inhibitor effectiveness on co corrosion with oil and … · 2011. 11. 8. · corrosion has an...

EROSION/CORROSION RESEARCH CENTER IX-1

NOV 2011

INHIBITOR EFFECTIVENESS ON CO2 CORROSION WITH OIL AND SAND

INTRODUCTION

CO2 corrosion, sand erosion, and their synergistic effects (erosion-corrosion) cause many

problems in offshore pipelines, tubing and pipe fittings. Erosion-corrosion related problems involve

such concerns as safety, economy, and conservation of materials.

Corrosion has an important impact on the total cost of oil and gas production. Based on the

number, severity and diversity of corrosion related problems, CO2 corrosion (sweet corrosion) is

probably the material degradation mechanism most extensively studied in this industry over the last

30 years. In the last decade, predictive models have experienced a major improvement in accuracy as

well as in the development of mechanistic models of the physics involved in the CO2 corrosion

process. Several empirical laboratory models, empirical field models and mechanistic models have

been developed in this area and many parameters have been taken into account, namely the effect of

CO2 pressure, temperature, pH, chloride content, and hydrodynamics among others. But,

applicability of these models when sand is produced is still not clear.

One of the most common methods for controlling corrosion and erosion-corrosion is the use

of chemical inhibitors. Various factors affect inhibitor performance including temperature, inhibitor

concentration , flow velocity, sand erosion, water cut, metal cations, chlorides, type of metal,

electrolytes, pH, flow geometry and others [1-10]. Considerable research in the oil and gas industry

has been devoted to the development of inhibitor systems that can reduce corrosion rates in

production equipment to acceptable levels. As a result, methodologies have been developed for

predicting inhibitor efficiency as a function of environmental conditions and inhibitor concentration.

However, prior to field testing, very little is known about how the efficiency of an inhibitor is

affected by the erosive action of sand particles entrained in the flow stream.

Previous studies have shown that sand erosion decreases the inhibitor efficiency [11-13].

Sand production also raises the inhibitor concentration needed for optimum inhibitor effectiveness

[4]. Using laboratory tests simulating field conditions, McMahon [14] showed that large amounts of

corrosion inhibitor can be lost from the bulk solution by adsorption of inhibitor onto the surfaces of

produced sand particles. This can reduce the concentration of inhibitor which is available to protect

steel surfaces. However, this effect only becomes significant for high concentrations of sand (> 1000


NOV 2011

ppm, i.e., >35 lb/Mbbl) and small particle sizes (e.g., silt <10 microns in diameter), especially for

oil-wetted particles. On the other hand, Ramachandran et al. [15], showed that the effect of inhibitor

loss due to sand adsorption is small for industrial corrosion inhibitors used under most field

conditions. Tandon et al.[11] showed that for non scale-forming conditions with sand, inhibitor

protection provided by concentrations of 100 ppm and above appeared not to be affected much by

the addition of small amounts of sand. However, for some inhibitor concentrations, increasing sand

concentration adversely affected the ability of the inhibitor to maintain optimum protection over

extended periods of time [11].

Neville and Wang [16, 17] showed that the presence of inhibitor decreased the sand erosion

rate by adsorption on the sand and thus reducing the sand impact energy. Tummala et al. [18],

studied two inhibitor treatment scenarios involving sand production and a pre-existing iron carbonate

scale. In general, inhibitors that are effective in a CO2 saturated static brine, are not necessarily

effective under erosion-corrosion conditions [19]. Therefore, interactions of sand particles with

chemical inhibitors in oil and gas wells depend on many parameters including inhibitor

characteristics and the erosivity and corrosivity of the system.

Crossland et al. suggested a correlation for prediction of likelihood of erosion-corrosion

inhibition success in the oil and gas industry as a function of environmental factors such as

temperature, shear stress, and total dissolved solids. This correlation is a statistical correlation based

on experimental and field data in a wide range of production conditions. They defined four different

regions for inhibitor performance which can be used for the estimation of the amount of the inhibitor

needed to get the corrosion rate lower than 0.1 mm/y [20].

The need to be able to predict inhibitor performance under sand production conditions is

particularly acute when the wells are deep or off-shore because of the difficulty in running coupon

tests to evaluate the inhibitor efficiency at critical points throughout a system which might involve a

number of wells flowing into a single header. Further, it would be highly desirable to be able to

make decisions on the design of the well given advanced knowledge of the inhibition options and

their predicted effectiveness.

In the current study, which is an individual project for PETROBRAS oil and gas company, a

new approach is developed for predicting inhibited erosion-corrosion rate based on inhibitor

adsorption isotherms together with mechanistic models for predicting CO2 corrosion rates and sand

particle erosion rates. Synergistic effects of sand particle erosion with corrosion of carbon steel


NOV 2011

under non scale-forming conditions, in a CO2 saturated system, and in the presence of an inhibitor is

also examined. Flory-Huggins, Frumkin, Temkin, and Langmuir adsorption isotherms are used to

describe the inhibitor adsorption mechanism and the effects of inhibitor concentration and sand

erosion on CO2 corrosion of carbon steel. Metal loss rates are measured by long-term weight loss,

and linear polarization resistance (LPR) techniques. Potentiodynamic polarization and

Electrochemical Impedance Spectroscopy (EIS) are also used to examine the electrochemical

mechanisms of corrosion and inhibition.

BACKGROUND

During past 30 years extensive research on erosion-corrosion in oil and gas industry has

been conducted at the Erosion-Corrosion Research Center (E/CRC) at the University of Tulsa.

Erosion-corrosion of different materials such as carbon steel and corrosion resistance alloys has been

studied under sand particle erosion in CO2 saturated systems. Inhibitor performance has been also

investigated under erosion-corrosion condition. Previous studies at E/CRC have shown that sand

erosion decreases the inhibitor efficiency [11-13]. Tandon et al. studied inhibitor performance under

low erosivity in CO2 saturated systems at E/CRC. All tests were conducted in a half inch elbow

geometry in a liquid/solid two-phase flow loop at a flow velocity of 15 ft/s for non-scale-forming

conditions and for iron carbonate scale-forming conditions. For non scale-forming conditions, tests

carried out without an inhibitor consistently provided about the same metal loss rate for conditions

with and without sand. The LPR values monitoring the corrosion rate were nearly identical for all

these tests, which indicate the absence of a significant synergistic erosion-corrosion effect (Figure 1).

Results indicated that 100 ppm and 150 ppm inhibitor concentrations provided about the same level

of protection from corrosion but loss of protection provided by the 50 ppm concentration was more

significant (Figure 2). For non-scale-forming tests with sand, inhibitor protection provided by

concentrations of 100 ppm and above appeared not to be affected much by the addition of sand. It

should be mentioned here that for 100 ppm inhibitor concentration, the inhibitor protection

diminished only slightly for sand concentrations as high as 4%, which is much higher than

concentrations found in typical field conditions. For 50 ppm inhibitor concentration, the loss in

inhibitor protection was more significant at higher sand rates. Tests carried out without sand or


NOV 2011

inhibitor under scale forming conditions illustrated the ability of protective films to reduce the metal

loss rates to very low levels. However, addition of 1% sand at these conditions partially removed the

protective scale, increasing the metal loss rate and in some cases resulted in severe localized

corrosion at sand impingement points on the elbow specimen (Figure 3) [11].

Figure 1: Comparison of metal loss rates from weight loss and LPR method without inhibitor


NOV 2011

Figure 2: Average metal loss rate for different inhibitor concentrations with and without sand

Figure 3: Metal loss rate by LPR averaged over test period after initial formation of protective

scale for test without and with 100 ppm inhibitor concentration

Inhibited erosion-corrosion under high erosivity and non-scale-forming conditions was

investigated at E/CRC by Dave el al. [12, 13]. This research focused on the effectiveness of a

corrosion inhibitor for higher flow velocities (42 fps) entraining sand. The inhibitor appears to be


NOV 2011

very effective in reducing corrosion in this high velocity system (Figure 4). In erosion-corrosion with

1% sand, the inhibitor appeared to be very effective in reducing the corrosion component of erosion-

corrosion, although not quite as effective as for similar tests without sand. The inhibitor works

mainly on the corrosion component of erosion-corrosion. Thus, in inhibited erosion-corrosion

systems with high sand concentrations, the metal loss rates could be judged too high due to the

mechanical erosion component (Figure 5). At low sand concentrations, in inhibited erosion-corrosion

systems, the corrosion component appeared to be nearly as low as for similar inhibited systems with

no sand. Erosion may still be a problem at low sand concentrations depending on flow velocity and

piping size and geometry. Sand erosion can increase the corrosion part of erosion-corrosion by

removing the protective layer of inhibitor from the surface. Sand particles may also adsorb inhibitor

molecules and reduce the inhibition efficiency. Changing the surface roughness as a result of sand

erosion can also affect corrosion rate.

Figure 4: Summary of LPR values for different inhibitor concentration with and without sand


NOV 2011

Figure 5: Comparison of weight loss and LPR values for 100 ppm inhibitor

Inhibited erosion-corrosion under scale forming condition was also studied by Tummala et

al. [18] at E/CRC for two inhibitor treatment scenarios involving sand production and a pre-existing

iron carbonate scale. In both scenarios, inhibitor treatment was not applied until after the iron

carbonate scale had formed. The only difference between the two scenarios is the order of addition

of inhibitor and sand after the formation of iron carbonate scale. In the first scenario, sand is added

after a scale is formed, then inhibitor is added to the system (Figure 6). In the second scenario,

inhibitor is added after the formation of an iron carbonate scale on the specimen, then sand is added

to the system (Figure 7). However both scenarios resulted in an end-of-test LPR value in the range

20-25 mpy (0.508-0.635 mm/y) – the same range found for sand production conditions, but where

the inhibitor treatment was applied at the beginning of the test. These tests also showed that

corrosion rates with sand and inhibitor were twice the corrosion rates obtained with inhibitor but

without sand [18]. In general, inhibitors that are effective in a CO2 saturated static brine, are not as

effective under erosion-corrosion conditions [19].


NOV 2011

Figure 6: Corrosion rates by LPR for 1018 carbon steel when the iron carbonate scale has been

partially or completely removed by the addition of 0.5 wt% sand followed by the addition of

100 ppm inhibitor

Figure 7: Corrosion rates by LPR for 1018 carbon steel where inhibitors has been added after

scale formation as a preemptive measure prior to sand introduction

Figure 8 shows a schematic of the previous studies on effects of sand erosion on inhibitor

effectiveness in E/CRC.


NOV 2011

Figure 8: Previous studies on effect of sand erosion on amidoamine-fatty acid inhibitor

effectiveness in E/CRC.


NOV 2011

OBJECTIVE

The current research is a sponsored project for PETROBRAS Oil and Gas Company. The

main objective of this research is to predict inhibited erosion-corrosion of carbon steel under a set of

laboratory conditions that simulate conditions that oil and gas companies may expect to encounter in

the field. The block diagram shown in Figure 9 provides an overview of this research. It shows

previous, current, and future work and how they relate to each other. In previous research, the

E/CRC developed SPPS:CO2 corrosion model and the SPPS sand erosion model were combined

together to develop the SPPS:E-C prediction model for single phase. Also indicated in the diagram is

current research on expansions of the erosion-corrosion model to draw from past E/CRC research

areas involving chemical inhibition in sand producing wells. PETROBRAS has agreed to make the

results of this research available for extending the current E-C prediction computer program.

Figure 9: Erosion-corrosion prediction research


NOV 2011

APPROACH

• Determine the baseline erosion, corrosion and erosion-corrosion rates in two phase flow

conditions.

• Simulate two-phase flow in a single phase flow loop by selecting flow conditions that

produce the same corrosion rate and erosion rate in the single phase flow loop that were

observed in two-phase flow.

• Determine the corrosion and erosion-corrosion rates for selected concentrations of inhibitor,

and selected ranges of pH, temperature and water cut.

• Develop a model for prediction of erosion-corrosion in the presence of inhibitor, oil and

sand using experimental data and existing inhibitor protection isotherms. A more detail plan

for developing a model for prediction of inhibited corrosion and erosion-corrosion is shown

in Figure 10.

Figure 10: Schematic of E/CRC approach for prediction of inhibited corrosion and erosion-corrosion


NOV 2011

EXPERIMENTAL PROCEDURE

Two Phase Flow Loop (Gas-Liquid Erosion-Corrosion Loop)

Tests in multiphase flow are carried out in an erosion-corrosion loop. A schematic of the flow

loop is shown in Figure 11. The major components of the flow loop are two Corken D490

compressors (each with a maximum capacity of about 30-cfm), a 40-gpm diaphragm pump, a large

separator tank, several heat exchangers and scrubber, and a cyclone separator for separating sand

from the gas-liquid-sand mixture.

Gas from the compressors flows through a heat exchanger and splits into two branches as shown

in Figure 11. One branch leads to the test cell section and the other branch is a bypass going back to

the compressor intakes. Before the gas has reached the test cell, dry sand is added to the system by

means of a vibration driven sand feeder. Downstream of the sand injection point, the liquid is

incorporated into the flow-stream and then the three phases (gas-liquid-sand) flow together in the

test section. Downstream of the test section, sand is separated from the slurry by the cyclone

separator. Sand with some water falls down into the separator to a receiver cylinder where the sand

is collected and removed from the system. Most of the gas- liquid mixture passes through the top of

the cyclone separator and flows into the main tank (gas- liquid separator). Here the gas phase is

separated from the gas-liquid mixture and the liquid flows back to the pump. The gas flows to a heat

exchanger and scrubber to remove any moisture from it before flowing back to the compressors.

Another heat exchanger at the compressor discharge is used to cool the gas before it flows back to

the test section.


NOV 2011

Figure 11: Schematic of gas-liquid erosion-corrosion loop

The Gas-Liquid Erosion-Corrosion loop is capable of producing superficial liquid velocities

up to 15 m/s, and superficial gas velocities up to 110 m/s. The maximum working pressure is 150

psig. The maximum temperature is 200°F. In this loop, erosion and erosion/corrosion tests can be

conducted on horizontal and vertical plugged Tees. A high resolution electrical resistance (ER)

probe (Ceion®) is also used to collect the erosion and erosion-corrosion penetration data, which

permits short test times even in cases where the metal loss rates are expected to be low. The fluid

flow is diverted from the upward vertical direction to the horizontal direction. The actual geometry is

similar to a plugged tee. An E/CRC (Erosion/Corrosion Research Center) designed probe was also

used to estimate penetration rates with the linear polarization resistance (LPR) technique. The probe

was made using an X65 carbon steel LPR configuration inserted into the horizontal branch of a Tee

as shown in Figure 12.


NOV 2011

Figure 12: Schematic of LPR and ER probe position in gas-liquid erosion-corrosion loop

A schematic of the working electrode in combination with reference electrode is shown in

Figure 13. The reference electrode is 0.085 inches in diameter. This reference electrode is

surrounded by ceramic coating which is then surrounded by X65 carbon steel which acts as the

working electrode. The assembly consisting of the reference electrode and the working electrode is

mounted into a phenolic holder for electrical isolation. The counter electrode is the 316L stainless

steel flow loop.

Figure 13: Schematic of Working-Reference electrode


NOV 2011

A picture of the ER probe which is used in this study is shown in Figure 14. The ER probe is

inserted into the vertical Tee for evaluating erosion, corrosion and erosion-corrosion behavior of

X65 carbon steel in multiphase flow condition. Diameter of ER probe was 1 inch.

Figure 14: A picture of ER probe

Single phase flow loop (Mini Loop)

The erosion-corrosion experiments were carried out in a single phase flow loop, which is called

Mini Loop #1, with a direct impingement test cell. The single phase liquid circulated in the loop is

CO2-saturated brine and impinges the carbon steel target at different flow velocities. A schematic of

the Mini loop is shown in Figure 15. The piping of the loop is constructed of 316L stainless steel

material due to its high resistance to corrosion and pitting. The loop is operable at pressures up to

1.13 MPa and at temperatures up to 93°C. The major components of the loop are the test section,

sand/inhibitor injector, cyclone separator, tank and circulation pump. A test solution of 10 gallons

was introduced into the tank whose maximum capacity is 20 gallons and de-aerated using a vacuum

pump in order to remove dissolved oxygen present in the test solution. During a test, the

concentration of oxygen in solution is less than 10 ppb. The test solution was then pressurized with

CO2 for 24 hours.

Epoxy X‐65


NOV 2011

The test solution was circulated in the system using a Wanner Engineering D-20 Hydra-cell

diaphragm pump with a variable speed drive to achieve the desired flow velocity in the range of 9-60

m/s. Direct measurement of the solution flow velocity through the jet nozzle impinging orthogonal

to the test specimen could not be obtained due to the compact size of the test section which prevents

the use of the ultrasonic flow meter. However, the velocities were estimated from the exit pressure

using Bernoulli’s equation. The pressure difference between the total and static pressure was

measured using a straight Pitot-tube and a digital manometer. Two band heaters and a temperature

controller provide accurate temperature control of the Mini loop and test solution. The pH of the test

solution was monitored before and after the tests in the by-pass section between the tank and the

pump using a temperature-compensated pH probe. The pH probe is calibrated prior to each Mini

loop test and corrected for high chloride content. In order to maintain the desired pH of the test

solution, HCl or NaOH was injected into the system as needed by means of a dosing pump.

Figure 15: Schematic of the Mini Loop #1


NOV 2011

Figure 16 shows a schematic of the test cell. Electrochemical measurements are carried out

within the test cell using the test specimen (X65) as the working electrode, a 316 stainless steel rod

as a reference electrode, and the 316L stainless steel test cell casing as the counter electrode. The

0.92 cm diameter jet is placed in alignment with the working electrode such that the jet directly

impacts the center of the circular face of the working/reference electrode. All components are

enclosed in an 11.43 cm × 7.62 cm area. The test cell is sealed with gaskets and clamped to maintain

the system pressure of 2.4 bar.

Corrosion, erosion, and erosion-corrosion measurements are made using different methods

such as weight loss (WL), linear polarization resistance (LPR), Electrochemical Impedance

Spectroscopy (EIS), Potentiodynamic Polarization (PDYN), and 3D profilometer methods. For

weight loss and 3D profilometer, initial and final weights and surface topography of the test

specimen were measured. Before and after each test, the specimen is cleaned with acetone and dried

prior to measurements. LPR measurements utilized a potentiostat operating in the three-electrode

arrangement. Tafel slope for LPR test is measured for each test condition by running

potentiodynamic polarization test and the potential is ramped +5 mV.

Test parameters are summarized in Table 1. All tests in the Mini loop were carried out in a

CO2-saturated environment under non scale-forming conditions. The test solution consists of 18 wt

% NaCl, 1000 ppm NaHCO3, and 50 ppm CaCl2 dissolved in 38 liters of distilled water as indicated

in Table 1. The other major test parameters are a temperature of 57°C and a CO2 pressure of 2.4 bar.

Test parameters are summarized in Table 2. More details about experimental set up and procedure

can be found in Reference [21].


NOV 2011

Figure 16: Test Cell for Electrochemical Measurement in Single Phase Flow Condition

Table 1: Composition of Test Solution

Constituent Composition NaCl 18 % by weight

NaHCO3 1000 ppm CaCl2 50 ppm

Table 2: Parameters for Mini loop – Non-Scale-Forming Conditions

PARAMETERS CONDITIONS

Temperature 57, 93 °C

pH 3.5, 4.8, 5, and 6

Test solution composition 18 % NaCl, 1000 ppm NaHCO3, 50 ppm CaCl2

Flow velocity 9.4 m/s

Gas CO2 2.4 bar

Material tested X65

Geometry Direct Impingement

Average Sand size 150 μm

Measurement techniques Weight loss, LPR, 3D Profilometer, EIS, PDYN

Dissolved Oxygen Less than 10 ppb

Inhibitor Conc. 0, 10, 25, 50, 100, 150, 250


NOV 2011

Results and Discussion

A short review of first part of the project

Baseline two phase flow test conditions were defined as follows: Vsg=24.4 m/s and Vsl=0.61 m/s

and two different values of temperature and pH, 57oC and 4.8 pHactual and 93oC and 5.0 pHactual

respectively. Testing was conducted at these conditions using ER probes and long-term weight loss

probes. At pHactual of 4.8 and temperature of 57oC, corrosion rate is in the range of 522 to 682 mpy

and at pHactual of 5.0 and temperature of 93oC, corrosion rate is in the range of 627 to 766 mpy. There

was good agreement between ER probe test results and long-term weight loss measurements. X-ray

diffraction analysis after corrosion testing showed no iron carbonate scale at either of these test

conditions. High corrosion rate at these test conditions also indicated that that there was no

protective layer on the surface for these test conditions. An electrochemical measurement approach

is not useful for a corrosion study in two phase (gas-liquid) flow, at least for the flow conditions

used in this research.

Erosion-corrosion test results for the two phase flow baseline conditions of Vsg=24.4 m/s and

Vsl=0.61 m/s and two different values of temperature and pH, 57oC and pHactual of 4.8 and 93oC and

pHactual of 5.0 and sand concentration of 30 lb/day were obtained using an ER probe. Erosion-

corrosion rate at these test conditions is in range of 751 to 754 which is very close to the sum of the

erosion rate in pure erosion testing and corrosion rate in pure corrosion testing at the same test

conditions. This means there is no synergistic effect between erosion and corrosion at these test

conditions.

Erosion data for the two phase flow baseline conditions (Vsg=24.4 m/s and Vsl=0.61 m/s and

temperature 93oC in solution containing 18 wt% NaCl) was collected using ER probes and long-term

weight loss probes. Erosion rate for this test condition is in range of 110 and 184 mpy. Erosion test

results in single phase flow loop testing at two different temperatures of 57oC and 93oC are almost

the same as obtained from the two phase flow testing.

The complexity of the two phase flow loop makes this loop not suitable for inhibitor and oil

phase studies. Therefore, Corrosion tests at the same pH’s and temperatures and different flow

velocities were run in a single phase flow loop in order to identify the velocities that produce the

same corrosion rate in the single phase flow loop that were obtained using the two phase flow loop.

Corrosion rate at 12.8 m/s in single phase flow, at pHactual of 5 and temperature of 93oC using


NOV 2011

different methods such as LPR, long-term weight loss and 3D profilometer is about 650 mpy which

is close to the corrosion rate obtained for the two phase flow conditions of Vsg=24.4 m/s and

Vsl=0.61 at the same pH and temperature. The corrosion rate at 12.8 m/s in single phase flow, at

pHactual of 4.8 and temperature of 57oC using LPR, long-term weight loss and 3D profilometer is

about 402 mpy which is close to corrosion rate obtained for the two phase flow condition of

Vsg=24.4 m/s and Vsl=0.61 at same pH and temperature. Therefore, flow velocity of 12.8 m/s was the

single phase flow loop flow speed selected to get a corrosion rate close to the corrosion rate obtained

two phase flow.

In order to study the effect of sand erosion on inhibitor efficiency and because of the limitation

of two phase flow loop for inhibitor studies, it was decided to use the single phase flow loop at the

flow speed and sand concentration that provides the same erosivity in single phase that was obtained

previously in two phase flow. A flow velocity of 12.8 m/s previously was selected in order to get

same corrosion rate in single phase flow and two phase flow. Therefore, the desired erosion rate in

the single phase flow loop must be obtained by adjusting the sand concentration at the 12.8 flow

velocity until the erosion rate in the single phase flow loop matches or is close to the erosion rate

observed for the baseline conditions in two phase flow.

Shear Stress Calculation for Direct Impingement Condition

Shear stress for direct impingement conditions was measured using Phares, et al [22] and

Giralt and Trass [23] equations. Two different flow regions were considered for shear stress

calculation: Laminar flow region which is at the center and turbulent flow region which is away

from the center of specimen. Shear stress profile on the surface of the specimen for two different

flow velocities of 9.4 and 12.8 m/s are shown in Figure 17.


NOV 2011

Figure 17: Shear stress profile on the surface of the specimen at two different velocities of 9.4 and 12.8 m/s (d is the jet diameter and r is the specimen radius)

Inhibitor Performance Characterization:

It is generally accepted that adsorption is the basic mechanism for corrosion protection by

Imidazoline-based inhibitors, and the adsorption depends on the molecule’s chemical composition,

the temperature, and the electrochemical potential at the metal/solution interface. Different inhibitor

adsorption isotherms have been developed for studying the mechanism of corrosion inhibition such

as Flory–Huggins, Frumkin, Temkin, Langmuir, Freundlich, Bockris–Swinkels, Hill–de Boer,

Parsons, Damaskin–Parsons, and Kastening–Holleck. All these isotherms have the general form of

Eq. (1),

/ , 1


NOV 2011

Where H(θ,n) is the configurational factor, which depends upon the physical mode and the

assumptions underlying the derivation of the isotherm, Cinh is the inhibitor concentration, “θ” is the

surface coverage by inhibitor, “f” is an adjustable parameter accounting for the interaction between

adsorbed particles, and “n” may be interpreted as the ratio of the inhibitor molecule coverage to that

of the water molecule.

Inhibitor adsorption isotherms can be developed by corrosion rate measurement for

different inhibitor concentrations. An inhibitor adsorption isotherm is governed by the interaction of

inhibitor particles with the metal surface and by their mutual interaction. One possibility is that the

mutual interaction is negligible, and interaction with the metal substrate is independent of coverage.

In this case, the Langmuir isotherm applies. The Frumkin isotherm can be used when the mutual

interaction of the inhibitor molecules is important [24]. Flory-Huggins, Frumkin, Temkin, and

Langmuir isotherms are used in this research to study the inhibition mechanism, Eq. (2) to (5)

respectively. In this research, the Frumkin isotherm has shown the best fit to the experimental data.

/ 1 2

/ 1 3

/ 4

/ 1 5

Where Ka/d is an adsorption/desorption constant, Cinh is the inhibitor concentration, θ is the

surface coverage by inhibitor, and f is an adjustable parameter accounting for interaction between

adsorbed particles, and “n” may be interpreted as the ratio of the inhibitor molecule area to that of

the water molecule. A negative value for “f” means inhibitor molecules adsorbed on the surface of

the metal attract each other, while a positive value for “f” indicates repulsion among the inhibitor

molecules. Repulsion among inhibitor molecules decreases the inhibition efficiency because it

creates a gap between the inhibitor molecules which provides a good path for the water and

corrosive ions to reach the metal surface. Surface coverage by the inhibitor can be calculated based


NOV 2011

on corrosion rate at different inhibitor concentrations using Eq. (6) or charge transfer resistance data

from EIS test results using Eq. (7).

1 6

1 7

Where θ is surface coverage by inhibitor, (CR)θ is corrosion rate when the metal is protected by

inhibitor, (CR)θ=0 is the corrosion rate when there is no inhibitor in the system, (Rct)θ is the charge

transfer resistance when the metal is protected by inhibitor, and (Rct)θ=0 is the charge transfer

resistance when there is no inhibitor in the system.

The Flory-Huggins adsorption isotherm, Eq. (2), was fitted to the experimental data by

plotting log(θ/Cinh) versus log(1-θ) in order to find the number of water molecules displaced by a

molecule of inhibitor, “n” (Figure 18). Adsorption of the inhibitor on the metal occurs when the

interaction energy between metal and the inhibitor is more favorable than the interaction energy

between the metal and the water molecules. “n” may be interpreted as the ratio of the inhibitor

molecule area to that of the water molecule. As a result, “n” was found to be equal roughly to one

which means that each molecule of Imidazoline based inhibitor studied in this research displaces one

molecule of water on the metal surface. For this type of inhibitor for which n = 1, the Flory-Huggins

isotherm reduces to the Frumkin isotherm.

Figure 18: Flory-Huggins isotherm fitted to experimental data to determine the "n" parameter

y = 1.260x - 0.030R² = 0.970

-3

-2.5

-2

-1.5

-1

-0.5

0

-2 -1.5 -1 -0.5 0

Log(θ/

Cin

h)

Log(θ-1)


NOV 2011

Frumkin, Temkin, and Langmuir inhibitor adsorption isotherms for pure corrosion and erosion-

corrosion tests at temperature of 93oC and pH=5 are shown in Figure 19, Figure 20, and Figure 21

respectively. Surface coverage by the inhibitor for pure corrosion and erosion-corrosion tests were

measured using the weight loss method and Eq. (6). The isotherms were fitted to experimental data

using a least squares method. According to Figure 19, Figure 20, and Figure 21, adding sand to the

system, reduces the inhibitor performance by removing the inhibitor from the metal surface and

decreasing the surface coverage by inhibitor. Sand also, to a lesser extent, reduces the inhibitor

performance by adsorption of inhibitor. The same effect of sand was observed at T=57oC and

pH=4.8.

Figure 19: Frumkin isotherms fitted to normalized weight loss data for pure corrosion and for

erosion-corrosion tests with pure erosion = 4.06 mm/y

0

0.2

0.4

0.6

0.8

1

0.01 0.1 1 10 100

Surf

ace

Cov

erag

e (θ

)

Pure Erosion =0 - Fit

Pure Erosion = 0 - Exp

Pure Erosion = 4.06 mm/y - Fit

Pure Erosion=4.06 mm/y - Exp

Inhibitor Concentration (ppm)

Increasing Erosivity

Pure Corrosion Exp.

Pure Corrosion Fit.

Erosion-Corrosion Exp.

Erosion-Corrosion Fit.


NOV 2011

Figure 20: Temkin isotherms fitted to normalized weight loss data for pure corrosion and

erosion-corrosion tests

Figure 21: Langmuir isotherms fitted to normalized weight loss data for pure corrosion and

erosion-corrosion tests


NOV 2011

Physical adsorption (physisorption) and chemisorptions are principal types of interaction between

an organic inhibitor and a metal surface. The change in adsorption free energy was used to determine

the type of adsorption (Eq. (8)).

/1

55.5∆

8

Where Ka/d is adsorption/desorption constant which can be calculated from the adsorption isotherm.

∆ is the change in Gibbs free energy for the adsorption/desorption process, R is the universal

gas constant, and T is temperature. ∆ values on the order of -20 kJmol-1 or less negative indicate

physisorption which has low activation energy and depends on electrical characteristics of the

organic inhibitors, the position of corrosion potential with respect to zero potential, and the type of

adsorbable anions present in the aggressive solution[25]. ∆ values on the order of -40 kJmol-1 or

more negative indicate chemisorption which involves charge transfer from the inhibitor molecules to

the metal surface and chemical bonding. ∆ values between -20 kJmol-1 and -40 kJmol-1 indicate

physisorption and chemisorptions[26]. Using the Ka/d value from Frumkin isotherm in Eq. (3), ∆

values of the Imidazoline-based inhibitor studied in this research for pure corrosion tests in different

sets of pH, temperature, and water cut are shown in Table 1. The ∆ values on the order of -20

kJ.mol-1 or less negative indicate physisorption of the Imidazoline based inhibitor. A negative value

for Gibbs free energy means that the adsorption of inhibitor onto the metal surface is a spontaneous

process. Imidazoline-based inhibitors containing one or more nitrogen atoms can adsorb to the

metallic surface and can block the active sites thus generating a physical barrier to reduce the

transport of corrosive species to the metal surface[27].


NOV 2011

Table 3: Gibbs free energy calculation for different sets of pH, temperature, and sand

concentration

T(oC) pHact Sand Concentration

(wt%)

∆ (KJ/Mole) Type of adsorption

57 4.8 0 -8.65 Physisorption

93 5 0 -11.02 Physisorption

57 4.8 0.5 -6.74 Physisorption

93 5 0.5 -4.87 Physisorption

In order to study the inhibition mechanism in more detail, EIS was also used. Examples of

EIS Nyquist plots for CO2 corrosion of carbon steel for different inhibitor concentrations are shown

in Figure 22. According to Figure 22, increasing the inhibitor concentration up to 150 ppm increases

the impedance which means that increasing the inhibitor concentration increases the charge transfer

resistance and decreases the corrosion rate. The impedance diagrams shown in Figure 22 are not

perfect semicircles which may be explained by surface heterogeneity due to surface roughness,

impurities, and dislocations [26]. The depressed semicircular shape in the complex impedance

plane, with the center under the real axis, is a typical behavior for solid metal electrodes and shows

frequency depression of the impedance data. Therefore, a Constant Phase Element (CPE) is used to

fit the experimental data rather than an ideal capacitor in order to take into account the non-ideal

frequency response of the displayed data. The equivalent circuit used in this study for interpretation

of EIS data is shown in Figure 23. An excellent fit with the model was obtained for all experimental

data. The fit follows the same pattern as the experimental results. By analysis of impedance spectra,

main parameters including Rct, Yo, and “a” at different inhibitor concentrations were obtained and

listed in Table 4. In Table 4, the double layer capacitance Cdl was calculated by Eq. (9):

. / 9


NOV 2011

Where Yo and “a” are CPE parameters. The parameter “a” of the CPE is an indicator of electrode

surface roughness or heterogeneity and the parameter “Yo” is considered to be the CPE admittance.

Inhibition efficiency in Table 4 was calculated according to Eq. (10). According to Table 4,

inhibition efficiency increases as inhibitor concentration increases.

% 100 10

Figure 22: EIS Nyquist graphs of erosion-corrosion test results for different inhibitor

concentrations

0

30

60

90

120

150

0 30 60 90 120 150

0 ppm inh10 ppm inh25 ppm inh100 ppm inh250 ppm inh

‐Zim

ag (Ω

cm

2 )

‐Zreal (Ω cm2)


NOV 2011

Figure 23: Equivalent Circuit for Analysis EIS Data

Table 4: Circuit Parameters for Different Inhibitor Concentration

Inhibitor

Concentration

(ppm)

Rs

(Ω cm2)

Rct

(Ω cm2)

Yo

(Ω-1 cm-2 sn × 104)

a

0 0.377 22.35 18 0.869

10 0.328 75.47 4.79 0.825

25 0.412 78.36 4.57 0.806

100 0.0237 101.8 7.33 0.701

250 .0215 136.7 9.86 0.657

At the start of the test there was an inductive loop in the EIS Nyquist graph; but after 24 hrs it

disappeared (Figure 24). The reason for the change is that immediately after adding inhibitor to the

solution, the replacement of water molecules by inhibitor molecules was the controlling process; but,

after about 24 hours the cumulative adsorption of inhibitor on the metal surface was sufficiently high

that adsorption was no longer the controlling mechanism. This statement is supported by the

disappearance of the inductive loop.


NOV 2011

Figure 24: EIS Nyquist diagrams for corrosion test in solution containing inhibitor at the start

of the test and after 24 hours

Figure 25 shows potentiodynamic polarization curves for different inhibitor concentration at T=93oC

and pH=5. Based on Figure 25, adding inhibitor to the system shifts both the cathodic and anodic

branches of the polarization curve to the lower current densities. Therefore, the Imidazoline based

inhibitor used in this study decreases both cathodic and anodic corrosion reactions by blocking the

active sites of cathodic and anodic reactions on the metal surface and consequently decreases the

corrosion rate.


NOV 2011

Figure 25: Potentiodynamic polarization curves for different inhibitor concentration at

T=93oC and pH=5

Effect of Oil on CO2 Corrosion behavior

Different techniques (LPR, EIS, PDYN, WL, and 3D profilometer) were used to study the effect of

oil on CO2 corrosion behavior. At T=57oC and pH=4.8, adding oil to the system (60% Oil Cut)

slightly reduces the corrosion rate by decreasing the water wetted surface area of the specimen. Oil

also decreases the solution conductivity which decreases the corrosion rate. Table 5 shows average

of four corrosion tests at two different water cuts using different electrochemical and non-

electrochemical techniques. Agreement of electrochemical techniques with non-electrochemical

techniques suggest that electrochemical measurement techniques in 40% water cut with light oil can

be used reliably.


NOV 2011

Table 5: Average corrosion test results at two different water cuts at T=57oC and pH=4.8

Water Cut (%)

C.R. (mpy)

LPR W.L. 3D profile

100 505 456 458

40 422 416 433

At T=93oC and pH=5.0, LPR, EIS, and weight loss measurement after several tests showed that

adding oil to the system considerably reduces the corrosion rate (Figure 26 and Figure 27). Scanning

Electron Microscopy (SEM), X-Ray Diffraction (XRD), and Energy Dispersive Spectroscopy (EDS)

analysis of the surface of the specimen after the corrosion test at 40% water cut showed that iron

carbonate scale had formed on the surface of the specimen (Figure 28, Figure 29, and Figure 30).

Figure 26: LPR and weight loss corrosion test results at T=93oC and pH=5.0 for 40 and 100% water cut


NOV 2011

Figure 27: EIS corrosion test results at T=93oC and pH=5.0 for 40 and 100% water cut

Figure 28: SEM image of the surface after the corrosion test at 40% water cut and at T=93oC and pH=5.0


NOV 2011

Figure 29: XRD analysis of the surface after the corrosion test at 40% water cut and at T=93oC and pH=5.0

Figure 30: EDS analysis of the surface after the corrosion test at 40% water cut and at T=93oC and pH=5.0

Effect of Oil on Inhibitor Performance in CO2 Systems

Different techniques (LPR, EIS, PDYN, WL, and 3D profilometer) were used to study the effect of

oil on CO2 corrosion inhibition. EIS, PDYN, LPR, and weight loss measurement results at T=57oC

and pH=4.8 and inhibitor concentrations of 0, 10, 25, 50, 100, 150, and 250 ppm showed that adding

inhibitor to the system decreases the CO2 corrosion rate. Figure 31 shows weight loss corrosion test

results for different inhibitor concentration at T=57oC and pH=4.8 at two different water cuts. As it

can seen in Figure 31 when inhibitor concentration is zero, adding oil to the system decreases the

CO2 corrosion rate but at higher inhibitor concentrations adding oil to the system increases the

corrosion rate by reducing the inhibition efficiency. Inhibitor residual concentration measurement


NOV 2011

using standard method for Imidazoline based inhibitor concentration measurement showed that 10%

of inhibitor added to the system dissolves in the oil phase for PETROBRAS test condition.

Therefore, oil decreases the inhibition efficiency by dissolving the inhibitor in the oil phase. Some of

the inhibitor also stays in the water/oil interface in the emulsion which decreases the inhibitor

concentration in the water phase and consequently decreases the inhibition efficiency. Frumkin

isotherm also was fitted to the experimental data (Figure 32) to show the effect of oil on inhibition

efficiency.

Figure 31: weight loss corrosion test results at T=57oC and pH=4.8 at two different water cuts and seven different inhibitor concentrations


NOV 2011

Figure 32: Frumkin isotherm fitted to experimental data at T=57oC and pH=4.8 at two different water cuts and seven different inhibitor concentrations

Prediction of Inhibited Corrosion

The Frumkin isotherms for different sets of pH and temperature with and without sand were used in

order to predict the inhibited CO2 corrosion rate as a function of inhibitor concentration. These

isotherms were used to calculate the surface coverage by the inhibitor or percent of area exposed to

corrosion that is protected by the inhibitor. Then, a mechanistic model for prediction of CO2

corrosion rate (i.e. SPPS1:CO2) was used to calculate the electrochemical parameters such as

electrochemical reaction rate constants, mass transfer constants, corrosion potential and etc. Percent

area that is protected by the inhibitor was integrated into the mechanistic model to reduce the active

surface area. The mechanistic model then predicts the inhibited corrosion rate based on the

remaining unprotected area. The Frumkin isotherm was not applied to the mass transfer reaction

because potentiodynamic polarization test results show that the corrosion reaction is not diffusion

1 Sweet Production Pipe Saver:CO2 (SPPS:CO2), Erosion/Corrosion Research Center, The University of Tulsa, OK, USA


NOV 2011

controlled. Therefore, charge transfer controls the corrosion reaction and there is no need to modify

the mass transfer equations in the mechanistic model for prediction of CO2 corrosion rate.

Corrosion rate prediction using the mechanistic model for prediction of CO2 corrosion rate shows

good agreement with experimental data at two different sets of pH and temperature with and without

sand for the range of inhibitor concentration between 0 and 250 ppm (Figure 33).

Figure 33: Comparison between experimental corrosion data and prediction of CO2 corrosion rate using a mechanistic model after integrating the Frumkin isotherm for different inhibitor

concentrations (With and without sand)

Effect of oil, temperature and pH are also included in corrosion rate prediction using the mechanistic

model for prediction of CO2 corrosion rate. Prediction of CO2 corrosion rate shows good agreement

with experimental data at four different sets of pH and temperature with and without oil for the range

of inhibitor concentration between 0 and 250 ppm. Figure 34: Comparison between experimental

corrosion data and prediction of CO2 corrosion rate using a mechanistic model after integrating the

Frumkin isotherm for different inhibitor concentrations (With and without oil at T=57oC and

1

10

100

1000

1 10 100 1000

Cor

rosi

on R

ate

Pred

ictio

n (m

py)

Corrosion Rate by Experiment (mpy)

T=57C, pH=4.8, No SandT=93C, pH=5, No SandT=57C, pHact=4.8, 0.5wt% SandT=93C, pHact=5, 0.5wt% Sand

015

10

25

150

100

250

0

15

10

25

50

50

100


NOV 2011

pH=4.8)Figure 34 Shows the effect of oil at T=57oC and pH=4.8 and Figure 35 shows the effect of

pH and temperature.


concentrations (With and without oil at T=57oC and pH=4.8)


NOV 2011


concentrations (without sand at four different sets of temperature and pH)

Effect of Sand Erosion on Inhibitor Performance:

Tests with an inhibitor were carried out in order to determine the level of protection the inhibitor can

provide to the metal when sand is being produced. Figure 36 and Figure 37 show the effect of

inhibitor concentration on erosion-corrosion metal loss rate (measured using WL method), the

corrosion part of erosion-corrosion (measured using LPR method), and the erosion part of erosion-

corrosion (calculated as WL minus LPR) at a temperature of 93oC, pH of 5.0, and flow velocity of

9.4 m/s. According to Figure 37, by increasing the inhibitor concentration in the solution, erosion-

corrosion and both of its parts are reduced with a logarithmic trend. For conditions within the bounds

of the experimental conditions tested in this research, these logarithmic relations can be used for

prediction of inhibited erosion-corrosion rate as a function of inhibitor concentration.

At pHact=5 and T=93oC, when there was no inhibitor in the system, the erosion-corrosion rate was

12.9 mm/yr which is smaller than the summation of the pure corrosion rate (i.e., average value of

25.9 mm/yr) and the pure erosion rate (i.e., average value of 4.14 mm/yr). The corrosion part of

erosion-corrosion for these test conditions measured with LPR (i.e., average value of 9.4 mm/yr) and

the erosion part of erosion-corrosion (i.e. average of 3.5 mm/yr) are smaller than the pure corrosion


NOV 2011

and the pure erosion rates, respectively. Visual inspection of specimen after the pure corrosion test

showed that there was some loose black powder on the surface of the specimen identified as iron

carbide. Typically, higher corrosion rates are observed in pure corrosion test when iron carbide

accumulates on the surface of the specimen than when iron carbide does not form. Iron carbide

accumulation on the surface of the metal at low flow velocity and low shear stress increases cathodic

reaction rates by galvanic corrosion. In these cases sand particle erosion removes the iron carbide

film from the surface of the metal, thus keeping the corrosion rate lower as compared to the

corrosion rate obtained without sand.

Erosion-corrosion test results by Dave et al. at higher flow velocity (i.e. 12.8 m/s) and higher shear

stress showed that the erosion-corrosion rate was higher than the summation of the pure corrosion

and the pure erosion rate [13]. Visual inspection of the specimen after the pure corrosion testing at

Dave’s test conditions indicated that there was no iron carbide on the surface, even without sand.

This is because the shear stress on the surface of the specimen was strong enough to remove the

carbide film from the surface. In Dave’s case, erosion accelerated the corrosion rate. Corrosion can

also accelerate the erosion rate. An increase in surface roughness by erosion can intensify the

corrosion processes by increasing the surface area of the specimen subjected to corrosion. Surface

roughness also increases the corrosion rate because electron density in the indentations of the surface

is higher and the higher density of electrons causes higher corrosion rate. Corrosion may also

accelerate the erosion rate by creating a favorable surface roughness for ductile erosion processes.

The erosion part of erosion-corrosion can be thought of as having two components: a) pure erosion,

and, b) erosion affected by corrosion. Likewise, the corrosion part of erosion-corrosion has two

components: a) pure corrosion, and, b) corrosion affected by erosion. Adding 25 ppm or more

inhibitor to the system changes the synergy between erosion and corrosion. Post-test visual

inspection of the specimen showed that in pure corrosion testing with 25 or more ppm inhibitor, no

iron carbide layer formed on the surface of the specimen. When inhibitor concentration was 25 ppm

or more the corrosion rate was low; therefore, accumulations of iron carbide on the metal surface

were prevented by the shear stresses generated by the flowing fluid. For these conditions, adding

sand to the flow did not decrease the corrosion rate because the presence of the inhibitor prevented

iron carbide accumulation.

Corrosion in these experiments did not accelerate the erosion rate very much, which means that the

erosion affected by corrosion component was very small. The hatched area in Figure 37 shows the

magnitude of erosion affected by corrosion for different inhibitor concentrations at a temperature of


NOV 2011

93oC and pH=5. On the other hand, in the inhibited system, erosion accelerated the corrosion rate by

a factor of about two by removing the inhibitor protective layer from the surface and also, to a lesser

extent, by adsorption of inhibitor molecules onto sand particles. Dave et al. showed that at a higher

flow velocity (12.8 m/s), sand erosion accelerated the corrosion rate by a factor of about three which

means that the higher erosivity reduced the inhibition efficiency [13].

Figure 36: Erosion-corrosion rate, erosion part of erosion-corrosion and corrosion part of

erosion-corrosion versus Inhibitor concentration at T=93oC, pH=5, and flow velocity of 9.4

m/s.


NOV 2011

Figure 37: Effect of inhibitor concentration on erosion-corrosion rate and its components at T=93oC,

pH=5, and flow velocity of 9.4 m/s.

Figure 38 and Figure 39 show the effect of inhibitor concentration on erosion-corrosion, the erosion

part of erosion-corrosion, and the corrosion part of erosion-corrosion at a temperature of 57oC, pH

actual of 4.8, and flow velocity of 9.4 m/s. Erosion-corrosion behavior at a temperature of 57oC, and

pH actual of 4.8 was found to be very similar to erosion-corrosion behavior at a temperature of 93oC

and pH actual of 5. Increasing the inhibitor concentration decreased the erosion-corrosion rate and

the corrosion part of erosion-corrosion. The erosion affected by corrosion (i.e. the hatched area in

Figure 39) was found to be very small as compared with the erosion-corrosion rate for all inhibitor

concentrations.

When there was no inhibitor in the system, the erosion-corrosion rate (8.79 mm/yr) again was

smaller than the summation of the pure corrosion rate (12.8 mm/yr) and the pure erosion rate (4.14

mm/yr). Also, the erosion part of erosion-corrosion (0.46 mm/yr) and the corrosion part of erosion-

corrosion (8.33 mm/yr) were smaller than the pure erosion and the pure corrosion rates respectively.

Without sand or inhibitor in the system, formation of iron carbide films caused corrosion rates to

increase significantly at this lower temperature of 57oC, and pH actual of 4.8 just as they had for a

y = -0.90ln(x) + 10.86R² = 0.994

y = -1.24ln(x) + 7.534R² = 0.979

0

3

6

9

12

15

0 50 100 150 200 250 300

Met

al L

oss

Rat

e (m

m/y

)

Inhibitor Concentration (ppm)

Erosion-Corrosion (E-C)

Erosion Part of Erosion-Corrosion (EPE-C)

Corrosion part of Erosion-Corrosion (CPE-C)

Pure Erosion


NOV 2011

temperature of 93oC, and pH actual of 5. The presence of sand or of 25 ppm or more of inhibitor

prevented the iron carbide film from accumulating.

Figure 38: Erosion-corrosion rate, erosion part of erosion-corrosion and corrosion part of

erosion-corrosion versus inhibitor concentration at T=57oC and pH=4.8


NOV 2011

Figure 39: Effect of inhibitor concentration on erosion-corrosion rate and its components at

T=57oC and pH=4.8

Prediction of Inhibited Erosion-Corrosion:

In order to predict the inhibited erosion-corrosion rate, erosion-corrosion is considered to consist of

two parts, the erosion part of erosion-corrosion and the corrosion part of erosion-corrosion (Eq.

(11)). The erosion part of erosion-corrosion has two components, pure erosion and erosion affected

by corrosion. Pure erosion can be predicted using an available mechanistic model for prediction of

erosion rate (i.e. SPPS2 model). The erosion affected by corrosion component is much smaller than

the inhibited erosion-corrosion rate for the test conditions of this study (Figure 37 and Figure 39).

Therefore, as a practical consideration, the erosion affected by corrosion component can be

neglected for these test conditions: with this simplification, the erosion part of erosion-corrosion can

be considered to be equal to the pure erosion rate.

The corrosion part of erosion-corrosion is a function of inhibitor concentration and can be predicted

based on the available Frumkin inhibitor adsorption isotherms. But the Frumkin adsorption isotherm

2 Sweet Production Pipe Saver (SPPS), Erosion/Corrosion Research Center, The University of Tulsa, OK, USA


NOV 2011

has to be modified somewhat in order to include erosivity as a factor in predicting the corrosion part

of erosion-corrosion.

11

Surface coverage data versus inhibitor concentration for different sets of temperature and pH

without any sand erosion is shown in Figure 40. Figure 40 shows that inhibitor performance for the

different sets of temperature and pH studied in this research can be described approximately by the

same isotherm. Changing pH from 3.5 to 6.0 did not have a significant effect on the surface coverage

data for different inhibitor concentrations, which means that pH did not affect the inhibitor

performance very much for the test conditions of this study. Therefore, Ka/d equal to 0.7451 and f

equal to -1 were found to be the best-fit values for the Frumkin isotherm constants over the range of

temperatures from 57 to 93oC and the range of pH from 3.5 to 6.0 for pure corrosion conditions (i.e.

without sand).

Figure 40: The Frumkin isotherm at the range of temperature of 57 to 93oC and the range of

pH 3.5 to 6 for pure corrosion condition (i.e. without sand)


NOV 2011

As mentioned earlier, the Frumkin isotherm has two constants: adsorption/desorption constant,

“Ka/d”, and mutual interaction of inhibitor molecules constant, “f” (Eq. (3)). In the derivation of Ka/d

[28], Ka/d is an exponential function of the entropy change occurring over the adsorption process (Eq.

(12)).

/ ∆

12

Where, Ka/d is adsorption/desorption constant, ΔSads is adsorption entropy change, and R is the

universal gas constant. Entropy is an expression of disorder, or randomness, in the system. Sand

erosion and increasing the temperature also cause disorder in the adsorption/desorption process of

inhibitor on the surface. Therefore, sand erosion and temperature change the entropy of the system

and consequently also change Ka/d. It is assumed for the prediction method presented here that sand

erosion and temperature affect the adsorption/desorption constant; but, they do not have a significant

effect on the constant f representing the mutual interaction of inhibitor molecules.

An expression shown in Eq. (13) for the adsorption/desorption constant was written as a function of

erosion rate and temperature based on experimental data for two values of temperature and three

values of erosivity from original research presented in this paper and from the work described by

Dave et al. [13] .

/ 1 ∆ 13

Where Ko, K1, K2, and K3 are constants having the following values: K0 = 0.745, K1 = -0.154, K2 =

0.009, and K3 = 0.008. ER in Eq. (13) is erosion rate in mm/yr, and the temperature increment, ΔT =

T°C – 57. Substituting Eq. (13) for Ka/d into Eq. (3) yields a Frumkin isotherm modified to include

effects of temperature and sand erosion, Eq. (14).


NOV 2011

1 ∆1

14

From Eq (14), when there is erosion, increasing the temperature decreases the value of Ka/d, which

means in order to achieve the same surface coverage and inhibition efficiency at higher temperature,

more inhibitor has to be added to the system. Increasing the temperature increases the disorder in the

system and consequently increases the entropy. Furthermore, increasing the entropy decreases the

adsorption/desorption constant; with lower Ka/d a greater inhibitor concentration is needed in order to

get the same surface coverage or inhibition efficiency based on the Frumkin adsorption isotherm.

Therefore, the effect of temperature on inhibition efficiency can be explained similar to the effect of

erosivity by changing the entropy of the system. Experimental data showed that the effect of

temperature on inhibition in the range of 57 to 93oC is small when there is no sand in the system but

adding sand to the system makes the effect of temperature more important. This behavior shows that

there is a synergistic effect between temperature and sand erosion which causes more disorder in the

system and increases the entropy of the system and consequently decreases the inhibition efficiency.

The modified Frumkin isotherm developed in this study can be used to predict the inhibited erosion-

corrosion rate in the temperature range 57 to 93°C and different erosion rates. Experimental data and

prediction of inhibited erosion-corrosion rate at pH of about 5, erosion rate of 4.06 mm/y and for two

different temperatures, 57 and 93oC, are shown in Figure 41 and Figure 42, respectively.


NOV 2011

Figure 41: Prediction of inhibited erosion-corrosion rate using mechanistic models for pure

erosion and pure corrosion and modified Frumkin isotherm at T=57oC

Figure 42: Prediction of inhibited erosion-corrosion rate using mechanistic models for pure

erosion and pure corrosion and modified Frumkin isotherm at T=93oC


NOV 2011

The Frumkin isotherm using the modified Ka/d shows good agreement with the experimental data in

this research for different erosion rates and different temperatures. Inhibited erosion-corrosion rate

was also predicted for different inhibitor concentrations using the mechanistic models for pure

erosion and pure corrosion together with the modified Frumkin isotherms over a range of erosion

rates and temperatures

CONCLUSIONS

In erosion-corrosion with 0.5% sand under the 9.4 m/s direct impingement of a CO2

saturated NaCl solution, the inhibitor appears to be very effective in reducing the corrosion part of

erosion-corrosion, although not quite as effective as for similar tests without sand. Sand erosion

reduces the inhibitor efficiency by partially removing the inhibitor protective layer from the surface

and also, to a lesser extent, by the adsorption of inhibitor on sand. Erosion-corrosion and the

corrosion part of erosion-corrosion showed roughly logarithmic relations with inhibitor

concentration for the conditions tested in this study. Flow loop experimental results showed that the

Imidazoline-based inhibitor used in this research physically adsorbs on the metal surface. The Flory-

Huggins adsorption isotherm fitted to experimental data showed that each molecule of the inhibitor

displaces one molecule of water on the metal surface during adsorption process. The inhibitor was

not very effective in reducing pure erosion for the conditions tested.

Adding oil to the system at T=57oC and pH=4.8 slightly reduced the CO2 corrosion rate by

decreasing the water wetted surface area and also by decreasing the conductivity of the solution; but

at T=93oC and pH=5.0 adding oil to the system considerably reduces the CO2 corrosion rate by

forming iron-carbonate scale on the surface of the specimen. Adding oil to the system also decreased

the inhibition efficiency at T=57oC and pH=4.8 by reducing the inhibitor concentration in the oil

phase since some of the inhibitor dissolves in the oil phase and some inhibitor also stays in the

water/oil interface in the emulsion.

Integration of the Frumkin adsorption isotherm into a mechanistic model for prediction of

CO2 corrosion showed good agreement with experimental inhibited corrosion data. The pH of the

solution was found not to have a strong effect on inhibition for the test conditions studied in this

research over the range of pH 3.5 to 6. In the absence of erosion, inhibitor performance for all sets of

temperature and pH studied in this research can be described approximately by the same isotherm.


NOV 2011

An original approach was suggested for prediction of inhibited erosion-corrosion rate as a

function of erosivity and inhibitor concentration. In this approach, in order to predict the inhibited

erosion-corrosion, erosion affected by corrosion is assumed to be negligible for the conditions tested

in this study and the Frumkin inhibitor adsorption isotherm was modified to include the effects of

erosivity and temperature using experimental data and basic concepts in developing the Frumkin

isotherm. It was also assumed that mutual interaction of inhibitor molecules is not affected much by

sand erosion. For a range of temperature, pH and erosivity conditions, inhibited erosion-corrosion

rate prediction for different inhibitor concentrations shows good agreement with experimental

results.

PROPOSED FUTURE WORK

To continue this research, effects of oil on erosion, corrosion and erosion-corrosion behavior

of carbon steel in CO2 saturated system will be studied in the different pH, temperature and flow

conditions examined in preliminary tasks. In addition, a relation between inhibitor concentration and

corrosion rate will be investigated using adsorption isotherms and experimental data. Furthermore,

the effects of oil and chloride concentration on erosion-corrosion behavior will be studied using flow

loop tests. Finally, the effect of sand production on inhibitor performance in water and oil will be

investigated in different erosivity conditions: based on experimental data and available adsorption

isotherms a model will be developed for predicting erosion-corrosion.

DELIVERABLES

The main deliverable of this research will be a model and computer program as a design tool

for prediction of safe operating condition in presence of sand, oil, high chloride concentration, and

inhibitor in CO2 saturated systems. In addition, this research will provide increased understanding of

the relationships between inhibitor performance and different parameters such as erosivity, water

cut, temperature, pH, and chloride concentration.


NOV 2011

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inhibitor effectiveness on co corrosion with oil and … · 2011. 11. 8. · corrosion has an...

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