Water-saturated Supercritical CO2 Research Articles

Revealing the Mechanism of O<sub>2</sub> and Pressure Effects on the Corrosion of X80 Carbon Steel Under Supercritical CO<sub>2</sub> Conditions

Pipeline transportation is widely used due to its ability to improve the efficiency of CO<sub>2</sub> transportation in Carbon Capture, Utilization, and Storage (CCUS). Within the transport pipelines, CO<sub>2</sub> fluid exists in a supercritical state and often contains various impurity gases such as O<sub>2</sub> and H<sub>2</sub>O, which can easily cause steel corrosion, affecting the safety of pipeline operations. In this investigation, we examine the corrosion behavior of X80 carbon steel within a water-saturated supercritical CO<sub>2</sub> environment utilizing weight loss experiments, electrochemical tests, and surface analysis techniques. Furthermore, we explore the impact of pressure and oxygen on the corrosion process of X80 steel. The results indicated that X80 steel underwent severe corrosion under the experimental conditions, with FeCO<sub>3</sub> as the primary corrosion product. Both the introduction of oxygen and an increase in pressure accelerated the steel's corrosion, and the addition of oxygen led to the formation of a new corrosion product, Fe<sub>2</sub>O<sub>3</sub>. Electrochemical test results showed that changes in pressure did not significantly alter the electrochemical corrosion characteristics of the steel, but the introduction of oxygen decreased the electrochemical reaction resistance of X80 steel. Combined with surface analysis, the following conclusions were drawn: In a 50°C supercritical CO<sub>2</sub> environment, the anode reaction of X80 steel corrosion is the active dissolution of iron, while the cathode reaction involves the dissolution and ionization of CO<sub>2</sub>. Changes in pressure do not alter the corrosion mechanism, but the introduction of oxygen leads to oxygen corrosion reactions in the system, accelerating the anode reaction rate and thus increasing the degree of corrosion.

Unraveling the effect of O2, NO2 and SO2 impurities on the stress corrosion behavior of X65 steel in water-saturated supercritical CO2 streams

The stress corrosion behavior of X65 steel in water-saturated supercritical CO2 streams with various impurities was explored. The stress demonstrates a significant acceleration effect on the corrosion, especially the localized corrosion, which mostly depends on impurity type. O2 scarcely raises the SCC susceptibility of X65 steel, whereas SO2 and NO2 greatly enhance its SCC susceptibility due to their strong corrosion effects. The SCC process of X65 steel in SO2-containing environment is dominated collectively by local anodic dissolution, hydrogen embrittlement and stress, while the couple effect of local anodic dissolution and stress plays a leading role in SCC in NO2-containing environment.

Annular corrosion risk analysis of gas injection in CO2 flooding and development of oil-based annulus protection fluid

Abstract To investigate the corrosion behavior of gas-injection well of CO 2 flooding and then to take measures to inhibit the corrosion of casing, firstly an HTHP autoclave and surface characterization technology are applied to analyzing the corrosion behavior of casing and then a new type of oil-based annulus protection fluid has been developed to avoid the casing corrosion issue. The results show that the casing in the simulated supercritical CO 2 -saturated aqueous brine phase (SC CO 2 -saturated aqueous phase) has severe uniform corrosion, while that in the simulated water-saturated supercritical CO 2 (SC CO 2 phase) has severe pitting corrosion. The temperature and CO 2 partial pressure can promote the water film adsorbed on the steel surface, further inducing the corrosion of casing. In order to prevent casing corrosion, an oil-based annulus protection fluid suitable for gas-injection well in CO 2 flooding is developed, and the preparation process of oil-based annulus protection fluid is proposed. The oil-based annulus protection fluid is composed of white oil and 1000 mg/L imidazoline inhibitor. The flash point of the oil-based annulus protection fluid is over 160 °C, the freezing point −23 °C, and the density 0.85 g/cm 3 . The corrosion inhibition rate is more than 80% when P110 steel is in SC CO 2 phase with oil-based annulus protection fluid, and it is more than 95% when P110 steel is in SC CO 2 -saturated aqueous phase. It proves that the newly developed oil-based annulus fluid can effectively solve the corrosion problem of P110 steel as casing in gas-injection well of CO 2 flooding. • Corrosion risk of casing in CO 2 flooding gas well is analyzed. • Preparation method of oil-based annulus protection fluid is established. • A novel oil-based annulus protection fluid for injected gas well in CO 2 flooding is developed.

Unraveling the Effect of O2, No2 and So2 Impurities on the Stress Corrosion Behavior of X65 Steel in Water-Saturated Supercritical Co2 Streams

Unraveling the Effect of O2, No2 and So2 Impurities on the Stress Corrosion Behavior of X65 Steel in Water-Saturated Supercritical Co2 Streams

Effect of Flow Rate on the Corrosion Behavior of API 5L X80 Steel in Water-Saturated Supercritical CO2 Environments

The effect of the water-saturated supercritical carbon dioxide (scCO2) flow rate on the corrosion behavior of API 5L X80 steel at a temperature of 35°C and pressure of 80 bar was investigated. Tests were performed with the samples attached to a rotating shaft inside an autoclave. Results indicate that increasing the scCO2 flow rate had no significant influence on the general/localized corrosion rate under the various dynamic conditions considered. The average general corrosion rate was 0.064 mm/y, while the average measured pitting penetration rates were one order of magnitude higher. The size of the corrosion features on the surface of the samples, which were believed to provide an indication as to the size of the condensed water droplets, was much smaller than the calculated critical droplet size needed to be displaced by the flow, supporting the theory as to why flow rate had little effect on the corrosion response.

Effect of fines migration and mineral reactions on CO2-water drainage relative permeability

CO2-water drainage relative permeability is usually measured in laboratory using a three-stage unsteady-state flooding on cores. This three-stage flooding involves injecting water, then CO2-saturated water, and finally water-saturated supercritical CO2. The injection of CO2-saturated water has been previously found to generate fines due to mineral dissolution. The generated fines can flow with injected fluids and cause pore blockage.This paper examines the effect of fines migration and mineral reactions on CO2-water drainage relative permeability measurements, using a sintered glass core and eight Berea sandstone cores. Three-stage and two-stage flooding are performed on the cores. Three-stage flooding sequence is same as literature. Two-stage flooding involves injection only of water and then water-saturated CO2, to avoid the chemical reactions brought about by CO2-saturated water injection and thereby reduce mineral reactions. Pressure difference across the cores and volumes of water produced are recorded. These data are used to generate CO2-water drainage relative permeability functions.Inductively Coupled Plasma Optical Emission Spectrometry (ICP-OES) analysis of the produced water and Scanning Electron Microscopy (SEM) images of the cores confirm mineral reactions occurred during CO2-saturated water injection in Berea cores. For Berea cores, CO2 relative permeability is reduced (by 21%–48%) during three-stage flooding when CO2-saturated water is injected. The reduction in CO2 relative permeability is found to be a function of water salinity and pore volumes of CO2-saturated water injected. Experiments performed on the glass core suggest that the error in CO2 relative permeability caused by the absence of CO2-saturated water is negligible. Therefore, we propose that CO2-saturated water be omitted during CO2-water drainage relative permeability measurements.

Synergistic effect of O2 and SO2 gas impurities on X70 steel corrosion in water-saturated supercritical CO2

The synergistic effect of O2 and SO2 on the corrosion behavior of X70 steel was evaluated in water-saturated supercritical CO2 using weight loss analysis and surface analysis techniques. Corrosion experiments were conducted at 40°C and 100bar to simulate typical CO2 transportation conditions. Results indicate that the synergistic effects of O2 and SO2 enhance or inhibit the corrosion rate, depending on the concentration variation of impurities. SO2 had the highest corroding influence on X70 steel, with the corrosion rate of 1.10 mm/year with the addition of 500 ppmv SO2. The presence of SO2 changed the corrosion mechanism and the final products of corrosion consisted mostly of FeSO3. Low concentrations of O2 increased the corrosion rate (0.09 mm/year) primarily by destroying the integrity of the FeCO3 product film in the absence of SO2. However, the corrosion rate of X70 steel progressively decreased to 0.03 mm/year as the concentration of O2 increased to 1000 ppmv, due to high concentration of O2 causing the steel substrate to enter the passivation zone. This study is important for a number of industrial applications, as it provides a theoretical basis for corrosion control of supercritical CO2 pipelines.

Effect of microstructure on corrosion of welded joints of X80 steel in water saturated supercritical CO2

Purpose The purpose of this paper is to research whether microstructure varieties of zones at welded joints pose a tremendous effect on its corrosion in SC-CO2. Design/methodology/approach The interrelation between the corrosion and microstructure of base metal (BM), fine grain heat affected zone (FHAZ), coarse grain heat affected zone and weld metal (WM) in welded of X80 steel in water saturated supercritical CO2 was studied by using optical microscope, weight loss test, electrochemical measurements and surface analytical techniques. Findings The all subzones of X80 weld joints were attacked by SC-CO2 corrosion and showed flower-like corrosion scale spots consisted of granular FeCO3. The most severe corrosion appeared at WM due to lower proportion of ferrite to pearlite, but the slightest corrosion displayed at BM. GHAZ with larger grains and more polygonal ferrite exhibited more severe corrosion than that at BM. Due to its smaller grain, FHAZ displayed comparatively more severe corrosion to that at BM. Originality/value There exists close interrelation between the corrosion and microstructure of the welded carbon steel in water saturated supercritical CO2.

CORROSION AND FATIGUE OF HEAT TREATED MARTENSITIC STAINLESS STEEL 1.4542 USED FOR GEOTHERMAL APPLICATIONS

During capture and storage technology (CCS) as well as in geothermal energy production steels need to withstand the corrosive environment such as: heat, pressure, salinity of the aquifer and CO 2 -partial pressure. 1.4542 shows unusual corrosion phenomena, but is still sufficiently resistant in corrosive environments. To better understand its behaviour differently heat treated coupons of 1.4542 and for comparison X20Cr13 and X46Cr13 were kept in the artificial brine of the Northern German Basin at T=60 °C. Ambient pressure as well as p=100 bar for 700 h - 8000 h in water saturated supercritical CO 2 and CO 2 -saturated synthetic aquifer environment was applied. Fatigue tests were performed via push-pull tests with a series of 30 specimens from 150 MPa to 500 MPa (sinusoidal dynamic test loads, R=-1; resonant frequency ~ 30 Hz). FeCO 3 and FeOOH are corrosion products also after dynamic corrosion tests. Martensitic microstructure offers good corrosion resistance in geothermal environment. The S-N-curve showing no typical fatigue strength and very steep slopes of possible fatigue strength for finite life. Possible influencing artefacts, such as Al-inclusions could not be correlated to early rupture despite specimens containing inclusions at the fracture surface and cross section reached lower number of cycles. Applied potential proofed to enhance fatigue life tremendously. Article DOI: https://dx.doi.org/10.20319/mijst.2019.51.138158 This work is licensed under the Creative Commons Attribution-Non-commercial 4.0 International License. To view a copy of this license, visit http://creativecommons.org/licenses/by-nc/4.0/ or send a letter to Creative Commons, PO Box 1866, Mountain View, CA 94042, USA.

Effect of water salinity on permeability alteration during CO₂ sequestration

Fines migration during CO₂ injection into water-saturated rocks causes mineral dissolution and precipitation. We present a careful experimental study to investigate the effect of water salinity on permeability damage during CO₂ sequestration.Core samples were cut from two Berea sandstone blocks for coreflooding images. The core samples were characterized using X-Ray Powder Diffraction (XRD), X-Ray Fluorescence (XRF), and Scanning Electron Microscopy (SEM) analyses. The coreflooding began by injecting a core sample with water having salinity values of 0, 10, 30, or 60 g/L NaCl. Then, CO₂-saturated water was injected to displace the previously injected water. The resulting fluid was then displaced by the injection of water-saturated supercritical (sc) CO₂. Throughout coreflooding, the pressure difference across the core sample was monitored, and produced water samples were collected. After the coreflooding, SEM and energy dispersive X-ray spectroscopy (EDS) analysis was run to generate images that were then registered with the pre-injection images to reveal fines migration. The produced water samples were subjected to measurement of fines concentration and ionic chromatography analysis.During CO₂-saturated water injection, permeability increased for low-salinity water coreflooding (0 and 10 g/L NaCl) and decreased for high-salinity water coreflooding (30 and 60 g/L NaCl). After water-saturated scCO₂ injection, Permeability decrease ranged from 85% for freshwater (0 g/L NaCl) to 20% for high-salinity water (60 g/L NaCl). Fines migration and its consequent mineral dissolution and precipitation determine the core samples' permeability.

Assessing the corrosion product scale formation characteristics of X80 steel in supercritical CO2-H2O binary systems with flue gas and NaCl impurities relevant to CCUS technology

The corrosion product scale formation mechanism of X80 steel in the supercritical (SC) CO2-H2O binary phase containing flue gases and NaCl impurities at 8 MPa and 60 °C was investigated. The formation process of corrosion product scale was significantly different in the SC CO2-saturated aqueous and water-saturated SC CO2 phases. In the SC CO2-saturated aqueous phase, an amorphous product scale was formed initially, then a crystalline product scale was precipitated. The formation process of the corrosion product scale in the saturated-water SC CO2 phase proceeded in just the opposite way. In the water-saturated SC CO2 phase, the inner scale had better protectiveness to the substrate than the outer scale, but it was just the opposite in the SC CO2-saturated aqueous phase. The severity of pitting in the SC CO2-saturated aqueous phase was much greater than the pitting corrosion in the water-saturated SC CO2 phase.

Changes in Corrosion of X70 Steel in Water-Saturated Supercritical CO<sub>2</sub> System Caused by Impurity

During the process of Carbon Capture and Storage, some impurity may be found in the supercritical CO2fluid. The changes in corrosion of X70 Steel in water-saturated supercritical CO2system caused by impurity has been studied by the simulation experiment. The average corrosion rate was got from weight loss measurement. The morphologies and compositions of corrosion products were analyzed by SEM, EDS and XRD. It was observed that the existence of separate impurity would aggravate the corrosion of X70 steel in the water-saturated supercritical CO2system. The average corrosion rate was the highest when NO2or SO2was included, followed by H2S, and the average corrosion rate was the smallest when O2was contained. Among them, X70 steel suffered local corrosion when NO2was contained. The corrosion scale was monolayer structure of FeCO3under the supercritical CO2-H2O system. After the addition of O2, Fe2O3appeared in the corrosion scale, indicating that the oxygen corrosion process occurred. While with the addition of H2S, corrosion scales were double layers. FeS was mainly present in the outer layer. The corrosion process was controlled by CO2and H2S. The corrosion products were mostly FeSO3·xH2O and a spot of FeCO3when SO2was contained. SO2mainly governed the corrosion process. Besides, corrosion product was Fe2O3without FeCO3in the supercritical CO2-H2O-NO2system, NO2completely controlled the corrosion process.

Effect of temperature and pressure on corrosion behavior of X65 carbon steel in water-saturated CO2 transport environments mixed with H2S

The effect of temperature and pressure on corrosion behavior of X65 carbon steel in water-saturated supercritical CO2 containing H2S was studied to determine the role of H2S on the corrosion product formation and corrosion mechanism. Weight loss measurements showed that the highest corrosion rate of 0.190 mm/year was recorded at 35 °C and 8 MPa. The presence of 1000 ppmv H2S resulted in the corrosion products comprised of a double-layer structure in both supercritical and non-supercritical conditions. The results indicated that the presence of 1000 ppmv H2S has significantly influenced on the corrosion mechanisms, corrosion product morphology and composition as well as promoted the precipitation of water based on thermodynamic model.

Corrosion of low alloy steel containing 0.5% chromium in supercritical CO2-saturated brine and water-saturated supercritical CO2 environments

The corrosion behavior of P110 low-Cr alloy steel in supercritical CO2-saturated brine (aqueous phase) and water-saturated supercritical CO2 (SC CO2 phase) was investigated. The results show that P110 steel primarily suffered general corrosion in the aqueous phase, while severe localized corrosion occurred in the SC CO2 phase. The formation of corrosion product scale on P110 steel in the aqueous phase divided into three stages: formation of the initial corrosion layer containing amorphous Cr(OH)3, FeCO3 and a small amount of Fe3C; transformation of initial corrosion layer to mixed layer, which consisted of FeCO3 and a small amount of Cr(OH)3 and Fe3C; growth and dissolution of the mixed layer. Finally, only a single mixed layer covered on the steel in the aqueous phase. However, the scale formed in SC CO2 phase consisted of two layers: the inner mixed layer and the dense outer FeCO3 crystalline layer.

Ab Initio Thermodynamics of Hydrated Calcium Carbonates and Calcium Analogues of Magnesium Carbonates: Implications for Carbonate Crystallization Pathways

Formation of calcium carbonate and its hydrates are important for a wide variety of geological, biological, and technological concerns. Recent studies have determined that formation of anhydrous crystalline calcite, aragonite, and vaterite can involve a complex series of nonclassical pathways in which the hydrated polymorphs monohydrocalcite (CaCO3·H2O), ikaite (CaCO3·6H2O), and amorphous calcium carbonate (ACC) play key roles and in some instances are stable or metastable endproducts. The stages of nucleation and crystallization along these pathways are not well understood, nor is how what is learned in an aqueous environment transfers to CO2-rich conditions. In this work ab initio thermodynamics based on density-functional theory and experimental chemical potentials for H2O-rich and CO2-rich systems are used to determine the stability of calcium carbonate polymorphs as a function of environmental conditions. In water-saturated supercritical CO2, formation of ikaite and monohydrocalcite are both highly e...

Degradation of AISI 630 exposed to CO2-saturated saline aquifer at ambient pressure and 100 bar

In general high alloyed steels are suitable as pipe steels for carbon capture and storage technology (CCS), because they provide sufficient resistance against the corrosive environment of CO2-saturated saline aquifer which serves as potential CCS-site in Germany. High alloyed martensitic steel AISI 630 has been proven to be sufficient resistant in corrosive environments, e.g. regarding heat, pressure, salinity of the aquifer, CO2-partial pressure), but reveals a distinct corrosion pattern in CCS environment. Therefore coupons of AISI 630 heat treated using usual protocols were kept at T=60 °C and ambient pressure as well as p=100 bar up to 8000 h in an a) water saturated supercritical CO2 and b) CO2-saturated synthetic aquifer environment similar to on-shore CCS-sites in the Northern German Basin. AISI 630 precipitates a discontinuous ellipsoidal corrosion layer after being exposed for more than 4000 hours. Best corrosion resistance in the CO2-saturated synthetic aquifer environment phase is achieved via normalizing prior to exposure. In water saturated supercritical CO2 tempering at medium temperatures after hardening gives lowest corrosion rates. Corrosion fatigue via push-pull tests with a series of 30 specimens was evaluated at stress amplitudes between 150 MPa and 500 MPa (sinusoidal dynamic test loads, R=-1; resonant frequency ~ 30 Hz). The endurance limit of AISI 630 is reduced by more than 50% when exposed to CCS environment (maximum number of cycles (10 x 106) at a stress amplitude of 150 MPa).

Effect of impurity interaction on the corrosion film characteristics and corrosion morphology evolution of X65 steel in water-saturated supercritical CO2 system

The corrosion behavior of X65 steel in water-saturated supercritical CO2 system containing NO2 with or without O2, H2S and SO2 impurities was investigated using weight loss measurement and surface analysis techniques. The interactions between NO2 and O2, SO2 or H2S promoted the formation of extra corrosive species and subsequently changed the corrosion film characteristics. In water-saturated supercritical CO2-NO2-O2-SO2-H2S system, FeSO4 and S preferentially formed in the early corrosion stage due to the impurity interactions. As the corrosion time prolonged, (NH4)Fe3(SO4)2(OH)6 and FeOOH formed due to the subsequent reactions of the impurity interaction products, and S disappeared in the corrosion scale via participating in the subsequent corrosion reactions during long-term corrosion. Localized corrosion was initiated by the inhomogeneous precipitation of acid-rich water in the presence of NO2. However, the propagation rate of the corrosion pit in depth direction greatly reduced with time, and the corrosion morphology of X65 steel shifted from localized corrosion towards general corrosion during long-term corrosion.

Assessment of general and localized corrosion behavior of X65 and 13Cr steels in water-saturated supercritical CO2 environments with SO2/O2

To mitigate the corrosive effect encountered in carbon steel pipelines during dense phase CO2 transport the general consensus is that the CO2 stream must be sufficiently dehydrated. Although such a process will undoubtedly help prevent the breakout of free water, it can contribute significantly towards the handling costs, particularly in the context of offshore installations. As opposed to drying the CO2 stream to excessive levels, one alternative option is the application of corrosion resistant alloys such as 13Cr. This paper performs a comparison between X65 carbon steel and 13Cr in pure and impure CO2, evaluating the influence of SO2 and O2 on the general and localized corrosion rate of both materials at 80bar and 35°C. The results show that 13Cr is able to perform exceptionally well in comparison to X65 in pure CO2 as well as when SO2 and O2 are present in the system individually, producing no localized corrosion and general corrosion rates below 0.02mm/y. However, when SO2 and O2 were combined, the formation of sulfuric acid was permitted which proved detrimental to 13Cr, producing excessive localized attack much greater than that observed on X65. Raman spectrosopy, XRD and SEM/EDX are used to analyse the corrosion products.

Unusual Corrosion Behavior of 1.4542 Exposed a Laboratory Saline Aquifer Water CCS-environment

Differently heat treated coupons of 1.4542 were kept at T=60°C and ambient pressure as well as p=100bar for 700h - 8000h in an a) water saturated supercritical CO2 and b) CO2-saturated synthetic aquifer environment similar to on-shore CCS-sites in the Northern German Basin. Surface corrosion layers are homogeneous but unusually discontinuously ellipsoidal. After 8000h at 100bar maximum corrosion rate in the liquid phase is approximately 0.014mm/year, with normalizing providing best corrosion resistance and approximately 0.003mm/year in the supercritical phase where hardening+tempering at 670°C leads to lowest corrosion rates.

Inhibition of N80 steel corrosion in impure supercritical CO2 and CO2-saturated aqueous phases by using imino inhibitors

Steel corrosion has been widely investigated during supercritical CO2 phase with various impurities in carbon capture and storage system; however, the use of inhibitors to suppress steel corrosion has been rarely studied. This work investigated the corrosion inhibition effect of imidazoline and piperazine on N80 steel in water-saturated supercritical CO2 phase and supercritical CO2-saturated aqueous phase with impurities (SO2, NO2, and O2). Results showed that the inhibition efficiency of piperazine increased from 64% to 86% in the aqueous phase when the piperazine concentration increased from 300ppm to 1000ppm. In all cases, the inhibition efficiency in the supercritical CO2 phase was lower than that in the aqueous phase under the same test conditions. By contrast, the inhibition effect of imidazoline was negligible, and severe localized attacks were found within deep pits in supercritical CO2 and aqueous phases. Based on the pH measurement results, piperazine exhibited remarkable neutralization effect and thus could be a potential pH stabilizer. Fe3C possibly resided on the steel surface, and Fe2(SO4)3 was confirmed in the product scale. Nevertheless, steel corrosion inhibition in impure supercritical CO2 phase remains challenging.