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

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

As geologic environments associated with oil and gas production have become increasingly aggressive, aqueous corrosion at high temperatures in the presence of hydrogen sulfide (H2S) is more frequently encountered. The understanding of sour corrosion mechanisms is an important but still largely elusive target, especially at high temperatures. The purpose of this project is to explore the thermodynamics and kinetics of H2S corrosion at high temperature, and to develop a thermodynamic model to predict the corrosion product layer formation, as well as a mechanistic kinetic model to predict the corrosion rate of mild steel at high temperature in the presence of H2S. The first part of the project focused on the development of experimental and safety procedures to investigate layer formation and corrosion mechanisms in high temperature environments. This included the development and validation of a water chemistry model for a closed system especially designed to properly control the experimental parameters. In the second part of this project, the effects of temperature (80~200°C), exposure time (1~21 days), and partial pressure of H2S (0.1~2.0 bar) were thoroughly investigated. Significant and somehow unexpected findings were obtained: A Fe3O4 layer was always identified on the steel surface although this type of corrosion products was thermodynamically less stable than FeS. Fe3O4 formed very fast at the initial stage of corrosion and was responsible for the quick decrease of the corrosion rate. The Fe3O4 layer experienced a continuous process of formation (due to corrosion at the steel/Fe3O4 interface) and conversion to iron sulfide (at the Fe3O4/FeS interface). The transformation of the outer iron sulfide layer was also observed at high temperature and thoroughly documented for the first time. The general transformation sequence was identified as mackinawite, troilite, pyrrhotite, pyrite. With the increase of temperature, time, and partial pressure of H2S, iron sul (open full item for complete abstract)

Committee: Marc Singer (Advisor); Srdjan Nesic (Committee Member); Dina Lopez (Committee Member); Jason Trembly (Committee Member); Rebecca Barlag (Committee Member); David Young (Committee Member) 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, 2023, Chemical Engineering (Engineering and Technology)

Sour hydrocarbon reservoirs, containing H2S gas, are receiving increasing attention due to the growing demand for energy. Although uniform corrosion is not a significant obstacle for oil and gas companies in sour environments, the major challenge in this field is prevention of localized corrosion that can cause failures in production infrastructure. Formation of different types of iron sulfides as corrosion products has been postulated to be a main culprit for localized attack, due to their wide-ranging physicochemical properties, such as their electrical conductivities. The galvanic coupling between iron sulfides layers and mild steel was shown to be the mechanism associated with the localized attacks in sour environments. However, the mechanism of galvanic coupling between mild steel and iron sulfides has not been understood due to the lack of systematic and parametric studies. The research described herein addresses the galvanic coupling between mild steel and iron sulfide polymorphs to investigate the involved mechanisms. For the first step, the uniform corrosion of mild steel in aqueous H2S solutions was critically reviewed, and the mechanism associated with this system including the involved chemical electrochemical reactions was fully described. Furthermore, the mathematical modeling of uniform corrosion rate of mild steel in H2S environments was also comprehensively reviewed. In addition, some new approaches for the modeling of electrochemical reactions as well as corrosion rate were proposed, and the validity of the proposed models were verified through comparing with experimental data. Next step of the current research focused on the galvanic corrosion between mild steel and iron sulfides using both experimental and modeling investigations. In the experimental section, a systematic study was performed in order to determine the contribution of the influential parameters on the galvanic corrosion between mild steel and iron sulfides. On that account, the (open full item for complete abstract)

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

Master of Science, The Ohio State University, 2019, Chemical Engineering

Fossil fuel power plants often generate sulfur species such as hydrogen sulfide or sulfur dioxide due to the sulfur content of the raw feedstocks. To combat the associated environmental, processing, and corrosion issues, facilities commonly utilize a Claus process to convert hydrogen sulfide to elemental sulfur and water. Unfortunately, the Claus process suffers in efficiency from a thermal oxidation, or combustion, step and high equilibrium reaction temperatures. In this work, two different chemical looping process configurations towards recovering sulfur and H2 are investigated: (1) 3 reactor system (SR) for sulfur recovery; (2) 2 reactor system (SHR) for sulfur and H2 recovery. Since, H2 yield and sulfur recovery in a single thermal decomposition reactor in the SHR system is limited by low H2S equilibrium conversion, a staged H2 separation approach is used to increase H2S conversion to H2 using a staged separation methodology. Steady-state simulations and optimization of process conditions are conducted in Aspen Plus v10 simulation software for the chemical looping process configurations and the Claus process. An energy and exergy analysis is done for the chemical looping and Claus processes to demonstrate the relative contribution to exergy destruction from different unit operations as well as overall exergy and energy efficiency. The two chemical looping process configurations are compared against the Claus process for similar sulfur recovery in a 629 MW integrated combined cycle gasification power plant. The SHR system is found to be the most attractive option due to a 97.11% exergy efficiency with 99.31% H2 recovery. The overall energy and exergy efficiencies of this chemical looping system are 14.74% and 21.54% points higher than the Claus process, respectively, suggesting more efficient use of total input energy.

Committee: Liang-Shih Fan PhD (Advisor); Bhavik Bakshi PhD (Committee Member) Subjects: Energy; Engineering

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

Iron sulfide corrosion product layers commonly form on mild steel surfaces corroding in aqueous H2S environments. These layers present a barrier which may retard the corrosion rate. However, their semiconductive nature leads to an acceleration of corrosion via galvanic coupling, by increasing the cathodic surface area. The electrocatalytic properties of different iron sulfides, which are important in this process, were heretofore unknown. The research herein reports cathodic reaction rates on the surfaces of geological specimens of both pyrite and pyrrhotite along with mild steel in HCl, CO2 and H2S aqueous solutions at different pH values. The results show that in solutions where H+ reduction dominates pyrite has similar electroactivity to X65 steel, while pyrrhotite exhibits approximately one order of magnitude smaller current densities. An extra wave observed in the cathodic sweeps on pyrrhotite was due to conversion of pyrrhotite to troilite. In aqueous CO2 solutions similar results were obtained, while in H2S aqueous environments both pyrite and pyrrhotite showed similar electroactivity that was slightly less than that of X65 steel. Zero resistance ammeter (ZRA) measurements were utilized in order to measure the galvanic current between an X65 mild steel surface and a pyrite or pyrrhotite surface; cathode to anode surface area ratios of circa 20 and 7 were employed in separate sets of experiments. The results were compared with the proposed model which takes into account the reduction rates, changes in surface characteristics of the iron sulfides and their surface area. Due to the electrical conductivity and the observed galvanic current between pyrrhotite and a mild steel, it was hypothesized that its presence in the corrosion product layer on a steel surface could lead to localized corrosion. Mild steel specimens (API 5L X65) were pretreated to form a pyrrhotite layer on the surface by high temperature sulfidation in oil. The pretreated specimens were (open full item for complete abstract)

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

Master of Science, The Ohio State University, 2012, Food, Agricultural and Biological Engineering

Lignocellulosic biomass feedstocks, in particular yard waste, are highly desired for anaerobic digestion as they are widely available and tipping fees are commonly associated with disposal. The high concentration of lignin presents a major challenge for utilizing yard wastes as a feedstock for anaerobic digestion. Therefore, additional steps are necessary to increase the biodegradability of yard waste. The initial focus of this study was to test two potential methods for increasing the methane production of yard waste: pretreatment and co-digestion. Sodium hydroxide (NaOH) pretreatment was studied at NaOH concentrations of 3% and 5%. It was found that 3% NaOH pretreatment had no significant improvement on methane production while 5% NaOH pretreatment had a significant negative effect on methane production. The second method studied was co-digestion of yard waste and food waste. Co-digestion at a ratio of 75% food waste and 25% yard waste showed a four-fold increase in methane yield compared to digestion of 50% food waste and 50% yard waste and a two-fold increase in methane production compared to digestion of 100% food waste. Anaerobic digestion of food waste containing protein and other sulfur containing substances produces hydrogen sulfide in biogas. Hydrogen sulfide (H2S) in biogas causes corrosion of metal components such as regulators, gas meters, valves, and mountings. Combustion of biogas containing H2S produces poisonous sulfur dioxide (SO2). The SO2 also dissolves in engine oil causing the oil to become acidic and lose its ability to lubricate. One method for H2S removal involves using hydrated iron oxides supported on a media comprised of wood chips or wood shavings. The iron oxide reacts with the H2S in the gas to form iron sulfide and water. This method is called an iron sponge. The second focus of this study was to test hydrogen sulfide removal using the iron sponge method. The first goal was to determine the optimum operating parameters of an iron s (open full item for complete abstract)

Committee: Dr. Yebo Li (Advisor); Dr. Jay Martin (Committee Member); Dr. Frederick Michel (Committee Member) Subjects: Agricultural Engineering; Energy; Engineering

Doctor of Philosophy (PhD), Ohio University, 2011, Chemical Engineering (Engineering and Technology)

Corrosion, especially the localized corrosion of carbon steel, in sour systems (H2S dominant) has progressively become a greater concern to the oil and gas industry as a result of production from increasingly sour environments. In this study, the effects of chloride ion concentration on the localized H2S corrosion were initially investigated, followed by the investigation of the corrosion of carbon steel in the presence of elemental sulfur, which is often present in sour systems. Attempts were also made to determine if classic galvanic theory can be applied to explain the propagation of localized corrosion in sour systems. A series of experiments were performed to study high chloride concentration effects on the initiation and propagation of localized H2S corrosion. Localized corrosion events were detected in both chloride-free and high chloride concentration conditions. The results suggest that chloride ion may not be the direct cause of initiation of localized H2S corrosion. Instead, high concentrations of chloride ions significantly decreased overall general H2S corrosion. The corrosion of carbon steel in the presence of elemental sulfur was also studied. Elemental sulfur was shown to cause catastrophic corrosion of carbon steel when water is present. The addition of salts significantly accelerates the corrosion. From the experimental results, it has been concluded that an electrochemical process is the dominant corrosion mechanism of elemental sulfur corrosion, and that solution conductivity plays a very important role. Based on the experimental data, an electrochemical model is proposed for elemental sulfur corrosion. Propagation of localized corrosion in an H2S system was also studied using an artificial pit technique. From the experimental results, it was determined that standard galvanic theory cannot be used to explain the propagation of localized corrosion in H2S systems.

Committee: Srdjan Nesic (Advisor); Daniel Gulino (Committee Member); Michael Prudich (Committee Member); Howard Dewald (Committee Member); Lauren McMills (Committee Member) Subjects: Chemical Engineering

Master of Science (MS), Ohio University, 2008, Chemical Engineering (Engineering)

The present study has been conducted to investigate the corrosion and scale formation rates of CS-A106 and 5Cr-A182 exposed to different acid concentrations and varying amounts of sulfur compounds. The experiments were designed to determine the effect of time, temperature and acid concentration on the formation and retention of sulfide films formed on the steel surface. A hot oil flow loop “Flow Through Mini Autoclave” was used to conduct experiments forming sulfide scales at different acid concentrations varying from 0.04 to 4. Temperature of these experiments was varied from a low temperature (450°F) to a high temperature (700°F). Tests were conducted for a short period of 3 hr to a long period of 96 hr. It was observed that sulfide scales protect steel surface from being corroded once they formed on the steel. Amount of scale accumulated on the steel increased with time but the protectiveness of the scale was highly reliant on the time of exposure, acid concentration and temperature. Sulfide scales were subjected to cracking and it reduced the adherence of scale to steel surface. Sulfide scales were not 100% dense and SEM pictures showed porous scales formed in all experiments.

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

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

An experimental series was conducted to measure the effect of low concentrations of H2 S (3, 15, 100 ppm) under “non-film forming conditions” for iron carbonate at pH 4 in a CO2 saturated environment on the corrosion rates of UNS C1018 and X65 carbon steels at two temperatures (60°C and 80°C). These experiments in the Hydrogen Sulfide Multiphase Flow Loop provide the first example of the effect of H2S concentration on corrosion rates measured concurrently in single phase and multiphase flow in a CO2 saturated environment. At 60°C and 80°C, any addition of H2S retarded the corrosion rate in both single phase and multiphase flow conditions over a 96-hour exposure period as compared to the corrosion rate measured under the same partial pressure of CO2 without the presence of H2S. At pH 4, films of 5 to 10μm were produced over 96 hours for UNS C1018 flush-mounted coupons in a system with a 100ppm concentration of H2S in the gas phase. Electron dispersion spectroscopy of the films provides proof of an iron sulfide (FeS) film. Thinner films were developed under conditions of 3ppm and 15ppm H2S concentrations, but film thickness was not as easily quantified by scanning electron microscopy. Overall, higher corrosion rates consistently occurred in multiphase flow when compared to those measured under single phase conditions. Pitting corrosion was observed at 80°C for both 3ppm and 15ppm H2S concentrations. System validation tests on the Hydrogen Sulfide Flow Loop system prior to this experimentation show repeatability and good comparison to another flow system under the same operating conditions without the presence of H2S.

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