ABSTRACTChemical inhibition in the presence of silica sand deposit has been reported as a cause of severe localized corrosion attack in CO2-saturated brine environments. This paper suggests a new mechanism for explaining physics behind the localized corrosion attack based on experimental evidences. The effect of sand size and deposit type on localized corrosion attack in the presence of imidazoline type inhibitor is also experimentally investigated in CO2-saturated brine solution. Smaller silica sand particles (diameter less than 44 micron) are found to cause less localized corrosion attack in comparison to larger sand particles (In the range of 250-750 micron diameter). Localized corrosion attack in the presence of paraffin deposit is also negligible compared to silica sand deposit.INTRODUCTIONUnder-deposit corrosion (UDC) has frequently been reported as a cause of failure in the oil and gas industry.1 Under-deposit corrosion often results in severe localized corrosion attack; this is difficult to monitor, predict, and mitigate. Galvanic cells established between covered and uncovered regions of the metal surface, resulting in severe localized corrosion. Monitoring of localized corrosion is problematic because predicting the location of deposit formation is difficult and it happens along the pipeline in random locations. Mitigation is challenging because corrosion inhibitors do not efficiently protect the areas of the pipe covered by deposit. The inhibitors may even accelerate localized corrosion attack under deposits by the creation of more pronounced galvanic effects.2 One of the best tools to mitigate under-deposit corrosion is pipeline pigging. It is important to mention that not every pipeline is piggable and even those lines that are piggable may suffer from extensive corrosion damage if the pigging frequency is not adequate.Different types of deposits have been reported in the oil and gas industry. In 2005, de Reus, et al.3 reported that field deposits are most frequently silica sand associated with produced oil. Deposits can be divided into two main categories:
ABSTRACTHydrogen sulfide (H2S) corrosion of mild steel is a serious concern in the oil and gas industry. However, H2S corrosion mechanisms, specifically at high partial pressures of H2S (pH2S), have not been extensively studied because of experimental difficulties and associated safety issues. The current study was conducted under well-controlled conditions at pH2S of 0.05 and 0.096 MPa. The pH range used was from pH 3.0 to pH 5.0, at temperatures of 30 and 80°C, and with rotating cylinder speeds of 100 rpm and 1000 rpm. Short-term exposures, lasting between 1.0 and 1.5 hours, were used to avoid formation of any protective iron sulfide layers. The experimental results were compared with a recent mechanistic model of sour corrosion developed by Zheng, et al. (2014). This model was based on corrosion experiments conducted at low pH2S (0.0001 - 10 kPa) and is applicable only to conditions where protective iron sulfide layers do not form. The validity of the model at higher pH2S was examined, as it was uncertain if the mechanisms identified at lower pH2S were still valid. The comparison with the experimental results obtained in the present study indicated a good agreement between the model and the measurements. This confirmed that the physico-chemical processes underlying H2S corrosion in the absence of protective iron sulfides are very similar across a wide range of H2S aqueous concentrations. It also demonstrated that the mechanistic corrosion model was reasonable when extrapolating from low to high pH2S.INTRODUCTIONThe role of hydrogen sulfide (H2S) on aqueous mild steel corrosion has been one of the concerns of corrosion researchers since 1940 1-13. Ewing14 and Sardisco, et al., 15 were among the first scholars to initiate controlled H2S corrosion experimentation which was later continued by other researchers 13,16-20. The focus of much of the H2S related studies in the past was on iron sulfide formation and the resulting effect on corrosion3,21-23. The vast majority of the available research results come from experiments conducted at lower H2S partial pressures (pH2S < 10-2 MPa). Over the past few decades, a significant number of new oil and gas fields are sour, ranging from a few ppm up to 15-20 mol% H2S (e.g., the Kashagan Field24). This indicated a growing need for better understanding of H2S corrosion mechanisms and more effective prediction tools, particularly at higher pH2S.
ABSTRACTThe primary objective of this study was to investigate iron carbonate (FeCO3) formation mechanisms on ferritic-pearlitic carbon steel corroding in a CO2 saturated aqueous solution near iron carbonate saturation, with particular emphasis on the effect of solution pH. A controlled water chemistry test apparatus was developed to resolve issues with drifting water chemistry during long-term corrosion experiments. An improved test apparatus for holding the metal samples was also introduced to eliminate the non-uniformity of flow across the samples and assure well controlled mass transfer conditions in the glass cell. Results pertaining to the solution pH effect are presented by discussing associated water chemistry, corrosion rates, and FeCO3 morphologies. Under the controlled water chemistry conditions, iron carbide (Fe3C) was found to play a critical role in the formation of FeCO3 near the steel surface, where ferrous ions accumulate and surface pH is higher than solution pH. Experiments within the pH range (pH 5.4-6.0) resulted in similar corrosion product characteristics and corrosion rates given that the level of FeCO3 saturation was controlled. It was found that a higher solution pH was likely to give a slightly better protection to the steel surface.INTRODUCTIONIt has been verified both experimentally and computationally that pH has a strong effect on aqueous CO2 corrosion of carbon steel.1 At a high pH value, the solubility of FeCO3 decreases and results in a higher precipitation rate.2,3 Solution pH is calculated directly from the hydrogen ion concentration that results from the dissociation of the carbonate and bicarbonate in aqueous solution.7 Furthermore, bicarbonate dissociation leads to the generation of carbonate ion. Hence, the pH i.e. the concentration of hydrogen ions is linked to the concentration of carbonate ion, which is an important parameter for determining the saturation value (S[FeCO3]) as expressed in Equation (1)).Many methods have been proposed to measure surface pH directly4,5 and indirectly6,7,8. It is understood that a reduction in the general CO2 corrosion rate of mild steel occurs at higher pH when the solubility of FeCO3 decreases. Figure 1 shows the solution pH effect on solubility of FeCO3. The S[Feco3] = 1 line represents saturation with respect to FeCO3 while the dashed lines represent a factor of two from the saturation value. The region on the right of the saturation value represents a supersaturated solution with respect to FeCO3, where protective FeCO3 layers form and corrosion rates are uniformly low. The region on the left represents an undersaturated solution with respect to FeCO3, where protective FeCO3 layers are not going to form, and uniform “bare steel” corrosion is a result. Both of these regions have been explored experimentally in the past. However the intermediate conditions is where limited information on CO2 corrosion is available and the corrosion behavior seems to be sensitive to small variations in environmental conditions, in some cases resulting in localized attack.9 In order to address this issue, more in-depth research on corrosion mechanisms and FeCO3 formation in the midrange of solution pH 5.4-6.0 is needed.
ABSTRACTThe objective of this work was to determine the corrosion rate of mild steel and characterize the corrosion products in sour environments at temperatures ranging from 80°C to 200°C. First, a H2S-H2O water chemistry model was developed based on available literature for a closed system at high temperature. Then, H2S corrosion tests were conducted at 80°C, 120°C, 160°C and 200°C with an exposure time of 4 days. Linear polarization resistance (LPR) and weight loss (WL) methods were used to measure the corrosion rates. X-ray diffraction (XRD) and scanning electron microscopy with energy dispersive X-ray spectroscopy microanalysis (SEM/EDS) were employed to characterize the corrosion products and surface morphology. The results show that the initial corrosion rates increased with temperature then decreased as they achieved steady-state. The corrosion product was comprised of two distinct layers. The inner corrosion product was always an iron oxide layer (hypothesized to be Fe3O4), while mackinawite, troilite, pyrrhotite and pyrite were identified as the main components of the outer layer at 80°C, 120°C, 160°C and 200°C, respectively. Pourbaix diagrams generated based on the analysis of water chemistry corroborated the experimental characterization of the corrosion products.INTRODUCTIONAs geologic environments associated with oil and gas production have become increasingly aggressive, aqueous corrosion at higher temperatures in the presence of hydrogen sulfide (H2S) is more frequently encountered.-3 High temperatures and high pressures in combination with H2S lead to many materials selection and engineering challenges, as well as potential for pipeline and equipment failures, especially in downhole environments.H2S corrosion at low temperatures (< 80°C) has been widely studied,4-6 and significant progress has been made to elucidate the general corrosion mechanisms involved. As a result, kinetic and thermodynamic models have been built and verified. It is known that the initial “bare steel” corrosion rate increases with temperature, but the increase of cathodic current is more significant than that of the anodic current.7 When conditions are favorable for the formation of a corrosion product layer, its characteristics are strongly dependent on temperature. At 25°C, a porous and non-protective mackinawite layer forms on the steel surface. At 80°C, a dense and adherent corrosion product layer, composed of mackinawite and pyrrhotite, forms that confers good protectiveness.8 Temperature can accelerate both the rates of corrosion as well as the rate of corrosion product layer formation. Consequently, a peak in corrosion rate is often observed when increasing the temperature at a fixed pH2S.9
ABSTRACTLocalized corrosion is troublesome for corrosion engineers because it is generally considered the main cause for pipeline failures in the oil and gas industry, particularly in sour systems, and it is hard to predict or detect. However, compared to general corrosion, localized corrosion is poorly understood and less studied. Hence, understanding mechanisms of localized corrosion in sour fields is critical to corrosion engineers for integrity management. In a previous study, a strong correlation between the formation of greigite and/or pyrite and the onset of localized corrosion was observed. A further comprehensive study was then required to investigate this correlation between localized corrosion and greigite and/or pyrite. Thus, novel experiments involving deposition of pyrite on the steel surface were designed and conducted for the current study to investigate if localized corrosion occurs when pyrite is deposited on mild steel in an aqueous H2S environment. It was confirmed that severe localized corrosion was observed and replicated in the presence of pyrite deposit layers. Furthermore, the impact of pyrite particle size on pit characteristics was also studied. It was found that smaller and deeper pits were observed in the presence of smaller pyrite particles. This was concluded to be due to a larger cathodic area of the small particles, compared to the same amount of larger particles.INTRODUCTIONCO2 and H2S corrosion of carbon steel are amongst the most frequently encountered materials' degradation processes associated with production and transportation of oil and gas.1,2 The CO2 corrosion mechanism is generally well defined, however, complications arise when H2S is present. H2S metal loss attack can be classified into two categories, localized corrosion and general corrosion, based on the appearance of the corroded steel. Due to recent studies3-9, mechanisms associated with H2S general corrosion have become better understood. Localized H2S corrosion is more troublesome for corrosion engineers because it is generally considered the main cause for pipeline failures in the oil and gas industry. Compared to H2S general corrosion, there is minimal understanding of H2S localized corrosion. In general, it can be concluded that mechanisms of H2S localized corrosion are unclear and the causes of H2S localized corrosion are uncertain.
ABSTRACTThe most common corrosion inhibitors used to minimize corrosion of carbon steel in the oil and gas industry contain imidazoline molecules. However, the behavior of imidazoline molecules at the interface remains poorly understood, especially with respect to the adhesive and cohesive forces of inhibitor films. The objective of this work is to understand the adsorption/desorption process of 1-(2- aminoethyl)-2-oleyl-2-imidazolinium chloride on carbon steel. In order to study adsorption of imidazolinium chloride on carbon steel, in-situ atomic force microscopy (AFM) measurements were performed in air, with and without imidazolinium chloride, in a 1 wt% NaCl solution purged with CO2 at pH 4. In-situ electrochemical/AFM measurements confirmed the formation of an inhibitor film on carbon steel surface, resulting in a decrease in corrosion rate as determined by electrochemical measurements. Quantitative force measurements were also performed to evaluate the force required for penetration of the inhibitor film adsorbed on carbon steel.INTRODUCTION & BACKGROUNDThe use of atomic force microscopy (AFM) for corrosion research studies is becoming more widespread over the last decade. Several research groups have coupled the use of atomic force microscopy with the study of corrosion and corrosion inhibition studies on mild steel,[1-5] but until now they have not coupled the AFM contact mode and force spectroscopy studies with in situ corrosion rate and electrochemical spectroscopy measurements during the AFM analysis.One of the earliest papers found about using AFM for imaging the adsorption of corrosion inhibitors on steel was conducted by Kinsella and Becker.  This paper won the Marshall Fordham Best Research paper award at Corrosion & Prevention 2008, Australia. The research showed the advantage of using AFM imaging techniques over other methods, since the AFM could physically measure the assembly of molecules on the surface in the presence of an aqueous phase. Specimen of AISI 304L stainless steel were polished to a mirror finish, etched in order to observe grain structure, and measured by AFM. Topography of the surface was obtained along with proving the adsorption of inhibitor on the surface by use of force-distance plots. Topographical AFM images were correlated to three basic shapes of an inhibitor layer (rod, sphere, and bi-layer).
ABSTRACTIn the present study, the effect of temperature on the adsorption/desorption kinetics and thermodynamics of diethylenetriamine talloil fatty acid imidazoline (DETA/TOFA imidazoline) is studied on a gold coated crystal using a quartz crystal microbalance (QCM) in a CO2 saturated 1wt% NaCl aqueous solution. Concurrently, the corrosion inhibition performance of imidazoline on API 5L X65 steel was also investigated at different temperatures using linear polarization resistance (LPR). QCM results show that the adsorption of imidazoline-type inhibitor generally follows the Langmuir adsorption process and the desorption of inhibitor is favored with increasing temperature. While both adsorption and desorption rate constants increase with temperature, the effect on desorption was found to be more pronounced. Inhibition test results generally agree well with those obtained in the adsorption study and the loss of corrosion inhibition efficiency observed at higher temperature is attributed to a greater rate of desorption of the inhibitor.INTRODUCTIONAs CO2 corrosion is one of the major threats to operational safety in oil and gas production, the use of organic corrosion inhibitors to control CO2 corrosion is of great interest to the industry. Consequently, many research projects have explored inhibition performance in various production environments1-8.The effect of temperature on corrosion inhibition performance is a particularly significant concern. Generally, organic inhibition performance is governed by adsorption/desorption behavior. Inhibition efficiency of physisorbed inhibitors decreases with temperature, whereas for chemisorbed inhibitors inhibition efficiency usually increases with temperature4-6,9-11. However, little is known about the underlying mechanisms as, up until now, most corrosion inhibitor research has focused on inhibition efficiency, instead of on adsorption behavior itself. Use of in situ methods to study adsorption behavior of corrosion inhibitors are anticipated to lead to an improved understanding of how they function.The quartz crystal microbalance (QCM) is a device that can measure mass changes in situ on a crystal surface at the μ,g-cm-2 level12. Therefore, it is an ideal technique for studying temperature effects on adsorption/desorption processes. In the study reported herein, a generic corrosion inhibitor termed talloil diethylenetriamine imidazoline (TOFA/DETA imidazoline) was chosen for testing. Temperature effects on adsorption are examined by studying the adsorptive behaviors of TOFA/DETA imidazoline inhibitor at various temperatures using a QCM. In addition, the influence of temperature was investigated by studying corrosion inhibition performance at various temperatures using linear polarization resistance (LPR). As a result, temperature effects on adsorption kinetics and thermodynamics and corrosion inhibition performance were determined.
In aqueous carbon dioxide (CO2) solutions where both Ca2+ and ferrous iron (Fe2+) are present, such as downhole gas reservoirs or deep saline aquifers after CO2 injection, mixed metal carbonates with the formula FexCayCO3 (x+y=1) can form. This inhomogeneity may lead to localized corrosion. During carbon steel corrosion experiments conducted in electrolytes containing high Ca2+ concentrations, inhomogeneous corrosion product layers with the composition FexCayCO3 (x+y=1) were indeed observed, along with non-uniform corrosion. Determining relative molar fractions of Ca2+ and Fe2+ in FexCayCO3 is paramount to predicting the relative properties and stability of such mixed metal carbonates. Using Bragg’s Law and equations to relate inter-planar spacings to unit cell parameters, Xray diffraction (XRD) data yielded values for the molar fraction of Ca2+ in FexCayCO3. Procedures in the current experimental study were designed to develop a range of specific corrosion product layers on mild steel samples. Experiments were conducted at constant Cl- concentration with and without 10,000 ppm Ca2+ in stagnant conditions, for two different flow conditions. In stagnant conditions, localized corrosion was associated with the presence of Ca2+ and the inhomogeneity of the corrosion product layer. The corrosion attack became uniform when flow was introduced.
The effect of calcium cations (Ca2+) on the formation and protectiveness of iron carbonate (FeCO3) layers in aqueous carbon dioxide (CO2) corrosion of mild steel was discussed in a previous study.1 It showed that the isostructurality of calcium carbonate (CaCO3) and FeCO3 allowed the incorporation of Ca2+ into the FeCO3 structure; thus, the morphology and chemical properties of FeCO3 were altered.
The importance of FeCO3 formation on corrosion protection of mild steel has been well documented.2-7 In a stagnant aqueous CO2 solution, the water chemistry at the corroding steel surface is not the same as the bulk water chemistry. As a consequence of the corrosion process that consumes hydrogen (H+) and releases ferrous iron (Fe2+) to the solution, the pH and Fe2+ concentration increase adjacent to the steel surface. This leads to a higher degree of FeCO3 saturation near the steel surface and a higher probability of protective FeCO3 layer formation. However, in a turbulent well-mixed solution a corroding bare steel surface has almost the same water chemistry as the bulk solution, making protective FeCO3 layer formation less probable.2,6-9 In addition, at very high flow rates, there is a possibility of removal of protective FeCO3 layers, leading to localized corrosion. 8,9
Mitigation of localized under deposit corrosion (UDC) in upstream oil and gas pipelines is an important research topic for both industry and academia. In a research program focused on understanding various inhibitor components that provide mitigation of UDC, initial research investigated the effect of varied ratios of mono- to dinonylphenol phosphate esters (PE) by testing a set of specifically formulated inhibitors. Inhibitors with three mono- to di- PE ratios were tested in the presence and absence of 2-mercaptoethanol (ME). Using two 1.25 in. (3.18 cm) diameter API 5L X65 pipeline steel samples and 250 µm silica sand, UDC testing was conducted for 28 days in a CO₂ saturated solution at 70°C and 1 bar total pressure. Analysis has shown that localized corrosion (pit penetration rate) increased for ME-free nonylphenol PE as the concentrations of di-PEs and mono-PEs approached equivalency. The nonylphenol PE inhibitor with a 50:50 mono- to di- PE ratio at 100 ppm concentration failed to protect the surface of the sample under the individual sand grains. Even the base product inhibitor package with no PE provided better mitigation under these test conditions than the 50:50 mono- to dinonylphenol PE. However, it was observed that the addition of ME provided a dramatic improvement in the mitigation of UDC for each mono- to di- PE ratio of the nonylphenol PE tested. From this research, it is seen that the mono- to di- phosphate ester ratio is important to consider when developing corrosion inhibitors containing phosphate esters.
UDC is a localized corrosion that occurs where sediments, carried through a production or transmission pipeline, have settled in stagnant or low-flow sections of a pipeline and mitigation strategies have been ineffective or impractical. When the flow is low enough and silica sand collects on the bottom of the pipeline, the sand deposit can retard uniform corrosion of mild steel by slowing down the mass transfer of corrosive species. When an inhibitor has been introduced to mitigate corrosion, it has been thought that the sand deposit can act to slow down inhibitor diffusion to the metal surface and may deplete the inhibitor concentration through adsorption on the large surface area of the sand. However, these mechanisms are not considered to be the critical factors leading to localized corrosion in under-deposit CO₂ corrosion, although localized corrosion is documented to occur. In one published example, general corrosion rates in a crude oil transmission pipeline were measured in the range of 0.2 to 0.4 mpy (0.005 to 0.01 mm/yr), but significant localized pitting was found under the sediment in the bottom of the line.¹
Localized corrosion in sour fields is a challenge persisting in the oil and gas industry since it has frequently been seen as a cause for catastrophic failures of upstream pipelines. Hence, prediction and mitigation of H2S localized corrosion of mild steel is of key importance for integrity management. However, our current understanding of H2S localized corrosion mechanism(s) from numerous studies in both in the laboratory and the field is far from being conclusive. Especially, the environmental conditions that may cause localized H2S corrosion are unclear. Therefore, defining an experimental condition in the laboratory that can replicate localized corrosion in a sour environment is critical to our understanding of mechanisms of localized corrosion. The focus of the present research was to explore environmental conditions leading to localized H2S corrosion. It was found that severe localized corrosion was repeatedly observed in experiments, when there was a simultaneous formation of greigite and/or pyrite. Based on those experimental results, a hypothesis for a mechanism of H2S localized corrosion was proposed.
Corrosion caused by the presence of H2S and CO2 in produced fluids is frequently encountered in pipelines during the production of oil and gas. Compared to general CO2 and H2S corrosion1-3, localized H2S corrosion is much less understood and less studied. This poses a key challenge for integrity management in the oil and gas industry.
In open literature, H2S localized corrosion has been usually associated with multiple risk factors, such as the presence of elemental sulfur4-8, the presence of polysulfides9-11, high salinity12-14, flow velocity15, a change in local water chemistry at steel surface16, and metallurgy. In addition, corrosion and scaling mitigation strategies, such as corrosion inhibitors, alcohol and glycols, and pH stabilization, used in sour systems in the oil and gas industry, can greatly decrease the uniform corrosion, while increasing the probability for localized corrosion. Kvarekval et al.17 have showed very strong evidence of this with examples of severe localized corrosion.