Optimizing Location of CO2 Recovery Units

2021 ◽  
Author(s):  
Indrajit Dutt ◽  
Jagannathrao Allamaraju
Keyword(s):  
Molecular Sieves ◽  
Unit Cost ◽  
Co2 Removal ◽  
Treatment Unit ◽  
Gas Treatment ◽  
Acid Gas ◽  
Recovery Unit ◽  
Gas Removal ◽  
Technology Maturity ◽  
Co2 Recovery

Abstract In line with ADNOC Sustainability policy, reduction of GHG emissions, AGP has initiated projects for recovery of CO2 from existing plants. The extracted CO2 is planned to be used for Enhanced Oil Recovery. The current paper highlights method used for evaluation of various location and technology options for implementation of the new CO2 recovery units, considering existing plants flow schemes along with their interfaces and associated challenges. Key Performance Indicators (KPIs) were identified based on Inherent Safety, Economics, Technology Maturity, Product Quality, Operability / Flexibility, Constructability. Identified options were further developed and subsequently evaluated based on preliminary economic analysis and available technical information. Accordingly, weighted scores of the KPIs developed for option selection. Major criteria used for ranking were unit cost of CO2 product, adherence to required H2S and COS specifications, technology maturity and deployment in industry.For one location, the options considered included installation of new Acid Gas Removal Unit (AGRU) upstream of existing AGRU, revamp of existing Acid Gas Enrichment Unit (AGEU), new AGEU, and direct feed of Acid gas to new CO2 recovery unit to supplement falling upstream reservoir profile.For another location, the options included new CO2 recovery plant upstream of existing Sulphur Recovery Unit (SRU) or downstream of existing Tail Gas Treatment Unit (TGTU), compression of TGTU gases upstream of proposed CO2 recovery unit, installation of new unit downstream of existing incinerators, combination of CO2 recovery units of both plants, were also assessed.In addition, new CO2 Dehydration and Compression units considered to meet CO2 product specifications and B/L requirements. Based on project requirements, physical methods of CO2 removal like membranes and molecular sieves deemed unsuitable. Further to discussions with various licensors, emphasis remained on chemical and physical solvent technologies. Based on assessment, solvent swap for AGEU (upstream of existing SRUs) with reduced lean solvent temperature at one location, solvent swap in TGTU followed by a new polishing unit at another location combined with common high pressure compression facility, was selected for engineering development.

A Novel Coal-Based Hydrogen Production System With Low CO2 Emissions

2009 ◽  
Author(s):  
Gang Xu ◽  
Hongguang Jin ◽  
Yongping Yang ◽  
Liqiang Duan ◽  
Wei Han ◽  
...  
Keyword(s):  
Energy Consumption ◽  
Hydrogen Production ◽  
Production Process ◽  
Production System ◽  
H2 Production ◽  
Co2 Removal ◽  
Low Co2 ◽  
Recovery Unit ◽  
Energy Penalty ◽  
Co2 Recovery

In this paper, we have proposed a novel coal-based hydrogen production system with low CO2 emission. In this novel system, a pressure swing adsorption H2 production process and a CO2 cryogenic capture process are well integrated to gain comprehensive performance. In particular, through sequential connection between the PSA H2 production process and the CO2 capture unit, the CO2 concentration of PSA purge gas that entering the CO2 capture unit can reach as high as 70%, which results in as much as 90% of CO2 to be separated from mixed gas as liquid at temperature of −55°C. This will reduce the quantity and quality of cold energy required for cryogenic separation method, and the solidification of CO2 is avoided. The adoption of cryogenic energy to capture CO2 enables direct production of liquid CO2 at low pressure, and thereby saves a lot of compression energy. Besides, partial recycle of the tail gas from CO2 recovery unit to PSA inlet can help to enhance the amount of hydrogen product and lower the energy consumption for H2 production. As a result, the energy consumption for the new system’s hydrogen production is only 196.8 GJ/tH2 with 94% of CO2 captured, which is 9.2% lower than that of the coal-based hydrogen production system with Selexol CO2 removal process, and is only 2.6% more than that of the coal-based hydrogen production system without CO2 recovery. What’s more, the energy consumption of CO2 recovery is expected to be reduced by 20–60% compared to that of traditional CO2 separation processes. Further analysis on the novel system indicates that synergetic integration of the H2 production process and cryogenic CO2 recovery unit, along with the synthetic utilization of energy, plays a significant role in lowering energy penalty for CO2 separation and liquefaction. The promising results obtained here provide a new approach for CO2 removal with low energy penalty.

Hexapod Pilot Tests Determine the Influence of 3D Motions on the Performance of an Amine-Based Acid Gas Removal Unit Installed on a Floating Support

2016 ◽  
Author(s):  
Perdu Gauthier ◽  
Salais Clément ◽  
Carlier Vincent ◽  
Prosernat S. A Weiss Claire ◽  
Maubert Thomas ◽  
...  
Keyword(s):  
Acid Gas ◽  
Gas Removal ◽  
Pilot Tests

Simulation of an Acid Gas Removal Unit Using a DGA and MDEA Blend Instead of a Single Amine

2020 ◽  
Vol 0 (0) ◽  
Author(s):  
Umer Zahid
Keyword(s):  
Energy Savings ◽  
Circulation Rate ◽  
Inlet Temperature ◽  
Acid Gas ◽  
Gas Processing ◽  
Gas Removal ◽  
Processing Plants ◽  
Operational Energy ◽  
Commercial Process ◽  
The Impact

AbstractMost of the industrial acid gas removal (AGR) units employ chemical absorption process for the removal of acid gases from the natural gas. In this study, two gas processing plants operational in Saudi Arabia have been selected where two different amines n1amely, diglycolamine (DGA) and monoethanol amine (MDEA) are used to achieve the sweet gas purity with less than 4 ppm of H2S. This study performed a feasibility simulation of AGR unit by utilizing the amine blend (DGA+MDEA) for both plants instead of a single amine. The study used a commercial process simulator to analyze the impact of process variables such as amine circulation rate, amine strength, lean amine temperature, regenerator inlet temperature, and absorber and regenerator pressure on the process performance. The results reveal that when the MDEA (0–15 wt. %) is added to DGA, marginal energy savings can be achieved. However, significant operational energy savings can be made when the DGA (0–15 wt. %) is blended with MDEA being the main amine.

Investigation of a Shell and Tube Exchanger in Process Gas Heating Service

2008 ◽  
Author(s):  
M. A. Porter ◽  
D. H. Martens
Keyword(s):  
Heat Exchanger ◽  
Tube Sheet ◽  
Sulfur Recovery ◽  
Treatment Unit ◽  
Gas Treatment ◽  
Flexible Tube ◽  
Process Gas ◽  
Large Shell ◽  
Section Viii ◽  
Shell And Tube

The design requirements for a large shell and tube vertical heat exchanger (to be used in a sulfur recovery tail gas treatment unit) included startup, shutdown and upset conditions that would subject the exchanger to significant temperature changes. The exchanger was designed to the requirement of the ASME Boiler and Pressure Vessel Section VIII Division 1 [1]. A detailed analysis of the thermal profiles and related stresses was performed to confirm the use of a flexible tube sheet design. The heat exchanger uses high pressure superheated steam on the shell side to heat a low pressure process gas on the tube side. The heat exchanger was sized and thermally rated, using commercially available analysis software. The proposed design was analyzed by Finite Element methods that included both thermal and stress analysis. These evaluations confirmed that a flexible tube sheet design was satisfactory when using specific dimensions.

Exergy and Exergoeconomic Assessment of an Acid Gas Removal Unit in a Gas Refinery Plant

2021 ◽  
Author(s):  
Mohamad Mohamadi-Baghmolaei ◽  
Abdollah Hajizadeh ◽  
Sohrab Zendehboudi ◽  
Xili Duan ◽  
Hodjat Shiri ◽  
...  
Keyword(s):  
Acid Gas ◽  
Gas Removal ◽  
Refinery Plant ◽  
Gas Refinery

Carbon Emission Reduction via HNGLRP CC&S Technology

2021 ◽  
Author(s):  
Sultan Ahmari ◽  
Abdullatef Mufti
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Water Reuse ◽  
Carbon Emission ◽  
Ventilation System ◽  
Acid Gas ◽  
Gas Removal ◽  
Saudi Aramco ◽  
Supercritical Phase ◽  
Incineration Process

Abstract The paper objective is to present the successful achievement by Saudi Aramco gas operations to reduce the carbon emission at Hawyiah NGL Recovery Plant (HNGLRP) after successful operation & maintainability of the newly state of the art Carbon Capture & Sequestration (CC&S) technology. This is in line with the Kingdom of Saudi Arabia (KSA) 2030 vision to increase the resources sustainability for future growth and part of Saudi Aramco circular economy in action examples. Saudi Aramco CC&S started in June 2015 at HNGLRP with main objective to capture the carbon dioxide (CO2) from Acid Gas Removal Units (AGRUs) and then inject an annual mass of nearly 750 Kton of carbon dioxide into oil wells for sequestration and enhanced oil recovery maintainability. This is to replace the typical acid gas incineration process after AGRUs operation to reduce carbon footprint. CC&S consists of the followings: integrally geared multistage compressor, standalone dehydration system using Tri-Ethylene Glycol (TEG), CO2 vapor recovery unit (VRU), Granulated Activated Carbon (GAC) to treat water generated from compression and dehydration systems for reuse purpose, and special dense phase pump that transfers the dehydrated CO2 at supercritical phase through 85 km pipeline to replace the typical sea water injection methodology in enhancing oil recovery. CC&S has several new technologies and experiences represented by the compressor capacity, supercritical phase fluid pumping, using mechanical ejector application to maximize carbon recovery, and CO2/TEG dehydration system as non-typical dehydration system. CC&S design considered the occupational health hazards generated from the compressor operation by installing engineering enclosure with proper ventilation system to minimize the noise hazard. CC&S helped HNGLRP to reduce the overall Greenhouse Gas (GHG) emission resulted from typical CO2 incineration process (thermal oxidizing). (2) The total GHG resulted from combustion sources at HNGLRP reduced by nearly 30% since CC&S technology in operation. The fuel gas consumption to run the thermal oxidizers in AGRUs reduced by 75% and sent as sales gas instead. The Energy Intensity Index (EII) reduced by 8% since 2015, water reuse index (WRI) increased by 12%. In conclusion, the project shows significant reduction in the carbon emission, noticeable increase in the production, and considerable water reuse.

scholarly journals EVALUASI KESETIMBANGAN KELARUTAN GAS KARBON DIOKSIDA (CO2) DALAM PELARUT ALKANOLAMINA MENGGUNAKAN SIMULATOR PROSES

2015 ◽  
Vol 4 (4) ◽  
pp. 1-7
Author(s):  
Yansen Hartanto ◽  
Tri Partono Adhi ◽  
Antonius Indarto
Keyword(s):  
Natural Gas ◽  
Process Simulation ◽  
Column Temperature ◽  
Basic Module ◽  
Acid Gas ◽  
Simulation Tools ◽  
Gas Removal ◽  
Commercial Process ◽  
Electrolyte Nrtl ◽  
Carbon Dioxide Co2

Acid gas removal to remove carbon dioxide (CO2) in natural gas is one of the most important processes. The common removal process of CO2 from natural gas by using alkanolamine solution This process was adopted as basic module in commercial process simulation tools with various equilibrium models. Thus, this study was focused to evaluate the validity in certain operating condition and equilibrium model that produced by commercial simulation tools. The model in this study included coefficient activity model based on Kent-Eisenberg, Li-Mather, and Electrolyte Non Random Two Liquid (NRTL). The evaluation was conducted by doing analysis from simulation result and experiment data that have been used as reference. Furthermore, validation test in absorption process simulation was done to compare column temperature profile. The overall conclusions show that electrolyte NRTL gives the most accurate result.

scholarly journals Analisis dan Optimasi Pengaruh Suhu Gas Umpan Pada Kinerja Acid Gas Removal Unit

2021 ◽  
Vol 1 ◽  
pp. 67-74
Author(s):  
Iwan Febrianto ◽  
Nelson Saksono
Keyword(s):  
Simulation Model ◽  
Flow Rate ◽  
Gas Production ◽  
Gas Content ◽  
Production Test ◽  
Reservoir Pressure ◽  
Gas Temperature ◽  
Separation Unit ◽  
Acid Gas ◽  
Gas Removal

The Gas Gathering Station (GGS) in field X processes gas from 16 (sixteen) wells before being sent as selling gas to consumers. The sixteen wells have decreased in good pressure since 2011, thus affecting the performance of the Acid Gas Removal Unit (AGRU). The GGS consists of 4 (four) main units, namely the Manifold Production/ Test, the Separation Unit, the Acid Gas Removal Unit (AGRU), the Dehydration Unit (DHU). The AGRU facility in field X is designed to reduce the acid gas content of CO2 by 21 mol% with a feed gas capacity of 85 MMSCFD. A decrease in reservoir pressure caused an increase in the feed gas temperature and an increase in the water content of the well. Based on the reconstruction of the design conditions into the simulation model, the amine composition consisting of MDEA 0.3618 and MEA 0.088 wt fraction to obtain the percentage of CO2 in the 5% mol sales gas. The increase in feed gas temperature up to 146 F caused foaming due to condensation of heavy hydrocarbon fraction, so it was necessary to modify it by adding a chiller to cool the feed gas to become 60 F. Based on the simulation, the flow rate of gas entering AGRU could reach 83.7 MMSCFD. There was an increase in gas production of 38.1 MMSCFD and condensate of 1,376 BPD. Economically, the addition of a chiller modification project was feasible with the economical parameters of NPV US$ 132,000,000, IRR 348.19%, POT 0.31 year and PV ratio 19.06.

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