Techno-Economic and Environmental Analyses of an Integrated Liquefied Natural Gas/Allam–Fetvedt Cycle/Air Separation Unit Complex

Abstract

The natural gas (NG)-powered compressors/engines used in liquified natural gas (LNG) plants are a major source of methane emission. The Allam–Fetvedt cycle (AFC), an oxyfuel, carbon-neutral, high-efficiency power plant, generates pipeline-grade CO₂. This work performed novel process modeling, economic analysis, and greenhouse gas emissions analysis for a heat-integrated, electrified LNG/AFC/air separation unit (ASU) complex (LAA), then compared it to standalone LNG and AFC/ASU plants (baseline) as well as an LNG plant electrified with AFC/ASU without heat integration. The low-grade heat generated from compressors of the LNG plant can enhance the AFC net power output by 7.1%. Utilizing the nitrogens cold energy reduces the compressor power requirement by 1.6%. In the integrated LAA complex, not only are GHG emissions avoided, but the energy efficiencies are also improved for both the LNG plant and the AFC power plant. A cash flow analysis of LAA was performed over a 20-year period with 5%, 7%, and 10% discount rates and three levels of LNG prices. The 45Q CO₂ credit of USD 85/T as stipulated by the recent Inflation Reduction Act (IRA) of 2022 has been incorporated. The results clearly indicate the economic and environmental benefits of the proposed electrification and heat/power integration.

1. Introduction

The liquefied natural gas (LNG) supply chain contains oil and gas exploration, gas treatment, liquefaction, shipping, regasification, and marketing distribution. The natural gas (NG) liquefaction process plays a significant role in transporting natural gas over long distances from different regions.

The LNG liquefaction system in this report is the propane precooled mixed refrigerant process (C3MR), which involves precooling of natural gas using a propane refrigeration loop followed by subcooling and liquefaction in the second loop using a mixed refrigerant composed of methane, ethane, and propane, as shown in Figure 1. The modeling of a typical propane/mixed refrigerant (C3MR) LNG is shown in Figure 2 [1,2,3,4,5,6,7,8,9,10,11,12,13,14,15].

The Allam–Fetvedt cycle (AFC) is an oxy-combustion, carbon-neutral, high-efficiency (approximate 59%) super-critical CO₂ Brayton power cycle operated at elevated temperatures (up to 1050 °C) and pressures (between 30 and 300 bar). The exhaust CO₂ is captured during the process and recycled as system working fluid. The excess high-pressure CO₂ is sent to the pipelines for sequestration or utilization [16,17,18,19,20,21].

Liquified natural gas (LNG) plants use natural gas (NG)-powered compressors to run the refrigeration train, which emits methane, CO₂, nitrous oxide (N₂O), nitrogen oxides (NOx), and PM (soot). It is worth noting that SOx emissions are usually not an issue for the LNG plants since natural gas (sales gas) feed has been desulfurized (S content < 5 mg/m³) [22,23,24,25,26,27,28,29,30,31,32,33]. Among the above-mentioned emissions from the LNG facilities, methane emissions have gained most attention recently. Methane emissions (from various sources) contributed to about one-third of the current anthropogenic temperature rise and undermine the claim that natural gas is a clean energy. As can be seen in Figure 3, natural gas processing and petroleum production contribute significantly to US methane emissions, so the system and methods to reduce methane emissions from the LNG operations is a timely effort. Methane emissions include fugitive, vent, and flare emissions from natural gas-fired engines/turbines, storage tanks, and piping systems [22,29,33]. LNG companies plan to cut greenhouse gas (GHG) emissions and electrification is the top priority for achieving decarbonization. Electric motors are much more efficient (>95%) than the internal combustion engine (ICE, <50%). They are also lightweight, smaller, can provide instant and consistent torque, and do not emit carbon into the atmosphere. For these reasons, electric motors are replacing internal combustion in transportation and industry. Electrification has become an important tool to decarbonize NG liquefaction operations as it may increase the reliability of the equipment in addition to reducing methane emissions [4,7,15,33]. Companies intend to electrify LNG operations to minimize methane emissions and potentially CO₂ emissions if the carbon intensity of electricity is below 600 metric tons of carbon dioxide equivalent per gigawatt hour (t CO_2e/GWh) [25,26]. The carbon intensity qualifier for electricity is important as the power generation can come from either renewable wind, solar, biogas, or carbon-free nuclear, low-carbon natural gas, or even carbon-intensive coal-fired power plants. In other words, the benefit of electrification actually depends on the carbon intensity of the mix of electrical power sources. However, without considering methane emissions, the availability of cheap natural gas dictates the choice of compressors, i.e., whether the use of electric compressors or natural gas-powered compressors is economically more favorable. One of the novel features of this work is to replace natural gas-powered compressors in the LNG operations with electric compressors powered by the carbon-neutral AFC.

Greenhouse gas emissions in natural gas liquefaction operations come from the combustion of natural gas in heaters, flares, and most importantly, engines/turbine-driven compressors. Environmental performance was compared in terms of GHG emission reduction. Economic performance was evaluated in terms of capital investment, operating cost, payback period, net present value, and internal rate of return with a 45Q tax credit.

No prior work on such an integration between an LNG facility and the Allam–Fetvedt cycle (AFC) was found in the literature. The reason is that high-efficiency, carbon-neutral AFC power generation is fairly new. The demonstration plant in La Porte, TX, achieved its first fire in 2018 and connected to the Texas grid in 2021. This paper is believed to be the first of its kind to show the benefits of such an integration. This paper analyzes not only the technical/economic side to show the improvement in energy efficiencies and profitability but also the benefits of reducing greenhouse gas emissions (especially methane).

2. Methodology

2.1. Heat and Power Integration

The material and energy integration of the Allam–Fetvedt cycle, air separation unit (ASU), and LNG among the three subsystems (shown in Figure 4) was modeled with Aspen Plus [34], and the important aspects are listed below [12,18,19]:

o

An air separation unit (ASU) supplies pure oxygen to the power plant and nitrogen cold energy for precooling of the natural gas feed for the LNG plant.

o

The power plant subsystem is the natural gas empowered complex, which includes an oxy-combustion power plant driven by the Allam–Fetvedt cycle to generate net power and pure CO₂ for commercial utilization. The power generated from the Allam–Fetvedt cycle can also be utilized for ASU/LNG compressors.

o

An LNG plant relies on power supplied by the AFC and supplies extra heat to the AFC combustor/turbine. The low-grade heat (122–126 °C) from LNG compressors lifts the net power of the Allam–Fetvedt cycle/ASU by increasing the recycle oxidant and CO₂ stream temperatures.

2.2. Economic Analysis Using Aspen Process Economic Analyzer and General Investment Evaluation Tools

2.2.1. Aspen Process Economic Analyzer (APEA)

Aspen Process Economic Analyzer (APEA), a subsystem of Aspen Plus, was used to conduct the economic analysis to evaluate the financial viability of the integration. APEA provides economic analysis including total capital cost, total operating cost, total raw material cost, and total product sales. The price data of compressors, recuperators, electricity, natural gas, and LNG were obtained from the open literature [1,5,13,17,28].

We further investigated several investment evaluation tools: net present value (NPV), payback period (PBP), internal rate of return (IRR), and cash flow [28,29,30,31,32,33,34,35,36,37,38]. These tools are detailed below.

2.2.2. Net Present Value (NPV)

The NPV is a fundamental financial metric used for investment appraisal. It measures the profitability of a project or investment by assessing the difference between the present value of expected cash inflows and the present value of cash outflows over the investment’s time horizon. A positive NPV, as shown in Equation (1), indicates a potentially profitable investment, while a negative NPV suggests that the investment may not be financially viable [28,29,30].

$$\mathbf{N}\mathbf{P}\mathbf{V}={\sum }_{\mathit{t}=\mathbf{0}}^{\mathit{n}}\frac{{\mathbf{R}}_{\mathbf{t}}}{{\left(\mathbf{i}+\mathbf{1}\right)}^{\mathbf{t}}}$$

(1)

where R_t = Net cash flow (in–out flows) during a single period t;

i = discount rate;

t = number of time periods.

2.2.3. The Payback Period (PBP)

The PBP method is widely used and considered an important, and traditional method for capital budgeting or investment decision-making [38,39,40,41,42,43]. PBP is a superior performance appraisal method because it gives a more accurate approximation even with the non-uniform future cash flows, which is more likely in the real business world [41,42]. The PBP method is a simplistic method of looking at the investment ideas and finding out the time period by which the project will earn back the investment for the investors. PBP is determined based on the cumulative net cash flow over the duration of the project. It is the point in time when the running total of net cash flow becomes positive, signifying that the investment has been paid back in full:

• Calculate the cumulative net cash flow for each year. Start from the beginning of the project and sum the net cash flows up to that year.
• Identify the latest year, denoted as “n”, when the cumulative net cash flow becomes positive. This year is when the investment has been fully recovered.
• To determine the exact point in the latest year n when the remaining original investment is paid back, use the following formula:

Exact Time in Year n = (Original Investment − Cumulative Net Cash Flow at the end of Year n-1)/Net Cash Flow in Year n

(2)

In this formula,

• “Exact Time in Year n” indicates the precise moment in the latest year when the investment is fully recovered;
• “Original Investment” represents the initial capital invested in the project;
• “Cumulative Net Cash Flow at the end of Year n-1” is the cumulative cash flow at the end of the previous year (n-1); and
• “Net Cash Flow in Year n” is the cash flow for the latest year (n).

2.2.4. Internal Rate of Return

The internal rate of return (IRR) is a financial metric employed to assess the potential profitability of investments. It represents the discount rate at which the sum of the present values of all cash flows becomes zero at the end of the project period in a discounted cash flow analysis, helping determine the attractiveness of an investment opportunity [44,45].

2.2.5. Cash Flow

Cash flow tables similar to those provided by Chaturvedi et al. [14] were constructed for a project period of 20 years. These tables provide details of design capacity, sales, capital costs, working capital, total operating cost, depreciation, taxable income, taxes, CO₂ credit, net earnings, cash flow, net present value (NPV), and earnings before interest, taxes, depreciation, and amortization (EBITDA). Cash flow curves were also generated to show the cash flow changes over the period.

2.3. Greenhouse Gas (GHG) Emission Analysis

The CO₂ and methane emission factors were obtained from the US EPA and industrial reports. The greenhouse gas emissions were estimated based on the CO₂ emission factor for the natural gas-powered turbine = 540 kg/MWh, CH₄ emission factor for the LNG plant compressors = 0.240 scf/(hp*h), 90% utilization rate, natural gas simple cycle (NGSC) efficiency of 36%, and 100-year global warming potential (GWP) of methane = 28 [1,3,11,14,22,24,26,27,29,30,31,32,33].

3. Results and Discussion

3.1. LNG Plant Operating Data (Base Case)

The base case is a standalone LNG plant and a standalone AFC plant with its associated air separation unit (ASU).

Table 1. NG feed stream composition.

NG Feed Stream Composition
	Mass Flow (kg/h)	Mole Flow (kmol/h)
METHANE	480,000	29,920.039
ETHANE	36,000	1197.221
PROPANE	12,000	272.13
BUTANE-N	6000	103.229
BUTANE-I	6000	103.229
PENTAN-N	3000	41.58
PENTAN-I	3000	41.58
NITROGEN	24,000	856.73
H2O	30,000	1665.253

gives the component flow rates of the natural gas feed stream, a typical gas sold in the US that is free of contaminants such as H₂S and CO₂.

Table 2. MR feed stream composition.

MR Feed Stream Composition
	Mass Frac %	Mole Frac %
METHANE	0.243	0.4
ETHANE	0.399	0.35
PROPANE	0.251	0.15
NITROGEN	0.106	0.1

provides the composition of the mixed refrigerant (MR) stream typical for the Air Products AP-C3MR process. The process conditions are based on the ones described by Ravavarapu et al. [10]. The specifications used for propane/MR cycle heat exchangers and compressors are listed in

Table 3. Input specification for propane/MR cycle heat exchangers and compressors.

Name	HX11		HX12	HX13	HX21	HX22
Exchanger specification	20		0	−34	0	−34
Hot side outlet pressure [bar]	−0.1		−0.1	−0.1	−0.1	−0.1
Cols side outlet pressure [bar]	−0.1		−0.1	−0.1	−0.1	−0.1
Inlet hot stream temperature [C]	25		19.95	0	20	0
Outlet hot stream temperature [C]	20		0	−34	0	−34
Inlet cold stream temperature [C]	18.35		−3.11	−36.35	−3.11	−36.34
Outlet cold stream temperature [C]	17.88		−3.86	−38.26	−3.86	−38.26
Heat duty [Gcal/h]	1.93		6.89	11.58	32.14	60.57
Name	CMP-11	CMP-12	CMP-13	CMP-21	CMP-22	CMP-23
Model Type	Isentropic	Isentropic	Isentropic	Isentropic	Isentropic	Isentropic
Specified discharge pressure [bar]	4.2	8	12	5	14	42
Mechanical efficiency	0.9	0.9	0.9	0.9	0.9	0.9
Net work required [kW]	29,015.92	23,178.64	15,617.68	64,604.99	64,888.02	57,336.89
Calculated pressure ratio	3.81	1.90	1.52	4.17	3.01	2.79
Outlet temperature [C]	22.71	45.57	61.28	50.92	125.84	122.40

. The stream data including temperature, pressure, flow, and enthalpy are given in

Table 4. Major stream results for the base case.

Stream ID	Temperature °C	Pressure Bar	Mass Enthalpy kcal/kg	Mass Flows kg/h
NG	25.00	50.00	−1158.13	600,000.00
NG-O-X11	20.00	49.90	−1161.34	600,000.00
DRY-NG	19.96	49.80	−1023.69	570,430.30
NG-O-X12	0.00	49.70	−1035.76	570,430.30
LIGHT-NG	0.00	49.70	−1063.66	528,539.29
NG-O-X13	−34.00	49.60	−1085.57	528,539.29
PURE-NG	−34.00	49.60	−1120.87	505,261.70
LNG-MCHX	−112.00	49.30	−1239.60	505,261.70
LNG	−161.00	49.00	−1281.83	505,261.70

.

3.2. Precooling of Natural Gas Feed with Cold Nitrogen Stream from ASU

The prior work from this group (Shetty, 2020) incorporated a cold nitrogen stream from the air separation unit (ASU) associated with the Allam power plant, making use of its available cold duty for the precooling of the natural gas feed in the propane precooling cycle of the LNG plant. Different types of scenarios were modeled using Aspen Plus and analyzed based on heaty duty, compressor work, and cost.

From the base case, a two-stage cooling chain including booster heat exchangers B1 and B3 is added for enhanced utilization of the cold N2 energy as shown in Figure 5.

The scenario of integrating cold N₂ stream from the ASU with an LNG plant is compared to the base case with no N₂ precooling. The booster heat exchanger duties are given in

Table 5. Booster heat exchanger heat duties for the precooling of NG.

	Booster HX Duty
HX Duty	B1	B3	GCal/h	MW
Base Case	0.00	0.00	0.00	0.00
Integrated	3.42	3.28	6.70	7.79

. The total compressor power inputs required to operate the C3 and MR cycles are presented in

Table 6. Total compressor work required to run both C3 and MR cycles.

		Total Compressor Work
Total Work	MW	ΔΜW	ΔGcal/h
Base Case	254.64	0.00	0.00
Integrated	251.18	3.46	2.97

. The Aspen Plus process flow diagrams (PFDs) for the ASU and AFC (with and without N₂ precooling) are shown in Figure 6, Figure 7 and Figure 8.

As can be seen, the integrated case has a higher booster heat exchanger heat duty and a lower compressor power requirement. It also indicates that roughly half of the precooling heat duty is converted to compressor power savings (2.97 Gcal/h/6.70 Gcal/h = 3.46 MW/7.79 MW = 44.5%).

Table 7. LNG MR compressor aftercooler heat duties utilized for the Allam recuperator.

Aftercooler	HT-MRCL2	HT-MRCL3
Q Gcal/h	55	58
T begin °C	126	122
T end °C	40	40

provides the compressor aftercooler duties of the C3/MR cycle. These duties can be utilized for the recuperator in the AFC, especially with the total amounts of heat duties coming from the MR cycle (MR-COOL1, MR-COOL2, and MR-COOL3). The heat integration of the MR cycle and recuperator will increase the efficiency of the AFC, which can be calculated based on the Allam subsystem’s current efficiency.

3.3. LNG Heat from MR Compressors for the Allam–Fetvedt Cycle Recuperator

The heat generated from mixed refrigerant compressors CMP-22, -23, (i.e., cooler duties of MRCooler-2 and -3) in Figure 2 can be added to the AFC recuperator to raise the enthalpies of streams back to the combustor (Stream 9 recycled CO₂ and Stream 13 recycled oxidant CO₂+O₂). These heat sources as given in Table 7 are used to increase the AFC’s thermal efficiency.

The AFC cycle recuperator is simulated as a series of three multi-stream heat exchangers: RECU, HX2, and HX3. In the base case, no LNG heat is supplied to the Allam–Fetvedt cycle HX3, so the ASU heat of 50 Gcal/h is added to HX2. In the improved case, HX3 utilizes the low-grade heat (26 Gcal/h, ~125 °C) from the aftercoolers’ (MR-COOL2 and MR-COOL3) heat duties of LNG mixed refrigerant compressors (CMP-22 and 23), as shown in Figure 4. Only a fraction (~19%) of the low-grade heat from the LNG compressors can be utilized in the Allam recuperator to raise the recycled oxidant (a mix of O₂ and remainder CO₂) and recycled CO₂ from ~40 °C to ~125 °C. Then, the heat from the ASU air compressor is used in HX2 to further raise the temperature of the recycle streams to ~300 °C. The net power of the AFC is increased from 395 MW to 423 MW by increasing the NG flow to the combustor section from 36,000 kg/h to 52,800 kg/h. Simultaneously, the air flow for the ASU is increased from 917.5 T/h to 1347 T/h, which results in an increase in O₂ flow from 144,145 kg/h to 211,622 kg/h.

3.4. Energy Efficiency Improvement

The compressor work in the LNG operation is reduced from 255 MW to 251 MW, or by roughly 1.6%, due to the precooling of incoming NG with the nitrogen (N2) stream from the ASU. On the other hand, the net power from the AFC is increased from 395 MW to 423 MW, or an increase of 7.1%, due to the utilization of the waste heat from the LNG MR cycle compressors.

The overall energy efficiency improvement from the standalone LNG and AFC/ASU units to fully integrated LAA complex based on the same natural gas consumption is 8.8% (=1.071/(1 − 0.016) = 1.088). The AFC/ASU power output is increased by 7.1%, while the compressor power requirement is reduced by 1.6%.

3.5. Economic Analysis for Heat Integration between LNG and AFC/ASU Plants

Within this report, we present three distinct scenarios: the base case, an electrified LNG plant, and a heat and power integration among LNG/AFC/ASU.

• Base case: This case portrays a standalone LNG plant and a standalone ASU/AFC operating independently, devoid of electrification or heat integration.
• Electrified case: In this scenario, an LNG plant is energized by the ASU/AFC plant, i.e., the natural gas simple cycle (NGSC) power plant in the LNG is replaced by the AFC. In addition, all natural gas-powered compressors are replaced by electric compressors.
• Integrated case: In this scenario, power is procured from the ASU/AFC system, and conversely, surplus heat (26 Gcal/h) from the LNG plant is channeled into the ASU/AFC system. This integration leads to an enhancement in the power generation capacity of the ASU/AFC, elevating it from 395 MW to 423 MW. Also, cold N₂ from the ASU/AFC plant is used to precool the incoming NG before refrigeration, resulting in reciprocal benefits for both facilities.

Table 8. Economic analysis for the base case (standalone ASU/AFC and standalone LNG plant).

	ASU/AFC	LNG	Overall
Total Capital Cost (MMUSD)	950	4253	5203
Total Operating Cost (MMUSD/Year)	332	1329	1661
Total Cost of Raw Materials (MMUSD/Year)	74	1039	1113
Total Product Sales (MMUSD/Year)	1403	2752	4155

MMUSD: USD million.

,

Table 9. Economic analysis for an LNG plant electrified with an ASU/AFC complex.

	ASU/AFC	Electrified LNG	Overall
Total Capital Cost (MMUSD)	950	3623	4573
Total Operating Cost (MMUSD/Year)	332	1204	1536
Total Cost of Raw Materials (MMUSD/Year)	74	914	988
Total Product Sales (MMUSD/Year)	1403	2752	4155

and

Table 10. Economic analysis for the LNG/AFC/ASU complex with heat/power integration.

LNG/AFC/ASU	Heat-Integrated ASU/AFC	Electrified/Heat-Integrated LNG	Overall
Total Capital Cost (MMUSD)	953	3634	4587
Total Operating Cost (MMUSD/Year)	339	1200	1539
Total Cost of Raw Materials (MMUSD/Year)	74	914	988
Total Product Sales (MMUSD/Year)	1436	2752	4188

provide economic analysis including total capital cost, total operating cost, total raw material cost, and total product sales for the base case, electrified case (LNG plant is electrified with electricity from the AFC+ASU complex), and an electrified case with fully heat-integrated LNG+AFC+ASU complex. It can be seen from

Table 11. Comparison of the costs and revenues due to low-grade heat integration.

	MMUSD
Total Capital Cost Increase (one time)	14
Total Operating Cost Increase per Year	3
Total Sales Increase per Year	33

that the heat integration increases the total capital cost by USD 14 million (one time) and the total operating cost by USD 3 million/yr, but the total product sales also go up by USD 33 million/yr. The product sales from AFC/ASU include only surplus electricity and N₂.

The total capital costs include the refrigeration train (natural gas-powered/electric compressors, aftercoolers, heat exchangers) in the LNG plant, the natural gas compressors, the combustor/turbine unit, and the recuperator in the Allam–Fetvedt power plant, and air compressors, O₂ compressors, and high-pressure column, and low-pressure column in the air separation unit. The operating cost includes natural gas feed, natural gas for running the AFC plant, and the natural gas simple cycle in the LNG plant, workforce to run the plants, and maintenance costs. The equipment cost bases and index to inflation are obtained from various sources [1,17,46,47,48,49,50,51]. The revenues include sales of LNG, nitrogen, and electricity.

The increase in capital cost for integrated LAA complex arises from the installation and operation of the duct connection (between the LNG compressor aftercoolers and the Allam–Fetvedt cycle recuperator, 1000 m) and 50 fans (30”, 100 BHP) for transporting hot air.

The operating cost is lower due to increased energy efficiency, i.e., the LAA complex consumes less natural gas to power the Allam–Fetvedt cycle in the integrated LNG/AFC/ASU complex.

Selection of the three LNG prices is based on the LNG contract/spot prices data from the past 10 years. The spot price spiked to USD 59/MMBtu in Asia on 4 March 2022 [50,51].

In

Table 12. Comparison of net present value (NPV) and payback period (PBP) for a 7% discount rate.

LNG Sale Price USD/MMBtu	Discount Rate of 7%
	Standalone LNG		Base Electrification		Further Heat Integration
	NPV (MMUSD)	PBP (Years)	NPV (MMUSD)	PBP (Years)	NPV (MMUSD)	PBP (Years)
6.45	−23.3	10.73	12,608.5	3.19	12,891.4	3.16
11.1	9850.7	3.55	22,479.5	2.21	22,762.4	2.20
35.5	52,092.7	1.29	76,074.3	1.07	76,357.2	1.07

NPV = net present value at the end of 20 years of operation; PBP = payback period.

, the NPV and PBP values are compared for the above three cases for a 7% discount rate and three different LNG sale prices. Also, for integrated LNG/AFC/ASU plant the cash flow analysis over 5%, 7%, 10% discount rates is done with both high (USD 35.5/MMBtu), medium (USD 11.1/MMBtu), and low (USD 6.05/MMBtu) LNG prices, the comparison is shown in

Table 13. Comparison of net present value and payback period for integrated LNG/AFC/ASU for three discount rates.

LNG Sale Price USD/MMBtu	Integrated LNG/AFC/ASU
	5%	7%	10%	PBP (Years)
	NPV (MMUSD)	NPV (MMUSD)	NPV (MMUSD)
6.45	16,106.8	12,891.4	9462.5	3.16
11.1	27,790.7	22,762.4	17,172.5	2.20
35.5	91,225.6	76,357.2	59,824.1	1.07

and a pictographic representation in Figure 9a–c.

IRR for the Base case is 29%, whereas for electrification from the Allam–Fetvedt cycle is 48.76% and the fully integrated (power + heat integration) case is 49.10%,

Table 14. Internal rate of return for 3 LNG prices.

	Internal Rate of Return
Price of LNG	USD 6.45	USD 11.1	USD 35.5
Standalone LNG	6.93	29%	96.96
Base Electrification	32.38	48.76%	125.59
Further Heat Integration	32.81	49.10%	125.66

.

In Figure 10, cash flow curves are displayed for all 3 plant configurations with a medium LNG sale price of USD 11.1/MMBtu and a 7% discount rate for a project period of over 20 years.

Table 15. Cash flow summary for the integrated LNG/AFC/ASU.

Years	% Design Capacity	Sales, MMUSD	Capital Costs, MMUSD	Working Capital, MMUSD	Total Op. Costs, MMUSD	Depreciation, MMUSD	Taxable Income, MMUSD	Taxes, MMUSD	CO2 Credit (USD/T CO2)	CO2 Credit, MMUSD	Net Earnings	Cash Flow, MMUSD	EBITDA, MMUSD	NPV, MMUSD
0	0	0	4587	45.87	0	0.0	0.0	0.0	0	0.0	0.0	−4587.0	0.0	−4587.0
1	50	2094	0	22.935	769.5	0.0	1324.5	30.5	40	51.4	1345.4	1345.4	1375.9	−3329.6
2	100	4188	0	22.935	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	−972.3
3	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	1230.8
4	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	3289.8
5	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	5214.0
6	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	7012.4
7	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	8693.1
8	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	10,263.9
9	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	11,731.9
10	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	13,103.9
11	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	14,386.1
12	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	15,584.4
13	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	16,704.4
14	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	17,751.1
15	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	18,729.2
16	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	19,643.5
17	100	4188	0	0	1539	69.1	2579.9	59.3	85	109.2	2629.7	2698.9	2758.2	20,497.8
18	100	4188	0	0	1539	0.0	2649.0	60.9	85	109.2	2697.3	2697.3	2758.2	21,295.9
19	100	4188	0	0	1539	0.0	2649.0	60.9	85	109.2	2697.3	2697.3	2758.2	22,041.7
20	100	4188	0	91.74	1539	0.0	2649.0	60.9	85	109.2	2697.3	2789.0	2758.2	22,762.4

provides the detailed cash flow analysis for the integrated LNG/AFC/ASU plant configuration. Detailed costs, revenues, taxes, 45Q carbon credit, cash flow, net earnings, and net present value (NPV) are presented for a 20-year period.

3.6. Estimated Greenhouse Gas Reduction

The total CO₂ emissions from the standalone LNG plant are 1.96 × 10⁶ T/yr. The 100-year global warming potential of methane is set as 28. This is shown in

Table 16. Summary of greenhouse gas (GHG) emissions from the standalone LNG plant.

GHG Emissions, T/yr
	CO2	CH4	CO2e
Compressors	1.09 × 106	1.02 × 104
NGSC	4.61 × 105	4.74 × 103
Total	1.55 × 106	1.49 × 104	1.96 × 106

. These calculations are based on the CO₂ emission factor for the natural gas-powered turbine = 540 kg/MWh, CH₄ emission factor for the LNG plant compressors = 0.240 scf/(hp*h), 90% utilization rate, and natural gas simple cycle (NGSC) efficiency of 36%. The GHG emissions from the standalone LNG are estimated to be 1.96 × 10⁶ T/yr.

Electrification of the LNG plant with an AFC/ASU helps avoid the CO₂ emissions of 1.96 × 10⁶/yr and also captures 1.27 × 10⁶ T/yr of the CO₂ by AFC/ASU power generation, as shown in

Table 17. GHG emissions captured from the zero-emission AFC/ASU.

GHG Emissions, T/yr
	CO2	CH4	CO2 Captured
AFC/ASU	0.00	0.00	1.27 × 106
Total	0.00	0.00	1.27 × 106

. Also, the estimated CO₂ emissions avoided for the AFC plant due to LNG compressors heat integration are 4.22 × 10⁴ T/yr. The estimated CO₂ emissions avoided due to N₂ precooling heat integration for the LNG plant are 9.12 × 10³ T/yr. Thus, the total CO₂ emissions avoided due to heat integration of the LNG plant and AFC/ASU are 5.13 × 10⁴ T/yr or 2.6% of the standalone LNG emissions, as shown in

Table 18. Summary of greenhouse gas (GHG) emissions avoided after heat integration.

GHG Emissions, T/yr				% Reduction
	CO2	CH4	CO2e
LNG Heat	4.22 × 104	0.00	4.22 × 104	2.2
N2 Cooling	9.12 × 103	0.00	9.12 × 103	0.5
Total	5.13 × 104	0.00	5.13 × 104	2.6

Note: T = metric ton.

.

4. Conclusions

The following conclusions can be drawn from this study:

o

The integration of a 5.3 million ton per annum (MTA) liquefied natural gas (LNG) plant with a 52.8 T/h NG Allam–Fetvedt Cycle (AFC) power plant and an associated air separation unit (ASU) has been modeled with Aspen Plus V. 11.

o

The heat integration of an LNG/AFC/ASU complex (LAA) provides two types of energy benefits: (1) use of the cold stream from the ASU to precool the NG feed to the LNG plant; (2) addition of low-grade waste heat from mixed refrigerant compressors to the AFC recuperator to raise the Allam–Fetvedt cycle net power.

o

The compressor work in the LNG operation is reduced from 255 MW to 251 MW, or by roughly 1.6%, due to the precooling of incoming NG with the nitrogen (N₂) stream from the ASU.

o

The net power from the AFC is increased from 395 MW to 423 MW, or an increase of 7.1%, due to the utilization of the waste heat from the LNG MR cycle compressors.

o

The overall energy efficiency improvement from the standalone LNG and AFC/ASU units to the fully integrated LAA complex based on the same natural gas consumption is 8.8%.

o

Detailed cash flow analysis has been carried out for a standalone LNG plant, an electrified LNG plant with AFC/ASU power, and an integrated Allam–Fetvedt cycle and LNG plant (with N2 heat exchange and 26 Gcal/h low-grade heat use in AFC). The 45Q CO₂ credit of USD 85/T as stipulated by the recent Inflation Reduction Act (IRA) of 2022 has been incorporated.

o

The net present value (NPV) and payback period (PBP) as a function of LNG price and 7% discount rate are presented. The internal rate of returns (IRRs) are compared for three different plant integration scenarios as well as three different LNG price levels.

o

The estimated CO₂ emissions avoided are 4.22 × 10⁴ T/yr due to the utilization of 26 Gcal/h LNG heat from compressors. The estimated CO₂ emission avoided is 9.12 × 10³ T/yr from precooling of NG by N₂. The CO₂ emissions avoided are 2.6% by these heat integrations. The amount of CO₂ captured by AFC/ASU is 1.27 × 10⁶ T/yr.

o

The overall greenhouse gas emission reduction from electrification and the full heat/power integration among the LNG, AFC, and ASU (LAA) complex is 1.96 × 10⁶ T/yr CO₂e compared to the base case.

o

The results clearly indicate the economic and environmental benefits of the proposed electrification and heat/power integration.