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Sour gas reservoirs and sulfur-removal technologies: A collection of published research (2009–2015)
Journal of Natural Gas Science and Engineering 26 (2015) 1485e1490
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Journal of Natural Gas Science and Engineering journal homepage: www.elsevier.com/locate/jngse
Sour gas reservoirs and sulfur-removal technologies: A collection of published research (2009e2015) 1. Introduction
2. Sour gas reservoirs
This article serves as the introduction and overview to the Journal of Natural Gas Science and Engineering's virtual special issue (VSI) concerning Sour Gas Reservoirs and Sulfur- Removal Technologies, compiled in July 2015 (Zhang & Wood, 2015). This JNGSE VSI collects 35 articles reporting diverse topics related to sour gases that were published by Journal of Natural Gas Science and Engineering since the start of 2009. Each article included in the compilation represents a stand-alone analysis and research on a relevant topic that has passed the journal's rigorous peer-review editorial system. Collectively, these articles provide key insight to the progress being made towards better understanding of removal of sour gases and other components in gas streams using different techniques, sour gas reservoirs, and corrosion and safety issues in sour gas sweetening plants. The published articles compiled in this virtual special issue provide a useful synthesis of progress made in recent years in several diverse research areas pertaining to sour gas. The articles compiled are classified into eight distinct categories:
Guo et al. (JNGSE, 2015, 22, 371e376) investigated the prediction of sulfur saturation based on non-Darcy flow. The effects of reservoir compaction, gas properties, the dependence of sulfur solubility on pressure, and sulfur deposition on gas-well deliverability were studied. They claimed that the rate of sulfur deposition was underestimated by Roberts' Model, and their modified model was more accurate and practical in predicting sulfur deposition. Reservoir compaction should be considered in sulfur deposition predictions as it leads to a faster rate of sulfur deposition. On the other hand, the effect of variation in gas properties on sulfur deposition was directly attributed to the influence of pressure change, which should be calculated according to the corresponding pressures. Also, it was found that the radius of damage caused by sulfur deposition increased with increasing gas production rate and production time. The analysis suggests that gas production rate dramatically decreases as sulfur saturation increases. Hu et al. (JNGSE, 2013, 11, 18e22) developed a reservoir damage model for describing the change of pressure and production with sulfur deposition considering non-Darcy flow. The glomeration mechanism of precipitated sulfur in pores was discussed, and the effect of irreducible water sulfur deposition was investigated. The results indicated that when reservoir pressure was lower than the critical pressure, a higher degree of saturation of irreducible water might lead to more rapid pressure decline. Moreover, the velocity of sulfur precipitation increased and the gas limited production time became shorter when non-Darcy flow was considered. They also found that irreducible water not only decreased the gas flow, but also caused difficulty in sulfur being carried by gas. Hu et al. (JNGSE, 2014, 18, 31e38) proposed a model for elemental sulfur solubility in various sour gas mixtures using a database of experimental measurements. The calculation results using the proposed model more accurately fitted the experimental results than calculations using the Roberts's solubility formula. This was due to the fact that the experimental solubility data considering Roberts's model used sulfur dissolved in pure hydrogen sulfide, but not in sour gas mixtures. It revealed that the new developed model could be used for describing the solubility changes with variations of temperatures and pressures more accurately. Kamari and Oyarhossein (JNGSE, 2012, 9, 11e15) conducted experiments on the hydrate formation while producing from an Iranian sour gas well. They obtained the hydrate formation temperatures at different operating pressures (770, 600, 450, 330, 235 and 123 psia) after sampling the reservoir's produced fluids from a separator. The results were compared with previous
2. Sour gas reservoirs 3. Wellbore issues for sour gas reservoirs 4. Natural gas desulfurization by methyldiethanolamine (MDEA) absorption 5. Natural gas desulfurization by Sulfinol-M absorption 6. Natural gas desulfurization by other absorption liquids 7. Other natural gas desulfurization methods 8. Removal of components other than hydrogen sulfide from sour gas 9. Corrosion and safety issues for gas sweetening plants Note that published articles relating to CO2 removal are not included in this compilation as they have been addressed in the recent JNGSE virtual special issues on gas hydrates (Wood, 2015a) and CO2 handling and Carbon Capture Utilization and Sequestration (CCUS) research (Wood, 2015b). This virtual special issue should highlight to researchers JNGSE's keen interest in topics concerning sour gas removal in gas processing plants and in sour gas reservoirs, and the journal's willingness to peer-review research articles on sour gas behavior and related topics (e.g. gas sweetening plant optimization, impurities removal from sour gas, and sour gas plant case studies), as they relate to natural gas, on an ongoing basis. The brief summaries of the articles included in this virtual special issue now follow, organized into the categories described above. http://dx.doi.org/10.1016/j.jngse.2015.08.022 1875-5100/© 2015 Elsevier B.V. All rights reserved.
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correlations proposed in previously published work. Analysis verified that the correlation proposed by Østergaard et al. (2000) was the best fit for this sour gas sample. The reason for this better fit might be because the effects of CO2 and N2 were taken into account in the correlation of Østergaard et al., while other correlations have only considered a maximum of three parameters: pressure, temperature and gas specific gravity. The results are helpful in determining the safe and unsafe operating zones using PeT curves to avoid hydrate formation conditions. 3. Wellbore issues for sour gas reservoirs Long et al. (JNGSE, 2014, 21, 270e274) evaluated the sulfide stress corrosion cracking (SSC) issue using different anti-SSC casing design methods. The basic principles of mitigating SSC in wellbore casing design were discussed to minimize SSC initiation and improve the integrity and service life of casing. It was recommended that additional axial stress should be considered for determining the maximum allowable tension load in anti-SSC casing design, in order to guarantee that the casing grade is selected with a greater safety margin. The design method described in this paper could be used to guide casing design in sour gas wells. 4. Natural gas desulfurization by methyldiethanolamine (MDEA) absorption Abdulrahman and Sebastine (JNGSE, 2013, 14, 116e120) simulated the prospective Khurmala (gas field in the Kurdistan region of Iraq) gas sweetening process by using the Aspen HYSYS commercial software. The simulation work evaluated a range of amine gas sweetening processes, including: DEA, MDEA and blends of MEA/ MDEA and DEA/MDEA. It achieved the highest acid gas removal with a DEA solution. H2S concentration in the sweet gas stream was about 4 ppm at (400 m3/h) amine circulation rate. Analysis also considered some of the critical amine process factors for each amine type, e.g., amine circulation rate and amine concentration. Furthermore, optimization runs indicated that the use of a 35% DEA solution should deliver the best results. Abukashabeh et al. (JNGSE, 2014, 19, 317e323) studied thermophysical properties for thermally degraded methyldiethanolamine (MDEA) solutions. Density, viscosity and surface tension of samples of fresh MDEA solutions, real lean MDEA solutions, and thermally degraded MDEA solutions were measured at different temperatures. The measured values were validated with literature data. The obtained results were used to produce correlations for MDEA solution density and viscosity as a function of initial amine concentration, degradation time, and temperature. Increasing the degradation time and temperature increased the density, viscosity and surface tension. The predicted MDEA concentrations of real lean amine samples were compared with the measured values through acidebase titration. The relative deviation between the results of titration and those predicted using the derived correlations ranged from 3.5 to 7.5%. Adib et al. (JNGSE, 2013, 14, 121e131) proposed a model to estimate process output variables of an industrial natural gas sweetening plant using the Support Vector Machine (SVM) algorithm. The model was evaluated with process operating data from the Hashemi Nejad natural gas refinery in Khorasan, Iran. A set of 13 input/output plant variables each consisting of 145 data points was used to train, optimize, and test the SVM model. Model development, which consisted of training, optimization and testing, was performed using randomly selected 80%, 10%, and 10% of available data, respectively. Modeling results were compared with those obtained from an artificial neural network ANN-based model,
developed using the same dataset. The results from the SVM based model showed better agreement with operating plant data compared to the ANN-based model. The minimum calculated squared correlation coefficient for the estimated process variables is 0.99. This verified that the SVM algorithm provides a reliable and accurate estimation method for natural gas sweetening. Alhseinat et al. (JNGSE, 2014, 17, 49e57) carried out experiments on the foaming behavior of aqueous methyldiethanolamine (MDEA) in the presence of various degradation products, and other contaminants as additives, to gas sweetening solutions. The foaming tendency of aqueous MDEA solutions was reported in terms of foam volume. Foam stability was studied on the basis of the time required for the last bubble to break. The effect of degradation products and heavy and light dissolved organics on solution physical properties i.e. density, surface tension and viscosity were examined. The 2.5 wt% addition of propionic acid decreased the foam volume by about 4% and the foam stability by about 7.14%, while the heaver organic acids (C5eC7) increased foaming. All organic acids increased the solution viscosity and density, and decreased the solution's surface tension to various extents. Formaldehyde increased the foaming tendency and enhanced the stability of the foam in MDEA solution. Iron(II) sulfide increased the foaming tendency by about 39.7%, although it decreased the foam stability by about 95.6%. The addition of both pentane and heptane decreased the foaming tendency and stability of the 50 wt% MDEA solutions. In addition a model was proposed to aid the prediction of foaming and defoaming behavior of the contaminants in terms of bubble radius, in order to provide a better understanding of the parametric effects behind the foaming problem of aqueous MDEA solutions. Alhseinat et al. (JNGSE, 2014a, 20, 241e249) predicted the simultaneous solubility of H2S and CO2 in aqueous MDEA solutions. They developed a new theoretical thermodynamic model based on incorporating thermodynamic relationships that correlated the equilibrium and solubility constants to the Gibbs free energy of reaction, leading to an enhanced predictive capability of the model. The non-ideality in the liquid phase was taken into account by using the Pitzer model to calculate the activity coefficients for all species present in the liquid phase. The non-ideality in the gas phase was taken into account by using the PR equation of state to calculate the fugacity coefficient for all species present in the gas phase. The developed model was then validated with literature data for H2S and CO2 absorption. The effects of process temperature, pressure, and pH on the H2S solubility in MDEA amine solutions were evaluated. Also this model could be further developed to provide a user-friendly program, able to give an accurate prediction of acid gas solubility at actual process conditions, allowing the optimization of the process accordingly. Alhseinat et al. (JNGSE, 2015, 26, 502e509) carried out a parametric study on removal of MDEA foam creators coupled with foam characterization. The foaming tendency of aqueous MDEA solution was reported in terms of foam volume. Foam stability was reported on the basis of the time required for the last bubble to break. The effect of process parameters such as time of foamate collection, flowrate of dispersion gas, initial liquid volume, and corrosion inhibitor concentration on foam fractionation performance was investigated. Surface tension of collected samples from bulk liquid, before and after foaming, as well as from foamate, was measured and correlated with the separation efficiency. It was found that foaming was capable for separating and concentrating corrosion inhibitor into the foamate. The added corrosion inhibitor increased the foam breaking time and volume. Increasing amine volume at the same gas flowrate decreased the contaminants' separation efficiency. The maximum separation occurred at gas flowrate of 1.0 L/ min. The observations of this study showed that foam fractionation
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could be used effectively to remove surface-active contaminates from MDEA amine solutions; however, operating conditions should be selected carefully. Al-Lagtah et al. (JNGSE, 2015, 26, 367e381) evaluated the performance improvement of Lekhwair natural gas sweetening plant using simulation and sensitivity analysis were carried out using Aspen HYSYS v7.3 commercial software. This study also reviewed the current operation of an existing plant (Lekhwair plant, Oman) considering the main operating parameters (i.e., lean amine circulation flow rate, temperature and concentration) and proposed some modifications to the existing plant to increase its profitability and sustainability. The operating capacities of some equipment were reviewed to assess the possibility of changing the operating parameters along with investigating the occurrence of common operational problems like foaming. Two modifications (conventional split-loop and modified split-loop) were simulated and discussed. A comparison between them and the current process were carried out in terms of profitability and sustainability. The conventional split-loop was found to save up to 50% of the current operating expenses for a mere £175,000 increase in capital investment, and a penalty of 1.0 ppm of H2S concentration in the sweet gas, which was still well below the pipeline gas specification. Finally, a sulfur recovery process was proposed to make the plant more sustainable and environmentally friendly along with proposing two modifications to the conventional sulfur recovery process. Even though the conventional and the proposed modified sulfur recovery processes were not economically profitable, the modified sulfur recovery process was more sustainable as its carbon footprint is lower than the conventional process. Banat et al. (JNGSE, 2014, 16, 1e7) investigated theoretically a gas sweetening unit with MDEA solution using the commerciallyavailable process simulator ProMax®. They found that the unit with highest value of exergy destruction was the absorber (3 MW) followed by the sweet gas air cooler (2.7 MW) and the flasher unit (2.2 MW). The energy and exergy efficiencies determined indicated that absorber was the most efficient process with energy and exergy efficiencies of about 94% and 98%, respectively. The flasher, air coolers and pressure recovery turbine were determined to be the under-performing components with exergy efficiencies of 27%, 24% and 31%, respectively. A further breakdown of exergy losses revealed that the chemical exergy losses are much higher than the physical exergy losses, contributing around 94% of the total exergy losses and, therefore, chemical exergy should be of more concern rather than physical exergy. Fouad and Berrouk (JNGSE, 2013, 11, 12e17) investigated the use of amine solvents that consist of two tertiary amines, namely methyldiethanolamine (MDEA) and triethanolamine (TEA). Results showed that up to 3.0% reduction in a unit's running cost can be obtained using the mixture (40 wt% MDEA þ 5 wt% TEA) while meeting the sweet gas specifications in terms of H2S and CO2 concentrations. The lean amine loading was fixed at a value of 0.005. Results for the (40 wt% MDEA þ 5 wt% TEA) mixture were compared to the results of the standardized (45 wt% MDEA) solvent used in the Habshan gas processing plant (UAE) and other possible primary/tertiary and secondary/tertiary amine mixtures. This reduction in cost was achieved through a decrease in the plant raw materials cost and in both regenerator, reboiler and trim cooler energy requirements. Ghanbarabadi and Zad Gohari (JNGSE, 2014, 20, 208e213) simulated the gas sweetening unit of Sarakhs refinery (Iran) using Aspen HYSYS commercially-available software with MDEA aqueous solvent to optimize the concentration, MDEA solvent's flow stream, thermal load of the restoration unit and other processing conditions. They investigated the effect of temperature, flow stream
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and concentration of input solvent on the contactor and other processing units. The simulation results revealed that the optimum performance of MDEA solvent was 45e50 wt% concentration at 55e63 C. Hamzehie et al. (JNGSE, 2015, 24, 106e114) proposed a model based on an artificial neural network (ANN) to predict the solubility of acid gases (H2S and CO2) in 32 commonly single and mixed amine, and ionic liquid (IL) solutions over a wide ranges of operating conditions. Temperature, partial pressure of acid gases, overall mass concentration, apparent molecular weight, critical temperature and critical pressure of solutions were chosen as input variables for the developed network. A collection of 733 experimental data points for H2S solubility (including train, test and validation data points) were gathered from the literature to develop the network. The best parameters of the developed ANN containing the number of neurons, numbers of hidden layers and the transfer function were acquired using these data points. The extrapolation capability of the network was tested with an extra data set (114 data points for CO2 solubility). The results showed that the developed ANN model had the ability to estimate accurately the solubility of acid gases in different solutions with Mean Relative Error (MRE) value of 3.104 and correlation coefficient (R2) of 0.997. Muhammad and Gadelhak (JNGSE, 2014, 17, 119e130) estimated the capital and operating costs accompanying the scale up of an amine sweetening process to treat high acid gas contents in sour natural gas (25 MMSCFD, 1.7 mol% H2S and 4.13 mol% CO2). The effects of amine circulation rate, lean amine temperature, re-boiler temperature and amine concentration were investigated. The process was scaled-up to handle a sour gas with up to 25 mol% CO2 and 3 mol% H2S by scaling up the amine circulation rate. The capital and operating costs showed a linear relationship with the increase of CO2 percentage in natural gas. Meanwhile, the utility requirements, regenerator column diameter, the surface area of the re-boiler, the lean-rich amine heat exchanger and the lean amine cooler demonstrated a strong positive linear correlation. For various acid gas partial pressures the capital and operating costs were fitted to a second order polynomial function with R2 > 0.97. Pal et al. (JNGSE, 2014, 21, 1043e1047) conducted experiments on the thermal degradation of methyldiethanolamine (MDEA) under different operating conditions. Effects of temperature and pressure were observed to understand the kinetics of MDEA degradation as well as formation of different organic degraded products. Heat stable salts (HSS) and various organic degradation products were identified with increasing concentration as degradation time increased. A microwave digester and a high pressure reactor were used to study the thermal degradation with fresh 3.781 M MDEA loaded with sour gas (i.e., H2S 38 ppm and RSH 40 ppm) at different temperatures and pressures. The results suggested that initial thermal degradation of fresh MDEA showed the highest formation of HSS, which were ranked as glycolate > acetate > formate using the microwave digester. Higher formation rates of the acetate and the glycolate were obtained at a higher pressure of 2.5 bars, whereas the formation rate of the formate obtained at 2.5 bars was lower than that obtained at 2.0 bars. The degraded products like ethylenediamine, bicine, bis(hydroxyethyl) piperazine (bHEP) etc. were observed with increasing concentration using GCeMS and DSA-TOF analysis in a gas sweetening unit. The analysis provides greater understanding of MDEA degradation using different types of reactor, degradation kinetics and degradation products. Pal et al. (JNGSE, 2015, 24, 124e131) studied the role of aqueous methyldiethanolamine (MDEA) as a solvent in a natural gas sweetening unit. The major hydrocarbons found in the feed natural gas were analyzed using gas chromatography mass spectrometry (GCeMS). Different types of organic and inorganic species were
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found as contaminants in the lean MDEA solvent. In comparison to inorganic anion contaminants, organic heat stable salts such as acetate (2806 ppm) and propionate (1614 ppm) were present in much higher concentrations. The UVeVis spectrophotometer confirmed the presence of these anions in almost the same concentrations in lean MDEA solvent. Heavy metal ions such as lead (1.009 ppm) and iron (0.967 ppm) determined by ICP-OES analysis were also found in substantial amounts in the lean MDEA solvents of natural gas sweetening units obtained from GASCO Company (Abu Dhabi). These organic thermally degraded products generated in lean MDEA samples of gas sweetening units were considered to be another major contaminant. Moreover, the thermal degradation experiment was compared with H2S and both H2S/CO2 to obtain similar compounds with varying concentration. Qiu et al. (JNGSE, 2014, 21, 379e385) studied a novel methyldiethanolamine (MDEA) modified process for high-sulfur gas sweetening. The influence of operating conditions on gas sweetening efficiency and economic benefits were evaluated by using process simulation and optimization. The results showed that the maximization of the treated gas yield should be selected as the optimization objective function for gas sweetening rather than the minimization of the operating costs. This enabled improvement of the economic efficiency of the gas processing unit. On the other hand, improving absorption pressure (AP) and tray number significantly reduced the circulation rate. Energy and operating costs reached their minimum value, when the AP simultaneously was at its maximum value. Rahimpour et al. (JNGSE, 2013, 15, 127e137) developed a mathematical model for a natural gas sweetening process using a corrugated packed-bed column based on the computational fluid dynamics (CFD) concept. 2D mass and energy transfer equations, incorporating chemical reactions between amines and acid gases, were developed for moving liquid and gas in a cylindrical coordinate system for the channels produced from counter course assembly of the corrugated sheets. Solution to the governing equations based on mass and energy conservation concepts provided temperature and concentration distributions along the bed height and across the gas and reacting liquid film. It was revealed that the structured-packed column showed a better performance for absorption of acid gases in comparison with a randomly-packed column of equal height and diameter. The results led to the conclusion that due to instantaneous reaction between hydrogen sulfide and amine, the slope of the concentration profile of H2S in the liquid film was greater than that of CO2. MDEA seemed to have the most selective solution for absorption of H2S and MEA showed better performance for absorption of CO2 in comparison with DEA. More generally, the selectivity for absorption of CO2 could be intensified, if necessary, in a case of interest. Santo and Rameshni (JNGSE, 2014, 18, 137e148) designed a sour gas field development considering particular proprietary schemes available and features to handle a wide range of operating cases in order to maintain a stable operation while meeting the required performance objectives. They discussed the design features of the units and reasons why they were selected, and the options that they considered when designing a specific unit, including the solvent evaluation and selection, the impact of H2S/CO2 ratio on the Acid Gas Removal Unit (AGRU) and the Sulfur Recovery Units (SRU) design, the selected optimum scheme of the SRU, and the Tail Gas Treating Units (TGU) to meet the performance guarantees for all 10 cases considered, including a comparison of the operating costs and the capital costs. It was concluded that the formulated chemical solvent MDEA was more effective than hybrid solvents. In addition, the tail gas absorber could be designed with a higher rich amine loading to achieve better results. Younas and Banat (JNGSE, 2014, 18, 247e253) applied the
commercially-available ProMax simulation model to determine the sensitivity of a gas sweetening process. Variables affecting absorption of acid gases, directly and indirectly, were tested. It was determined that the process can tolerate up to 4% CO2 and 1% H2S in the feed gas and it could operate around a large range of designed feed gas capacities, i.e., 50e130%. The most suitable feed gas temperature was determined to be 40e45 C. The optimum amine concentration and flow were found to be closer to the design values of 45% and 360 m3/h, respectively. The behavior of the parameters affecting the absorption process indirectly, such as: reboiler operating pressure, rich amine temperature, reflux ratio and boilup ratio were also discussed. Analysis suggested that the reboiler operating temperature should be held below 130 C at all times to minimize amine degradation. The reflux and boilup ratios could also be manipulated to achieve specific desired operational results. 5. Natural gas desulfurization by Sulfinol-M absorption Angaji et al. (JNGSE, 2013, 15, 22e26) conducted optimization analysis of Sulfolane concentration in proposing the use of Sulfinol-M solvent instead of MDEA solvent in the Sarakhs refinery (Iran). They examined the performance of a mixture of physical and chemical solvents in the gas treatment process. This study evaluated the performance of various concentrations of Sulfolane in the Sulfinol-M solvent in this gas refinery, which led to the conclusion that a solvent of composition 40.2 wt% Sulfolane, 21.2 wt% H2O, and 37.7 wt% MDEA should be used in the liquid mixture of Sulfinol-M. The analysis highlighted the possibility of adjusting the concentrations of water, Sulfolane and MDEA to decrease the energy required for solvent restoration, and to control the investment cost consistent with the process conditions. The results led to the conclusion that the replacement of Sulfinol-M solvent resulted in better performance and more favorable economics compared to the solvent composition currently used in the Sarakhs refinery, and other amine solvents evaluated. Asil and Shahsavand (JNGSE, 2014, 21, 791e804) used combinations of Aspen-HYSYS software and two in-house artificial neural networks (ANN, namely, Regularization and stabilized multilayer perceptron networks) to compare the acid gas enrichment (AGE) capability of sulfinol-M (sulfolane þ MDEA) solvent at optimal concentration with traditional MDEA solutions for use in a conventional gas treating unit (GTU). The simulation results indicated that the optimal concentration of Sulfinol-M aqueous solution (i.e., containing 37 wt% Sulfolane, 45 wt% MDEA and 18 wt% H2O) completely eliminated toluene and ethylbenzene from the (Sulfur Recovery Units) SRU feed stream while removing 80% of benzene entering the GTU process. Furthermore, mole fraction of H2S in the SRU feed stream increased from the conventional 33.48 mol% to over 57 mol%. The increased H2S selectivity of the optimal sulfinol-M aqueous solution elevated the CO2 slippage through to the sweet gas stream by about 4.5 mol%, which was still below the permissible threshold. Ghanbarabadi and Khoshandam (JNGSE, 2015, 22, 415e420) simulated the removal of acid gases (CO2, H2S) and sulfur compounds (methyl and ethyl mercaptans, dimethyl-sulfide, COS) with mixed solvent Sulfinol (Sulfolane þ MDEA þ H2O) and DGA, MDEA þ AMP solvents and compare their performance with the presently-used solvent, MDEA. The objective was to establish the feasibility of utilizing Sulfinol-M solvent to replace the aqueous amine solvent in the gas sweetening unit of Ilam gas refinery (Iran). The results showed that more than 30e40% of mercaptans, together with sour gas was absorbed with Sulfinol-M solvent at a lower flow rate and consuming considerably less energy (i.e., 10e25% less) in solvent regeneration. Furthermore, very little waste
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of solvent was observed compared with other amine solvents (i.e., MDEA þ AMP, DGA, MDEA). The results led to the conclusions that many of the process parameters evaluated were controlled more easily with the compositional characteristics of the Sulfinol-M compound than with other amine solvents, and these benefits are also accompanied by energy and economic saving in different aspects of mercaptan and acid gas absorption. 6. Natural gas desulfurization by other absorption liquids Azizkhani et al. (JNGSE, 2014, 21, 26e39) developed an optimization model for the performance of a gas sweetening plant using negative correlation learning (NCL) and a genetic algorithm (GA) to create an ensemble neural network (ENN). Diethanolamine (DEA) was used as the chemical solvent. In this approach the component neural networks (CNNs) of ENN were trained simultaneously. The resulting CNNs negatively correlated the penalty terms in their objective functions. The predicted output was obtained by using the weighted averages of the outputs of the CNNs. The GA participated in the training of CNNs and assigned optimized weights to each trained CNN in the ensemble. The proposed method was tested in a case study involving the gas treatment plant (GTP) of the AMMAK project in the Ahwaz onshore field in Iran. The results of the proposed model were shown to be in good agreement with the experimental data derived from the GTP. In addition, the proposed method outperformed single neural network and some other network ensemble techniques. Behroozsarand and Shafiei (JNGSE, 2010, 2, 284e292) studied the optimal control of an amine plant using the multi-objective genetic algorithm concept in conjunction with a proportionalintegral-derivative (PID) controller. The tuning of the PID controllers was achieved by minimizing two objective functions (Overshoot and IAE) through the Non-Dominated Sorting Genetic Algorithm-II (NSGA-II). An amine solution of DEA was used for the gas sweetening. Simulation results showed that NSGA-II tuning method had excellent ability in optimal control of all subunits of amine plant, such as the absorption and regeneration towers. Mohebi et al. (JNGSE, 2009, 1, 195e204) applied a simulation model to evaluate a sour gas membrane-absorption system. The hollow fiber membrane contactor and amine solution were used for separation of CO2 and H2S from CO2/H2S/CH4 gas mixture. Sour gas and diethanolamine (DEA) solution were fed into the shell and fiber respectively. CO2 and H2S reacted with the amine solution. Reaction mechanisms and equations for three phases of gas, liquid, and membrane were needed for modeling of this system. MATLAB software was used to conduct the simulations. The results showed that concentrations of CO2 and H2S decreased at the beginning of the fiber and that the liquid phase was controlling phase. Furthermore, the result showed that pressure increase had a positive effect on separation of the species. 7. Other natural gas desulfurization methods Moaseri et al. (JNGSE, 2013, 12, 34e42) performed experiments and a techno-economical evaluation of Khangiran sour natural gas condensate desulfurization process (Iran), considering different scenarios. The effects of reagent, temperature, volume ratio, and concentration were examined. The oxidative desulfurization process delivered the best results being able to decrease the total sulfur content from 8500 ppm to less than 700 ppm, by eliminating all hydrogen sulfide and mercaptans, and severely reducing other heavy sulfur-bearing compounds. The odor of the treated condensate was completely eliminated due to removal of all volatile sulfur components. The preliminary techno-economic evaluation of an
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industrial scale process was performed based on the experimental results. The results indicated that the proposed process was beneficial from both financial and environmental standpoints. 8. Removal of components other than hydrogen sulfide from sour gas Aleghafouri et al. (JNGSE, 2015, 22, 618e624) investigated benzene, toluene, ethylbenzene and metaxylene (BTEX) removal from aqueous solution of diethanolamine (DEA) experimentally and theoretically. The Langmuir, Freundlich and Sips isotherm models were used to describe the equilibrium data. The accuracy of the results obtained from the adsorption isotherm models was compared and the values for the regressed parameters reported. The results showed that the Freundlich and Sips isotherms had better agreement with the experimental data than Langmuir isotherm for all activated carbon (AC) samples. According to the adsorption isotherm curves obtained from experiments, the amount of adsorption of metaxylene, ethylbenzene, toluene and benzene increased. In addition, a mathematical model was proposed for describing the BTEX transfer between the amine solution and solid particles. The breakthrough predicted by the proposed model was compared with the experimental results and a satisfactory agreement was observed between them. Rashidi et al. (JNGSE, 2015, 25, 103e109) synthesized a carbon nanotube-supported metallo-carboxyporphyrin catalyst for mercaptan removal from a gas stream in a fixed bed reactor. The nano catalyst was characterized by X-ray diffraction (XRD), fieldemission scanning electronic microscopy (SEM), and Fourier transform infrared spectroscopy (FT-IR). The effects on performance of important operating parameters including temperature, gas hourly space velocity (GHSV), and loading (%) were investigated. The results confirmed that the mercaptan concentrations in the output gas flow could be decreased from 16,800 ppm to less than 10 ppm under optimized conditions by (Fe)TCPP-MWCNTs-NH2 as nanocatalyst. Tohidi et al. (JNGSE, 2015, 26, 758e769) developed a more efficient and economical cyclic adsorption process for mercaptan removal from natural gas (NG) to reduce mercaptan content to less than 10 ppm and meet the environmental rules. Continuous sulfur removal was studied for the NG feed stream, with pressure of 6.8 MPa, flow rate of 2850 Nm3/hr and molar composition of 95.98% methane, 0.00182% water vapor, 1% carbon dioxide, 0.0134% mercaptan and 3% heavier hydrocarbons (C3þ). The proposed process of Pressure Vacuum Swing Adsorption (PVSA) was designed and simulated as a more efficient alternative process compared to the current industrial PressureeTemperature Swing Adsorption (PTSA). In this work, an improved PVSA process was simulated with sequences of bed pressurization, adsorption, equalization, blow down, bed regeneration by vacuum and purge by product, in each process cycle. Vacuum conditions of 10 KPa with the molar purge/feed ratio of 0.06 and temperature of 350 K were required for appropriate bed regeneration from adsorbed mercaptan to approach a continuous cyclic steady condition. Comparison between PVSA and PTSA, for the same feed characteristics, same packed columns and adsorption operating conditions, revealed that the PVSA process, with less cycle time than PTSA, could achieve the same product purity with 94.8% recovery and 3.90 mol/(kg$day) productivity, whereas PTSA achieved recovery of only 74.04% and productivity of 2.79 mol/(kg$day). At the same time, operating with PVSA, instead of the PTSA process, reduced operating cost by 17%. 9. Corrosion and safety issues for gas sweetening plants Alaei
et
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(JNGSE,
2014,
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271e284)
observed
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implementation of hazard and operability (HAZOP) analysis applied to identify all the dangerous deviations, potential hazards, and operational problems possibly associated the Claus reaction furnace package, blower, and heat exchanger equipment in a sulfur recovery unit (SRU). This allowed a significant reduction in implementation costs, where the expected saving from risk reduction was high. The efficiency of the SRU was strongly associated with the performance of those aforementioned components. It is noteworthy that these components are the most important parts of the SRU. The analysis led to recommendation concerning risk ranking in such plants. In addition, cause and effect diagrams for the Claus burner in start-up/heating and fuel gas/sour gas modes were presented. Davoudi et al. (JNGSE, 2014, 19, 116e124) performed experiments to establish the effects of impurities on thermal degradation and corrosivity of amine solutions in a sour gas sweetening plant. The effects of heat stable salt on pressure drop, pressure drop on steam consumption, MEG contamination of the solvent on boil up temperature, H2S loading, heat stable salts and chloride on corrosion rates were investigated. The results indicated that the presence of MEG in an aqueous phase affected the thermal degradation temperature of the solution. It also changed the solution concentration and the acid gas loading. Analysis also suggested that acetate anion could be carried over in the system from upstream process units.
10. Ongoing sour gas research JNGSE also has manuscripts under review in July 2015, not included in this virtual special issue, addressing the following sour gas and gas contaminant topics: Integrated mathematical modeling for prediction of rich CO2 absorption in structured packed column at elevated pressure conditions; Effects of a cooler's operating parameters on the performance of CO2 absorption processes using alkanolamine solutions; Refrigeration cycles in low-temperature distillation processes for the purification of natural gas; Modeling of nitrogen separation from natural gas through nanoporous carbon membranes; Modeling of PES/modified Multi-Walled Carbon Nanotube (MWCNT) mixed matrix membranes performance for CO2/CH4 separation using artificial neural network and ANFIS; Natural gas sweetening using PU-zeolite X nanocomposite membranes; Prediction of carbon dioxide solubility in amino acid salt solutions as absorbents using artificial neural network and DeshmukheMather models;
The activity loss modeling for the catalytic reactor of a sulfur recovery unit in South Pars Gas Complex (SPGC) 3rd Refinery based on percolation theory; Feasibility of supersonic separation for deep natural gas sweetening using computational fluid dynamics: Early design; Process optimization of the gas sweetening unit to increase a sulfur recovery unit's performance. The diversity of above topics highlights the varied nature of ongoing research and the multiple ways in which sour gas removal methods and production from sour gas reservoirs could potentially be improved through a better understanding of the complex processes involved and innovative applications. The Journal of Natural Gas Science & Engineering has an ongoing interest in topics concerning sour gas that are relevant to natural gas, and is keen to be given the opportunity to review manuscripts addressing original research and case studies pertaining to such topics. We hope the articles presented in this compilation will not only provide you with ideas to develop your own ongoing research applications, but also inspire you to submit manuscripts of your current and future original research work to this journal. For detailed references pertaining to the JNGSE-published articles summarized above please see the main VSI document (http://dx.doi.org/10.1016/j.jngse.2015.08.006). References Østergaard, K.K., Tohidi, B., Danesh, A., Todd, A.C., Burgass, R.W., 2000. SPE Prod. Facil. 15, 228e233. Wood, D.A., 2015a. Gas hydrate research advances steadily on multiple fronts: a collection of published research (2009 - 2015). J. Nat. Gas Sci. Eng. 24, A1eA8. Wood, D.A., 2015b. Carbon dioxide (CO2) handling and carbon capture utilization and sequestration (CCUS) research relevant to natural gas: A collection of published research (2009-2015). J. Nat. Gas Sci. Eng. 25, A1eA9. Zhang, Z., Wood, D.A., 2015. Virtual special issue: sour gas reservoirs and sulfurremoval technologies: a collection of published research (2009 to 2015). J. Nat. Gas Sci. XX. XXXeXXX.
Zhien Zhang, Editorial Supervisor Journal of Natural Gas Science & Engineering, College of Power Engineering, Chongqing University, Chongqing, China E-mail address: [email protected]. David A. Wood, Editor-in-Chief* Journal of Natural Gas Science & Engineering, DWA Energy Limited, Lincoln, United Kingdom *
Corresponding author. E-mail address: [email protected] (D.A. Wood). Available online 12 August 2015
Contents lists available at ScienceDirect
Journal of Natural Gas Science and Engineering journal homepage: www.elsevier.com/locate/jngse
Sour gas reservoirs and sulfur-removal technologies: A collection of published research (2009e2015) 1. Introduction
2. Sour gas reservoirs
This article serves as the introduction and overview to the Journal of Natural Gas Science and Engineering's virtual special issue (VSI) concerning Sour Gas Reservoirs and Sulfur- Removal Technologies, compiled in July 2015 (Zhang & Wood, 2015). This JNGSE VSI collects 35 articles reporting diverse topics related to sour gases that were published by Journal of Natural Gas Science and Engineering since the start of 2009. Each article included in the compilation represents a stand-alone analysis and research on a relevant topic that has passed the journal's rigorous peer-review editorial system. Collectively, these articles provide key insight to the progress being made towards better understanding of removal of sour gases and other components in gas streams using different techniques, sour gas reservoirs, and corrosion and safety issues in sour gas sweetening plants. The published articles compiled in this virtual special issue provide a useful synthesis of progress made in recent years in several diverse research areas pertaining to sour gas. The articles compiled are classified into eight distinct categories:
Guo et al. (JNGSE, 2015, 22, 371e376) investigated the prediction of sulfur saturation based on non-Darcy flow. The effects of reservoir compaction, gas properties, the dependence of sulfur solubility on pressure, and sulfur deposition on gas-well deliverability were studied. They claimed that the rate of sulfur deposition was underestimated by Roberts' Model, and their modified model was more accurate and practical in predicting sulfur deposition. Reservoir compaction should be considered in sulfur deposition predictions as it leads to a faster rate of sulfur deposition. On the other hand, the effect of variation in gas properties on sulfur deposition was directly attributed to the influence of pressure change, which should be calculated according to the corresponding pressures. Also, it was found that the radius of damage caused by sulfur deposition increased with increasing gas production rate and production time. The analysis suggests that gas production rate dramatically decreases as sulfur saturation increases. Hu et al. (JNGSE, 2013, 11, 18e22) developed a reservoir damage model for describing the change of pressure and production with sulfur deposition considering non-Darcy flow. The glomeration mechanism of precipitated sulfur in pores was discussed, and the effect of irreducible water sulfur deposition was investigated. The results indicated that when reservoir pressure was lower than the critical pressure, a higher degree of saturation of irreducible water might lead to more rapid pressure decline. Moreover, the velocity of sulfur precipitation increased and the gas limited production time became shorter when non-Darcy flow was considered. They also found that irreducible water not only decreased the gas flow, but also caused difficulty in sulfur being carried by gas. Hu et al. (JNGSE, 2014, 18, 31e38) proposed a model for elemental sulfur solubility in various sour gas mixtures using a database of experimental measurements. The calculation results using the proposed model more accurately fitted the experimental results than calculations using the Roberts's solubility formula. This was due to the fact that the experimental solubility data considering Roberts's model used sulfur dissolved in pure hydrogen sulfide, but not in sour gas mixtures. It revealed that the new developed model could be used for describing the solubility changes with variations of temperatures and pressures more accurately. Kamari and Oyarhossein (JNGSE, 2012, 9, 11e15) conducted experiments on the hydrate formation while producing from an Iranian sour gas well. They obtained the hydrate formation temperatures at different operating pressures (770, 600, 450, 330, 235 and 123 psia) after sampling the reservoir's produced fluids from a separator. The results were compared with previous
2. Sour gas reservoirs 3. Wellbore issues for sour gas reservoirs 4. Natural gas desulfurization by methyldiethanolamine (MDEA) absorption 5. Natural gas desulfurization by Sulfinol-M absorption 6. Natural gas desulfurization by other absorption liquids 7. Other natural gas desulfurization methods 8. Removal of components other than hydrogen sulfide from sour gas 9. Corrosion and safety issues for gas sweetening plants Note that published articles relating to CO2 removal are not included in this compilation as they have been addressed in the recent JNGSE virtual special issues on gas hydrates (Wood, 2015a) and CO2 handling and Carbon Capture Utilization and Sequestration (CCUS) research (Wood, 2015b). This virtual special issue should highlight to researchers JNGSE's keen interest in topics concerning sour gas removal in gas processing plants and in sour gas reservoirs, and the journal's willingness to peer-review research articles on sour gas behavior and related topics (e.g. gas sweetening plant optimization, impurities removal from sour gas, and sour gas plant case studies), as they relate to natural gas, on an ongoing basis. The brief summaries of the articles included in this virtual special issue now follow, organized into the categories described above. http://dx.doi.org/10.1016/j.jngse.2015.08.022 1875-5100/© 2015 Elsevier B.V. All rights reserved.
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correlations proposed in previously published work. Analysis verified that the correlation proposed by Østergaard et al. (2000) was the best fit for this sour gas sample. The reason for this better fit might be because the effects of CO2 and N2 were taken into account in the correlation of Østergaard et al., while other correlations have only considered a maximum of three parameters: pressure, temperature and gas specific gravity. The results are helpful in determining the safe and unsafe operating zones using PeT curves to avoid hydrate formation conditions. 3. Wellbore issues for sour gas reservoirs Long et al. (JNGSE, 2014, 21, 270e274) evaluated the sulfide stress corrosion cracking (SSC) issue using different anti-SSC casing design methods. The basic principles of mitigating SSC in wellbore casing design were discussed to minimize SSC initiation and improve the integrity and service life of casing. It was recommended that additional axial stress should be considered for determining the maximum allowable tension load in anti-SSC casing design, in order to guarantee that the casing grade is selected with a greater safety margin. The design method described in this paper could be used to guide casing design in sour gas wells. 4. Natural gas desulfurization by methyldiethanolamine (MDEA) absorption Abdulrahman and Sebastine (JNGSE, 2013, 14, 116e120) simulated the prospective Khurmala (gas field in the Kurdistan region of Iraq) gas sweetening process by using the Aspen HYSYS commercial software. The simulation work evaluated a range of amine gas sweetening processes, including: DEA, MDEA and blends of MEA/ MDEA and DEA/MDEA. It achieved the highest acid gas removal with a DEA solution. H2S concentration in the sweet gas stream was about 4 ppm at (400 m3/h) amine circulation rate. Analysis also considered some of the critical amine process factors for each amine type, e.g., amine circulation rate and amine concentration. Furthermore, optimization runs indicated that the use of a 35% DEA solution should deliver the best results. Abukashabeh et al. (JNGSE, 2014, 19, 317e323) studied thermophysical properties for thermally degraded methyldiethanolamine (MDEA) solutions. Density, viscosity and surface tension of samples of fresh MDEA solutions, real lean MDEA solutions, and thermally degraded MDEA solutions were measured at different temperatures. The measured values were validated with literature data. The obtained results were used to produce correlations for MDEA solution density and viscosity as a function of initial amine concentration, degradation time, and temperature. Increasing the degradation time and temperature increased the density, viscosity and surface tension. The predicted MDEA concentrations of real lean amine samples were compared with the measured values through acidebase titration. The relative deviation between the results of titration and those predicted using the derived correlations ranged from 3.5 to 7.5%. Adib et al. (JNGSE, 2013, 14, 121e131) proposed a model to estimate process output variables of an industrial natural gas sweetening plant using the Support Vector Machine (SVM) algorithm. The model was evaluated with process operating data from the Hashemi Nejad natural gas refinery in Khorasan, Iran. A set of 13 input/output plant variables each consisting of 145 data points was used to train, optimize, and test the SVM model. Model development, which consisted of training, optimization and testing, was performed using randomly selected 80%, 10%, and 10% of available data, respectively. Modeling results were compared with those obtained from an artificial neural network ANN-based model,
developed using the same dataset. The results from the SVM based model showed better agreement with operating plant data compared to the ANN-based model. The minimum calculated squared correlation coefficient for the estimated process variables is 0.99. This verified that the SVM algorithm provides a reliable and accurate estimation method for natural gas sweetening. Alhseinat et al. (JNGSE, 2014, 17, 49e57) carried out experiments on the foaming behavior of aqueous methyldiethanolamine (MDEA) in the presence of various degradation products, and other contaminants as additives, to gas sweetening solutions. The foaming tendency of aqueous MDEA solutions was reported in terms of foam volume. Foam stability was studied on the basis of the time required for the last bubble to break. The effect of degradation products and heavy and light dissolved organics on solution physical properties i.e. density, surface tension and viscosity were examined. The 2.5 wt% addition of propionic acid decreased the foam volume by about 4% and the foam stability by about 7.14%, while the heaver organic acids (C5eC7) increased foaming. All organic acids increased the solution viscosity and density, and decreased the solution's surface tension to various extents. Formaldehyde increased the foaming tendency and enhanced the stability of the foam in MDEA solution. Iron(II) sulfide increased the foaming tendency by about 39.7%, although it decreased the foam stability by about 95.6%. The addition of both pentane and heptane decreased the foaming tendency and stability of the 50 wt% MDEA solutions. In addition a model was proposed to aid the prediction of foaming and defoaming behavior of the contaminants in terms of bubble radius, in order to provide a better understanding of the parametric effects behind the foaming problem of aqueous MDEA solutions. Alhseinat et al. (JNGSE, 2014a, 20, 241e249) predicted the simultaneous solubility of H2S and CO2 in aqueous MDEA solutions. They developed a new theoretical thermodynamic model based on incorporating thermodynamic relationships that correlated the equilibrium and solubility constants to the Gibbs free energy of reaction, leading to an enhanced predictive capability of the model. The non-ideality in the liquid phase was taken into account by using the Pitzer model to calculate the activity coefficients for all species present in the liquid phase. The non-ideality in the gas phase was taken into account by using the PR equation of state to calculate the fugacity coefficient for all species present in the gas phase. The developed model was then validated with literature data for H2S and CO2 absorption. The effects of process temperature, pressure, and pH on the H2S solubility in MDEA amine solutions were evaluated. Also this model could be further developed to provide a user-friendly program, able to give an accurate prediction of acid gas solubility at actual process conditions, allowing the optimization of the process accordingly. Alhseinat et al. (JNGSE, 2015, 26, 502e509) carried out a parametric study on removal of MDEA foam creators coupled with foam characterization. The foaming tendency of aqueous MDEA solution was reported in terms of foam volume. Foam stability was reported on the basis of the time required for the last bubble to break. The effect of process parameters such as time of foamate collection, flowrate of dispersion gas, initial liquid volume, and corrosion inhibitor concentration on foam fractionation performance was investigated. Surface tension of collected samples from bulk liquid, before and after foaming, as well as from foamate, was measured and correlated with the separation efficiency. It was found that foaming was capable for separating and concentrating corrosion inhibitor into the foamate. The added corrosion inhibitor increased the foam breaking time and volume. Increasing amine volume at the same gas flowrate decreased the contaminants' separation efficiency. The maximum separation occurred at gas flowrate of 1.0 L/ min. The observations of this study showed that foam fractionation
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could be used effectively to remove surface-active contaminates from MDEA amine solutions; however, operating conditions should be selected carefully. Al-Lagtah et al. (JNGSE, 2015, 26, 367e381) evaluated the performance improvement of Lekhwair natural gas sweetening plant using simulation and sensitivity analysis were carried out using Aspen HYSYS v7.3 commercial software. This study also reviewed the current operation of an existing plant (Lekhwair plant, Oman) considering the main operating parameters (i.e., lean amine circulation flow rate, temperature and concentration) and proposed some modifications to the existing plant to increase its profitability and sustainability. The operating capacities of some equipment were reviewed to assess the possibility of changing the operating parameters along with investigating the occurrence of common operational problems like foaming. Two modifications (conventional split-loop and modified split-loop) were simulated and discussed. A comparison between them and the current process were carried out in terms of profitability and sustainability. The conventional split-loop was found to save up to 50% of the current operating expenses for a mere £175,000 increase in capital investment, and a penalty of 1.0 ppm of H2S concentration in the sweet gas, which was still well below the pipeline gas specification. Finally, a sulfur recovery process was proposed to make the plant more sustainable and environmentally friendly along with proposing two modifications to the conventional sulfur recovery process. Even though the conventional and the proposed modified sulfur recovery processes were not economically profitable, the modified sulfur recovery process was more sustainable as its carbon footprint is lower than the conventional process. Banat et al. (JNGSE, 2014, 16, 1e7) investigated theoretically a gas sweetening unit with MDEA solution using the commerciallyavailable process simulator ProMax®. They found that the unit with highest value of exergy destruction was the absorber (3 MW) followed by the sweet gas air cooler (2.7 MW) and the flasher unit (2.2 MW). The energy and exergy efficiencies determined indicated that absorber was the most efficient process with energy and exergy efficiencies of about 94% and 98%, respectively. The flasher, air coolers and pressure recovery turbine were determined to be the under-performing components with exergy efficiencies of 27%, 24% and 31%, respectively. A further breakdown of exergy losses revealed that the chemical exergy losses are much higher than the physical exergy losses, contributing around 94% of the total exergy losses and, therefore, chemical exergy should be of more concern rather than physical exergy. Fouad and Berrouk (JNGSE, 2013, 11, 12e17) investigated the use of amine solvents that consist of two tertiary amines, namely methyldiethanolamine (MDEA) and triethanolamine (TEA). Results showed that up to 3.0% reduction in a unit's running cost can be obtained using the mixture (40 wt% MDEA þ 5 wt% TEA) while meeting the sweet gas specifications in terms of H2S and CO2 concentrations. The lean amine loading was fixed at a value of 0.005. Results for the (40 wt% MDEA þ 5 wt% TEA) mixture were compared to the results of the standardized (45 wt% MDEA) solvent used in the Habshan gas processing plant (UAE) and other possible primary/tertiary and secondary/tertiary amine mixtures. This reduction in cost was achieved through a decrease in the plant raw materials cost and in both regenerator, reboiler and trim cooler energy requirements. Ghanbarabadi and Zad Gohari (JNGSE, 2014, 20, 208e213) simulated the gas sweetening unit of Sarakhs refinery (Iran) using Aspen HYSYS commercially-available software with MDEA aqueous solvent to optimize the concentration, MDEA solvent's flow stream, thermal load of the restoration unit and other processing conditions. They investigated the effect of temperature, flow stream
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and concentration of input solvent on the contactor and other processing units. The simulation results revealed that the optimum performance of MDEA solvent was 45e50 wt% concentration at 55e63 C. Hamzehie et al. (JNGSE, 2015, 24, 106e114) proposed a model based on an artificial neural network (ANN) to predict the solubility of acid gases (H2S and CO2) in 32 commonly single and mixed amine, and ionic liquid (IL) solutions over a wide ranges of operating conditions. Temperature, partial pressure of acid gases, overall mass concentration, apparent molecular weight, critical temperature and critical pressure of solutions were chosen as input variables for the developed network. A collection of 733 experimental data points for H2S solubility (including train, test and validation data points) were gathered from the literature to develop the network. The best parameters of the developed ANN containing the number of neurons, numbers of hidden layers and the transfer function were acquired using these data points. The extrapolation capability of the network was tested with an extra data set (114 data points for CO2 solubility). The results showed that the developed ANN model had the ability to estimate accurately the solubility of acid gases in different solutions with Mean Relative Error (MRE) value of 3.104 and correlation coefficient (R2) of 0.997. Muhammad and Gadelhak (JNGSE, 2014, 17, 119e130) estimated the capital and operating costs accompanying the scale up of an amine sweetening process to treat high acid gas contents in sour natural gas (25 MMSCFD, 1.7 mol% H2S and 4.13 mol% CO2). The effects of amine circulation rate, lean amine temperature, re-boiler temperature and amine concentration were investigated. The process was scaled-up to handle a sour gas with up to 25 mol% CO2 and 3 mol% H2S by scaling up the amine circulation rate. The capital and operating costs showed a linear relationship with the increase of CO2 percentage in natural gas. Meanwhile, the utility requirements, regenerator column diameter, the surface area of the re-boiler, the lean-rich amine heat exchanger and the lean amine cooler demonstrated a strong positive linear correlation. For various acid gas partial pressures the capital and operating costs were fitted to a second order polynomial function with R2 > 0.97. Pal et al. (JNGSE, 2014, 21, 1043e1047) conducted experiments on the thermal degradation of methyldiethanolamine (MDEA) under different operating conditions. Effects of temperature and pressure were observed to understand the kinetics of MDEA degradation as well as formation of different organic degraded products. Heat stable salts (HSS) and various organic degradation products were identified with increasing concentration as degradation time increased. A microwave digester and a high pressure reactor were used to study the thermal degradation with fresh 3.781 M MDEA loaded with sour gas (i.e., H2S 38 ppm and RSH 40 ppm) at different temperatures and pressures. The results suggested that initial thermal degradation of fresh MDEA showed the highest formation of HSS, which were ranked as glycolate > acetate > formate using the microwave digester. Higher formation rates of the acetate and the glycolate were obtained at a higher pressure of 2.5 bars, whereas the formation rate of the formate obtained at 2.5 bars was lower than that obtained at 2.0 bars. The degraded products like ethylenediamine, bicine, bis(hydroxyethyl) piperazine (bHEP) etc. were observed with increasing concentration using GCeMS and DSA-TOF analysis in a gas sweetening unit. The analysis provides greater understanding of MDEA degradation using different types of reactor, degradation kinetics and degradation products. Pal et al. (JNGSE, 2015, 24, 124e131) studied the role of aqueous methyldiethanolamine (MDEA) as a solvent in a natural gas sweetening unit. The major hydrocarbons found in the feed natural gas were analyzed using gas chromatography mass spectrometry (GCeMS). Different types of organic and inorganic species were
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found as contaminants in the lean MDEA solvent. In comparison to inorganic anion contaminants, organic heat stable salts such as acetate (2806 ppm) and propionate (1614 ppm) were present in much higher concentrations. The UVeVis spectrophotometer confirmed the presence of these anions in almost the same concentrations in lean MDEA solvent. Heavy metal ions such as lead (1.009 ppm) and iron (0.967 ppm) determined by ICP-OES analysis were also found in substantial amounts in the lean MDEA solvents of natural gas sweetening units obtained from GASCO Company (Abu Dhabi). These organic thermally degraded products generated in lean MDEA samples of gas sweetening units were considered to be another major contaminant. Moreover, the thermal degradation experiment was compared with H2S and both H2S/CO2 to obtain similar compounds with varying concentration. Qiu et al. (JNGSE, 2014, 21, 379e385) studied a novel methyldiethanolamine (MDEA) modified process for high-sulfur gas sweetening. The influence of operating conditions on gas sweetening efficiency and economic benefits were evaluated by using process simulation and optimization. The results showed that the maximization of the treated gas yield should be selected as the optimization objective function for gas sweetening rather than the minimization of the operating costs. This enabled improvement of the economic efficiency of the gas processing unit. On the other hand, improving absorption pressure (AP) and tray number significantly reduced the circulation rate. Energy and operating costs reached their minimum value, when the AP simultaneously was at its maximum value. Rahimpour et al. (JNGSE, 2013, 15, 127e137) developed a mathematical model for a natural gas sweetening process using a corrugated packed-bed column based on the computational fluid dynamics (CFD) concept. 2D mass and energy transfer equations, incorporating chemical reactions between amines and acid gases, were developed for moving liquid and gas in a cylindrical coordinate system for the channels produced from counter course assembly of the corrugated sheets. Solution to the governing equations based on mass and energy conservation concepts provided temperature and concentration distributions along the bed height and across the gas and reacting liquid film. It was revealed that the structured-packed column showed a better performance for absorption of acid gases in comparison with a randomly-packed column of equal height and diameter. The results led to the conclusion that due to instantaneous reaction between hydrogen sulfide and amine, the slope of the concentration profile of H2S in the liquid film was greater than that of CO2. MDEA seemed to have the most selective solution for absorption of H2S and MEA showed better performance for absorption of CO2 in comparison with DEA. More generally, the selectivity for absorption of CO2 could be intensified, if necessary, in a case of interest. Santo and Rameshni (JNGSE, 2014, 18, 137e148) designed a sour gas field development considering particular proprietary schemes available and features to handle a wide range of operating cases in order to maintain a stable operation while meeting the required performance objectives. They discussed the design features of the units and reasons why they were selected, and the options that they considered when designing a specific unit, including the solvent evaluation and selection, the impact of H2S/CO2 ratio on the Acid Gas Removal Unit (AGRU) and the Sulfur Recovery Units (SRU) design, the selected optimum scheme of the SRU, and the Tail Gas Treating Units (TGU) to meet the performance guarantees for all 10 cases considered, including a comparison of the operating costs and the capital costs. It was concluded that the formulated chemical solvent MDEA was more effective than hybrid solvents. In addition, the tail gas absorber could be designed with a higher rich amine loading to achieve better results. Younas and Banat (JNGSE, 2014, 18, 247e253) applied the
commercially-available ProMax simulation model to determine the sensitivity of a gas sweetening process. Variables affecting absorption of acid gases, directly and indirectly, were tested. It was determined that the process can tolerate up to 4% CO2 and 1% H2S in the feed gas and it could operate around a large range of designed feed gas capacities, i.e., 50e130%. The most suitable feed gas temperature was determined to be 40e45 C. The optimum amine concentration and flow were found to be closer to the design values of 45% and 360 m3/h, respectively. The behavior of the parameters affecting the absorption process indirectly, such as: reboiler operating pressure, rich amine temperature, reflux ratio and boilup ratio were also discussed. Analysis suggested that the reboiler operating temperature should be held below 130 C at all times to minimize amine degradation. The reflux and boilup ratios could also be manipulated to achieve specific desired operational results. 5. Natural gas desulfurization by Sulfinol-M absorption Angaji et al. (JNGSE, 2013, 15, 22e26) conducted optimization analysis of Sulfolane concentration in proposing the use of Sulfinol-M solvent instead of MDEA solvent in the Sarakhs refinery (Iran). They examined the performance of a mixture of physical and chemical solvents in the gas treatment process. This study evaluated the performance of various concentrations of Sulfolane in the Sulfinol-M solvent in this gas refinery, which led to the conclusion that a solvent of composition 40.2 wt% Sulfolane, 21.2 wt% H2O, and 37.7 wt% MDEA should be used in the liquid mixture of Sulfinol-M. The analysis highlighted the possibility of adjusting the concentrations of water, Sulfolane and MDEA to decrease the energy required for solvent restoration, and to control the investment cost consistent with the process conditions. The results led to the conclusion that the replacement of Sulfinol-M solvent resulted in better performance and more favorable economics compared to the solvent composition currently used in the Sarakhs refinery, and other amine solvents evaluated. Asil and Shahsavand (JNGSE, 2014, 21, 791e804) used combinations of Aspen-HYSYS software and two in-house artificial neural networks (ANN, namely, Regularization and stabilized multilayer perceptron networks) to compare the acid gas enrichment (AGE) capability of sulfinol-M (sulfolane þ MDEA) solvent at optimal concentration with traditional MDEA solutions for use in a conventional gas treating unit (GTU). The simulation results indicated that the optimal concentration of Sulfinol-M aqueous solution (i.e., containing 37 wt% Sulfolane, 45 wt% MDEA and 18 wt% H2O) completely eliminated toluene and ethylbenzene from the (Sulfur Recovery Units) SRU feed stream while removing 80% of benzene entering the GTU process. Furthermore, mole fraction of H2S in the SRU feed stream increased from the conventional 33.48 mol% to over 57 mol%. The increased H2S selectivity of the optimal sulfinol-M aqueous solution elevated the CO2 slippage through to the sweet gas stream by about 4.5 mol%, which was still below the permissible threshold. Ghanbarabadi and Khoshandam (JNGSE, 2015, 22, 415e420) simulated the removal of acid gases (CO2, H2S) and sulfur compounds (methyl and ethyl mercaptans, dimethyl-sulfide, COS) with mixed solvent Sulfinol (Sulfolane þ MDEA þ H2O) and DGA, MDEA þ AMP solvents and compare their performance with the presently-used solvent, MDEA. The objective was to establish the feasibility of utilizing Sulfinol-M solvent to replace the aqueous amine solvent in the gas sweetening unit of Ilam gas refinery (Iran). The results showed that more than 30e40% of mercaptans, together with sour gas was absorbed with Sulfinol-M solvent at a lower flow rate and consuming considerably less energy (i.e., 10e25% less) in solvent regeneration. Furthermore, very little waste
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of solvent was observed compared with other amine solvents (i.e., MDEA þ AMP, DGA, MDEA). The results led to the conclusions that many of the process parameters evaluated were controlled more easily with the compositional characteristics of the Sulfinol-M compound than with other amine solvents, and these benefits are also accompanied by energy and economic saving in different aspects of mercaptan and acid gas absorption. 6. Natural gas desulfurization by other absorption liquids Azizkhani et al. (JNGSE, 2014, 21, 26e39) developed an optimization model for the performance of a gas sweetening plant using negative correlation learning (NCL) and a genetic algorithm (GA) to create an ensemble neural network (ENN). Diethanolamine (DEA) was used as the chemical solvent. In this approach the component neural networks (CNNs) of ENN were trained simultaneously. The resulting CNNs negatively correlated the penalty terms in their objective functions. The predicted output was obtained by using the weighted averages of the outputs of the CNNs. The GA participated in the training of CNNs and assigned optimized weights to each trained CNN in the ensemble. The proposed method was tested in a case study involving the gas treatment plant (GTP) of the AMMAK project in the Ahwaz onshore field in Iran. The results of the proposed model were shown to be in good agreement with the experimental data derived from the GTP. In addition, the proposed method outperformed single neural network and some other network ensemble techniques. Behroozsarand and Shafiei (JNGSE, 2010, 2, 284e292) studied the optimal control of an amine plant using the multi-objective genetic algorithm concept in conjunction with a proportionalintegral-derivative (PID) controller. The tuning of the PID controllers was achieved by minimizing two objective functions (Overshoot and IAE) through the Non-Dominated Sorting Genetic Algorithm-II (NSGA-II). An amine solution of DEA was used for the gas sweetening. Simulation results showed that NSGA-II tuning method had excellent ability in optimal control of all subunits of amine plant, such as the absorption and regeneration towers. Mohebi et al. (JNGSE, 2009, 1, 195e204) applied a simulation model to evaluate a sour gas membrane-absorption system. The hollow fiber membrane contactor and amine solution were used for separation of CO2 and H2S from CO2/H2S/CH4 gas mixture. Sour gas and diethanolamine (DEA) solution were fed into the shell and fiber respectively. CO2 and H2S reacted with the amine solution. Reaction mechanisms and equations for three phases of gas, liquid, and membrane were needed for modeling of this system. MATLAB software was used to conduct the simulations. The results showed that concentrations of CO2 and H2S decreased at the beginning of the fiber and that the liquid phase was controlling phase. Furthermore, the result showed that pressure increase had a positive effect on separation of the species. 7. Other natural gas desulfurization methods Moaseri et al. (JNGSE, 2013, 12, 34e42) performed experiments and a techno-economical evaluation of Khangiran sour natural gas condensate desulfurization process (Iran), considering different scenarios. The effects of reagent, temperature, volume ratio, and concentration were examined. The oxidative desulfurization process delivered the best results being able to decrease the total sulfur content from 8500 ppm to less than 700 ppm, by eliminating all hydrogen sulfide and mercaptans, and severely reducing other heavy sulfur-bearing compounds. The odor of the treated condensate was completely eliminated due to removal of all volatile sulfur components. The preliminary techno-economic evaluation of an
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industrial scale process was performed based on the experimental results. The results indicated that the proposed process was beneficial from both financial and environmental standpoints. 8. Removal of components other than hydrogen sulfide from sour gas Aleghafouri et al. (JNGSE, 2015, 22, 618e624) investigated benzene, toluene, ethylbenzene and metaxylene (BTEX) removal from aqueous solution of diethanolamine (DEA) experimentally and theoretically. The Langmuir, Freundlich and Sips isotherm models were used to describe the equilibrium data. The accuracy of the results obtained from the adsorption isotherm models was compared and the values for the regressed parameters reported. The results showed that the Freundlich and Sips isotherms had better agreement with the experimental data than Langmuir isotherm for all activated carbon (AC) samples. According to the adsorption isotherm curves obtained from experiments, the amount of adsorption of metaxylene, ethylbenzene, toluene and benzene increased. In addition, a mathematical model was proposed for describing the BTEX transfer between the amine solution and solid particles. The breakthrough predicted by the proposed model was compared with the experimental results and a satisfactory agreement was observed between them. Rashidi et al. (JNGSE, 2015, 25, 103e109) synthesized a carbon nanotube-supported metallo-carboxyporphyrin catalyst for mercaptan removal from a gas stream in a fixed bed reactor. The nano catalyst was characterized by X-ray diffraction (XRD), fieldemission scanning electronic microscopy (SEM), and Fourier transform infrared spectroscopy (FT-IR). The effects on performance of important operating parameters including temperature, gas hourly space velocity (GHSV), and loading (%) were investigated. The results confirmed that the mercaptan concentrations in the output gas flow could be decreased from 16,800 ppm to less than 10 ppm under optimized conditions by (Fe)TCPP-MWCNTs-NH2 as nanocatalyst. Tohidi et al. (JNGSE, 2015, 26, 758e769) developed a more efficient and economical cyclic adsorption process for mercaptan removal from natural gas (NG) to reduce mercaptan content to less than 10 ppm and meet the environmental rules. Continuous sulfur removal was studied for the NG feed stream, with pressure of 6.8 MPa, flow rate of 2850 Nm3/hr and molar composition of 95.98% methane, 0.00182% water vapor, 1% carbon dioxide, 0.0134% mercaptan and 3% heavier hydrocarbons (C3þ). The proposed process of Pressure Vacuum Swing Adsorption (PVSA) was designed and simulated as a more efficient alternative process compared to the current industrial PressureeTemperature Swing Adsorption (PTSA). In this work, an improved PVSA process was simulated with sequences of bed pressurization, adsorption, equalization, blow down, bed regeneration by vacuum and purge by product, in each process cycle. Vacuum conditions of 10 KPa with the molar purge/feed ratio of 0.06 and temperature of 350 K were required for appropriate bed regeneration from adsorbed mercaptan to approach a continuous cyclic steady condition. Comparison between PVSA and PTSA, for the same feed characteristics, same packed columns and adsorption operating conditions, revealed that the PVSA process, with less cycle time than PTSA, could achieve the same product purity with 94.8% recovery and 3.90 mol/(kg$day) productivity, whereas PTSA achieved recovery of only 74.04% and productivity of 2.79 mol/(kg$day). At the same time, operating with PVSA, instead of the PTSA process, reduced operating cost by 17%. 9. Corrosion and safety issues for gas sweetening plants Alaei
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implementation of hazard and operability (HAZOP) analysis applied to identify all the dangerous deviations, potential hazards, and operational problems possibly associated the Claus reaction furnace package, blower, and heat exchanger equipment in a sulfur recovery unit (SRU). This allowed a significant reduction in implementation costs, where the expected saving from risk reduction was high. The efficiency of the SRU was strongly associated with the performance of those aforementioned components. It is noteworthy that these components are the most important parts of the SRU. The analysis led to recommendation concerning risk ranking in such plants. In addition, cause and effect diagrams for the Claus burner in start-up/heating and fuel gas/sour gas modes were presented. Davoudi et al. (JNGSE, 2014, 19, 116e124) performed experiments to establish the effects of impurities on thermal degradation and corrosivity of amine solutions in a sour gas sweetening plant. The effects of heat stable salt on pressure drop, pressure drop on steam consumption, MEG contamination of the solvent on boil up temperature, H2S loading, heat stable salts and chloride on corrosion rates were investigated. The results indicated that the presence of MEG in an aqueous phase affected the thermal degradation temperature of the solution. It also changed the solution concentration and the acid gas loading. Analysis also suggested that acetate anion could be carried over in the system from upstream process units.
10. Ongoing sour gas research JNGSE also has manuscripts under review in July 2015, not included in this virtual special issue, addressing the following sour gas and gas contaminant topics: Integrated mathematical modeling for prediction of rich CO2 absorption in structured packed column at elevated pressure conditions; Effects of a cooler's operating parameters on the performance of CO2 absorption processes using alkanolamine solutions; Refrigeration cycles in low-temperature distillation processes for the purification of natural gas; Modeling of nitrogen separation from natural gas through nanoporous carbon membranes; Modeling of PES/modified Multi-Walled Carbon Nanotube (MWCNT) mixed matrix membranes performance for CO2/CH4 separation using artificial neural network and ANFIS; Natural gas sweetening using PU-zeolite X nanocomposite membranes; Prediction of carbon dioxide solubility in amino acid salt solutions as absorbents using artificial neural network and DeshmukheMather models;
The activity loss modeling for the catalytic reactor of a sulfur recovery unit in South Pars Gas Complex (SPGC) 3rd Refinery based on percolation theory; Feasibility of supersonic separation for deep natural gas sweetening using computational fluid dynamics: Early design; Process optimization of the gas sweetening unit to increase a sulfur recovery unit's performance. The diversity of above topics highlights the varied nature of ongoing research and the multiple ways in which sour gas removal methods and production from sour gas reservoirs could potentially be improved through a better understanding of the complex processes involved and innovative applications. The Journal of Natural Gas Science & Engineering has an ongoing interest in topics concerning sour gas that are relevant to natural gas, and is keen to be given the opportunity to review manuscripts addressing original research and case studies pertaining to such topics. We hope the articles presented in this compilation will not only provide you with ideas to develop your own ongoing research applications, but also inspire you to submit manuscripts of your current and future original research work to this journal. For detailed references pertaining to the JNGSE-published articles summarized above please see the main VSI document (http://dx.doi.org/10.1016/j.jngse.2015.08.006). References Østergaard, K.K., Tohidi, B., Danesh, A., Todd, A.C., Burgass, R.W., 2000. SPE Prod. Facil. 15, 228e233. Wood, D.A., 2015a. Gas hydrate research advances steadily on multiple fronts: a collection of published research (2009 - 2015). J. Nat. Gas Sci. Eng. 24, A1eA8. Wood, D.A., 2015b. Carbon dioxide (CO2) handling and carbon capture utilization and sequestration (CCUS) research relevant to natural gas: A collection of published research (2009-2015). J. Nat. Gas Sci. Eng. 25, A1eA9. Zhang, Z., Wood, D.A., 2015. Virtual special issue: sour gas reservoirs and sulfurremoval technologies: a collection of published research (2009 to 2015). J. Nat. Gas Sci. XX. XXXeXXX.
Zhien Zhang, Editorial Supervisor Journal of Natural Gas Science & Engineering, College of Power Engineering, Chongqing University, Chongqing, China E-mail address: [email protected]. David A. Wood, Editor-in-Chief* Journal of Natural Gas Science & Engineering, DWA Energy Limited, Lincoln, United Kingdom *
Corresponding author. E-mail address: [email protected] (D.A. Wood). Available online 12 August 2015