Reversible solid oxide cell systems for integration with natural gas pipelineand carbon capture infrastructure for grid energy managementEvan P. Reznicek, Robert J. Braun⁎
Department of Mechanical Engineering, Colorado School of Mines, CO, USA
H I G H L I G H T S
• The ReSOC P2G/G2P system canachieve a LCOE between 6 and 11¢/kWh.
• The ReSOC system is economicallycompetitive with batteries and gaspeaker plants.
• The ReSOC system achieves P2G/G2Pmode LHV efficiencies of 84% and69%, respectively.
• The system is more compatible withpipeline natural gas than hydrogen-only systems.
• The system allows greater operationalflexibility than stand-alone storagesystems.
G R A P H I C A L A B S T R A C T
A R T I C L E I N F O
Keywords:Reversible solid oxide cellsPower-to-gasGrid energy managementTechno-economicSynthetic natural gasCarbon capture and utilization
A B S T R A C T
Electrical energy storage (EES) is necessary to enable greater penetration of renewables and as a grid-balancingsolution, but current EES technologies suffer from capacity or geological limitations and high cost. Reversiblesolid oxide cells (ReSOCs) are an electrochemical energy conversion technology that can produce both electricityfrom fuel (gas-to-power) and fuel from electricity (power-to-gas), depending on resource availability and de-mand. Leveraging in situ C-O-H chemistry and operating at intermediate temperature (600°C) and elevatedpressure (10–20 bar) enables these cells to be mildly exothermic, eliminating the need for external heat input orhigh over-potential (low-efficiency) operation during electrolysis mode. This operating strategy also results inhigher methane production during electrolysis, facilitating easier integration with natural gas pipeline infra-structure over steam/hydrogen electrolytic processes.
This study proposes a ReSOC system integrated with both natural gas pipeline and carbon capture and storage(CCS) infrastructure to render a flexible, grid energy management resource. In gas-to-power mode, the systemtakes natural gas from a pipeline to produce electricity. Un-utilized fuel is combusted with oxygen and expandedthrough a turbine to produce more power. The water in the exhaust is condensed, and the remaining carbondioxide is compressed for tanker or pipeline transportation to a carbon sequestration site. In power-to-gas mode,carbon dioxide and water are co-electrolyzed in the stack to produce methane and hydrogen, which can beinjected directly into a natural gas pipeline or further refined into a purer stream of methane. We explore systemdesign concepts, performance, and cost of a 50 MWe ReSOC system. Results indicate that synthetic natural gas(92.0% methane) can be produced at $22.7/MMBTU with a lower heating value efficiency of 81%. Alternatively,a system that net meters produced syngas and operates in power producing mode 50% of the time can generateelectricity at a levelized cost of 10.5¢/kWh with an efficiency of 69% (LHV), while producing exhaust that is95.5% carbon dioxide at 40 bar. If the system operates disproportionally in gas-to-power mode the LCOE drops
https://doi.org/10.1016/j.apenergy.2019.114118Received 13 June 2019; Received in revised form 22 October 2019; Accepted 10 November 2019
to near 6¢/kWh. The economic outlook for mature ReSOC systems presented herein are found to be competitivewith current energy storage technologies and natural gas peaker plants.
1. Introduction
Electrical energy storage has been identified as a critical technologyfor enabling widespread adoption of intermittent renewable energysources. However, existing technologies such as pumped hydro, com-pressed air energy storage, and various types of electrochemical bat-teries suffer from high cost and/or limitations in capacity and suitablegeology [1–3]. Power-to-gas is an emerging concept in which excesselectricity is used to produce hydrogen or a synthetic natural gas (SNG)for injection into the natural gas pipeline network, where the energy iseffectively stored (see Fig. 1). This approach allows the avoidance ofrenewables curtailment while reducing both natural gas extraction andcarbon emissions. Natural gas is a flexible fuel used in baseload power,peaking power, distributed energy generation, heating, and transpor-tation, and the infrastructure for its distribution is well establishedwithin the United States.
The power-to-gas concept encompasses a variety of approaches taken inliterature, including (1) renewable hydrogen production for a yet-to-berealized hydrogen distribution network and economy or direct injection intonatural gas pipelines; (2) low-temperature water electrolysis for methane orsyngas production with CO2 [4]; (3) high-temperature steam electrolysis formethane or syngas production with CO2; and (4) high-temperature co-electrolysis of steam and CO2 for methane or syngas production [5–7].Researchers at Idaho National laboratory have also studied solid oxidesteam and co-electrolysis for both hydrogen and syngas production usingnuclear power rather than renewables [8–11]. Hydrogen can be used as afuel for many of the same applications as natural gas, but it faces manychallenges including development of compression, storage, and dispensing,and pipeline transportation infrastructure, and inefficiency [4]. Employingexisting natural gas infrastructure alleviates or eliminates many of thesechallenges. While it is possible to inject hydrogen directly into natural gaspipelines, pipeline standards vary as to the amount that can be injectedsafely; allowable bulk hydrogen concentrations vary between 0 and 12%[6,12]. For these reasons, power-to-gas technologies that focus on syntheticnatural gas production may face fewer barriers in the development processand may be able to achieve scales of impact more quickly than renewablehydrogen production alone.
The key components for producing renewable synthetic natural gasare water and carbon dioxide, the latter of which would most appro-priately be delivered via pipeline or tanker from carbon capture andsequestration (CCS) technology applied to a fossil fuel power plant oran industrial process such as cement or steel production (Fig. 1). Beckeret al. [4] performed a techno-economic analysis of a methanation plantthat reacts renewably produced hydrogen, from either wind-poweredproton exchange membrane or alkaline electrolysis, with CO2 from CCSvia the Sabatier process. Their analysis identified a system conceptcapable of 78.1% LHV efficiency, and cost of SNG ranging from 8.2 to81.8 $/MMBTU (28 – 279 $/MWh), depending on the cost of hydrogenand plant capacity factor. Other concepts that rely on low temperatureelectrolysis using PEM or alkaline electrolyzers benefit from the ma-turity of these technologies, but suffer from low efficiency and energydensity in the case of alkaline electrolyzers and high cost and de-gradation rates in the case of PEM electrolyzers [7]. High-temperatureelectrolysis studies focus on reaping the benefits in efficiency and fuelflexibility of solid oxide technology [7,13–20]. Wang et al. [7] in-vestigated solid-oxide-electrolysis based power-to-methane designconsiderations for both steam- and co-electrolysis. They found a tradeoff between efficiency and methane yield, that pure oxygen is a desir-able substitute for sweep air only at low current densities, and thatexothermic operation allows a much wider operating envelope andbetter heat integration than thermoneutral operation.
One of the primary criticisms of power-to-methane is that thecarbon dioxide will ultimately end up back in the atmosphere, leadingto a lower global warming reduction impact and higher CO2 mitigationcosts than other technologies capable of using excess renewables [21].While it is worth noting that this type of carbon recycle may still reduceemissions by supplementing natural gas extraction and increasing re-newables penetration, SNG production is more environmentally at-tractive under scenarios in which the CO2 ultimately ends up seques-tered in the ground. Additional economic benefit could be realized ifthe same technology used to produce the SNG could be used to produceelectricity with CCS.
Reversible solid oxide cells (ReSOCs) are capable of producing bothSNG with excess electricity and producing electricity with natural gas.
Fig. 1. Pipeline integrated ReSOC system concept.
E.P. Reznicek and R.J. Braun Applied Energy 259 (2020) 114118
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They share the high efficiency and fuel flexibility experienced by con-ventional solid oxide fuel and electrolysis cells. Furthermore, becausesolid oxide cells only conduct oxygen anions, the fuel oxidation pro-cesses do not involve inert gases, such as nitrogen, thereby enablingcarbon dioxide in the anode exhaust gas to be more easily capturedcompared with capture from the flue gas of a conventional natural gaspower plant. Conventional ReSOCs are fabricated with yttria-stabalizedzirconia (YSZ) electrolytes with nickel-YSZ anodes and operate above750°C [22–25]. However, at intermediate temperatures between 500and 650°C, reaction thermodynamics favor the production of methaneover carbon monoxide and hydrogen [26] during electrolysis. Metha-nation is highly exothermic and can effectively serve as a heat sourceduring endothermic steam electrolysis operation. Several studies haveshown high performance results for intermediate temperature cellsfabricated with strontium- and magnesium-doped lanthanum gallate(LSGM) electrolytes [27–34].
The performance and economics of intermediate temperatureReSOCs for standalone energy storage systems have been previouslyanalyzed [35–38], and find that ReSOC systems can achieve round tripefficiencies between 50 and 75% and levelized storage costs competi-tive with other energy storage technologies, which have been reportedas low as 20 ¢/kWh for batteries [38–40] and 3 ¢/kWh for pumped-hydro [37,41]. In these studies, the methane content of the stored fuelis limited because the stack requires a hydrogen-to-carbon ratio (HCR)greater than that of pure methane in order to avoid carbon deposition,and the HCR is constant throughout the system. As a result, post-stackmethanation is limited by the amount of carbon in the exhaust feed-stock, and the produced fuel always contains hydrogen (up to 65% afterwater knockout). These studies also illustrate that a significant portionof system cost is allocated to storage tanks, a component unnecessary inpower-to-gas systems.
Butera et al. [42,43] analyzed a ReSOC system for integration withnatural gas pipelines. They design the stack to operate at an elevatedpressure of 18.7 bar to promote internal methanation. With post-stackmethanation reactors and an aggressive system integration approach,this study produced a system design capable of a round trip efficiency of80% DC-DC. However, it does not take into account the economics ofthe system, which are necessary towards understanding the trade-offsbetween capital cost and efficiency. Giglio et al. [18,19,44] performtechno-economic analysis on solid oxide cell steam and co-electrolysissystems with post-stack methanation. Similarly, Parigi et al. [45] ana-lyze solid oxide cell systems for power-to-fuels, comparing productionof methane and methanol. However, these studies only consider power-to-gas operation, and do not take advantage of the benefits of inter-mediate temperature solid oxide cells. At present, studies that estimateboth performance and cost for an intermediate temperature reversiblesolid oxide cell system integrated with natural gas pipeline
infrastructure are needed.This paper presents a techno-economic optimization and design
analysis of an intermediate temperature ReSOC system for integrationwith both natural gas and CCS infrastructure. The system is sized for a50 MWe electrolysis stack, suitable for a moderately sized wind farmand for providing energy management services to a regional grid. Weanalyze the efficiency and cost of developing the system for syntheticnatural gas production alone, and for reversible operation in whichnatural gas is net-metered and the end product is electricity supplied tothe grid.
2. System design and modeling
This section discusses the system layout and the modeling methodsemployed to predict the performance of the stack, balance-of-plant(BOP) machinery, and system as a whole. All modeling and calculationswere performed using gPROMS ModelBuilder [46].
2.1. System design
Fig. 2 shows the system design in power-to-gas (electrolysis) mode.Carbon dioxide enters the system at 40 bar at statepoint (1) and ispreheated. Most of the CO2 is mixed with steam and directed toward thestack. The amount of steam is determined by fixing the stack inlet watercomposition to 58%, which yields a hydrogen-to-carbon ratio roughly10% larger than the ratio that would render carbon deposition at 600°Cand 20 bar. Previous studies have shown that employing as low of ahydrogen-to-carbon ratio as possible results in the thermoneutral vol-tage being close to the Nernst potential [26], which allows the stack tooperate exothermically in electrolysis mode at lower current densities.An additional preheater raises the temperature to that of the stack inletat statepoint (3), and the stack electrochemically reduces the mixtureaccording to the following reactions, representing electrochemicalwater reduction, methanation (or reverse reforming), and reverse wa-ter–gas-shift, respectively:
+ ° =H O H 12
O H 600 C 247 kJ/mol2 2 2 rxn(1)
+ + ° =CO 3H CH H O H (600 C) 226 kJ/mol2 4 2 rxn (2)
+ + ° =H CO H O CO H (600 C) 36 kJ/mol2 2 2 rxn (3)
While direct oxidation and reduction of CO and CO2, respectivelyhave been shown to occur in ReSOCs [47], previous modeling work onco-electrolysis of steam and CO2 [48,49] has shown that because thebulk channel gas is in chemical equilibrium, the relative electro-chemical reduction of steam and carbon dioxide does not affect the
Fig. 2. Schematic of the ReSOC system in power-to-gas mode.
E.P. Reznicek and R.J. Braun Applied Energy 259 (2020) 114118
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overall conversion and local energetics. Furthermore, experimentalobservations [50,51] have shown that even small amounts of watervapor in the fuel stream results in cell voltage–current characteristiccurves almost identical to those produced by pure steam electrolysis,suggesting that the water–gas shift/reverse water-gas shift reactions arethe preferred pathways for CO/CO2 consumption, and that the overallelectrochemical performance of the cell is negligibly impacted whenappreciable steam is present in the fuel gas channel. For these reasons,only electrochemical reduction of water is considered in this work.
Some of the stack exhaust at statepoint (5) in Fig. 2 is recycled to thestack inlet in order to promote additional internal reforming within thestack, which allows the stack to operate exothermically. This recycle ismanaged by constraining the volumetric ratio of carbon dioxide tohydrogen entering the stack to equal 1.5. The remaining stack exhaustis mixed with the CO2 bypassed around the stack and reacted in themethanator at statepoint (7) to convert additional hydrogen into me-thane. This process is highly exothermic, and the heat is used to boil upto 40% of the steam required for electrolysis. After the reactor, theexhaust is cooled by the stack feedwater, and about 98% of the exhaustwater content is condensed out. The exhaust is then compressed,cooled, and condensed again. A hydrogen permeable membrane atstatepoint (9) provides the option of removing some of the remaininghydrogen to increase the end-product methane purity, rendering asynthetic natural gas stream consisting of 92% methane, 1% hydrogen,and 4.9% nitrogen. The separated hydrogen can be diverted to the in-coming CO2 stream at statepoint (2), reducing the amount of fuelelectrode recycle. On the oxygen electrode side of the system, air iscompressed and preheated as a sweep gas to balance stack pressure atstatepoints (12)-(16). The air exhaust is used to boil some of the waterat statepoint (19), and an air expander recovers energy to increase thesystem net efficiency.
Fig. 3 shows the system in gas-to-power (fuel cell) mode. In thismode, the methanator, air boiler, and water cooled condenser are un-used, as all steam requirements can be met through anode recycle.Because GtP mode is much more exothermic than PtG mode, an ex-pander can be used in place of a valve to develop work when expandingthe natural gas from pipeline pressure down to stack pressure at sta-tepoint (2). The extent of recycle at statepoint (7) is determined byfixing the steam-to-methane ratio entering the stack to 2.8, which againrenders a hydrogen-to-carbon ratio roughly 10% greater than thatwhich would result in carbon deposition. Because the stack cannotutilize all of the fuel delivered, an oxy-combustor is introduced down-stream of the stack at (9) to simplify carbon capture and sequestration.(Alternatively, ambient air or stack air-exhaust could be used for de-pleted fuel oxidation in non-CO2 capture systems.) The stack exhaust ismixed with a small amount of oxygen from an air separation unit (ASU)
at statepoint (10), combusted with 5% excess oxygen, and expandedthrough a turbine at statepoint (11) to produce additional power. Theexhaust is then cooled, condensed, and compressed at statepoints (12) -(17). Some of the exhaust is recycled back to the combustor at state-point (16) to limit the combustor exhaust temperature to 950°C. Thecompression and condensation processes render an exhaust stream withhigh CO2 purity. Air is compressed and preheated to supply oxygen tothe stack at statepoints (18) through (22), and an air expander at sta-tepoint (24) recovers energy to increase system efficiency. This studyassumes that the air-side equipment, fuel preheaters, anode recycleblower, and exhaust compressors and condensers are compatible inboth modes. A previous study has shown through off-design modelingof ReSOC systems that components can be selected and designed tooperate in both modes [38]. This may lead to a small decrease in effi-ciency due to components operating away from their design pointsduring one mode or the other. More importantly, off-design analysis canbe used to assess part-load performance of the system. While mode-compatibility and part-load performance are both important, they areout of the scope of this study, which seeks to identify optimal systemdesigns and operating parameters for PtG and GtP systems.
In both modes, the first two air-side compressor stages have apressure ratio of 2.72, with an air-cooled intercooler that reduces thesecond stage inlet temperature down to 60°C. The air cooler in betweenthe second and third stages reduces the air temperature sufficiently toachieve a third compression stage discharge temperature of 315°C. Thisis done because it balances air preheating with steam generation for alldesign approaches considered in this study. In gas-to-power mode, thepost combustion turbine expands down to atmospheric pressure. Thefirst exhaust compression stage discharge pressure is set to 5 bar, andthe second stage raises the pressure to roughly 20 bar for CO2 recycle.Each air-cooled condenser in the exhaust compression and waterknockout train is designed to reduce the exhaust temperature to 50°C.Tables 9–12 in the Appendix give state point data for PtG and GtPmodes, respectively, for a system that employs both the methanator andmembrane and is optimized for reversible operation.
2.2. Stack modeling
The planar stack was modeled using a one-dimensional, steady statemodel originally developed by Wendel et al. [28] and used in severalother studies [35,38,52]. The model solves channel-level conservationequations of mass, momentum, energy, and charge, and captures elec-trochemical performance of large platform cells whose electrochemicalparameters were extracted from experimental button-cell data. The testcells were comprised of an LSGM electrolyte, nickel infiltrated LSGMfuel electrode, Ni-SLT fuel electrode support, and LSCF-GDC oxygen
Fig. 3. Schematic of the ReSOC system in gas-to-power mode.
E.P. Reznicek and R.J. Braun Applied Energy 259 (2020) 114118
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electrode. While these cells have primarily only been tested in a la-boratory setting, they do not require exotic materials and can bemanufactured using common methods. Table 1 gives stack designparameters. For detailed electrochemical parameters, see Ref [28].
2.3. Balance-of-plant component modeling
Compressors and expanders are modeled thermodynamically withisentropic efficiencies of 78% and 83%, respectively. These values arereasonable for intermediate-sized machinery generally under 10 MWein size [36,53]. The anode recycle blower is modeled using fan lawequations, assuming a static fan efficiency of 65% [54]. All heat ex-changers are modeled with NTU-effectiveness correlations. The aircooled condensers and air coolers are modeled as single pass, cross flowdevices, with an axial fan static efficiency of 75%. The water-cooledcondenser is modeled using a counterflow correlation, which is ap-propriate for a shell-and-tube heat exchanger with a single tube pass.The preheaters and recuperators are also modeled using counterflowcorrelations. Ambient air is assumed to be at 30°C, and the effectivenessof all heat exchangers is limited to 92%, as higher values can rendervery expensive recuperators [55].
The methanation reactor is assumed to be isothermal [7,56], cooledby the boiling electrolysis feed water. In practice, it is difficult toachieve a truly isothermal methanation reactor [4]. However, Beckeret al. showed that isothermal operation may be approached in a regionof a cooled methanation reactor where temperature control is accom-plished via phase change of the cooling fluid [4]. The reactor config-uration resembles a shell-and-tube heat exchanger where the tube-sideserves as a packed bed reactor for converting the gas flow, and thecooling fluid is shell-side. Methanation is assumed to take place ac-cording to the reverse steam methane reforming and reverse water–gas-shift reactions, given by Eqs. (2) and (3), respectively. The reversewater–gas-shift reaction is assumed to be at equilibrium in the presenceof a nickel catalyst [57], and the overall conversion of hydrogen isspecified as follows:
=Xn n
nH2H2,in H2,out
H2,in (4)
We define the extent of methanation in Eq. (4) in terms of hydrogenbecause it is the utilization of hydrogen that is desired; only carbondioxide sufficient to meet the hydrogen utilization target is provided tothe reactor while rendering an outlet CO2 mole fraction of 1%. Thestack outlet carbon monoxide mole fraction is already less than 1%, andis expected to be consumed readily within the methanation reactor. Thesize of the reactor is estimated by assuming a reactor space velocity of5000 h−1 [7] at equilibrium, and that the reactor size varies linearlywith conversion below that of equilibrium. However, the maximumconversion is limited to 93.5% of that established by chemical equili-brium. Both the stack and methanator models contain equations tocalculate the minimum hydrogen-to-carbon ratio (HCR) that thermo-dynamically favors carbon deposition based on the inlet temperature,pressure, and composition according to Ref [58]. The hydrogenpermeable membrane is modeled as a one-dimensional, steady state,counterflow membrane. The membrane flux at axial location z is de-termined as:
=J z P p z p z( ) ( ( ) ( ))m,H2 H2 H2,feed H2,permeate (5)
where p z( )H2,feed is the partial pressure of hydrogen in the feed ataxial location (z), p z( )H2,permeate is the partial pressure of hydrogen inthe permeate at axial location (z), and PH2 is the pressure-normalizedflux or “permeance” of the membrane. According to Ref. [59], a typicalpolysulfone hydrogen-permeable membrane will have a permeance of100–200 (10 6cm3(STP)/cm2-s-cmHg). The lower value of 100 is usedin this study, and we assume that the membrane has an infinite se-lectivity for hydrogen over other species. The primary effect of
imperfect selectivity will be a change in the amount of stack exhaustrecycled at the fuel electrode, which should have a relatively smallimpact on system cost and efficiency. The hydrogen membrane is as-sumed to be capable of separating a maximum of 90% of hydrogen (byvolume), where the separation is defined as:
=Xn n
nm,H2H2,in H2,out
H2,in (6)
The oxygen in gas-to-power mode is assumed to be provided by anair separation unit with power consumption of 0.35 kWh/Nm3 [60].Because the oxygen is needed to combust only a small amount of fuel,the total air separation power requirement is fairly low. Table 2 listscomponent design and performance parameters. These values are basedon studies of intermediate temperature ReSOCs [28,52,38], large-scaleSOFC and SOEC systems [61,62], and large-scale pressure swing ad-sorption air separation [60].
2.4. System performance metrics
The primary performance metrics of interest are the lower heatingvalue (LHV) efficiencies of each respective operating mode. For power-to-gas mode, the LHV efficiency is defined as:
= m LHVWLHV,PtG
SNG SNG
net,AC (7)
where mSNG is the produced flow rate of synthetic natural gas, LHVSNG isthe lower heating value of the SNG, andWnet,AC is the net power input tothe system including stack power, net BOP power, and inverter andmotor losses. In gas-to-power mode, the LHV efficiency is defined as:
=W
m LHVLHV,GtPnet,AC
NG NG (8)
where mNG is the supplied flow rate of natural gas, LHVNG is thelower heating value of methane, and Wnet,AC is the net system poweroutput, deducting inverter and motor losses from the stack and BOPpower. For both operating modes, it is assumed that the air expandersare shaft-connected to air compressors, reducing the air-side motorpower requirements. In gas-to-power mode, the post-combustion ex-pander powers the CO2 compression chain, and extra shaft power isconverted to electrical power in a generator.
Another performance parameter of interest is the Wobbe index:
E.P. Reznicek and R.J. Braun Applied Energy 259 (2020) 114118
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= HHVWobbeIndex SNGSNG,STP
air,STP (9)
where HHVSNG is the higher heating value of the produced syngas,and SNG,STP and air,STP are the densities of the SNG and air, respec-tively, at standard temperature and pressure. According to Ref. [4], theWobbe index is a standard used in the design of natural gas burner unitsand end-use appliances. Ultimately, the Wobbe index of the entire pi-peline is most important, but in an energy network with a high pro-portion of synthetically produced gas, any syngas produced needs to becompliant with respect to the industry standard Wobbe index of about46–48MJ/Sm3.
2.5. System economics
The economic parameters of greatest interest are the levelized costof synthetic natural gas (LCOSNG) of a plant operated in electrolysismode alone, and the levelized cost of energy (LCOE) of a plant operatedin both modes. These parameters are calculated as:
In this study we make simplifying assumptions that the price offeedstocks (carbon dioxide, water, oxygen, fuel, etc.) and electricity areconstant throughout the year, and that the plant operates at rated ca-pacity for the entire duration of its annual operation. As a result, theannual cost of feedstock i can be calculated as =C P m ti ifs,i fs, fs, ann, whereP ifs, is the price of feedstock i m, ifs, is the net input flow rate of feedstocki, and tann is the number of hours the plant operates in a year, which isdetermined by the plant capacity factor. Like feedstocks, the annualSNG energy is calculated as =E m LHV tSNG,ann SNG SNG GtP,ann, and theannual gas-to-power energy output is calculated as
=E W tGtP,ann net,GtP,AC GtP,ann. In both modes, the operations and main-tenance cost is estimated to be 2 ¢/kWh. This estimate represents thetotal impact of O&M costs on the value of the end product (either SNGor electricity) regardless of time spent in either mode - that is, the O&Mcost is assumed to be independent of capacity factor and time spent inGtP mode versus PtG mode. With these assumptions, the LCOS andLCOE can be expressed as:
=+ +
+ +LCOSNGC t P m P m
t m LHVP C
( )cap,ann PtG CO2 CO2 H2O H2O,net
PtG SNG SNG
elec
PtG,ACO&M
(12)
= +
+
+
+ + +
LCOE CCt W
t P m P m t P m P Wt W
P t m LHV t m LHVt W
O&M
( ) ( )
( )
cap,annGtP GtP,AC
GtP O2 O2 CO2,st CO2,st PtG CO2 CO2 elec PtG,ACGtP GtP,AC
fuel GtP NG NG PtG SNG SNGGtP GtP,AC (13)
where the fuel costs in Eq. (13) directly account for plant efficiencythrough the natural gas and SNG mass flow rate and power productionterms. The cost of water is captured in the LCOSNG calculation but notin the LCOE calculation because as long as the system operates 50% ofthe time in GtP mode, the system provides net water rather than con-suming it. The annualized capital cost of component i is estimated as:
=+
C f C dd1 (1 )i i Ncap,ann, install cap, i (14)
where finstall is the installation factor, C icap, is the capital cost of com-ponent i, d is the discount rate, and Ni is the life of component i inyears.
Table 3 gives values for various economic parameters. Note that thecost of stack replacement (anticipated every 5 years) is accounted for inthe operations and maintenance cost, rather than in the annualizedcapital cost. The capacity factor of 65% represents the total operatingtime. For the LCOSNG calculation, this means that the power-to-gasplant operates 65% of the year. For the LCOE calculation, this meansthat the entire system operates 65% of the year, split equally betweenpower-to-gas and gas-to-power modes (i.e., 32.5% of the year in eachmode). The price of electricity is an anticipated price for off-peak re-newables that would otherwise be curtailed [39,40], and the fuel priceis based on 2018 US natural gas prices. The price of CO2 is the pricepaid for CO2 delivered in electrolysis mode, while the cost of CO2 T&S isthe cost of transporting and sequestering the CO2 produced in fuel cellmode. The price of oxygen is the levelized cost of oxygen provided byan air separation unit.
O&M costs for fuel cell/electrolyzer power plants are highly un-certain. Given the scarcity of data arising from few pressurized, SOFCand SOEC systems that have been built, the approach taken here reliedon a survey of O&M estimates reported for various fuel cell/electrolyzersystems as documented in the extant literature. Data for solid oxide,molten carbonate, phosphoric acid and proton exchange membrane fuelcell, as well as solid oxide electrolyzer systems suggest O&M valuesranging from 0.4 to 2.5 ¢/kWh [68–72,61]. Given that operation forenergy storage based ReSOCs requires multiple, reversing modes andpressurization, and is hybridized with turbines, we selected the highestO&M costs for the present analysis.
Table 4 gives the capital cost correlations of various system
Table 2System design and performance parameters.
Parameter Value
Oxy-combustor temperature 950 °CGas heat exchanger pressure drop 1% of PinAir cooler tube pressure drop 10 kPaAir cooler fin pressure rise 1.5 kPaCombustor pressure drop 20 kPaMethanator pressure drop 40 kPaMembrane pressure drop 1% of PinAir exhaust boiler pressure drop 15 kPaCondenser liquid pressure drop 10 kPaCompressor isentropic efficiency 78%Expander isentropic efficiency 83%Radial blower static efficiency 65%Air cooler axial fan static efficiency 75%Motor efficiency 96%Generator efficiency 96%Inverter efficiency 98%ASU energy consumption 0.35 kWh/Nm3
Table 3Economic parameters.
Parameter Value Ref.
Discount rate 8% [63]Installation factor 2.1 [62]Capacity factor 65% [4]Cost of O&M $0.02/kWh [62]Price of electricity $0.025/kWh [39]Price of CO2 $61/tCO2 [64]Cost of CO2 T&S $20/tCO2 [65]Price of H2O $1/tH2O [14]Price of O2 $40/tO2 [66]Price of fuel $0.014/kWh ($4/MMBTU) [67]Stack life 5 years [52]Catalyst life 2 years [4]Membrane life 5 years [4]BOP (system) life 20 years [52]
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components. The stack pressure vessel mass is calculated by de-termining the shell thickness according to the ASME Boiler and PressureVessel code Section 8, as described in Ref. [73]. The compressor costmultiplier ft is a temperature factor; its value is 1.0 for compressordischarge temperatures below 250°C and 2.0 for discharge tempera-tures above 250°C. The blower cost correlation from Ref. [74] has alsobeen multiplied by two to account for the high operating temperature ofthe fuel electrode recycle stream. The methanator catalyst cost is basedon volume and conversion, assuming the maximum volume attained bya space velocity of 5000 h−1 is accomplished in a reactor that achievesequilibrium conversion.
2.6. Optimization
Determining the best system design operating parameters requirescareful consideration of the requirements of both operating modes, andis dependent on whether it is most desirable to minimize the levelizedcost of SNG of an electrolysis-only plant, or to minimize the levelizedcost of energy of a reversible SOC plant. The primary parameters ofinterest are stack operating pressure, reactant utilization, and currentdensity. For reversible operation, the stack pressure should remainequal in both modes, as planar solid oxide cell stacks are sensitive topressure fluctuations, and swinging the stack pressure back and forthwould severely complicate and elongate mode switching. However,reactant utilization and current density do not need to be equal in bothmodes, as is required for stand-alone energy storage ReSOC systems[52,38].
In this work, we employ the NLSPQ solver in gPROMS to identifyoperating parameter values that minimize either the levelized cost ofsynthetic natural gas or the levelized cost of energy. This solver em-ploys a sequential quadratic programming method to solve the non-linear programming problem. Convergence to a local minima isachieved when feasibility, complementarity, Taylor, and overall opti-mization tolerances fall below 0.001 [46]. Decision variables includestack current density in each mode, reactant utilization in each mode,and stack pressure. These variables and their bounds are shown inTable 5. While other decision variables are possible, early optimizationefforts found that cost is most sensitive to the variables considered here.When minimizing the levelized cost of SNG alone, the GtP mode currentdensity and utilization are not used as decision variables, as GtP per-formance has no impact on a system that only operates in PtG mode.
The upper bounds on these decision variables represent practical
limitations. The stack size (number of cells) and pressure in each modeare set equal. In addition to these constraints and the bounds on deci-sion variables, we also constrain heat exchanger effectiveness to be lessthan 92% for all heat exchangers (except for the air boiler, which isallowed up to 94%), and require that the stack fuel inlet hydrogen-to-carbon ratio in each mode be 10% greater than the ratio that wouldlead to carbon deposition based on thermodynamic equilibrium calcu-lations [58]:
HCR HCR1.1 CDB (15)
Optimization was performed to minimize LCOSNG and LCOE forfour cases each: (1) without methanator and without hydrogen se-paration; (2) methanator with conversion set to 93.5% of equilibriumconversion but no hydrogen separation; (3) 90% hydrogen separationand recycle without methanation; and (4) both methanation and hy-drogen separation at 93.5% of equilibrium and 90%, respectively.
3. Results
This section presents the optimization results for two systems: anelectrolysis system that produces synthetic natural gas as the end pro-duct, and a reversible system that produces electricity as the end pro-duct. For both systems, results for the four cases (no methanation,methanation without membrane, membrane without methanation, andmethanation with membrane) are presented and compared.
3.1. Electrolysis operation for synthetic natural gas production
The optimization results for the four cases for SNG production onlyare shown in Table 6. In general, we see that high utilization and highcurrent density are desirable, while stack pressure depends on theamount of methanation and hydrogen separation. Although the addi-tion of a methanator allows lower current density, efficiency changeslittle between cases. Cost generally increases with the addition of themethanator and membrane. Installed cost appears low for a solid oxideelectrochemical system largely because it is based on electrolysis powerinput, which is higher than the fuel cell mode power output that wouldbe achievable with the same stack at the same current density. Thelevelized cost of SNG is not economically competitive with U.S. marketnatural gas, which ranges from 3 to 6 $/MMBTU (10.2 to 20.4 $/MWh)[67]. However, it may be competitive with production costs in Eur-opean countries, which range from 14 to 24 $/MMBTU (47.8 to 81.9$/MWh) [4].
Fig. 4 shows the composition of the SNG produced in each case.Even without external methanation, the base case achieves almost 55%methane content. Adding both the methanator and membrane increasesthe methane content of the SNG to near-pipeline natural gas levels. The4–5% nitrogen originates in the carbon dioxide, which is presumablyonly 95% pure. The Wobbe index of all of the cases are slightly lowrelative to the normal natural gas value of 48MJ/SM3, as shown inTable 6. This is largely because natural gas also contains up to 15%higher hydrocarbons such as ethane, propane, butane, and traceamounts of other heavier hydrocarbons[4].
Fig. 5 shows the levelized SNG cost breakdown for the four cases.Electricity and CO2 contribute significantly toward this cost. The cost
Table 4Component capital cost correlations in 2016 USD.
E.P. Reznicek and R.J. Braun Applied Energy 259 (2020) 114118
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generally increases with additional methane concentration due to theincreased capital cost and the increased amount of CO2 needed to makethe methane. In all cases, the capital cost is less than 15% of the totalcost, meaning that if the capital cost were doubled, the total levelizedcost would only increase by a maximum of 15%. Reductions in elec-tricity and CO2 costs would have the greatest impact on LCOSNG. Thecost of electricity assumed in this study is already low, but each 0.5¢/kWh decrease in cost would bring an LCOSNG reduction of roughly$1.8/MMBTU (6.1 $/MWh). Similarly, a $10/tCO2 decrease in the costof CO2 would reduce LCOSNG by $0.61/MMBTU (2.1 $/MWh).
3.2. Reversible operation for electricity production
The optimization results for reversible operation for the four casesare shown in Table 7. Because PtG and GtP modes are only coupled bystack pressure and size, changes made to PtG mode design have noimpact on GtP mode design and performance. In fact, the only effectthat the addition of the methanator and/or membrane have are on theselected PtG mode current density, and therefore the overall size of the
ReSOC stack. As illustrated in Figs. 4 and 6, increasing methanatorconversion enables lower PtG mode current density. This decrease incurrent density can occur because as the conversion of hydrogen andcarbon dioxide to methane increases, the exotherm in the methanatorincreases, thereby supplying a larger fraction of the steam generationload. The air-heated boiler then needs less waste heat from the stack, sothe current density can decrease.
Fig. 6 also shows that the decrease in PtG mode current densityresults in a modest increase in PtG mode LHV efficiency. This increasein efficiency reduces the contribution that charging electricity makes tooverall LCOE, as illustrated in Fig. 7. Overall capital cost also decreasesslightly with an increase in conversion within the methanator (and theassociated PtG mode current density) because reducing PtG modecurrent density increases the size of the ReSOC stack for a fixed 50MWof capacity in PtG mode. This increased stack size allows higher GtPmode stack power, and therefore, more energy produced in GtP mode.This effectively reduces LCOE by increasing the size of the denominatorin the first term of Eq. (13). Net fuel costs increase with GtP mode stackpower output, but not enough to offset the cost reduction due to in-creased PtG mode efficiency.
Fig. 8 shows that while the addition of a methanator reduces LCOE,adding the membrane provides less economic benefit, and the differ-ences between all cases are relatively small. Furthermore, in practicethe size of the ReSOC stack will also be based on the desired powercapacity of the ReSOC GtP system. For these reasons, the decision toinclude a methanation reactor and/or membrane should not be madeon the basis of cost alone.
Reversible system installed cost is comparatively low with respect toestimates for SOFC-GT and distributed-scale ReSOC energy storagesystems, which can have installed costs between $2000/kWe and$4000/kWe, depending on the system type and scale [38,61,80].Thisdifference is primarily due to the stack power density being roughlydouble that of Ref [38] and the lack of expensive storage tanks. Com-paring to a study of a 550MW Integrated Gasification Fuel Cell (IGFC)system performed by [61], this ReSOC system has much lower stack andstack pressure vessel costs. Given the coarseness of fuel cell stack in-formation in the IGFC study, it is difficult to pinpoint where differencesin cost estimates may lie. However, one possibility is that the ReSOCstack in this study has an ASR of 0.23 ohm-cm2, which may be sub-stantially lower than that of the stack technology considered in theNETL study. Comparing to a 100 kWe distributed generation system[38], the system considered here benefits from economies of scale andthe lack of storage tanks. Another study focused on 280MW atmo-spheric and pressurized SOFC-GT systems estimated total plant costs of$753/kW-$768/kW and LCOE of $5.56/kWh-$5.94/kWh [81]. Ref [75]estimates pre-markup capital costs of 250 kW scale SOFC combinedheat and power systems at $787/kW-$1194/kW, depending on manu-facturing volumes. These estimates are in line with costs presented
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here, especially considering system scale and the fact that SOFC-GT andSOFC-CHP systems are not designed to also be capable of reversibleoperation, which increases capital cost and reduces the capacity factorof electricity-producing operation.
Table 8 shows ReSOC total installed cost (TIC) and levelized costsrelative to other major battery and fossil fuel technologies, as reportedby Refs. [40,80], respectively. Here we assume uncertainty in ReSOCsystem cost of −30%, +100% [38,82]. The abbreviation “LCOS” in-dicates levelized cost of storage for Li-Ion and Va-Redox flow batterytechnologies, while “LCOE” indicates levelized cost of energy forReSOC, gas peaking, nuclear, and coal. The technologies are not uni-form in assumptions such as power capacity, operating capacity factor,charging cost, debt terms, interest rates, etc, illustrating the difficulty incomparing different technologies across different studies. For thisreason we have included the power capacity, discharge capacity factor,and charging cost for each technology, and applied the aforementionedmargin of uncertainty applied to ReSOC LCOE and total installed cost.Despite this margin, this comparison suggests that ReSOC systems maybe economically competitive with conventional energy storage andfossil fuel technologies on both installed and levelized cost bases.
In an effort to provide additional depth for comparing technologies,Fig. 9 shows ReSOC LCOE as a function of both electricity price andtotal capacity factor (charge plus discharge - i.e., multiply dischargecapacity factor in Table 8 by two). For similar charging costs and ca-pacity factors as batteries, ReSOC still achieves a lower levelized cost ofenergy/storage. Only in scenarios with high electricity price and lowtotal capacity factor does ReSOC lose its economic advantage overbatteries. Fig. 9 indicates that ReSOC systems must maintain high ca-pacity factors and/or employ low cost charging electricity to remaincompetitive with conventional power generation technologies.
Table 7 illustrates that although incorporating methanation canallow a decrease in levelized cost of energy, the overnight capital costincreases noticeably, as all of the equipment used in gas-to-power modemust become larger to support the increased net power output. In thisstudy the GtP mode current density was selected to minimize LCOE. Inpractice, the desired plant power rating and overnight capital costmight influence current density as well. Furthermore, high stack
Fig. 6. Average stack design current density and efficiency in PtG mode as afunction of methanation conversion.
Fig. 7. LCOE and its contributors (except O&M, which is constant at 2¢/kWh)as a function of methane conversion.
Fig. 8. LCOE breakdown for the four cases.
Table 8ReSOC system cost compared to other technologies.
Fig. 9. LCOE as a function of electricity price for different total capacity factors.
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current densities likely result in faster degradation, and this sensitivitywas not included in this study.
One of the most significant benefits of integrating ReSOC tech-nology with natural gas and CO2 pipeline infrastructure relative totanked storage of feedstocks is that energy generation capacity is lessrigidly coupled to energy storage capacity. In a standalone system, onlythe energy that has been stored can be used to produce power in fuelcell mode. In the pipeline integrated system discussed here, the fractionof time spent producing electricity is not limited by the time spentproducing fuel with excess renewables. This is beneficial for two rea-sons. First, the system can still be used to meet peak demand even whenrenewable generation during off-peak hours is low. This simplifies thetask of reliably meeting demand for utilities, and reduces the risk thatthey incur by purchasing and installing renewables with stand-alonestorage technologies such as batteries. From this standpoint alone, pi-peline-connected ReSOC systems may be a safer investment. Second,the levelized cost of electricity reduces as more time is spent operatingin gas-to-power mode and selling electricity. Fig. 10 shows how LCOEchanges as a function of both gas-to-power mode operating time andtotal capacity factor Cf . For high total capacity factors and high frac-tions of gas-to-power mode operating time, the LCOE drops con-siderably. Under these conditions, the system begins to look like atraditional power production plant that is also capable of convertingcurtailed renewable energy into synthetic natural gas.
This trend is consistent with prior work by Guandalini et al. [83]that investigated a combination of low-temperature electrolysis power-to-gas technology with gas turbines, ultimately finding that the highestnet-present value was attained for scenarios with low installed elec-trolyzer capacity. However, that study also showed that scenarios suchas higher natural gas prices relative to electricity prices and the pre-sence of incentives for “green gas” could favor a higher electrolysiscapacity. The ReSOC system presented here serves essentially the samepurpose as the combination of technologies studied in [83], and similarsensitivities to parameters such as natural gas and electricity prices canbe expected. While a direct comparison between power-to-gas/gasturbine and ReSOC systems on the basis of net present value is beyondthe scope of this work, it should be noted that ReSOC systems have anumber of advantages including higher efficiency, easier integrationwith carbon capture and storage (and therefore potential for lower netgreenhouse gas emissions), and intensification of both processes intofewer components. Theses characteristics make ReSOC power-to-gas/gas-to-power systems a very attractive option for grid-energy balancingfrom both economic and environmental perspectives.
3.3. Round trip efficiency
Round trip efficiency is an important performance parameter forenergy storage technologies, and has been quantified for previousReSOC studies [52,38,43]. However, it is somewhat more difficult toquantify for the ReSOC power-to-gas system in question because thissystem does not conserve charge the way that a battery or stand-aloneReSOC system does. In other words, the discharge capacity is not tied tothe charge capacity. For ReSOC systems for which charge is conserved,the round trip efficiency can be simply evaluated as:
= =WWRT
FC
ECLHV,GtP LHV,PtG (16)
These two definitions are equivalent as long as an equal amount ofcharge is transferred across the electrolyte in both modes. Because thesystem considered here does not require conservation of net charge,these definitions are not equal and neither gives an accurate re-presentation of round trip efficiency - the first gives an RTE greater than100%, and the second gives an RTE of roughly 59%. A more usefuldefinition of round trip efficiency is useful energy out divided by ex-pensive energy in:
= =+
EE
W tW t m LHV t m LHV t( )RT
out
in
net,FC FC
net,EC EC CH4,FC CH4 FC SNG,EC SNG EC
(17)
where tFC and tEC are the times spent in FC (GtP) and EC (PtG) modes,respectively. If the system were net producing fuel, the net fuel pro-duction would go in the numerator instead of the denominator. Thisdefinition gives a second law round trip efficiency of roughly 63%.However, it should be noted that for a pipeline connected system, roundtrip efficiency is a less useful metric than the LHV efficiency of eachindependent mode. These metrics allow comparison to non-storagetechnologies such as electrolysis plants and conventional power gen-eration plants.
Nonetheless, if high round trip efficiency is required independent oflevelized cost, it could be improved by reducing electrochemical po-larization resistances in the stack, reducing design stack current den-sity, and selecting stack pressure to minimize pumping work associatedwith compressing air for the stack and/or compressing natural gas up topipeline pressure. Another option would be to move to a pure oxygenworking fluid on the oxidant electrode side of the plant. Optimizationcould be performed to maximize round trip efficiency, but minimizinglevelized cost of energy generally provides a rational means of balan-cing capital costs with fuel and/or charging costs.
4. Discussion
The results show that reversible solid oxide cell systems can bedesigned to achieve high efficiency and low levelized cost when in-tegrated with natural gas and CCS infrastructure. If the system is to beused solely for synthetic natural gas production, then the choice ofwhether to purify the SNG towards a higher methane concentrationshould be driven primarily by local or regional regulations and otherfactors beyond the performance and cost of the system. On the otherhand, methanation benefits a reversible system in both performanceand cost, because methanation allows the stack to be operated lessexothermically (i.e., more efficiently) while still providing enough heatfor steam generation. However, previous ReSOC studies have shownthat designing a system to provide just enough waste heat for steamgeneration at rated power results in a heat deficit at part load [38].During part load operation, the system must operate at a lower currentdensity, thus reducing the amount of waste heat produced by the stackthat can be used to generate steam. Electrical heaters can be used tomake up the energy deficit, and although the resulting detriment toefficiency is partially offset by higher stack efficiency at part-load, itwould be preferable if the system could operate over a wide rangewithout the need for supplemental electrical heating [7]. Methanationis beneficial in this regard because it allows either a greater turn downratio without electrical heating, or it allows a lower design point
Fig. 10. LCOE as a function of gas-to-power mode operating time for differenttotal capacity factors.
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current density while meeting steam generation needs at part load.This thermal management feature is noteworthy because opera-
tional flexibility is an important consideration with energy storage andgrid energy management technologies. To enable greater penetration ofrenewables, these technologies must be capable of responding tochanges in load and renewable supply in ways that do not significantlydegrade performance, reliability, or durability. Steam electrolysis sys-tems are disadvantageous in this regard because their thermal in-tegration generally requires high overpotential operation or supple-mental heat from electricity or external sources, which limits theirefficiency and operability at part-load [84–86,10]. Co-electrolysis sys-tems aimed at producing methane reap the benefits of easier systemthermal management and the existing natural gas infrastructure.
As shown in Fig. 10, this study illustrates other benefits to opera-tional flexibility enabled by integration with existing natural gas in-frastructure. Traditional ReSOC systems that store all reactants in tanksare limited in capacity by the size of storage [38,52,35,43] and thestorage “state of charge”. Depending on the pipeline capacity of naturalgas and carbon dioxide of a given geographic region, this constraintmay be greatly alleviated by power-to-gas technology. For example, ifrenewable generation is particularly poor on a given day and the ReSOCsystem cannot produce much SNG, it can still employ pipeline naturalgas to produce power during peak hours. This quality could makeReSOC power-to-gas systems an attractive option to utilities because itreduces or eliminates the need for backup capacity to meet demand.The dual ability of these systems to both store excess renewable energyand provide on-demand power without energy capacity limitationslikely has economic benefits beyond the often-used levelized cost ofenergy metric.
Development of ReSOC systems, however, are not without chal-lenges. Managing stack pressure is a particularly common issue withsolid oxide technology, especially in systems that do not mix fuel andair streams immediately downstream of the stack. The proposed systemhas a 20 bar pressure differential between the stack and ambient con-ditions, and a 20 bar pressure differential between the pipelines andstack, with a significant amount of turbomachinery to ensure high ef-ficiency. Controlling this equipment over a range of operating condi-tions while preventing potentially damaging stack pressure excursionsand avoiding compressor surge or choking warrants an in-depth studyin and of itself. The transient behavior of the stack and system duringpart-load and mode-switching operations is another area that couldbenefit from further analysis.
Additionally, development and demonstration of large platform,intermediate temperature, pressurized kW-scale ReSOC stacks lagsconsiderably behind solid oxide fuel cell (SOFC) stack technology de-velopment. Most planar SOFC stacks operate well-above 700°C, withoutany pressurized operating units (commercial or pre-commercial) in thefield [87]. Metal-supported SOFC technology based on gandolinium-doped ceria composites has made considerable strides towards com-mercialization and is currently one of the only SOFC stack technologiesoperating at 600°C or below [88–90]. However, this technology has notoperated at pressure or under electrolytic conditions. In general, in-creasing research and development activity is underway for high tem-perature electrolytic SOC stack technology[7,13,91–100,100,101,86,102]. These works have largely not includedlow- and intermediate-temperature ReSOC stack technology develop-ment, and thus, much development work remains, including for re-versible, pressurized operation before such stack technology is ready forintegration with system BOP equipment.
As mentioned in the introduction, the environmental sustainability
of the proposed system depends on the ability to sequester the carbondioxide produced in gas-to-power mode. In practice, this necessitatescarbon dioxide transportation and sequestration infrastructure. Thoughcarbon capture, transport, and storage technologies are all consideredmature, their adoption and implementation has been slow, possibly duein part to a lack of consistent public policy and high private sector risk.However, most work to date has been focused on post-combustioncapture. Some predict that transformational technologies that blur theline between carbon capture and power generation by making CCSmore implicit in system design will render current capture methodsobsolete in the long run [64]. Companies are already investing sig-nificantly in such concepts like the Allam cycle, which uses oxy-com-bustion of natural gas to provide heat to a supercritical CO2 cycle,producing power at nearly 60% efficiency and exhaust streams com-posed of liquid water and high purity, high pressure CO2 [103]. TheReSOC system described in this study offers even higher gas-to-powerefficiency, while also providing grid management capabilities for in-tegration of renewables. The future of energy infrastructure is expectedto be more distributed, and technologies that offer greater flexibility inenergy management operations will have deployment advantages.
5. Conclusions
This paper analyzes the economics and performance of a 50 MWeintermediate temperature ReSOC system integrated with both naturalgas and carbon capture and storage infrastructure. We consider twoobjectives: electrolysis operation for production of synthetic naturalgas, and reversible operation for storage and production of electricity.For both objectives, the system is optimized to minimize the levelizedcost of the product for four scenarios: (1) no external methanation orhydrogen separation, (2) external methanation without hydrogen se-paration, (3) hydrogen separation without external methanation, and(4) both external methanation and hydrogen separation. Methanation isaccomplished with a water-cooled, packed bed, isothermal methanationreactor, and hydrogen separation is accomplished with a counterflowhydrogen permeable membrane. Without external methanation, thesystem can produce a synthetic gas mixture of roughly 42% hydrogenand 54.8% methane at a cost of $21.3/MMBTU (72.7 $/MWh) and anLHV efficiency of 81.7%. Including both a methanator and membraneseparator increases the methane purity to 92%, but increases the le-velized SNG cost to $22.7/MMBTU (77.5 $/MWh). Electricity and CO2
contribute to over half of the LCOSNG.A system designed for reversible operation can achieve LHV effi-
ciencies of 84% and 69% in power-to-gas and gas-to-power modes, re-spectively, with a levelized cost of energy of roughly 10.5 ¢/kWh, de-pending on what methanation and/or separation technology is included.Methanation benefits reversible operation by allowing higher electrolysissystem efficiency and reducing electricity input costs. Allowing the cur-rent density of gas-to-power mode to be greater than that of power-to-gasmode reduces system cost by increasing power output. Whereas the le-velized cost of SNG possible with ReSOC technology is not competitivewith current U.S. natural gas markets without subsidies or incentives, thelevelized cost of energy possible with reversible operation is competitivewith existing grid energy management technologies, such as batteriesand natural gas peaker plants. If the plant is operated at a high capacityfactor and spends more time in gas-to-power mode than in power-to-gasmode the LCOE approaches 6 ¢/kWh, which is competitive with com-bined-cycle natural gas. However, the ReSOC system has the addedbenefit of fuel production capability.
Intermediate temperature ReSOC stack development operating on
E.P. Reznicek and R.J. Braun Applied Energy 259 (2020) 114118
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carbonaceous fuels will require considerable attention to transitionfrom lab-scale experiments and conceptual models to commercializedsystems. This includes larger scale tests and demonstrations, part-loadand transient simulation and testing, and control strategy development.In addition to these tasks, the conceptual space of ReSOCs is not fullyexplored. The proposed reversible system is novel relative to both en-ergy storage technologies and conventional power plant concepts.Unlike batteries and conventional energy storage technologies, theenergy generation capacity is decoupled from energy storage capacity.Unlike conventional fossil-based power plants, the system also has theability to store excess renewable energy. The net value that this
flexibility offers to the grid has yet to be quantified.
Declarations of Competing Interest
None.
Acknowledgments
This research was partially supported by the Stanford UniversityGlobal Climate and Energy Project through award #51922.
Appendix A. Statepoint Tables
Tables 9–12.
Table 9Power-to-gas mode statepoint data (optimized for reversible operation).
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