CO2 H2S Research Articles

Development of a selective sequential process for H2S enrichment and CO2 capture in aqueous MDEA solutions

The typical acid gas removal process can simultaneously remove acid gases from the raw gas using an aqueous MDEA solution. But it cannot further separate and capture hydrogen sulfide and carbon dioxide, and increases the burden on subsequent processing. Recovering carbon dioxide from that not only increases the H2S content in the acid gas, but also achieves the CO2 capture. To realize these, acid gas enrichment and carbon dioxide capture are integrated into the typical acid gas removal process. In this study, a novel selective sequential process in aqueous MDEA solutions is proposed for H2S enrichment and CO2 capture. And an optimization framework is proposed to optimize the parameters of the whole process, mainly to improve the efficiency of the column equipment. It is found that small diameter column is suitable for enhancing selectivity and large diameter column is suitable for maximizing productive capacity. To demonstrate the performance of the proposed process, the evaluation results, carbon sulfur ratio (3.81), return on investment (6.26) and carbon dioxide capture ratio (−0.63) are obtained from technical, economic and environmental evaluations. In comparison with the typical process, the novel process can achieve H2S enrichment and CO2 capture while remaining economically viable. This study presents a method for collaborative removal of H2S and CO2 in acid gas removal process. It is advantageous to reduce carbon dioxide emissions.

Hydrothermally synthesized nanostructured NiTiO3 thick films for H2S and room temperature CO2 gas sensing

Hydrothermally synthesized nanostructured NiTiO3 thick films for H2S and room temperature CO2 gas sensing

Alumina-based ceramic coatings obtained by the SHS process for high temperature corrosion and wear protection of steel tubulars

Ceramic coatings have much potential for steel tubulars' protection against high temperature corrosion of gases and liquids, often containing abrasive solid particles, and to enhance their integrity in severe power generation, mineral and oil & gas production environments. Combining self-propagating high-temperature synthesis (SHS) with high-speed centrifugal process, alumina-based coatings were produced onto the inner surface of tubulars for these applications. According to the developed SHS batch formulation and the designed centrifugal device and process, well-consolidated composite ceramic layers with a thickness of 1.5–3 mm have been obtained. The developed SHS process does not create hazardous gases, and it takes ∼30 s for the ceramic phase formation. A high-level compaction due to centrifugal forces and a liquid phase sintering approach provided a dense gradient ceramic structure formed by oxide grains cemented by a glassy phase and bonded with a steel substrate through a thin iron layer. The coatings were successfully produced onto the inner surface of carbon and stainless steels’ tubes of up to 12 ft-lengths and standard dimensions from 2 to 3/8″ to 7.5” OD. The coatings were tested, for the first time, in wear and high-temperature corrosive environments, e.g., in steam–H2S–CO2 gases and molten salts, with encouraging results due to high contents of Al2O3 and some other oxides and consolidated ceramic structure. They can be recommended for applications in high-temperature (900 °C and greater) corrosive environments and erosive flows.

Formation integrity evaluation for geosequestration of CO2 in depleted petroleum reservoirs under cyclic stress conditions

The geological storage of carbon dioxide (CO2), also referred to as CO2 geosequestration, represents one of the most promising options for reducing greenhouse gases in the atmosphere. However, most of the time, CO2 is captured with small amounts of other industrial gases such as sulphur dioxide (SO2) and hydrogen sulphide (H2S), which might be compressed together and stored in depleted petroleum reservoirs or aquifers. Moreover, during CO2 geosequestration in reservoirs, pressure variations during injection could force some amount of CO2 (with or without other acid gas impurities) into the caprock; thereby, altering the petrophysical, geochemical, and geomechanical properties of the caprock. Thus, the brittleness index of the reservoir and caprock might be impacted during CO2 geosequestration due to the chemical reactions between the rock minerals and the formation fluid. Furthermore, to meet the world net-zero carbon target, the promotion of CO2 utilization is paramount. This could be possible by developing an effective technology for cyclic CO2 geosequestration (with or without gas impurities). Therefore, studies on the co-injection of CO2 with other acid gases from industrial emissions, their withdrawal from the porous medium, and their impact on reservoir and caprock integrity are paramount. In this study, a dual-tubing string well completion technology was designed for cyclic injection and withdrawal of CO2 (with or without another acid gas), and numerical simulations were performed using TOUGHREACT codes, to model the cyclic process and investigate the co-injection of SO2 and H2S (separately) with CO2 in sandstone formations overlain by shale caprock. A novel technique of converting the volume fraction of minerals to their weight fraction was developed in this study, to evaluate the brittleness index of the sandstone reservoir and shale caprock during CO2 geosequestration. The findings of the study indicate that the porosity and permeability increase for the CO2 only and CO2–H2S injection cases, in the shale caprock; while for the CO2–SO2 injection case, porosity and permeability only decreased in the layers of the shale caprock contacted by SO2 and due to anhydrite precipitation. In all the injection cases, the porosity and permeability of the sandstone reservoir decreased in a few layers directly below the perforation interval of the production zone. However, in other regions in the sandstone reservoir, the porosity and permeability increased for the CO2 only and CO2–H2S injection cases. In contrast, for the CO2–SO2 co-injection case, porosity and permeability decreased in the layers of the sandstone rock contacted by SO2. In all the CO2 geosequestration cases, the brittleness of the shale and sandstone rocks investigated decreased slightly, except in the CO2–SO2 co-injection case where the brittleness of the sandstone rock decreased significantly. Based on the mineralogical composition of the formations in this study, co-injection of SO2 gas with CO2 gas, only decreased the brittleness index of the shale caprock slightly, but significantly decreased the brittleness of the sandstone reservoir.

A novel material selection method and application in an aqueous environment containing CO2, H2S, O2 and SO2

The corrosion in the aqueous environment of CO2–H2S–O2–SO2 is extremely severe, causing frequent failures of pipeline and posing a challenging issue for material selection. This paper drew on excellent standards and past experiences to provide a suitable method for selecting materials. The method consisted of four components: standard primary selection, corrosion evaluation selection, mechanical property selection, and economic final selection. A case study demonstrated that the applicable materials for the environment (total pressure of 1.5 MPa, temperature of 30–120 °C, H2S content of 0.1–1.5%, CO2 content of 8–55%, SO2 content of 0–0.00015% and O2 content of 1–3%) were composed of 2Cr13 or 316L. Additionally, the main control factors for corrosion rate were ranked as follows: O2 > H2S > temperature > CO2 > SO2. And a reduction in mechanical properties was observed for 2Cr13, 316L, and 825 after corrosion.

The influence factors of dielectric barrier discharge plasma to production of syngas derived from H2S-CO2 acid gas

H2S and CO2, two harmful acid waste gases, often co-exist in important chemical production such as coal-chemical industry, natural gas chemical industry and petrochemical industry, causing corrosion of industrial equipment and pipelines, and must be treated innocuously. Co-conversion of H2S-CO2 mixed acid gas to syngas has been carried out using dielectric barrier discharge (DBD) plasma-catalysis, which renders the highly corrosive and toxic H2S and greenhouse gas CO2 harmless, and produces syngas. The effects of various parameters of the DBD plasma on the reaction of one-step conversion of H2S-CO2 to syngas were studied. Moreover, a comparative study of the different parameters of DBD plasma was carried out. The intrinsic correlation between the reaction performance of syngas production via H2S-CO2 conversion and these parameters, including specific energy input (SEI), discharge shape, discharge frequency, discharge gap and discharge length, was investigated and revealed. On this basis, a multi-tube parallel DBD plasma reaction system was designed and constructed.

Assessment of ternary CO2 mixtures as working fluids in supercritical Brayton cycles with floating critical points

The performance of the supercritical CO2 (sCO2) Brayton cycle deteriorates due to the mismatch between critical temperature and cold source temperature. An innovative solution based on ternary CO2 mixtures with adjustable compositions is proposed to expand the variation range of the critical temperature. An in-house MATLAB code is developed to investigate the design-point performance of the proposed system. The results indicate that the effect of improving cycle efficiency by using the modified floating critical point method becomes increasingly significant as the target critical temperature deviates from that of CO2. The CO2–H2S–Kr is screened out as the best ternary mixture, with the cycle efficiency being increased by over 8 % compared to the sCO2 cycle at very high (45 °C) and low (−15 °C) temperatures. The long-term performance is also evaluated based on the hourly historical weather data of two typical climate regions. The annual performance depends on both the average value and the distribution characteristics of the local ambient temperature. A relative improvement in annual average efficiency of 7%–9.56 % can be obtained depending on the regions. The present work is helpful to make the supercritical Brayton cycle give full play to its efficiency advantage in a wide cold source temperature range.

Fluid Regime of Crystallization of the Calcite–Quartz Carbonatitoids of the Murun Massif

Abstract —Primary melt and fluid inclusions in quartz and dalyite of calcite–quartz carbonatitoids of the Murun massif have been studied. They contain CO2, N2, CH4, C2H6, C3H8, H2, and H2S as well as sulfates and hydrocarbonates as solid daughter phases. The inclusion solutions contain HS- and chlorides. In addition, disordered carbon and bitumen are present. It is concluded that the magmatic fluid phase that was in equilibrium with quartz was characterized by a predominantly H2O–CO2–H2S composition and a reduced state. This explains the appearance of sulfides at the magmatic stage of crystallization of calcite–quartz carbonatitoids of the Murun massif. We substantiate the hypothesis that the sulfates, hydrocarbons, and H2 detected in the inclusions form at decreasing temperature as a result of shift of the redox equilibrium.

Monitoring and Preventing Failures of Transmission Pipelines at Oil and Natural Gas Plants

In recent years, the increase in energy prices and demand has been driven by the post-pandemic economic recovery. Of the various energy sources, oil and natural gas remain the most important source of energy production and consumption after coal. Oil and gas pipelines are a key component of the overall energy infrastructure, transporting oil and gas from mines to end users, so the reliability and safety of these pipelines is critical. The oil and gas industry incurs large expenses for the removal of failures related to, among others, corrosion of pipelines caused by the presence of Hg, CO2 H2S, carbonates and chlorides in reservoir waters. Therefore, pipeline operators must constantly monitor and prevent corrosion. Corrosion failure losses are a major motivation for the oil and gas industry to develop accurate monitoring models using non-destructive NDT methods based on test results and failure frequency observations. Observing the locations of frequent pipeline failures and monitoring and applying corrosion protection to pipelines play an important role in reducing failure rates and ultimately increasing the economic and safety performance of pipelines. Monitoring and prevention efforts support the decision-making process in the oil and gas industry by predicting failures and determining the timing of maintenance or replacement of corroded pipelines. We have presented methods of prevention through the use of corrosion inhibitors in crude oil and natural gas transmission pipelines, as well as various factors that influence their application. In this article, a review of corrosion rate monitoring systems is conducted, and a range of control and monitoring scenarios is proposed. This knowledge will aid scientists and practitioners in prioritizing their policies, not only to choose the appropriate monitoring technique but also to enhance corrosion protection effectiveness.

Investigation of oxy-fuel combustion for methane and acid gas in a diffusion flame

Co-combustion of methane (CH4) and acid gas (AG) is required to sustain the temperature in Claus reaction furnace. In this study, oxy-fuel combustion of methane and acid gas has been experimentally studied in a diffusion flame. Three equivalence ratios (ER = 1.0, 1.5, 2.0) and CH4-addition ratios (CH4/AG = 0.3, 0.5, 0.7) were examined and the flame was interpreted by analyzing the distributions of the temperature and species concentration along central axial. CH4-AG diffusion flame could be classified into three sections namely initial reaction, oxidation and complex reaction sections. Competitive oxidation of CH4 and H2S was noted in the first section wherein H2S was preferred and both were mainly proceeding decomposition and partial oxidation. SO2 was formed at oxidation section together with obvious presence of H2 and CO. However, H2 and CO were inclined to be sustained under fuel rich condition in the complex reaction section. Reducing ER and increasing CH4/AG contributed to higher temperature, H2S and CH4 oxidation and CO2 reactivity. Hence a growing trend for CH4 and AG to convert into H2, CO and SO2 could be witnessed. And this factor enhanced the generation of CS2 and COS in the flame inner core by interactions of CH4 and CO2 with sulfur species. COS was formed through the interactions of CO and CO2 with sulfur species. The CS2 production directly relied on reaction of CH4 with sulfur species. The concentration of COS was greater than CS2 since CS2 was probably inhibited due to the presence of H2. COS and CS2 could be consumed by further oxidation or other complex reactions.

Off-design performances of a dry-cooled supercritical recompression Brayton cycle using CO2–H2S as working fluid

Off-design performances of a dry-cooled supercritical recompression Brayton cycle using CO2–H2S as working fluid

Thermodynamics analysis of the supercritical CO2 binary mixtures for Brayton power cycles

Supercritical CO2 Brayton-based cycles are a promising technology for concentrated solar power plants. Their high efficiency can be improved by using CO2 mixtures as working fluid instead of pure CO2. This work studies 3 cycle topologies: simple recompression (RCC), recompression with main compressor intercooling (RCMCI) and partial cooling recompression (PCRC), across a range of regenerator conductance (UA), compressor and turbine inlet temperatures. Each topology is simulated with different working fluids: CO2, CO2–NH3, CO2–SO2, CO2–COS and CO2–H2S. The influence of the working fluid, operating conditions and cycle irreversibility on the overall efficiency has been analyzed in depth, finding two interesting, opposing trends. The mixtures with higher critical pressure improve the heat absorption and rejection temperatures of the cycles, but also increase irreversibility. The combination of topology and mixture that achieves the best compromise between both trends will have the higher efficiency. In general, using RCMCI instead of PCRC or RCC can improve efficiency by up to 4% depending on the working fluid and operating conditions. Using a mixture instead of pure CO2 by up to near 3%.

Supercritical CO2 mixture Brayton cycle with floating critical points for concentrating solar power application: Concept and thermodynamic analysis

A novel concept of supercritical Brayton cycle with floating critical points is proposed to cope with the rapid deterioration of cycle performance at high heat sink temperatures. By coupling the power cycle with a distillation based composition tuning subsystem, the circulating mixture composition in the cycle can be altered dynamically to obtain the desired critical points at various ambient temperatures, thereby leading to a better match between the cold-end parameters of power cycle and the heat sink conditions. A thermodynamic model is established for the proposed novel system based on a recompression layout with single stage reheating. Four binary mixtures, including CO2–H2S, CO2–Butane, CO2–Isobutane, and CO2–Butene are employed. Simulation results indicate that an increasingly larger improvement in cycle efficiency compared to the pure CO2 cycle can be obtained as the ambient temperature increases from 20 to 50 °C. When the composition tuning process is not considered, the CO2–H2S cycle shows the best performance among the four mixture cycles, with an improvement between 1.3% and 7.4% being achieved over the entire temperature range. Several feasible schemes for composition tuning subsystem are proposed and compared in terms of energy consumption. Finally, the hourly efficiencies of the integrated system are evaluated based on typical daily weather conditions, with a piecewise control strategy for critical points. It is found that although the use of CO2–H2S causes relatively high energy consumption for distillation, a significant improvement in the daily average thermal efficiency of the integrated system can still be achieved, with efficiency being increased by 3.5%-5.1% in comparison with pure CO2 cycle on hotter days.

Screening of Pure ILs and DESs for CO2 Separation, N2O Separation, and H2S Separation Processes

Ionic liquids (ILs) are proposed as potential “green” solvents with remarkable properties. Deep eutectic solvents (DESs) are a new type of ILs with additional properties, such as higher biodegradability and a lower price. ILs and DESs are “green” absorbents for various gas separations, such as CO2/N2, CO2/H2/CO, H2S/CH4, and N2O/N2. Due to their large number, the screening of ILs is crucial. Although ILs with high absorption capacities were screened using gas solubility and selectivity, it is important to consider the energy and solvents used in the process. In this paper, the absorbent amount and the energy consumption were used for screening absorbents for various gas separation processes. The results reveal that physical IL [Bmim][DCA] and chemical IL [Eeim][Ac] are screened for CO2/N2 and CO2/H2/CO separation, physical IL [Omim][PF6] for H2S/CH4 separation, and physical IL [P66614][eFAP] for NO/N2 separation. The screened ILs offer some advantages over commercial absorbents in terms of lower energy consumption or amount.

Simultaneous inhibition of natural gas hydrate formation and CO2/H2S corrosion for flow assurance inside the oil and gas pipelines

Compatibility problems are observed during the co-injection of corrosion and gas hydrate inhibitors inside oil and gas pipelines, which reduces their performance. In this study, the newly synthesized dual-purpose inhibitors (DPIs) were developed to overcome the compatibility challenge between the inhibitors. A detailed experimental and computational study was performed to investigate the inhibition activity of DPIs. The results of constant cooling experiments showed that the inhibitors significantly prevented natural gas hydrate formation. DPI2 with a propyl pendant group was the best sample by providing a subcooling temperature of 18.1 °C at 5000 ppm. DPI1 and DPI3 decreased gas consumption by 2.6 and 2.4 times, respectively, compared to pure water. In addition, molecular dynamics simulation revealed that the transportation of gas molecules to the growing hydrate cages was disrupted due to DPI2 adsorption on the surface of the hydrate, which partially covered it and acted as a mass transfer barrier. Furthermore, the interaction of the anion part of the inhibitor with the nearest neighbor water molecules lowered the water activity to form the hydrogen-bonding networks for the hydrate formation. According to corrosion measurements, DPIs suppressed the corrosion rate of mild steel in H2S–CO2 saturated oilfield-produced water, and a maximum inhibition efficiency of 96.3% was obtained by adding 1000 ppm of DPI2. Moreover, the estimated adsorption energy of DPI2 were relatively high and matched with experimental data, implying that the inhibitor has a high degree of adsorption on the metal for forming a protective layer on the mild steel surface. These findings signified that DPIs provide a potential hybrid inhibition of corrosion and gas hydrate formation for flow assurance applications and reduce the operation costs.

Primary Corrosion Cause of P110S Steel Tubing Corrosion Thinning in CO2–H2S Well and Its Remaining Life Prediction

To investigate the tube thinning of gas wells in the northwestern oilfield, the failed tubing was analyzed by using material property testing, SEM, EDS, and XRD. A novel model that was specific to the service life of tubing in terms of the wall thickness of tubing was established. The model is based on the circumferential stress of tubing. The safety factor against internal pressure and corrosion rate are considered in the model. Our results make clear that the chemical composition, non-metallic inclusion, hardness, and tensile strength of the pipe meet the requirements of relevant standards. The corrosion products on the inner and outer wall of the tubing are mainly FeCO3 and BaSO4, while CaCO3 exists in the outer wall. Additionally, we prove that the corrosion process of the failed tubing is CO2 corrosion. The tubing under the packer suffers from water-accumulation corrosion, and the tubing above the packer suffers from water-carrying corrosion. It is observed that the failed tubing arises under-deposit corrosion in local areas. According to the model calculation, the safe service life of tubing above the packer is 20.6 years. However, the safe service life of tubing below the packer is only 4.9 years.

Comparison of 3%-Cr steel and carbon steel corrosion behavior as well tubing materials in CO2–H2S environment

This study provides two case studies involving carbon steel and 3%-Cr steel exposed to a CO2–H2S environment with a moderate scaling index. The carbon steel tubing show shows pitting and severe corrosion, whereas the 3% chromium steel tubes are undamaged. XRD results showed that the chromium-rich layer did not alter scaling on both tubes. Investigations using SEM and EDS reveal the formation of a dense and compact layer in the 3%-Cr steel, which serves to resist corrosion. In contrast, carbon steel has a porous structure and is easily detachable due to wall shear stress caused by slug movement. In 3%-Cr steel, the EDS analysis reveals a compact layer with a significant number of chromium, which is an indication of a Cr-rich iron oxide layer. Potentiodynamic polarization shows that the anodic curve is shifting, which means that the rate of corrosion is slowing down. This study shows that 3% Cr steel is a good choice for a mixed CO2–H2S environment with a high total dissolved solid (TDS).

Corrosion main control factors and corrosion degree prediction charts in H2S and CO2 coexisting associated gas pipelines

The pipeline corrosive environment in T oil field contains H2S and CO2, with 96 corrosion perforations. OLGA software was used to simulate the internal flow environment. Combined with Pearson correlation coefficient analysis method and the Apriori algorithm, the association rules between corrosion rate and main corrosion control factors were determined. The results show that corrosion perforation of associated gas pipelines mostly occurred at the effusion in low-lying and climbing sections. Corrosion in the associated gas pipelines were strongly related to liquid velocity and holdup, and moderately related to temperature, H2S partial pressure and CO2 partial pressure. 10 association rules with confidence ≥90% between main corrosion control factors and corrosion rate were mined. Finally, the three kinds of corrosion evaluation charts parameters: liquid velocity & holdup, temperature & PCO2/PH2S and liquid velocity & PCO2/PH2S were established respectively.

The high-temperature mechanical properties of HS110S steel and its corrosion behaviors in harsh downhole environment

PurposeThis paper aims to investigate the high-temperature mechanical properties of HS110S steel and its corrosion behaviors in harsh downhole environment.Design/methodology/approachIn this work, mechanical property measurements were carried out from 25°C to 350°C and the scanning electron microscopy was used to observe the fracture morphology. The weight-loss measurements and surface characterization were used to evaluate the corrosion resistance of HS110S steel in harsh downhole environment.FindingsResults show that the yield strength and tensile strength of HS110S steel at 350 °C are 779 and 861 MPa, respectively. Compared with room temperature, the reduction rate values are both less than 20%. At the high-temperature corrosion environment (350 °C), the static and dynamic corrosion rates are 0.9668 and 1.9236 mm/a, respectively. The generated corrosion products are mainly composed of FeSx, FeCO3 and Fe3O4. Therefore, the HS110S steel applied under such conditions needs to take suitable protective measures.Originality/valueIn general, the HS110 steel has widely used in conventional development conditions (e.g. low H2S or high CO2 environments). However, to the best of the authors’ knowledge, no studies have reported on its application at more than 250°C. Therefore, this work can be a reference to the application of HS110S steel in high-temperature corrosion conditions.

Environmentally benign methane-regulated catalytic desulfurization

Hydrodesulfurization is well established in the industry while costly and environmentally unfriendly due to CO2 emissions and H2S production. An alternative, cost-effective desulfurization process remains unreported. Here, we demonstrate a desulfurization process for dibenzothiophene, one of the most well-known and recalcitrant sulfur-containing model compounds against catalytic desulfurization, under the regulation of methane instead of hydrogen over a combination of two catalysts, generating a new sulfur-containing product, CS2, as an important intermediate in organic chemistry and non-polar solvent with lower environmental impact than H2S. A catalytic mechanism is proposed and supported by extensive experimental and computational evidence. It is discovered that methane acts as a critical initiator and intensifies the direct desulfurization pathway, where two catalysts must work cooperatively and a surface sulfur transfer process is indispensable. This study explores an alternative desulfurization route with unique reaction pathways towards CS2 formation, whose practical potential is also supported by the desulfurization performance over a series of real-world crude samples.