Effect of operating conditions on cryogenic CO2 ... - Wiley Online Library

DOI: 10.1002/ente.201600802

Effect of Operating Conditions on Cryogenic Carbon Dioxide Removal Farhad Fazlollahi,*[a] Samrand Saeidi,[b, c] Mohammad-Saeed Safdari,[a] Majid Sarkari,[d] Jirˇ& J. Klemesˇ,[e] and Larry L. Baxter[a] In this investigation, a natural-gas (NG) treatment system for NG sources with high CO2 content is simulated experimentally and theoretically using Aspen Plus. The concept uses patented heat exchangers and a process design developed as part of the cryogenic carbon capture(CCC) process to remove enough CO2 to enable the treated gas to be handled without the modification of traditional NG equipment. Simultaneously, the process removes liquefied natural gas (LNG) very efficiently. This process provides a simpler alternative to the solvent-based CO2 removal, absorbent drying,

and cryogenic NG liquid extraction systems found in traditional NG processing. The data from an experimental benchscale apparatus verify the results of the simulations as a function of NG composition and pressure. Costing parameters, exergy loss, and heat-exchanger efficiency are also discussed. The results confirm low exergy losses for bench-scale apparatus. The system uses heat exchangers with efficiencies of more than 90 %. High pressure and low methane content in the NG result in high CO2 capture.

Introduction Climate scientists attribute climate change overwhelmingly to fossil-fuel utilization and the associated increase in the atmospheric CO2 concentration.[1] However, nearly all projections show that fossil-fuel utilization is increasing at significant rates, driven largely by the increased energy demand caused by economic progress in underdeveloped nations. Although this demand continues to be met predominantly by fossil fuels, carbon capture and storage (CCS) is one possible way of mitigating the otherwise global climate threat associated with increased energy use.[2] The commercialization of carbon capture (CC) faces several obstacles. Principal among these are improved efficiency and reduced cost.[3] For example, CC from existing power plants consumes up to 30 % of the energy and greatly increases power costs. These costs and inefficiencies increase significantly for CO2 emissions from distributed, mobile, or intermittent sources. Transportation and power generation account for approximately 30 and 32 %, respectively, of global CO2 emissions. Current CO2 capture technologies suitable for stationary flue gas include amine scrubbing, cryogenic distillation, solid sorbent adsorption, chemical looping, oxyfuel combustion, and a host of developing technologies.[3] None of these are commercially established, but amine scrubbing was employed at one small commercial-scale power plant.[4] Additional CO2 reductions can be achieved through the reduction of fossilfuel combustion or the improvement of the efficiencies of coal-fired plants.[5] Carbon capture and storage is identified by energy and environmental groups as one of the most essential elements of any plan to reduce CO2 emissions. Carbon capture falls into three categories: (1) precombustion carbon capture,[6] (2) combustion technology changes,[7] and Energy Technol. 2017, 5, 1588 – 1598

(3) postcombustion carbon capture.[6] Precombustion carbon capture implies the removal of carbon before combustion, usually through gasification processes and CO2 capture from the producer gas. Gasification is more expensive and difficult to operate than combustion; however, once a gasifier is operating, CO2 capture from the producer gas is cheaper.[8] Combustion technology changes include oxyfuel and chemicallooping combustion. Like precombustion capture, this option requires new facilities and is more suited to new power plants than existing power plants. Postcombustion capture separates CO2 from nitrogen–carbon dioxide mixtures as the main constituent of the flue gas generated in power plants is nitrogen.

[a] Dr. F. Fazlollahi, Dr. M.-S. Safdari, Prof. L. L. Baxter Chemical Engineering Department Brigham Young University Provo, UT 84602 (USA) E-mail: [email protected] [b] Dr. S. Saeidi School of Chemical Engineering Amirkabir University of Technology (Tehran Polytechnic) No. 424, Hafez Avenue, 15914, Tehran (Iran) [c] Dr. S. Saeidi Departments of Wood and Paper Science Research Institute of Forests and Rangelands (RIFR) Tehran (Iran) [d] Dr. M. Sarkari South Pars Gas Complex Company Asalooye (Iran) [e] Prof. J. J. Klemesˇ Faculty of Information Technology and Bionics P#zm#ny P8ter Catholic University 1083 Budapest, Pr#ter utca 50/a (Hungary)

T 2017 Wiley-VCH Verlag GmbH & Co. KGaA, Weinheim

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The most mature technology for postcombustion carbon capture involves the absorption ofCO2 in solvents, typically amine solutions. Amine-based postcombustion CO2 capture technology has well-established applications in chemical processing, especially the treatment of natural gas (NG). However, the application of this technology to power plants requires significant changes, largely because of the change in stoichiometry from reducing to oxidizing conditions, the change in pressure and temperature, and the suitability of the very large flows with trace contaminants at power plants. Many of the postcombustion processes available for carbon capture are shown in Figure 1. The major processes available can be grouped as follows.[9]

Absorption processes (chemical and physical absorption) This process uses solvents that absorb CO2 selectively and is the most common technology used for the removal of acid gas. The solubility of CO2 depends on its partial pressure and on the temperature. Higher CO2 partial pressures and lower temperatures favor CO2 solubility. There are generally two categories of absorbents, namely, potassium carbonate, which causes stress corrosion and erosion, and amine-based solvents. Owing to the high capital demand of potassium carbonate methods, the amine absorption process is by far the most common.[10] This process can meet common pipeline

specifications of no more than 3 % CO2[11] but struggles to meet the 50 ppm specification of liquefied natural gas (LNG).[12] Adsorption process This process is based on the exothermic reaction of a solvent with the gas stream to remove the CO2 present. Most chemical reactions are reversible; in this case, the reactive solvent removes CO2 in the contactor at high pressure and preferably at low temperature.[13] The reaction is then reversed by endothermic stripping at high temperature and low pressure. In these processes, the gas flows through the fixed bed, while the acid gases adsorb on solid particles.[14] The beds need to be replaced or regenerated by heating once the bed saturates with acid gases. More details on these processes can be found elsewhere.[15] Physical separation (membrane, cryogenic separation) Membranes are an emerging process for CO2 separation from natural gas and find increasing use in gas-field operations for reducing carbon dioxide and water vapor to meet pipeline and LNG specifications. For a gas to permeate through a membrane, the gas must enter the high-pressure side of the membrane, diffuse across the membrane wall, and

Figure 1. Postcombustion carbon capture processes.[3]

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exit from the low-pressure side. Membranes are usually good for the bulk removal of acid gases. At low concentrations of acid gases, membrane technology is inferior to other processes. This is because the partial pressures of the components are small at low concentrations, and the pressure driving force of the process decreases. In such situations, membrane technology is sometimes combined with chemical solvent systems. This combined process has high adaptability to the variation of the CO2 content in the feed gas, and membranes have good weight and space efficiency; therefore, this process is more applicable to an offshore environment. However, the separated CO2 is at low pressure and requires additional compression to meet pipeline pressure requirements; therefore, the hydrocarbon losses are high. Hybrid solution (mixed physical and chemical solvent) The hybrid separation processes combine the properties of physical and chemical solvents for the effective and selective removal of acid gas from natural gas. In a physical solvent process, the acid gases are dissolved in the solvent instead of reacting with it. The solubility of CO2 varies with pressure and temperature and, hence, these processes are sensitive to changes in these operating conditions. Most physical solvent processes require licenses, for example, the Selexol, Sulfinol, and Fluor processes. Physical solvent processes should be avoided for gases with high heavier-hydrocarbon fractions and they are usually used if the partial pressure of the acid gases is above 3.5 bar. Success has been achieved through the combination of physical and chemical solvent processes.[16] The current investigation explores an alternative separation technology for natural-gas processing to meet composition standards and separate high-value products, such as natural gas liquids. Typical pipeline specifications limit CO2 to 1–3 %,[11] and the CO2 concentration in some fields starts as high as 70 %. An example of a gas field with a very high concentration of CO2 is the giant Natuna offshore gas field, Indonesia. The removal of CO2 in natural gas is an industrydriven rather than regulation-driven practice and, therefore, provides an opportunity for the more immediate adoption of promising new technologies. Liquefaction processes that transform natural gas to liquid form involve operation at a very low temperature (@161 8C) and as low as atmospheric pressure. Under these conditions, CO2 freezes on exchanger surfaces, plugs lines, and reduces plant efficiency. Therefore, CO2 must be removed before liquefaction. This is done not only to overcome the process bottlenecks but also to meet the LNG product specifications and prevent the corrosion of process equipment. In addition to its environmental impact, CO2 reduces the heating value of the CH4 gas streams in power plants.[17] The quality requirements for NG are 2 and 2.5 % CO2 in Canada and the EU, respectively.[18] The US does not currently have federal LNG quality requirements, but revaporized LNG must meet NG pipeline standards of 2–4 % CO2. Industrial natural-gas specifications require 50 ppm of CO2 or less for streams that form LNG. The Energy Technol. 2017, 5, 1588 – 1598

reason for CO2 removal down to 50 ppm stems from concerns about the degradation of operability caused by potential CO2 freezing during the liquefaction of natural gas. The solubility of CO2 in the final LNG product under normal conditions is higher than 50 ppm.[19] Thus, it is important to consider the application of the cryogenic carbon capture (CCC) of LNG to achieve 50 ppm CO2 and the potential for CO2-tolerant liquefaction. This makes the removal of CO2 from natural gas of crucial importance. The CCC processing of natural gas results in the formation of solids and, therefore, is distinguished from all but one of the alternative processes. The amine absorption processes discussed earlier are the most common and operate at temperatures and pressures well above the melting point of CO2. The one process that does form solid CO2 is the ExxonMobil Controlled Freeze Zone process, in which solids form in the middle of a distillation column but dissolve at the top of the column and melt at the bottom of the column. The CCC removes solid CO2 in desublimating heat exchangers and, therefore, is distinct from even the Controlled Freeze Zone technology. The process described here removes excess CO2 from natural-gas streams before traditional NG processing. The process produces three streams: an essentially pure CO2 stream that originates from the solid CO2 formed in this process, a liquid NG stream that contains small amounts of dissolved CO2, and a vapor stream that is predominantly CH4. The liquid NG stream is suitable for traditional, low-CO2-level processing. The vapor stream joins the NG produced downstream as a purified methane product. No commercial process simulation software known to the authors can predict the formation or destruction solids in heat exchangers or other process equipment except equilibrium reactors. This simulation works around these limitations by using reactors in series to approximate heat exchangers. Nevertheless, the multicomponent, solid–liquid–vapor equilibrium calculations over a broad temperature and pressure range present computational and theoretical challenges. For example, the dissolution of solids in liquids is normally considered to be pressure independent but will not be if the dissolving species is also present in the vapor phase. In this application, solid CO2 dissolves partially in liquid hydrocarbons and is simultaneously a component of the methane-rich vapor phase. This creates a complex pressure dependence of the amount of solid formed in the liquid phase. The amount of solid CO2 formed initially increases with pressure as increasing pressure causes CO2 vapor to condense or desublimate. The fraction of CO2 in the solid then decreases with further pressure increases as the hydrocarbon vapors increasingly condense, dilute the liquid phase, and dissolve additional fractions of solid CO2. Eventually, the solid CO2 fraction becomes insensitive to pressure as the vapor fraction drops to zero. This and similar complex behaviors depend on thermodynamic subtleties. An experimental component of this work provides confirmation of the thermodynamic predictions. The discussion also includes a financial analysis of the process.


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Process Design

Contact liquid

Feed-gas parameters The experimental CCC natural-gas treatment system uses an 8 mol h@1 (3100 cm3 min@1) feed stream of 84 % methane, 6 % ethane, 4 % propane, 1 % isobutane, and 5 % carbon dioxide. The power-plant simulations use a natural-gas flow rate of 1000 kmol h@ of a feed with the same composition. All of other operating conditions are the same (Table 1).

Process optimization A sensitivity analysis helps to optimize the system. Several variables provide the optimization objective function for the natural-gas and contact-liquid streams, including pressure, composition, and flow rate. For optimization, the composition and flow rate are tied together so that the flow rates of individual components were specified rather than their concentrations (mol-%) and the overall flow rate. The naturalgas stream is comprised of C1–C4 hydrocarbons. Each of these variables had three to five values, including the current value and at least one lower and higher value. The decision to include additional higher and lower values was based on the previous set of variables. Owing to the large number of possible combinations, each value was usually only given three values unless more were expected to significantly accelerate the process. The algorithm selects a new solution based on the two previous best solutions, and the process was repeated until the optimal solution repeated several times with adjustments to input values. The following process assumptions constrain the problem: 1) A minimum approach temperature of 1 8C was necessary in brazed-plate heat exchangers. 2) A single liquid phase flows through the expanders and pumps (100 % liquid flow). 3) The expansion valves operate adiabatically.[21–23]

The contact liquid (isopentane) forms a nearly closed loop with some minor losses into the solid CO2. In general, contact liquids should have low vapor pressures to decrease losses through evaporation and additionally be environmentally and physically benign. The contact liquid is used primarily to prevent the formation of solid CO2 on surfaces and, thus, prevent process freeze up. A pump pressurizes the slurry before it enters a solid–liquid separator. The separator consists of an auger-driven continuous filter press. The bulk contact liquid, now free of solids, is recooled in a closed-loop refrigeration system in preparation for re-entry to the desublimating column. The contact liquid recovered from the CO2-rich stream returns to the process. The vapor pressure data for contacting liquids under these operating conditions are not commonly available. Experimental vapor pressure measurements ensure compliance with hydrocarbon emission standards. Solid separation The CO2 solids separator reduces the contact-liquid content of the slurry to approximately 6.7 % in the solid. The press filter captures 100 % of the solid CO2 as assumed (adapted to the experimental results) in the simulation. This does not take solubility into account, which may increase the concentration of CO2 in the recycled contact liquid. However, this CO2 returns to the heat exchanger in a contact liquid and, therefore, does not leave the process. Phase equilibrium equations The Peng–Robinson (PR) equation describes the vapor and liquid phases in this simulation, including the default interaction parameters included in Aspen PlusTM.[24] Apparatus for natural-gas processing experimentation Aspen Plus simulates the CCC process for natural-gas treatment. However, Aspen Plus cannot form or destroy solids,

Table 1. Process parameters for the lab-scale system. Parameter

Value

feed-gas pressure contact-liquid pump pressure feed-gas temperature composition of the NG feed [mole fraction]

689.5 kPa 68–2758 kPa 20 8C CH4 C2H6 C3H8 C4H10

average molecular weight feed CO2 mole fraction pressure drop in heat exchanger pressure drop in cooler ambient temperature pump adiabatic efficiency

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CO2 5 kPa 1 kPa 25 8C 92 %

Notes

0.84 0.06 0.04 0.01 17.6 0.05

the value varies up to 22 % for economic analysis to simplify the process

[20]


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Figure 2. Aspen Plus simulation setup for CCC.

such as solid CO2 in any vessel other than a Gibbs reactor. Therefore, a series of Gibbs reactors approximate the desublimating heat exchangers in these simulations (see Figures 2 and 3). For more details, refer to Refs. [20–23].

The apparatus used in these natural-gas experiments operates at pressures up to 4 MPa with arbitrary gas compositions and temperatures from 20 to @133 8C (Figure 4). This system was built and demonstrated by others in the early portion of

Figure 3. Heat and mass transfer unit in the desublimator.

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Figure 4. Natural-gas-capable apparatus with (A) gas cylinder cabinet, (B) GC–MS sample analyzer, (C) exhaust fume hood for flaring and venting, (D) computer control interface, (E) bubbler and separator cold box, (F) reservoir cold box, (G) data acquisition, (H) mass-flow controllers, (I) heat exchange and pumping cold box, (J) power supply for mass-flow controller, (K) pump-motor controller, (L) pump motor, (M) cryocooler.

the development of CCC for flue gases.[20] The stainless-steel construction avoids deterioration, and a 10 mm polycarbonate blast shield protects the operators in the event of a catastrophic failure. Additional safety considerations include a hydrocarbon sensor with interlock, an oxygen sensor, and multiple pressure-relief valves. In these experiments, the process pressure ranges from local pressure (86 kPa absolute) to 4 MPa with an additional mass-flow controller on the exhaust gas. The cylinders contain 99.5 % pure CO2 (Airgas), 99.0 % pure CH4 (Airgas), 99.0 % pure C3H8 (Airgas), natural gas (88 % CH4, 7 % C2H6, 4 % C3H8, and 1 % C4H10 ; Airgas), and 99.0 % pure C2H6 (Praxair). The design maximum total gas flow rate is 3.7 L min@1, which is measured by four mass-flow controllers (Brooks 5850). A Sensidyne Gilibrator bubble chamber provides flow calibration, and gas analyzers verify the compositions of the mixed gases. The uncertainty of the flow measurements (C5 + ) is not significant because the experiments reach phase equilibrium. The cryogenic portion of the process occurs inside the cold boxes with cooling by liquid nitrogen or an industrial refrigeration system (Telemark TVP-2000, see Figure 4). The heat exchangers are stainless-steel, brazed-plate style (GEAPHE). A pump (Micro pump EW-73005-06) circulates the contact liquid through the desublimating heat exchanger and brazed-plate heat exchangers. A cartridge filter removes solid CO2 particles to extend the experimental run times and prevent the CO2 concentration in the liquid from exceeding the solubility limit. The cartridge filter uses a 30 X 30 mm stainless-steel mesh with 0.53 mm openings and was regenerEnergy Technol. 2017, 5, 1588 – 1598

ated by isolating, draining, and introducing warm nitrogen with manually operated valves. During the time that the filter is not in operation for regeneration, particles continue to build up within the system. However, measurements are not reported during regeneration because the contact liquid could have CO2 concentrations greater than that of the liquid-phase equilibrium. Three different gas analyzers measure the CO2 concentrations as the experiments progressed. A nondispersive infrared (NDIR) M-700 emissions analyzer (Enerac) has a limited resolution of 0.1 %. A 5975C quadrupole mass spectrometer (Agilent Technologies) provides additional gas analysis, specifically (1) verification of the adequacy of the CO2 measurements of the NDIR analyzer and (2) quantification of the trace elements (i.e., contact liquid). For portable skids, an industrial ABB EL3040 analyzer provides continuous results with an increased resolution compared with that of the M700 analyzer (0.006 %). The EL3040 also uses NDIR techniques and is limited to the CO2 concentration range of 0– 3 %. The analyzers were calibrated with National Institute of Standards and Technology (NIST) traceable calibration gas from Mesa Specialty Gases and with in-house calibration gases. The in-house calibration gases were prepared volumetrically using a 1 L syringe (SGE). The desublimating heat exchangers comprises a singlestage stainless-steel column with five 3.2 mm diameter holes for gas bubbling and a 13 mm diameter tube or downcomer (see Figures 5 and 6). The top of the downcomer is 25 mm above the bubbling plate; therefore, liquid builds up on the stage. The column rests on the inside of a stainless-steel pressure vessel. Liquid at the bottom of the vessel ensures that the entering gas progress up through the liquid on the tray and exchanges heat rather than passing the stage. At least 6 in. of perlite in every direction insulate the cold portions of the apparatus. In high-pressure experiments with the complete liquefaction of natural gas, there is no vapor stream from the desublimating column, and the natural gas enters the desublimating column as a warm gas. The pressure and temperature affect the performance of the desublimating heat exchanger strongly. The apparatus contains 16 K-type thermocouples (Omega) with uncertain-

Figure 5. Inside view of cold boxes with perlite insulation removed. From left to right: heat exchange and pumping cold box, reservoir cold box, and bubbling heat exchanger and separations cold box.


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LabVIEW program to control natural-gas apparatus The LabVIEW data acquisition (DAQ) system (National Instruments) provides data acquisition and process control. The front panel of the LabVIEW system contained controls for the pump flow rate and mass-flow controllers. The front panel also allows a user to adjust the P&ID controller parameters dynamically. The P&ID controller adjusted the total flow rate of the mass-flow controllers to achieve the set pressure. The display also had numerical and graphical indicators of the measured actual flow, pressures, and temperatures that were broken into four groups, namely, bubbler contact liquid, bubbler gas, metal contacts, and other process areas.

Figure 6. Stainless-steel single-stage columns.

ties of : 0.5 K in the temperature range 93–153 K. Four of the thermocouples measure the temperatures of the fluid streams immediately entering and exiting the desublimating heat exchanger. These thermocouples are calibrated through the comparison of the boiling points of pure nitrogen, pure methane, and pure ethane at known room pressures with the theoretical boiling points at these pressures. The experimental apparatus also contains two pressure transducers (Transducers Direct) with uncertainties of : 0.25 % over the pressure range 0–6.9 MPa. One of the pressure transducers is built into the desublimating heat exchanger, and the other monitors the pressure drop of the contact liquid over the solid CO2 filter. An Agilent 5975C Series GC/MSD instrument with a triple-axis high-energy diode electron multiplier (HEDEM) detector was used to measure the product composition. The 5975C detector uses a new ion guide and shield to position a new long-life triple-channel electron multiplier (EM) doubly off-axis from the analyzer exit. The optimized ion path increases the signal and eliminates noise from energetic neutrals. In the GC–MS analysis process, a fluid mixture was sampled, injected into the GC, and separated into its components, and the fragments were detected through MS.

Experimental procedure The system was purged with nitrogen before the introduction of the contact fluid, isopentane. The system was then cooled through the circulation of the contact liquid through the system as a cryogenic refrigerator, liquid nitrogen, or both, cooled the contacting fluid in brazed-plate heat exchangers to temperatures generally between 123 and 183 K. The volume of the contact liquid in the system is typically 2–3 L. The contact liquid circulates through the system at a rate of 2 L min@1. If the contact liquid and process equipment were sufficiently cool, gas flow started through the mass-flow controllers at the desired composition. After the flow of the inlet gas was started, the exhaust valve or mass-flow controller maintained a steady-state pressure as the system equilibrates. The visual verification of the performance of the desublimating column was extremely important in the first attempted experimental runs to ensure proper operation. Energy Technol. 2017, 5, 1588 – 1598

Results and Discussion The amount of CO2 captured equals the amount in the solid phase, which varies with temperature and pressure. This system provides reliable measurements of the system temperature and pressure as well as the compositions of the vapor and liquid phases. The system does not provide meaningful estimates of the amounts of vapor, liquid, or solid phases. The amounts of these phases help determine the amount of CO2 capture, which is the primary result of interest. The measured CO2 capture as a function of pressure and temperature depends on the measured compositions of the liquid and vapor phases, an assumed solid-phase composition of pure CO2, and the computed amounts of liquid and vapor phases. The assumption that the solid phase is pure CO2 should be accurate. However, the data and the predictions are not entirely independent of each other, as the data rely on the computed amounts of the liquid and vapor phases. Effect of pressure In this section, we explore the effects of pressure on CO2 capture and the mole fractions of CO2 and methane in the vapor. The pressure range was from 10 to 400 psi (1 psi = 6.89 kPa) with a constant temperature of @133 8C. The increasing CO2 capture and, hence, methane mole fraction in the vapor as the pressure increases are shown in Figure 7 a–c. Consequently, the mole fraction of CO2 in the vapor decreases. The plots in Figure 7 contain the experimental data, simulations of the performance of the lab-scale system, and simulations of a commercial power plant using a commercialscale version of this technology. The initial increase in capture with increased pressure stems from the decreasing vapor mole fraction of condensable CO2 with increasing pressure. The highest capture of 94.6 % (experimental) is observed at 206.84 kPa. However, as the pressure increases, the methane in the vapor also condenses and creates more liquid in which solid CO2 can dissolve. At a pressure of approximately 250 kPa, the condensing methane from the vapor more than compensates for the condensing CO2 from the vapor, and the capture efficiency begins to decrease. At approximately


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ture profile in a heat exchanger is only approximated. In the USA, Sustainable Energy Solutions (SES) maintains inhouse process modeling software that calculates the performances of desublimating heat exchangers more robustly and accurately. Effect of varying composition The composition of the NG including methane, ethane, and propane also affects CO2 removal. As the methane content increases, the CO2 and C1 content in the vapor stream increases, and the CO2 capture percentage decreases. As the ethane and propane content increases, the CO2 and C1 content of the vapor increases, and the CO2 capture percentage decreases. However, as illustrated in Figures 8 a and b and 9 a and b, ethane affects CO2 capture most strongly. In all cases, the effects of the composition on CO2 capture are slight. The

Figure 7. Effect of pressure on a) CO2 capture, b) methane vapor mole fraction, and c) CO2 vapor mole fraction.

600 kPa, all components in the vapor phase have condensed completely. From this point on, the capture efficiency does not change with pressure because the solubility of CO2 in the liquid mixture is insensitive to pressure. The experimental trends are consistent with the predictions, but the three-phase predictions require some sophistication. The Aspen simulations used here depend on some workarounds in the software, which can only form or destroy solids in a Gibbs reactor. Neither Aspen nor any other commercial process simulation software known to us is capable of forming and destroying solids in heat exchangers, turbines, and so forth. Therefore, a series of Gibbs reactors represents the desublimating heat exchangers, and the actual temperaEnergy Technol. 2017, 5, 1588 – 1598

Figure 8. Effect of varying compositions on CO2 capture at a) 206.84 and b) 517.1 kPa; x-axis label: A) 78 % C1, 15 % C2, 4 % CO2, 2.6 % C3, 0.4 % C4 ; B) 80 % C1, 12 % C2, 4.5 % CO2, 3 % C3, 0.5 % C4 ; C) 82 % C1, 9 % C2, 5 % CO2, 3.5 % C3, 0.5 % C4 ; D) 84 % C1, 6 % C2, 5 % CO2, 4 % C3, 1 % C4 ; E) 86 % C1, 5.5 % C2, 4.5 % CO2, 3.5 % C3, 0.5 % C4 ; F) 88 % C1, 5 % C2, 4 % CO2, 2.5 % C3, 0.5 % C4 ; G) 82 % C1, 5.5 % C2, 4.5 % CO2, 7 % C3, 1 % C4 ; H) 80 % C1, 5 % C2, 4.5 % CO2, 10 % C3, 0.5 % C4 ; I) 78 % C1, 4.5 % C2, 4 % CO2, 13 % C3, 0.5 % C4.


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a consistent method to predict costs and to compare them across designs, and it is recognized fully that the actual costs may vary substantially owing to unforeseen market shifts. The capital and utilities costs for an industrial system are given in Table 2. On the basis of the CO2 content in the feed stream and the feed-stream flow rates, these values can be compared with those of other CO2 removal systems (see Figure 10).[25]

Table 2. Total and operating costs for our industrial system [1000 kmol h@ feed stream, 99 % CO2 capture].

Model

Total capital cost [USD]

Utilities cost [USD h@1]

industrial

657 190

38 146

Figure 9. Effect of varying composition on the mole fraction of methane in the vapor at a) 206.84 and b) 517.1 kPa; x-axis label: A) 78 % C1, 15 % C2, 4 % CO2, 2.6 % C3, 0.4 % C4 ; B) 80 % C1, 12 % C2, 4.5 % CO2, 3 % C3, 0.5 % C4 ; C) 82 % C1, 9 % C2, 5 % CO2, 3.5 % C3, 0.5 % C4 ; D) 84 % C1, 6 % C2, 5 % CO2, 4 % C3, 1 % C4 ; E) 86 % C1, 5.5 % C2, 4.5 % CO2, 3.5 % C3, 0.5 % C4 ; F) 88 % C1, 5 % C2, 4 % CO2, 2.5 % C3, 0.5 % C4 ; G) 82 % C1, 5.5 % C2, 4.5 % CO2, 7 % C3, 1 % C4 ; H) 80 % C1, 5 % C2, 4.5 % CO2, 10 % C3, 0.5 % C4 ; I 78 % C1, 4.5 % C2, 4 % CO2, 13 % C3, 0.5 % C4.

CO2 capture fraction depends on the measured inlet and outlet CO2 fractions in the vapor. The measurements indicate an approximate 30 % change in the CO2 composition of the outlet gas, which these instruments measure readily and reliably. These vapor concentrations correspond to outlet capture percentages that vary by only a few parts per 1000; nevertheless, these small changes are reliably estimated as they are based on vapor measurements that are well within the detection limits and accuracy of the instrumentation. Economics The capital and operating costs of the system depend as much or more on market demands and the cost of raw materials as they do on equipment size and type, as has been painfully clear to the natural-gas industry in the last decade. No economic analysis is capable of anticipating these market-based fluctuations. The approach used here relies on Energy Technol. 2017, 5, 1588 – 1598

Figure 10. Total cost comparison for different systems: A) the new system (494 cm3 min@1 feed stream and 8, 18, and 21 % CO2 content in feed stream) versus a membrane (494 cm3 min@1 feed stream and 8, 18, and 21 % CO2 content in feed stream); B) the new system (9834 cm3 min@1 feed stream and 8, 18, and 21 % CO2 content in feed stream) versus absorption (9834 cm3 min@1 NG and 8, 18, and 21 % CO2 content in feed stream); x-axis label for CO2 content in feed stream: this investigation—A) 8 %, B) 18 %, and C) 21 %, membrane—D) 8 %, E) 18 %, and F) 21 %.


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To compare our setup with an industrial one, an industrial model was simulated in Aspen.

Efficiency of heat exchanger and exergy losses In this discussion, heat-exchanger efficiency is defined. As insulated heat exchangers conserve enthalpy, a first-law definition is problematic. That is, the enthalpy flowing out of the system equals that flowing in.[26] As heat exchangers do not involve shaft work, a second-law definition (work over heat) does not naturally fit the system. Nevertheless, in this investigation, we propose a second-law definition for heat-exchanger efficiency that is both useful and simple.[27] Fazlollahi et al.[21] and Li et al.[28] have introduced the exergy losses equations of the heat exchanger. The exergy changes associated with this process are summarized in Table 3.

The financial and technical support of Sustainable Energy Solutions (SES) LLC of Orem, Utah, and the Advanced Research Projects Agency—Energy (ARPA-E), U.S. Department of Energy, under Award Number DE-AR0000101 is gratefully acknowledged. This project was partially funded by SES projects sponsored by the Advanced Conversion Technologies Task Force in Laramie, Wyoming through the School of Energy Resources and by the Climate Change and Emissions Management Corporation (CCEMC) of Alberta, Canada.

Conflict of interest The authors declare no conflict of interest.

Keywords: carbon dioxide · cryogenic carbon capture · hydrocarbons · natural gas · process optimization

Table 3. Efficiency of heat exchanger and exergy losses.[22, 23]

Parameter

Lab-scale simulation

Lab-scale experiment

Plant-scale simulation

heat exchanger efficiency [%] exergy loss [kW]

93.4 39.6

92.2 44.8

93.1 41.4

Conclusions Natural-gas (NG) pretreatment systems have been simulated to remove more than 99 % of the CO2 from NG. Steadystate simulations with Aspen Plus illustrate the effects of different parameters on the CO2 capture percentage. The vapor mole fractions of CO2 and methane were also investigated by changing the pressure at constant temperature. An increased pressure increases CO2 capture and, hence, the methane mole fraction in the vapor. Consequently, the mole fraction of CO2 in the vapor decreases. As the pressure increases, the methane in the vapor also condenses and creates more liquid in which solid CO2 can dissolve. An increase in the amount of methane increases the amounts of both CO2 and C1 in the vapor stream and decreases the CO2 capture percentage. Increases in the amounts of ethane and propane increase the amounts of both CO2 and C1 in the vapor and decreases the CO2 capture percentage. An experimental bench-scale apparatus verified the simulation results. The exergy loss and heat-exchanger efficiency were calculated, and equipment sizes and costs were estimated. The results confirm low exergy losses of 39.6 kWh kg@1 for the simulation and 44.8 kWh kg@1 for bench-scale apparatus. A high heat-exchanger efficiency of 90 % was achieved. A high pressure and low methane content in the NG composition results in high CO2 capture, though the capture efficiency reaches a maximum at intermediate pressure.

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Manuscript received: December 26, 2016 Revised manuscript received: March 22, 2017 Accepted manuscript online: March 28, 2017 Version of record online: May 31, 2017


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