A technoeconomic analysis of cryogenic recovery of heavy hydrocarbons from LNG using seawater as the heat source

Figures (9) Tables (11)

Figure 1.
Simplest configuration of hydrocarbons recovery during regasification.
Figure 2.
Hydrocarbons recovery from LNG, design 1.
Figure 3.
Hydrocarbons recovery from LNG, design 2.
Figure 4.
Hydrocarbon recovery from LNG, design 3.
Figure 5.
Concentrations of methane and ethane in bottom and overhead streams at different operation pressures in demethanizer for designs 1 and 2.
Figure 6.
Production of ethane at different demethanizer and deethanizer operating pressures.
Figure 7.
Economic performances under three different LNG mass flow rates.
Figure 8.
Economic performances for LNG from different origins.
Figure 9.
Sales prices of natural gas and NGL (graph drawn based on EIA data^[28]).

Hydrocarbon	Composition (mol%)*				Usage
Hydrocarbon	Australia (NWS)	Qatar	Russia (Sakhalin)	USA (Alaska)	Usage
Methane	87.33	90.91	92.53	99.71	Fuel
Ethane	8.33	6.43	4.47	0.09	Fuel, petrochemical feedstock
Propane	3.33	1.66	1.97	0.03	Fuel, coolant, solvent, petrochemical feedstock
Butane	0.97	0.74	0.95	0.01	Fuel, aerosol propellant, petrochemical feedstock
* The values do not add up to 100% as there are other elements in trace quantities. NWS: North West Shelf.

Table 1.

Concentrations and usages of major hydrocarbons in LNG from different origins

Demethanizer		Deethanizer		Heat source	LNG flow (t h^–1)	Profit (mUSD${\bf\$} $ a^–1)	Ref.
P (MPa)	T (°C)	P (MPa)	T (°C)	Heat source	LNG flow (t h^–1)	Profit (mUSD${\bf\$} $ a^–1)	Ref.
3	40	0.11	1	Combustion, seawater	127.2	505.2^a	[20]
2.4	30	0.11	1	Combustion, seawater	127.2	506.8^a	[20]
4.3	20 to 70	0.11	–20 to –35	Combustion, seawater	122.5	7.67^b	[22]
2.4	20 to 70	0.11	–20 to –35	Combustion, seawater	122.5	10.42^b	[22]
3.7	N/A	N/A^c	N/A	Steam	435.7	15	[24]
N/A	N/A	N/A	N/A	Steam, seawater	109.6	24.5	[25]
^a Total revenue, also included further separations of propane from C4+. ^b Converted from CNY to USD by the author. ^c Ethane and C3+ were not further separated.

Table 2.

Summary of LNG fractionation designs

LNG terminal metric	China	Japan
Receiving terminals design capacity (onshore) (MTPA)	94.87	213.48
LNG import in 2021 (MT)	79.3	74.3
Number of receiving terminals	22	33
Receiving terminal design capacity (average) (MTPA)	4.31	6.47
LNG received in 2021 (average per terminal) (MT)	3.6	2.25
MT, million tons; MTPA, million tons per annum.

Table 3.

Scale of LNG receiving terminals in China and Japan^[17]

Hydrocarbon product	Requirement	China	US
Natural gas	Higher heating value	≥ 34.0 MJ m^{–3 a}	37.4–45.3 MJ m^–3[16]
Ethane	C2 liquid composition	–	≥ 95 vol%^c
LPG	Vapour pressure at 37.8 °C	< 1,380 kPa^b	< 1,434 kpa^d
LPG	C3 + C4	> 95 vol%^b	–
^a GB 17820-2018, ^b GB 11174-2011, ^c GPA Standard 2108-14 (2014a), ^d GPA Standard 2140-97.

Table 4.

Typical requirements for sales gas in China and the US

Table 5.

LNG feed conditions

Parameter	Value
Pump/turbine adiabatic efficiency (%)	75
Number of stages in demethanizer	10
Number of stages in deethanizer	10
Tray efficiency (%)	60
Pressure drop in demethanizer (kPa)	10
Pressure drop in deethanizer (kPa)	10
Pressure drop in the heat exchanger (kPa)	20
Maximum temperature of reboilers (°C)	0

Table 6.

A summary of key design parameters

	Design 1	Design 2	Design 3
Optimum operation condition
Demethanizer feed temperature (°C)	–105.22	–106.06	–134
Demethanizer bottom pressure (kPa)	1,690	1,670	1,600
Separator boil-off ratio	–	0.3936	–
Deethanizer pressure (kPa)	380	380	380
Deethanizer reflux ratio	2.34	1.827	1.133
Energy balance
LNG pump duty (kW)	457	448	468
NG pump/compressor duty (kW)	1,023	1,017	8,467
Reboiler heat flow (demethanizer) (kJ h^–1)	8.04 × 10⁷	7.85 × 10⁷	1.56 × 10⁸
Reboiler heat flow (deethanizer) (kJ h^–1)	6.78 × 10⁷	5.68 × 10⁷	4.28 × 10⁷
NG temperature (°C)^a	–80	–83.4	–37.49
Heat for warming NG (kJ h^–1)^a	1.06 × 10⁸	1.19 × 10⁸	2.89 × 10⁷
Mass flow (kg h^–1)^b
Natural gas	276,037	275,596	273,663
Ethane	47,218	47,801	50,218
LPG	36,744	36,601	36,118
Total	360,000	360,000	360,000
Ethane recovery (%)	91.5	92.3	96.4
LPG recovery (%)	93.1	92.8	91.5
^aNatural gas product is warmed to 0 °C before distributing through the pipeline. ^b All products comply with the typical specifications outlined in Table 3.

Table 7.

Optimised operation conditions and simulation results for the three designs

Parameter	Value
Natural gas selling price (USD${\$} $ kg^–1)	0.18
Ethane selling price (USD${\$} $ kg^–1)	0.25
LPG selling price (USD${\$} $ kg^–1)	0.45
Wholesale electricity cost (USD${\$} $ MWh⁻¹)	56.88
Discount rate (%)	3
Equipment lifespan (year)	20

Table 8.

Economic analysis parameters

Table 9.

Economic analysis for the proposed designs

	Design 1	Design 2	Design 3
Installed capital cost
Demethanizer column (mUSD${\$} $)	0.68	0.7	1.34
Deethanizer column (mUSD${\$} $)	0.62	0.56	0.48
Deethanizer condenser (mUSD${\$} $)	0.92	0.89	0.7
Heat exchanger (mUSD${\$} $)	0.14	0.14	−
NG compressor (mUSD${\$} $)	−	−	2.89
Separator (mUSD${\$} $)	−	0.45	−
Total (mUSD${\$} $)	2.36	2.74	5.42
Operations and maintenance cost
Demethanizer (mUSD${\$} $ year⁻¹)	6.1	5.97	12.19
Deethanizer (mUSD${\$} $ year⁻¹)	5.21	4.37	2.86
Heat exchanger (mUSD${\$} $ year⁻¹)	8.57	8.27	−
NG compressor (mUSD${\$} $ year⁻¹)	−	−	6.11
Total (mUSD${\$} $ year⁻¹)	19.89	18.61	21.16

Table 10.

Breakdown of installed capital and operations and maintenance costs

Table 11.

Economic analysis of the proposed designs at the lowest NGL sales prices