2018-01-19T21:12:36Z
http://gpj.ui.ac.ir/?_action=export&rf=summon&issue=3731
Gas Processing
2322-3251
2322-3251
2014
2
2
Selecting Optimal Acid Gas Enrichment Configuration For Khangiran Natural Gas Refinery
Ali
Garmroodi Asil
Akbar
Shahsavand
Â Performance and capacity of sulfur recovery unit (SRU) are greatly affected by the H2S:CO2 ratio of the acid gas stream. The acid gases in Iran contain around 35 mol% H2S and 60 mol% CO2. This low concentration of H2S calls for more complex sulfur plant, larger equipments, and higher costs. Acid gas enrichment processes (AGE) is run to upgrade low quality acid gas collected from gas treating units in to higher quality Claus plant feed stream. Using specially formulated solvents or modifications of the existing gas treating units are the most popular approaches for efficient acid gas enrichment. Â Three different enrichment schemes are considered and simulated for Khangiran refinery acid gas stream. The results are then compared with each others to select the optimal AGE scheme, which can maximize the H2S content of SRU feed stream while minimizes H2S emission to atmosphere. In the first scheme, part of the acid gas leaving the GTU regenerator overhead is recycled back to the main contactor. In the other two, a separate enrichment tower is utilized between the amine flash drum and regenerator. In the second scheme, the enrichment tower pressure is set between regenerator pressure and ambient pressure, while in the third scheme, the enrichment tower pressure is fixed between amine flash drum pressure and regenerator pressure. The simulation results revealed that the SRU feed stream can be significantly enriched from its original value of 33.5 mol% H2S to about 70 mol%, by applying to the third scheme.
Acid Gas
Enrichment
SRU
age
Simulation
Khangiran Refinery
2014
02
01
1
21
http://gpj.ui.ac.ir/article_20179_d2c5a9adc7bb4a9f0f85934cfe73ef6c.pdf
Gas Processing
2322-3251
2322-3251
2014
2
2
Mathematical Modeling of Gas Adsorption Processes in Packed Bed: The Role of Numerical Methods on Computation Time
Maryam
Mashayekhpour
Mohammadreza
Talaie
Rigorous mathematical modeling of adsorption processes in packed beds involves time-consuming computations which are considered as the fundamental weakness of such thorough mathematical models. Thus, reducing the computation time was a key factor in improving adsorption mathematical models. In order to achieve this goal, an attempt was made to know how much using different numerical methods influenced the accuracy and time of these computations. For this purpose, the adsorption process of gas mixture consisting of H2O, CO2, CH4 and N2 in a tower packed with Zeolite 5A was considered to be modeled. The mathematical model was simplified based on the fact that neglecting the variations of pressure and temperature had no significant effect on the results of the model. This fact has been confirmed through previous research (M. Gholami & Talaie, 2009). The main objective of this study was to compare the capabilities of two important numerical methods in terms of their computation time and stability. Finite difference and orthogonal collocation were the numerical methods that were taken into account to be examined in solving the governing equations. The results obtained in this study revealed that orthogonal collocation was the best to solve pellet equations, while finite difference was more appropriate for bed equations. As a result, a combined method was suggested to be proper, i.e. orthogonal collocation for solving pellet equations and finite difference for solving bed equations. The results demonstrated that the combined method required half as much computation time as the one in which finite difference method was employed to solve the whole equations.
Simulation
Natural gas
Zeolite 5A
Adsorption
Orthogonal Collocation
Finite Difference
2014
02
01
23
38
http://gpj.ui.ac.ir/article_20176_c492e2a47cdc121f65afb8b473e67d20.pdf
Gas Processing
2322-3251
2322-3251
2014
2
2
Thermodynamic and Economic Optimization of a Refrigeration Cycle for Separation Units in the Petrochemical Plants Using Pinch Technology and Exergy Syntheses Analysis
Soheil
Sheikhi
Bahram
Ghorbani
Reza
Shirmohammadi
Mohammad-Hossein
Hamedi
Exergy and thermoeconomic analyses are herein employed to evaluate the proposed refrigeration cycle of Tabriz olefin plant. The exergetic and exergoeconomic variables of all equipment and streams are calculated. Thermoeconomic model is developed according to the total revenue requirement (TRR) method. The results indicate that the rational efficiencies of the Heat Exchanger E-104 and compressor are the lowest. Throttle valves also have 38% of the total exergy destruction, aside from the compressor which alone have 31% of exergy destruction of the cycle. In addition, heat exchanger LNG-100 and E-104 have respectively 15% and 10% of the total exergy losses of the system and the other equipment do not have a considerable amount of exergy destruction and loss. The thermoeconomic analysis results can depict valuable cost-based information concerning capital investment and operating costs of the system.
Aspen HYSYS
Exergy
Thermoeconomic
Refrigeration Cycle
Mixed Refrigerant
2014
02
01
39
51
Gas Processing
2322-3251
2322-3251
2014
2
2
Modeling the Solubility of Acid Gases in Ionic Liquids
Cyrus
Ghotbi
Mohammadali
Safavi
Maryam
Tavakolmoghadam
In this work, the PC-SAFT equation of state (EoS) has been used to model the solubility of acid gases (CO2 and H2S) in two imidazolium-based ionic liquids (ILs) ([C8-mim][PF6] and [C8-mim][Tf2N]). Parameters of pure ILs were estimated using experimental densities. Two strategies were considered to model densities of pure ILs. In strategy 1, ILs were modeled as nonassociating compounds and in strategy 2 ILs were considered as self-associating molecules and both association sites were assigned to each ILs. According to the results, the associating contribution should be taken into account in order to accurately correlate the properties of ILs. The solubility of CO2 and H2S in ionic liquids was then studied. In order to describe the experimental gas solubilities quantitatively, binary interaction parameters between the ILs and the gases were applied, which were allowed to depend linearly on temperature. After fitting a binary interaction parameter kij on experimental VLE data, the model was able to describe accurately the solubility of acid gases in these two ionic liquids. Using second strategy, an average deviation of less than 2.2% and 3.2% in the calculation of the mole fraction of CO2 and H2S in ILs (x2) were obtained, respectively.
Acid Gas
PC-SAFT
Ionic Liquid
Solubility
PC
SAFT
2014
02
01
53
66
http://gpj.ui.ac.ir/article_20178_a302fa555343bfe32c30d72957b9d874.pdf
Gas Processing
2322-3251
2322-3251
2014
2
2
Investigating the Effects of Inlet Conditions and Nozzle Geometry on the Performance of Supersonic Separator Used for Natural Gas Dehumidification
Akbar
Shahsavand
Seyed Heydar
Rajaee Shooshtari
Supersonic separators have found extensive applications in dehumidification of natural gases since 2003. Unlike previous studies, which have investigated the inlet conditions and nozzle geometry of supersonic separators for pure fluids, the present study employed a combination of momentum, heat, and mass transfer equations along with Virial equation of state (EOS) to inspect the effect of inlet conditions and nozzle geometry for methane-water systems. The simulation results were validated using several experimental data (borrowed from the literature) to ensure the capability of the current model. Afterward, the effects of various inlet parameters (P & T) and nozzle geometries (converging and diverging angles) were examined on the position of collection point and nucleation zone for separation of water vapor from a methane rich natural gas. The simulation results indicated that inlet gas temperature and pressure and diverging nozzle angle had severe effects on the condensation process inside supersonic separator, while the converging nozzle angle affects the inlet gas velocity and had minor effect on condensation process. For example, by increasing the 3S inlet pressure from 6 MPa to 10 MPa, the distance between throat and collection point reduced at least by half, whereas decreasing the inlet temperature from 300K to 285K, drastically decreased the same distance by fourth. The diverging nozzle angle effect approximately stood between the above two values.
Supersonic Separator
Natural gas
Dehumidification
Optimal Conditions
Geometry
2014
02
01
67
80
http://gpj.ui.ac.ir/article_20180_59985614b17f41a46b7c5a230b9aed1c.pdf
Gas Processing
2322-3251
2322-3251
2014
2
2
Developing a Novel Temperature Model in Gas Lifted Wells to Enhance the Gas Lift Design
Farzaneh
Rabiee Shirehjini
Peyman
Pourafshari
Ayub
Zamani
In the continuous gas lift operation, compressed gas is injected into the lower section of tubing through annulus. The produced liquid flow rate is a function of gas injection rate and injection depth. All the equations to determine depth of injection assumes constant density for gas based on an average temperature of surface and bottomhole that decreases the accuracy of gas lift design. Also gas-lift valve design requires exact temperature at each valve depth. Hence, enhanced gas lift design can be achieved by more accurate prediction of temperature profile in annulus and tubing. Existing temperature models for gas lifted wells have been roughly and inaccurately estimated for they ignore temperature variation due to phase changes as well as cooling the effect of injected gas inflow to the wellbore. Also, they find temperature profile from a known injection depth obtained from unreal previous assumptions. In this paper a novel model is developed to obtain the temperature profile in annulus and tubing of gas lifted well and injection depth simultaneously. This new model considers all the real conditions such as heat transfer between triple systems of liquid slug, injected gas and formation, cooling effect of gas inflow, joule-Thomson effect, potential energy, and phase changes in both conduits. The model was applied on Iran's Aghajary oil field wells. Results showed how ignoring temperature variations caused substantial errors in gas lift design. From our experience and according to results of this simulator, it can be concluded that the calculated injection depth from classic method and developed model had a difference between 200 and 400m for Aghajary field wells, as the total depth varied from 3000 to 4200m. The comparison made between temperature profile resulted from developed simulator and previous temperature models using temperature survey data of Aghajary wells showed much better matching for developed simulator.
Gas Lift Design
Joule-Thomson Effect
Temperature Profile
Pressure Profile
Joule
Thomson Effect
Modeling
2014
02
01
81
85
http://gpj.ui.ac.ir/article_20177_817e114fc19ff0bb412f338636d9d871.pdf