrosion
Inhibitors in the Laboratory
This standard is issued under the fixed designation G 170; 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 (e) indicates an editorial change since the last revision or reapproval.
1. Scope G 96 Guide for On-Line Monitoring of Corrosion in Plant
Equipment (Electrical and Electrochemical Methods)
1.1 This guide covers some generally accepted laboratory
G 102 Practice for Calculation of Corrosion Rates and
methodologies that are used for evaluating corrosion inhibitors
Related Information from Electrochemical Measurements
for oilfield and refinery applications in well defined flow
G 106 Practice for Verification of Algorithm and Equipment
conditions.
for Electrochemical Impedance Measurements
1.2 This guide does not cover detailed calculations and
G 111 Guide for Corrosion Tests in High Temperature or
methods, but rather covers a range of approaches which have
High Pressure Environment, or Both
found application in inhibitor evaluation.
2.2 NACE Standards:
1.3 Only those methodologies that have found wide accep-
NACE-5A195 State-of-the-Art Report on Controlled-Flow
tance in inhibitor evaluation are considered in this guide.
Laboratory Corrosion Test, Houston, TX, NACE Interna-
1.4 This guide is intended to assist in the selection of
tional Publication, Item No. 24187, December 1995
methodologies that can be used for evaluating corrosion
NACE-ID196 Laboratory Test Methods for Evaluating Oil-
inhibitors.
Field Corrosion Inhibitors, Houston, TX, NACE Interna-
1.5 This standard does not purport to address all of the
tional Publication, Item No. 24192, December 1996
safety concerns, if any, associated with its use. It is the
NACE-TM0196 Standard Test Method “Chemical Resis-
responsibility of the user of this standard to establish appro-
tance of Polymeric Materials by Periodic Evaluation,”
priate safety and health practices and determine the applica-
Houston, TX, NACE International Publication, Item No.
bility of regulatory requirements prior to use.
21226, 1996
2. Referenced Documents
2.3 ISO Standards:
ISO 696 Surface Active Agents — Measurements of Foam-
2.1 ASTM Standards:
ing Power Modified Ross-Miles Method
D 1141 Practice for Preparation of Substitute Ocean Water
ISO 6614 Petroleum Products — Determination of Water
G 1 Practice for Preparing, Cleaning, and Evaluating Cor-
Separability of Petroleum Oils and Synthetic Fluids
rosion Test Specimens
G 3 Practice for Conventions Applicable to Electrochemical
3. Terminology
Measurements in Corrosion Testing
3.1 Definitions of Terms Specific to This Standard:
G 5 Reference Test Method for Making Potentiostatic and
3.1.1 atmospheric pressure experiment—an experiment
Potentiodynamic Anodic Polarization Measurements
conducted at the ambient atmospheric pressure (typically less
G 15 Terminology Relating to Corrosion and Corrosion
than 0.07 MPa (10 psig)), using normal laboratory glassware.
Testing
3.1.2 batch inhibitor—an inhibitor that forms a film on the
G 16 Guide for Applying Statistics to Analysis of Corrosion
metal surface that persists to effect inhibition.
Data
3.1.3 batch treatment—a method of applying a batch inhibi-
G 31 Practice for Laboratory Immersion Corrosion Testing
tor. Batch inhibitors are applied as a plug between pigs or as
of Metals
slugs of chemical poured down the well bore. The batch
G 46 Guide for Examination and Evaluation of Pitting
inhibitor is dissolved or dispersed in a medium, usually
Corrosion
hydrocarbon and the inhibited solution is allowed to be in
G 59 Test Method for Conducting Potentiodynamic Polar-
contact with the surface that is to be protected for a fixed
ization Resistance Measurements
amount of time. During this period, the inhibitor film is formed
on the surface and protects the surface during the passage of
This guide is under the jurisdiction of ASTM Committee G01 on Corrosion of
Metals and is the direct responsibility of Subcommittee G01.05 on Laboratory
Corrosion Tests. Available from National Assoc. of Corrosion Engineers, P.O. Box 218340,
Current edition approved June 10, 2001. Published September 2001. Houston, TX 77218.
2 5
Annual Book of ASTM Standards, Vol 11.02. Available from American National Standards Institute, 11 West 42nd Street,
Annual Book of ASTM Standards, Vol 03.02. 13th Floor, New York, NY 10036.
Copyright © ASTM, 100 Barr Harbor Drive, West Conshohocken, PA 19428-2959, United States.
G 170
multiphase flow, for example, oil/water/gas. measuring techniques are mass loss, linear polarization resis-
tance (LPR), electrochemical impedance spectroscopy (EIS),
3.1.4 continuous inhibitor—an inhibitor that is continuously
electrical resistance (ER), and potentiodynamic polarization
injected into the system in order to effect inhibition. Since the
(PP) methods.
surface receives full exposure to the inhibitor, the film repair is
continuous. 3.1.20 multiphase flow—simultaneous passage or transport
of more than one phase, where the phases have different states
3.1.5 EIS—electrochemical impedance spectroscopy.
(gas, liquid, and solid) or the same state (liquid), but different
3.1.6 electrochemical impedance—the frequency depen-
fluid characteristics (viscosity, density, and specific gravity).
dent, complex valued proportionality factor, DI/DE, between
3.1.21 synthetic water—a synthetic solution prepared in the
the applied potential (or current) and the response current (or
laboratory using various chemicals. The composition is based
potential) in an electrochemical cell. This factor becomes the
on the composition of fluid found in an oil production system.
impedance when the perturbation and response are related
3.1.22 Reynolds Number (Re)—a ratio of the convective
linearly (the factor value is independent of the perturbation
forces to the viscous forces in the fluid. This dimensionless
magnitude) and the response is caused only by the perturba-
number is the product of velocity, density, and pipe diameter
tion. The value may be related to the corrosion rate when the
divided by viscosity.
measurement is made at the corrosion potential.
3.1.23 Schmidt Number (Sc)—a measure of the ratio of the
3.1.7 emulsification-tendency—a property of an inhibitor
hydrodynamic boundary layer to the diffusion boundary layer.
that causes the water and hydrocarbon mixture to form an
This dimensionless parameter is equal to kinematic viscosity
emulsion. The emulsion formed can be quite difficult to remove
divided by diffusion coefficient.
and this will lead to separation difficulties in the production
3.1.24 wall shear stress (t, N/m )—a force per unit area on
facilities.
the pipe due to fluid friction.
3.1.8 film persistency—ability of inhibitor film (usually
3.2 The terminology used herein, if not specifically defined
batch inhibitor) to withstand the forces (for example, flow) that
otherwise, shall be in accordance with Terminology G 15.
tend to destroy the film over time.
Definitions provided herein and not given in Terminology G 15
3.1.9 flow loop—an experimental pipe that contains various
are limited only to this guide.
corrosion probes to monitor corrosion rates. A flow loop can be
constructed in the laboratory or attached to an operating
4. Summary of Guide
system.
4.1 Inhibitor evaluation in the laboratory consists of two
3.1.10 foaming tendency—tendency of inhibitor in solution
steps (1) evaluation of inhibitor efficiency and (2) evaluation of
(water or hydrocarbon) to create and stabilize foam when gas
secondary inhibitor properties.
is purged through the solution.
4.2 Four laboratory methodologies, flow loop, rotating cyl-
3.1.11 gas to oil ratio (GOR)—ratio of the amount of gas
inder electrode (RCE), rotating cage (RC), and jet impinge-
and oil transported through a pipe over a given time.
ment (JI) are available to evaluate the inhibitor efficiency in the
3.1.12 high-pressure—a pressure above ambient atmo-
laboratory. All four methodologies can be operated at atmo-
spheric pressure that cannot be contained in normal laboratory
spheric and high pressure conditions. The corrosion rates can
glassware. Typically, this is greater than 0.07 MPa (10 psig).
be measured using mass loss or electrochemical methods.
3.1.13 high-temperature—temperatures above ambient
Using the methodologies, several variables, compositions of
laboratory temperature where sustained heating of the environ-
material, composition of environment (gas and liquid), tem-
ment is required.
perature, pressure, and flow, that influence the corrosion rate in
3.1.14 high-temperature, high-pressure experiment—an ex-
the field can be simulated in the laboratory. Rotating cylinder
periment that is conducted at high-pressure and high-
electrode (RCE), rotating cage (RC), and jet impingement (JI)
temperature.
methodologies are compact, inexpensive, hydrodynamically
3.1.15 laboratory methodology—a small laboratory experi-
characterized, and scalable; that is, can be carried out at various
mental set up, that is used to generate the corrosion. Examples
flow conditions.
of laboratory methodologies include rotating cylinder electrode
4.3 Several secondary properties of the inhibitor are evalu-
(RCE), rotating cage (RC), and jet impingement (JI) under
ated before the inhibitor is applied in the field. They are
flowing conditions.
water/oil partitioning, solubility, emulsification tendency, foam
3.1.16 live water—aqueous solution obtained from a pipe-
tendency, thermal stability, toxicity, and compatibility with
line or well. Usually live water is protected from atmospheric
other additives/materials. Laboratory methods to evaluate the
oxygen.
secondary properties are described.
3.1.17 LPR—measurement of corrosion current by displac-
5. Significance and Use
ing the potential by a small amount (below 20 mV) from the
corrosion potential and monitoring the current. The plot of
5.1 Corrosion inhibitors continue to play a key role in
potential versus current is linear.
controlling internal corrosion associated with oil and gas
3.1.18 mass transfer coeffıcient (k, m/s)—the rate at which
production and transportation. This results primarily from the
the reactants (or products) are transferred to the surface (or industry’s extensive use of carbon and low alloy steels, which,
removed from the surface).
for many applications, are economic materials of construction
3.1.19 measuring technique—technique for determining the that generally exhibit poor corrosion resistance. As a conse-
rate of corrosion and the inhibitor efficiency. Examples of quence, there is a strong reliance on inhibitor deployment for
G 170
achieving cost-effective corrosion control, especially for treat- used. The environmental conditions in the field locations will
ing long flowlines and main export pipelines (1).
dictate the laboratory conditions under which testing is carried
5.2 For multiphase flow, the aqueous-oil-gas interphases can out.
take any of an infinite number of possible forms. These forms
5.5 Various parameters that influence corrosion rates, and
are delineated into certain classes of interfacial distribution
hence, inhibitor performance in a given system are (1) com-
called flow regimes. The flow regimes depend on the inclina-
position of material (2) composition of gas and liquid (3)
tion of the pipe (that is, vertical or horizontal), flow rate (based
temperature (4) flow and (5) pressure.
on production rate), and flow direction (that is, upward or
5.5.1 In order for a test method to be relevant to a particular
downward). The common flow regimes in vertical upward
system, it should be possible to control the combined effects of
flow, vertical downward flow, and horizontal flow are pre-
various parameters that influence corrosion in that system. A
sented in Figs. 1-3 respectively (2, 3).
test method is considered to be predictive if it can generate
5.3 Depending on the flow regime, the pipe may undergo
information regarding type of corrosion, general and localized
various forms of corrosion, including general, localized, flow-
corrosion rates, nature of inhibition, and life of inhibitor film
induced, and erosion-corrosion. One of the predominant failure
(or adsorbed layer). Rather than try to perfectly reproduce all
mechanisms of multiphase systems is pitting corrosion.
the field conditions, a more practical approach is to identify the
5.4 The performance of a corrosion inhibitor is influenced
critical factors that determine/impact inhibitor performance
primarily by the nature of inhibitor, operating conditions of a
and then design experiments in a way which best evaluates
system, and the method by which it is added. Two types of
these factors.
inhibitors are used in the oil field, continuous and batch.
5.6 Composition of material, composition of gas and liquid
Water-soluble and oil-soluble, water-dispersible inhibitors are
(oil and water), temperature, and pressure are direct variables.
added continuously. Oil-soluble inhibitors are, in general,
Simulation of them in the laboratory is direct. Laboratory
batch treated. The test methods to evaluate the inhibitors for a
experiments are carried out at the temperature of the field using
particular field should be carried so that the operating condi-
coupons or electrodes made out of the field material (for
tions of the system are simulated. Thus during the evaluation of
example, carbon steel). The effect of pressure is simulated by
a corrosion inhibitor, an important first step is to identify the
using a gas mixture with a composition similar to the field for
field conditions under which the inhibitor is intended to be
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, aque-
The boldface numbers in parentheses refer to the list of references at the end of
ous (brine water), and gas. Corrosion occurs at places where
this standard.
NOTE—r and r are gas and liquid densities and U and U are
G L L G
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
G 170
FIG. 2 Flow Regimes for Vertical Downward Flow (2)
NOTE—Boundary conditions given by two studies are presented.(2)
FIG. 3 Flow Regimes for Horizontal Flow
the aqueous phase contacts the material (for example, steel). can have significantly different ef
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