Impure CO2 Streams Research Articles

Corrosion maps: Stability and composition diagrams for corrosion problems in CO2 transport

We present a Pourbaix-like graphical approach to assess the corrosive nature of impure CO2 streams for carbon capture and storage purposes. The effects of critical N- and S-containing impurities is evaluated. The model behind the approach assumes that chemical equilibrium is established, with some kinetic effects accommodated. The input is the composition of the stream (total quantity of S, N, H and O) and the output is the equilibrium composition (speciation). Comparison with experimental data shows that the content of acids in the CO2 stream upon reaching chemical equilibrium is a strong indicator of the corrosiveness of a given mixture.

A robust Fe-based heterogeneous photocatalyst for the visible-light-mediated selective reduction of an impure CO2 stream.

The transformation of CO2 into value-added products from an impure CO2 stream, such as flue gas or exhaust gas, directly contributes to the principle of carbon capture and utilization (CCU). Thus, we have developed a robust iron-based heterogeneous photocatalyst that can convert the exhaust gas from the car into CO with an exceptional production rate of 145 μmol g-1 h-1. We characterized this photocatalyst by PXRD, XPS, ssNMR, EXAFS, XANES, HR-TEM, and further provided mechanistic experiments, and multi-scale/level computational studies. We have reached a clear understanding of its properties and performance that indicates that this highly robust photocatalyst could be used to design an efficient visible-light-mediated reduction strategy for the transformation of impure CO2 streams into value-added products.

CO[formula omitted] dissociation using a lab-scale microwave plasma torch: An experimental study in view of industrial application

Under laboratory conditions, microwave plasma torches are known to be an energetically very efficient CO2 conversion technology, for pressures ranging from 100mbar up to atmospheric pressure. However, issues relevant for industrial application such as the total energy efficiency, including the power consumption of peripheral equipment, the performance for impure CO2 streams (such as directly from carbon capture facilities) and the stability at long-term operation are usually not addressed. To fill that gap, a lab-scale plasma torch and the corresponding vacuum pump are connected to an energy meter system. Measured wall-plug energy efficiencies yielded values up to 17.9%, corresponding to an electrical power consumption of 19.6kWh per produced Nm3 of carbon monoxide. Experiments with controlled amounts of impurities (Ar, N2, O2, real air and synthetic air) in the feed gas stream are performed. It is shown that small amounts of nitrogen can even increase energy efficiency whereas humidity in the CO2 stream might have an extremely detrimental effect on CO2 decomposition. Finally, a durability test over 29h was performed, demonstrating that microwave plasma torch operation is very reproducible and stable in all figures of merit with short ramp-up times, making it a promising technology for intermittent operation on industrial scale.

Integrated Formation Evaluation for Site-Specific Evaluation, Optimization, and Permitting of Carbon Storage Projects

Participation in over 80 carbon capture and sequestration (CCS) projects spanning 25 years has led to the evolution of a recommended well-based appraisal workflow for CO2 sequestration in saline aquifers. Interpretation methods are expressly adapted for CCS applications to resolve key reservoir parameters, constrain field-scale modeling, provide answers required for the permitting process, and de-risk unique CCS evaluation challenges, such as Storage capacity Injectivity Containment. A challenge complicating all of the above is the eventual impact of three-way interaction among rock matrix, brine, and (impure) CO2 streams. Most logging, sampling, and laboratory techniques are adapted from established domains such as enhanced oil recovery, underground gas storage, and unconventional reservoir evaluation, though some CCS-specific innovation is also needed. Storage evaluation begins with established methods for lithology, porosity, permeability, and pressure, while special core analysis (SCAL) determines CO2 storage efficiency and relative permeability. Containment evaluation spans multiple disciplines and methods: the petrophysicist’s task to quantify seal capacity relies heavily on laboratory analysis, while geologists leverage downhole imaging tools to verify caprock structural/tectonic integrity. Geomechanics engineers define safe injection pressure via mechanical earth models (MEMs) built on advanced acoustic logs calibrated by core geomechanics, wellbore failure observations, and in-situ stress tests. The impact of rock-brine-CO2 interactions is studied via custom SCAL experiments and/or pore-scale digital rock simulations that rigorously represent chemical and thermal processes. Wireline formation tester samples provide representative formation brine as feedstock for SCAL. Water samples also enable operators to prove injection within regulatory limits while establishing baselines for future monitoring programs. Examples applied to recent CCS projects in North America are presented. All of the above data need to be integrated into a CCS model predicting the CO2 plume behavior across the area of interest and within multiple horizons.

Effect of H2O Content on the Corrosion Behavior of X52 Steel in Supercritical CO2 Streams Containing O2, H2S, SO2 and NO2 Impurities

In this study, the corrosion behavior of X52 pipeline steel affected by H2O content in supercritical CO2 streams containing O2, H2S, SO2 and NO2 impurities was investigated by the weight loss test and surface characterization. The corrosion differences of the steel in impure supercritical CO2 streams containing different H2O contents were analyzed. The influence of the variation of H2O content on the corrosion mechanism of steel in the complex impurity-containing supercritical CO2 streams was discussed. The results show that the H2O content limit is 100 ppmv in supercritical CO2 streams containing 200 ppmv O2, 200 ppmv H2S, 200 ppmv SO2 and 200 ppmv NO2 at 10 MPa and 50 °C. The impurities and their interactions significantly promote the formation of corrosive aqueous phase, thereby exacerbating the corrosion of X52 steel. The corrosion process of X52 steel in the environment with a low H2O content is controlled by the products of impurity reactions, whereas the impurities and the products of impurity reactions jointly control the corrosion process of the steel in the environment with a high H2O content.

Unlocking the impurity-induced pipeline corrosion based on phase behavior of impure CO2 streams

This study explored the phase behavior of impure CO2 streams and further unmasked its effects on pipeline corrosion by combing thermodynamic calculation and corrosion test. Thermodynamically, H2S impurity promotes water precipitation via reducing the H2O solubility in CO2. H2S-induced phase distribution changes point to the root cause of H2S-enhanced corrosion. To mitigate the above effects from impure CO2 streams on pipeline steel, we prepared an amorphous Ni–P coating on steel and found that the formation of protective film endows the coating with good corrosion resistance. Hence, more than 80 % of corrosion effects and the localized corrosion are effectively prevented.

Assessment of Fracture Propagation in Pipelines Transporting Impure CO2 Streams

Running fractures are considered as most dangerous catastrophic mode of failure of high-pressure transportation pipelines. This paper describes methodology for coupled modelling of an outflow, heat transfer and crack propagation in pipelines. The methodology is validated and applied to investigate the ductile fracture propagation in pipelines transporting impure CO2 streams to provide recommendations for the fracture control. To assess the propensity of pipelines to brittle fractures, the temperature distribution in the pipe wall in the vicinity of a crack is simulated for various conditions of heat transfer relevant to both overground and buried pipelines.

Does impure CO2 impede or accelerate the onset of convective mixing in geological storage?

We have conducted a linear stability analysis to investigate the effect of impurity in CO2 stream on the onset of convective mixing associated with impure carbon dioxide (CO2) storage in deep saline aquifers. It has been generally thought that injecting impurities such as hydrogen sulphide (H2S) and nitrogen (N2) along with carbon dioxide impedes the buoyancy-driven instabilities resulting in less efficient CO2 solubility trapping. In this work, we have for the first time shown that in contrary to the original thought informed inclusion of an impurity such as H2S has a potential to accelerate the onset of buoyancy-driven instabilities and possibly leading to more effective solubility trapping. This result improves our understanding of the storage of impure CO2 streams in deep saline aquifers and uncovers a new area for further research.

Integrating support vector regression with genetic algorithm for CO2-oil minimum miscibility pressure (MMP) in pure and impure CO2 streams

Accurate knowledge of the minimum miscibility pressure (MMP) is essential in successful design of any miscible gas injection process, particularly in CO2 flooding. It is however well-acknowledged that experimental measurements are expensive, time-consuming, and cumbersome. As a direct consequence, a support vector regression model combined with genetic algorithm (GA-SVR) was proposed to predict pure and impure CO2-crude oil MMP. The accuracy and reliability of the proposed model were evaluated through 150 data sets collected in the open literature and compared with approaches commonly used to estimate the MMP (Lee correlation, Shokir correlation, Orr-Jensen correlation, Yellig-Metcalfe correlation, Alston correlation, Emera-Sarma correlation, Cronquist correlation, Kamari et al. correlation, and Fathinasab-Ayatollahi correlation). The results showed that the proposed model for predicting the MMP is in excellent agreement with experimental data and outperforms all the existing methods considered in this work in prediction of pure and impure CO2-oil MMP. Furthermore, outlier diagnosis was performed on the whole data sets to identify the applicable range of all models investigated in this work by detecting the probable doubtful MMP data.

Subsurface geochemical fate and effects of impurities contained in a CO2 stream injected into a deep saline aquifer: What is known

Geological storage of anthropogenic CO2 captured from large emitters has been identified and demonstrated on a pilot and commercial scale as a viable means for reducing atmospheric CO2 emissions from fossil-fuel based power generation and other industrial processes such as cement and steel making. In particular, CO2 storage in deep saline aquifers has been identified as having the greatest capacity and widest global distribution. Although the captured stream will be “overwhelmingly CO2”, any number of source and/or process associated impurities may be co‑injected, with the potential of additional impurities initially present in the aquifer being incorporated in the plume of stored CO2 post-injection. Impurities may make the injected phase more reactive than pure CO2 and will also change the physical properties of the injected CO2 stream. This paper documents the progress since the IPCC Special Report on CCS in understanding the fate and geochemical effects of these impurities when co-injected in an impure CO2 stream into deep saline aquifers.The presence of inert or non-condensable impurities in the injected CO2 stream, such as Ar, N2 and CH4, will have no or negligible geochemical effects in the subsurface, notwithstanding a reduction in CO2 storage capacity. The presence of acid gases such as SOx (and NOx) will likely have a negative effect particularly in the near-well region due to their tendency to accumulate in acidic forms in the water (and mineral phases) around the injection well. Other impurities that may be present in the CO2 stream, such as O2 and H2S, may or may not have a negative effect, depending on aquifer’s mineral composition. The severity of these effects should be evaluated through appropriate modelling of the impure-CO2/water/rock system. In extreme cases this may impose more severe limitations than those imposed by transportation systems on the type and amount of certain impurities present in the CO2 stream. In general, further development of the work performed to date will continue to yield valuable results dealing with impure-CO2/ aquifer interactions. Future research will benefit from closer integration between the various research communities to better define the myriad chemical environments which may develop due to the injection of impure CO2 streams. Exploration of the post-injection interactions in the vicinity of injection wells is one avenue which should be explored more vigorously.

SO2 impurity impacts on experimental and simulated CO2–water–reservoir rock reactions at carbon storage conditions

Some industrial CO2 streams stored geologically may contain impurities including SO2, O2, and NOX. The impacts of these reactive gases in CO2–water–rock interactions have received limited attention relative to pure CO2 studies. An experimental and geochemical modelling study of reservoir and cap-rock core samples from a potential CO2 storage site in the Surat Basin, Queensland, Australia is described. Reservoir and cap-rock samples were reacted with low salinity fluid saturated with an impure CO2 stream containing 0.16% SO2 at reservoir simulated in situ conditions. This study is relevant to the storage of impure CO2 streams from industrial sources in sandstone reservoirs.Experimentally, dissolution of SO2 from the supercritical gas phase into the aqueous phase showed a kinetic control. The acidification from sulphuric acid generation, and the resulting silicate and carbonate dissolution were generally observed in all experiments. Significant dissolved cation concentrations in solution (up to ~843mg/kg) indicated a higher potential for CO2 trapping, especially from mineralogically reactive core samples. The extent of mineral dissolution was dependent on the rock mineralogy. Precipice Sandstone samples showed the lowest reactivity indicating its suitability as a reservoir unit. However this study indicates the potential for localised changes to water quality in the near wellbore region that necessitate further investigation. Corrosion of the carbonates calcite, siderite and ankerite, and silicates including iron-rich chlorite, plagioclase, and K-feldspar was observed on rock surfaces in potential seal rocks. Calcite cement partially dissolved and acicular gypsum precipitated on the surface of a sandstone formation that could act as a potential secondary sealing unit. The formation of dense sulphates may self-seal some cap-rock. Simulations showed a good history match with the experiments, with the main predicted reactive phases including calcite, ankerite, siderite and chlorite +/− Fe oxides on the time scale of the experiments. Redox potential of the system was important; where oxidised iron was present SO2 oxidation to sulphuric acid was predicted to dominate in the simulations; otherwise pyrite and elemental S formation were also predicted (as observed experimentally). The findings of this study are generally applicable to understanding likely impacts to water quality from impure CO2 injection in CCS sites in Australia and internationally. Data has been provided which may be used to improve longer term modelling predictions.

A new correlation for calculating carbon dioxide minimum miscibility pressure based on multi-gene genetic programming

Miscible gas injection is one of the most efficient enhanced oil recovery (EOR) methods in petroleum industry. Minimum miscibility pressure (MMP) is a key parameter in any gas injection design project. Experimental Measurement of MMP is a costly and time-consuming method; so searching for a quick, not expensive and reliable method to determine gas-oil MMP is inevitable. This paper Present a fast and vigorous method using a new approach based on multi-gene genetic programming (MGGP) to determine carbon dioxide minimum miscibility pressure (CO2 MMP) for carbon dioxide injection processes. Then, new correlations for MMP calculation of both pure and impure CO2 streams using the MGGP, have been developed. Consequently, the MGGP models have been validated and compared with the other conventional model results, to evaluate different techniques. It was founded that the new developed correlations predict accurate values of CO2 MMP compare with the experimental slim-tube CO2 MMP test results, with the lowest average relative and absolute error and also higher correlation coefficient among all evaluated CO2 MMP correlation results.

Accurate Determination of the CO2–Brine Interfacial Tension Using Graphical Alternating Conditional Expectation

A newly developed CO2–brine interfacial tension (IFT) correlation based on the alternating condition expectation (ACE) algorithm has been successfully proposed to more accurately estimate the CO2–brine IFT for a wide range of reservoir pressure, temperature, formation water salinity and injected gas composition. The new CO2–brine correlation is expressed as a function of reservoir pressure, temperature, monovalent cation molalities (Na+ and K+), bivalent cation molalities (Ca2+ and Mg2+), N2 mole fraction and CH4 mole fraction in injected gas. This prediction model is originated from a CO2–brine IFT database from the literature that covers 1609 CO2–brine IFT data for pure and impure CO2 streams. To test the validity and accuracy of the developed CO2–brine IFT model, the entire dataset was divided into two groups: a training database consisting of 805 points and a testing dataset consisting of 804 points, which was arbitrarily selected from the total database. To further examine its predicted capacity, the...

Factors affecting the chromatographic partitioning of CO2 and H2S injected into a water-saturated porous medium

Acid gas comprising 98% CO2 and 2% H2S has been injected since 2002 in a depleted gas reservoir in Alberta, Canada, that has 20% water saturation. Carbon dioxide broke through first at producing wells, while H2S broke through after CO2. It was hypothesized that the delayed breakthrough of H2S was due to its greater solubility in reservoir water than that of CO2. Static laboratory experiments at in-situ conditions confirmed the higher solubility of H2S in brine than that of CO2. The solubility of the injected gas seems to increase linearly with the mole fraction of H2S in the gas stream; however, due to preferential H2S solubility, the dissolved gas has a greater proportion of H2S than CO2 compared with the injected gas. Dynamic laboratory experiments of the flow of CO2 containing H2S through a 24 m long coil tube packed with silica sand and saturated with brine at in-situ conditions of pressure and temperature have shown that the higher solubility of H2S in contrast to that of CO2 results in suppressed H2S concentrations at the leading edge of the breakthrough gas phase at outlet. Additional laboratory experiments with variable composition of the injected CO2 and H2S stream, and different conditions of temperature, pressure and water salinity have shown that these factors affect the breakthrough of the two gases and the time lag between them. Subsequently, the laboratory experiments were replicated using a compositional numerical simulator. Sensitivity analysis of the numerical simulations has shown that the CO2 and H2S breakthrough at the outlet is affected also by factors affecting the length of the twophase region such as medium relative permeability and flow direction with respect to gravity. Dispersion does not affect the timing of the gas breakthrough, but reduces the lag between the CO2 and H2S breakthrough. The results of these laboratory and numerical experiments should impact injection and monitoring strategies for impure CO2 streams.

Correlation of Minimum Miscibility Pressure for Impure CO2 Streams

Correlation of Minimum Miscibility Pressure for Impure CO2 Streams

CO2 Minimum Miscibility Pressure: A Correlation for Impure CO2 Streams and Live Oil Systems

Abstract This paper presents an empirically derived correlation for estimating the minimum pressure required for multicontact miscible (MCM) displacement of live oil systems by pure or impure CO2 streams. Minimum miseibility pressure (MMP) has been correlated with temperature, oil C5+ molecular weight, volatile oil fraction, intermediate oil fraction, and composition of the CO2 stream. The effects of temperature and oil C5+ molecular weight on pure CO2 MMP have been well documented. However, CO2 sources are rarely pure, and solution gas usually is present in reservoir oils. The correlation presented in this paper accounts for the additional effects on MMP caused by the presence of volatile components (methane, C1; and N2) and intermediate components (ethane, C2; propane, C3; butane, C4; hydrogen sulfide, H2S; and CO2) in the reservoir oil. This correlation also is capable of estimating MMP for a contaminated or enriched CO2 stream on the basis of the pure CO2 MMP.

Effects of Impurities on Minimum Miscibility Pressures and Minimum Enrichment Levels for CO2 and Rich-Gas Displacements

Abstract Multicontact miscible displacement processes are becoming increasingly popular as a means of recovering secondary and tertiary oil reserves in the U.S. and Canada. Economics of multicontact miscible flooding are governed to some extent by the availability of large sources of high purity CO2 or suitable liquefied petroleum gas (LPG) streams. This is because achievement of miscibility depends on the solvent composition as well as the system temperature and pressure. Atypical components in a CO2 or solvent stream therefore may increase the required pressure or enrichment levels for achievement of miscibility. Several papers have been published discussing the pressure (for CO2) and composition (for rich gas) levels required for miscible displacement. The potential CO2 supply could be increased if complicated cleanup procedures for injected and produced fluids were not required. For engineering studies it is important that CO2 streams containing H2S and hydrocarbons be evaluated for their miscible flooding potential. It is also important to evaluate the effects of CO2 and C5 + components in rich gas mixtures to determine whether they can be used to reduce calculated enrichment levels for solvent systems. This paper presents results of studies using mixtures of CO2, H2S, and C1, CO2-LPG, and rich gas solvents containing CO2 or C5 to displace oil miscibly in slim-tube experiments. The purpose of this work is to show the effects of various components on pressure and compositions required for miscibility. As expected, the changes in CO2 miscibility pressure are direct functions of temperature. It is reported that the addition of H2S and C2+ hydrocarbons lowers the miscibility pressure for CO2, whereas the presence of C1 in a CO2 solvent increases it. More important, the results give a quantitative titative measure of the degree of reduction/elevation in miscibility pressure to be expected with impure CO2 streams. The paper also presents similar results from displacements with typical rich gas solvents mixed with CO2 and/or C5. It is reported that CO2 increases the minimum enrichment required, while a heavier hydrocarbon component actually can reduce anticipated enrichment levels.