Doctor of Philosophy (PhD), Ohio University, 2020, Chemical Engineering (Engineering and Technology)

The produced fluids from oil and gas wells usually contain a considerable amount of carbon dioxide (CO2). Although CO2 itself is not a corrosive agent, its hydrated form, carbonic acid (H2CO3) is involved in corrosion processes. CO2 corrosion, also known as “sweet corrosion”, is by far the most common type of corrosion encountered in upstream pipelines of the oil and gas industry. Despite its susceptibility to corrosion, low carbon steel (mild steel) is widely used in the oil industry because of its availability and cost-effectiveness. Understanding the corrosion behavior of mild steel in oilfield conditions and applying appropriate mitigation programs are crucial to enhance the lifespan of upstream infrastructures. Iron (II) carbonate (FeCO3) is the main corrosion product in CO2 corrosion of mild steel. An FeCO3 layer can protect the steel from rapid corrosion by acting as a diffusion barrier to relevant species for cathodic reactions and by covering portions of the steel surface and retarding the iron dissolution (anodic) reaction. The aqueous phase co-produced with the hydrocarbon phase, known as “brine”, usually contains a high concentration of calcium ions (Ca2+) and magnesium ions (Mg2+). Ca2+ and Mg2+ can incorporate into the FeCO3 lattice and form a substitutional solid solution with different physiochemical characteristics compared to pure FeCO3. This phenomenon happens because FeCO3 (siderite), CaCO3 (calcite), and MgCO3 (magnesite) share the same hexagonal crystal structure. Over the past decades, mechanisms of CO2 corrosion of mild steel and the characteristics of its corrosion products (FeCO3 and Fe3C) have been intensively studied and documented by different researchers. However, most of these studies have been performed in various dilute solutions of sodium chloride (NaCl), while Ca2+ and Mg2+ are also present in most geological formations. Additionally, the limited available literature is contradictory about the true effect of Ca2+ and Mg2+ (open full item for complete abstract)

Committee: Marc Singer (Advisor); Srdjan Nesic (Committee Member); Jason Trembly (Committee Member); Travis White (Committee Member); Lauren McMills (Committee Member); David Young (Committee Member) Subjects: Chemical Engineering; Materials Science

Doctor of Philosophy (PhD), Ohio University, 2023, Chemical Engineering (Engineering and Technology)

Internal corrosion of transmission tubulars is a huge concern in the oil and gas industry. Corrosion inhibitors (CIs) are often considered the first step in mitigating internal corrosion due to their high efficiency and cost-effectiveness. Yet, predicting the efficiency of corrosion inhibitors, developed and tested in a laboratory environment, in operating field conditions is very challenging. In addition, the presence of corrosion residues or corrosion products on the internal surface of tubular steels can significantly affect the inhibition performance of organic corrosion inhibitors. This aspect is only rarely considered when characterizing the performance of corrosion inhibitors. Therefore, understanding their effects on corrosion inhibition is of great benefit in applying corrosion inhibitors to tackle internal corrosion issues, particularly in aging pipelines. This work mainly focuses on evaluating the corrosion inhibition and revealing the inhibition mechanisms in the absence and presence of various corrosion residues or products, commonly found in oil and gas production. The first half of this work (Chapter 5 and 6) presents a methodology for the characterization of corrosion inhibitors and proposes several innovations to an inhibition prediction model, originally based on the work of Dominguez, et al.. An inhibitor model compound, i.e., tetradecyl phosphate ester (PE-C14), was synthesized in-house and characterized to obtain necessary parameter values required as inputs for the inhibition model. The updated inhibition model could predict steady state and transient corrosion inhibition behaviors with good accuracy. The second half of the presented work (Chapter 7, 8, and 9) focuses on the effects of corrosion residue (Fe3C) and products (FeCO3 and FeS) on corrosion inhibition and advances the understanding of the associated inhibition mechanisms. The galvanic effect caused by residual Fe3C on corrosion rate and inhibition efficiency was quantitatively (open full item for complete abstract)

Committee: Marc Singer (Advisor); Srdjan Nesic (Committee Member); David Young (Committee Member); Sumit Sharma (Committee Member); Katherine Cimatu (Committee Member); Katherine Fornash (Committee Member) Subjects: Chemical Engineering; Engineering; Materials Science

Doctor of Philosophy (PhD), Ohio University, 2021, Chemical Engineering (Engineering and Technology)

One of the most challenge issues in oil and gas industry is the corrosion of pipeline materials caused by carbon dioxide (CO2) and hydrogen sulfide (H2S). The precipitation of corrosion product layers, their characteristics, composition, and kinetics, play a key role in governing corrosion behaviors. The present project is focused on one key aspect in understanding and modeling the effect of surface layers: the investigation of the precipitation kinetics of corrosion product on carbon steel, the most preferred construction material in the field. The study focuses as well on brines containing high concentrations of dissolved NaCl, a situation also commonly encountered in the oil and gas industry. The first part of the project aims at improving the accuracy in the determination of species concentration in CO2 and H2S aqueous environments. The consumption of ferrous ions due to the presence of chloride ions was addressed. Several expressions related to H2O/CO2 and H2O/H2S equilibrium speciation were updated based on literature data. A previously well accepted expression for iron carbonate (FeCO3) solubility limit was re-calibrated against experimental data to better account for salt concentration effects. A methodology was developed for using Electrochemical Quartz Crystal Microbalance (EQCM) for the study of precipitation kinetics of both iron carbonate and iron sulfide (FeS), as EQCM is a technique providing very accurate in-situ measurement of surface mass change. Repeatable and consistent precipitation rates of FeCO3 obtained via the EQCM across different substrates, temperatures, and sodium chloride (NaCl) concentrations suggest that increasing NaCl from 1 wt.% to 9 wt.% did not change the precipitation rate significantly. Based on the measurements, a kinetics model was proposed to describe the FeCO3 precipitation rate in CO2 environments with varied NaCl concentrations. For FeS, the inherent complexity of the system limited the scope of the (open full item for complete abstract)

Committee: Marc Singer (Advisor); Srdjan Nesic (Committee Member); Katherine Fornash (Committee Member); Howard Dewald (Committee Member); John Staser (Committee Member) Subjects: Chemical Engineering

Doctor of Philosophy, The Ohio State University, 2019, Materials Science and Engineering

Corrosion of carbon steel exposed to aqueous environments containing dissolved carbon dioxide (CO2) and hydrogen sulfide (H2S) is responsible for many failures of equipment and pipelines in the oil and gas industry. Corrosion product films, e.g., iron carbonate (FeCO3) and iron sulfide (FexSy), play a major role in enhancing localized corrosion after breakdown of these films by either mechanical or chemical means. This has been attributed to galvanic effects driven by the difference in open circuit potential (OCP) between steel covered by FeCO3 or FexSy and bare uncovered areas. Upon localized breakdown of the films, a galvanic current flows between the bare metal areas (anodes) and the areas covered with FeCO3 or FexSy (cathodes). Although many studies have evaluated these galvanic effects, there are still some questions remaining related to the cathodic nature of corrosion product films and their role in enhancing localized corrosion. The present study focused on the evaluation of galvanic interactions of iron (Fe) in CO2 and CO2/H2S environments. The corrosion rate and OCP were measured over time for samples under various conditions, corrosion products on those samples were characterized, and galvanic currents were measured between samples exposed to different conditions. The test conditions were selected to favor the formation of protective films. Fe and steel samples were immersed in 1% NaCl saturated with 100% CO2 or 0.1, 1, 10% H2S/balance CO2. The pH of the bulk solution was adjusted to values between 6 and 8, while the temperature was controlled between 20°C and 80°C. Corrosion product layers were characterized using scanning electron microscopy, energy-dispersive X-ray spectroscopy and X-ray photoelectron spectroscopy. The galvanic interactions were measured using a modified split cell that allowed customization of different environments in each of the half cells, along with simultaneous monitoring of the galvanic current and driving force as indicated by (open full item for complete abstract)

Committee: Gerald Frankel Dr. (Advisor); Jenifer Locke Dr. (Committee Member); Narasi Sridhar Dr. (Committee Chair); Jose Vera Dr. (Committee Chair) Subjects: Materials Science

Master of Science (MS), Ohio University, 2017, Chemical Engineering (Engineering and Technology)

Iron carbonate (FeCO3) is the commonest corrosion product that forms on the surface of mild steel as a by-product of the CO2 corrosion process. This FeCO3 layer slows down further corrosion by acting as a diffusion barrier, blocking corrosive species from reaching the steel surface. However, high flow velocities, which can be common in various industrial operations, have been postulated either to lead to partial mechanical removal of FeCO3 layers or to impede the nucleation of FeCO3 crystals on the steel surface altogether. In the experimental study described herein, corrosion product formation in highly turbulent conditions was investigated with surface analysis techniques. Experiments were divided in relation to three different sets of tasks focusing on high initial saturation values, low and constant saturation values, and high velocity experiments. The first set of experiments was performed in a three electrode glass cell and rotating cylinder setup and investigated the presence/attachment/adherence of FeCO3 on the steel surface in short term experiments with high initial saturation values (S(FeCO3) = 150). The aim was to study the precipitation of FeCO3 in conditions where the bulk solution has a high concentration of ferrous ions at continuous rotational speeds, from the start to the end of each experiment. It was found that as the fluid velocity increased, there was less attachment of FeCO3, with the highest velocity of 2.0 m/s (wall shear stress of 7 Pa) showing no FeCO3 formation/attachment on the metal surface. The second task focused on controlling the pH and ferrous ion concentration in solution, in order to better mimic actual field conditions. Additionally, a controlled mass transfer setup was utilized that eliminated any non-uniformity of flow and centrifugal forces often associated with rotating cylinder working electrodes. In this set of experiments, four different materials and/or microstructures were tested, namely pure Fe (99.8%), UNS G101 (open full item for complete abstract)

Committee: Marc Singer (Advisor); Srdjan Nesic (Committee Member); Reza M. Toufiq (Committee Member); Craig Grimes (Committee Member) Subjects: Chemical Engineering

Doctor of Philosophy (PhD), Ohio University, 2016, Chemical Engineering (Engineering and Technology)

Degradation of metals associated with hydrocarbon production, combustion processes, and carbon capture is a pernicious problem in the energy sector. Consequently, laboratory simulation of CO2-containing aqueous environments is of vital importance for the study of steel corrosion. However, discrepancies between predicted, experimental, and field corrosion rate data in a midrange of operating parameters have been reported. These discoveries necessitate improving the accuracy of corrosion prediction models. Based upon preliminary experiments, iron carbonate formation near its saturation condition was identified as a major factor observed corrosion rate discrepancies. Therefore, it is imperative to conduct a systematic study to gain more understanding of corrosion product layer formation mechanisms in controlled water chemistry conditions. Small scale CO2 corrosion experiments have lacked control of pH and ferrous ion concentration, potentially creating misleading conditions related to the growth of protective iron carbonate (FeCO3). An improved experimental apparatus to study steel corrosion and associated formation of FeCO3 was developed. The design incorporates a flow-through system, enabling control of water chemistry, and newly developed sample holders that eliminate non-uniformity of flow associated with hanging samples as well as centrifugal effects associated with rotating cylinder electrodes. Corrosion experiments were conducted in a conventional glass cell and the newly developed flow-through system. Significantly different corrosion product morphologies were observed in these different systems. In controlled water chemistry conditions, iron carbide (Fe3C) was found to play a crucial role in the development of the corrosion product as it provided a favorable environment for the formation of a FeCO3 layer at the steel surface. Three different kinds of material (X65 with tempered-martensitic microstructure, C1018 with ferritic-pearlitic microstructure, an (open full item for complete abstract)

Committee: Srdjan Nesic (Advisor); Rebecca Barlag (Committee Member); Craig Grimes (Committee Member); Marc Singer (Committee Member); Yoon-Seok Choi (Committee Member); David Young (Committee Member) Subjects: Chemical Engineering

Master of Science (MS), Ohio University, 2014, Chemical Engineering (Engineering and Technology)

Several types of mild steel are used in pipeline transmission. Steels with similar mechanical properties, e.g., yield strengths, have different contents and structures of iron carbide. This leads to different corrosion behaviors and corrosion inhibitor performance. The purpose of the present study is to develop an understanding of how iron carbide layers, derived from the different microstructures of carbon steels during corrosion, affect corrosion behavior and inhibitor performance. Glass cell experiments were conducted with 2 liters of 1 wt. % NaCl as the electrolyte at the desired temperature. A magnetic stirrer, set to 200 rpm, was used to ensure a fully mixed solution as carbon dioxide gas was constantly sparged into the test electrolyte. The solution pH was adjusted to the desired pH by addition of deoxygenated 1.0 M sodium hydroxide (NaOH) or sodium bicarbonate (NaHCO3) solutions. Hydrochloric acid (HCl) was used to maintain the pH around 5.0 ± 0.1. Three steel samples were immersed in the glass cell once the pH stabilized and tests were run for 3 days. Steels with different microstructures and chemical compositions were used in separate sets of experiments. After 24 hours of each experiment, a sample was withdrawn for surface analysis. In addition, experiments show that iron carbide layer development is dependent upon the microstructure and chemical composition, particularly carbon content, of the carbon steel from which it is derived. In each case, iron carbide impairs the performance of tested imidazoline-type inhibitors. The Fe3C developed from X65 (0.14 wt. % C) steel (ferrite-discrete cementite) has significantly more effect (i.e. decreases the inhibition efficiency) on the performance of inhibitors than the Fe3C developed from other types of steel. The performance of the inhibitor on X65 (0.05 wt. % C) spheroidized was less impaired than the performance of the inhibitor on other types of steel. In addition, the performance of the inhibit (open full item for complete abstract)

Committee: David Young (Advisor) Subjects: Chemical Engineering

Doctor of Philosophy (PhD), Ohio University, 2013, Chemical Engineering (Engineering and Technology)

Understanding the mechanisms that lead to localized corrosion in oil and gas pipeline is of great interest to corrosion engineers worldwide. The objective of this study is to examine the phenomena of localized corrosion in upstream oil and gas industry pipelines which operate under slightly sour conditions due to an H2S/CO2 environment. Experimental studies have been carried out to identify the parameters with the most influence on the likelihood of localized corrosion. It is shown that the solution bulk pH, concentrations of carbonates, concentration of sulfides, and the ionic strength of the solution are the major factors for localized corrosion. The flow temperature, and saturation values for both iron sulfide and iron carbonate were also identified as important parameters affecting the corrosion process. The experimental data were then analyzed and used to develop a correlation to relate these parameters to the likelihood of localized corrosion in mild steel pipelines.

Committee: Khairul Alam (Advisor); Frank Kraft (Committee Member); Valerie Young (Committee Member); Dina Lopez (Committee Member); Michael Jensen (Committee Member) Subjects: Chemical Engineering

Doctor of Philosophy (PhD), Ohio University, 2006, Chemical Engineering (Engineering)

Kinetics of iron carbonate and iron sulfide scale formation in CO2/H2S corrosion was investigated by individually studying iron carbonate formation in pure CO2corrosion, iron sulfide formation in N2/H2S corrosion, and the mixed iron carbonate/sulfide formation in CO2/H2S corrosion. The first part of the project was to investigate kinetics of iron carbonate scale formation in CO2 corrosion. A unified iron carbonate solubility expression which accounts for both temperature and ionic strength effects was proposed based on the literature data. The weight change method was developed to more accurately define kinetics of scale formation in CO2 corrosion and demonstrated that the old data from literature are one to two orders of magnitude too high. Based on the experimental data, a reliable iron carbonate formation equation was developed to describe iron carbonate scale growth on the steel surface in CO2 corrosion. The second part of the project was to investigate the mechanism and kinetics of iron sulfide formation in N2/H2S environment. The solubility limits of hydrogen sulfide and iron sulfides were clarified based on the literature data. Using weight change method, both the corrosion rate of the steel and the retention rate of the scale were found. It was also concluded that mackinawite is the predominant iron sulfide formed on the steel surface under the test conditions studied, most likely by a direct reaction of H2S with the underlying steel. Based on the experimental results, a mechanistic model of uniform H2S corrosion of mild steel was presented that was able to predict corrosion rate with time. Finally, kinetics experiments conducted in CO2/H2S solution proved that the makeup of the surface scale not only depends on the water chemistry and the respective solubility of iron carbonate and iron sulfide, but also on the competitiveness of the two scale formation mechanisms. Based on the experimental data it was found that mackinawite was the predominant scale formed (open full item for complete abstract)

Committee: Srdjan Nesic (Advisor) Subjects: Engineering, Chemical

Doctor of Philosophy (PhD), Ohio University, 2024, Chemical Engineering (Engineering and Technology)

Oil and gas transmission pipelines are frequently prone to internal corrosion in field environments. Use of organic corrosion inhibitors is an economical and effective way to combat this problem. Their typically amphiphilic inhibitor molecules provide protection by adsorption on the metal surface. Therefore, understanding and quantifying adsorption phenomena has significance for prediction of corrosion inhibition performance of a particular compound. In this dissertation research, a quartz crystal microbalance with dissipation monitoring (QCM-D) was the primary tool used to investigate the adsorption of two corrosion inhibitor model compounds on a noble gold substrate. The research reported herein shows how QCM-D can be used effectively to gain insights about the properties of the adsorbed layer, quantify adsorption/desorption kinetics, make predictions on the possible adsorbed layer configurations, and investigate the influence of inhibitor molecular structure on adsorption phenomena. Since real scenarios involve an actively corroding substrate, a classical oscillatory circuit-based quartz crystal microbalance (QCM) was also used to probe the metal-solution interface for a corroding and corrosion product forming experimental system; this facilitated deciphering the various reaction steps involved. The QCM-D findings in the present research indicate that the geometric surface coverage was less than 100% even for inhibitor concentrations above the surface saturation concentrations. This can help in answering a historical question in corrosion inhibition research about non-zero corrosion rates at inhibitor concentrations corresponding to maximum inhibition. Furthermore, the kinetic adsorption/desorption constants were estimated from the adsorption curves and verified successfully by predicting desorption behavior. This is of great significance, as this methodology can be further extended to study corrosion inhibition and its persistency. Furthermore, this serves as (open full item for complete abstract)

Committee: Srdjan Nešić (Advisor) Subjects: Chemical Engineering

Doctor of Philosophy (PhD), Ohio University, 2020, Chemical Engineering (Engineering and Technology)

The objective of this dissertation research was to investigate initiation mechanisms for CO2 localized corrosion on mild steel, encompassing the effects of chloride, oxygen, and acetic acid. In CO2 corrosion, iron in steel will be oxidized to ferrous ions under deareated conditions. The ferrous and carbonate ions can combine to form FeCO3 and precipitate once exceeding the solubility limit. When the precipitation of FeCO3 occurs evenly on the steel surface it forms a compact and protective layer. This acts as a diffusion barrier hindering the mass transfer of electrochemical species and covers/blocks the surface making it unavailable for corrosion, which enhances the resistance of mild steel to further uniform CO2 corrosion. However, there are various scenarios where localized corrosion may occur. When the environment becomes more aggressive, the FeCO3 could be partially removed. This leads to localized regions of the bare steel surface that become exposed to the corrosive solution and, subsequently, localized corrosion could be initiated. To study CO2 localized corrosion, two-stage experiments were performed: (1) a uniform protective FeCO3 layer was first formed on a carbon steel with high initial FeCO3 saturation; (2) localized CO2 corrosion scenarios were then developed by adding additional salts (NaCl or NaClO4), oxygen or acetic acid to challenge the protective FeCO3 layer. The experiments were conducted in a two-liter glass cell with a three-electrode system, working electrode (X65 carbon steel), reference electrode (Ag/AgCl saturated electrode), and counter electrode (platinum). Electrochemical measurements (linear polarization resistance) were carried out to observe electrochemical behaviors and calculate the corrosion rates. Weight loss was also used to determine general corrosion rates. Fe2+ concentration was measured using spectrophotometry in order to study the solubilization of FeCO3. Scanning electron microscopy (SEM), energy dispersive X-ray spe (open full item for complete abstract)

Committee: Srdjan Nesic (Advisor) Subjects: Chemical Engineering; Materials Science

Doctor of Philosophy (PhD), Ohio University, 2018, Chemical Engineering (Engineering and Technology)

The development of new hydrocarbon gas fields with high CO2 content is inevitable as the market demand for natural gas increases. Some of these fields contain up to 70 mole % of CO2 at pressures of up to 100 bar and are of large volume, which make them important reserves for production development. The challenges span from production at wellheads to eventual underground storage that will require a major capital expenditure for the necessary infrastructure. Corrosion issues can become particularly significant when mild steel is the material of choice due to its economics, engineering adaptability, and bulk availability. However, current corrosion prediction tools significantly overestimate CO2 corrosion rates by up to five times when the CO2 partial pressures exceed 20 bar, thus disqualifying the use of mild steels even with the application of appropriate corrosion mitigation strategies such as corrosion inhibitors. High partial pressure of CO2 (pCO2 ) leads to high concentrations of carbonic acid (H2CO3) in the aqueous phase, thus stimulating acid gas corrosion processes at the steel surface. This may result in extreme and catastrophic corrosion rates. However, specific conditions may be present to retard the corrosion process through growth/deposition of FeCO3 on the steel surface. Formation of FeCO3 as a corrosion product layer is mainly dependent on its degree of supersaturation and temperature. Therefore, studies of water chemistry relating to mutual solubility effects in the CO2-H2O system are an important first step to understand corrosion in high pressure CO2 environments. A model to describe water chemistry was proposed in a related research project and further validated in the research reported in this dissertation; showing good agreement. The linear solubility trend according to Henry's law shows deviation above 20 bar of pCO2. Therefore, this model better predicts speciation (H2CO3, HCO3-, CO32-, H+) concentrations, and distributions, in the binary (open full item for complete abstract)

Committee: Srdjan Nesic Prof (Advisor) Subjects: Chemical Engineering; Materials Science

Doctor of Philosophy (PhD), Ohio University, 2014, Chemical Engineering (Engineering and Technology)

The environmental conditions encountered in oil and gas wells and pipelines can cause severe localized corrosion to mild steel. The utility of carbon steel in oil and gas pipelines depends on formation of protective corrosion product layers. However, the microstructure and chemical composition of steel are considered to be important variables that affect the ability of these layers to protect steel from corrosion. The present study investigated the effect of alloying elements and metallurgy of five different pipeline steels, with different chemical composition and microstructure, on CO2 corrosion in flowing conditions with focus on the iron carbonate layer formed and related corrosion phenomena that could lead to localized corrosion. The microstructure of tested steels was examined using optical microscopy and etching. Preliminary experiments were conducted using a glass cell, which is a very well known and widely used apparatus. Then a comparison was done with the newly developed thin channel flow cell (TCFC) to validate whether the TCFC can be used instead of glass cell in this study, which required very high velocity and wall shear stresses. It was found that there are no significant effects of alloying elements and steel microstructure on corrosion rate in experiments done at pH 4.0 at 25°C and 80°C. Further experiments were then conducted in the TCFC to study the effect of alloying elements and microstructure under conditions where a protective FeCO3 corrosion product layer forms, using very high liquid flow rates. For each of the studied steels, an FeCO3 corrosion product layer was formed within two days of exposure at low wall shear stress at 80°C, pH 6.6, and partial pressure of CO2 of 1.5 bar (1.5 bar pCO2). For all tested steels, the FeCO3 layer reduced the general corrosion rate to less than 1.0 mm/y. These "pre-formed" FeCO3 layers were then exposed to high liquid flow velocity and wall shear stress (535 Pa) for 3 days. This caused partial lo (open full item for complete abstract)

Committee: Srdjan Nesic (Advisor) Subjects: Chemical Engineering

Doctor of Philosophy (PhD), Ohio University, 2012, Chemical Engineering (Engineering and Technology)

In the oil and gas industry, internal corrosion of carbon steel pipelines is commonly encountered during production and transportation. Iron carbonate is the main corrosion product layer in a CO2 corrosion environment. The formation of a protective iron carbonate layer can protect the steel from further corrosion by acting as a diffusion barrier and also by covering portions of the steel surface. Partial removal of the protective iron carbonate layer can lead to severe localized corrosion by the galvanic effect established between layer-covered and layer-free areas. Therefore, it is very important to understand the mechanisms of protective iron carbonate layer removal. In the current study, two possible removal mechanisms were examined by experimental studies: mechanical removal by flow and chemical removal by dissolution. Three types of experimental setups were used in order to examine whether the protective iron carbonate layer could be removed by flow. Small scale experiments were conducted in a glass cell with a rotating cylinder electrode setup and jet impingement setup. Although two different types of flow pattern were used, results showed that the protective iron carbonate layer was not affected by the flow and a thin yet adherent layer remained on the steel surface and protected the steel from corrosion. Furthermore, a medium scale thin channel flow cell system was designed and constructed, in order to conduct tests under more realistic flow conditions. It was once again proven that the iron carbonate layer remained protective under the enhanced flow condition. In addition, the mechanical strength of the protective layer was characterized in tensile strength experiments. It appeared that the measured strength necessary to separate the protective iron carbonate layer from the steel substrate was on the order of 106 Pa. This value was a few orders of magnitude higher than the wall shear stress encountered in most realistic flow systems, which demonstrated that (open full item for complete abstract)

Committee: Srdjan Nesic (Advisor) Subjects: Chemical Engineering

Master of Science (MS), Ohio University, 2011, Mechanical Engineering (Engineering and Technology)

The organic acid content in oil wells plays a determining role in the severity of corrosion even when only small concentrations are present. Organic acids are weak Brønsted acids that exist mainly as undissociated molecular species. Like all weak acids, a certain moiety will dissociate to form hydrogen ions and an anionic conjugate base. Therefore, with these acids the corrosion rate is not influenced only by pH, but also by the concentration of the undissociated acids in the solution. The vast majority of the literature on the effect of organic acids on CO2 corrosion of carbon steel focuses on acetic acid because this acid is the most abundant in the mixture of organic acids seen in the field. The purpose of this project was to understand and determine the mechanistic role of organic acids on the initiation of localized corrosion. It was concluded that the presence of acetic acid may lead to damage of the protective iron carbonate scale formed on X65 carbon steel. This leads directly to a temporary increase in the corrosion rate. However, the final corrosion rate does not seem to be affected. This raises the possibility that there may be a different phase conferring protection on the steel surface. This phase (corrosion scale) was characterized using different analytical techniques (SEM, EDS, XRD, XPS and FIB/TEM/EDS) to provide a more complete understanding of the metal's surface. It was found that the protection persisted as part of the FeCO3 remained on the surface. No localized attack was found under the studied conditions. In order to quantify iron carbonate dissolution, the electrochemical quartz crystal microbalance (EQCM) was used for the study of scale solubility in the presence of acetic acid. This confirmed that the presence of acetic acid was responsible for partial removal of the iron carbonate scale by selective dissolution, corroborating the characterization data obtained by surface analysis.

Committee: Srdjan Nesic Dr (Advisor); Hajrudin Pasic Dr (Committee Member); David Ingram Dr (Committee Member); David Young Dr (Committee Member); Frank F. Kraft Dr (Committee Member) Subjects: Materials Science

Master of Science (MS), Ohio University, 2004, Chemical Engineering (Engineering)

In the present study, the interaction of inhibitor film and iron carbonate scale in CO 2 corrosion has been investigated using electrochemical techniques. The experiments were designed to see the interaction of the inhibitor film and the iron carbonate scale under various stages of iron carbonate scale growth. The inhibitors used were generic imidazoline based inhibitors. The experiments were conducted in a glass cell at an iron carbonate supersaturation range of 7-150. Different inhibitor concentrations were used at various stages of scale formation. It is observed that the addition of the inhibitor hinders the corrosion rate as well as hampers the precipitation of the iron carbonate scale. This might be due to the lower concentration of Fe ++ at the metal surface and/or scale inhibition properties of the inhibitor. Under the conditions studied, there was no antagonism between the inhibitor and the iron carbonate scale.

Committee: Srdjan Nesic (Advisor) Subjects: Engineering, Chemical

Master of Science (MS), Ohio University, 2013, Chemical Engineering (Engineering and Technology)

Due to the isostructurality between calcite (CaCO3) and siderite (FeCO3), the Ca2+ ion incorporates in the hexagonal FeCO3 lattice and vice versa the Fe2+ ion incorporates in the hexagonal CaCO3 lattice. Thus, in aqueous CO2 environments, where both Ca2+ and Fe2+ are present, such as in gas reservoirs or deep saline aquifers, following CO2 injection, mixed metal carbonates with the formula FexCayCO3 (x+y=1) will be expected to form. This will likely have implications for corrosion, so that corrosion product layers will have the potential to be inhomogeneous, with behavior that deviates from that of pure FeCO3. In the present study, the effect of Ca2+ on the CO2 corrosion behavior of mild steel was investigated with different concentrations of Ca2+ (10, 100, 1,000 and 10,000 ppm). Electrochemical methods (open circuit potential (OCP) and linear polarization resistance (LPR) measurements) were used to measure the corrosion rate with time. Surface analysis techniques (scanning electron microscopy (SEM), energy dispersive X-ray spectroscopy (EDS) and X-ray diffraction (XRD)), were used to characterize the morphology and composition of the corrosion products. The results showed that with low concentrations of Ca2+ (10 and 100 ppm), the corrosion rate decreased with time due to the formation of protective FeCO3 and/or FexCayCO3 (x + y =1). However, the presence of high concentrations of Ca2+ (1,000 and 10,000 ppm) resulted in the change of corrosion product from protective FeCO3 to non-protective CaCO3 and FexCayCO3 (x + y =1) and an increasing corrosion rate with time. While the general corrosion rate was high for both 1,000 and 10,000 ppm Ca2+, surface analysis data revealed that localized corrosion was observed in the presence of 10,000 ppm Ca2+. Since Ca2+ was added in the tested conditions as CaCl2, the possible effect of Cl- on the non-uniform attack was studied by testing with the equivalent concentration of Cl- using a NaCl solution. However, the result showed (open full item for complete abstract)

Committee: Srdjan Nesic Prof. (Advisor) Subjects: Engineering