Supercritical Direct-Methane-to-Methanol Coupled with Gas-to-Wire for Low-Emission Offshore Processing of CO 2 -Rich Natural Gas: Techno-Economic and Thermodynamic Analyses

: A greater H/C ratio and energy demand are factors that boost natural gas conversion into electricity. The Brazilian offshore pre-salt basin has large reserves of CO 2 -rich associated gas. Selling this gas requires high-depth long-distance subsea pipelines, making gas-to-pipe costly; in particular, gas-to-wire instead of gas-to-pipe is more practical since it is easier to transmit electricity via long subsea distances. This research proposes and investigates an innovative low-emission gas-to-wire alternative consisting of installing supercritical direct-methane-to-methanol upstream to gas-to-wire, which is embedded in an exhaust-gas recycle loop that reduces the subsequent carbon capture costs. The process exports methanol and electricity from remote offshore oil-and-gas ﬁelds with available CO 2 -rich natural gas, while capturing CO 2 . Techno-economic, thermodynamic and lost work analyses assess the alternative. Supercritical direct-methane-to-methanol is conducted in supercritical water with air. This route is chosen because supercritical water readily dissolves methanol and CO 2 , helping to preserve methanol via stabilization against further oxidation by gaseous air. Besides being novel, this process has intensiﬁcation since it implements exhaust-gas recycle for –ﬂue-gas reduction, CO 2 abatement via post-combustion capture with aqueous monoethanolamine, CO 2 dehydration with triethylene glycol and CO 2 densiﬁcation for enhanced oil recovery. The process is fed with 6.5 MMS m 3 /d of CO 2 -rich natural gas (CO 2 > 40%mol) exporting methanol (2.2 t/h), electricity (457.1 MW) and dense CO 2 for enhanced oil recovery, with an investment of 1544 MMUSD, 452 MMUSD/y in manufacturing costs and 820 MMUSD/y in revenues, reaching 1021 MMUSD net present value (50 years) and a 10 year payback time. The Second Law analysis reveals overall thermodynamic efﬁciency of 28%. The lost work analysis unveils the gas-combined-cycle sub-system as the major lost work sink (76% lost work share), followed by the post-combustion capture plant (14% lost work share), being the units that prominently require improvements for better economic and environmental performance. This work demonstrates that the newly proposed process is techno-economically feasible, environmentally friendly, thermodynamically efﬁcient and competitive with the gas-to-wire processes in the literature.


Introduction
Fossil fuels still lead the global energy matrix, despite the increasing utilization of renewable sources.A huge rise in power generation from natural gas is predicted for the next few decades, considering that natural gas (NG) is the cleanest fossil fuel and its reserves are expanding [1].In the Brazilian pre-salt offshore basin, the deep-water oil reserves have a high gas-to-oil ratio with an associated gas that is very rich in terms of carbon dioxide (CO 2 ) (above 40%mol) [2].The commercialization of this low-quality gas requires large investments in high-depth long-distance subsea pipelines to deliver such NG to the market [3].In this context, a suitable solution to overcome both the NG and CO 2 transport infrastructures (gas-to-pipe) is to implement floating gas-to-wire (GTW) plants comprising NG combined cycles (NGCC) [4].An important issue for the technical feasibility of GTW is the gas availability in order to guarantee its conversion into electricity [5].Implemented on floating rigs over offshore gas fields, GTW converts the raw gas directly into electricity, which is sent to onshore sites by using high-voltage direct-current (HVDC) cables [6] for lower transmission losses [7].However, GTW per se is not sufficient given the current climate concerns, i.e., GTW must be accompanied by carbon capture and storage (CCS) or carbon capture and utilization (CCU) in order to guarantee low CO 2 emissions.
1.1.Offshore Gas-to-Wire with CCS Given the global warming scenario, GTW must be combined with CCS or CCU to reach emission targets [8], lowering the carbon footprint of the produced power [9].A suitable solution for the captured CO 2 is its reinjection into the reservoir as enhanced oil recovery (EOR) fluid [10], since it increases oil production [11], offering additional monetary leverage [12].Thus, EOR is considered a CCU strategy.Assessing several CCS configurations (such as chemical absorption, physical absorption, membrane permeation and hybrids), Araújo et al. [13] identified that chemical absorption attains the minimum CO 2 emissions per ton of CO 2 injected.Hetland et al. [14] studied a GTW-CCS plant evaluating the coupling of post-combustion carbon capture (PCC) with a floating Siemens NGCC.In their configuration, the NGCC flue gas feeds a PCC unit using an aqueous monoethanolamine (aqueous MEA) solvent.Despite not considering important techniques like exhaust gas recycling (EGR) and CO 2 -EOR stream dehydration, the authors demonstrated the theoretical feasibility of a floating GTW-CCS.
In the context of low-emission GTW-CCS processes, EGR is being considered in the literature [15].EGR favors the CO 2 separation step, since it lowers the exhaust gas flow rate and raises the flue gas CO 2 content.Higher CO 2 content increases the driving force for CO 2 capture, decreasing the column height, while the lower flue gas flow rate lowers the column diameter, i.e., both EGR consequences reduce the CCS/CCU investment [16].As the circulating nitrogen and oxygen flow rates diminish in the flue gas, EGR also reduces NOX emissions [17].Thus, GTW-CCS implementation on offshore rigs over deep-water oil-and-gas fields must consider (i) EGR; (ii) post-combustion carbon capture from enriched flue gas through absorption in aqueous monoethanolamine (aqueous MEA), i.e., the PCC-MEA plant; (iii) a high-pressure CO 2 dehydration unit (CDU) to reduce the water content (below ≈160 ppm-mol), preventing CO 2 hydrate formation [18]; and (iv) the injection of dense CO 2 in the reservoir as an EOR agent.

Direct Methane-to-Methanol
Direct methane (conversion) to methanol (DMTM) has been widely investigated in the literature as an alternative for the production of methanol from methane, dismissing the expensive reforming and synthesis gas route.Zakaria and Kamarudin [19] discuss several pathways for DMTM, including gas-phase DMTM, liquid-phase DMTM and supercritical DMTM.Zhang et al. [20] carried out gas-phase DMTM, obtaining methanol selectivity of 60% at 13% methane conversion at 50 bar and 430-470 • C. Holmen [21] also studied gas-phase DMTM and claimed that the best results occurred at methanol selectivity values of 30-40%, with methane conversion of 5-10% under 30-60 bar and 450-500 • C. In liquidphase DMTM routes, a crucial factor is the selection of a convenient solvent [22].The major obstacle is the need for catalysts that not only exhibit adequate selectivity and reactivity, but also tolerate oxidation and protic solvents.Liquid-phase DMTM reactions generally present methane conversion limited to ≈10% [23].The main challenge of gasphase and liquid-phase DMTM is to preserve the formed methanol, stabilizing it to prevent further oxidation, since the reaction medium conditions are aggressive and usually promote methanol degradation.
In this context, supercritical DMTM conducted in supercritical water (SCW) emerges as an alternative to the DMTM reaction.In supercritical DMTM, the properties of the reaction medium (supercritical solvent properties) can be adjusted by manipulating the pressure and temperature [24].Supercritical water (SCW) (P > 22.12 MPa, T > 374.3 • C) is an effective supercritical DMTM solvent since it readily dissolves the formed methanol, stabilizing it and preventing further oxidation perpetrated by the gaseous air, i.e., creating a special reaction medium [25].Savage et al. [24] investigated DMTM-SCW's feasibility (T = −481 • C) and obtained methane conversion of up to 6%, oxygen conversion of up to 100% and methanol selectivity ranging from 4 to 75%.The authors noted that the highest selectivity occurred at lower conversion rates.Lee and Foster [26] investigated DMTM in supercritical water (DMTM-SCW) using an isothermal laminar reactor at 250 bar, at varying temperatures in the 400-450 • C range.The authors showed that methane was oxidized mainly to CO, CO 2 and methanol, wherein the highest methanol selectivity reached ≈35% for 1-3% methane conversion at 400-410 • C. The authors also detected the small formation of hydrogen and attributed it to the water-gas shift reaction.Regarding the operational difficulties brought by supercritical DMTM, they are obviously the high pressure and temperature [25], but these conditions would be also encountered in the case of methanol production through the conventional NG reforming and synthesis gas conversion route [25], which, in fact, is a much more complex and expensive process.Moreover, NG production and NG processing on oil-and-gas offshore rigs are essentially characterized by high pressure (e.g., membrane skids operating at 70 bar or higher, gas lift injection lines at pressures around 200 bar or higher, CO 2 injection lines at 400 bar or higher, water injection lines above 200 bar, etc.).Thus, particularly high pressures are not a major concern on deep-water gas-and-oil offshore rigs.It is reasonable to suppose that these severe conditions of supercritical DMTM are not especially problematic in the offshore rig context.Moreover, the proposed supercritical DMTM is a once-through version with a short-residence-time reactor, to avoid methanol selectivity losses through parasitic oxidations, i.e., supercritical DMTM does not prescribe a recycle loop around the small DMTM reactor, in spite of the low methane conversion.This fact considerably simplifies the process because high-pressure recycle compressors, pumps, intercoolers, knock-out vessels, several heat exchangers and complex large reactors are eliminated.Lastly, the high pressure and high temperature investment of supercritical DMTM is somewhat recovered via power generation through adiabatic expanders after the DMTM.

The Present Work
The present work proposes supercritical DMTM insertion upstream of the GTW without DMTM recycling.The intention here is to evaluate the conversion of a part of the CO 2 -rich NG into valuable methanol products before burning the rest of the NG in the GTW.The supercritical DMTM route is chosen due to its high selectivity to methanol and the nonrequirement for another chemical solvent, and water is a safe and inexpensive raw material whose reposition is not necessary.Offshore DMTM-SCW coupled to GTW employing EGR, CCS and CDU configures a new processing route for CO 2 -rich NG available at remote offshore locations.This new route is denoted here by DMTM-GTW-CCU.There is a clear literature gap concerning DMTM-GTW-CCU with DMTM-SCW.To fill this gap, the present work designs and investigates-via techno-economic and thermodynamic (Second Law) analyses-an innovative conceptual offshore DMTM-GTW-CCU with DMTM-SCW and explores its peculiarities.

Methods
Offshore DMTM-GTW-CCU fed with CO 2 -rich NG exports methanol and power and dispatches CO 2 -to-EOR.The DMTM-GTW-CCU system was designed and simulated in Aspen-HYSYS for technical, economic and thermodynamic evaluations.The necessary theoretical frameworks are discussed in this section.

Feed Compression Unit
The supercritical DMTM step proposed in this research is an adaptation of the experiment carried out by Lee and Foster [26], which uses, in addition to water, raw CO 2 -rich NG (CH 4 = 49.82%mol) and air (O 2 = 20.60%mol), as feeds, instead of pure CH 4 and O 2 , respectively.The reactant streams (Figure 2) need to pass through compression trains (compressors with stage compression ratio ≈ 3 and pumps with stage compression ratio = 4) to reach the DMTM-SCW reaction pressure (P = 250 bar).The aqueous condensates generated by air and NG compression are mixed, according to their pressure, in the water compression train.

Direct Methane-to-Methanol in Supercritical Water (DMTM-SCW)
The high-pressure stream that leaves the FCU (T = 31.4• C, P = 250 bar) is heated with the reactor product stream (T = 410 • C) in a plate exchanger (Plate Exch-1).To simulate the DMTM-SCW reaction in Aspen-HYSYS, an adiabatic conversion reactor was used (O 2 Conv = 100%, CH 4 Conv = 4.5%), considering CO, CO 2 and methanol as products and using 50%, 22% and 28% for their selectivities, respectively [26].After the reactor (Figure 3), the cooled product stream passes through a flash separator (Fl-1), where the generated gas stream is first sent to an expander (EXP), reducing its temperature and pressure (T = 11.6 • C, P = 35 bar) while generating power, and subsequently to a threephase separator, which separates the gas, liquid hydrocarbon and aqueous phases.The Fl-1 liquid stream (T = 410 • C, P = 250 bar) heats the streams leaving the three-phase separator and, after being cooled and having its pressure reduced (T = 70.2• C, P = 25 bar), passes to another flash separator (Fl-2).The Fl-2 gas stream mixes with the other gas and hydrocarbon streams, forming the fuel gas that feeds the NGCC, and the Fl-2 liquid stream mixes with the aqueous stream and is sent to the methanol-water separation system (MWS).The high-pressure stream that leaves the FCU (T = 31.4°C, P = 250 bar) is heated with the reactor product stream (T = 410 °C) in a plate exchanger (Plate Exch-1).To simulate the DMTM-SCW reaction in Aspen-HYSYS, an adiabatic conversion reactor was used (O2 Conv = 100%, CH4 Conv = 4.5%), considering CO, CO2 and methanol as products and using 50%, 22% and 28% for their selectivities, respectively [26].After the reactor (Figure 3), the cooled product stream passes through a flash separator (Fl-1), where the generated gas stream is first sent to an expander (EXP), reducing its temperature and pressure (T = 11.6 °C, P = 35 bar) while generating power, and subsequently to a three-phase separator, which separates the gas, liquid hydrocarbon and aqueous phases.The Fl-1 liquid stream (T = 410 °C, P = 250 bar) heats the streams leaving the three-phase separator and, after being cooled and having its pressure reduced (T = 70.2°C, P = 25 bar), passes to another flash separator (Fl-2).The Fl-2 gas stream mixes with the other gas and hydrocarbon streams, forming the fuel gas that feeds the NGCC, and the Fl-2 liquid stream mixes with the aqueous stream and is sent to the methanol-water separation system (MWS).
The Peng-Robinson-Twu equation of state was selected in sub-systems that operate with the supercritical phase (FCU and DMTM-SCW) due to the fact that this equation of state guarantees adequate thermophysical property calculations in the supercritical region and the suitable calculation of VLE in multicomponent systems containing polar species such as water and methanol [27,28].The Peng-Robinson-Twu equation of state was selected in sub-systems that operate with the supercritical phase (FCU and DMTM-SCW) due to the fact that this equation of state guarantees adequate thermophysical property calculations in the supercritical region and the suitable calculation of VLE in multicomponent systems containing polar species such as water and methanol [27,28].

Methanol-Water Separation and Light-Ends Combustion
As shown in Figure 4, MWS is composed of three distillation columns: (i) the lightends column (LEC), (ii) methanol-water separation column 1 (MWSC-1) and (iii) methanolwater separation column 2 (MWSC-2).The LEC is a 20-staged column (P = 7 bar) and aims to remove nitrogen, hydrogen, CO, CO 2 and light hydrocarbons (methane, ethane and propane) from the methanol-water mixture.The LEC top stream current (T = 35

Natural Gas Combined Cycle Plant
The NGCC plant contains four parallel NGCC elements for suitable electricity generation ( 550 MW).Each NGCC element (Figure 5) consists of four gas turbines sending hot flue gas to one heat recovery steam generator (HRSG), which heats a steam Rankine cycle.Compared with a gas turbine simple cycle, the combined cycle substantially lowers the ratio of CO2 emitted per MWh generated [33].Gas turbines of the aero-derivative type (Table 1) are more appropriate in offshore rigs thanks to their lower weight-to-power [34] and footprint-to-power ratios [35], besides enhanced crew safety and simple maintainability [36].Gas turbines directly burn raw CO2-rich NG (CO2 > 40%mol), producing a flue gas (FG) that feeds the HRSG at T = 484 °C [32], where low-pressure steam (LPS) (T LPS = 154.6 °C, P LPS = 5.4 bar) and high-pressure superheated steam (HPS) (T HPS = 459 °C, P HPS = 24 bar) are produced from liquid water at the respective pressures.HPS expands in the steam turbine to P = 0.12 bar and is cooled down in the sub-atmospheric condenser with cooling water (CW), recycled as a condensate to HRSG at T = 45 °C.The HRSG-and LECE- MWSC-1 is a 20-staged column (P = 1.013 bar) that receives the LEC bottom stream and aims to concentrate the methanol.The MWSC-1 top stream is directed to MWSC-2 (20 stages, P = 1.013 bar), which has the function of reaching Grade AA methanol purity (99.85%w/w) [30].Pure water is produced in the MWSC-1 and MWSC-2 bottom streams.All columns require LPS (T LPS = 154.6 • C, P LPS = 5.4 bar) to heat their reboilers.

Natural Gas Combined Cycle Plant
The NGCC plant contains four parallel NGCC elements for suitable electricity generation (≈550 MW).Each NGCC element (Figure 5) consists of four gas turbines sending hot flue gas to one heat recovery steam generator (HRSG), which heats a steam Rankine cycle.Compared with a gas turbine simple cycle, the combined cycle substantially lowers the ratio of CO 2 emitted per MWh generated [33].Gas turbines of the aero-derivative type (Table 1) are more appropriate in offshore rigs thanks to their lower weight-to-power [34] and footprint-to-power ratios [35], besides enhanced crew safety and simple maintainability [36].Gas turbines directly burn raw CO 2 -rich NG (CO 2 > 40%mol), producing a flue gas (FG) that feeds the HRSG at T = 484 The gas turbine model in Aspen-HYSYS includes (i) an adiabatic single-stage air compressor; (ii) a combustion chamber modeled as an adiabatic conversion reactor; and (iii) an adiabatic expander.This model was calibrated to factory settings by manipulating the adiabatic efficiencies of the air compressor and expander.Air is supplied at stoichiometric proportions for complete NG combustion.To limit the combustion temperature to manufactory constraints, stoichiometric air is mixed with the EGR stream.Recycled flue gas is extracted after Plate Exchanger 2 (T = 40 °C) and its flow rate is adjusted to match the recommended flue gas temperature at the expander outlet (T = 484 °C).The gas turbine model in Aspen-HYSYS includes (i) an adiabatic single-stage air compressor; (ii) a combustion chamber modeled as an adiabatic conversion reactor; and (iii) an adiabatic expander.This model was calibrated to factory settings by manipulating the adiabatic efficiencies of the air compressor and expander.Air is supplied at stoichiometric proportions for complete NG combustion.To limit the combustion temperature to manufactory constraints, stoichiometric air is mixed with the EGR stream.Recycled flue gas is extracted after Plate Exchanger 2 (T = 40 • C) and its flow rate is adjusted to match the recommended flue gas temperature at the expander outlet (T = 484 • C).

Post-Combustion Capture with Aqueous MEA
The flue gas (FG) (T = 40 • C) that leaves Plate Exchanger 2 from the four NGCC elements is connected to the flue gas (FG) from the LECE (T = 40 • C) and both are sent to the PCC-MEA for decarbonation with aqueous MEA (MEA ≈ 30%w/w).The flue gas feed is distributed in the PCC-MEA absorber through four plates (Figure 6) for better overall mass transfer [37].The PCC-MEA is designed to abate 90% of the CO 2 in the flue gas.Two parameters that define the solvent recirculation and stripper duty are critical in PCC-MEA design: (i) the capture ratio (CR-kg of fresh solvent per kg of captured CO 2 ) and (ii) the stripper heat ratio (HR-kJ per kg of captured CO 2 ).Ideal values for the CR (10-15 kg Solvent /kg CO2 ) and HR (2000-4500 MJ/t CO2 ) are reported by Araújo et al. [38].
Processes 2024, 12, 374 10 of 29 The atmospheric PCC-MEA stripper (Figure 6) demands LPS (T LPS = 154.6 °C, P LPS = 5.4 bar) to heat the reboiler (T = 102.6 °C).The stripper condenser operates in total reflux (i.e., 100% condensate reflux) and releases water-saturated CO2 (P = 1 atm) through its vent.In order to keep CO2 restricted within the CO2 loop between the PCC-MEA and CDU-TEG units, all condensed carbonated waters (T = 35 °C) from the CU-1 knock-out vessels and from the TEG stripper condenser (T = 35 °C) are recycled to PCC-MEA stripper tray #1, while wet CO2 from the TEG stripper condenser vent (T = 35 °C) is recycled to tray #10.This water recycling lowers the water make-up and condenser heat duty and avoids fugitive liberations of CO2 from the CU-1 and CDU-TEG units.Lean MEA is recycled to the PCC-MEA absorber through a pump after the addition of water and MEA make-ups.2.1.6.CO2 Compression Units, CO2 Dehydration Unit and Stripping Gas Unit CU-1 (Figure 7a) is a four-staged intercooled compression train (stage compression ratio ≈ 3) to raise the CO2 stream pressure up to 50 bar for CO2 dehydration, favoring water removal [39].The CO2 to CDU-TEG stream (≈2730 ppm-mol H2O) and TEG solvent (98.5%w/wTEG) feed the 15-staged TEG absorber (Figure 7b), producing dry CO2 (≈160 ppm-mol H2O) for the SGU unit as the top product and rich TEG (H2O ≈ 55%mol) as the bottom product.The TEG solvent is regenerated in the 10-staged TEG stripper, which produces lean TEG as the bottom product (T = 138.9°C) and vapor wet CO2 and carbonated liquid water as top distillate products in the partial condenser.Both the water and wet CO2 distillates are recycled to the PCC-MEA, blocking CO2 emissions.The SGU is a small-scale unit that adjusts the stripping gas (1.5% of dry CO2) in order to control the TEG stripper reboiler temperature below 140 °C [31].These two dry CO2 streams feed a countercurrent heat exchanger (Figure 7c), granting a slight temperature reduction (≈0.5 °C) in the EOR-CO2 stream.The remaining dry CO2 is sent to CU-2 (Figure 7c) to achieve the EOR pipeline pressure (P = 300 bar). .This water recycling lowers the water make-up and condenser heat duty and avoids fugitive liberations of CO 2 from the CU-1 and CDU-TEG units.Lean MEA is recycled to the PCC-MEA absorber through a pump after the addition of water and MEA make-ups.
2.1.6.CO 2 Compression Units, CO 2 Dehydration Unit and Stripping Gas Unit CU-1 (Figure 7a) is a four-staged intercooled compression train (stage compression ratio ≈ 3) to raise the CO 2 stream pressure up to 50 bar for CO 2 dehydration, favoring water removal [39].The CO 2 to CDU-TEG stream (≈2730 ppm-mol H 2 O) and TEG solvent (98.5%w/wTEG) feed the 15-staged TEG absorber (Figure 7b), producing dry CO 2 (≈160 ppm-mol H 2 O) for the SGU unit as the top product and rich TEG (H 2 O ≈ 55%mol) as the bottom product.The TEG solvent is regenerated in the 10-staged TEG stripper, which produces lean TEG as the bottom product (T = 138.9• C) and vapor wet CO 2 and carbonated liquid water as top distillate products in the partial condenser.Both the water and wet CO 2 distillates are recycled to the PCC-MEA, blocking CO 2 emissions.The SGU is a small-scale unit that adjusts the stripping gas (1.5% of dry CO 2 ) in order to control the TEG stripper reboiler temperature below 140 • C [31].These two dry CO 2 streams feed a countercurrent heat exchanger (Figure 7c), granting a slight temperature reduction (≈0.5 • C) in the EOR-CO 2 stream.The remaining dry CO 2 is sent to CU-2 (Figure 7c) to achieve the EOR pipeline pressure (P = 300 bar).

Process Economic Analysis
The economic analysis of DMTM-GTW-CCU was performed via Turton et al. [40] to calculate the (i) fixed capital investment FCI (MMUSD); (ii) cost of manufacturing COM (MMUSD/y); (iii) revenues REV (MMUSD/y); (iv) gross annual profit GAP (MMUSD/y) and annual profit AP (MMUSD/y); and (v) net present value NPV (MMUSD).FCI (MMUSD) was estimated via Equation (1) through the bare module costs (C BM ) determined from the reference purchase costs, which are updated with the CEPCI Chemical Engineering Plant Cost Index (CEPCI = 816, for 2022 [41]).C BM was calculated via the Six-Tenth Rule (Equation ( 2)) for equipment capacities above/below correlation limits using the equipment capacity (CAP) at limiting and design conditions.The data used for FCI calculation can be found in Table S1 in the Supplementary Materials file.CUT (MMUSD/y) represents the cost of utilities given by Equation (3) and COM (MMUSD/y) is calculated through Equation ( 4), where COL (MMUSD/y) and CRM (MMUSD/y) stand for the annual costs of labor and raw materials.GAP (MMUSD/y), AP (MMUSD/y) and NPV (MMUSD) are found via Equations ( 5) and ( 6), wherein REV (MMUSD/y), DEPR (MMUSD/y), ITR (%), i (%) and N(y), respectively, represent annual revenues, annual depreciation, the income tax rate, the annual interest rate and the project lifetime (Table 2).Offshore DMTM-GTW-CCU revenues include electricity and methanol exportation, besides the increment in oil production from the EOR yield generated by CO 2 injection in the reservoir.

Process Thermodynamic Analysis
Thermodynamic analysis is effective to identify the degradation of resources throughout the process.The steady-state offshore DMTM-GTW-CCU and sub-systems are assessed via an analysis of processes known as the Second Law analysis or thermodynamic analysis.In the Second Law analysis, the overall system and each of its sub-systems have to be previously identified as either a power-producing system or a power-consuming system.Figure 9a displays a steady-state open system for Second Law analysis showing various feed and product streams (arrows).The open system only makes thermal contact with an infinite and isothermal heat reservoir R 0 kept at temperature T 0 .It is important to understand that any system under Second Law analysis (i.e., the overall system or its sub-systems) complies with Figure 9a and is either a power-producing system ( .W > 0) or a power-consuming system ( .W < 0), but only has heat interactions with R 0 via heat absorption ( .Q > 0) or via heat rejection ( .Q < 0).G n , H G n , S G n , respectively, designate the molar flow rate (kmol/s), enthalpy (MJ/kmol) and entropy (MJ/kmol•K) of the nth feed stream (n = 1..Nf).K n , H K n , S K n are analogous symbols for the nth product stream (n = 1..Np).

W
MAX is calculated via the Second Law at reversibility using Equations ( 9)- (12).Equation (10) symbolizes the entropy balance of the Universe at reversibility, being .

Equivalent Power
Equivalent power .

W
Eq represents the thermodynamic power equivalence of electricity production (consumption) and utility production (consumption) [29] and is always positive for regular systems.However, it can be negative for "outlaw" systems, like a theoretically power-producing system (i.e., spontaneous system) that consumes power instead of producing power (e.g., CW tower).For instance, the consumption (production) of LPS is equivalent to the consumption (production) of  The equivalence of heat and power is settled through reversible heat engines that can attain the maximum yields of heat-work conversion.These maximum yield engines are well known as the Carnot engine (CE) and the Carnot heat pump (CHP) [29].The CE receives heat from a hot source, generates power and discharges heat to a colder source.Analogously, the CHP absorbs power while drawing heat from a cold source and discharging heat to a hotter one.Figure 9b depicts a configuration compatible with Figure 9a, i.e., it depicts a steady-state open system thermally interacting only with the heat reservoir R 0 , generating a work effect associated with .EE and other work streams.The difference is that the system in Figure 9b  Q LPS from the LPS loop (imports power .W Eq LPS ). Figure 9b shows that the CW loop and LPS loop are external to the original system (but are added to it, defining a newer system compatible with Figure 9a), R 0 is always a cold heat reservoir (cold source), Q LPS are always positive.It is not difficult to create an analogous version of Figure 9b for a power-producing system (i.e., in which CW is imported and electricity and LPS are exported).
The steady-state power-consuming system (Figure 9b) rejects heat ( .Q CW ) to cold CW, producing hot CW, which is restored to cold CW via a CW loop using the CE that exports power ( .W Eq CW ) and rejects heat ( .Q R 0 CW ) to R 0 .Equivalently, the power-consuming system absorbs heat ( .Q LPS ) from LPS, becoming an LPS condensate, which is restored to LPS via an LPS loop, using the CHP that imports power ( .W Eq LPS ) and absorbs heat ( . W Eq CW is obtained by Equation ( 16) using Equation (15a), Equation (15b) and CE entropy conservation in Equation (15c).Appropriately, .

W
Eq LPS is obtained by Equation (18) using Equation (17a), Equation (17b) and CHP entropy conservation in Equation (17c).Equation ( 18) also works for .W Eq LPS in power-producing systems, but with the difference that the LPS loop now spins counter-clockwise, the CE replaces the CHP, and all effects are reversed.
Equation (19a) calculates the equivalent power produced by a power-producing system that exports .EE and LPS (counter-clockwise LPS loop in Figure 9b) and consumes CW.Analogously, Equation (19b) is the equivalent power consumed by a power-consuming system that consumes .EE, CW and LPS.The substitution of Equations ( 16) and ( 18) into Equation (19a,b) creates Equation (20a,b), respectively, leading to the equivalent power produced by a power-producing system and the equivalent power consumed by a powerconsuming system, respectively. .

Thermodynamic Efficiency
Second Law analysis allows the calculation of the thermodynamic efficiency and the lost work (lost power) of the overall system and also of its sub-systems.This corresponds to estimating the degree of resource degradation in the system and its sub- . . . . .

Results and Discussion
The results from the technical, economic and thermodynamic analyses of the offshore DMTM-GTW-CCU are next presented and discussed.

Technical and Economic Performance
Table 3 summarizes the technical and economic results of the offshore DMTM-GTW-CCU.The DMTM plant, which encompasses the FCU, DMTM-SCW, MWS and LECU sub-systems, produces methanol (2.2 t/h) from methane (91.7 t/h, contained in 342.4 t/h of raw CO 2 -rich NG).Grade AA methanol purity (99.85%w/w) [30] is achieved through two distillation columns: (i) MWSC-1, which aims to concentrate the methanol stream (from 1.1 to 49.0%mol), and (ii) MWSC-2, which obtains methanol specification.Pure water was generated as MWSC-1 and MWSC-2 bottom products.The NGCC plant (with four parallel NGCC elements) of the offshore DMTM-GTW-CCU produces 564.5 MW of gross power (≈97.8% from gas turbines), allowing 457.1 MW of net exported power.Each gas turbine burns ≈23.4 t/h of fuel-gas and produces ≈34 MW at 33.8% LHV efficiency.EGR entails that a single NGCC element produces 1890.7 t/h flue gas at 16.7%mol CO 2 .The HRSG cools down the gas turbine flue gas from 484 • C to 160 • C, the minimum temperature for maximum HPS generation, ensuring sufficient LPS to heat the MWS, PCC-MEA and CDU-TEG reboilers.
The PCC-MEA stripper requires 694.5 MW of LPS and discharges 515.0 t/h of watersaturated CO 2 as the top product.CU-1 pressurizes the CO 2 stream up to 50 bar to reach the CDU-TEG's ideal conditions for CO 2 dehydration.The CDU-TEG removes ≈94% of the water from its feed and produces 498.4 t/h of dry CO 2 (≈160 ppm-mol H 2 O).The SGU sends 7.1 t/h of low-pressure dry CO 2 to the TEG stripper reboiler to maintain its temperature below 140 • C to avoid TEG degradation [31].Considering the small flow rate of the water removed from the CO 2 stream, the TEG stripper reboiler demands 1.1 MW of LPS.CU-2 exports 491.3 t/h of dry CO 2 (P = 300 bar, T = 35 • C) to EOR, avoiding the emission of this CO 2 to the atmosphere.Thus, EOR is classified as a carbon capture and utilization (CCU) process, since it produces oil from the injected CO 2 (EOR yield = 1.5 bbl Oil /t CO2 [29]) and consequently monetizes it.
The offshore DMTM-GTW-CCU power demand corresponds to 19.0% of its gross power.The FCU, CU-1 and CU-2 are the main electricity consumers (considering their compressor trains), while the PCC-MEA leads the CW and LPS consumption.
Figure 10a shows the process of water generation or consumption of the overall system and its sub-systems.As the offshore DMTM-GTW-CCU produces water, it becomes self-sufficient in terms of this resource.Thus, it is not necessary to import water.The calculated economic variables (FCI, COL, CUT, CRM, REV, NPV) are presented in Table 3.One can note that the cost of utilities (CUT) is zero, since the power, LPS and CW are produced on site.Although DMTM-GTW-CCU plant implementation requires a high fixed capital investment (FCI = 1544.4MMUSD), the project is economically feasible, considering the scenario described in Table 2. Figure 10b shows the NPV for a 50 year horizon, highlighting a payback time of 10 years.

Thermodynamic Analysis Results
Thermodynamic and lost work analyses were executed for the offshore DMTM-GTW-CCU overall system and its sub-systems, i.

W
LOST for all sub-systems must provide the same values as for the overall system, which are determined independently of the subsystems.The paralleling of the overall system values with the respective sum over the sub-systems leads to a consistency check of the thermodynamic investigation.There is always some divergence between the sums over the sub-systems and the overall system in practice.Therefore, divergences below 1% could be established to confirm consistency in the thermodynamic analysis.4).
The LECU is also a power-producing system ( .EE that is generated in the gas turbines and in the steam turbine minus the Rankine cycle pump power (Figure 5).The thermodynamic efficiency of the NGCC plant reached 46.98%.
As with any separation process, the MWS is a power-consuming system.As predicted, the MWS .EE are all zero, the SGU's thermodynamic efficiency is 0%, meaning that the SGU has sufficient spontaneity to produce power, but this potential is wasted and no power is actually produced.

Comparison with the Literature
Hetland et al. [14] is a classical and essential reference on floating GTW-CCS.The authors carried out a theoretical GTW-CCS study evaluating PCC-MEA implementation downstream of a floating Siemens NGCC (450 MW).The authors pointed out that the floating GTW-CCS was technically feasible, although they did not consider intensification factors, as considered here, such as the EGR and CO 2 -EOR stream dehydration (both are realistically necessary to radically reduce the CCS costs and to prevent CO 2 hydrate formation in the exported CO 2 stream).Additionally, they did not perform economic, thermodynamic or exergy analyses of the floating GTW-CCS.On the other hand, the present work filled these gaps as it considered a floating DMTM-GTW-CCU with a DMTM-SCW process coupled to gas-to-wire, achieving low emissions and producing methanol, wherein complete techno-economic, thermodynamic and lost work analyses were conducted.The present DMTM-GTW-CCU is able to generate 550 MW at low emissions and reasonable thermodynamic efficiency.Above all, it was demonstrated that the overall offshore DMTM-GTW-CCU process is potentially profitable, thermodynamically efficient and without environmental impacts.
In a recent work, using the same raw CO 2 -rich NG conditions, Milão et al. [29] obtained thermodynamic efficiency of 35.5% for their offshore GTW-CCS (677 MW) overall process without considering DMTM, EGR and CO 2 dehydration.The present work found similar NGCC and PCC-MEA sub-system thermodynamic efficiencies and lost work but with differences in efficiency in the overall system (28% versus 35.5%).The underlying factor is that the DMTM addition upstream of the GTW-CCS in the present case made the offshore DMTM-GTW-CCU overall process more irreversible, consequently generating more lost work, despite the production of methanol.Moreover, the inclusion of EGR improves the PCC-MEA efficiency in the present case, reducing the lost work, while the inclusion of the TEG dehydration unit and the small stripping gas unit has the opposite effect, consuming power and generating lost work, resulting in lower overall thermodynamic efficiency of 28.0% for the present case.However, evidently, the present analysis is more complete and much more realistic.
These facts confirm that the proposal and the full analysis of the DMTM-GTW-CCU (with DMTM-SCW), as conducted here, constitute a novel study with reasonable contributions vis-à-vis the literature so far.

Conclusions
This work proposed and techno-economically and thermodynamically analyzed an innovative low-emission offshore DMTM-GTW-CCU process using CO 2 -rich NG available at remote deep-water offshore sites as raw material.The DMTM-GTW-CCU partially converts methane from ≈6.5 MMSm 3 /d of CO 2 -rich NG (CO 2 > 40%mol) into methanol (2.2 t/h) by conducting DMTM in supercritical water and then exports low-emission electricity (457.1 MW of net power) and liquid dry CO 2 as EOR fluid, bringing additional economic and environmental advantages.Offshore DMTM-GTW-CCU is an intensified power production process whose main intensification elements are (i) exhaust gas recycling (EGR), which reduces the flue gas flow rate while increasing its CO 2 content; (ii) post-combustion carbon capture via PCC-MEA from enriched flue gas; and (iii) high-pressure CO 2 dehy-dration in CDU-TEG, which removes ≈94% of the water from the CO 2 -to-EOR stream to achieve the final content of ≈160 ppm-mol H 2 O, preventing hydrate formation in EOR pipelines.EGR reduces the PCC-MEA investment and operational costs by lowering the column diameter/height, consequently increasing the DMTM-GTW-CCS' profitability.The process proves to be self-sufficient in process water, thus overcoming a fundamental aspect that would represent a serious shortcoming: at deep-water offshore sites, the continuous importation of water would be an obstacle to plant sustainability.
The Second Law analysis of the offshore DMTM-GTW-CCU overall system reveals 28% thermodynamic efficiency with ≈72% of lost work, with the NGCC sub-system being the greatest lost work sink (≈76% share of overall lost work) due to the highly spontaneous gas turbine firing process.The second lost work sink lies in the PCC-MEA sub-system (≈14% share of overall lost work), while the DMTM-SCW system is the third lost work sink, with a ≈3% lost work share, probably because the extension of the DMTM reaction is appreciably small to prevent methanol selectivity degeneracy.Thereby, the NGCC plant and PCC-MEA are the leading DMTM-GTW-CCU sub-systems that demand thermodynamic improvement in order to generate higher economic and environmental benefits.The consistency of the thermodynamic analysis was demonstrated through lost work sum crosschecks and lateral checks applying the alternative Second Law formula T 0 • .

S UN IV
for the lost work (Table 4).In summary, this work demonstrates that the newly proposed DMTM-GTW-CCU process is techno-economically feasible, environmentally friendly, thermodynamically efficient and competitive with other gas-to-wire processes from the literature, as shown in Section 3.3.

Suggestions for Future Work
The results of the technical, economic and thermodynamic analyses of the offshore DMTM-GTW-CCU were obtained in the context presented in Tables 1 and 2. These results could be influenced by the variations in some parameters.Therefore, it is relevant to implement a sensitivity analysis varying the major factors that influenced the present work's results (especially the prices of NG, oil, methanol and electricity).It is worth mentioning that other factors, such as the geographical location and climate factors, could have influenced the results obtained in this work and should also be considered.In the same way, there are other different and important analyses that could be proposed to investigate the system, such as an exergy analysis of the process and an environmental impact analysis, among others.
and NG compression are mixed, according to their pressure, in the water compression train.
• C) is sent to the light-ends combustion chamber (LECC), generating a hot flue gas (FG) (T = 425.6 • C) that produces LPS (T LPS = 154.6 • C, P LPS = 5.4 bar) in the light-ends combustion exchanger (LECE).The cooled flue gas (T = 40 • C) that leaves the LECE is sent to PCC-MEA.A combustion chamber is modeled as an adiabatic conversion reactor in Aspen-HYSYS.Processes 2024, 12, 374 8 of 29
• C [32], where low-pressure steam (LPS) (T LPS = 154.6 • C, P LPS = 5.4 bar) and high-pressure superheated steam (HPS) (T HPS = 459 • C, P HPS = 24 bar) are produced from liquid water at the respective pressures.HPS expands in the steam turbine to P = 0.12 bar and is cooled down in the sub-atmospheric condenser with cooling water (CW), recycled as a condensate to HRSG at T = 45 • C. The HRSG-and LECE-produced LPS heats the MWS, PCC-MEA and CDU-TEG reboilers.Hence, the Rankine cycle power is restrained by the LPS demand.Processes 2024, 12, 374 9 of 29 = 45 °C.The HRSG-and LECE-produced LPS heats the MWS, PCC-MEA and CDU-TEG reboilers.Hence, the Rankine cycle power is restrained by the LPS demand.

2. 1 . 5 .
Post-Combustion Capture with Aqueous MEAThe flue gas (FG) (T = 40 °C) that leaves Plate Exchanger 2 from the four NGCC elements is connected to the flue gas (FG) from the LECE (T = 40 °C) and both are sent to the PCC-MEA for decarbonation with aqueous MEA (MEA≈30%w/w).The flue gas feed is distributed in the PCC-MEA absorber through four plates (Figure6) for better overall mass transfer[37].The PCC-MEA is designed to abate 90% of the CO2 in the flue gas.Two parameters that define the solvent recirculation and stripper duty are critical in PCC-MEA design: (i) the capture ratio (CR-kg of fresh solvent per kg of captured CO2) and (ii) the stripper heat ratio (HR-kJ per kg of captured CO2).Ideal values for the CR (10-15 kg Solvent /kg CO2 ) and HR (2000-4500 MJ/t CO2 ) are reported byAraújo et al. [38].

Figure 6 .
Figure 6.Post-combustion capture with aqueous MEA (PCC-MEA) (CDU-TEG: CO 2 dehydration unit with TEG; CU: CO 2 compression unit; LPS: low-pressure steam; CW: cooling water).The atmospheric PCC-MEA stripper (Figure6) demands LPS (T LPS = 154.6 • C, P LPS = 5.4 bar) to heat the reboiler (T = 102.6 • C).The stripper condenser operates in total reflux (i.e., 100% condensate reflux) and releases water-saturated CO 2 (P = 1 atm) through its vent.In order to keep CO 2 restricted within the CO 2 loop between the PCC-MEA and CDU-TEG units, all condensed carbonated waters (T = 35 • C) from the CU-1 knock-out vessels and from the TEG stripper condenser (T = 35 • C) are recycled to PCC-MEA stripper tray #1, while wet CO 2 from the TEG stripper condenser vent (T = 35 • C) is recycled to tray #10.This water recycling lowers the water make-up and condenser heat duty and avoids fugitive liberations of CO 2 from the CU-1 and CDU-TEG units.Lean MEA is recycled to the PCC-MEA absorber through a pump after the addition of water and MEA make-ups.

Figure 7 .
Figure 7. Compression units CU-1 (a); CU-2 (c); CO2 dehydration unit with TEG (b) (CDU-TEG) and stripping gas unit (SGU) (c) (CW: cooling water; LPS: low-pressure steam; PCC-MEA: postcombustion capture with aqueous MEA; EOR: enhanced oil recovery).2.1.7.Primary Cooling SystemFigure8exhibits the primary cooling system (PCS) that regenerates cold CW (T = 30 °C) by cooling down hot CW (T = 45 °C) from the intercoolers, condensers and Plate Exchanger 2 (NGCC).Sea water (SW) is the cooling medium and it is collected from the sea surface at tropical latitudes (T = 25 °C) and returns to the sea at T = 35 °C.After this heat exchange carried out through Plate Exchanger 3, cold CW (T = 30 °C) is pumped back to be processed (P = 4 bar).

Figure 9 .
Figure 9. (a) Open system for thermodynamic analysis; (b) equivalent power for power-consuming open system (arrows as feed and product streams) that imports electricity ( EE  ), exports equivalent power via CW loop ( Eq CW W  ) and imports equivalent power via LPS loop ( Eq LPS W ) (CW: cooling

Figure 9 .
Figure 9. (a) Open system for thermodynamic analysis; (b) equivalent power for power-consuming open system (arrows as feed and product streams) that imports electricity ( .EE), exports equivalent and (8) implement the First Law of Thermodynamics for the steady-state open system depicted in Figure9a.The system maximum power (maximum work) .
for power-consuming systems (in general, non-spontaneous changes provided by compression/pumping systems and separation systems like the FCU, MWS, PCC-MEA, CU-1, CU-2 and CDU-TEG), a negative .

.
consumption of CW is always equivalent to the production of .W Eq .The offshore DMTM-GTW-CCU uses three utility types: (i) CW with flow rate J CW (kmol/s), isobaric heat capacity C CW P (MJ/kmol•K) and hot/cold temperatures T CW H (K), T CW C (K); (ii) LPS with flow rate J LPS (kmol/s), vaporization enthalpy ∆H VAP LPS (MJ/kmol) and temperature T LPS (K); and (iii) electricity.constant, considering that CW and LPS operate within narrow temperature ranges.
is a power-consuming System with the following utility effects: it absorbs .EE, rejects heat .Q CW to the CW loop (exports power . 20a,b) , the thermodynamic efficiencies of power-producing systems and power-consuming systems are calculated via Equation (21a,b), respectively.η% = 100• .,b) are intuitive formulas for the lost work (lost power) of powerproducing systems and power-consuming systems, respectively.An alternative way to calculate lost work can be derived from the Second Law formula in Equation (23a) that represents all Universe changes resulting from system transitions, where .S UN IVis the entropy creation rate of the Universe owing to the system operation.Hence, Equation (23b,c) are the lost work formulas generated by Equation (23a) for powerproducing systems and power-consuming systems, respectively, where .SR 0 is replaced by Equation (24a,b), again, for power-producing systems and power-consuming systems..

=
W MAX is negative (−0.01 MW), due to the equivalent power required for methanol and water separation.The MWS imported .W Eq (10.30MW) is measured as the .W Eq LPS consumed in the LEC, MWSC-1 and MWSC-2 reboilers, minus the .W Eq CW produced as hot CW from the LEC, MWSC-1 and MWSC-2 condensers and from four cooling water heat exchangers, added to the .EE demanded in three pumps.The MWS' thermodynamic efficiency reached 0.12%.As with any separation process, the PCC-MEA is a power-consuming system ( −28.23 MW) due to the equivalent power demanded for CO 2 separation from flue gas.The PCC-MEA .W Eq consumed (187.95MW) is obtained as follows: the .W Eq LPS imported by the PCC-MEA stripper reboiler, minus the .W Eq CW exported as hot CW from the stripper condenser and from the lean MEA cooler, added to the .EE required by the solvent recirculation pump and water and MEA make-up pumps.The PCC-MEA's thermodynamic efficiency was 15.02%.CDU-TEG is also a separation process, so it should be a power-consuming system ( .W MAX = −0.003MW).The slight .W MAX value is a result of the very low flow rate of the water removed from the CO 2 stream (≈2730 ppm-mol H 2 O to ≈160 ppm-mol H 2 O).The CDU-TEG .W Eq (0.31 MW) imported is calculated as follows: the .W Eq LPS consumed in the CDU-TEG stripper reboiler, subtracted from the .W Eq CW produced through hot CW from the stripper condenser and from the lean TEG cooler, added to the .EE demanded in the TEG recirculation pump and in the TEG make-up pump.The CDU-TEG thermodynamic efficiency reached 1.11%.The SGU is another sub-system driven by spontaneities, being a power- the lost work results and also verifies the consistency of the present thermodynamic analysis via a comparison of the lost work values estimated through two thermodynamically independent methods, namely (i) via .22a,b) and (ii) via T 0 • .

Figure 11 presents
Figure 11 presents Sankey diagrams for the

3. 3 .
Comparison with the LiteratureHetland et al.[14] is a classical and essential reference on floating GTW-CCS.The authors carried out a theoretical GTW-CCS study evaluating PCC-MEA implementation downstream of a floating Siemens NGCC (450 MW).The authors pointed out that the floating GTW-CCS was technically feasible, although they did not consider intensification factors, as considered here, such as the EGR and CO2-EOR stream dehydration (both are realistically necessary to radically reduce the CCS costs and to prevent CO2 hydrate formation in the exported CO2 stream).Additionally, they did not perform economic, thermodynamic or exergy analyses of the floating GTW-CCS.On the other hand, the present work filled these gaps as it considered a floating DMTM-GTW-CCU with a

Table 1 .
Design and simulation assumptions.

GTW-CCU System Utilities Demand CW (t/h) LPS (t/h) Power (MW)
* Plant is self-sufficient in terms of electricity, CW and LPS.

Table 4 .
Second Law analysis and lost work validation.
It is worth highlighting that CW is a process stream in the PCS, so it should not be counted as a CW utility (i.e., . EE imported in the compressors and pumps, minus the .W Eq CW produced as hot CW from the compressor intercoolers.There is no LPS consumption ( . .EE in the CW/SW pumps, i.e., .W Eq . .