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Original article
A techno-economic assessment of the liquefied natural gas (LNG)
production facilities in Western Canada
Ratan Raj
a
, Ravi Suman
b
, Samane Ghandehariun
a
, Amit Kumar
a,
⇑
, Manoj K. Tiwari
b
a
Department of Mechanical Engineering, University of Alberta, Edmonton, Alberta T6G2G8, Canada
b
Department of Industrial and Systems Engineering, Indian Institute of Technology, Kharagpur 721302, India
article info
Article history:
Received 10 September 2015
Revised 13 October 2016
Accepted 24 October 2016
Keywords:
Natural gas
Liquefied natural gas
Natural gas processing
Liquefaction
abstract
The availability and low cost of natural gas in North America open the possibility of transporting it to
places where there is significant demand. Natural gas can be transported long distances as liquefied nat-
ural gas (LNG). In this paper, data-intensive techno-economic models were developed to assess LNG pro-
duction costs in Western Canada. A two-train (each with an annual natural gas liquefaction capacity of 5
million tons) LNG plant is designed in the context of anticipated LNG export facilities in British Columbia,
Canada. The plant equipment parameters and costs were estimated using a data-intensive bottom-up
cost calculation methodology. Cost correlations linking the equipment’s design parameters to the equip-
ment’s installed cost were developed and overall costs assessed. The total installed cost of the plant
equipment is about US$1.9 billion. Considering a $1200/tpa capital expenditure, a 12% discount rate,
and a 25-year plant life, the total product (LNG) cost is $7.8/GJ, if the gas supply source is Montney,
and $9.1/GJ, if the gas supply source is Horn River. The delivery cost of Canadian LNG to Asia was esti-
mated and a sensitivity analysis conducted. Total liquefaction cost is influenced most by the LNG facility
capital expenditure, gas supply cost, and the discount rate.
Ó2016 Elsevier Ltd. All rights reserved.
Introduction
The emergence of advanced fracturing and well drilling tech-
nologies coupled with the development of unconventional natural
gas resources in Western Canada have opened up new opportuni-
ties and redefined the Canadian natural gas market. Recent esti-
mates show that there are potentially 632 trillion cubic feet (tcf)
of natural gas in the Western Canadian Sedimentary Basin, which
is equivalent to 145 years of Canada’s 2012 consumption of 3 tcf
[1]. The emergence of advanced fracturing and well drilling tech-
nologies coupled with the development of unconventional natural
gas resources have created export opportunities for natural gas
producers in Canada, especially when the anticipated Canadian
production exceeds the domestic consumption requirement.
Currently the U.S. is Canada’s only natural gas export client and
due to the development of unconventional sources of natural gas in
U.S., Canada’s net export of natural gas to U.S. is declining [2]. The
net pipeline imports of natural gas from Canada to the U.S. have
declined to around 158 billion cubic feet (bcf) in 2014 from 289
bcf in 2000 [3]. This decline has left Canada with LNG as the only
other gas export alternative.
The Asia-Pacific region is a lucrative market for Canadian LNG
producers for several reasons. First, natural gas prices in Canada
are substantially lower than the Asia-Pacific region. Average well-
head/city gate prices of natural gas in British Columbia, Canada, are
around $4.7 per gigajoule [4], which is lower than Asian prices
($15–16 per gigajoule) [5]. This price differential creates opportu-
nities for profit for Canadian natural gas companies investing in
developing LNG facilities. Second, Asia’s regional share of global
demand for natural gas has increased from 13 to 19% and overall
consumption has nearly doubled in the past decade [3,6], making
the Asia-Pacific region the most significant region in international
LNG trade. At the same time, the gap between demand and supply
of natural gas is increasing due to the lack of sufficient hydrocar-
bon reserves, thereby increasing Asia’s reliance on LNG and pipe-
line imports [7]. These developments, coupled with relatively
high growth in electricity consumption and declining domestic fos-
sil fuel energy, have made the Asia-Pacific region highly dependent
on LNG imports to satisfy their energy requirements in near future
[7].
Japan is the world’s largest importer of liquefied natural gas [6]
and its import volume is expected to increase from 3.18 trillion
cubic feet (tcf) in 2009 to 4.0 tcf by 2035 [3]. The 2011 Fukushima
nuclear power disaster, contributed somewhat to this increase. In
order to achieve a reliable supply of LNG and to gain better control
http://dx.doi.org/10.1016/j.seta.2016.10.005
2213-1388/Ó2016 Elsevier Ltd. All rights reserved.
⇑
Corresponding author.
E-mail address: amit.kumar@ualberta.ca (A. Kumar).
Sustainable Energy Technologies and Assessments 18 (2016) 140–152
Contents lists available at ScienceDirect
Sustainable Energy Technologies and Assessments
journal homepage: www.elsevier.com/locate/seta
of LNG prices, policy makers in Japan are intent on diversification
of sources of LNG [6]. Australia, Russia, Malaysia, and Qatar are
the main LNG suppliers to Japan [6,8]. For its LNG supply, China
has largely relied on Australia since it began importing LNG in
2006. Australia contributed to around 80% of China’s LNG import
between 2006 and 2008 [6]. Similar to Japan, China has also
focused on diversification of its LNG suppliers and imported
around 10% of its LNG from each of Malaysia, Qatar, and Indonesia
in 2010 [6].
As a result of this diversification, Australia’s share in China’s
LNG imports dropped to less than 25% in 2012 [3]. Despite this
drop, Australia is still China’s largest source of imported LNG. In
May 2014, Russia and China announced a new gas pipeline deal
that would include shipments of 1.3 trillion cubic feet of gas to
China over 30 years [9]. India’s natural gas import scenario is com-
parable. Since 2004, India has seen an annual growth of 36% in its
LNG imports and the Indian government is focusing on diversifica-
tion and, to that end, signed deals with the U.S. and Australia in
2011 and 2009, respectively [3].
With an export capacity of around 77 million tons per year,
Qatar is the world’s largest producer and supplier of global LNG
[9] and meets around one-third of global demand [10]. Australia
ranks second in the list of LNG suppliers, but exports of LNG are
expected to grow substantially in the coming years [9]. This is
mainly because Australia currently has a large number of LNG
export projects under construction [11]. Algeria, Malaysia, and
Indonesia are Australia’s strong competitors [8]. As discussed
above, since all the three major Asian countries wish to diversity
their LNG imports, Canada has a potential export market for its
processed natural gas. Given that Asia’s overall consumption of
natural gas is expected to increase [12] and that Canada’s natural
gas prices will likely stay at their current level, there is good poten-
tial for Canadian natural gas producers. Moreover, political stabil-
ity within Canada leading to a reliable supply of LNG can help
Asian countries to build long-term LNG export contracts with
Canada. Currently, most of the proposed liquefaction projects in
Western Canada are undergoing a detailed study of construction
costs to check the feasibility of the entire project. The unavailabil-
ity of these studies in the public domain suggests an immediate
need to conduct a detailed techno-economic study focusing on
the cost estimates of Canadian liquefaction projects. However, as
of now, there are no studies that focus on overall natural gas lique-
faction costs in Canada. Most of the studies on natural gas liquefac-
tion projects in literature pertaining to geographical regions other
than Canada. Javanmardi et al. [13] estimated the total cost of nat-
ural gas liquefaction and shipping of LNG from the South-Pars gas
fields in Iran to the world market. Other studies focus on the techo-
economic analysis of different processes like gas-sweetening,
dehydration, and natural gas liquid (NGL) recovery in an LNG plant.
Lars Peters et al. [14] did a detailed technical and economic analy-
sis of gas sweetening processes for natural gas with amine absorp-
tion and membrane technology. In this study, a simulation analysis
with Aspen HYSYS for amine absorption and a membrane model
interfaced within Aspen HYSYS was performed for different feed
gas cases. Further, an economic analysis was conducted to evaluate
gas processing costs and the total capital investment cost. Getua
et al. [15] investigated the different process schemes used for
known NGL recovery methods under variations of feed composi-
tions with respect to their economic performance. Netusil et al.
[16] compared the costs of three different natural gas dehydration
processes that are widely used in the natural gas industry. The
comparisons were made based on the process’s energy demand
and suitability for use. To address these gaps in academic literature
and present a novel contribution, in this paper, a detailed economic
analysis of the various process equipment used in an LNG plant
with an annual liquefaction capacity of 10 million tons (the aver-
age capacity of the newly proposed LNG plants in British Columbia,
Canada [see Appendix 2]), was carried out.
The overall objective of this paper is to conduct a comprehen-
sive techno-economic study of the LNG production through devel-
opment of techno-economic models. This was done by calculating
the installation cost of different unit process equipment and esti-
mating the entire cost of the plant. In addition, the overall cost
from liquefaction to the final sale of LNG was calculated.
Nomenclature
C
AT
cost of the absorber tower, $
C
b
cost coefficient in cost of absorber tower, which
depends on weight of absorber column
W
a
weight of the absorber column, kg
V
p
packing volume of the absorber tower, m
3
D
a
diameter of the absorber, m
L
a
length of the absorber, m
C
R
cost of regenerator column, $
C
HE
cost of heat exchanger in gas sweetening unit, $
A
HE
area of heat exchanger in gas sweetening unit, m
2
C
condenser
cost of condensers, $
C
Reboiler
cost of reboiler in gas sweetening unit, $
C
AD
cost of adsorber column, $
W
d
weight of the desiccant, kg
C
D
cost of deethanizer column, $
D
d
diameter of the deethanizer column, m
L
d
length of the deethanizer column, m
C
C
cost of compressors, $
P
c
power rating of the compressor, MW
C
GT
cost of gas turbines, $
C
T
total liquefaction cost, $
C
I
total investment cost, $
C
IA
total amortized investment cost, $
C
OA
total amortized operations and maintenance cost, $
C
on
total on-site cost of the project, $
C
r
raw material cost, $
C
U
utility cost, $
C
labor
total operations labor cost, $
r rate of return of the project, %
n lifetime of the project, years
L
c
liquefaction capacity of the LNG plant, million tons per
annum
C
LNG Plant
total LNG plant cost, $
gpm gallon per minute
Tcf trillion cubic feet
Bcf billion cubic feet
Tcf/d trillion cubic feet per day
Bcf/d billion cubic feet per day
Acronyms
USD United States dollar
LNG liquefied natural gas
NG natural gas
NGL natural gas liquid
BC British Columbia
APCI air Products and Chemicals, Incorporation
C3MR propane pre-cooled mixed refrigerant
R. Raj et al. / Sustainable Energy Technologies and Assessments 18 (2016) 140–152 141
Methodology
System boundary description and cost estimation approach
The raw gas feed is delivered to an LNG plant in Kitimat, British
Columbia, from the Horn River Basin or the Montney Play. The
Horn River Basin, an unconventional shale gas play, represents
around 28% of the remaining recoverable raw natural gas reserves
in British Columbia, while Montney Play, an unconventional tight
gas play represents 33% [17]. The different shale reserves and Kiti-
mat Port are shown in Fig. 1 below. An upstream LNG supply chain
(see Fig. 2) typically consists of four processes: production, trans-
portation, gas processing, and liquefaction. In this paper, for each
upstream process (other than production), a cost and scale analysis
in the context of the anticipated LNG export facilities in British
Columbia, Canada were conducted.
At the liquefaction facility, the gas undergoes processes such as
gas sweetening, dehydration, natural gas liquid recovery, and liq-
uefaction (see Fig. 3).
The annual capacity of 10 million tons per annum (MTPA) cor-
responds to 39 million cubic metres per day of LNG production.
Each process or unit operation illustrated in Fig. 3 was analysed
in terms of investment cost and operations cost. To calculate the
equipment installation cost, of equipment a data-intensive model
was developed considering bottom-up cost calculation
methodology.
First, all major unit processes such as gas sweetening, dehydra-
tion, and NGL recovery are identified. Second, relevant equipment
and the characteristics in each unit process are analysed. This
equipment is studied and analysed based on parameters such as
diameter, length, density, etc. These parameters correspond to a
liquefaction capacity of 10 MTPA. Empirical relationships linking
the equipment’s parameters to equipment cost are developed.
After determining the parameters, a bottom-up cost estimation
approach is used. The equipment costs were considered to get
the final installation cost or investment cost of a 10 MTPA LNG
plant. Operations and maintenance costs are considered to esti-
mate the total investment cost and subsequently the final total
cost. A discounted cash flow analysis is conducted to calculate
the cost of liquefying one gigajoule of natural gas. All the costs
mentioned in the paper are in U.S. dollars with 2014 as the base
year unless specified otherwise.
System description, data, and assumptions
Natural gas sweetening unit
To remove the acid gases (mainly hydrogen sulfide and carbon
dioxide), raw gas is sweetened. This process helps prevent pipeline
corrosion during gas transportation and reduces the volume of
undesired gases [18]. In the gas sweetening unit, the feed gas is
treated with aqueous amine solutions (diethanolamine [DEA] in
this paper). DEA is considered because it leads to fewer hydrocar-
bon losses in the natural gas [10].
The absorber tower, lean/rich heat exchangers, stripper or
regeneration column, condensers, and pressure vessels are the
equipment that contribute most to cost in the acid gas removal
unit [14]. The installation cost for this equipment is calculated
using the methodology presented in Section ‘System boundary
description and cost estimation approach’. Since the train size (5
MTPA) is large, the feed rate is high and hence two gas sweetening
units in each train are considered, for a total of four. The feed rate
of each acid removal unit is 359 mmscfd, which has been calcu-
lated based on the annual liquefaction capacity of the LNG plant.
Note that the gas sweetening process is required only for gas pro-
Fig. 1. Map overview of Port Kitimat and different shale reserves in Western Canada.
142 R. Raj et al. / Sustainable Energy Technologies and Assessments 18 (2016) 140–152
duced from the Horn River basin. This is because the average CO
2
content in the recoverable gas from the Horn river basin is about
10%, and for the Montney formation this value is negligible [17].
To calculate the parameters of some of the gas processing equip-
ment, GCAP [19] was used. GCAP, or Gas Conditioning and Process-
ing, is a software package based on equations and correlations
provided by John M. Campbell & Co. Javanmardi et al. [13] used this
software package to estimate the design parameters of dehydra-
tion units in their research paper in which they estimate the total
product cost of exporting LNG from the South Pars gas fields in Iran
to world markets. The various parameters of the equipment used in
a gas-sweetening unit are reported in Table 1.
In this paper, the equipment purchase price was calculated
using the cost correlations given in Couper et al. [23] and Douglas
[11]. The installation cost was obtained by multiplying the pur-
chase price by the installation factor of the process equipment as
provided by Gran [26], and the installation costs were updated
using the 2014 Chemical Engineering Plant Cost Index [27]. The
installation costs were then added in order to calculate the on-
site costs. The purchase price of the absorption tower and regener-
ation tower were estimated using the values of the parameters
(from Table 1) in cost correlations presented by Couper et al.
[23] (see Eqs. (1)–(3) in the Appendix). For the heat exchanger,
the cost correlation, as shown in Eq. (4), was obtained by calculat-
ing the cost of the lean amine heat exchanger for different surface
area values using Matches’ [28] equipment cost data for different
types of heat exchangers and surface areas and then developing a
general cost expression dependent only on surface area. However,
this generalized equation is only valid for shell and tube heat
exchangers constructed with stainless steel type 304 and pressure
as described in Table 1. Using a cost estimation methodology sim-
ilar to the one used to estimate the cost of lean amine heat exchan-
ger as described above, the installed cost of the condenser,
pressure vessels, and re-boiler was estimated. An additional 6%
of the total installation cost was included as miscellaneous cost
[24]. Since there are four gas sweetening units in the LNG plant
(two units in each train), the total installation cost of the gas
sweetening equipment is estimated by multiplying the gas sweet-
ening per unit cost by four.
Dehydration unit
In this unit, water from the feed gas is removed by adsorption
by a solid desiccant such activated alumina, silica gel, or molecular
sieves [29]. The removal of water prevents the formation of
hydrates in the main cryogenic heat exchanger during the liquefac-
tion process. In this paper, adsorption by molecular sieve was con-
sidered because the sieve is considered the most versatile
adsorbent and is capable of dehydration to less than 0.1 ppm water
content [16] [29]. In order to carry out the dehydration process
effectively, a minimum of two bed systems is required. Adsorption
dehydration columns work alternately. This means that while one
absorption bed is regenerated while the other dehydrates the wet
gas. The regeneration is performed by preheated gas, which flows
through the adsorbent into a cooler and then into the separator.
In this paper it is assumed that the heater an ordinary burner. Since
each of the LNG trains designed in this paper has a liquefaction
Fig. 2. A typical LNG supply chain.
Fig. 3. Major unit operations involved in a typical LNG facility.
R. Raj et al. / Sustainable Energy Technologies and Assessments 18 (2016) 140–152 143
capacity of 5 MTPA, the feed rate is very high (143 mmscfd). There-
fore, to satisfy this requirement, 5 parallel dehydration units are
used in each train with each dehydration unit consisting of 4 tow-
ers. The parameters for the adsorbers in the dehydration unit are
presented in Table 2. Using the parameters developed for the
adsorber tower (see Table 2) in Eq. (7), we obtained the cost of
an adsorber tower.
Natural gas liquid (NGL) recovery unit
In this process, the heavier hydrocarbons (C
3
–C
7
+
) present in the
natural gas are absorbed preferentially by absorber oil in the
absorption column. The hydrocarbon rich absorber oil leaves from
the bottom of the absorption column and is expanded to liberate
most of the absorbed methane. Afterwards, this rich oil is sent to
a deethanizer column, where absorbed methane is rejected and
part of ethane is absorbed. When the rich oil leaves the deethanizer
column, it is sent to a regeneration column, where the higher
hydrocarbons and other NGL components are driven to the top of
the regeneration column by heating them to a very high tempera-
ture [32]. In this process major cost driving equipment are the
deethanizer column, heat exchangers, pumps, compressors, and
vessels [14]. For heat exchangers considered in this process, a typ-
ical heat transfer coefficient (U-value) of 362.5 W/m
2
°C has been
[33]. The pressure values at the top and the bottom of the deetha-
nizer column are taken from [32]. The inlet temperature and pres-
sure are assumed to be the same as they were in other gas
Table 2
Parameters for adsorbers in the dehydration unit.
Parameter Value Units Reference/Comment
Gas flow rate 143.4 mmscfd Calculated for a liquefaction capacity of 5 MTPA
Gas pressure 6.78 Mpa [13]
Inlet gas temperature 311 K [13]
Inlet gas water content 0.0012 mole fraction [30]
Gas relative density 0.6 – [20]
Adsorption time 8 h [29]
Gas compressibility factor 0.96 – [20]
Number of towers in the plant 4 – [9]
Gas viscosity 0.012 [31]
Useful desiccant capacity (weight %) 25 weight % [16]
Dynamic capacity at saturation 20 weight % [16]
Minimum required bed length 1.6 m Calculated using GCAP [19]
Minimum required bed diameter 1.75 m Calculated using GCAP [19]
Minimum required desiccant 2669.4 kg Calculated using GCAP [19]
Table 1
Parameters of equipment in a gas-sweetening unit.
Parameter Value Unit Source/Comment
Absorber tower
Gas flow rate 359 mmscfd Calculated for a 10 MMTPA liquefaction plant
Feed gas pressure 30–40 MPa [17]
Feed gas temperature 60–75 °C[17]
Average gas compressibility 0.96 – [20]
Gas relative density 0.59 – [20]
Value of coefficient (Ks) 0.03 m [21]
Material of construction (stainless
steel 304) density
8000 kg/m
3
[22]
Packing material used metal ring,
2 in.
[23]
Diameter 4.02 m Calculated using GCAP [19]
Height (tangent-to-tangent) 8.14 m Calculated using GCAP [19]
Thickness 0.01 m Calculated using GCAP [19]
Regenerator column
Column height (tangent-to-tangent) 22.34 m Calculated using GCAP [19]
Column diameter 4 m Calculated using GCAP [19]
Tray spacing 0.42 m Diameter of the column lies in the range of 3.6 m-7.3 m [24]
Number of trays 25 Calculated using column height and tray spacing values
Material of construction (stainless
steel 304) density
8000 kg/m
3
Generally used for petrochemical industry applications [22]
Thickness 0.01 m Calculated using GCAP [19]
Total weight of the column 49,934 kg Calculated using the pacing volume of the tower and density
Lean-rich amine heat exchanger
DEA circulation rate 52 gpm Calculated for a feed rate of 359 mmscfd, k (DEA) of 1.45 [25] and acid gas mole percent of natural
gas from the Horn River basin [17]
Heating load 9.67 W [21]
Overall heat transfer coefficient 750 W/m
2
°C
[13]
Material of construction (stainless
steel 304) density
8000 kg/m
3
Generally used for petrochemical industry applications [22]. This grade of steel has been used for
both shell and tube construction.
Area 849.3 m
2
Calculated using GCAP [19]
Condenser
Condenser cooling load 2.18 W Optimal operating conditions [13]
Condenser surface area 39.5 m
2
Calculated using GCAP [19]
144 R. Raj et al. / Sustainable Energy Technologies and Assessments 18 (2016) 140–152
processing unit operations. Five deethanizer columns are installed
to sustain a high feed rate. The parameters for equipment in the
NGL recovery unit are presented in Table 3.
When we substitute the values of the diameter and length of
the deethanizer column from Table 3 in Eq. (8), we get the cost
of one column. We used Eqs. (4) and (9) to estimate the cost of
the heat exchangers and compressors, respectively.
Liquefaction unit
The liquefaction process considered in this paper is the propane
pre-cooled mixed refrigeration (APCI C
3
MR) process. This process
dominates the LNG market with a 77% share [34]. Before the natural
gas flows into the main cryogenic heat exchangers, it is precooled to
16 °C in the high-pressure propane cooler and further cooled to
35 °C in the medium- and low-pressure propane coolers. The large
surface area of the main cryogenic heat exchanger helps in efficient
heat transfer from the feed gas and cools the gas to 155 °C. The gas
exits as LNG and to reduce its pressure, it is sent to expanders, after
which it is routed to storage ranks [10]. The number of compressors
considered in this paper for propane cycle and mixed refrigerant
(MR) cycle is 1 and 2, respectively [10]. The heating load values of
theses compressors correspond to the optimal liquefaction process
cycle [34]. The gas feed rate pertains to liquefaction capacities of 5
MTPA. The surface areas for the heat exchangers were estimated
using GCAP [19]. The parameters for the equipment considered
are listed in Table 4. The main cryogenic and propane heat exchang-
ers, compressors, gas turbines, and expanders are the major cost
driving equipment in this process.
Two General Electric (GE) Frame 7 gas turbines provide the
power requirement for the compressors. These turbines have a
power generation capacity of 88.2 MW [35]. The installation cost
of the turbines was calculated using the values of their power out-
put in cost and power correlation as presented in Eq. (10). The
installation cost for propane compressors and mixed refrigerant
compressors was estimated by substituting the power require-
ments of the compressors in Eq. (9). The cost of propane heat
exchangers and main cryogenic heat exchanger depends on their
surface area and is estimated using Eq. (4).
Results
Equipment cost
In this section, the results of the paper, i.e., the cost of equip-
ment in each unit operation, are presented and discussed. The esti-
mated cost of one gas-sweetening unit is $6.3 M, in which the
major cost contributing equipment are the heat exchanger, re-
boiler, and regeneration column. The remaining pieces of equip-
ment each contribute less than 10% of the total cost. Since there
are 4 gas sweetening units in the plant designed for this paper,
the total cost is $25.2 M. The cost distribution for this unit is pre-
sented in Fig. 4.
For the gas dehydration unit, the adsorber tower contributes to
the total installed cost, which is estimated to be $9.8 M for the
designed liquefaction facility. There are five dehydration units
available per train, resulting in a total of 10 units for the entire liq-
uefaction plant. In the natural gas liquid recovery unit, the deeth-
anizer column makes up 72% of the total the total cost, followed by
compressors (19%). Heat exchangers, vessels, and miscellaneous
costs make up 10% of the total cost. There are 2 NGL recovery units
per LNG train, and the installed cost of one NGL recovery unit is
$19 M. Of all the unit operations in natural gas processing, lique-
faction is the most capital intensive. The total installed cost of
equipment used in liquefaction is $265 M, with around 44% of
the total cost shared by gas turbines. The second-most cost con-
tributing equipment is the main cryogenic heat exchanger. The
cost distribution of different equipment is presented in Fig. 5.
The summary of capital cost for equipment for the entire liquefac-
tion facility is presented in Table 5.
Cost estimation of delivering Canadian LNG to Asia
The total cost of delivering Canadian LNG to Asia (China, Japan,
and India) consists of five cost components, namely, feed gas price
at the wellhead, pipeline transpiration cost, liquefaction facility
capital expenditure (CAPEX), operational expenditure (OPEX), and
shipping cost. In this section, all of these costs are discussed in
detail and total delivery cost of LNG is estimated. Two supply
sources of raw natural gas (Horn River and Montney shale reserve)
are considered in this study. The Horn River shale reserve has a gas
Table 3
Equipment parameters in an NGL recovery unit.
Parameter Value Unit Reference/Comments
Compressor efficiency 80% [32]
Feed rate 7154.95 kmol/hr Calculated for 10 MTPA liquefaction capacity
Plate inlet gas pressure 6.78 MPa [13]
Plate inlet gas pressure 311 K
Deethanizer top pressure 452 psig [4]
Deethanizer bottom pressure 457 psig [4]
Deethanizer column
Diameter 4.2 m Calculated using GCAP [19]
Length 20 m Calculated using GCAP [19]
Heat exchanger
Heat load 8.2 MW [13]
Area 194 m
2
Calculated using GCAP [19]
Compressors
Power consumption 8.2 MW [5]
Table 4
Parameters for the liquefaction process.
Parameter Value Unit Reference/Comments
Feed temperature 6.76 MPa [13]
Feed pressure 311 K [13]
Feed rate 19.26 10
6
m
3
/day Calculated for a 10 MTPA
liquefaction capacity plant
Total power
requirement of the
compressors
141.86 MW Calculated for a 5 MTPA
liquefaction train [34]
Surface area of heat exchangers
Propane cooling heat
exchanger
164 m
2
Calculated using GCAP [19]
Main cryogenic heat
exchanger
490 m
2
Calculated using GCAP [19]
R. Raj et al. / Sustainable Energy Technologies and Assessments 18 (2016) 140–152 145
supply break-even cost of $4.74/GJ, which includes the wellhead
and pipeline transport cost, whereas the liquid rich Montney has
a gas supply cost of $3.48/GJ [38] (see Table 5). The lower heating
value of natural gas (37.3 MJ/m
3
) and the feed value (1.5 bcf/d)
corresponding to a 10 MTPA plant were used to estimate total nat-
ural gas feed cost. Construction labor costs depend on the number
of laborers, labor cost, country, and the employment industry. This
cost was calculated based on the average wages of construction
laborer employed in Canada’s oil and gas sector [39] and the total
number of workers expected to be employed in the Kitimat LNG
plant [40]. Due to the unavailability of Canada-specific peer-
reviewed data, the project management labor and engineering
labor costs were estimated using the ‘‘percentage of installed
equipment cost method” provided by West et al. [24]. This method
is generally used for preliminary paper estimates and has an accu-
racy range of ±20–30 percent [24]. In the Kitimat LNG plant, Gen-
eral Electric gas turbines would be installed and would generate
electricity at the plant. The water cost is negligible compared to
the operations and maintenance cost. Therefore, the overall utility
costs are negligible and not accounted for in this study.
26%
10%
22%
5% 6%
26%
6%
0%
5%
10%
15%
20%
25%
30%
Heat exchanger Absorber tower Regeneration
column
Condenser Press ure
vessels
Reboiler Miscellaneous
Percentage share (%)
Fig. 4. Cost distribution of the equipment in a gas sweetening unit.
21%
2%
18%
9%
44%
6%
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
Main cryogenic
heat exchan
g
er
Propane heat
exchan
g
er
Compressor (MR
c
y
cle)
Compressor
(
p
ro
p
ane c
y
cle)
Gas turbine
(three in total)
Miscellaneous
Percentage share (%)
Fig. 5. Cost distribution of the equipment in a liquefaction unit.
Table 5
Summary of equipment costs for the LNG plant.
Operation Cost
(US$)
Percentage
share (%)
Comments
Gas sweetening 25.2 M 3 Estimated cost of 4 gas sweetening units
Dehydration 9.8 M 1 Estimated cost of 10 dehydration units
NGL recovery 38.5 M 5 Estimated cost of 2 NGL recovery units
Liquefaction 265.8 M 33
LNG storage tanks 461.7 M 58 Estimated cost of three storage tanks (each with a storage capacity of 160 K m3 accommodating a ship delay of
7 days and price of $150 M per tank [36])
On-site cost 801.1 M
Total installed
equipment cost
1.9B Calculated using empirical relationship provided in Ref. [37]
146 R. Raj et al. / Sustainable Energy Technologies and Assessments 18 (2016) 140–152
The total investment cost is calculated using the methods pre-
sented by Douglas [37] and using Eq. (13). These costs were amor-
tized assuming a 12% discount rate (r), and a plant life (n) of
25 years. By substituting the total investment cost and operations
cost in Eqs. (12) and (14), respectively, we find the total amortized
investment and total operations cost. The cost of liquefying one
gigajoule of natural gas is shown in Table 6. The total product cost
is $7.8/GJ, if the gas supply source is Montney and is $9.1/GJ, if the
gas supply source is Horn River. All the cost values mentioned
above have been summarized and presented in Table 6.
After the liquefaction process, LNG carriers ship LNG. The cost of
shipping would depend on the type of carrier, its propulsion
system and fuel consumption, hiring rate, etc. An in-depth
techno-economics analysis of shipping natural gas in the form of
LNG to Asian countries (Japan, China, India) can be found in a paper
in preparation by Raj et al. [42]. The shipping cost values reported
in Raj et al. [42] have been adapted in this paper . The break-even
cost of delivery to three Asian countries has been presented in
Fig. 6. The delivery cost is the price at which the Canadian LNG
must be sold in these Asian countries to recover all the costs
incurred. For Japan the delivered cost of Canadian LNG ranges from
$8.2/GJ to $10.1/GJ with a base case estimate of $9.15/GJ. The cor-
responding cost for China is $9.28/GJ with a range similar as that of
Japan. For India, the delivered cost is 8% higher than for Japan due
to the greater shipping distance.
LNG plant scale analysis
For this section, we estimated the scale factor associated with
the capital cost of LNG facility construction. Fig. 7 shows some of
the LNG projects around the globe whose capital cost [43] and
annual liquefaction capacity [44] were considered to determine
the dollar per ton value of LNG plants. The capital cost of all the
projects was adjusted for inflation and exchange rates between
their completion year and 2014. The value of the scale factor expo-
nent is estimated to be 0.69. This demonstrates economies of scale
in the construction of LNG plants. Using LNG project data and
power sizing exponents, an equation (Eq. (15)) for the cost of
LNG projects was formulated. This equation has been estimated
using the power-sizing model. This model accounts explicitly for
economies of scale. To estimate the cost of B based on the cost of
comparable item A, we use the equation
Table 6
Cost summary for a two-train 10 MTPA Canadian natural gas liquefaction facility.
Cost (US$) Reference/Comments
Capital cost
Equipment cost 1.9B
Construction labor
Project management labor 3.7B Calculated by using project management labor’s fraction (1.94) of total installed equipment cost [41]
Construction labor 6.7B Calculated using the number of construction laborers working in the Kitimat LNG facility and the average
salary of oil and gas laborers in Canada
Engineering labor 2B Calculated using engineering labor’s fraction (1.05) of total installed equipment cost [41]
Total capital expenditure
(CAPEX)
$1200/tpa Calculated by dividing the total estimated capital cost by the liquefaction capacity
Operations and maintenance cost
Natural gas supply cost $3.48/GJ (Montney) Includes a break-even wellhead cost of $2.63/GJ and a transportation tariff of $0.84/GJ [38]
$4.74/GJ (Horn River) Includes a break-even wellhead cost of $3.74/GJ and transportation tariff of $1.0/GJ [38]
Total operational
expenditure (OPEX)
$48/tpa Assumed to be 4% of the total capital expenditure
Amortized cost
Amortized CAPEX $3.6/GJ Calculated using a 12% rate of return and a plant life of 25 years
Amortized OPEX $0.8/GJ
Total product cost $7.8/GJ (Montney), $9.1/GJ
(Horn River)
Sum of amortized investment and operations and maintenance cost
9.15 9.28
9.90
0.00
2.00
4.00
6.00
8.00
10.00
12.00
Japan China India
Delivered cost of Canadian LNG ($/GJ)
Shipping cost
Liquefaction cos
t
Pipeline cost
Well head cost
Fig. 6. Break-even cost of delivery of Canadian LNG to Asia.
R. Raj et al. / Sustainable Energy Technologies and Assessments 18 (2016) 140–152 147
Cost of B ¼ðCost of AÞ½ð\Size"of BÞ=ð\Size"of AÞ
x
where x is the appropriate power-sizing exponent, available from a
variety of sources. An economy of scale is indicated by an exponent
less than 1.0 An exponent of 1.0 indicates no economy of scale, and
an exponent greater than 1.0 indicates a diseconomy of scale.
Sensitivity analysis
For this section, we conducted a sensitivity analysis to assess
the impact of various parameters on the total product cost. Five
parameters, namely, the discount rate, LNG facility capital expen-
diture (CAPEX), operating expenditure (OPEX), natural gas well-
head cost, and pipeline transport cost were varied to assess their
significance. A discount rate of 12% was considered in the base case
study. For the purposes of the sensitivity analysis, the discount rate
was varied from 8% to a maximum of 24%. All other parameters
were varied within a ±100% range. The results of this analysis are
presented in Fig. 8 below. It is clear from the results that CAPEX
is the most influential parameter on overall product cost followed
by gas wellhead cost and the discount rate. The CAPEX cost consid-
ered in the base case is $1200/tpa. This cost is high for Canadian
LNG projects since most of the projects are greenfield. The opera-
tional expenditure (OPEX) of the LNG facility and the transporta-
tion cost were found to have a similar impact on the total
product cost.
A sensitivity analysis for the equipment was also performed.
The variations in equipment cost with changes in parameter are
shown in Figs. 9–14. The costs represented are shown with a ±5
percent variation. Fig. 9 represents gas turbine cost variations with
respect to the power a turbine generates. A wide variation in cost
for different values of power generated can be observed. The cost
0
5
10
15
20
25
30
0
500
1000
1500
2000
2500
3000
3500
4000
Donggi-Senoro LNG Project,
…
Darwin LNG Project, Australia
Burrup Park (Pluto) LNG Project,
…
Yemen LNG, Yemen
Brunei LNG Plant, Lumut, Brunei
Tangguh LNG Project, Indonesia
Qalhat LNG Plant, Oman
Sakhalin II LNG, Russia
Qatar Gas I LNG Plant, Ras Laffan,
…
Karratha LNG Plant, Australia
Bontang LNG Plant, Indonesia
Petronas Bintulu LNG Complex,
…
Equatorial Guinea LNG Project,
…
Angola LNG Project, Soyo, Angola
SEGAS LNG Complex, Damietta,
…
Idku LNG port , Egypt
Bonny Island, Nigeria
Sonatrach Skikda LNG Project,
…
Snøhvit LNG Export Terminal,
…
Arzew LNG, Algeria
Peru LNG Project, Peru
Atlantic LNG, Trinidad & Tobago
Liquefaction capacity of LNG Plant
$/ton
$/ton Liquefaction Capacity (MTPA)
Fig. 7. The cost of liquefying one ton of LNG ($/ton) vs. LNG plant capacity (MTPA).
3
4
5
6
7
8
9
10
11
12
13
-100 -95 -75 -50 -25 0 25 50 75 95 100
Total product (LNG) cost ($/GJ)
Percentage change in base parameter
Discount rate
Transport cost
Wellhead cost
CAPEX
OPEX
Fig. 8. Sensitivity analysis for total product (LNG) cost.
148 R. Raj et al. / Sustainable Energy Technologies and Assessments 18 (2016) 140–152
curve is a concave curve opening downwards and showing econo-
mies of scale involved. Fig. 10 shows the variation of compressor
costs with power requirement. The cost varies between 8 and 10
million U.S. dollars for a power range of 30–50 MW. Fig. 11 repre-
sents the variation of heat exchanger costs with surface area.
Fig. 12 represents variations of condenser cost with surface area.
Fig. 13 shows variations of absorber tower cost with changes in
diameter and a fixed tower length of 8.14 m. Fig. 14 shows varia-
tions of adsorber cost with varying lengths and a fixed diameter
of 4.02 m.
Conclusion
The objective of this paper was to conduct a data-intensive
paper to estimate the cost of equipment installed in a 10 MTPA
LNG plant in Canada through development of techno-economic
models and cost correlations. To this end, the equipment cost for
each LNG process and the liquefaction cost of one gigajoule of nat-
ural gas were calculated. It was found that the liquefaction unit
makes up the majority of costs incurred in liquefaction. Thus,
any slight improvement in liquefaction technology or the creation
of optimal conditions through process optimization software
5.0E+05
5.5E+05
6.0E+05
6.5E+05
7.0E+05
7.5E+05
8.0E+05
8.5E+05
9.0E+05
9.5E+05
1.0E+06
400 500 600 700 800 900 1000
Cost (US$)
Area (meter square)
Fig. 11. Cost versus area graph for heat exchangers.
0.0E+00
5.0E+04
1.0E+05
1.5E+05
2.0E+05
2.5E+05
3.0E+05
20 30 40 50
Cost ( US$)
Area (meter square)
Fig. 12. Cost versus area graph for condenser columns.
0.0E+00
5.0E+04
1.0E+05
1.5E+05
2.0E+05
2.5E+05
3.0E+05
3.5E+05
4.0E+05
45678910
Cost (CAD$)
Length (m)
Fig. 14. Cost versus length graph for absorber columns.
0.0E+00
5.0E+04
1.0E+05
1.5E+05
2.0E+05
2.5E+05
3.0E+05
3.5E+05
4.0E+05
4.5E+05
5.0E+05
22.533.544.55
Cost (US$)
Diamter (m)
Fig. 13. Cost versus diameter graph for absorber columns.
0.0E+00
5.0E+06
1.0E+07
1.5E+07
2.0E+07
2.5E+07
3.0E+07
20 40 60 80 100 120 140
Cost ( US$)
Power (MW)
Fig. 9. Cost versus power graph for gas turbines.
6.0E+06
7.0E+06
8.0E+06
9.0E+06
1.0E+07
1.1E+07
1.2E+07
1.3E+07
30 34 38 42 46 50
Cost (US$)
Power (MW)
Fig. 10. Cost versus power graph for compressors.
R. Raj et al. / Sustainable Energy Technologies and Assessments 18 (2016) 140–152 149
would greatly reduce the overall project cost. The total product
cost is $7.8/GJ, if the gas supply source is Montney and $9.1/GJ, if
the gas supply source is Horn River. This cost includes the gas well-
head cost, pipeline tariff, and the liquefaction cost. Apart from LNG
facility capital expenditure cost, the gas supply cost is a key param-
eter that can significantly impact the total product cost. Hence,
reducing gas supply cost by using more economic gas extraction
and recovery techniques can bring down product cost. If shipping
costs are added, we get the total delivery cost of Canadian LNG
to Asian countries. For Japan, the delivered cost of Canadian LNG
ranges from $8.2/GJ to $10/GJ with an average estimate of $9.15/
GJ. Therefore, Canadian LNG projects require a minimum of $62/
Appendix 1. List of Equations
Number Equation Reference/Comments
1C
AT
= 1.7C
b
+ 43.37V
p
+ 464.63D
a
0.74
L
a
0.71
[23]
2C
b
= 1.218 exp
(6.629+0.1826(lnWa)+0.02297(ln
Wa)(lnWa))
[23]
3C
R
= 1.218 (f
1
C
b
+Nf
2
f
3
f
4
C
t
+C
pt
) Here values of f
1
and f
2
correspond to stainless steel 304, values of f
3
and f
4
correspond to tray types and their number; C
b
,C
t
and C
pt
depend on the weight,
length, and diameter of the absorber column [23]
4C
HE
= 35969(A
HE
)
0.47
[28],[23]
5C
condenser
= 18707(A)
0.63
[28]
6C
Reboiler
= 2045(A)
0.9748
[28]
7C
AD
= 28712 + 3036 * (W
d
)
0.48
[28]
8C
D
= 102536 * D
d
0.63
*L
d
0.80
[28],[24]
9C
C
= 1065470 * (P
c
)
0.62
[23]
10 C
GT
= 0.69(HP)
0.81
[23], Horsepower of the gas turbines correspond to the GE Class 7 gas turbine
power output
11 C
T
=C
IA
+C
OA
Total LNG product cost is the sum of the amortized total investment cost and
amortized operations and maintenance cost [37].
12 C
IA
=(r*(1+r)
n
/L
c
)*C
I
Amortized investment cost calculation based on a 12% rate of return and a plant
life of 20 years
13 C
I
= 2.36 * C
on
[37]
14 C
OA
=C
O
/L
c
Amortized operations and maintenance cost based on the total annual liquefaction
capacity
15 C
LNG Plant
= 1.61 * (L
C
)
0.69
Generalized expression developed considering the cost of various LNG projects
across the globe.
Appendix 2. LNG projects in Canada
Location Name Capacity NEB export application
status
Length
(Years)
Expected Start
Date
References
Kitimat, B.C. Douglas Channel Energy
Project
1.8 Approved 20 2015 [46]
Kitimat, B.C. Kitimat LNG Terminal 5 Approved 20 2017 [47]
Kitimat, B.C. Haisla Cedar 14.5 Under review 25 [48]
Kitimat, B.C NewTimes Energy LNG 12 Under review 25 [49]
Kitsault, B.C. Kitsault 5 Under review 25 2017 [50]
Woodfibre, B.C. Woodfibre LNG 2.1 Approved 25 2017 [51]
Kitimat or Prince Rupert,
B.C.
Triton LNG 2.3 Approved 25 2017 [52]
Prince Rupert, B.C. Orca LNG 24 Under review 25 [53]
Sarita Bay, B.C. Steelhead LNG 30 Under review 25 [54]
Lelu Island, Port Edward,
B.C.
Pacific Northwest LNG 12 Approved 25 2018 [55]
Coos Bay, Ore. Jordan Cove LNG 6 Approved 25 2018 [56]
Campbell River, B.C. Discovery LNG NA NA 2019 [57]
Kitimat, B.C. LNG Canada Terminal 12 Approved 25 2020 [58]
Kitimat or Prince Rupert,
B.C.
WCC LNG 12.50 Approved 25 2021–2022 [59]
Ridley Island, Prince
Rupert, B.C.
Prince Rupert LNG 14 Approved 25 2021 [60]
Grassy Point, B.C. Aurora LNG 24 Approved 25 2021–2023 [54]
Stewart, B.C. Stewart Energy LNG 17 Under review 25 2017 [61]
Vancouver, B.C. Tilbury LNG 3 Under review 25 2016 [5]
150 R. Raj et al. / Sustainable Energy Technologies and Assessments 18 (2016) 140–152
barrel in the central case assumptions, if an average 14.5% slope for
Japanese contracts indexed on the Japanese Crude Cocktail Price
(JCC) is assumed. Hence it is clear that LNG projects in Canada
are very susceptible to the oil prices in Japan. In China, however,
there is a wide gap among citygate natural gas prices from differ-
ent sources. Natural gas citygate prices in Shanghai range from $8/
GJ (domestic gas transported through the West-East Pipeline) to
$13/GJ (Turkmenistan gas imports) [45]. The delivered cost of
Canadian LNG lies midway in this range and hence the imported
LNG from Canada may be a cheap alternative source of LNG for
China at a time when Chinese policy makers are trying to diversify
their LNG import mix.
Acknowledgements
The authors are grateful to School of Energy and Environment
(SEE) – University of Alberta, Sino-Canadian Energy and Environ-
ment Research and Education Initiative (SCENEREI), the NSERC/
Cenovus/Alberta Innovates Associate Industrial Research Chair Pro-
gram in Energy and Environmental Systems Engineering and the
Cenovus Energy Endowed Chair Program in Environmental Engi-
neering for the financial assistance to carry out the research. The
authors thank Astrid Blodgett for editorial assistance.
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152 R. Raj et al. / Sustainable Energy Technologies and Assessments 18 (2016) 140–152
