Natural gas and grid electricity for seawater desalination: An economic and environmental life-cycle comparison

Desalination 414 (2017) 89–97

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Desalination journal homepage: www.elsevier.com/locate/desal

Natural gas and grid electricity for seawater desalination: An economic and environmental life-cycle comparison Carla Cherchi a,⁎, Mohammad Badruzzaman a, Larry Becker b, Joseph G. Jacangelo a,c a b c

MWH, now part of Stantec, Inc., 300 N. Lake Avenue, Suite 400, Pasadena, CA, USA Power Engineers, 22035 70th Ave S, Kent, WA, USA The Johns Hopkins University Bloomberg School of Public Health, 615 N. Wolfe Street, Baltimore, MD 21205, USA

H I G H L I G H T S • Grid electricity and onsite power generation using LNG were compared based on LCC. • Environmental benefits of onsite power generation using LNG/NG were assessed. • Key factors impacting the life cycle cost comparison were identified.

a r t i c l e

i n f o

Article history: Received 19 October 2016 Received in revised form 9 March 2017 Accepted 14 March 2017 Available online xxxx Keywords: Desalination Power generation Natural gas Grid electricity Life cycle assessment

a b s t r a c t In recent years, natural gas (NG)- and liquefied natural gas (LNG)-based power generation options have been considered as a potential alternative to grid electricity at desalination plants to reliably meet the increasing energy demand and reduce the associated environmental impacts. This study comparatively evaluated on a life cycle basis the economic and environmental cost-benefits of LNG/NG for self-generation of power with those of the grid electricity supply. The analysis conducted showed that for desalination plant sizes of 75– 570 ML/day, the LNG-based onsite power generation option is 20–30% more economical than the alternative connection to the grid. However, the life cycle cost (LCC) of the LNG-based onsite power generation system is from 43% to up to 86% higher than the NG-based counterpart for desalination plant sizes that increase progressively from 10 to 570 ML/day. A sensitivity analysis conducted on two conceptual mid-range capacity seawater desalination plants showed that variations in the electric tariff rate, fuel cost, plant efficiency, and economic parameters affect the LCC of various power supply options. The study also showed that when the grid electricity with a cleaner mix (i.e., low emission factor) is available, this option results in lower GHG emissions than the LNG/NG power source alternatives. © 2017 Elsevier B.V. All rights reserved.

1. Introduction Municipalities and water suppliers are increasingly considering seawater desalination to supplement inadequate freshwater sources worldwide [1,2]. Despite the technical improvement in desalination technologies, seawater desalination still remain a high energy intensive process compared to more conventional treatment systems [3]. Typically, the total energy requirement for seawater desalination using reverse osmosis (RO), including pre- and post-treatment, is on the order of 3 to 6 kWh/m3 [3,4]. In addition, the grid electricity, traditionally selected as preferred power supply option at desalination plants, often relies on the use of conventional fossil fuel resources, known to be responsible for emission of air pollutants and significant GHG emissions [5]. CO2 ⁎ Corresponding author. E-mail address: [email protected] (C. Cherchi).

http://dx.doi.org/10.1016/j.desal.2017.03.028 0011-9164/© 2017 Elsevier B.V. All rights reserved.

emissions of 1.78 kg/m3 and NOx emissions of 4.05 g/m3 of desalted water have been reported for an RO system used to desalinate seawater with traditional fossil fuel-based energy sources [4,6]. In California, the proposed 2 Mm3/day seawater desalination capacity is estimated to increase energy use by about 2800 GWh per year with related GHG emissions of about 1.0 MMTCO2e annually, assuming that all of the desalination plants are powered by the electricity grid [7]. To reliably meet the increasing energy demand and reduce cost and the associated environmental impact, desalination utilities often look for a diversified portfolio of energy alternatives to grid electricity based on conventional fossil fuels. In recent years, the development and use of nonconventional fossil fuel resources, such as shale natural gas (NG) and liquefied natural gas (LNG) have been considered as potential alternatives to meet this demand [5]. To date, the application of NG power plants for operating seawater desalination has been primarily located in regions, such as the Middle

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East, where natural gas is readily available at a low price [8]. The liquefaction process, where the NG volume is reduced by 600 times, makes LNG more economical to store and transport than NG and provides opportunities to store NG to meet peak demand electricity periods [9]. However, the LNG option to power desalination is not widespread in other parts of the world and only available in regions, such as Singapore, where the pipeline infrastructure for the natural gas option is limited or nonexistent [10,11]. The cost of NG, and consequently that of LNG, has declined over the last couple of years, primarily because of increased domestic production, making NG a feasible economic choice compared to other fuels. The U.S. Energy Information Administration (EIA) forecasted that NG will continue increasing as a share of overall U.S. energy production in the coming decades because of the continued expectation that the cost of NG will remain low [12]. In addition, the spot market of LNG has emerged in recent years because of an increase in the number of LNG tankers, the overcapacity in liquefaction worldwide, and increased contractual flexibility [9]. In evaluating the environmental impact of these alternatives to fossil fuels, the U.S. EPA reported that burning NG for electricity generation results in lower quantities of nitrogen oxides, carbon dioxide, and methane emissions, with the latter two being greenhouse gases [13]. In Israel, where a number of power generation plants supply power to desalination plants, NG-driven power generation produces only 20% of the CO2 emissions generated by coal power plants and is also 7–8% cheaper than the energy provided by the national coal-based power system, thus providing opportunities to further reduce the cost of producing the desalinated water [14]. The liquefied option of NG is cleaner upon removal of all higher hydrocarbons, inert components (N2 and CO2) and most impurities. LNG also has a higher Wobbe Index—the measure of the amount of energy delivered to a burner via an injector—than pipeline NG, making it a more sustainable alternative to fossil fuels to power desalination plants [15]. The 2011 U.S. GHG Inventory estimates that the contribution of methane from LNG operations represents 1.3% of methane emissions from all the segments that make up the NG systems [13]. In addition to being a lower carbon intensity fuel, NG combustion technology has become substantially more efficient over the years. In 2011, the CEC reported that the efficiency gain in California's gas-fired power plant fleet since 2001 was N 24% [16]. The benefits and challenges of the application of LNG is inherently dependent on its geography-driven abundance, technological and economic scale-up issues associated with engines/turbines, maturity of the technology, storage and transmission capabilities, environmental impacts and overall, on the familiarity of utility managers and policy makers with key implementation matrices. As availability of NG and LNG is continuously growing in the United States and other parts of the world, LNG/NG-powered desalination may be a feasible alternative to energy from an electrical grid. However, to date, the majority of the recent peer-reviewed literature on energy portfolios to power desalination utilities and related energy independence concepts focused on renewable energy sources [4]. Despite the growing interest in the US for co-located configurations, no systematic study has been conducted to identify the economics and environmental benefits of LNG/NG power plants solely designed to operate a desalination plant. Economic information on different power supply options at existing or proposed desalination applications are rarely found in the public domain and mostly the domain of private entities. In addition, most of the cost information available is based on the first-year present cost value; life cycle cost analyses are often lacking. This study aimed at filling these gaps by providing a more perspicuous understanding of the application of LNG/NG for self-generation of power at desalination plants as an alternative to grid electricity. This paper will assist designers, practitioners and decision-makers that face the challenge of selecting the appropriate energy mix to power desalination plants and provide reference values, with a sensitivity analysis on impacting parameters, on life cycle cost and GHG emissions. The main objectives of this study were to:

• Perform an economic analysis of the application of LNG/NG for power generation at desalination facilities; • Compare the grid electricity and LNG/NG-based power generation based on life cycle cost (LCC) analysis; • Identify the factors impacting the life cycle costs through sensitivity analysis on a set of parameters (electric tariff rate, fuel cost, plant efficiency, and economic parameters); and • Perform life cycle environmental benefits/impacts of incorporating LNG/NG at desalination facilities was also developed.

2. Materials and methods The cost and environmental analysis developed for this study incorporates three power supply options: on-site power generation using NG as a primary fuel, on-site power generation using the LNG alternative, and the sole power grid option. Fig. 1 summarizes the different alternatives considered.

2.1. Design specification of NG/LNG power generation plants On-site LNG and NG power generation plants of 5 to 100 MW size were considered for developing conceptual designs for 10 to 570 ML/day desalination plants. The correlation factor used in this study to determine the total unit energy requirement of a seawater reverse osmosis desalination plant (4.07 kWh/kL) was obtained from a seawater desalination plant demonstration study conducted in California [17]. From this reference study, the process requiring most of the energy per unit of water produced is the operation of high-pressure pumps (49%), followed by the product water energy use (31%), operation of other RO pumps (13%), desalination plant intake (5%) and the remaining by facility's energy needs, solid handling and membrane cleaning systems. Typically, pilot or demonstration studies are recommended to estimate the energy consumption values for SWRO influenced by feed water recovery, intrinsic membrane resistance (permeability), operational flux, feed water salinity and temperature fluctuations, product water quality requirements, and system configuration (e.g., use of energy recovery devices). This study does not provide guidance on how to determine the energy use at the desalination plant; rather it focuses on the life cycle cost analysis of different power source alternatives. Table 1 summarizes the details on the configuration and main process components of the LNG/NG power generation plants selected for this study. Power plants operating in simple cycle or combined cycle modes were considered depending on the plant power output. Typical process components of a NG simple cycle power generation plant include the prime mover and generator; whereas in a combined cycle configuration an additional steam cycle is integrated including a heat recovery system, steam turbine, and a generator. From an economic standpoint, the use of engine generators is the preferred option for smaller size plants (5–10 MW); however gas turbines and combined cycle processes are preferred for power generation plants of sizes N20 MW. Frame size gas turbines were considered for power plant sizes N75 MW, whereas for lower sizes the aeroderivative counterparts were preferred. When LNG is selected as the fuel option, regardless of the power plant configuration, a regasification process is needed to regasify the LNG into NG for use by the gas engines or turbines. For this study, the intermediate fluid vaporizers (IFVs), which uses an intermediate heat transfer fluid, was considered to revaporize LNG before delivery to the prime mover. An air emission control systems, a selective catalytic reduction unit that removes nitrogen oxides prior to the air heater and uses ammonia and a catalyst to reduce nitrous oxides, was considered for both simple and combined cycle options.

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Fig. 1. Power supply options considered for this study.

2.2. GT-pro modeling of power plant performance and cost For this study GT PRO (Thermoflow, Inc.) was used as a software design tool for identifying the physical equipment of combined cycle, cogeneration systems, and simple cycle gas turbine power plants and for the development of the cycle heat balances. For each size, specific engine/turbine manufacturer, their models and typical components, and range of operating performance (e.g., efficiency) were chosen. An addon module of GT-PRO, named PEACE (Plant Engineering and Cost Estimator), was used to provide engineering details and cost estimation for the options listed in Table 1, on roughly thirty-five components, covering heat recovery boilers, feed water heaters, wet condensers, cooling towers, air-cooled condensers, piping, pumps, and others used to model balance-of-plant components and sub-systems. The logical cost functions for all equipment and balance-of-plant were derived by PEACE from the detailed hardware specifications, so that any design change

was immediately reflected in corresponding changes in both performance and cost. The cost estimate, as developed from the GT PRO software, was indicative of the project based on the averages of equipment suppliers pricing in the marketplace although actual costs will be dependent on the technology, power plant location, freight costs, product line, and efficiency. In general, the GT PRO cost estimate closely represents the equipment price of a particular size category and might be within 10 to 20% of the budgetary cost provided by other competitive vendors. The information collected through GT-PRO simulations was used to develop the cost curves for each of the thirty-five elements and develop the capital costs for the power generation plants selected. Examples of these cost curves for the power generation plant main equipment are presented in Fig. 2 and include the gas turbine, steam turbine, heat recovery boiler, water cooled condensers, fuel gas compressor, and emission control system (Fig. 2).

Table 1 NG/LNG power plants coupled with desalination selected for this study. Plant size

Configuration

Prime mover

Steam turbine

5 MW

Simple cycle Combined cycle Simple cycle Combined cycle Cogeneration plant Combined cycle Combined cycle - aeroderivative CTG Combined cycle - aeroderivative CTG Combined cycle - frame based CTG Combined cycle - frame based CTG

Engine generator Engine generator Engine generator Engine generator Gas turbine Gas turbine Gas turbine Gas turbine Gas turbine Gas turbine

N/A 1–2 MW N/A 1–2 MW N/A 5–8 MW 20–30 MW 40 MW 40 MW 40–50 MW

10 MW 20 MW 50 MW 75 MW 100 MW

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Fig. 2. Empirical equation estimation for cost of selected equipment for different power plant sizes.

Empirical equations were also derived for the civil and mechanical work as well as the electrical assembly and wiring that is required for the installation of such power plants (data not shown). From these cost curves, the empirical equations of costs were estimated and used as a basis to develop the LCC analysis presented in the following sections. 2.3. Design specification and cost estimation of grid electricity Desalination plants with electrical loads need a connection to the electrical power grid for their source of power provision or redundancy [18]. The selection of the interconnection to the power grid is influenced by a number of factors such as the electrical loads of the facility as well as the proximity of electrical facilities to the desalination site. The electric loads associated with desalination plants of 10 to 570 ML/day can be interconnected using distribution systems for new loads not exceeding 10 MW distribution (system voltage 34.5 kV or less), or sub-transmission systems for loads between 10 MW and 100 MW (typically 66 kV through 138 kV). In this study, for distribution systems the cost of a dedicated feeder, with a thermal capacity of 10 MW from an existing substation with sufficient capacity to serve the new load, was estimated at $250,000, in addition to $100,000 or $250,000 per mile of overhead or underground feeder, respectively. Sub-transmission systems provide power over an area typically within 10 miles of its origin at a substation with a connection to the transmission system and require a dedicated substation due to the higher system voltage of that required by the desalination plant. The estimated cost of a substation includes many features such as major equipment (e.g., transformer that coverts the voltage from the incoming line down to a voltage appropriate for a distribution system), permitting, engineering and design, construction, project management, testing and commissioning, and a contingency allowance. For this study, the cost was estimated at $6M for a substation with a primary connection to a sub-transmission system and a rate of $1M per mile as an approximation of the cost of the transmission line from the point-of-interconnect to the new substation. The cost of interconnecting a desalination plant to the grid was estimated and used as guidance for developing the LCC. 2.4. Cost and environmental life cycle cost analysis The elements of the conceptual design and operating parameters of the gas engines/turbines and their related capital and operations and maintenance (O&M) cost information were used to conduct the economic and environmental life cycle comparison between purchasing

electricity directly from the power grid and the use of commercially supplied LNG/NG for self-generation of power for desalination processes. An Excel-based spreadsheet was developed to estimate the total first year cost and LCC (capital and O&M), the levelized cost of energy (LCOE) and the first year and life cycle GHG emissions of different options. A list of assumptions including life cycle, financial and economic parameters were considered for the economic and environmental assessment of different project alternatives. Costs were discounted to a base year by using a present value (PV) analysis of all the future capital and annual costs, by first computing a future value at a given year (using an appropriate escalation rate) and then computing the PV of that future value (FV) at a year n using an appropriate discount rate, based on Eqs. (1) and (2). x

FV ¼ ∑ C n  ð1 þ pÞn 1

x

PV ¼ ∑ 1

FVn ð1 þ iÞn

ð1Þ

ð2Þ

where Cn is the cost at year “n” for the above indicated cost categories; n is the total number of years being considered; p is the expected average rate of cost escalation; i is the discount rate; and x is the number of cost elements. For this study, the life cycle period, the time over which projected capital costs and annual costs of project options are evaluated, was set to 25 years. The year at which the present values of all future LCC were determined was set in 2015, which was also the cost estimate dollar basis year. The year 2017 was instead selected as the initial year of operation, the first year of the life cycle period that follows the construction period. The construction cost escalation and O&M and general cost escalation were 3.5% and 3.0%, respectively. For this study, all LCC capital costs were assumed to be long-term debt financed, with a debt financing interest rate of 5.25% and a financing maturity of 25 years. As part of the economic assumptions, a 5.25% discount rate for computing present values of future costs, based on risk-adjusted cost of capital, was considered. In addition, a 2% growth in electricity consumption was assumed. The LCOE was also used as a metric to compare the cost of energy generated by the different power generation options and represents the cost per kilowatt-hour of building and operating a power generation alternative given an assumed life cycle. The LCOE was calculated using Eq. (3):

LCOE ¼

! N LCC dð1 þ dÞ  N Q ð1 þ dÞ −1

ð3Þ

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where LCC is the present value of the LCC; Q is the annual energy output (kWh); N is the analysis period; and d is the discount rate. Life cycle GHG emissions were also estimated for the proposed alternatives. For LNG and NG-based on-site power generation options, the GHG emitted are from direct emissions caused by the use of the fuel, whereas for grid electricity connections, the electricity usage is responsible for an indirect production of GHGs. The accuracy in calculating GHG emissions from energy usage is directly dependent on the accuracy of the data available for energy utilization and associated GHG emission factors per unit of energy consumed. The GHG emissions were calculated using Eqs. (4) and (5) for the LNG/NG power generation plant and for the grid electricity, respectively: GHGLNG=NG ¼ EFLNG=NG  TH

ð4Þ

GHGGRID ¼ EFGRID  Q

ð5Þ

where GHGLNG/NG are the GHGs emitted by the operation of NG or LNGbased power generation plants (ton-CO2/year); GHGGRID are the GHGs emitted by the grid power (ton-CO2/year); EFLNG/NG is the emission factor for LNG/NG (ton-CO2/MMBTU); EFGRID is the emission factor for the grid (ton-CO2/kWh); and TH is the annual thermal energy of NG/LNG (MMBTU/year). The emissions factors used in this study for the NG/ LNG-based processes was 0.05306 tons CO2/MMBTU, selected for a NG higher heating value range of 1025 to 1050 BTU/scf and carbon content of 14.47 gC/MBTU [13]. For the grid electricity option, two emission factors were tested to cover two extreme emission scenarios: the U.S. EPA eGRID national average emission factor of 0.620 ton CO2eq/MWh [19] and a lower future emissions of 0.177 ton CO2/MWh, which is representative of an electric utility implementing strategies that would reduce emissions. 2.5. Sensitivity analysis A series of sensitivity analyses were carried out with variations in several important parameters that could potentially have a significant influence on the final first year or life-cycle cost of LNG-based and grid power supply options for two mid-range capacity seawater desalination plants (95 and 190 ML/day). These parameters included the purchase electricity rates and fuel costs, plant efficiencies for simple and combined cycle alternatives and financing interest rates. The parameters that were varied for the sensitivity analyses and related ranges of variations from the baseline condition are listed in Table 2. 3. Results and discussion A comparative economic feasibility and GHG emissions potential assessment of on-site LNG/NG-based power generation systems at desalination plants and grid electricity supply was conducted in this study. The comparison was based on first year and life cycle costs, levelized cost of energy and environmental impact through GHG emissions analyses. Table 2 Variability of parameters for the sensitivity analysis. Parameter

Electricity rate (purchase) Fuel purchase (for LNG) Plant efficiency (simple cycle) Plant efficiency (combined cycle) Financing interest rate a

Baseline condition.

Unit

Values tested Option 1

Option 2

Option 3

Option 4

$/kWh $/MMBTU % %

0.05 5 35 45

0.08a 8a 40 50a

0.10 10 45a 55

0.15 12 – –

%

4

5.25a

7

–

93

3.1. Comparative economic and environmental evaluation of NG/LNG versus grid A conceptual assessment of the economic feasibility and GHG emissions potential of the application of LNG/NG-based power and grid supply options was performed. The analysis was based on the estimation of total costs in the first year of operation, LCC, LCOE and GHG emissions. This comparison was performed for desalination plants of various sizes (from 10 to 570 ML/day) and two fuel options (NG vs. LNG). The findings and interpretations presented in the following sections are valid only under the assumptions presented in previous sections. 3.1.1. Life cycle cost analysis Capital and O&M costs of power plant installations vary depending on the configuration selected (simple versus combined cycle), and the size and complexities associated with the installation [20]. Fig. 3 shows the contributions to the capital and the O&M costs for a LNGbased power generation and the grid connection of 33 MW that supplies power to a 190 ML/day desalination plant. For the LNG-based option, a high share of the capital cost was for special equipment, which includes the LNG regasification system, the gas and steam turbines package of the combined cycle configuration, the heat recovery system, and others. The contractor and owner's soft miscellaneous costs were the other major expenses that follow the equipment cost, while the expenses related to the total project engineering, procurement, and construction costs accounted for approximately 20% of the total capital cost. Similarly, the equipment cost for the grid connection represented approximately 50% of the total capital expenses for the purchase of the substation, on-site transformers, and interconnections. The estimation of capital costs for both power supply options did not include any potential cost for land acquisitions to build the power plant or the transmission costs of a grid electricity connection because these cost components are fundamentally site specific and can only be analyzed on a case-by-case basis. For the on-site power generation, approximately 80% of the total O&M costs were associated with the fuel consumed whereas the majority of the O&M costs for the grid electricity option were represented by the electricity cost (85%) and partially by the related demand charges (15%). As reference values for this study an electricity rate of $0.08/ kWh and a fuel purchase for NG and LNG of $3/MMBTU and $8/ MMBTU, respectively, were considered. U.S. LNG prices were quoted as low $3.00/MMBTU tolling fee (Sabine Pass – Gulf Coast) to as high as $8–10/MMBTU for non-Gulf Coast small-scale facilities (these prices do not include LNG transportation costs, which will depend on geographical market and distances) [21]. The cost of labor for the two options evaluated was minimal compared to the fuel or energy expenditures and accounts for b3% of the total O&M costs. Recently, a feasibility study performed on the Poseidon Ocean Desalination facility in California (190 ML/day estimated capacity), showed that the unit price of water will be more sensitive to energy price, with approximately 20% of the annual project expenses required to supply power [22]. Annual O&M costs at Poseidon calculated based on the year 2013 were estimated at approximately $46.7 million, with about $20.4 million to supply grid power assuming a rate of $0.09/kWh [22]. Capital and O&M costs for the first year of operation were calculated for desalination plants of sizes ranging from 10 to 570 ML/day powered by the LNG-based power generation or the grid electricity connection alternatives proposed (Fig. 4). For desalination plant sizes above 40 ML/day, the grid electricity required lower capital investments than the LNG-based options, and the gap in total capital cost between the different options increased with increasing plant size. In contrast to the trend observed for the capital investment, from an O&M cost perspective, the LNG-based options appeared to be the best solution for desalination plants of capacity above 40 ML/day, with the gap in total capital cost between the different options increasing with increasing plant size.

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Fig. 3. Breakdown of capital (top) and O&M (bottom) costs for an on-site LNG fired power generation (190 ML/day).

From a life cycle perspective, the LNG on-site generation alternative yielded lower total LCC than the grid electricity connection for desalination plant sizes that are higher than 75 ML/day (Fig. 5). For desalination plants of 75 to 570 ML/day capacity, the LCC of the LNG power generation option was between 20% and 30% lower than that of the grid connection, whereas for plant sizes smaller than 75 ML/day, the LCC for the grid alternative and that of LNG-based power generation were comparable, being within a 5 to 13% difference. Fig. 5 also shows the

breakdown of the life-cycle capital and O&M costs for a power generation facility driven by LNG for desalination plants of various sizes. The results show that the life cycle O&M costs increased over time at a greater extent than the life cycle capital costs and represented the highest share of the total LCC for this option. Life cycle O&M costs were also the major cost if a grid connection alternative was selected; however, for this specific option, a lower impact on the life cycle capital costs was observed.

Fig. 4. Total first-year capital and O&M costs for the LNG-based power generation (top) and grid electricity connection (bottom) options for desalination plants of various sizes.

Fig. 5. Total life cycle capital and O&M costs for the LNG-based power generation (top) and grid electricity connection (bottom) options for desalination plants of various sizes.

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Limited information is available in literature on the comparison of various power options that supply power to desalination plants. In a recent study, a comparison based on direct cost levelized was developed to assess feasibility of various alternative power supply technologies to the existing Federal Electric Commission power facility for a seawater reverse osmosis plant to be located at Rosarito Beach, Mexico, supplying potable water to both Mexico and the United States [23]. For this project, the use of reciprocating engines with 10 MW gross capacity showed lower direct cost levelized (8.7 cents/kWh) than 500 MW combined cycle (10.7 cents/kWh), based on fuel (NG) cost of $6.49/MBTU [23]. Fig. 6. Total life cycle costs for LNG and NG on-site power generation options for desalination plants of various sizes.

An economic comparison was also developed between LNG and NG fuel options to power desalination plants of the same size. As Fig. 6 shows, the total LCC of the LNG-based power generation system was 43% to 86% higher than the NG-based counterpart for desalination plant sizes that increased progressively from 10 to 570 ML/day. Compared to NG-based options, in fact, power generation plants that use LNG need an additional equipment including the regasification system to revaporize the LNG into gas for use (i.e., the capital cost of a regasifier was calculated based on a $60/kW). Differences in O&M costs were due to differences in fuel prices considered in this study ($3/MMBTU for NG and $8/MMBTU for LNG). It is important to note that the cost of LNG considered in this study was not inclusive of the inland transportation cost of the fuel from the LNG terminal to the desalination plant site, which is site-specific. 3.1.2. Levelized cost of energy A LCOE analysis was performed to compare the cost of energy generated by different power supplies for desalination plants of various sizes (10 to 570 ML/day) (Fig. 7). The LCOE represents the cost per kilowatthour of building and operating a power generation alternative given an assumed life cycle. The results of the LCOE analysis showed that for LNG-based power generation systems, the LCOE decreased from 19 to 11 cents/kWh with increasing size of the desalination plant from 10 to 570 ML/day. This observation is in line with the findings of previous studies, where the cost of installation for gas turbines followed economy of scale principles with larger units being more economical than smaller units on a $/kWh basis [20]. When NG fuel was selected, the LCOE values were lower than those estimated for LNG and decreased from 13 to 6 cents/kWh with increasing size of the desalination plant. For the grid electricity the LCOE was slightly affected by the desalination plant size with values between 16 and 17 cents/kWh. Therefore, the LCOE analysis performed to compare the cost of energy generated by the different power source options showed that for desalination capacities of 40 ML/day and higher, the NG or LNG based on-site power generation were lower cost options than the grid electricity.

Fig. 7. Levelized cost of energy for the NG- and LNG-based on-site power generation, and the grid electricity connection for desalination plants of various sizes.

3.1.3. Life cycle GHG emissions The power source alternatives considered in this study were also compared based on their potential to generate GHG emissions over the project life time. The GHG emissions from electricity use are a Scope 2 (indirect) type of emission and are directly dependent on the energy utilization and the GHG emission factor per unit energy consumed. Conversely, the emissions from the NG or LNG use are considered as Scope 1 (direct) emission; therefore, the accounting methodologies and site-specific regulations are different [24]. Accuracy in reporting GHG emissions is directly dependent on the accuracy of the activity data (e.g., energy or fuel use) as well as the accuracy of the associated GHG emission factors per unit energy/fuel consumed. Each LNG/ NG-powered desalination facility should follow national and regional regulation on the reporting requirements for GHG emissions and, in some cases, the reporting can be mandatory. For example, in California, electricity generating units (including cogeneration) are subject to the Regulation for the Mandatory Reporting of Greenhouse Gas Emissions (Title 17, California Code of Regulations) [25]. Fig. 8 shows the life cycle GHG emissions for the different power source options evaluated and for various desalination plant sizes. The selection of the emission factor for the power grid largely influenced the results when low GHG emission factors were used. The grid electricity option resulted in lower life-cycle GHG emissions than those of other power source alternatives. For higher emission factors, such those issued by the eGrid, the opposite was true, and the LNG power generation appeared to be the most sustainable option with life cycle GHG emitted varying from 218,000 million ton CO2 to approximately 13,000 billion ton CO2. In Israel, under the assumption that the desalination of 1 m3 of water requires 3.85 kWh, a total of 2.574 billion kg CO2 are expected to be emitted annually by a desalination capacity of approximately 2050 ML/day, projected to be achieved in 2020 [14]. 3.2. Results of the sensitivity analysis A series of sensitivity analyses were carried out for two conceptual case studies of a mid-range capacity seawater desalination plants (95 and 190 ML/day) with variations in several important parameters that

Fig. 8. Life cycle GHG emissions from the LNG/NG and two grid electricity connection options calculated with different GHG emission factors (EF) for desalination plants of various sizes.

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are critical to the cost of energy generation (e.g., electric tariff rate, LNG cost, plant efficiency, and economic parameters, such as the financing interest and discount rates). The total LCC of the project was found to be affected by possible variations in the electric tariff rate applied. In particular, for the grid electricity-based power supply option, a 24% increase in total LCC was obtained when the 8 cents/kWh electric tariff rate was increased to 10 cents/kWh and rose to approximately 85% at 15 cents/kWh. In contrast, a 36% decrease in LCC was achieved when the tariff rate was set at 5 cents/kWh. For the LNG-based power generation alternative, the total LCC was affected by variations in the costs of the fuel which is plausible in light of the high variability of the LNG prices over the long term. In particular, a 17% increase in total LCC was obtained at a LNG price of $10/MMBTU (from a $8/MMBTU baseline value) and rose to approximately 35% at $12/MMBTU fuel cost. In contrast, about a 25% decrease in LCC was achieved when the LNG price was set at $5/MMBTU. The efficiency of the power generation process also influenced the total LCC of a project. In particular, a 20% increase in total LCC was obtained by decreasing simple cycle plants' efficiency from the 45% baseline value to 35%. Conversely, about a 5% increase in LCC was achieved for combined cycle plants when the efficiency was increased from 50% (baseline value) to 55%. In general, the efficiency of electric power generation for combustion turbine systems, operating in a simple-cycle mode, ranged from 21 to 40%. About 60% efficiency was possible when the turbine exhaust heat was recovered in a heat recovery steam generator to produce steam that could either be used for mechanical/process needs or for generation of additional power in a steam turbine. The structure of financing can impact project costs, control, and flexibility, as well as affect the long-term return on investment [26]. The sensitivity of LCC to the financing interest/discount rates (e.g., 4%, 5.25%, and 7%) showed that by increasing the financing interest and discount rates from the baseline, a decrease in the total LCC was observed. An increase in the discount rate caused, in fact, a decrease in the present value of the life cycle O&M and, consequently, decreased the total LCC, because the O&M costs represented the majority (i.e., N80%) of the total LCC. For instance, for a 190 ML/day desalination plant, a 15% decrease in LCC was achieved when the financing interest/discount rate was increased from the 5.25% to a 7% value. The findings from the sensitivity analysis demonstrated that the life cycle cost of a power generation project are contingent on the assumptions made. Particularly, the cost of energy is highly volatile, impacting the cost of desalination. The understanding of the year of reference used for cost estimation is required when attempting comparative evaluations among projects. In general, this study showed that the use of alternative fuels are reliable, cleaner and economically viable alternatives to conventional fossil fuels to provide power at desalination plants and may be able to address the unpredictability of energy prices. 4. Conclusions On-site LNG/NG-based power generation at seawater desalination plants is increasingly being considered as an alternative to using the grid electricity option. The life cycle analysis conducted in this study was proven to be a powerful tool for cost and environmental assessment of various power supply options for desalination plants. This study showed that the on-site NG or LNG option for desalination plants under co-located configurations with a power generation plant has the potential to be more economically and environmentally favorable than the direct power purchase from the grid. Overall, the decision to develop gas-fueled power facilities versus connecting to the grid should take into consideration a number of issues including customer requirements (e.g., electricity demand, process energy demand, operating philosophy, financing), site-related factors (fuel,

water, space availability, legislation/emission requirements), design and operating parameters of the plant (type and number of gas turbines, single shaft versus multi-shaft, efficiency). In addition, decision makers must first understand the total annual energy requirements (base and peak power) of the desalination facility, the make-up of that power mix (e.g., the fraction of total energy requirement that will be met by LNG/NG), and the current cost of that power to determine the economic and environmental viability of the power supply options considered. Acknowledgments The authors gratefully acknowledge the financial, technical, and administrative support of the WateReuse Research Foundation (now Water Environment & Reuse Foundation) (Project Funding Agreement WRRF-13-05). We are particularly indebted to Justin Mattingly in his role as the Foundation Project Officer and to the Project Advisory Committee of the WateReuse Research Foundation. The support of Erik Hale and the Power Engineers team is gratefully acknowledged. The comments and views detailed herein may not necessarily reflect the views of the WateReuse Research Foundation, its officers, directors, employees, affiliates or agents. The authors would also like to thank Terence Lee of MWH and the Technical Advisory Committee (TAC) for their input and review of project deliverables. References [1] GWI (Global Water Intelligence), Desalination Markets, http://www. globalwaterintel.com/market-intelligence-reports/desalination-markets-2016/ 2010 (accessed March 2015). [2] K. Quteishat, Energy for desalination, Presented at Stockholm Water Week, Stockholm, Sweden, August 18 2009. [3] R. Semiat, Energy issues in desalination processes, Environ. Sci. Technol. 42 (2008) 8193–8201. [4] A. Subramani, M. Badruzzaman, J. Oppenheimer, J.G. Jacangelo, Energy minimization strategies and renewable energy utilization for desalination: a review, Water Res. 45 (2011) 1907–1920. [5] N. Ghaffour, J. Bundschuh, H. Mahmoudi, M.F. Goosen, Renewable energy-driven desalination technologies: a comprehensive review on challenges and potential applications of integrated systems, Desalination 356 (2015) 94–114. [6] R.G. Raluy, L. Serra, J. Uche, Life cycle assessment of desalination technologies integrated with renewable energies, Desalination 183 (1) (2005) 81–93. [7] H. Cooley, M. Heberger, Key Issues for Seawater Desalination in California Energy and Greenhouse Gas Emissions, Pacific Institute, Beltsville, MD, May 2013 www. pacinst.org/reports/desalination_2013/energy (accessed December 2014). [8] Y. Garb, Desalination in Israel: Status, Prospects, and Contexts, Presented at the Water Wisdom Conference, Amman, Jordan, April 2008. [9] U.S. DOE (Department of Energy), Liquefied Natural Gas: Understanding the basic facts, Report # DOE/FE-0489, 2005. [10] CEE (Center for Energy Economics), Introduction to LNG. An overview on liquefied natural gas (LNG), its properties, the LNG industry, and safety considerations, Bureau of Economic Geology, Jackson School of Geoscience and The University of Texas at Austin, 2012. [11] C. Hurn, T. Hagedorn, Tuaspring Sea Water Desalination with CCPP in Singapore: An Example for Sustainable Power Generation, PowerGen Asia, Bangkok, Thailand, October 3–5 2012. [12] J. Pinzon, Energy Efficiency in Water Reuse and Desalination: Five Individual Projects Which Address Energy Efficiency in Both Water Reuse and Desalination, WateReuse Research Foundation, Alexandria, VA, 2013. [13] API (American Petroleum Institute), Consistent methodology for estimating greenhouse gas emissions from Liquefied Natural Gas (LNG) operations, The Levon Group, Thousand Oaks, CA, May 2015. [14] Spiritos, Lipchin, Global Issues in Water Policy: Desalination in Israel, Springer Science+Business Media, Dordrecht, 2013. [15] S. Mokhatab, J.Y. Mak, J.V. Valappil, D.A. Wood, Handbook of Liquefied Natural Gas, Gulf Professional Publishing, 2013. [16] CEC (California Energy Commission), Thermal Efficiency of Gas Fired Generation in California, Report No. CEC-200-2011-008, California Energy Commission, Sacramento, CA, 2012. [17] J. Loveland, Personal Communication (Email), February 2015. [18] W. Ko, S.S. Bokjung-Dong, K.J.H. Lee, C. Ham, A grid-connected desalination plant operation, J. Educ. Inform. Cybern. 11 (1) (2013). [19] U.S. EPA (Environmental Protection Agency), eGrid, (Emissions & Generation Resource Integrated Database), 9th edition Version 1.0, 2010 (Summary Tables), February 2014. [20] URS, Alternative Energy Survey for Proposed Desalination Plant, A Report, June 2003. [21] Sempra Energy, Personal Communication (Email), May 29th 2014.

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