Economic evaluation of a new small-scale LNG supply chain using liquid nitrogen for natural-gas liquefaction

Applied Energy 182 (2016) 154–163

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Applied Energy journal homepage: www.elsevier.com/locate/apenergy

Economic evaluation of a new small-scale LNG supply chain using liquid nitrogen for natural-gas liquefaction Juwon Kim, Youngkyun Seo, Daejun Chang ⇑ Department of Mechanical Engineering, Korea Advanced Institute of Science and Technology, Daehak-ro 291, Yuseong-gu, Daejeon 34141, Republic of Korea

h i g h l i g h t s
A small-scale natural gas supply chain using liquid nitrogen is suggested.
The supply chain is evaluated in terms of life cycle cost and life cycle profit.
The profit of the supply chain is maximized when the pressure of LNG is 7 bar.
The liquefaction process is economical when the flowrate of LNG is under 27 ton/h.

a r t i c l e

i n f o

Article history: Received 19 April 2016 Received in revised form 4 August 2016 Accepted 20 August 2016 Available online 27 August 2016 Keywords: Natural gas recovery Stranded gas LNG Life-cycle cost Life-cycle profit Liquid nitrogen

a b s t r a c t This study proposed a new LNG (liquefied natural gas) supply chain using liquid nitrogen (LN2) to liquefy natural gas on a small scale, and analyzed the life cycle cost (LCC) and the life cycle profit (LCP) for the supply chain. Natural gas was liquefied with the latent heat of LN2 without any turbo-machines. The LNG was transported to an LN2 production site, where LN2 was produced with the cold (cryogenic) energy of the LNG. Then, LN2 was transferred to the LNG production site again, completing the cycle. To verify the economics of this supply chain, the LCC and LCP were estimated with different design and operation conditions. This supply chain was found to be significantly profitable because it efficiently used the cold energy of both LNG and LN2, eliminating the required cost for the regasification process. The results of LCC and LCP showed that the profit of the supply chain was maximized when the pressure of the LNG product was approximately 7 bar, irrespective of the transportation distance. This was because the latent heat and density of LNG were different from those of LN2. The distance between the LNG and LN2 production sites was the dominant parameter that governed the economics of this supply chain. Ó 2016 Elsevier Ltd. All rights reserved.

1. Introduction The global demand for natural gas as an energy source is rapidly increasing. The desire for low-carbon fuels and reduced CO2 emissions is driving this demand. The increasing demand for natural gas is also motivated by the exploitation of shale gas, which has recently begun to affect the world’s energy market significantly. The use of hydraulic fracturing and horizontal drilling technologies has reduced the cost of shale gas production and led to its sharp increase. According to the US Energy Information Administration, US shale gas production will increase by 73% from 11.3 TCF (trillion cubic feet) in 2013 to 19.6 TCF in 2040 [1,2]. Onshore natural gas that is produced in considerable amounts is supplied through a pipeline infrastructure or it is liquefied in a ⇑ Corresponding author. E-mail addresses: [email protected] (J. Kim), [email protected] (Y. Seo), [email protected] (D. Chang). http://dx.doi.org/10.1016/j.apenergy.2016.08.130 0306-2619/Ó 2016 Elsevier Ltd. All rights reserved.

large-scale liquefaction plant for overseas shipping. However, natural gas that is sporadically found in small amounts, which is called stranded gas, is not developed because of low economic incentives caused by insufficient gas quantities, a lack of available pipeline infrastructure, and remote locations of consumers [3]. This stranded gas accounts for approximately 40% of the world’s natural gas reserves [4]. Associated natural gases that are generated in small amounts from oil in oil fields or shale gas fields have many environmental issues [5]. They are only flared, which leads to greenhouse gas emission and a loss in potential value. US industries flared 260 billion cubic feet of natural gas in 2013, which is equivalent to approximately 2.3 billion dollars [6]. The flaring of these associated gases is also performed for the same reasons for which stranded gas are undeveloped. Fig. 1 shows how natural gas is supplied to customers. When the pipeline infrastructure is unavailable or economically infeasi-

J. Kim et al. / Applied Energy 182 (2016) 154–163

155

Nomenclature Subscripts N required number of trucks V transport capacity of a truck T operation time for a round trip M required amount of liquids transported per unit time D distance between the liquefaction process and the LN2 production site U average velocity of a truck

L NIV NDOF NBC Nv Ne NLNG NLN2

loading/unloading time number of independent variables number of degrees of freedom number of boundary conditions number of variables for streams number of equations for equipment number of variables for LNG streams number of variables for LN2 streams

Fig. 1. Supply chain of onshore natural gas.

ble, stranded or flared natural gas can be monetized with a few technologies as follows: GTL (gas to liquids), CNG (compressed natural gas), and LNG (liquefied natural gas) [7–9]. Because the amount of recoverable stranded gas is insignificant at a given well and because the production rate rapidly decreases with time, the economics of these technologies are governed by their mobility, production reliability, operational convenience, and energy efficiency as well as their production quantity. GTL technology is an option for monetizing stranded gas. Unlike LNG or CNG technology, GTL chemically converts natural gas into heavy hydrocarbons such as LPG (liquefied petroleum gas), gasoline, diesel, and wax, which are liquids under atmospheric conditions and are also traded in the commodity market [10]. However, this process requires several units with extensive plot areas, such as an air separation unit (ASU), to supply a considerable amount of oxygen to reform the natural gas. This technology is currently under development to improve the system’s economics, and some processes are commercialized to recover the stranded gas [11]. CNG technology is a method for supplying natural gas using compressed gas. It is an economical method of recovering stranded gas because it is simple and has a lower cost than LNG for smallscale sources. CNG can be transported using trucks, pipelines, or, in the case of marine reserves, ships. In the marine environment especially, CNG is more economical than LNG when the distance from the consumer is short and the natural-gas volume is low. CNG acts as an alternative solution when LNG systems or pipelines are unavailable [12]. A well-developed LNG supply chain is required to recover stranded gas using LNG technology. There are three primary stages for supplying LNG from a well to customers, namely liquefaction,

transportation, and regasification. Natural gas is liquefied to LNG during the liquefaction process. The LNG is then transported to the regasification site by trucks or ships. After regasification, the transported LNG is finally supplied to the customers. Kumar et al. indicated that the LNG would be the most feasible technology and can become a promising energy source due to its flexibility and transportability [13]. The following are several conventional processes to liquefy natural gas: the cascade process, propane precooled mixed-refrigerant process (C3MR), single mixed-refrigerant (SMR) process, dual mixed-refrigerant (DMR) process, and N2 expansion process. For small-scale LNG liquefaction, the N2 expander cycle and SMR process are representative technologies [14,15]. Generally, the initial investment cost and the efficiency of the liquefaction cycle are proportional to the amount of LNG production [16]. Remeljej and Hoadley investigated the small-scale SMR, twostage nitrogen expansion, and other two open-loop different open-loop cycles (New LNG and Gas Consult Ltd. cycle) [17]. The SMR process requires less power consumption than the N2 expansion process. The remarkable efficiency of the SMR process is attributed to the optimization of the composition of the mixed refrigerant [18,19]. In contrast, the N2 expansion cycle has strong advantages that overcome the low efficiency of liquefaction. Nitrogen is a nonreactive refrigerant, and hence, it has high inherent safety. Also, the nitrogen refrigerant is largely independent of the feed gas condition unlike SMR process [20]. Kohler et al. pointed out that the N2 expansion process had a competitive edge with simplicity, quick startup, partial-load capability, efficiency, and convenient maintenance [14]. He and Ju proposed a novel process that liquefies natural gas from a small-scale pipeline [21]. This process uses the pressure

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exergy of the natural gas and does not use any energy for liquefaction. However, the requirement for highly pressurized pipeline natural gas and the low liquefaction rate are limitations for stranded gas recovery. Yuan et al. proposed a novel small-scale liquefaction process utilizing nitrogen expansion with carbon dioxide precooling [22]. It has lower energy efficiency than the conventional small-scale liquefaction processes. They concluded that the new process could be suitable for stranded gas recovery with the compact device, safety operation, and simple capability. However, the conventional liquefaction processes use turbomachinery, which is expensive and has a high failure rate, leading to frequent shutdown, malfunction, and the need for maintenance [23]. These disadvantages of the conventional liquefaction processes make natural-gas recovery infeasible and uneconomical for such small-scale stranded gas sources. Hence, a new simple and robust technology is required to recover natural gas and solve the flaring problem. There are two primary processes for vaporizing LNG: an openrack vaporizer that uses sea water and a submerged combustion vaporizer that burns fuel gas [24]. These systems require additional energy to vaporize LNG and are thus uneconomical. Heat integration using the cold (cryogenic) energy of LNG leads to a considerable improvement in the regasification system. Several studies were conducted to improve the regasification system with the cold energy of LNG. The LNG cold energy could be used to liquefy CO2, a carbon capture and storage (CCS) technology [25]. The organic Rankine cycle (ORC) uses the cold exergy from LNG to generate electricity [26–28]. In addition, the thermodynamic efficiency of air separation units (ASU) can be improved with the cold energy from LNG [29]. It can also be used for separating light hydrocarbons [30,31]. However, it is not sufficient to maximize the economic feasibility of the whole LNG supply chain. A novel energy-integrated LNG supply chain is required to improve the efficiency of the whole LNG supply chain and to monetize stranded gas. Aspelund and Gundersen suggested a liquefied energy chain that combines LNG liquefaction, ASU, and CO2 capture and storage [32–35]. These authors efficiently integrated these processes throughout the whole chain, not only for the liquefaction and regasification systems but also in the transportation system. They liquefied natural gas using turbo-machines with the cold energy from LCO2 and LN2. The cold energy of LNG is also used to improve the ASU efficiency in the chain. This process is efficient and well-organized, but it is too complex and requires a high initial investment cost to recover stranded gas. The high complexity with low mobility, flexibility, operability, availability, and robustness is a significant disadvantage when recovering small-scale stranded gas. Moreover, the suggested liquefied chain requires a stable source of CO2 that can restrict its applications. Brown and Minton proposed a liquefaction process that used liquid nitrogen (LN2) as a refrigerant to liquefy natural gas [23].

They used electric power to operate the process, including a nitrogen liquefier. The system contained a modular plant for producing 10,000–250,000 gallons of LNG per day. It could recover raw and untreated gas while generating vehicular-grade LNG. However, this study did not include the details of the proposed process. The authors discussed the economics of the process, but the methodology or basis of the evaluation was not revealed. Additionally, they did not use the cold energy of the LNG to separate and liquefy nitrogen, which is one of its differences from the LNG supply chain proposed by the present paper. The present study proposes a new LNG supply chain to recover a small-scale stranded gas or associated gas using LN2. The primary concept of this chain is as an efficiently integrated system that is simple, robust, reliable, and easy to transplant. This supply chain is evaluated on the basis of its life cycle cost and life cycle profit analyses. The new LNG supply chain is suggested and described in Section 2. The methodologies for economic evaluation are explained in Section 3. Section 4 shows the results of the cost and profit estimation, including sensitivity analyses. Finally, Section 5 presents the conclusions. 2. System description of the new LNG supply chain 2.1. New LNG supply chain Fig. 2 shows the new LNG supply chain using LN2. This chain consists of three parts: LNG production, transportation, and LN2 production. The LNG production is a liquefaction process that liquefies the natural gas with the cold energy of LN2, while the LN2 production separates and liquefies nitrogen with LNG. Both LN2 and LNG are transferred to the other production site by trucks. In the LN2 production site (ASU), which generates liquid air, nitrogen is separated from the air and liquefied to LN2 using the electricity and the cold energy of the LNG. The produced LN2 is transported to the LNG production site. In the LNG production site, natural gas is liquefied by heat exchange with cryogenic LN2. The gasified nitrogen is vented into the air, and the LNG is transported to the LN2 production site and finally supplied to the customers after regasification. Since the LN2 production site can be a big power plant consuming a huge amount of LNG, multiple LNG production sites can be combined with an LN2 production site. The LNG production site should be located at the small-scale naturalgas wells. The use of LN2 in this supply chain has several benefits. LN2 is safe in the supply chain because it is nonflammable and inactive. Air separation plants are readily available in the industry. Also, LN2 can be produced from the facilities at low cost. The production cost of LN2 can be reduced by further utilizing the cold energy of LNG. That is, the wasted cold energy during LNG vaporization is utilized as the cold source of LN2 production in the chain.

Fig. 2. New LNG supply chain using LN2.

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9

Heat exchanger 1

Gas N2

J-T valve

Natural gas 1

Heat exchanger 2

8

7

LN2

Vessel

LNG 6

5

2 3

4

NGL

Fig. 3. Process flow diagram of LNG production.

Table 1 Process details of streams. Stream no.

1

2

3

4

5

6

7

8

9

Temperature (°C) Pressure (bar) Flow rate (ton/h)

30 40 10

80.5 40 10

150 1 10

150 1 1.379

150 1 8.621

165.2 1 8.621

185.2 3 21.5

155 3 21.5

19.7 3 21.5

2.1.1. Liquefaction process of LNG production Fig. 3 indicates the process flow diagram (PFD) of the liquefaction process. The latent and sensible cold energy of LN2 is used to liquefy the natural gas. The feed gas is precooled in the first heat exchanger. After passing the J-T (Joule-Thomson) valve, the natural gas is expanded and cooled. J-T expansion process expands the gas to lower pressure with a constant enthalpy. The natural gas is cooled down by about 50 °C in the given feed gas condition, undergoing the J-T expansion process. The natural gas liquid (NGL) is extracted in the separating vessel. NGL differs from LNG in that the former is mainly composed of not C1 (methane), but C2 (ethane), C3 (propane), and heavier hydrocarbons, while the latter predominantly consists of C1. NGL is separated in most gas processing plants because these it could lead to condensation in subsequent processes and it could be sold as a high-price liquid [16]. Finally, the vapor in the vessel goes to the second heat exchanger, and the LNG is produced by the cold energy of LN2. While a conventional liquefaction process of natural gas includes compressors or expansion turbines, the proposed one does not require such turbo-machines. Instead, it requires a separating vessel, a J-T valve, and two heat exchangers. Because this configuration does not contain turbo-machinery, the process has a reduced failure rate, leading to low maintenance cost with high production availability. The turbo-machinery accounts for most of the equipment expense in conventional processes [36]. These characteristics make this new process economical in capital expenditure. In addition, the small equipment enables this system to have high mobility, making it economical and optimal to recover gas from multiple sources by transplanting the system. Table 1 shows the details of the process when the pressure of the LNG product is set at 1 bar. The feed gas is transported at 30 °C, 40 bar, and a flow rate of 10 ton/h. Table 2 indicates the feed

Table 2 Feed gas composition [37]. Feed gas composition

Mole fraction

Methane Ethane Propane i-butane n-butane i-Pentane n-Pentane Nitrogen Oxygen

0.9301 0.0450 0.0043 0.0033 0.0035 0.0004 0.0005 0.0107 0.0022

gas composition, which is based on the Barnett Shale gas [37]. The pressure of LN2 is assumed to be 3 bar, and the nitrogen is assumed to be saturated pure nitrogen. Based on the conventional engineering data for heat exchangers, the minimum approach temperatures are assumed to be 10 and 5 °C for Heat Exchangers 1 and 2, respectively. The produced LNG is set to be saturated. This liquefaction process is simulated with the Peng-Robinson equation of state in ASPEN Hysys v8.4 [38]. 2.1.2. Analysis of the degree of freedom for the process The degree of freedom (DOF) is analyzed to determine the variables that affect the efficiency and LCC of the supply chain for this process. The DOF analysis is conducted to find the number of independent variables that uniquely define the process. The degree of freedom (N DOF ) is calculated by subtracting the number of equations (N e ) from the number of variables (N v ). Table 3 shows the number of variables of the streams calculated. Each stream has variable temperature, pressure, and mass (mole) flow rates of the components. Table 4 shows the details of the equations in each piece of equipment. The number of equations is calculated on the basis of each piece of equipment. Material balance and energy balance must be satisfied for all equipment. Vapor/liquid equilibrium is applied to the separator vessel. The heat and pressure loss in the process is assumed to be negligible. The vessel is assumed to be isobaric and isothermal. Eq. (1) indicates the number of degrees of freedom [39]. Here, N LNG and N LN2 are the number of compositions of LNG and LN2, respectively.

NDOF ¼ Nv  N e ¼ NLNG þ NLN2 þ 7

ð1Þ

Table 3 Number of variables for streams. Contents

Number of variables

Streams for LN2 Streams for LNG

3NLN2 + 6 6NLNG + 12

Table 4 Number of equations for equipment. Contents

Number of equations

Heat exchangers Valve Separation vessel

NLNG + NLN2 + 3 NLNG + 1 2NLNG + 4

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The independent variable is a necessary input to determine the process. The number of independent variables (N IV ) is defined as the difference between the number of DOF and the number of boundary conditions ðN BC ). The boundary conditions are shown in Table 5. The number of independent variables is calculated as follows:

NIV ¼ NDOF  NBC ¼ NLN2 ¼ 1

ð2Þ

The pressure of the LNG product, which is easy to control using the J-T valve, is set as an independent variable and changed from 1 to 10 bar. The maximum pressure is set to 10 bar based on the maximum design pressure of a commercial LNG truck. 2.2. Transportation site The LNG products and LN2 refrigerant are transported on road by heavy trucks. Because LNG and LN2 are cryogenic liquids, the truck should be equipped with a cryogenic pressurized tank. It is assumed that one LNG production site corresponds to one LN2 production site to investigate a single train of the LNG supply chain. Regarding the application of this chain to the industry, several LNG production sites can be connected to a LN2 production site and vice versa. The variables in the transportation are the pressure of the transported LNG and the distance between the LNG and LN2 production sites. The LNG pressure is assumed to be in the range of 1–10 bar as is identical to those in the liquefaction process. The distance is changed from 500 to 4000 km, considering the geographical characteristics of the US energy market. The heat ingress from the ambient air to LNG and LN2 during transportation is assumed to be negligible. Eq. (3) shows the requirement needed to satisfy the volumetric balance, which stems from the mass balance in the entire chain. Here, N, V, T, and M are the required number of trucks, transport capacity of a truck, operation time for a round trip, and required amount of liquids transported per unit time, respectively.

NV ¼T M

ð3Þ

Table 5 Number of boundary conditions. Boundary conditions

No.

Feed gas composition LN2 pressure Saturated LN2 feed Saturated LNG product Minimum approach temperatures NBC

NLNG + 2 1 1 1 2 NLNG + 7

Eq. (4) shows the required operation time of a truck for a round trip. Here D, U, and L are the distance between the liquefaction process and the LN2 production sites, average velocity of a truck, and loading/unloading time, respectively.

T ¼ 2  D=U þ L

ð4Þ

2.3. Liquid-nitrogen production site LN2 is produced in the ASU with the cold energy of the LNG. However, the ASU is not covered in this paper. To evaluate the economics of the LNG supply chain without demonstrating the ASU, LN2 is assumed to be bought from the ASU that uses the LNG cold energy. Fig. 4 shows the simplified version of the LNG supply chain with the LN2 purchased from the ASU. The cost of LN2 is categorized into the refrigerant cost in the LNG production site. 3. Methodology of economic evaluation 3.1. Life cycle cost analysis The proposed LNG supply chain is evaluated in terms of the life cycle cost (LCC), the total required cost during the life cycle of the entire chain. This cost includes all expenditures for procurement, construction, operation, maintenance, etc. The LCC is generally divided into capital expenditures (CAPEX) and operation expenditures (OPEX). The LCC shows how economic a process is and whether it is feasible in the early design stage [40]. 3.1.1. LCC of the LNG production 3.1.1.1. CAPEX of the LNG production. CAPEX is defined as the total capital for the initial investment. It is the sum of the fixedcapital investment and the working capital. The former is the required cost to supply manufacturing and all necessary plant components for complete operation, while the latter is the required cost to prepare for stocks of raw materials, products, semi-products, and byproducts as well as accounts, taxes, and cash kept on hand for monthly payment of operating expenses. The percentage of delivered-equipment cost method is used to estimate the CAPEX. This method requires the information of the delivered-equipment cost to determine the CAPEX. The other expenditures of the CAPEX are estimated as percentages of the delivered-equipment cost. Eq. (5) summarizes this method. Table 6 shows the details of the CAPEX [32].

X ðE þ f 1 E þ f 2 E þ f 3 E þ    þ f n EÞ X ¼E ð1 þ f 1 þ f 2 þ f 3 þ    þ f n Þ

CAPEX ¼

ð5Þ

E is the delivered-equipment cost, and f 1 ; f 2 ; f 3 ; . . . ; f n are multiplying factors (percentages of the delivered equipment cost) for instal-

Fig. 4. Simplified LNG supply chain with bought LN2.

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J. Kim et al. / Applied Energy 182 (2016) 154–163 Table 6 Detail items of CAPEX of LNG production [40].

Table 8 Detail items of OPEX of transportation [45]. Percentage of deliveredequipment cost (%)

Normalized percentages (%)

Purchased equipment (Delivered) Purchased equipment installation Instrumentation and controls Piping Electrical equipment and materials Building Yard improvements Service facilities

100

16.8

47

7.9

36 68 11

6.1 11.5 1.9

18 10 70

3.0 1.7 11.8

Engineering and supervision Construction expenses Legal expense Contractor’s fee Contingency

33 41 4 22 44

5.6 6.9 0.7 3.7 7.4

Working capital

89

15.0

Total

593

100

Contents

Direct cost

Indirect cost

Items

(USD/km)

Fuel & oil Repair & maintenance Truck insurance premiums Permits and licenses Tires Tolls Driver wages Driver benefits

0.33 0.08 0.04 0.02 0.02 0.01 0.27 0.09

Total

0.86

expenditure in the transportation site. Table 8 shows the details for the OPEX [45]. The costs include fuel, maintenance, insurance, permits, tires, tolls, and labor. Eqs. (6) and (7) show how the CAPEX and OPEX are calculated. The commercial truck and trailer are selected to estimate the CAPEX and OPEX. The truck capacity is assumed to 48 m3 on the basis of a commercial truck. Both the assumed loading and unloading periods are 4 h [46].

CAPEX ¼ 0:5  N

ð6Þ

OPEX ¼ 0:86  D  2  N  20  8760=T

ð7Þ

3.2. Life cycle profit analysis lation, piping, working capital, etc. These factors are determined using the complexity, required materials, and type of process. The cost of the purchased equipment is estimated using the Aspen Capital Cost Estimator (ACCE) [30]. The ACCE provides the equipment cost based on the results of the process simulation. 3.1.1.2. OPEX of the LNG production. OPEX is the operational expenditure that is spent to operate the system during the lifespan of the chain. To turn the inventory into the product, the system requires a number of costs such as operating labor, utility cost, maintenance and repair, operating supplies, local taxes, insurance, and plant overhead costs. Several items in the OPEX are based on the CAPEX information. The price of LN2 reflects the LCC of the LN2 production site. The original price of LN2, which is produced by a normal ASU, is approximately 80 USD/ton in bulk [41]. When the cold energy of the LNG for the ASU is used, the LN2 cost decreases to 30 USD/ton [42]. The operating labor cost is estimated from the operating labor hours and unit labor cost. The operating labor hours are obtained using the plant capacity, processing step, and characteristics of the plant [43]. Table 7 shows the details of OPEX in the liquefaction process. 3.1.2. LCC of transportation 3.1.2.1. CAPEX and OPEX of transportation. CAPEX of transportation is the cost of trucks and trailers. The cost of the truck is assumed to be 0.5 million USD [44]. There are several items for operation

Table 7 Detail items of OPEX of LNG production. Items

Methodologies

Operating labor Refrigerant cost

Using operating labor requirements [43] Price of LN2 (From LN2 production site), 30 USD/ton [42] 7% of CAPEX

Maintenance and repair Operating supplies Local Taxes Insurance Plant overhead costs

15% of maintenance and repair 3% of CAPEX 1% of CAPEX 60% of the maintenance and repair

The life cycle profit analysis is used to economically evaluate a system or a chain using the LCC and revenue of the life cycle [47]. The life cycle profit (LCP) is the difference between the revenue of the life cycle and the LCC. The LCP reflects the total profit earned during the life cycle of the entire chain. The LCP shows how profitable a process is in the early design stage. In the proposed LNG supply system, the revenue from the LNG product is the only source of incoming cash flow. The price of the LNG is assumed to be 9 USD/MMBtu [48]. The profit from the effect of eliminating the regasification process is not considered. The related assumptions for LCC and LCP analyses are shown in Table 9. The TIPS (Treasury Inflation Protected Securities) 10-year real discount rate is used to estimate the costs and profits with response to the uncertainty of inflation rate in the future [49]. The annual operating hours can be assumed to 8760 h/yr because of the high availability of the liquefaction process. 4. Results & discussions 4.1. LNG production The CAPEX of the LNG production at 1 bar is larger than that of any other cases with a higher production pressure, as shown in Fig. 5. The LNG temperature in the equipment also increases with the LNG pressure. The LNG used during the process decreases the cryogenic load of the equipment with increasing temperature. As a result, the material for the cryogenic vessel is replaced by inexpensive steel. When the pressure is over 4 bar, the CAPEX insignificantly changes because the temperature of LNG in the equipment becomes noncryogenic. Fig. 6 indicates that the OPEX of LNG production decreases with the product LNG pressure. The LN2 cost is the only raw-material Table 9 Assumptions for LCC and LCP analyses. Assumptions

Value

Lifetime (years) Annual operating hours (h/yr) 10-year real discount rate (%) [49]

20 8760 0

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the two main reasons. First, the liquefaction process uses a remarkably small number of instruments and does not need any high-cost turbo-machinery. Second, the price and amount of LN2 account for the high OPEX. The LCC of the liquefaction process is 1.6–1.7 USD/ MMBtu, depending on the LNG pressure.

CAPEX (MMUSD)

0.6

0.4

4.2. Transportation

0.2

0.0 1

2

3

4

5

6

7

8

9

10

Pressure (bar) Fig. 5. CAPEX of LNG production.

cost that is used to account for the largest percentage of the OPEX in the liquefaction process. When the LNG temperature is increased, the liquefaction duty that LN2 should take during the process decreases and so does the amount of LN2 required for the liquefaction. The other OPEX items such as maintenance, taxes, and insurance also tend to decrease with the pressure because they are mostly proportional to their CAPEX. The LCC or the sum of the CAPEX and OPEX is shown in Fig. 7. Because the OPEX dominates, the LCC and OPEX share a similar tendency. The OPEX is much higher than the CAPEX because of

Fig. 8 indicates the LCC of transportation when the distance between the production sites is set at 1300 km. The LCC is maximized at the lowest pressure and minimized around 7 bar. Note that the LCC varies in a discrete manner because it depends on the number of operating trucks. It is necessary to know the amount of transported LNG and LN2 for estimating the transport cost. Fig. 9 shows that the transported amount of the liquids in this process is minimized at 7 bar. When the LNG temperature is increased, the following two important results are observed: the required amount of LN2 decreases, and the density of the LNG decreases. As a result, the mass and volumetric flow rates of LN2 decrease, and the volumetric flow rates of the LNG increases. The transported amount is the larger of the LNG and LN2 flow rates. Consequently, during truck operation, if the LNG pressure is 1–6 bar, the LN2 tank is full, whereas the LNG tank is partially filled. When the pressure is approximately 7 bar, where the LNG and LN2 transported rates are equal to each other, both the LN2 and LNG tanks are full. If the pressure is less or greater than this pressure, at least one of the LNG and LN2 tanks

Fig. 8. LCC of transportation. Fig. 6. OPEX of LNG production.

Fig. 7. LCC of LNG production.

Fig. 9. Required amount of transported liquids.

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is partially filled. This transported amount value remains invariant with respect to the distance between the LNG and LN2 production sites. Fig. 10 shows the CAPEX of transportation, which depends on the distance. The CAPEX linearly increases from 0.075 to 0.35 USD/MMBtu with the distance. When the distance increases, the number of trucks should also be increased accordingly to satisfy the mass balance and maintain the steady state. Deviation from the linearity occurs because of the discrete number of trucks. The OPEX of the transportation varies from 1 to 8 USD/MMBtu, as shown in Fig. 11. Because the fuel cost, labor cost, and maintenance cost account for the major percentages of the OPEX, the OPEX rapidly increases when the distance increases. Fig. 12 demonstrates the LCC of transportation varying from 2.8 to 9.8 USD/MMBtu. This result shows that the LCC of transportation dominates that of the LNG liquefaction and LN2 production. During the transportation, the OPEX is larger than the CAPEX.

Fig. 12. LCC of transportation.

4.3. LNG supply chain The LCCs of the LNG supply chain at a distance of 1300 km are shown in Fig. 13. The LCC is minimal when the pressure is 7 bar. The value of 7 bar is the optimal point because the CAPEX decreases with the product pressure, and the amount of transport and OPEX in the transportation site are minimized at 7 bar. Fig. 14 shows the chain LCC on the entire LNG supply chain. The LCC is the sum of the LCC of the LNG production, transportation,

Fig. 13. LCC of LNG supply chain (pressure).

Fig. 10. CAPEX of transportation.

Fig. 14. LCC of LNG supply chain (distance).

Fig. 11. OPEX of transportation.

and LN2 production site. When the distance increases, the LCC of transportation becomes dominant. The LCC for the entire chain varies from 2.8 to 9.8 USD/MMBtu. The LCPs from the LNG supply chain are shown in Fig. 15. The price of LNG, which is directly linked with the revenue, is assumed to be 9 USD/MMBtu. These data show that the LCP is maximized at

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Fig. 15. LCP from LNG supply chain.

Fig. 17. LCPs with sensitivity analysis (LNG price).

The established assumptions in this paper are changed considering the market conditions. The sensitivity analyses are conducted for the changeable LNG price, LN2 cost, and flowrate of LNG product. The LNG price is the unique source of revenue that stems from the natural gas, while the LN2 cost is the dominating OPEX component for the LNG liquefaction process. The life cycle cost analysis considering changes in the flowrate of the LNG product shows the economic feasibility for various sizes of small-scale stranded gas sources. Fig. 16 shows the sensitivity analysis regarding the flow rate of the LNG product. The SMR process and the nitrogen expansion process are compared to evaluate how economically beneficial the process is. The LCCs of the liquefaction sites are estimated at product flowrates of 2.5, 5, 10, 20, 30, and 40 ton/h. The result shows that when the LNG flowrate is under 27 ton/h, the suggested liquefaction process is more economical than the conventional liquefaction processes. On top of that, the cost difference with the

conventional process increases as the LNG flowrate becomes smaller. The specific LCCs of the conventional liquefaction cost were based on a commercial brochure of small-scale LNG modular [50]. The additional benefits of the proposed process, owing to the other advantages such as high reliability, availability, robustness, flexibility, and easiness to modularize and transplant, are not taken into account in this result. These benefits make the process attractive, even though the LNG flowrate becomes over 27 ton/h. Fig. 17 shows the LCPs from the LNG supply chain when the LNG price varies from 6 to 12 USD/MMBtu. The range of the investigated LNG price is based on the historical and geographical data from the US LNG market. The profitable distance increases when the LNG price increases. The proposed LNG supply chain can always make profits if the distance is under 2000 km. When the LNG price is over 10 USD/ MMBtu, this supply chain is profitable up to at least 4000 km. The profitable distance increases by 500 km and the LCP increases by 100 MMUSD, as the LNG price increases by 1 USD/MMBtu. Fig. 18 shows the sensitivity of LCP depending on the LN2 cost. The LCPs are estimated when the LN2 cost changes from 30 to 50 USD/ton. The range of the investigated LN2 prices is conservatively assumed, considering the cases that the LNG’s cold energy is less efficiently utilized. The LN2 cost affects the LCP less than the LNG price. As expected, the cost of LN2 is inversely proportional to the LCP.

Fig. 16. LCCs of liquefaction process with variations of flowrates.

Fig. 18. LCPs with sensitivity analysis (LN2 price).

approximately 7 bar. The distance-axis intercept indicates the maximum profitable distance using this LNG supply chain. When the LNG pressure is 7 bar, the LCP is maximized, and so is the profitable distance. 4.4. Sensitivity analyses

J. Kim et al. / Applied Energy 182 (2016) 154–163

5. Conclusions This study proposed and evaluated a new LNG supply chain to recover natural gas that is reserved on a small scale or being flared. The LNG supply chain consisted of three sites: an LNG production site, a transportation site, and an LN2 production site. The natural gas was liquefied with the cold energy of LN2 in the LNG production site. LN2 was separated and liquefied in the LN2 production site. In the transportation site, LN2 and LNG were transported on road by trucks. The LCP and LCC in the LN2 production site were reflected in those of the LNG production site based on several assumptions. In the LNG production site, the LCC tended to decrease with the increase in the LNG pressure. The LCC on the transportation was minimized, which implies that the LCP was maximized at the product pressure approximately equal to 7 bar. Additionally, the LCC of the entire chain linearly increased with the increasing distance between the sites. The sensitivity analyses were conducted to consider the fluctuation of the price of LNG and the cost of LN2. This study showed that the LNG supply chain can be a solution to flaring gas and monetizing the small-scale stranded natural gas. Additional research for the LN2 production site will be conducted. The study for the ASU using pressurized LNG is also required to improve the efficiency of the process. Acknowledgements This research was supported by a Grant from the LNG Plant R&D Center funded by the Ministry of Land, Infrastructure and Transport of the Korean government. References [1] Kargbo DM, Wilhelm RG, Campbell DJ. Natural gas plays in the Marcellus shale: challenges and potential opportunities. Environ Sci Technol 2010;44 (15):5679–84. [2] U.S. Energy information administration (EIA). Shale gas production: ; 2009–2013. [3] Mokhatab S, Poe WA. Handbook of natural gas transmission and processing. Gulf Professional Publishing; 2012. [4] Attanasi ED, Freeman PA. Role of stranded gas in increasing global gas supplies (No. 2013-1044). US Geological Survey; 2013. [5] Tan SH, Barton PI. Optimal dynamic allocation of mobile plants to monetize associated or stranded natural gas, part I: Bakken shale play case study. Energy 2015;93:1581–94. [6] Horwitt D. Up in flames: U.S. shale oil boom comes at expense of wasted natural gas, increased CO2. Washington, D.C., USA: Earthworks; 2014. Available from: . [7] Khalilpour R, Karimi IA. Evaluation of utilization alternatives for stranded natural gas. Energy 2012;40(1):317–28. [8] Wood DA, Nwaoha C, Towler BF. Gas-to-liquids (GTL): a review of an industry offering several routes for monetizing natural gas. J Nat Gas Sci Eng 2012;9:196–208. [9] Beronich EL, Abdi MA, Hawboldt KA. Prediction of natural gas behaviour in loading and unloading operations of marine CNG transportation systems. J Nat Gas Sci Eng 2009;1(1):31–8. [10] Chang HM. A thermodynamic review of cryogenic refrigeration cycles for liquefaction of natural gas. Cryogenics 2015;72:127–47. [11] Venkatarathnam G. Cryogenic mixed refrigerant processes. In: Timmerhaus KD, editor. New York: Springer; 2008. p. 262. [12] Al-Sobhi SA, Elkamel A. Simulation and optimization of natural gas processing and production network consisting of LNG, GTL, and methanol facilities. J Nat Gas Sci Eng 2015;23:500–8. [13] Kumar S, Kwon HT, Choi KH, Lim W, Cho JH, Tak K, et al. LNG: an eco-friendly cryogenic fuel for sustainable development. Appl Energy 2011;88 (12):4264–73. [14] Kohler T, Bruentrup M, Key RD, Edvardsson T. Choose the best refrigeration technology for small-scale LNG production. Hydrocarbon Process 2014:45–52. [15] Thomas S, Dawe RA. Review of ways to transport natural gas energy from countries which do not need the gas for domestic use. Energy 2003;28 (14):1461–77. [16] Mokhatab S, Mak JY, Valappil JV, Wood DA. Handbook of liquefied natural gas. Gulf Professional Publishing; 2013. [17] Remeljej CW, Hoadley AFA. An exergy analysis of small-scale liquefied natural gas (LNG) liquefaction processes. Energy 2006;31(12):2005–19.

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