Acid Gas Removal Process Research Articles

Reconfiguration of acid gas removal process matching the integration of coal chemical industry with green hydrogen

The focus of the acid gas removal process has shifted from decarbonization and desulfurization to desulfurization in the context of integrating coal chemical technology with green H2 without a water gas shift unit. The conventional Rectisol process, Selexol process, organic amine process, and sulfone-amine process have been reconfigured to form the R-Rectisol process, R-Selexol process, R-MDEA process, and R-Sulfolane-MDEA process to adapt to the shift of acid gas removal target. The removal efficiency of H2S and CO2, process energy consumption, and process cost are investigated to evaluate the technical and economic performance of the above four reconfigured acid gas removal processes. The results indicate that for the R-Recitsol process and R-Selexol process, both high pressure and low temperature increase the relative selectivity of H2S to CO2, thereby enhancing the selective removal of H2S. In contrast, for the R-MDEA process and R-Sulfolane-MDEA process, low pressure and low temperature improve the relative selectivity of H2S to CO2, thereby facilitating the selective removal of H2S. Under optimal operating conditions, the value of relative selectivity of H2S to CO2 of the R-Sulfolane-MDEA process is the largest, and the relative selectivity of H2S to CO2 of the R-Rectisol process, R-Selexol process and R-MDEA process are only 7.64 %, 12.85 %, and 68.40 % of the relative selectivity of H2S to CO2 of the R-Sulfolane-MDEA process, respectively. Compared to the other three reconfigured acid gas removal processes, the R-Sulfolane-MDEA process demonstrates superior advantages in both energy consumption and economic feasibility, provided that the H2S levels remain below 0.1 ppm in purified syngas. This study aims to enhance the decision-making process for gas purification methods in the coal chemical industry by considering integrated green H2 as an alternative to the water gas shift unit.

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.

Multiparameter optimization of the acid gas removal process using self-heat recuperation technology in IGCC system based on genetic algorithm

The acid gas removal (AGR) process in the integrated gasification combined cycle (IGCC) system consumes a large amount of heat and reduces the generation efficiency. Process modification of self-heat recuperation (SHR) technology based on vapor compression heat pumps is expected to reduce the energy consumption of the AGR process. On this basis, this paper conducted a comprehensive and parametric analysis of the AGR process integrated with a vapor compression heat pump. Wherein, two key parameters, the stripper pressure (P1) and the heat pump heat exchanger inlet pressure (P2), were analyzed in detail to understand the energy consumption characteristics of each module of the system. By establishing the optimization objective functions of minimizing system operating cost and exergy loss respectively, the system multi-parameter optimization was conducted based on the genetic algorithm by coding and solving in HYSYS and MATLAB. The corresponding parameter variables for the optimal cases of the two optimization objectives are also comparatively derived. The results showed that P1 mainly changes the SHR capacity of the system by changing the allowable flow rate of the SHR mass under different working conditions, while P2 mainly affects the SHR capacity of the system by changing the heat of the fraction at the top of the stripper. The minimum operating cost of the system decreased to 0.0655 $/kgH2S, which is 1.50 % lower compared to the original case. The minimum exergy loss of the system is reduced from 7788.89 kW to 7398.59 MW, which is about 5.01 % lower than that of the original case.

A comparison between Claus and THIOPAQ sulfur recovery techniques in natural gas plants

A sulfur recovery process is one of the most important processes in the oil and gas industry to get rid of hydrogen sulfide (H2S) which is produced from the acid gas removal process of sour natural gas to convert it into sweet natural gas. Actual data from a gas field is used to obtain a realistic comparison between two sulfur recovery techniques, through which researchers and/or manufacturers can obtain information that will help them choose the most appropriate and cheapest method. A total feed acid gas flow rate of 5.1844 MMSCFD with an H2S concentration of 24.62% by mole percent was produced from amine acid gas removal units. Claus sulfur recovery technique is a traditional chemical process that uses thermal and catalytic reactors. Therefore, an acid gas enrichment unit is applied to increase the H2S concentration to approximately 50% mole to provide reliable and flexible operation in the thermal and catalytic reactors. Moreover, a tail gas treatment unit is applied to increase the overall conversion efficiency to 99.90% with the Claus technique instead of 95.08% without it to achieve high sulfur recovery and reliable operation through the conversion of carbonyl sulfide (COS) and mercaptans. Studies on the safety and simplicity of the Claus technique revealed many important hazards and a large number of transmitters (379) and control loops (128) in one Claus train. THIOPAQ sulfur recovery as a new technology is a biological desulfurization process that uses a natural mixture of sulfide-oxidizing bacteria. It is also a unique H2S removal process with an efficiency of 99.999%. In addition, studies on the safety and simplicity of the THIOPAQ technique have shown that the hazards, the number of transmitters (74), and the number of control loops (29) of a one THIOPAQ train are lower. The THIOPAQ technique showed higher efficiency, was safer, simpler, and had lower CAPEX and OPEX. This study was conducted using Aspen HYSYS V11 and actual data.

Design and analysis for chemical process electrification based on renewable electricity: Coal-to-methanol process as a case study

Electrification of traditional large-scale chemical industry based on renewable electricity can greatly reduce process CO2 emission, and store intermittent renewable electricity into chemical products locally to decrease power grid frequency regulation caused by fluctuating renewable electricity. This study presents a framework for electrification of chemical industry from indirect and direct aspects using the state-of-art coal-to-methanol process as a case study. Traditional coal-to-methanol (Process 1) suffers from high CO2 emission due to mismatch of H/C ratio between coal and methanol. A pulverized coal gasification-integrated SOEC process (Process 2) has been investigated, the water–gas-shift unit is avoided and a simplified acid gas removal process is implemented to replace traditional acid gas removal unit in Process 2. Electric heaters and heat pump system are applied in Process 2 as direct electrification methods to form semi-electrified scenario (Process 3). To discuss the effect of electrification levels on process performances, a fully electrified process (Process 4) is also designed. The results show that: CO2 emissions of the four processes are 2.19, 0.71, 0.52 and 0.63 t/t MeOH, and energy efficiency are 57.40 %, 62.32 %, 64.31 % and 57.63 %, respectively. Production costs are 159.1, 294.3, 301.0 and 358.3 $/t MeOH, IRRs are 14, 31, 29 and 14.5 %, respectively. Through this research and analysis, we hope to explore integration potential of renewable electricity and traditional chemical industry, and design a greener methanol production route based on renewable electricity.

Rate-Based Modeling and Assessment of an Amine-Based Acid Gas Removal Process through a Comprehensive Solvent Selection Procedure

In this study, an industrial acid gas removal (AGR) process which uses amine-based solvents was designed and simulated. The selection of suitable absorbents is crucial for an effective AGR process. Therefore, various single and blended amine-based solvents for capturing acid gases were evaluated through a comprehensive procedure, including solvent screening and process design steps. First, various solvents were screened for their CO2 and H2S absorption efficiencies. Promising solvents were then selected for the process design step, in which all process alternatives were simulated and rigorously designed using Aspen Plus. The non-equilibrium rate-based method with an electrolyte non-random two-liquid thermodynamic model was employed for modeling the absorption column. All processes were evaluated in terms of energy requirements, costs, and carbon emissions. The results show that a blend of methyldiethanolamine and piperazine solutions are the most promising solvents for the AGR process, as they can save up to 29.1% and 30.3% of the total annual costs and carbon emissions, respectively, compared to the methyldiethanolamine + diethanolamine solvent process.

Novel coal-to-methanol process with near-zero carbon emission: Pulverized coal gasification-integrated green hydrogen process

The coal-to-methanol (CTM) is an important technical route for methanol production. The process suffers from high CO2 emission and low energy efficiency due to the mismatch of H/C (hydrogen-to-carbon) ratio between raw coal and products. Hydrogen production from renewable energy can be introduced into the system to meet the H/C ratio. In this paper, a novel CTM process with near-zero carbon emission has been proposed, the direct CO2 emission is decreased from 1.9 to 0.035 t CO2·t−1 MeOH. The novel process avoids requirement of the water-gas shift unit to reduce the production of CO2 from the source, and a novel acid gas removal process is proposed to remove sour gas while ensuring the reduction of CO2 loss. Compared with traditional CTM, CO2 emission intensity, carbon utilization efficiency and energy efficiency of the novel process are 88.87% lower, 130.77% higher, and 39.64% higher, respectively. The novel process is economically feasible when the H2 price is less than 10.36 CNY·kg−1 H2 and the carbon tax is higher than 223.3 CNY·t−1 CO2. This study will enable both economic and environmental route for methanol production in the future and will facilitate future studies on the integration and management of CTM coupled renewable energy.

Sustainability criteria as a game changer in the search for hybrid solvents for CO2 and H2S removal

• Robust multi-criteria screening for CO 2 and H 2 S absorption in water-free solvents. • Polar soft-SAFT validated for a wide range of solvent properties and conditions. • Water-free solvents have a competitive technical edge over aqueous solvents. • Sustainability metrics of water-free solvents calls for greener options. • Holistic solvent evaluation is essential for proper selection. The appearance of hybrid solvents in recent years introduced a potential replacement for aqueous amines for acid gas removal in order to mainly overcome the high energy of regeneration. Yet, the assessment of solvent potentiality remains haphazard with limited information and assessment criteria. In this contribution, we develop and apply a multi-criteria assessment approach built on the use of a molecular-based equation of state, namely, polar soft-SAFT, in combination with sustainability indicators to examine the performance of hybrid solvents for acid gas removal (CO 2 and H 2 S). The first stage of the approach relies on the robust development of the thermodynamic model with available experimental data. Subsequently, with assured fidelity, the model is used in a fully predictive manner to obtain relevant assessment criteria for technical performance evaluation. This is inclusive of standard key performance indicators such as cyclic capacity and energy of regeneration, along with key solvent properties at conditions representative of acid gas removal processes. Additionally, we examine the environmental, health and safety impact of the investigated solvents as a sustainability criteria to select them. This framework has been applied for the first time to six solvents for acid gas removal, including the benchmark solvents aqueous monoethanolamine (MEA) and aqueous diethanolamine (DEA), along with hybrid solvents formulated from chemical solvents such as MEA, or DEA, with physical co-solvents including N-methyl-2-pyrrolidone (NMP), or sulfolane (SFL). The results of the multi-criteria assessment demonstrate that among the six solvents investigated in this work, the overall best performer remains to be the benchmark aqueous MEA. Results also indicate the potentiality of MEA + NMP hybrid solvent in terms of an acceptable compromise between reduced absorption capability and reduced energy of regeneration, compared to aqueous MEA; however, the hybrid solvents fail when applying the sustainability metrics. This work clearly indicates that potential solvents for acid gas removal should be examined following a holistic approach, inclusive of their technical performance and environmental footprint.

New Solvents for CO2 and H2S Removal from Gaseous Streams

Acid gas removal from gaseous streams such as flue gas, natural gas and biogas is mainly performed by chemical absorption with amines, but the process is highly energy intensive and can generate emissions of harmful compounds to the atmosphere. Considering the emerging interest in carbon capture, mainly associated with increasing environmental concerns, there is much current effort to develop innovative solvents able to lower the energy and environmental impact of the acid gas removal processes. To be competitive, the new blends must show a CO2 uptake capacity comparable to the one of the traditional MEA benchmark solution. In this work, a review of the state of the art of attractive solvents alternative to the traditional MEA amine blend for acid gas removal is presented. These novel solvents are classified into three main classes: biphasic blends—involving the formation of two liquid phases, water-lean solvents and green solvents. For each solvent, the peculiar features, the level of technological development and the main expected pros and cons are discussed. At the end, a summary on the most promising perspectives and on the major limitations is provided.

Towards process, environment and economic based criteria for multi-objective optimization of industrial acid gas removal process

Acid gas removal is an important process to meet environmental regulations and protect machinery and pipelines. Non-dominated Sorting Genetic Algorithm-II (NSGA-II) is used to optimize the process considering economic and environmental objectives. The optimization was carried out using excel-based multi-objective optimization (EMOO). Acid gas removal process using dimethyl ethers of polyethylene glycol is optimized considering profit, global warming potential and Human Toxicity. At the same time, the amount of sulfide removed from the gas and that of methane gas recovered also need to be maximized. The trade-offs are investigated by reviewing the effects of the process variables on the objectives. Two-objective cases are considered and the Pareto optimal solutions are obtained. A comparison and a three-objective case was carried out. Two-objective optimization gave better results in all the cases but the three-objective solutions would be more practical, given that industries generally operate around more than two objectives.

Ionic liquid screening for CO2 capture and H2S removal from gases: The syngas purification case

A systematic ionic liquid (IL) screening approach for acid gas removal processes was developed by taking into account a wide range of process performance-determining factors. Selective and non-selective absorption of CO2 and H2S from syngas in conceptual low- and high-temperature processes was investigated to explore the optimal solvents, among 5980 ILs, for each process. Making use of the COSMO-RS and other suitable IL-systems predictive models, the process thermal efficiency (absorption enthalpy and sensible heat) and absorption–desorption working capacity were addressed in the selection of IL candidates along with the primary factors such as solubilities and selectivities. Meanwhile, the COSMO-RS predicted results were validated, and σ-profile and σ-potential of CO2, H2S, H2, CO and the featured ILs were analyzed to provide theoretical insights into intermolecular interactions between gas and IL. The same IL screening method can be extended to CO2 capture and H2S removal from natural gas, biogas, and other sources.

Combined energy consumption and CO2 capture management: Improved acid gas removal process integrated with CO2 liquefaction

Energy management is always facing a trade-off among the constrains of efficiency, energy consumption and CO2 capture rate. For example, the Rectisol wash is a promising and efficient purification process for acid gas removal. However, this process has the problems of high cold energy consumption and low CO2 capture rate. To solve the problems, this paper proposed an improved integrated Rectisol (Int-Rectisol) process with CO2 partial liquefaction. This paper demonstrated how to comprehensively reduce the energy consumption by liquefying part of the CO2 from the treated syngas before absorption. The decreased CO2 concentration in the syngas consequently reduced the methanol solvent consumption and regeneration in the process. Meanwhile, less solvent circulation and regeneration further reduced the energy consumption of the overall process. Process modeling and simulation was conducted in Aspen Plus. The techno-economic performance was then evaluated and compared with the conventional process. The results showed that the solvent circulation in the Int-Rectisol process reduced by 46.5% and the energy consumption decreased from 389.1 MJ to 204.3 MJ for capturing 1 kg of CO2. Meanwhile, the CO2 capture rate also increased from 46.7% to 85%. The exergy analysis showed that the exergy destruction in the Int-Rectisol was 20.95 MW less than the Rectisol process. As for the economic benefit, the Int-Rectisol process reduced the total capital investment and the total product cost by 12.4% and 8.7%, respectively.

Techno-economic analysis of acid gas removal from associated and non-associated sour gas using amine blend

Acid gas removal (AGR) is a critical step in the supply chain of natural gas for its safe transmission and clean combustion. Chemical amines are the most commonly employed commercial solvents for the gas cleaning. Due to energy intensive nature of the AGR process, ways to improve process efficiency are vital. This study investigated the removal of acid gases from the associated and non-associated sour feeds using a blend of diglycolamine (DGA) and methyldiethanolamine (MDEA) solvents at a total strength of 50 wt. %. Steady-state process simulation models have been developed to seek the process improvement by utilization of amine blends. The study performed a detailed energy and economic analysis to understand the feasibility of the investigated amine blends. The results show that when 45 wt. % DGA is mixed 5 wt. % MDEA additive for the processing of associated gas, a saving of 3.42 $/MMSCF of sweet gas produced is achieved. On the other hand, cost per MMSCF of sweet gas increases significantly when DGA additive is mixed with MDEA amine for the processing of non-associated gas.

Towards process, energy and safety based criteria for multi-objective optimization of industrial acid gas removal process

Acid gas removal processes find significance in industries because of the need to meet government regulations regarding the concentration of sweet gas. Also, the fact that the removed H2S can be converted to sulfur by the Claus process and the rising importance of carbon capture increases its importance. Optimization of the process with regards to energy consumption and damage index is among the many cases carried out in this study using evolutionary algorithm, NSGA-II. The process is simulated using ProMax 4.0 which was linked to Excel to conduct the multi-objective optimization cases (EMOO). Hydrocarbon recovery and sulfur removal have also been optimized. Detailed analysis of the two-objective optimization cases is carried out in the study followed by a three-objective case which is then compared with the two-objective cases and the results are reported. With industries operating under more than two objectives, the three-objective case would provide more practical results. A four-objective case optimization study, which combines all the studied objectives, is also carried out for more industrial practical solutions. The decision makers will be able to analyze the Pareto-optimal solutions to determine the preferred operating point.

Techno-Economic Analysis of a Novel Two-Stage Flashing Process for Acid Gas Removal from Natural Gas

Excessive CO2 content will reduce the natural gas calorific value and increase the energy consumption of the regenerator in natural gas desulfurization and decarbonization. This paper uses Aspen HYSYS to model a novel two-stage flash process of acid gas removal process from natural gas. According to the results from the simulation, as well as running experiences in a natural gas processing plant in the middle east, it can be demonstrated that this new process, which has been used in the field of natural gas desulfurization and decarbonization, can meet the requirement of product specifications. Based on the steady state simulation, Aspen HYSYS sensitivity function is used to evaluate influence of key operating parameters, such as the second flash pressure and temperature, on the energy consumption. Compared to the traditional acid gas removal process and acid gas enrichment process, the new two-stage flash acid gas removal process has less energy consumption (2.2 × 109 kJ·h−1). In addition, two-stage flash acid gas removal process also improves the efficiency of acid gas enrichment, while the overall energy consumption is less than combination process of traditional process and acid gas enrichment process.

ATR-FTIR Model Development and Verification for Qualitative and Quantitative Analysis in MDEA–H2O–MEG/TEG–CO2 Blends

A Fourier transform infrared (FTIR) spectroscopy method was developed to identify and quantify various components in an amine-based combined acid gas and water removal process. In this work, an attenuated total reflectance (ATR) probe was used. A partial least-squares (PLS) regression model was also developed using up to four components (methyl diethanolamine (MDEA)-H2O-CO2-ethylene glycol/triethylene glycol (MEG/TEG)), and it was successfully validated. The model was applied on thermally degraded CO2-loaded MDEA blends to predict the weight percentages of MDEA, H2O, CO2, and MEG or TEG to test the performance spectrum. The results confirmed that FTIR could be used as a simpler, quicker and reliable tool to identify and quantify various compounds such as MDEA, MEG/TEG, H2O and CO2 simultaneously in a combined acid gas and water removal process.

Nitrogen Sorption in a Transition Metal Complex Solution for N2 Rejection from Methane

Nitrogen is a ubiquitous impurity in natural gas that has to be removed for the production of liquefied natural gas (LNG). The most widely used technology for N2 rejection, cryogenic distillation, is a capital and energy intensive process. In this work, a nitrogen selective K[RuII(EDTA)] aqueous solution was prepared and tested for nitrogen sorption with the aim of reducing the N2 rejection costs by using a continuous recirculation absorption process analogous to the acid gas removal process in LNG production. The overall equilibrium amount of N2 sorption in the K[RuII(EDTA)] solution was obtained at 20 °C (0.075 mol N2/L solution at 2860 kPa), 30 °C (0.061 mol N2/L solution at 2873 kPa), and 40 °C (0.052 mol N2/L solution at 3049 kPa) using a custom-built volumetric sorption measurement apparatus. The corresponding specific N2 sorption amounts were 0.54 mol N2/mol Ru at 20 °C and 2860 kPa; 0.43 mol N2/mol Ru at 30 °C and 2873 kPa; and 0.34 mol N2/mol Ru at 40 °C and 3049 kPa. These specific N2 sorption a...

Verification of proper operation of dry acid gas removal process on syngas derived by O2/CO2-blown gasifier

Dry syngas purification process was demonstrated on the bench scale test facility comprised of halide removal unit and sulfur removal unit with three fixed bed reactors in which regenerable honeycomb sorbents were installed. The first-ever test of the facility aims to verify the resistance of the zinc ferrite desulfurization sorbent to the carbon deposition in actual syngas condition and proper operation of the cyclic run of the three-reactors system. The test was so challenging that the sulfur removal sorbent was exposed to the severe condition for carbon deposition in the actual syngas derived from oxygen/carbon dioxide blown coal gasifier. The process was operated at 450 °C and 0.98 MPa abs. under the duration of reactor switching of sulfur removal unit of 1 hr for the initial cyclic operation. The dry syngas purification process exhibited sufficient performance of halide and sulfur removal that was evaluated with gas analytical instruments and chemical analysis of the spent sorbent. The sulfur removal unit was operated for the initial cycle of sulfidation, regeneration, and reduction steps without any detrimental effect of carbon deposition. This result encouraged that the process is ready to perform the proper operation in the actual syngas condition during the longer duration of multiple cyclic operation of the bench scale test facility.

IL-Emitsol: Ionic Liquid Based [EMIM][Tf2N] Solvent Process for Selective Removal of CO2 and H2S from Syngas

For the first time, a practical ionic liquid (IL) based acid gas removal (AGR) process for selective removal of CO2 and H2S from syngas was designed, simulated, and optimized in this work. The popu...

Evaluation of dry acid gas removal process on bench scale test facility coupled with syngas produced by O2/CO2-blown gasifier

Dry acid gas removal test facility that comprises of halide and sulfur control units was coupled with O2/CO2-blown gasifier to demonstrate performance and operability of the dry gas purification process for the oxy-fuel IGCC power generation with efficient carbon dioxide separation. The facility was operated for initial five desulfurization cycles of sequential operation of sulfidation, regeneration, and reduction. The duration of each step was fixed to three hours which includes the purge operation to change the gas condition from syngas to oxidative gas, and vice versa. The test facility has the sulfur removal unit equipped with three fixed-bed reactors. Honeycomb shaped desulfurization sorbent that was improved to prevent harmful carbon deposition was installed in those reactors. The cyclic operation results revealed that the unit could reasonably remove sulfur compounds in the sulfidation steps and released the absorbed sulfur during succeeding regeneration steps for the initial five cycles of operation. The spent sorbent did not suffered with carbon deposition and retained their performance on sulfur removal. The absorbed sulfur in the spent sorbent was adequately released in regeneration steps for further operation of desulfurization cycles. The performance and operability of the dry acid gas removal process was successfully demonstrated in the actual syngas operation test.