Nationwide, Regional, and Statewide Energy Supply Chain

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Nationwide, Regional, and Statewide Energy Supply Chain Optimization for Natural Gas to Liquid Transportation Fuel (GTL) Systems Josephine Anastasia Elia, Richard C Baliban, and Christodoulos A. Floudas Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/ie401378r • Publication Date (Web): 05 Sep 2013 Downloaded from http://pubs.acs.org on September 14, 2013

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Industrial & Engineering Chemistry Research

Nationwide, Regional, and Statewide Energy Supply Chain Optimization for Natural Gas to Liquid Transportation Fuel (GTL) Systems Josephine A. Elia, Richard C. Baliban, and Christodoulos A. Floudas∗ Department of Chemical and Biological Engineering Princeton University, NJ 08544, USA August 14, 2013

Abstract An optimization-based supply chain framework is proposed for the nationwide, regional, and statewide analyses of natural gas to liquids (GTL) systems for the United States. Using optimized GTL refineries of differing capacities (i.e., 1, 5, 10, 50, and 200 thousand barrels per day) and fuel product ratios (i.e., unrestricted, maximization of diesel, maximization of kerosene, and commensurate with the United States demand), the optimal nationwide, regional, and statewide supply chains are obtained by solving a large-scale mixed-integer linear optimization (MILP) model that minimizes the total cost of fuel production. The mathematical formulation includes the locations of natural gas in the United States discretized by county, the delivery locations of fuel products, the transportation costs of every input and output of the refinery, the material balances of each GTL refinery, water resources, electricity requirement/production of the supply chain, and the CO2 sequestration capacities in the United States. Solutions of the proposed MILP optimization model provide useful information for the strategic locations of GTL refineries, the allocations of feedstocks and products in the supply chain, as well as a quantitative basis in evaluating each cost contributing factor. Comprehensive ∗ Corresponding

author; Tel: (609) 258-4595; Fax: (609) 258-0211; E-mail: [email protected].

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analyses on the effects of modifying the geographical scope of the supply chain problem are completed and the economic performances of GTL supply chains in different regions are compared. Results suggest that GTL supply chains can produce highly competitive liquid fuels in United States and the Southwest and Central regions of the United States are the most profitable areas for these supply chains.

1

Introduction

The Energy Information Administration projects that the increase in the transportation sector’s energy demand will be fulfilled by “non-petroleum” derived sources 1 . The total transportation fuel demand in 2010 was 13,466 thousand barrels per day (kBPD), 72.1% of the nationwide petroleum consumption 2 , and this demand is projected to reach 14,540 kBPD by 2035 1 . If these fuels can be produced using domestic feedstocks, the United States’ dependence on crude oil imports will decrease, the nation can enhance its energy independence, and the effects of fluctuating crude oil prices will be reduced in the national energy and fuel market. Recently, a review has highlighted the process design alternatives that can produce liquid hydrocarbon fuels and other fuel additives using coal, biomass, and natural gas feedstocks, or any combination of the three carbon based feedstocks, which are available domestically 3 . Coal is an attractive feedstock due to its abundant supply in the United States and its low delivered cost ($2.0-$2.5/MM Btu) 1 , but its high carbon content may result in high production of CO2 that needs to be vented, sequestered, or recycled 4–8 . Biomass is an important feedstock that can reduce the life cycle greenhouse gas emissions of liquid fuels from the CO2 uptake during cultivation 9–13 . An increase in the national crop production, however, needs to take place to generate sufficient amount of sustainable feedstock for fuel production 14–16 . In addition, processes that convert coal and biomass to liquid hydrocarbon fuels using a synthesis gas (syngas) intermediate require high capital costs and extensive syngas cleaning steps to remove the sulfur- and nitrogen-containing gas components. The gasification and cleaning processes for conventional coal or biomass plants approximately account for 50%-65% of the entire plant cost 17,18 . Technologies that convert natural gas feedstock to liquid transportation fuels have existed and studied for decades, but were not economically favorable in the United States due to the high

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natural gas prices. Commercial natural gas to liquids (GTL) plants exist around the world such as Shell’s Bintulu GTL plant in Malaysia and Shell’s Pearl GTL plant in Qatar. However, recent discoveries of shale gas in the United States, coupled with the horizontal drilling and fracking technologies that enable shale gas production, have driven the cost of natural gas down and made it a very attractive feedstock for liquid fuels and energy production 1 . Sasol has announced plans to construct the first GTL plant in the United States in Louisiana 19 . In hydrocarbon production, the high hydrogen to carbon ratio in the composition of natural gas is highly advantegous in increasing the yield of carbon in the fuel products. This, in turn, will reduce the capital investment required and mitigate the CO2 production from the process. GTL processes also do not require steps to remove sulfur from the synthesis gas since the pipeline requirement already enforces a very low amount of sulfur in the transported gas. Consequently the resulting liquid fuels have close to zero sulfur content. Various studies have proposed hybrid systems where the advantages of coal, biomass, and natural gas can be combined in a synergistic way 3 . Examples of hybrid systems include coal and natural gas to liquids 20–28 , biomass and natural gas to liquids (BGTL) 29–33 , and coal, biomass, and natural gas to liquids (CBGTL) 5–8,34,35 . However, the development of a single feedstock natural gas to liquids (GTL) refinery can take advantage of certain locations that are abundant in natural gas, but far away from coal and biomass resources. For example, GTL technologies can tap into unutilized stranded gas resources, which make up a significant portion of the United States gas supply 36–39 . Stranded gas is low value natural gas that is co-produced in small amount with oil production (associated gas) or gas in wells that are inaccessible from the current pipeline infrastructure. These resources are currently untapped, or in the case of associated gas, flared to the atmosphere since the its amount is too small to justify building an infrastructure to utilize it 36–39 . GTL technologies that can take advantage of stranded gas resources can bring economic value from adding fuels to the market and reduce the environmental damage from flaring. Efficient management of the upstream and downstream operations of GTL plants will determine their profitability. In the literature, extensive research has been done on biomass supply chains for fuel production to determine biorefinery locations with respect to the distributed nature of biomass resources 3,40–57 . Natural gas supply chain studies generally focus on the operational aspect of natural gas production complexes and the pipeline distribution systems that include re3



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fineries, compression stations, and mixing of products in the pipelines 58,59 . Hamedi et al. 58 studied a real-world natural gas supply chain from the gas and oil wells, refineries, compression stations, local gas companies, city gate stations, and consumers. They also included a literature review of studies on the operations of natural gas supply chains. Contesse et al. 60 studied the natural gas supply chain system that involves the producers, transportation companies, and local distribution companies to optimize the daily purchasing and transportation contracts between the companies. ¨ Ozelkan et al. 61 proposed a framework that analyzes the design of liquefied natural gas (LNG) terminals for the LNG supply chain. dos Santos et al. 62 used a simulation-based approach to develop a management system for the transportation logistics of natural gas. In the decisions to built new GTL refineries in the United States, it is important to analyze what strategic placements of GTL refineries will maximize their profitability in addition to the operational constraints. The strategic placements of GTL refineries have to ensure that the feedstock can be delivered sustainably to the plant over a long time horizon and that the fuel products can be distributed efficiently to the market. Environmental limitations such as freshwater availabilities and CO2 sequestration capacities in the local region must also be fulfilled. These logistical challenges must be considered simultaneously, and an optimization framework is an important tool that can maximize the profitability of the entire GTL supply chain. Previous studies have been done on a nationwide hybrid feedstock supply chain optimization for the coal, biomass, and natural gas to liquids system where the locations of the hybrid plants are optimized with respect to the feedstocks, fuel demand locations, plant investment costs, and environmental constraints such as water, electricity, and sequestration requirements 40,41 . In this paper, an optimization framework is considered for the nationwide, regional, and statewide GTL supply chains for the United States, using novel GTL processes that have been globally optimized in 63 . The supply chain begins at the natural gas feedstock locations, ends at the demand locations, and is optimized to yield the strategic placements of GTL facilities with minimum overall cost of fuel production. The supply chain also addresses the electricity supply, water supply, and the allocation of sequestered CO2 to injection sites. The rest of the paper is organized as follows.

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2

Natural Gas Resources

The first set of parameter inputs into the energy supply chain optimization model is the natural gas feedstock parameters. This category of parameters include (i) the locations of natural gas sources, (ii) the availabilities at each location, and (iii) the purchase price of natural gas at each location. The supply chain takes into consideration the geographical variabilities of these parameters, which influence the profitability of the GTL refineries across the country. The same type of GTL refinery in two different locations will have different operational costs due to the logistics and configuration of the upstream and downstream operations. In this study, one generic composition for natural gas is used based on an average composition of natural gas wellhead productions in the United States 63,64 . Note that the uniformity of natural gas feedstock is a reasonable assumption due to the quality requirement of natural gas for pipeline transportation that requires above 90% of methane content and very low sulfur and CO2 contents 65 . The data on natural gas resources across the United States are accessed from various statewide reports of gas wells production and these data are based on the 2010 natural gas production level. Natural gas production from oil and gas wells, as well as shale gas and coal-bed methane are included in the total production level on a county basis. When data on the well-specific production are available, the figures are grouped based on the county of the wells. Table 1 lists the sources of natural gas resources data that are used as inputs in this paper and Figure 1 shows the geographical distribution of natural gas production in the United States. The states that have major natural gas productions are Alabama, Arkansas, California, Colorado, Kansas, Kentucky, Louisiana, Michigan, Mississippi, Montana, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas, Utah, Virginia, West Virginia, and Wyoming. A total of 813 counties in the United States have natural gas production and these counties serve as the beginning points of the GTL supply chain as well as the candidate locations for potential GTL refineries. The breakdown of the number of counties and the 2010 natural gas production level for each state can also be seen in Table 1. The county-specific, statewide natural gas productions are compared with the EIA’s statewide production figures to make sure that the data corroborate each other. The wellhead costs of natural gas are taken from the EIA website, which are discretized by state and include all costs prior to shipment from the lease, including the costs for gathering, compression, and processes to prepare the feeds

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for pipeline quality. Since the county-specific natural gas prices are not available, it is assumed that all natural gas within a state has a uniform price as given by the EIA website. The amount of natural gas that is available for the GTL supply chain is assumed to come from further expansions from the 2010 natural gas production level. In other words, the GTL supply chain does not interrupt the current usage of natural gas in various energy, industrial, or residential sectors. In the supply chain case studies, 25%, 50%, 75%, and 100% expansion levels from the 2010 natural gas production are considered to analyze the amount of liquid fuels that can be produced using the optimized GTL refineries 63 .

3

Gas to Liquids (GTL) Refineries

The design and topology of the GTL refineries that may exist in the supply chain are optimized using the process synthesis methods developed in Baliban et al. 63 . For GTL systems, typical studies focus on fixed process designs and topologies where simulations are used to determine the heat and mass balances for the process 20,21,24,25,32,66–74,74–82 . However, recent developments in process synthesis strategies for hybrid feedstock systems 7,8,12,13,33–35,43,44,63,83–89 have shown that rigorous and computationally efficient methodologies can be developed and used to simultaneously analyze thousands of process designs to extract the optimal process design(s) and establish trade-offs among them. The superstructure optimization method can directly compare the technoeconomic and environmental benefits of GTL processes in a singular mathematical model, simultaneously analyzing several existing or novel processes via a process superstructure to determine the optimal topology which will have either the lowest cost or highest net present value. Combining an environmental objective function with the optimization of refinery designs in a multiobjective optimization framework has also been proposed to measure the tradeoff between economic and environmental performances of energy systems 43,44,86–89 . Yue et al. 86 proposed a life cycle optimization framework based on the functional unit of energy systems, which can be the mass or volumetric amount of the product or in a multi product system, the sum of the properties such as heating value or market value of the product streams. They proposed a four-stage steps of the life cycle assessment, begining with the definition of the scope and boundaries of the study (e.g., wellto-wheel, well-to-gate, etc.), inventory analysis, impact assessment, and interpretation, the last step 6


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Table 1: Summary of the states that produce natural gas, the number of counties, and the total production level in 2010. The statewide sources of the natural gas data are included for reference.

State

Region

Number of counties

Total natural gas production (billion SCF/yr)

Alabama

Southeast

21

240.71

Arkansas

Southwest

32

1,085.71

California

Western

27

262.88

Colorado

Central

37

1,917.81

Kansas

Central

56

333.18

Kentucky

Southeast

38

135.15

Louisiana

Southwest

60

2,142.41

Michigan

Midwest

43

143.83

Mississippi

Southeast

37

59.53

Montana

Central

30

105.29

New Mexico

Southwest

9

1,397.35

Ohio

Midwest

45

79.88

Oklahoma

Southwest

63

1,706.70

Pennsylvania

Northeast

33

671.11

Texas

Southwest

197

6,499.12

Utah

Central

10

493.26

Virginia

Northeast

7

147.26

West Virginia

Northeast

48

287.24

Wyoming

Central

20

2,522.94

Total

Nationwide

813

20,231.36

7

Data source

Geological Survey of Alabama State Oil and Gas Board www.gsa.state.al.us Arkansas Oil and Gas Commission www.aogc2.state.ar.us State of California Department of Conservation Division of Oil, Gas & Geothermal Resources www.conservation.ca.gov Colorado Oil and Gas Conservation Commission cogcc.state.co.us Kansas Geological Survey www.kgs.ku.edu Kentucky Geological Survey www.kgs.uky.edu State of Louisiana Department of Natural Resources: Sonris Database sonris.com State of Michigan Department of Environmental Quality www.michigan.gov/deq Mississippi State Oil & Gas Board www.ogb.state.ms.us State of Montana Department of Natural Resources & Conservation dnrc.mt.gov New Mexico Oil & Gas Association www.nmoga.org Ohio Department of Natural Resources www2.ohiodnr.gov Oklahoma Geological Survey www.ogs.ou.edu Pennsylvania Department of Environmental Protection www.depweb.state.pa.us Texas Oil & Gas Association www.txoga.org Utah Department of Natural Resources Division of Oil, Gas & Mining oilgas.ogm.utah.gov Virginia Department of Mines, Minerals and Energy www.dmme.virginia.gov West Virginia Oil and Natural Gas Association www.wvonga.com Wyoming Oil and Gas Conservation Commission wogcc.state.wy.us


660

880

LA

1,100

1,320

1,540 Miles

FL

GA MS AL

AR

184004757.000001 - 422199351.000000

82904348.470001 - 184004757.000000

25070843.000001 - 82904348.470000

1.000000 - 25070843.000000

Amount

Natural Gas Sources

422199351.000001 - 1197584292.000000

0 110 220

NM AZ

440

OK

TX

KY TN

KS CO

CA

OR

NV

ID

WY UT

NE

IA

MO

IL

IN

MI

OH

NC SC

PA NJ WV MDDE VA

VTNH NY CTMA MI WI SD

MN ND MT WA

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ME


Figure 1: The geographical layout of natural gas resources for the GTL supply chain network in the United States. The figures are based on the 2010 natural gas production on a county basis. There are a total of 19 states that produce natural gas in the United States. The counties highlighted in the figure are also candidate locations for GTL refineries.

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being coupled with the multiobjective optimization framework. The method has been applied to superstructure optimization of biorefineries that convert cellulosic biomass to gasoline and diesel via gasification 87 , hybrid poplar feedstock to gasoline and diesel range biofuels via fast pyrolysis and hydroprocessing steps 89 , and algae to biodiesel via lipid extraction and algal oil processing with CO2 from power plant flue gas 88 . In Baliban et al. 63 , a rigorous global optimization strategy 34,90–101 is used to mathematically guarantee that the GTL process design selected by the framework will have an overall cost (or profit) that is within a small percentage of the best value possible. The key process alternatives include (i) the inclusion and mathematical modeling of steam reforming of natural gas, auto-thermal reforming of natural gas, direct conversion of natural gas to methanol via partial oxidation, and direct conversion of natural gas to olefins via oxidative coupling as conversion technologies, (ii) the direct usage of natural gas in the fuel combustor unit to provide process heat and in the gas turbine for electricity production, (iii) synthesis gas conversion via Fischer-Tropsch (FT) or methanol synthesis, (iv) methanol conversion via methanol-to-gasoline (MTG) or methanol-to-olefins (MTO), and (v) hydrocarbon upgrading via ZSM-5 zeolite catalysis, olefin oligomerization, or boiling point fractionation and subsequent treatment, (vi) different product compositions (i.e., gasoline, diesel, and kerosene) considered, namely the unrestricted composition (U), maximization of diesel (D), maximization of kerosene (K), and compositions commensurate with the United States demand ratio (R), and (vii) calculations of the life cycle emissions of GTL systems compared to petroleumbased processes and natural gas-based electricity production 63 . The framework includes a simultaneous heat and power integration 6,7 using an optimization-based heat-integration approach 102 and a series of heat engines that can convert waste heat into electricity 5–7 . A comprehensive wastewater treatment network 8 that utilizes a superstructure approach 103–106 to determine the appropriate topology and operating conditions of process units is utilized to minimize wastewater contaminants and freshwater intake. Finally, recycling of gases and CO2 from and to various sections of the refinery (i.e., reformers, Fischer-Tropsch, reverse water gas shirt reactor) is allowed to maximize fuel production and limit CO2 emissions 7,8,34,35 . The life cycle analysis of the refineries is done on a well-to-wheel basis and an environmental constraint is included in the optimization model to limit the GTL refinery emissions to be at most equal to petroleum-based processes or natural gas-based electricity production (see Section 9) 63 . 9



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For this study, five different refinery capacities are considered, namely plants that produce 1 kBPD, 5 kBPD, 10 kBPD, 50 kBPD, and 200 kBPD of total liquid fuels to accommodate geographical locations that vary in natural gas resources. In addition to the varying capacities, four different modes of fuel production apply to the GTL refineries: (i) the unrestricted fuel composition (U) where only gasoline in produced with byproduct LPG, (ii) maximization of diesel (D) where 75 vol% diesel and 25 vol% gasoline are produced, (iii) maximization of kerosene (K) where 75 vol% kerosene and 25 vol% gasoline are produced, and (iv) fuel ratios commensurate with the 2010 United States demand (R) that produce 67 vol% gasoline, 22 vol% diesel, and 11 vol% kerosene 107 . The 20 combinations of capacity and fuel ratios are optimized via the process synthesis method and the outputs include (i) natural gas requirement, (ii) electricity production, (iii) butane requirement, (iv) water requirement, (v) investment cost, (vi) liquid fuel flow rates, (vii) CO2 vented, (viii) byproduct propane/liquefied petroleum gas (LPG) flow rates, and (ix) CO2 sequestered. The results for the 20 GTL refineries in the supply chain can be seen in Table 2 From Table 2 it can be seen that no butane requirement is needed except for the (R) refineries, and (K) refineries do not produce byproduct LPG. Economies of scale are observed as the capacities increase from 1 kBPD to 200 kBPD in the normalized investment cost figures. Electricity is produced in all cases, which excludes the need of consuming additional fossil fuels to produce electricity and add to the overall greenhouse gas emissions.

4

Liquid Fuel Delivery Locations

The 2010 demand data for petroleum based products are extracted from the Energy Information Administration (EIA) website, which are available on a statewide basis. Among the list of products, motor gasoline, distillate fuel oil, and jet fuel represent a large majority of the total product volumes 2 . In this study, the end destinations for the fuel products are the existing oil refineries in the United States to be distributed across the nation or to be blended with petroleum-based fuels before distribution. In other words, the GTL supply chain will take advantage of the hydrocarbon pipeline infrastructure connected to the refineries. Current oil refineries are viable options to send the GTL products to because they can help improve the quality of petroleum-based fuels via blending. The GTL products are high-quality liquid fuels that have close to zero sulfur content 10


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Table 2: Overall material balance, electricity output, and total investment cost for the 20 types of GTL refineries that may exist in the supply chain. The inputs to the GTL refineries are natural gas, butane, and water, while the outputs include gasoline, diesel, kerosene, LPG, sequestered CO2 , vented CO2 , and electricity. The four modes of fuel production are (i) unrestricted (U), where only gasoline is produced, (ii) maximization of diesel (D), where gasoline and diesel are produced, (iii) maximization of kerosene (K), where gasoline and kerosene are produced, and (iv) fuel ratios commensurate with the United States demand (R), where all three fuels are produced.

Natural gas (mscf/hr) Butane (kBD) Water (kg/s) Gasoline (kBD) Diesel (kBD) Kerosene (kBD) LPG (kBD) Seq. CO2 (tonne/hr) Vented CO2 (tonne/hr) Electricity Investment cost (MM $) Normalized inv. cost ($/bpd)

Natural gas (mscf/hr) Butane (kBD) Water (kg/s) Gasoline (kBD) Diesel (kBD) Kerosene (kBD) LPG (kBD) Seq. CO2 (tonne/hr) Vented CO2 (tonne/hr) Electricity Investment cost (MM $) Normalized inv. cost ($/bpd)

U-1

U-5

U-10

U-50

0.36 1.92 1.00 0.09 1.36 4.03 -2 138 138127

1.82 9.59 5.00 0.45 6.80 20.14 -12 478 95656

3.61 14.01 10.00 0.90 10.98 40.99 -25 798 79808

18.53 74.21 50.00 4.50 84.64 204.30 -141 3354 67072

K-1

K-5

K-10

K-50

0.36 1.42 0.25 0.75 1.35 4.15 -4 143 142978

1.81 7.09 1.25 3.75 6.76 20.75 -19 501 100208

3.54 19.85 2.50 7.50 10.00 40.14 -32 812 81192

18.31 85.89 12.50 37.50 73.66 214.71 -218 3393 67866

11

GTL Refineries U-200 D-1 73.57 400.25 200.00 19.78 347.18 796.88 -460 11685 58427

0.39 1.80 0.25 0.75 0.04 2.34 3.40 -2 139 138799

GTL Refineries K-200 R-1 77.28 300.19 50.00 150.00 587.99 808.07 -878 11732 58658

0.36 0.03 1.68 0.67 0.22 0.11 0.02 2.02 3.86 -4 145 145227


D-5

D-10

D-50

D-200

1.93 9.01 1.25 3.75 0.20 11.70 17.02 -11 464 92756

3.76 17.34 2.50 7.50 0.37 16.53 35.64 -25 800 79997

18.89 90.89 12.50 37.50 1.52 91.88 176.63 -134 3299 65977

73.85 406.92 50.00 150.00 6.06 265.71 706.08 -475 11384 56922

R-5

R-10

R-50

R-200

1.81 0.13 8.42 3.36 1.08 0.56 0.08 10.12 19.29 -19 510 102027

3.62 0.26 16.84 6.72 2.15 1.13 0.16 20.25 38.59 -38 834 83393

18.02 1.14 63.37 33.60 10.77 5.63 0.74 114.88 174.36 -141 3527 70538

72.20 4.29 370.23 134.39 43.10 22.51 3.01 463.60 696.58 -563 12347 61736


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and mixing them with petroleum-derived fuels can reduce the overall sulfur content and meet the imposed fuel standards. To specify the demand amount at each location, the statewide demand data are distributed over these oil refineries. The EIA database provides the maximum operating capacities of United States operating petrochemical refineries 108 . We assumed that the demand amount or the amount of GTL fuels delivered to each oil refinery does not exceed their operating capacities. The mixtures between gasoline, diesel, and kerosene in the delivered fuels are unspecified.

5

Transportation Costs

The modes of transportation for each commodity in the supply chain for both the upstream and downstream operations are defined. Natural gas is transported by pipeline, water is transported by pipeline, and fuel products are transported by a combination of truck, pipeline, and barge 40,41 . Natural gas and liquid fuels transportation costs by pipeline are calculated based on average values on a per mile per volumetric flow rate basis derived from the informational postings of 10 largest natural gas pipeline and 10 largest hydrocarbon pipeline companies in the United States 40 . These postings consist of information on pipeline origin and end points, and usage fees, which can be used to estimate the average transportation costs for natural gas and liquid fuel products. Connections between GTL refinery locations, ports (origin and destination), and demand locations are allowed for transportation by pipeline and barge, and the transportation costs for barge transportation follow the assumptions in Elia et al. 40 where a list of 50 United States ports was extracted from the World Port Source 109 consisting of the 49 highest ranked ports according to the total quantity of imports received in a year (excluding Virgin Islands and Puerto Rico) 110 and 1 port in Anchorage, AK. Port-to-port distances are determined from an online World Ports Distances calculator 111 and the ports that do not have an entry in the World Ports Distances database are listed in Table 7 of Elia et al. 40 , along with their respective reference ports (closest port location with available distance information) and the adjustment distance (i.e., the known distance in nautical miles between the unaccounted ports and their corresponding reference ports). Transportation costs by truck, barge, and water pipeline are calculated using Eq. 1, where DFC is the distance fixed cost, DVC is the distance variable cost, Distance is the distance traveled, and DM is the distance multiplier. Distance is the straight line distance calculated from the latitude and longitude coordinates of two 12


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points, and to account for path curvatures, DM is equal to 1.1 for truck transportation and water pipeline 112 . For fuel products transportation by truck, the DFC value is $3.318/bbl and the DVC value is $0.124/bbl-mi; for fuel products transportation by barge, the DFC value is $1.218/bbl and the DVC value is $0.0063/bbl-mi; and for water transportation by pipeline, the DFC value is $0.003/kg and the DVC value is $5E-6/kg-mi 112 . The CO2 pipeline transportation costs are discussed in further detail in Section 8.

Transportation Cost = DFC + DVC · Distance · DM

6

(1)

Electricity

When a GTL refinery produces electricity, it can be placed anywhere in the country and a profit will be taken from selling electricity to the grid. However, when a plant requires electricity, this requirement will add to the electrical power demand for the country and three options are available, namely drawing electricity from the grid, producing electricity from solar resources or wind resources. The 2009 net electricity generation capacity in the United States was reported to be 1025.4 GW in the summer and 1063.8 GW in the winter 113 , and most of this electrical power relies on fossil fuels. It is important to cap the total electricity usage in the supply chain network to prevent excessive expansion of the current power supply and limit the greenhouse gas emissions from power generation. On the single plant approach, heat and power integration is completed for each GTL refinery topology such that the combined heat and power requirement is minimized and electricity is recovered from waste heat 6,7,35,63 . On the supply chain network approach, a total cap on the grid expansion for the whole country is imposed, which is set to be at most 10% of current generation, amounting to 102.5 GW 41 . Electricity generated from renewable sources (i.e., solar and wind) is incorporated into the supply chain in the following way. The investment costs of each electricity option are accounted in the model, and the optimization model will select one or a combination of electricity sources for a given location. Electricity from solar and wind is assumed to be produced from solar and/or wind plants built on the site of the GTL refinery. The maximum capacity is set to 40 MW for a wind plant and 20 MW for a solar plant. Only counties that have adequate solar irradiation and wind 13



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

speed are allowed to have solar and wind power generation. Solar irradiation data are obtained from the National Solar Radiation Data Base (NSRDB) 1991-2005 Update 114 , which contain the longitude and latitude specifications of the station sites with solar irradiation. The longitude and latitude data are used to calculate the distance between solar sites and candidate locations of the GTL refineries. If a county is within 10 miles of a solar station site, and the data indicate that there is adequate irradiation surrounding the county, then a solar plant may be built with the GTL refinery 41 . Wind profiles across the United States are obtained from the National Renewable Energy Laboratory (NREL) Wind Integration Dataset 115 , namely the Eastern Wind Dataset and the Western Wind Datasets. The Western Wind Datasets contain 32,043 locations with the highest wind energy density in the western part of the United States. From the Eastern Wind Datasets, sites from the land based and Midwest ISO (MISO) areas are used in this analysis. The longitude and latitude data of the station sites are used to calculate the distance between wind sites and the candidate locations of the GTL refineries. If a county is within 10 miles of a wind site, and the data indicate that there is adequate wind speed surrounding the county, then a wind farm may be built with the GTL refinery. Note that due to the onsite power generation, the costs for transmission and electrical grid expansion are not included 41 .

7

Water Resources

To prevent over-stressing the regional water resources, the water supply chain is included in the GTL supply chain formulation. On the single plant level, the water network superstructure is optimized simultaneously with the process synthesis framework to minimize the freshwater input and wastewater discharge from the GTL refineries 8,35,63 . On the supply chain level, a regional constraint is included such that the water requirement for any GTL refinery must be satisfied locally within a 5-mile radius. Water usage data in the United States are obtained from the United States Geological Survey (USGS) database 116 , where estimates of freshwater consumption for domestic, agricultural, and industrial sectors are reported for each county. The available water for the GTL supply chain is calculated by taking the minimum of 1.5 times of current industrial use or 15% of total freshwater use in the county to prevent excessive expansion in the infrastructure. The water 14


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transportation costs by pipeline is included in the total cost of the GTL supply chain 41 .

8

CO2 Sequestration

The optimized GTL refineries include the selection of CO2 capture and sequestration in the optimal topologies (see Section 3). In the supply chain formulation, it is important to include the constraint that ensures viable locations of sequestration sites with enough capacities to accommodate the amount produced by the GTL refineries. Currently, potential geological storage sites are being explored in the United States and the National Energy Technology Laboratory (NETL) published estimates on the capacities of underground CO2 storage 117 . In this study, these estimates from the NETL 2010 Carbon Sequestration Atlas of the United States and Canada (Third Edition, Atlas III) 117 project are used to determine the end points and capacities of sequestered CO2 . Data from Appendix C of the document 117 are used to calculate the total estimated storage resources (low capacity scenario) by state and the sequestration sites are assumed to be at the center of the state from the purpose of calculating the distance of CO2 transportation. Note that the approach taken in the optimization model can be readily used where more discretized information on storage sites become available. The CO2 to be sequestered exits the GTL refineries at 150 bar and is transported via pipeline to the storage sites. The levelized costs of investment for CO2 pipelines are calculated using a linearization of the pipeline equations in Ogden 118 as functions of the CO2 flow rates and transportation distances, which are calculated explicitly in the model. The cost of injection and levelized cost for new wells also follow the approach in Ogden 118 and are minimized in the energy supply chain optimization model.

9

Life Cycle Analysis

Baliban et al. 63 described the methods of calculating the life cycle greenhouse gas emissions from the optimized GTL refineries. An environmental constraint is included in the process synthesis model to prevent excessive emissions from the process. For each GTL refinery, the total GHG emission target was set to be at most equal to that for petroleum-based production of liquid fuels 15



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or natural gas-based production of electricity. The GHG emission rates (in kg CO2 eq/s) for the eight major point sources in the refinery are given in Baliban et al. 63 and include (a) acquisition and transportation of the natural gas and butane feeds, (b) transportation and use of the gasoline, diesel, kerosene, and LPG, (c) transportation and sequestration of any CO2 , and (d) venting of any process emissions. In other words, the system boundaries start at the feedstock acquisition and end at the end use of the liquid fuels 35,40,41,63 . The GHG emissions for feedstock acquisition and transportation in (a), product transportation in (b), and CO2 transportation in (c) are calculated from the GREET model for well-to-wheel emissions 119 , with the given average distances traveled for each mode of transportation. The GHG emissions from product use in (b) are calculated assuming that each product will be completely combustion to generate CO2 that is simply vented to the atmosphere. The lifecycle GHG emissions (LGHG) was set to be the sum of the total emissions from each stage of the process. The GHG emissions avoided from liquid fuels (GHGAF) is equivalent to the total energy of fuels produced multiplied by a typical petroleum-based emissions level (i.e., 91.6 kg CO2eq /GJLHV ) while the GHG emissions avoided from electricity (GHGAE) is equivalent to the energy produced by electricity multiplied by a typical natural gas-based emissions level (i.e., 101.3 kg CO2eq /GJ) 120 . Note that since the GTL refineries are multi-product systems, the total fuel production is levelized to the total heating value of gasoline, diesel, and kerosene produced. The GHG emissions index (GHGI) represents the division of LGHG by the sum of GHGAF and GHGAE, and values less than unity are indicative processes with superior lifecycle GHG emissions than current processes. In the refinery topology, the CO2 management includes the option to vent CO2 to the atmosphere, capture and sequester CO2 , and recycling of CO2 into various units in the process (i.e., reformers, reverse water gas shift reactor, Fischer-Tropsch reactors) via the reverse water gas shift reaction to produce CO and liquid fuels subsequently 35,63 . Since the GTL refineries do not consume renewable carbon feedstock, the only negative contribution in the emissions is the CO2 sequestration. Baliban et al. 63 showed that for each of the optimized GTL refinery, the overall life cycle emissions is equal to petroleum-based processes (i.e., GHGI exactly equal to 1, according to the environmental constraint). The majority of the emissions are attributed to the liquid fuels consumption (i.e., 70% of total emissions). Natural gas is a particularly GHG intensive feedstock due to the small amount of methane that is leaked to the atmosphere during extraction from the 16


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ground. Nevertheless, it is still economical to develop GTL processes that can have appropriate GHG emissions targets. On the supply chain level, the transportation distances for the feedstocks and products will not be exactly the same as the assumed GREET parameters in Baliban et al. 63 . Some feedstocks and products will travel a greater distance and some will travel less distance, and the GTL refineries in the supply chain will have slight variations on the total life cycle emissions. Note that an environmental constraint on the life cycle emissions of the GTL supply chain may be included in the model formulation. However, since the GTL supply chain does not involve any renewable source and the emissions are comparable to petroleum-derived fuels, this constraint is not included in this study.

10

Energy Supply Chain Optimization Model

The previous subsections detail the parameter inputs required in the energy supply chain optimization model. These parameter inputs include: (i) the location, availabilities, and purchase prices of natural gas feedstock, (ii) the transportation costs of natural gas, water, and fuel products, (iii) investment costs, feedstock requirement, electricity requirement/output, fuel product amounts, and other input-output material balances for the 20 GTL refineries (see Table 2), (iv) locations of fuel product destination (i.e., oil refineries), and (v) price of utilities (i.e., water and electricity). The GTL supply chain optimization model is formulated as a mixed-integer linear optimization (MILP) model and is solved to give the (a) the strategic locations of the GTL refineries on a nationwide, regional, and statewide level, (b) the capacity of the selected GTL refinery at each location, (c) the supply chain topology from the feedstocks to product destination, and (d) the costs breakdown associated with each segment of the supply chain. Continuous variables are used to represent the levelized investment cost at a location (CostlI ), the total electricity requirement (EllT ), electricity produced (EllP ), solar electricity required (EllS ), wind electricity required (EllW ), grid electricity required (EllG ), the water requirement (W Fl ), the CO2 sequestration amount (SFl ), the flow of feedstock from the producing locations to the plant facility (x f ,c,l,m ), the required flow rate of natural gas feedstock to a plant facility (FR f ,l ), the flow of products transported from the GTL refineries to the demand locations (z p,l,c,m ), the flow of 17



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Page 18 of 79

freshwater to the facilities (wc,l ), and the sequestration amount from a facility (seqc,l ). Note that the model allows for electricity input in the supply chain, but since all of the GTL refineries have net electricity output, the EllT , EllS , EllW , and EllG values are zero in all cases. Binary variables (y f ,l,t,q ) represent the selection of a specific GTL refinery at location l with natural gas feedstock ( f ) ∈ FC, capacity t, and fuel product ratio q. The complete variable list can be found in the Notation Section. At most one GTL refinery may be selected at a given candidate loccation, which is specified at the county centroid where natural gas feedstock exists (Eq. 2). Equations 3-5 impose lower and upper limits in the number of selected GTL refineries for the entire network and per plant capacity. The typical bound for the overall number of refineires used in this paper is N = 1000, with Ntmax and Ntmin customized for each case study. For the nationwide supply chain case studies, the Ntmin values for the 1 kBPD and 5 kBPD refineries are set to be 5 and 3, respectively, to represent demonstration-scale GTL refineries in the early stage of the supply chain development. All other Ntmin values are set to zero. In the regional and statewide case studies, the lower bound for the 5 kBPD refineries is removed. The value of Ntmax is set to be 3 for the 200 kBPD refineries to prevent the model to excessively favor the large capacity due to economies of scale, since large risks are associated with installing 200 kBPD refineries. All other Ntmax values are set to be 500. y f ,t,l,q ≤ 1

∑

∀l ∈ LF

(2)

( f ,t,l,q)∈FL

y f ,l,t,q ≤ N

∑

(3)

( f ,t,l,q)∈FL

∑ ( f ,t,l,q)∈FL

∑ ( f ,t,l,q)∈FL

y f ,l,t,q ≤ Ntmax ∀t ∈ T

(4)

y f ,l,t,q ≥ Ntmin ∀t ∈ T

(5)

The correct investment cost parameters and the natural gas feedstock requirements associated with the selected GTL facilities are determined by Equations 6-7.

∑ ( f ,t,l,q)∈FL

FR f ,l =

y f ,l,t,q LC f ,t,q = CostlI ∑

( f ,t,l,q)∈FL

∀l ∈ LF

FRGf,t,q y f ,l,t,q ∀ f ∈ F G , l ∈ LF

18


(6) (7)

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Equation 8 constrains the flow rates from each natural gas feedstock source locations not to exceed the amount available at that location. The availability of natural gas is determined by the level of natural gas expansion as described in Section 2. The total natural gas flow rates arriving at a particular GTL refinery has to match the feedstock requirement of the selected GTL refinery (Eq. 9). Equation 10 constrains the product ratios exiting each GTL refinery to match either the unrestricted fuel ratio, maximum diesel production, maximum kerosene production, or 2010 United States demands for gasoline, diesel, and kerosene (see Section 3). Finally, the total product flow rates arriving at each demand location must be less than the known maximum capacities of the oil refineries and less than the total demand amount within the state. All product flows in the supply chain must amount to TotalFuel, which is determined by the maximum amount that can be produced by the available natural gas feedstock via a parametric analysis (Eq. 11-12).

∑

x f ,c,l,m ≤ FA f ,c

∀( f , c) ∈ CF

(8)

x f ,c,l,m = FR f ,l

∀ f ∈ F, l ∈ LF

(9)

y f ,l,t,q PR p,t,q ∀l ∈ LF , p ∈ P

(10)

( f ,c,l,m)∈FT

∑ ( f ,c,l,m)∈FT

z p,l,c,m =

∑ (p,l,c,m)∈PT

∑ ( f ,t,l,q)∈FL

z p,l,c,m ≤ DM p,c

∀(p, c) ∈ CP

(11)

z p,l,c,m = TotalFuel

∀(p, c) ∈ CP

(12)

∑ (p,c,l,m)∈PT

∑ (p,c,l,m)∈PT

The constraints associated with electricity requirement and production by the selected facilities are defined in Equations 13-18. Produced electricity is assumed to be sold to the grid at $0.07/kWh. Equations 13 and 14 define the electricity requirement and produced for each selected facility, respectively. The electricity requirement is fulfilled in a combination of three ways, namely through solar, wind, or grid electricity (Eq. 15). The amount of solar and wind electricity is capped at 20 MW and 40 MW, respectively, and only apply for locations that receive enough solar irradiation and wind speed for electricity generation (Eq. 16 and 17). Finally, a maximum for the total grid electricity expansion for the whole country is imposed (Eq. 18). In this paper, CapG is equal to

19



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Page 20 of 79

102.5 GW (i.e., about 10% increase of the grid capacity in 2009 113 ). y f ,l,t,q EL f ,t,q = EllT ∀l ∈ LF

(13)

y f ,l,t,q EPf ,t,q = EllP ∀l ∈ LF

(14)

EllT = EllS + EllW + EllG

∀l ∈ LF

(15)

EllS ≤ CapSl

∀l ∈ LS

(16)

EllW ≤ CapW l

∀l ∈ LW

(17)

∑ EllG ≤ CapG

∀l ∈ LF

(18)

∑ ( f ,t,l,q)∈FL

∑ ( f ,t,l,q)∈FL

l∈LF

Note that since all GTL refineries described in Section 3 are net producers of all electricity, all variables associated with the electricity requirement for the supply chain will take the value of zero. Equation 19 defines the freshwater input requirement for each selected facility. This value has to be matched with all water flowrates from various sources (Eq. 20) and they cannot exceed the water availabilities in each source location (Eq. 21).

∑

y f ,l,t,q FW f ,t,q = W Fl ∀l ∈ LF

(19)

∀l ∈ LF

(20)

∀c ∈ CW

(21)

( f ,t,l,q)∈FL

W Fl = ∑ wc,l c∈CW

∑ wc,l ≤ WAc l∈LF

Similarly, Equation 22 determines the amount of CO2 sequestered from each facility. They are delivered to the sequestration sites (Eq. 23), which have maximum capacities that cannot be exceeded (Eq. 24).

∑

y f ,l,t,q SQ f ,t,q = SFl ∀l ∈ LF

(22)

∀l ∈ LF

(23)

∀c ∈ CSQ

(24)

( f ,t,l,q)∈FL

SFl = ∑ seqc,l c∈CSQ

∑ seqc,l ≤ SQCAPc l∈LF

The objective function includes the total overall cost of the energy supply chain network, which 20


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covers (i) the investment costs associated with the new GTL plants, (ii) the electricity costs/gains, (iii) feedstock purchase and transportation costs, (iv) product transportation costs, (v) freshwater purchase and transportation costs, and (vi) sequestered CO2 transportation and injection costs. Note that the electricity sales and purchases are treated separately in the objective function to allow a degree of flexibility for the system to sell or purchase electricity at different costs and at different locations.

∑F CostlI − EllPCost El,P

l∈L

+

∑F EllGCost El,G + EllSCost El,S + EllW Cost El,W

l∈L

+∑

∑F wc,l (CostcW P +Costc,lW T )

+∑

∑F seqc,l (Costc,lCO2,T +CostcCO2,In j )

+

∑

c∈C l∈L

c∈C l∈L

x f ,c,l,m (Cost Ff,c +Cost FT f ,c,l,m )

( f ,c,l,m)∈FT

+

∑

PT z p,l,c,mCost p,l,c,m

(25)

(p,c,l,m)∈PT

Equations 2-25 represent a large-scale mixed-integer linear optimization (MILP) model that can be solved using CPLEX. Note that the model is flexible and can be adapted to solve for nationwide, regional, and statewide GTL supply chains by modifying the input parameters. For a nationwide supply chain case study with 50% natural gas expansion, the model consists of 16,044 binary variables, 1,516,410 continuous variables, and 19,757 constraints. The size of the model varies with the geographical scope of the supply chain problem. The solution of the MILP gives the active binary variables that represent the existence and selection of GTL refineries, the flow rates of feedstocks and products, water, CO2 , electricity amounts in the supply chain. The computation is completed on a single computer containing 8 Intel Xeon 2.83 GHz processors and shared memory parallelization, and the optimization model is solved using CPLEX with eight parallel threads. The best incumbent solutions are reported and the optimality gap for all performed computational studies are below 1%, and the computational times are within 24 CPU hours for regional and statewide case studies, and within 48 hours for the nationwide case studies.

21



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11

Computational Studies

The GTL supply chain optimization model is solved for (i) nationwide, (ii) regional, and (iii) statewide supply chain networks. In the nationwide supply chain studies, different levels of natural gas expansion are considered to show the maximum possible amount of liquid fuels that can be produced for the United States transportation sector via the optimized GTL technologies. For the regional supply chain studies, the optimization problem is solved for the six regions of the United States, namely the Northeast (NE), Southeast (SE), Midwest (MW), Southwest (SW), Central (CE), and Western (WE) regions. The regional divisions of the lower 48 states follow the delineations defined by EIA for natural gas pipelines 121 , and the states that belong in each region can be seen in Table 3. The specifications of the regional supply chain problem include (i) only natural gas resources within the specified region may be used, (ii) the facilities may only be selected within the region, and (iii) the liquid fuels can be delivered to other regions. Finally, the statewide supply chain is defined similarly as the regional case studies, with an additional specification that no inter-county natural gas transportation is allowed. In other words, the county where a GTL refinery is located must be able to satisfy the feedstock requirement of that refinery. The statewide supply chain case study is presented for Texas, which has an abundant resource of natural gas that will greatly enhance the profitability of the GTL refineries in the state. Note, however, that such an analysis can be applied for every state with natural gas resources. Table 3: State groupings and regional definitions of the United States. The grouping defined here is based on the 10 Federal Regions of the U.S. Bureau of Labor Statistics, as published on the EIA website. 121

Region

States

Northeast Southeast Midwest Southwest Central Western

CT, ME, MA, NH, RI, VT, NJ, NY, DE, DC, MD, PA, VA, WV AL, FL, GA, KY, MS, NC, SC, TN IL, IN, MI, MN, OH, WI AR, LA, NM, OK, TX IA, KS, MO, NE, CO, MT, ND, SD, UT, WY AZ, CA, NV, ID, OR, WA

The labeling convention for the supply chain case studies is given in Table 4. The first indicator denotes the geographical scope of the supply chain problem, either nationwide (N), regional (regional acronyms), or statewide (state acronyms, e.g., TX). The second indicator denotes the

22


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percentage of the expansion level of natural gas production and takes the value of 25, 50, 75, or 100. Indicators (U) and (R) signify the fuel ratios produced in the supply chain, whether they are unrestricted (U) or constrained to produce minimum portions of fuel ratio (R). When the fuel ratio is unrestricted, any composition of gasoline, diesel, and kerosene may be produced by the supply chain, and when the fuel ratio is restricted, at least 55 vol% of the total fuels must be gasoline, at least 20 vol% is diesel, and at least 10 vol% is kerosene. These minimum ratios are imposed to represent the composition of the United States transportation fuel demands. Lastly, the case studies with “10” are those that only allow 10 kBPD GTL refineries to exist in the supply chain. These represent the scenario in which modular 10 kBPD plants are built across the country. The 10 kBPD GTL facilities are especially attractive economically since they (i) harness the economies of scale for using one train of process units, (ii) yield good economic results in terms of investment cost and levelized cost of fuels produced, and (iii) are at a manageable scale in terms of feedstock requirements 63 .

11.1

Nationwide GTL Supply Chains

The nationwide supply chain case studies were completed for different levels of natural gas expansion (see Section 2). Based on the 2010 natural gas production levels, the availability of natural gas feedstock for the GTL supply chain is assumed to come from expansion and not from the established production levels. Four (4) levels of natural gas expansion are considered, namely 25%, 50%, 75%, and 100% of the 2010 natural gas production amounts and the usage of these amounts for the GTL supply chain is maximized. In other words, the maximum amount of liquid fuels produced is targeted, rounded to the nearest 100 kBPD. Using this natural gas figures, the resulting total amounts of liquid transportation fuels that can be produced are 1,500 kBPD, 3,100 kBPD, 4,500 kBPD, and 6,200 kBPD, respectively. The lower bounds on the number of the 1 kBPD and 5 kBPD refineries are set to be 5 and 3, respectively, to account for the initial developments of GTL technologies and demonstration of financibility using plants with lower total investment costs. The upper bound is imposed for only the 200 kBPD refineries and is set to be 3, except in the case studies with 100% natural gas expansion level, where the number is increased to 6. The summary of results for all nationwide supply chain case studies can be seen in Table 5.

23



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Page 24 of 79

Table 4: Case study labeling conventions.

Case study label

Geographical scope

Expansion level

Fuel ratio

Facilities

N-100-U

Nationwide

100%

Unrestricted

All

N-75-U

Nationwide

75%

Unrestricted

All

N-50-U

Nationwide

50%

Unrestricted

All

N-25-U

Nationwide

25%

Unrestricted

All

N-100-R

Nationwide

100%

Ratio

All

N-50-R

Nationwide

50%

Ratio

All

N-50-U-10

Nationwide

50%

Unrestricted

10 kBPD

N-50-R-10

Nationwide

50%

Ratio

10 kBPD

NE-50-U

Northeast

50%

Unrestricted

All

NE-50-R

Northeast

50%

Ratio

All

SE-50-U

Southeast

50%

Unrestricted

All

SE-50-R

Southeast

50%

Ratio

All

MW-50-U

Midwest

50%

Unrestricted

All

MW-50-R

Midwest

50%

Ratio

All

SW-50-U

Southwest

50%

Unrestricted

All

SW-50-R

Southwest

50%

Ratio

All

CE-50-U

Central

50%

Unrestricted

All

CE-50-R

Central

50%

Ratio

All

WE-50-U

Western

50%

Unrestricted

All

WE-50-R

Western

50%

Ratio

All

TX-50-U

Texas

50%

Unrestricted

All

TX-50-R

Texas

50%

Ratio

All

TX-50-U-10

Texas

50%

Unrestricted

10 kBPD

TX-50-R-10

Texas

50%

Ratio

10 kBPD

24


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Table 5: Summary of results for the nationwide GTL supply chain case studies. Case Study

N-100-U

N-75-U

N-50-U

N-25-U

N-100-R

N-50-R

N-50-U-10

N-50-R-10

BEOP ($/bbl)

$70.31

$67.34

$65.05

$61.87

$71.40

$66.25

$77.96

$80.25

Levelized cost ($/GJ)

$14.77

$14.38

$14.03

$13.67

$14.82

$13.92

$16.38

$16.35

128

103

71

35

129

71

310

311

1 kBPD

5

5

5

5

5

5

0

0

U

5

4

5

5

4

5

0

0

D

0

0

0

0

0

0

0

0

K

0

1

0

0

1

0

0

0

R

0

0

0

0

0

0

0

0

5 kBPD

3

3

3

3

5

3

0

0

U

3

3

3

3

2

3

0

0

D

0

0

0

0

3

0

0

0

K

0

0

0

0

0

0

0

0

R

0

0

0

0

0

0

0

0

10 kBPD

18

18

13

8

17

13

310

311

U

17

15

10

8

13

11

252

186

D

0

0

0

0

4

0

0

83

K

1

3

3

0

0

2

57

42

R

0

0

0

0

0

0

1

0

50 kBPD

96

74

47

16

96

47

0

0

U

59

53

35

14

62

30

0

0

D

0

0

0

0

16

9

0

0

K

37

21

12

2

18

8

0

0

R

0

0

0

0

0

0

0

0

200 kBPD

6

3

3

3

6

3

0

0

U

5

3

3

3

2

1

0

0

D

1

0

0

0

4

2

0

0

K

0

0

0

0

0

0

0

0

R

0

0

0

0

0

0

0

0

19.67

13.96

9.33

4.04

18.13

8.98

8.22

8.11

Total number of facilities

Electricity produced (GW) Total fuels (kBPD) Gasoline (kBPD) Diesel (kBPD)

6,200

4,500

3,100

1,500

6,200

3,100

3,100

3,110

4,655.00

3,689.25

2,627.50

1,425.00

4,283.00

2,147.50

2,669.21

2,172.50

150.00

0

0

0

1,241.25

637.50

2.15

622.50

Kerosene (kBPD)

1,395.00

810.75

472.50

75.00

675.75

315.00

428.63

315.00

Total LHV output

34.89

25.16

17.29

8.29

35.25

17.62

17.27

17.67

18.09

13.14

9.05

4.38

18.19

9.09

8.83

8.97

Natural gas purchase

5.76

5.81

5.80

5.85

5.73

5.72

5.68

5.63

Natural gas trans.

2.83

2.79

2.75

2.81

2.86

2.56

3.07

2.98

Butane purchase

0

0

0

0

0

0

0

0

Investment cost

6.77

6.89

6.86

6.76

6.66

6.69

8.29

8.12

Product trans.

1.19

0.77

0.61

0.56

1.26

0.64

0.69

0.70

Water purchase and trans.

0.01

0.01

0.01

0.01

0.01

0.01

0.01

0.01

CO2 trans. and injection

0.45

0.51

0.45

0.36

0.44

0.44

0.96

0.99

Propane sale

1.30

1.46

1.55

1.87

1.27

1.29

1.54

1.33

Electricity sale

0.95

0.93

0.91

0.82

0.86

0.86

0.80

0.77

(million GJ/day) Natural gas usage (trillion SCF/yr) Average cost breakdown ($/GJ)

25



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11.1.1

Costs of Fuel Production

In this section, the base case for the nationwide GTL supply chain is case study N-50-U where 50% natural gas expansion produces a total of 3,100 kBPD of liquid fuels, approximately 23.5% of the total liquid fuel demand in the United States. The break even oil price (BEOP), which is obtained from deducting the refiner’s margin from the total cost for all gasoline, diesel, and kerosene produced and dividing the remainder with the total volume produced in the supply chain, is $65.05/bbl. This BEOP is the minimum price of crude oil at which the supply chain becomes competitive with petroleum based processes and is also equivalent to a levelized cost of $14.03/GJ LHV (lower heating value) of total fuels produced. The contributing factors of the fuel production cost for each case study are comprised of: (1) natural gas purchase cost, (2) natural gas transportation cost, (3) GTL refinery investment cost, (4) water purchase cost, (5) water transportation cost, (6) butane purchase cost, (7) electricity cost, (8) fuel product transportation cost, (9) CO2 transportation for sequestration, and (10) CO2 injection cost. Natural gas, water, butane, and electricity are inputs to the GTL refineries, and gasoline, diesel, and kerosene are the main outputs of the refineries. None of the GTL refineries requires a net input of electricity, meaning that no electricity purchase cost applies to all case studies. Instead, the GTL refineries are net producers of electricity, and the sale profits from selling electricity to the grid are used to offset the overall total cost of fuel production. The second byproduct of these GTL refineries is propane/liquefied petroleum gas (LPG), and the sale profits are accounted for in the total cost figure. For case study (N-50-U), the cost breakdown for the entire supply chain is shown in Figure 2. The highest contributing factor is the investment cost to build the GTL refineries ($6.86/GJ), amounting to 41.60% of the total cost, followed by the natural gas purchase cost ($5.80/GJ) at 35.20%, and natural gas transportation cost ($2.75/GJ) at 16.67%. The relative contributions of the costs are consistent with the cost breakdown of the individual GTL refineries in Baliban et al. 63 . The product transportation at $0.61/GJ (3.70%) contributes to the overall cost in a lesser degree than the natural gas transportation due to the locations of the GTL refineries that are close to the oil refineries (see Figure 4), the demand end points for the GTL fuels. Water purchase and transportation, and CO2 transportation and injection costs contribute minimally to the overall cost

26


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figure at 0.09% and 2.74%, respectively. A total of 9.33 GW of electricity is produced, resulting in an amount of $0.91/GJ that offsets the overall cost, and an additional $1.55/GJ is deducted from the cost by the sales of byproduct LPG. The co-production of electricity is significant because no futher fossil fuels resources are added to satisfy the power requirement of the GTL refineries, implying that no additional greenhouse gas from electricity production is emitted. Since the optimization model relies on a large amount of data, the input parameters in this model are subject to uncertainties. The major sources of uncertainties are the prices of natural gas, the availabilities, and transportation costs. These uncertainties can be incorporated in a robust optimization framework for suppply chain design under uncertainty, which is the subject of future study. To illustrate the effect of changes in the price parameters, however, a parametric analysis is completed on case study (N-50-U) in which the natural gas prices are varied to 10% below and above the current nominal values. Note that each location has a different natural gas price parameter and the drop or increase in the price is done uniformly across the supply chain. For these case studies, the BEOP values are $61.78/bbl and $68.62/bbl, respectively, resulting in 5% change in the BEOP value from the nominal case study. The selection of the locations is generally uniform, with exchanges between the selection of one additional 50 kBPD refinery and five less 10 kBPD refineries, and vice versa. When the liquid fuels ratio is unrestricted, the supply chain produces a total of 2,627.50 kBPD of gasoline (84.76 vol%) and 472.50 kBPD of kerosene (15.24 vol%), with no production of diesel. The reason why no (D) GTL refineries that maximize the production of diesel is selected is because the natural gas feedstock requirements of the (D) refineries are higher than their unrestricted (U), maximization of kerosene (K), and United States fuel ratio (R) equivalents (see Table 2). In other words, to produce the same volume of liquid fuels, the (D) refineries require a greater amount of natural gas. In the supply chain formulation where it is desired to maximize the total volume of liquid fuels from the existing natural gas, it is intuitive that the (D) refineries are not selected even though their investment costs are comparatively lower (see Table 2). For the United States, however, some amount of diesel must be produced to fulfill the transportation fuel demands, which accounts for about 22 vol% of the total demand 107 . To impose the production of diesel, the case studies with minimum portions of liquid fuels are presented. Case study (N-50-R) produces a total of 2,147.50 kBPD of gasoline (69.27 vol%), 637.50 kBPD of 27



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Product Trans 3.70%

Water Purchase 0.08%

Water Trans CO2 Seq 2.67% 0.01%

CO2 Inj 0.07%

NG Purchase 35.20% Investment cost 41.60% NG Trans 16.67%

Figure 2: The cost contributions for the nationwide supply chain case study (N-50-U).

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diesel (20.56 vol%), and 315.00 kBPD of kerosene (10.16 vol%), with a BEOP value of $66.25/bbl, slightly higher than case study (N-50-U). Note in Table 5 that even though the BEOP is higher compared to the unrestricted case study, the levelized cost is lower ($13.92/GJ) due to the higher total amount of LHV output when diesel is produced (17.62 million GJ/day as opposed to 17.29 million GJ/day). The levelized investment cost is $6.69/GJ, the natural gas purchase cost is $5.72/GJ, and the natural gas transportation cost is $2.56/GJ, accounting for 41.63%, 35.62%, and 15.97% of the total costs, respectively (see Figure 3). The total electricity output is reduced from 9.33 GW to 8.98 GW due to the fact that the (D) refineries produce less amounts of electricity output compared to the (K) refineries (see Table 2). Product Water Water Trans CO2 Seq 2.67% Trans Purchase 0.01% CO2 Inj 0.08% 3.96% 0.07%

NG Purchase 35.62% Investment cost 41.63% NG Trans 15.97%

Figure 3: The cost contributions for the nationwide supply chain case study (N-50-R).

In the case where 100% of natural gas expansion is assumed (N-100-U), the total fuels produced is 6,200 kBPD with a BEOP value of $70.31/bbl and a levelized cost value of $14.77/GJ. The contributions of capital investment, natural gas purchase, and natural gas transportation costs to the 29



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overall cost are 39.79%, 33.84%, and 16.65%, respectively. Product transportation cost accounts for 6.98% to the overall cost, CO2 transportation and injection for sequestration account for 2.65%, and water purchase and transportation account for less for 0.08%. In this case, a small amount of diesel is produced (150 kBPD) due to the selection of one 200 kBPD refinery that maximizes the production of diesel (refinery D-200). The product compositions are 75.08 vol% gasoline, 2.42 vol% diesel, and 22.50 vol% kerosene. When the fuel ratio is enforced in case study (N-100-R), the BEOP increases to $71.40/bbl and the levelized cost to $14.82/GJ. The amount of electricity produced is reduced from 19.67 GW to 18.13 GW, and the supply chain produces 4,283.00 kBPD of gasoline (69.08 vol%), 1,241.25 kBPD of diesel (20.02 vol%), and 675.75 kBPD of kerosene (10.90 vol%). The investment cost accounts for 39.28% of the total cost with similar composition for the rest of the cost contributors. The effect of natural gas availabilities to the amount of fuels that can be produced can be seen in case studies (N-100-U), (N-75-U), (N-50-U), and (N-25-U). The BEOP decreases from $70.31/bbl, $67.34/bbl, $65.05/bbl, to $61.87/bbl, respectively, and the contributions of the investment cost are 39.79%, 41.05%, 41.60%, and 41.36%, respectively. The electricity outputs are 19.67, 13.96, 9.33, and 4.04 GW, and the propane byproduct sales grows more significant as the fuel production decreases. While the cost figures are similar, the topological network of the supply chains differ between the four case studies and the differences will be discussed in Section 11.1.2. Two additional case studies are presented with only 10 kBPD GTL refineries allowed in the supply chain, representing scenarios in which modular 10 kBPD plants are built across the country. The 10 kBPD GTL refineries are especially attractive economically since they maximize the economies of scale for using one train of process units, yield good economic results in terms of investment and levelized cost of fuels produced, and are at a scale where natural gas feedstock can be supplied locally. The unrestricted case study (N-50-U-10) has a BEOP of $77.96/bbl, 20% higher than case study (N-50-U), producing 2.669.21 kBPD gasoline, 2.15 kBPD diesel, and 428.63 kBPD kerosene. This increase is largely due to the investment cost contribution (44.27%) since the 10 kBPD refineries have higher levelized investment costs compared to the 50 kBPD and 200 kBPD refineries. The natural gas purchase contribution to the cost is decreased due to the lower natural gas usage overall. However, the transportation cost for natural gas is increased from $2.75/GJ to $3.07/GJ, due to the more dispersed layout of the GTL refineries locations. Lastly, when the fuel 30


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ratio is enforced (N-50-R-10), the BEOP further increases to $80.25/bbl due to lower byproduct LPG and electricity production. 11.1.2

Supply Chain Network Topology

The base case study (N-50-U) selected a total of 71 GTL refineries, 5 of 1 kBPD capacity, 3 of 5 kBPD capacity, 13 of 10 kBPD capacity, 47 of 50 kBPD capacity, and 3 of 200 kBPD capacity. Note that the solution consistently hits the lower and upper bounds for the 1, 5, and 200 kBPD refineries, respectively, for all of the nationwide case studies. The selection of larger facilities are more favorable, with most of fuel productions taking place in 10, 50, and 200 kBPD refineries. Each GTL refinery of a given capacity can have four modes of fuel production, namely (i) unrestricted (U), where no fuel ratio restriction is imposed, (ii) maximization of diesel (D), with a ratio of 75 vol% diesel and 25 vol% gasoline, (iii) maximization of kerosene (K), with a ratio of 75 vol% kerosene and 25 vol% gasoline, and (iv) fuel ratios commensurate with the United States demand (R), with a ratio of 67 vol% gasoline, 22 vol% diesel, and 11 vol% kerosene. The breakdown of the selected refinery types for each case study can be seen in Table 5. In case study (N-50-U), only the (U) and (K) GTL refineries are selected. The 1, 5, and 200 kBPD refineries are (U) GTL refineries, and the 10 and 50 kBPD refineries are a mixture of (U) and (K) refineries. The selection of these plants are not only motivated by the costs of the plants, since on an individual plant basis, the (D) refineries have the lowest investment costs. Instead, it is also driven by the amount of natural gas feedstock required by the refineries, which in this case study amounts to 9.05 trillion SCF annually. Even though the (D) refineries have lower overall costs, they require a higher amount of natural gas per unit volume of total fuels produced (see Table 2). For example, the (D-10) refinery requires 3.76 MSCF/hr, higher than the 3.61 MSCF/hr required for (U-10), 3.54 MSCF/hr for (K-10), and 3.62 MSCF/hr for (R-10). In the supply chain case studies where we maximized the production of liquid fuels to use as much natural gas resources as possible, the selections of the (U) and (K) refineries dominate. Most of the selected 71 refineries are located in the Southwest and Central regions of the United States, with several facilities around the intersections of the Northeast, Midwest, and Southeast regions. Figure 4 shows the graphical representation of the supply chain network layout, with the blue boxes indicating where the natural gas resources are drawn from, the brown circles indicating 31



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

"""" " " " " "" "^ " _ "MT ND "" " " """ _ ^ " " " MN MI "" """^ _ "" " " ^ _ ME "" " " """ " " "" " " "" " " SD WI ID """ " " """ " VTNH " " " " "^ _ OR MI " " " " " " " "" NY "WY" _" ^ _" ^ """""" "^ _ """ """ ^ IA "" " _ "" ^ " " _ " " " " CTMA " " NE " " " " " " "" """ _" " " " "" " "" " "" _ ^ "" ""PA " _ " ^"^ " " " RI _ ^ " " " " _ " " ^ " " " " " " " " " " " " " " "" "" " "" " " NJ " "" " " "" """"" " _ "" IL IN OH " " "" " " " "" " "" "" " "^ " " " "" MD "" " " " UT " NV ^ " _ " " " "" " " " " " " " " " " " " " " CO " " DE "^ """" WV "" MO " " " " "" " "" " " _ "" ^ """" " "" " " "" "KS " " "" " " "" "" " " """" "_ " " " "" "" " " " " " KY " " """ "" " "" " " " " " " " "" "" "" " """ "" "" " "" VA " " "" " " " "" """ " " " " " " " " "" _ " ^ _ ^ " " " " " " " " "" " " " " " " " _ _ ^ ^ " " " " " " " "^ CA """ "" """ "" _ "" """ """" _^ ^ " "" " "" TN "" _"" ^ """ """" _ " " " OK NC _" " " ^ " "" " " " """" " " " " "" " " " "" _ ^ " " " " " " " """"" " " " AR "" " " _ ^ " " " " " " NM " " " " " AZ " " _ ^ " " " " " " " """" " " """"" " SC " " _ ^ " " " " " " " " " " " """AL _ " ^ " " """ "" " "" "" " " " "" "" " " _ ^ " """ GA " " " " " " " " MS " _ ^ " " " "" " _ ^ " " "" " "" "" "^ " """ " _ _ "" " " " "" " _ """ ^ " " " " "" "" """"^ " """ """ "" "" " " " " " " " " " _ "" ^ " " " " " " " " " " " " " " " " TX " " " " " " " " " " """ " " " " " " " " " " " " " " " LA " " " " " " "" "" " """ " " """ "" "" _ " "" " " "" "" _ ^ " " ""^ _" "" """"" ^ " " "" _"" ^ " " "" _ " ^ "" """ Total capacity 3,100,000 BPD Natural Gas Feed Source " "" _ ^ " " " "" " " _"" " """"" " ^ " " " " " " " " " " " Plant size (BPD) Flow " """"""" FL " "" 1000 _ ^ "" " 0.000000 - 22.131700 "" "" " " " 5000 22.131701 73.574100 " """ " 10000 " 73.574101 - 180.423600 180.423601 367.672100 " 50000 0 110 220 440 660 880 1,100 1,320 1,540 Miles " 367.672101 - 866.572800

WA

200000

_ ^

Fuel Products Delivery Locations

Figure 4: Graphical representation of the locations of selected facilities for unrestricted nationwide supply chain case study with 50% natural gas expansion (N-50-U). The facilities are represented by dark brown circles with sizes that correspond to their respective capacities. The blue boxes indicate where the natural gas resources are drawn from and the red stars indicate the end locations of fuel delivery.

32


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the locations of the selected refineries, and the red stars indicating the end locations of fuel delivery. The produced liquid fuels are delivered to oil refineries to be distributed to the final consumer points or to be blended with petroleum-based fuels before distribution. The GTL fuels are high-quality liquid fuels that have close to zero sulfur content, and can be used to improve the quality of the petroleum fuels via blending. The locations of the facilities align well with the locations of the fuel delivery locations, which correspond to the fact that the product transportation cost contributes in a lesser degree than the natural gas transportation cost. This is intuitive since there are more locations of natural gas resources than fuel delivery locations and multiple sources of natural gas are required to fulfill the requirement of the facility. Locating the GTL refineries farther from the oil refineries will not guarantee that the natural gas transportation cost will be reduced. When the nationwide supply chain produces a ratio of gasoline, diesel, and kerosene (case study N-50-R), the network topology consists of the same total amount of GTL refineries and the same breakdown for each capacity level. However, the types of the selected GTL refineries differ due to the minimum amount of diesel imposed. Diesel is produced by the 9 refineries of 50 kBPD capacity and 2 refineries of 200 kBPD capacity. The resulting total amount of natural gas usage increases from 9.05 to 9.09 trillion SCF/yr, and the modified topological layout of case study (N50-R) is shown in Figure 5. Note that no (R) refineries are selected in the supply chain due to their high investment costs compared to the (U), (D), and (K) refineries. When 100% of natural gas expansion is allowed (N-100-U), (U) and (K) refineries are selected except for 1 refinery of 200 kBPD capacity. A total of 18.09 trillion SCF/yr natural gas is required and more populated Southwest and Central regions are observed (see Figure 6). In case study (N-100-R), the selected (D) refineries selected are the 3 refineries of 5 kBPD capacity, 4 refineries of 10 kBPD capacity, 16 refineries of 50 kBPD capacity, and 4 refineries of 200 kBPD capacity (see Figure 7 and Table 5). The selection of more (D) facilities in the larger refineries is caused by the switch in the ranking of natural gas requirement between the modes of fuel production. At 200 kBPD, the (D) refinery requires 73.85 MSCF/hr of natural gas (D-200), while the (K-200) refinery requires 77.28 MSCF/yr, the (U-200) refinery requires 73.57 MSCF/yr, and the (R-200) refinery requires 72.20 MSCF/yr of natural gas. Thus, no (K-200) refinery is selected in any of the nationwide case studies and only (U-200) and (D-200) refineries are selected. The (R-200) refinery requires the lowest amount of natural gas feestock, but the portion of diesel produced is 33



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Page 34 of 79

""""""" " " "" "^ " _ MT """ " " """" " ND _ ^ MN MI "" " ME "" _ ^ _ ^ " " " "" " " " " " " " " " " " " SD WI ID " " " " " " VT " " " " " " " " " OR " _ MI ^ """ """" NY NH "" WY" _" ^ _" ^ "" " "" "" _ """ ^ "" """ ^ MA IA " " " " " " _ " " ^ _ " NE " " " " " " "" " _"" " """"^ " "" ^ " """ CT " " " " " _ " " PA " " _ " " ^ " " " _ ^ " " " _ ^ " " " " "" " " """"" "" NJ "" " " " "" " " " " " IL IN "OH _ ^ " " " "" """ " "" " " " " " " ""MDDE "" " " NV ^ " " """ " " _ UT " " CO " " " " " MO " " " " "" " " " "" " " WV " " " " " " KS " " " " " " " " " " " " _ " " ^ _ " " ^ " " " " """ " " "" _ """" "" ^ "" " " " "" """ "" " "" " " " """ " KY "" "" " " " " " " "" " " "" VA "" " "" "" "" " " " " " "" " " " " " "" " " " _ ^ " " " " " """ "" "" " "" "" " " "" " " " _ _ ^ ^ " " " CA " " " " " " " " " " " " " _ ^ " " """ """""""""" _ ^ " "" TN " "" "" " _" " ^ OK NC ""^ _ " " " _" " ^ "" "" "^ """" " "" "" " " " "" "" "" " """" AR " "_"""" " "" " """^ " _ ^ " " NM " " " " " " AZ " _ " ^ " " " SC _ " " " " " " " " " "" """ """ " " "" " """" "" GA """ " "" _ ^ " "" "" "" "" " _ " ^ AL " "" " " " _ " " ^ " _ MS ^ "" " " " " " "" "" " "" " _ "" "" ^ " " " " "" " "" _ _ " ^ ^ " " _ ^ " " " " " " " " " " " " " " " " "" " " " " " " " " " _ """ " " " ^ " " " " " " " " " " " TX " " " " " " """ " " "" " "" " "" "" " " """ " " " "LA "" " "" """ " "" "" " " "" " " _""" """ ^ " " "" " "" "" " " " " " """ " _ " ^ " " "" " " " _ ^ "" " " "" " " " " " " " " _ ^ _ ^ " " " _ ^ " " """ " " " " " " _ ^ "" """ """ "" " "" "" " "" " " " " FL " " "" " _ ^ " " " """" " Legend " WA

United States - Total Capacity: 3,100,000 BPD Natural Gas Feed Source Plant size (BPD) 1000 5000

10000 50000

200000

_ ^

Flow (mscf/day)

" " " " "

0 105210

420

630

840

1,050 1,260 1,470 Miles

0.000000 - 22.826400

22.826401 - 76.020200

76.020201 - 185.241200

185.241201 - 360.608300 360.608301 - 964.403200


Figure 5: Graphical representation of the locations of selected facilities for the nationwide supply chain case study with 50% natural gas expansion and minimum portions of liquid fuels produced (N-50-R). The facilities are represented by dark brown circles with sizes that correspond to their respective capacities. The blue boxes indicate where the natural gas resources are drawn from and the red stars indicate the end locations of fuel delivery.

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not sufficient to fulfill the portion of diesel required for the supply chain. Consequently, along with the fact that the (R) refineries incur higher overall costs compared to the (U), (D), and (K) refineries, they are not selected in the supply chain.

"""" " " " " "" "^ " _ "MT ND "" " " """ _ ^ " " " MN " MI "" """^ _" " " ^ _ ME "" " " """ _ ^ " " "" " " " SD WI ID """ " " """ " " " VTNH " " " " " " _ OR ^ MI " " " " " " " "" NY "WY" _" ^ _" ^ """""" "^ _ """ """ ^ IA "" " _" "" ^ "" " CTMA _ " " "^ " " " NE " " " " " " " _ " ^ " " "" " " "" "" ""PA " " "" "_ "" "" "" _" " ^ "" " " RI _ ^ " " " " " _ " " ^ "" " " "" " " """ " "" " " " " "" " "" " " " " "" " _ ^ _NJ ^ " "" " IL IN "OH " " " " " " " " " " " " " " " " " " " " UT " " NV " _ " ^ " " " "" " " " "" " " "" " MDDE " " " """ " " "" " " "" " CO "" WV "" " " " " " "" " "" " " _ " ^ """^ _ "" MO " " " " " " "" " "KS " " "" " " "" "" " _ " ^ """" "^ """ " "" "" " " " _""" " "" " KY " " "" " VA "" "" "" " " " " " " "" " "" " " """ "" "" " " """" " " " " " " " " " " " " " " " " " " " "" _ " ^ _ ^ " """ "" """" "" "" "" _ " " """ "" _" ^ """ "" " "^ "^ " CA " "" " _ "" " """ """" _^ ^ " " " "" "" TN "" _"" ^ """ """" _ " " OK NC _" " " " ^ " "" " _" " " ^ " " " " " "" " " " " " " _ ^ " " " " " " " " " " " " " AR"" "" "" """"" " "" " """ _ ^ NM "" " " AZ " _ ^ " " " " _ " ^ " " " " " " SC " "" _" ^ " " "" " "" " "" " " """ " " """" " _ " ^ "" " " "" "" "" " " _ ^ "" "" AL " "" _ ^ " _ """ GA " " "" " " "" " MS "^ " " " " "" " " _ ^ " " "" " """ "" " "^ " """ " _ _ "" " ^ " " "" " _ """ ^ " " " " " " " " " " " " " " " " " " " " " " _ "" " ^ " _ ^ " " " " " " " " " " " " " " " " " " " " " TX " " " " " " " " """""" " " " " "" " " "" " " " "LA "^ _" """ """ "" "" " _"^ "" " """ " "" "" "" " _ " "" " " _ ^ " " ^ _ ^ " " " _ """"" ^ " " " " "" _ ^ " " " " "" _ " ^ _ ^ """ "" """ " Total capacity 6,200,000 BPD Natural Gas Feed Source "^ _ ^ _ "" "" " " " "" " " " _ _ ^ " " ^ " " " " """ _ ""^ "" Plant size (BPD) Flow "" FL _ "" "" "^ "" " " 1000 " _ ^ "" " 0.000000 - 48.366100 "" " " "" " " 5000 " 48.366101 - 150.694800 "" 10000 " 150.694801 - 318.361200 " 318.361201 - 721.216700 50000 0 110 220 440 660 880 1,100 1,320 1,540 Miles " 721.216701 - 1526.546200

WA

200000

_ ^


Figure 6: Graphical representation of the locations of selected facilities for unrestricted nationwide supply chain case study with 100% natural gas expansion (N-100-U). The facilities are represented by dark brown circles with sizes that correspond to their respective capacities. The blue boxes indicate where the natural gas resources are drawn from and the red stars indicate the end locations of fuel delivery.

The described pattern also applies in case studies (N-50-U-10) and (N-50-R-10). In the former case, mostly (U) and (K) 10 kBPD refineries are selected, with 1 (R-10) refinery selected. In the latter case, (U), (D), and (K) refineries are selected to fulfill the minimum fuel ratio. Since the (D-10) refineries require more natural gas, the total natural gas usage increases from 8.83 to 8.97 MSCF/yr. A larger number of total plants are selected in these case studies, 310 and 311, respectively, and Figures 8 and 9 show that the Southwest and Central regions are the most

35



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Page 36 of 79

_ ^ _ WA ^

""""""" " " "" "^ " _ MT """ " " """" " ND _ ^ MN MI "" " ME "" _ ^ _ ^ " " " "" " " " " _ ^ " " " " " " " " SD WI ID " " " " " " VT " " " " " " " " " OR " _ MI ^ """ """" NY NH "" WY" _" ^ _" ^ "" " "" "" _ """ ^ "" """ ^ MA IA " " _ ^ " " " " _ " " ^ _ " NE " " " " " " "" " _"" " """"^ " "" " """ CT " " " " " _ " " PA " " _"^ " ^ " " " " " _ ^ " " " _ ^ " "" " " "" _NJ " " """"" "" "" " " "" " " " " " IL IN "OH _ ^ " " " " "" """ " "" " " " " " " ""MD^ "" " " NV ^ " " """ " " " "" _ UT " " " CO " " " " " MO " " " " "" " " " "" DE " " WV " " " " " KS " " " " " " " " " " " " " _ " " ^ _ " " ^ " " " " " " "" "" " " " "" """" "" _ ^ """ " " _ " " ^ " """ "" " "" " _ ^ " " " " " " " " KY " VA " " " " " " " " " " " " " " "" " " " " " " " " " " " " " " " " " " " " " " " _ ^ " """ "" """" "" " """ """ "" "" """" _"" " _" " " ^ CA ^ " "" "" " "" _ ^ " " " _ ^ " "" TN " "" "" "" " _" " ^ " OK NC ""^ _ " " ^ "" " " " " " " " " _ ^ " "" " " " _ " " ^ " " " " " " " " " " " _ " " " " " " " " " " " AR"" " """" "" "" """ " _ ^ " NM " """"""" " " " " AZ " _ ^ " SC " " " _ ^ _" ^ " " " " " "" """ """ " " "" " """" "" GA """ " "" _ ^ " "" "" "" "" " _ " ^ AL " "" " " " _ " " ^ " _ MS ^ "" " " " " " "" "" " "" " _ "" "" ^ " " " " "" " " "" _ _ " ^ ^ " " _ ^ " " " " " " " " _ ^ " " " " " " " " " " " " " " " " " " _ """ " " " ^ " " " " " " " " " " " TX " " " " " " " "" " "" " " "" "" " " """ " " " "" "" "LA "" " " "" """ " "" """ " " "" " " " _""" """ ^ " " " " " " " " " _ " ^ " " _ " ^ " " " " " " _ ^ " " " " " " " " " " " " " " _ """ "^ " _ "" "^ "^ _ _ "^ "" " " " _ _ ^ "" "^ " " "" _ ^ " "" " " " "" "" " "" _ " ^ " " " FL " " " " _ ^ " """ "" " Legend "" " United States - Total Capacity: 6,200,000 BPD Natural Gas Feed Source Plant size (BPD) 1000 5000

10000 50000 200000

_ ^

Flow (mscf/day)

" " " " "

0 105 210

420

630

840

1,050 1,260 1,470 Miles

0.000000 - 47.099100

47.099101 - 147.148300

147.148301 - 306.977300 306.977301 - 721.216700

721.216701 - 1526.546200


Figure 7: Graphical representation of the locations of selected facilities for the nationwide supply chain case study with 100% natural gas expansion and minimum portions of liquid fuels produced (N-100-R). The facilities are represented by dark brown circles with sizes that correspond to their respective capacities. The blue boxes indicate where the natural gas resources are drawn from and the red stars indicate the end locations of fuel delivery.

36


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populated areas due to their abundant natural gas resources. A series of oil refineries along the southern border of Texas and Louisiana receive the fuels produced from the GTL facilities.

"" """" " "" ""^ ND _"MT " " " """" " ^ _ " MN "^ " MI " ME " "" _ _"" "" SD ^ "" " " " " "" " " " " " WI " ID " " " VT " "" " " OR " " " " " _ ^ ""MI """" NY NH WY" "" " _" ^ _ ^ " "" " "" " " """ ^ _ ^ IA " " " " " _ ^ " " CTMA " " " _ ^ ""^ " " _"" ^ " " " " " " " " "" NE " """ ^ " _""" " " _ PA " " "_ " " " " " _"^ ^ "" " " " " _ ^ " " " " " _ ^ " " "" OH " _ " " " " " NJ " " " " " " "" "" " "" ^ "" " " IL IN "" " " """" " " _ " " " "" " " " " " " NV ^ " " " " "" _ UT" "" " " " " " MO " " """ "" " " " ""CO " " " WV " " "" MDDE KS " " " " " " " " " " " " " " " " _ ^ " " _ ^ " " " " " " " " " " " " " " " " " " _ ^ " " " " " " " " " " """" " VA " " " " " "" " "" " " "" """ " """ " "" " """ " " " " ""KY "" " " " " "" " " " _ ^ _ ^ " " " " " "" "" " " "" " " "" " """ CA " " _ ^ " _ ^ " " """ " " " " " " " "" " " " " " " _ ^ " " TN " _ ^ " " " " " " " " OK NC " " " _ ^ " " " " _" " "" " "" " _ "NM ""^ ^ "" " " " _" " " " " " " "" " " " " " _"""" ^ "" " """ " "" " AR " " " "" " "^ " " _ ^ " " " AZ " " " " " "" " " _ ^ SC " " " " _ ^ " " " " " " " "" """ "" " " "" GA " " """ " """ " " _ ^ " "" "" "" " " " AL " _ ^ " " MS " " " " " " " " "" " " _ ^ "" " " " " " " _ ^ " "" " " "" " " " " _ ^ " " " " " " _ ^ _ ^ " " _ ^ " " " " " " " " " " " " " " " " " "" " " " " " " " " " " " " " " _ """ ^ _ ^ " "" "" " TX "" """ ""LA " " "" " "" " " "" """ " " "" "" " " "" " "_ " " " " " "" " " " " " " " " """ " " " " " "" "" " _ ^ " ""^ _ ^ " " " " " """" " "" _ ^ " " " " " " " _ ^ " "" " " " " " " " " " _ ^ " _ ^ _ ^ " " " _ ^ " _ ^ " " " " " "" "^ _ " " " _"" ^ "" " " "" "" " "" " " _ ^ " FL " " " " _ ^ " " """ "" Legend "" " WA

Plant size (BPD) 10000

_ ^


Natural Gas Feed Source Flow (mscf/day)

" " " " "

0.000000 - 8.220400

0 110 220

440

660

880

1,100

1,320

1,540 Miles

8.220401 - 23.111000

23.111001 - 41.819000

41.819001 - 68.173400 68.173401 - 86.614100

Figure 8: Graphical representation of the locations of selected facilities for unrestricted nationwide supply chain case study with 50% natural gas expansion and only 10 kBPD facilities allowed (N-50-U-10). The facilities are represented by dark brown circles with sizes that correspond to their respective capacities. The blue boxes indicate where the natural gas resources are drawn from and the red stars indicate the end locations of fuel delivery.

11.2

Regional GTL Supply Chains

While the nationwide supply chain studies can address the feasibility question of whether the natural gas supply in the United States can replace petroleum derived fuels and by how much, the implementation of the GTL supply chains will more applicable in a regional or statewide scale since each region will primarily optimize in favor of its own interest and energy needs. Thus, the optimization problem is solved for the six regions of the United States and the natural gas 37



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Page 38 of 79

"" """" " "" ""^ ND _"MT " " " """" " ^ _ " MN "^ " MI " ME " "" _"" "" _ ^ "" " "" " " "" " " " SD " " WI " ID " " " VT " "" " " OR " " " " MI _ ^ "" """ "" NY NH WY" "" " "" _^ ^ _ " "" "" """""""" CTMA "" " " """ ^ _ ^ IA " " _ ^ ""^ " " " " " " " " " " " "" NE " """ " _""" " " _ PA " " "_ " "" " " " " _"^ ^ "" " " _ ^ " " _ ^ """ " "" OH " " " " " " NJ " " " " " " IN " " " " " " " IL " " " " " " _ ^ _ " " " " " " " ""MD^ NV ^ " " " """ " " " " " " _ UT" """""CO "" " " " " " " " DE " " " " " WV " " " " KS " " " " " " " " MO " " """"""" " " " " " "" _ ^ "" VA _ ^ """ "" " " " """ """ "" " " " _"" ^ " " " " " " "" " " _ ^ " " KY " "" " " " " "" " "" "" " "" " " " " "" " " " " "" " "" " " " " " " " " " _ ^ " " " " " " " " " " " " " " " " " " _ ^ " _ ^ " " CA " " " " " " " " " " " " " "" " " _ ^ " "" TN " _ "" " """ "" "" OK NC " _" ^ ""^ " " _ " " " "" " _" "NM " ^ "^ " " " " _ "^ " " " "" " " " " " _"""" "" " "" " "" "" " AR "" " " " " " " "^ " " " _ ^ " " AZ " " "^ " " " " " " _ ^ SC " " " " _" " " " " " " " " GA "" """" " " " " " " "" " """ " " _ ^ " "" "" "" " " " AL " _ ^ " " " MS " """ " " " " "" " " _ ^ "" " " " " " """" " " " _ ^ " " " " " " " " " _ ^ " " " " " " _ ^ _ ^ " " _ ^ " " " " " " " " " " " " " " " " " " " " " " " " " " " """ _ """"""" ^ " " "" " TX "" "" "" " " "" " " """" " " " "" " " " " LA " "" "^ " " " " " "" " " " " " " " " " """ " _ " " " " " "" " " _ ^ " ""^ _ ^ " " " " " """" " " _ _ ^ " " " " " " " _ ^ " "" " " " " " " " " " _ ^ " _ ^ _ ^ " " " _ ^ " _ ^ " " " " " "" "^ _ " " " _"" ^ "" " " "" "" " "" " " _ ^ " FL " " " " _ ^ " " """ "" Legend "" " WA

Plant size (BPD) 10000

_ ^



" " " " "

0.000000 - 7.707800

0 110 220

440

660

880

1,100

1,320

1,540 Miles

7.707801 - 21.682400

21.682401 - 41.350500 41.350501 - 66.817700 66.817701 - 90.338800

Figure 9: Graphical representation of the locations of selected facilities for the nationwide supply chain case study with 50% natural gas expansion, minimum portions of liquid fuels produced, and only 10 kBPD facilities allowed (N-50-R-10). The facilities are represented by dark brown circles with sizes that correspond to their respective capacities. The blue boxes indicate where the natural gas resources are drawn from and the red stars indicate the end locations of fuel delivery.

38


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expansion level is set to 50% for all case studies. The specifications of the problem are modified such that (i) only natural gas resources within the specified region may be used, (ii) the refineries may only be located within the region, and (iii) the liquid fuels can be delivered to other regions. The lower bound of the number of 5 kBPD refineries is removed to accommodate regions with less natural gas resources and the summary of results for the unrestricted and minimum fuel ratio regional case studies are shown in Tables 6 and 7. 11.2.1

Northeast Region

The Northeast region includes Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, Vermont, New Jersey, New York, Delaware, DC, Maryland, Pennsylvania, Virginia, and West Virginia. The unrestricted fuel scenario (NE-50-U) yields the selection of 14 refineries, 5 of 1 kBPD capacity, 1 of 5 kBPD capacity, 6 of 10 kBPD capacity, and 2 of 50 kBPD capacity, producing a total of 170 kBPD liquid fuels. The selected facilities are located in the western side of Pennsylvania, western side of Virginia, and the northern and southern sides of West Virginia. Figure 10 shows the topological layout of the Northeast GTL supply chain. The natural gas resources, depicted as blue boxes, are drawn from the northern and western parts of Pennsylvania and across the state of West Virginia, and the GTL refineries deliver fuels to oil refineries in New Jersey, Ohio, and West Virginia. The 170 kBPD of fuels are composed of 95 kBPD gasoline and 75 kBPD kerosene, with an overall BEOP value of $71.86/bbl. When the minimum portions of fuel ratio are imposed (NE-50-R), the supply chain network selects the same total number of refineries. However, the 10 kBPD refineries changed from being all (U-10) refineries to 2 (U-10) refineries, 1 (D-10) refineries, and 3 (K-10) refineries. The two 50 kBPD refineries that maximize kerosene production in case study (NE-50-U) are not selected and instead, 1 (U-50) and 1 (D-50) refineries are selected. The decrease in the total electricity production from 0.61 GW to 0.47 GW and an increase in the natural gas usage from 0.49 trillion SCF/yr to 0.50 trillion SCF/yr are observed due to the selection of (D) refineries, and the resulting fuel composition consists of 102.50 kBPD gasoline, 45 kBPD diesel, and 22.50 kBPD kerosene, increasing the BEOP value to $73.45/bbl. In this topology, the delivery of fuels goes to more destinations, including locations in Ohio, Pennsylvania, New Jersey, and West Virginia (see Figure 11). The differences in the cost breakdown are most marked in the natural gas transportation, where the cost 39



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Page 40 of 79

Table 6: Summary of results for the regional GTL supply chain case studies with unrestricted fuel ratios. Case Study

NE-50-U

SE-50-U

MW-50-U

SW-50-U

CE-50-U

WE-50-U

BEOP ($/bbl)

$71.86

$81.33

$81.02

$65.60

$72.46

$106.27


$14.64

$17.31

$17.25

$14.18

$14.84

$21.84


14

11

8

80

30

9

1 kBPD

5

5

5

5

5

5

U

5

5

5

5

4

5

D

0

0

0

0

1

0

K

0

0

0

0

0

0

R

0

0

0

0

0

0

5 kBPD

1

0

0

1

1

1

U

1

0

0

1

1

1

D

0

0

0

0

0

0

K

0

0

0

0

0

0

R

0

0

0

0

0

0

10 kBPD

6

6

3

54

13

3

U

6

6

3

40

13

3

D

0

0

0

0

0

0

K

0

0

0

14

0

0

R

0

0

0

0

0

0

50 kBPD

2

0

0

17

10

0

U

0

0

0

13

3

0

D

0

0

0

0

0

0

K

2

0

0

4

7

0

R

0

0

0

0

0

0

200 kBPD

0

0

0

3

1

0

U

0

0

0

3

0

0

D

0

0

0

0

0

0

K

0

0

0

0

0

0

R

0

0

0

0

1

0

0.61

0.16

0.09

5.57

2.86

0.10

Electricity produced (GW) Total fuels (kBPD) Gasoline (kBPD) Diesel (kBPD)

170

65

35

2,000

840

40

95.00

65.00

35.00

1,745.00

511.14

40.00 0

0

0

0

0

43.85

Kerosene (kBPD)

75.00

0

0

255.00

285.01

0

Total LHV output

0.97

0.36

0.19

11.13

4.79

0.22

0.49

0.19

0.10

5.80

2.43

0.11

(million GJ/day) Natural gas usage (trillion SCF/yr) Average cost breakdown ($/GJ) Natural gas purchase

5.61

6.39

6.42

5.97

5.09

6.24

Natural gas trans.

1.97

3.04

3.02

2.62

2.84

7.41

Butane purchase

0

0

0

0

0.11

0

Investment cost

7.56

8.83

9.23

7.08

6.95

9.33

Product trans.

0.82

0.41

0.20

0.52

0.99

0.11


0.01

0.01

0.01

0.01

0.01

0.01


0.63

1.31

0.88

0.47

0.57

1.47

Propane sale

0.91

1.92

1.74

1.65

0.71

1.97

Electricity sale

1.06

0.77

0.77

0.84

1.00

0.76

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Table 7: Summary of results for the regional GTL supply chain case studies with minimum portions of fuel ratios. Case Study

NE-50-R

SE-50-R

MW-50-R

SW-50-R

CE-50-R

WE-50-R

BEOP ($/bbl)

$73.45

$90.97

$87.83

$68.36

$73.34

$123.09


$14.99

$17.92

$17.38

$14.23

$14.99

$23.48


14

12

8

88

28

10

1 kBPD

5

5

5

5

5

5

U

5

1

4

5

1

1

D

0

1

0

0

4

1

K

0

3

1

0

0

3

R

0

0

0

0

0

0

5 kBPD

1

2

0

1

3

3

U

1

1

0

1

3

1

D

0

1

0

0

0

1

K

0

0

0

0

0

1

R

0

0

0

0

0

0

10 kBPD

6

5

3

64

12

2

U

2

2

1

49

12

1

D

1

2

1

0

0

1

K

3

1

1

15

0

0

R

0

0

0

0

0

0

50 kBPD

2

0

0

15

6

0

U

1

0

0

12

2

0

D

1

0

0

0

0

0

K

0

0

0

3

2

0

R

0

0

0

0

2

0

200 kBPD

0

0

0

3

2

0

U

0

0

0

0

0

0

D

0

0

0

3

1

0

K

0

0

0

0

0

0

R

0

0

0

0

1

0

0.47

0.17

0.10

5.51

2.39

0.11

Electricity produced (GW) Total fuels (kBPD)

170

65

35

2,000

840

40

Gasoline (kBPD)

102.50

35.75

19.25

1,325.00

513.54

22.00

Diesel (kBPD)

45.00

19.50

7.50

450.00

217.64

12.00

Kerosene (kBPD)

22.50

9.75

8.25

225.00

108.82

6.00

Total LHV output

0.97

0.37

0.20

11.41

4.82

0.23

0.50

0.19

0.10

5.80

2.43

0.12


5.66

6.19

6.18

5.83

5.06

6.08

Natural gas trans.

2.56

2.93

2.92

2.47

3.24

7.22

Butane purchase

0

0

0

0

0.16

0

Investment cost

7.48

8.70

8.89

6.93

6.70

9.36

Product trans.

0.68

0.36

0.19

0.58

0.85

0.12


0.01

0.01

0.01

0.01

0.01

0.01


0.72

1.56

0.85

0.45

0.55

2.56

Propane sale

1.31

1.06

0.86

1.22

0.76

1.08

Electricity sale

0.81

0.77

0.80

0.81

0.83

0.80

41



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Page 42 of 79

MI

ME

WIWI WI

MI

IL

NY

IN

KY

" " " " " " " " " " " "" "" " " " " " " " PA _ ^ ^ " _ "" " " " " " OH " "" " " " _ ^ "" "" " " " MD " "" " "" " " " " " " "" DE DC " " ""WV " " _"" " " "" " " ^ "" " "" " " " VA "" " " " " "

TN AL

VT

GA

MA

CT

RI

NJ Northeast Region (170,000 BPD) Natural Gas Feed Source Plant size (BPD)

Flow

1000 5000

10000 50000

_ ^ 0 35 70

NC

NH


140

210

280

" " " " "

350

0.000200 - 5.380100

5.380101 - 14.197200

14.197201 - 29.013600 29.013601 - 52.496600

52.496601 - 156.820500

420

490 Miles

SC

Figure 10: Graphical representation of the supply chain case study for the Northeast region with unrestricted fuel ratio (NE-50-U). The Northeast region includes CT, ME, MA, NH, RI, VT, NJ, NY, DE, DC, MD, PA, VA, and WV. The facilities and natural gas sources must be located within the region, and the liquid fuels can be delivered to other regions.

42


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in (NE-50-R) is higher than (NE-50-U) due to the increased natural gas requirement. The propane sale increases from the unrestricted to the minimum fuel ratio case study, since (K) refineries do not produce byproduct LPG, but the electricity sale decreases due to less electricity production in (D) refineries compared to (K) refineries. The levelized investment cost decreases from (NE-50-U) to (NE-50-R) due to the lower costs of the (D) refineries, and this trend is consistent for all regional case studies. Legend

Northeast Region (170,000 BPD) Plant size (BPD) 1000 5000

10000 50000

_ ^



" " " " "

0.000000 - 4.062100

4.062101 - 14.197200

14.197201 - 32.217900 32.217901 - 52.936900

52.936901 - 130.865500

ME VT

MI

" _ " " " " " _^ ^ " " " " " "" "" " " " """ " PA " _ ^ ^ _ "" " " " " " OH " " " "" " _ ^ " "" " " " " MD " "" " " " " " " "" " " DE DC " "" "" " " WV _"""" " "" " " ^ " " "" " " " KY VA """ 0 """ " " "

TN

NH

NY MA CT

RI

NJ

35 70

140

210

280

350

420

490 Miles

NC

Figure 11: Graphical representation of the supply chain case study for the Northeast region with minimum portions of liquid fuels produced (NE50-R). The Northeast region includes CT, ME, MA, NH, RI, VT, NJ, NY, DE, DC, MD, PA, VA, and WV. The facilities and natural gas sources must be located within the region, and the liquid fuels can be delivered to other regions.

11.2.2

Southeast Region

The Southeast region includes Alabama, Florida, Georgia, Kentucky, Mississippi, North Carolina, South Carolina, and Tennessee. When the fuel ratio is unrestricted (case study SE-50-U), the solution yields the selection of 11 refineries, 5 of 1 kBPD capacity and 6 of 10 kBPD capacity, producing a total of 65 kBPD liquid fuels. The selected facilities are located in the eastern side of Kentucky, easterm side of Mississippi, and western part of Alabama, and deliver fuels to the 43



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same three states. From Figure 12, it can be seen that the locations of the GTL refineries align with the oil refineries and two clusters of GTL supply chain networks are formed along the border of Mississippi and Alabama. The 65 kBPD of fuels is composed entirely of gasoline and the overall BEOP value of $81.33/bbl. MI

IA IN

IL KS

OK

TX

MO

""" "" "" " " "" "

PA

OH

LA

"" """ " " " "" " " " " "" " "" " _ "AL ^

" MS " "" " " "" " _" " " " ^ """ """" " " " "" """" " "" _ "" "" ^ "

NJ MD DC

WV

"" _ ^ " "" "" " " KY "" """ " " """ "" _ ^ "" " "

MA CT RI NY

DE

VA

TN AR

NY

NC SC GA Southeast Region (65,000 BPD) Plant size (BPD)

_ ^

1000

10000

FL

_ ^ 0 40 80


160

240

320

Natural Gas Feed Source Flow

" " " " " 400

0.000000 - 1.238300 1.238301 - 4.427800 4.427801 - 8.738000

8.738001 - 36.002100

36.002101 - 84.542700

480

560 Miles

Figure 12: Graphical representation of the supply chain case study for the Southeast region with unrestricted fuel ratio (SE-50-U). The Southeast region includes AL, FL, GA, KY, MS, NC, SC, and TN. The facilities and natural gas sources must be located within the region, and the liquid fuels can be delivered to other regions.

When the minimum portions of fuel ratio are imposed (case study SE-50-R; Figure 13), the supply network selects 12 refineries, 5 of 1 kBPD capacity, 2 of 5 kBPD capacity, and 5 of 10 kBPD capacity, located in the same three states as in case study (SE-50-U). The 5 refineries of 1 kBPD capacity consist of 1 facility with unrestricted fuel production (U), 1 facility that maximizes diesel (D), and 3 facilities that maximize kerosene (K). The 2 facilities of 5 kBPD capacity consist of 1 facility with unrestricted fuel production and 1 facility that maximizes diesel. Finally, the 5 facilities of 10 kBPD capacity consist of 2 facilities with unrestricted fuel production, 2 that maximize diesel, and 1 that maximizes kerosene. The supply chain produces 35.75 kBPD gasoline, 19.50 kBPD diesel, and 9.75 kBPD kerosene and an increase in the total electricity production from 44


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0.16 GW to 0.17 GW is observed since the (D) and (K) refineries produce more electricity than the (U) refineries. The BEOP value increases significantly from $81.33/bbl to $90.97/bbl due to primarily the decrease in byproduct propane sale from $1.92/GJ to $1.06/GJ, as the (D) refineries produce less LPG byproduct than the (U) refineries, and the (K) refineries do not produce LPD at all. IA

WI

MO

OK

TX

""" " "" "" " " "" TN

AR

LA

Plant size (BPD) 1000 5000

10000

_ ^


CT RI

NY

DE

VA NC

" MS " "" " "" " " " " _" " " ^ """ """"" " " """ "" " "" _ " "" ^ " ^ _ "

Southeast Region (65,000 BPD)

NJ MD DC

WV

"^ " _ " " "" " " " " KY """"" " " """"" _ ^ " "" "

"" """ " " " "" " "" " " "" " "" _"AL ^

Legend

PA

OH

IN

IL

VTMA

NY

MI

SC GA

FL


" " " " "

0.000000 - 1.588600 1.588601 - 5.325900

5.325901 - 13.384700

13.384701 - 28.800200 28.800201 - 84.542700

0

45 90

180

270

360

450

540

630 Miles

Figure 13: Graphical representation of the supply chain case study for the Southeast region with minimum portions of liquid fuels produced (SE50-R). The Southeast region includes AL, FL, GA, KY, MS, NC, SC, and TN. The facilities and natural gas sources must be located within the region, and the liquid fuels can be delivered to other regions.

11.2.3

Midwest Region

The Midwest region includes Illinois, Indiana, Michigan, Minnesota, Ohio, and Wisconsin, whose natural gas resources allow the production of 35 kBPD of total fuels. The unrestricted fuel scenario (MW-50-U) yields the selection of 8 refineries, 5 of 1 kBPD capacity and 3 of 10 kBPD capacity, all of which have unrestricted fuel production ratios (U) or only gasoline production. The selected facilities are located in the southeastern part of Michigan but they draw natural gas resources mostly from the northern part of Michigan and the western part of Ohio. Note that the natural 45



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Page 46 of 79

gas resources in this region are located in two clusters that are far away from each other, and the selected refinery locations are placed in between the two clusters (see Figure 14). For case study (MW-50-U), the overall BEOP value of $81.02/bbl with a high contribution from the investment cost of the refineries. In case study (MW-50-R), the supply network also selects 8 facilities with the same locations as in case study (MW-50-U), as shown in Figure 15. One refinery of 1 kBPD capacity maximizes kerosene, 1 refinery of 10 kBPD capacity maximizes diesel, and 1 refinery of 10 kBPD capacity maximizes kerosene. This case study produces a total of 19.25 kBPD gasoline, 7.50 kBPD diesel, and 8.25 kBPD kerosene. Similar to the Southeast region, the increase in the BEOP value from $81.02/bbl to $87.83/bbl is primarily due to the decrease is byproduct propane sale from $1.74/GJ to $0.86/GJ as a lesser number of (U) refineries are selected.

_ ^

Fuel Products Delivery Locations Natural Gas Feed Source

Midwest Region (35,000 BPD) Plant size (BPD) 10000

0 40 80

ND MN

IA

IL

TX

OK

320

400

1.180801 - 3.680700 3.680701 - 7.288000

7.288001 - 12.736500

12.736501 - 47.881300

480

" " " " "" " """" " " " "" " " " "" " "" " MI" " """ " " " " " "" " "^ _ " " " "_ " " ^ " " " "" " "" " " " "" " " " "" " "" " " " " OH " "" " IN "" " """ " " " ""

WI

KS

240

0.000100 - 1.180800

560 Miles

MI

SD

NE

160

Flow

" " " " "

1000

PA MD DC

WV

MO

AR

NY

KY TN MS

AL

GA

NJ DE

VA

SC

NC

Figure 14: Graphical representation of the supply chain case study for the Midwest region with unrestricted fuel ratio (MW-50-U). The Midwest region includes IL, IN, MI, MN, OH, and WI. The facilities and natural gas sources must be located within the region, and the liquid fuels can be delivered to other regions.

46


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0

35 70

140

210

280

350

420

490 Miles

Legend

Midwest Region (35,000 BPD) Plant size (BPD) 1000

10000

_ ^


ND MN

MI WI

SD

IA

NE

IL KS

MO

Flow (mscf/day)

" " " " "

0.000100 - 1.025500 1.025501 - 3.139300 3.139301 - 6.160000

6.160001 - 12.736500

12.736501 - 48.278600

" """"" " """ " " " " "" " " " " " "MI" " " " "" " " " " " " " "" " "^ _ " " " "^ " _ " " "" " " """ " " " """ """ " " " " " OH " "" "" "" IN "" """""" " " " " WV KY

OK

Natural Gas Feed Source

NY PA MD

VA

Figure 15: Graphical representation of the supply chain case study for the Midwest region with minimum portions of liquid fuels produced (MW50-R). The Midwest region includes IL, IN, MI, MN, OH, and WI. The facilities and natural gas sources must be located within the region, and the liquid fuels can be delivered to other regions.

47



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

11.2.4

Southwest Region

The Southwest region is the region with the most abundant natural gas resources, allowing the regional supply chain to produce 2,000 kBPD total fuels. The region includes Arkansas, Louisiana, New Mexico, Oklahoma, and Texas. In case study (SW-50-U), the optimization model yields the selection of 80 refineries, 5 of 1 kBPD capacity, 1 of 5 kBPD capacity, 54 of 10 kBPD capacity, 17 of 50 kBPD capacity, and 3 of 200 kBPD capacity. Most of the fuels produced are gasoline (1,745 kBPD) and the remaining 255 kBPD is kerosene produced by the 14 refineries of 10 kBPD capacity and 4 refineries of 50 kBPD capacity that maximize kerosene production. The overall BEOP value for the case study is $65.60/bbl, the lowest out of all six regions, with output electricity of 5.57 GW. Figure 16 shows that the locations of the 80 refineries span across the entire region. Clusters of GTL refineries form along the borders of the states, with the highest density along the border between Texas and Louisiana. These locations correspond with the oil refineries locations and the GTL liquid fuels are delivered to oil refineries across the five Southwestern states plus one location in Mississippi. Natural gas is mostly drawn from across Arkansas, Oklahoma, Louisiana, and Texas. When the minimum portions of fuel ratio are imposed (SW-50-R), the supply network selects 88 facilities, 5 of 1 kBPD capacity, 1 of 5 kBPD capacity, 64 of 10 kBPD capacity, 15 of 50 kBPD capacity, and 3 of 200 kBPD capacity. All 3 of the 200 kBPD refineries maximize the production of diesel, and 15 refineries of 10 kBPD capacity and 3 refineries of 50 kBPD capacity maximize kerosene. The fuel composition is composed of 1,325 kBPD gasoline, 450 kBPD diesel, and 225 kBPD kerosene, with a BEOP value of $68.36/bbl. The topological layout of the supply chain is largely similar to case study (SW-50-U) with notable shifts in certain clusters, namely the reduction of refineries around the Texas and New Mexico border and the increase of refineries along the southeast border of Texas (see Figure 17). 11.2.5

Central Region

The Central region, the second largest fuel-producing region, is made up of Iowa, Kansas, Missouri, Nebraska, Colorado, Montana, North Dakota, South Dakota, Utah, and Wyoming. The total fuels produced in this region amounts to 840 kBPD with a BEOP value of $72.46/bbl. Case study

48


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Page 49 of 79

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CO

UT

_ "^ _" ^ AZ

KS

" NM

_ ^

KY

_ ^ "" " " " "" " " _ ^ " " " " " " " """"^ " " _ ^ " _ " _ " ^ " " " " "" " " " "^ TN _" " _" " OK" """" " "" " "" "" " "^ " " " " "" " " """ " " " " " " " " " " " "" "" " " " """ " """ " AR "" "" ^ _ "" " " " " " _" ^ " """" " " " " " "" " " " " " "" "_ " " _ ^ " """ " " """^ """"" AL _" " "" ^ " " _ ^ "" "" "" "" " " MS """ " _ "" "" "^ _"^ ^ " "" " "" " "^ " "" _ _ " " """" " ^ " _ " " " " " " " "" " " " " " " " " " "" " " " """ " " """" "" " " " " "" " " " TX " "" " "" " LA "" " "" " " """ """ """ " " ""_ FL " "" " """ " "" " " "^ " """ ""^ " " " _ ^ " " _ "" " _ ^ "" """" " " " " " " " _ ^ " _ ^ " " _ ^ " " " _ " " " "^ _ " "" " " " " " """ " " ^ "" " " " " " " "" " " "^ _ Southwest Region (2,000,000 BPD) Natural Gas Feed Source "" "" " Plant size (BPD) Flow _ ^ " " """ 1000 " 0.000200 - 21.616200 5000 " " "" " 21.616201 - 63.652600 10000 " "" " 63.652601 - 146.133700 50000 " " 146.133701 - 444.036800 200000 " 444.036801 - 763.273100

"

"

IN

IL

MO

"

_ ^


0 40 80

160

240

320

400

480

560 Miles

Figure 16: Graphical representation of the supply chain case study for the Southwest region with unrestricted fuel ratio (SW-50-U). The Southwest region includes AR, LA, NM, OK, and TX. The facilities and natural gas sources must be located within the region, and the liquid fuels can be delivered to other regions.

49



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

UT

CO

_ "^

"

KS

"

Page 50 of 79

IL IN

MO

^ _ "" " " " " "" " " _ ^ " " " " " " """"^ " " " " _ " _" " " "^ ^ " " " "" _ " " "_" " ^ ""OK" "" " " """

KY

" "" " " " " " " " " "" " " " " """ " " "" " " " " " """ "" " " " " " AR """ " "" ^ _ "" " NM " " " AZ " _"" ^ " """" "" " "" " "" " " " """" " _ "^ " _ ^ " " " " " """" " " _" " " ^ _ ^ " " " " " " " " " """" MS """"""" _ _""^ ^ " " " "^ " "^ " "" _ _ """"" " ^ " " " " """" _ " " "" " " " " " " " " " " " " " " " "" " " " " " " """" _ ^ "" " " " "" " " " "" " " " TX " "" """" """"" LA"" "" " " " " " " " " " " _""""" " ^ " """ " " "^ _ " " _ """" ^ "" "" "" " _ ^ """ "" " " "^ " _ " _ _" ^ ^ " " " ^ "^ _ """ _ " "" "" " _" """ "" "" ^ " _ "^ _ " " " """ "^ "" " " "^ _ "" """ " _ ^ " """" " "" " Legend " "" Southwest Region (2,000,000 BPD) Natural Gas Feed Source "

^" _

"


10000 50000

200000

_ ^


TN

AL

Flow (mscf/day)

" " " " "

0.000200 - 21.712800

21.712801 - 60.439100

60.439101 - 141.612700

141.612701 - 444.753100

444.753101 - 1037.128200

0 35 70

140

210

280

350

420

490 Miles

Figure 17: Graphical representation of the supply chain case study for the Southwest region with minimum portions of liquid fuels produced (SW50-R). The Southwest region includes AR, LA, NM, OK, and TX. The facilities and natural gas sources must be located within the region, and the liquid fuels can be delivered to other regions.

50


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(CE-50-U) selects 30 refineries, 5 of 1 kBPD capacity, 1 of 5 kBPD capacity, 13 of 10 kBPD capacity, 10 of 50 kBPD capacity, and 1 of 200 kBPD capacity. The fuel composition consists of 511.14 kBPD gasoline, 43.85 kBPD diesel, and 285.01 kBPD kerosene, being the only region that produces diesel in the unrestricted case. The diesel portion is produced by the 1 refinery of 1 kBPD capacity that maximizes diesel (D-1) and the 1 refinery of 200 kBPD capacity that produces fuels in United States demand ratio (R-200). The kerosene is produced by the same (R-200) refinery in addition to 7 refineries of 10 kBPD capacity that maximize kerosene (K-10). The locations of the refineries are spread across Montana, Wyoming, Utah, Colorado, and Kansas, and the fuel delivery locations are not only located within the region, but also Nevada, New Mexico, and Texas in the Western and Southwestern regions (see Figure 18). When the minimum portions of fuel ratio are imposed in case study (CE-50-R), the supply network selects 28 refineries, 5 of 1 kBPD capacity, 3 of 5 kBPD capacity, 12 of 10 kBPD capacity, 6 of 50 kBPD capacity, and 2 of 200 kBPD capacity. Four refineries of 1 kBPD capacity and 1 refinery of 200 kBPD maximize diesel, 2 refineries of 50 kBPD capacity maximize kerosene, 2 refineries of 50 kBPD capacity and 1 refinery of 200 kBPD capacity produce fuels in United States demand ratio. The BEOP is $73.34/bbl due to the decrease in electricity production and increase in natural gas transportation cost. The fuel cpmposition is 513.54 kBPD gasoline, 217.64 kBPD diesel, and 108.82 kBPD kerosene. In this case study, less fuel production takes place in the eastern part of Utah and more production takes place in the eastern part of Kansas compared to the unrestricted case (see Figure 19). 11.2.6

Western Region

The Western region has fuel production with the highest BEOP value at $106.27/bbl. The states within the region are Arizona, California, Nevada, Idaho, Oregon, and Washington. A total of 9 refineries are selected, 5 of 1 kBPD capacity, 1 of 5 kBPD capacity, and 3 of 10 kBPD capacity, where all of them produce only gasoline (U refineries). In case study (WE-50-R), 10 refineries are selected, 5 of 1 kBPD capacity, 3 of 5 kBPD capacity, and 2 of 10 kBPD capacity, producing 22 kBPD gasoline, 12 kBPD diesel, and 6 kBPD kerosene. A significant increase in the BEOP value to $123.09/bbl is observed due to the fact that the natural gas resources in the Western region are all located in California and are dispersed from each other (see Figures 20 and 21). The increase 51



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

" "" " " " " " "" "^ " ND _"" MT " " "" " _ ^ "" " MN " ""^ _ " " " ^ "_ " " " " " SD _ "" " " "^ " WY " _" ^ " _" ^ " IA _" " ^ " NE _" " " _ ^ " _ "^ ^ " " " "" " " " "" " "" " "" " _ ^ "" " " " " "" "" UT " "" " " "" " CO " " KS "" " " " " " MO "" _" " " """ """"^ " " """""" " " " " " " " " "" "" " " " " "" " "" " " " " " " "" " " " "" _ ^

WA ID

OR

NV

_ ^

CA

_ ^

_ ^

AZ

_ ^


10000 50000 200000

0

Flow

" " " " "

65 130

OK

_ ^ NM TX

_ ^

Fuel Products Delivery Locations Natural Gas Feed Source

Central Region (840,000 BPD)

Page 52 of 79

0.000900 - 37.424700

MI MI WI

IL

KY

TN

AR MS LA

IN

AL FL

37.424701 - 126.180600 126.180601 - 238.007900 238.007901 - 418.203000 418.203001 - 1223.397200

260

390

520

650

780

910 Miles

Figure 18: Graphical representation of the supply chain case study for the Central region with unrestricted fuel ratio (CE-50-U). The Central region includes IA, KS, MO, NE, CO, MT, ND, SD, UT, and WY. The facilities and natural gas sources must be located within the region, and the liquid fuels can be delivered to other regions.

52


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OR

""" " " " " " "" "^ " ND _" " MT " " """ _ ^ MN "" " " " ""^ _" " " "_^ "" " " SD _ "" " " "^ _" ^ " " WY " _" ^ " _" " ^ NE _" "" " _ ^ " _"^ ^ " " " " " " "" " "" " "^ " _ " "" "" " "" " CO" UT "" " "" " " " "" " "" " """ ""KS " " " _""" " """ """"^ """""""" " " _ ^ " " "" " "" " """ "" " " "" " """ """" """" " _"" ^

ID

_ NV^

_ ^

CA

_ ^

AZ

_ ^

OK

NM

_ ^

Legend

TX

Central Region (840,000 BPD) Plant size (BPD)

0 50100

200

300

400

500

600

MI WI IA

MO


Flow (mscf/day)

" " " " "

GA

AL

LA Natural Gas Feed Source

50000

_ ^

TN

MS

10000

OH

KY

AR

5000

200000

IN

IL

1000

700 Miles

MI

FL

0.000900 - 15.434000

15.434001 - 56.685700

56.685701 - 107.373900

107.373901 - 333.945500 333.945501 - 902.240800

Figure 19: Graphical representation of the supply chain case study for the Central region with minimum portions of liquid fuels produced (CE-50R). The Central region includes IA, KS, MO, NE, CO, MT, ND, SD, UT, and WY. The facilities and natural gas sources must be located within the region, and the liquid fuels can be delivered to other regions.

53



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Page 54 of 79

in the overall cost is due to the increase in CO2 transportation and injection costs for sequestration and the decrease in byproduct propane sale. Note that the Western region is the only region that has an average natural gas transportation cost that is higher than the natural gas purchase cost.

WA

SD

ID

OR

"

WY

" "" """ " "" _ ^ " " " "" " CA "" " "

_" ^

UT

NV

_" ^ " _" ^ ^ " _ _ ^

Products

1000 5000

10000

_ ^


NE

CO

NM

AZ

"

Western Region (40,000 BPD)

ND

MT

Natural Gas Feed Source Flow

" " " " "

TX

0.000100 - 1.353900 1.353901 - 5.692900 5.692901 - 13.557500 13.557501 - 26.208600 26.208601 - 71.392000

0 55 110

220

330

440

550

660

770 Miles

Figure 20: Graphical representation of the supply chain case study for the Western region with unrestricted fuel ratio (WE-50-U). The Western region includes AZ, CA, NV, ID, OR, and WA. The facilities and natural gas sources must be located within the region, and the liquid fuels can be delivered to other regions.

11.2.7

Regional Comparisons

The BEOP values for the six regional case studies for both the unrestricted fuel ratio case and the minimum portions of fuels are compared in Figure 22. The Southwest region has the most profitable regional supply chain, followed by the Central, Northeast, Midwest, Southeast, and Western regions. The Western region has a significantly higher BEOP value compared to the other regions due to the limited supply of natural gas, higher price of natural gas, and dispersed nature of the natural gas counties. The BEOP values of the (R) case studies are always higher than the (U) case studies but in varying degree across the six regions. Areas with abundant sources of natural gas, such as the Northeast, Southwest and Central regions have BEOP increases that 54


Page 55 of 79

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WA

MT

ID

OR

WY

"

Legend

Western Region (40,000 BPD) Plant size (BPD) 1000 5000

10000

_ ^


" "" NV "" " "" _ " _^ ^ " "" " CA "" " " _" _" ^ ^ " "^ _ ^ Natural Gas Feed Source " _ _" ^ Flow (mscf/day)

" " " " "

UT

AZ

CO

NM

0.000100 - 1.353900 1.353901 - 3.799300 3.799301 - 9.260500

9.260501 - 22.833500

22.833501 - 86.614100

0 40 80

160 240 320 400 480 560 Miles

Figure 21: Graphical representation of the supply chain case study for the Western region with minimum portions of liquid fuels produced (WE50-R). The Western region includes AZ, CA, NV, ID, OR, and WA. The facilities and natural gas sources must be located within the region, and the liquid fuels can be delivered to other regions.

55



are less than $3/bbl, while the other regions experience a BEOP increase ranging from $6.81/bbl to $16.82/bbl. Note also that the regions with small increases in BEOP experience drops in the electricity production, but the regions with large increases in BEOP experience an increase in the electricity production. The reason for this phenomenon is because the Southwest, Central, and Northeast regional supply chains selected (K) refineries in the unrestricted case studies, which have higher electricity production than the (D) refineries. Thus, when the minimum portions of fuels are imposed and the (D) refineries are selected, the total electricity production is reduced. On the contrary, the Southeast, Midwest, and Western regional supply chains only selected (U) refineries in the unrestricted case studies. When the minimum portions of fuels are imposed, the combined selections of (U), (D), and (K) refineries produce a higher total amount of electricity for the same total volumes of liquid fuels. $140.00 $120.00 $100.00 $80.00 $60.00

2,000,000.00

$0.00

Northeast Southeast Midwest Southwest Central Region and Total Volume of Fuels (BPD)

40,000.00

Fuel RaRo 840,000.00

$20.00 35,000.00

Unrestricted

65,000.00

$40.00

170,000.00

BEOP ($/bbl)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 56 of 79

Western

Figure 22: BEOP comparisons for the six regional supply chains for the unrestricted and minimum fuel ratio case studies.

The breakdown of the cost contributions for each regional supply chain is shown in Figures 23 and 24. It can be readily seen that the investment cost, natural gas purchase and transportation account for 90% of the total cost or more. Generally, the contribution from the natural gas transportation cost is less than the natural gas purchase cost except in the Western region due to the separated clusters of natural gas sources. The regional supply chains that locate the refineries very 56


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close to the oil refineries have less cost contributions from the product transportation segment. 100% 90% 80%

CO2 injecBon

70%

CO2 trans

60%


50%

Butane purchase Product trans.

40%

Investment

30%

NG trans.

20%

NG purchase

10% 0% Northeast Southeast Midwest Southwest Central Western

Figure 23: Comparison of the cost contributions in the six regional supply chains for the unrestricted case studies.

11.3

Statewide GTL Supply Chains: Texas

The last set of supply chain case studies limits the geographical scope of the problem further from United States regions to individual states. In these statewide supply chain problems, similar restrictions as in the regional case studies are imposed, namely only natural gas resources within the state can be used, the facilities must be located within the state, and the fuels may be delivered to other states. However, one additional restriction is that only counties that can supply entirely the natural gas requirement of the selected refinery can be selected. In other words, no inter-county natural gas transportation is allowed. The statewide supply chain case studies are applied to the state of Texas, the state with the most abundant natural gas sources and the largest number of counties that produce natural gas (see Table 1). Table 8 summarizes the results from the four case studies for Texas, where 50% natural gas expansion level is applied in all cases. Very low BEOP values are observed for Texas, ranging from $55.58/bbl to $65.05/bbl. Using the restrictions described above, Texas can produce a total of 200 kBPD liquid fuels when no inter-county natural gas transportation is allowed. Note that the 57



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

100% 90% 80%

CO2 injecBon

70%

CO2 trans

60%


50%

Butane purchase Product trans.

40%

Investment

30%

NG trans.

20%

NG purchase

10% 0% Northeast Southeast Midwest Southwest Central Western

Figure 24: Comparison of the cost contributions in the six regional supply chains for the minimum portions of liquid fuels case studies.

state can produce much more than 200 kBPD if all of its natural gas resources are used. Case study (TX-50-U), with a BEOP value of $55.58/bbl produces 200 kBPD of gasoline in 5 refineries of 1 kBPD capacity, 1 refinery of 5 kBPD capacity, 9 refineries of 10 kBPD capacity, and 2 refineries of 50 kBPD capacity. The number of facilities is the same in case study (TX-50-R) when 136.25 kBPD gasoline, 41.25 kBPD diesel, and 22.50 kBPD kerosene are produced. The BEOP increases to $60.21/bbl due to the higher investment costs of (D) and (K) refineries and the reduction in byproduct LPG sales. The geographical layout of the statewide supply chain can be seen in Figure 25 and the same locations are selected for case study (TX-50-R). The counties that can provide the natural gas resources without inter-county natural gas transportation are located in the northern and eastern part of Texas, and the fuels are delivered to oil refineries along the northern, eastern, and southeastern border of Texas. When only 10 kBPD refineries are allowed to exist in the supply chain, the BEOP values for the unrestricted and minimum portions of liquid fuels are $59.01/bbl and $65.05/bbl, respectively. In both cases, 20 refineries are selected, with all 20 producing gasoline in case study (TX-50-U10) and 12 refineries with unrestricted fuel production, 5 refineries that maximize diesel, and 3 refineries that maximize kerosene in case study (TX-50-R-10). Compared to the case studies that

58


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Table 8: Statewide GTL supply chain profiles for Texas. Case Study

TX-50-U

TX-50-R

TX-50-U-10

TX-50-R-10

BEOP ($/bbl)

$55.58

$60.21

$59.01

$65.05


$12.63

$12.83

$13.25

$13.72


17

17

20

20

1 kBPD

5

5

0

0

U

5

5

0

0

D

0

0

0

0

K

0

0

0

0

R

0

0

0

0

5 kBPD

1

1

0

0

U

1

0

0

0

D

0

1

0

0

K

0

0

0

0

R

0

0

0

0

10 kBPD

9

9

20

20

U

9

6

20

12

D

0

0

0

5

K

0

3

0

3

R

0

0

0

0

50 kBPD

2

2

0

0

U

2

1

0

0

D

0

1

0

0

K

0

0

0

0

R

0

0

0

0

200 kBPD

0

0

0

0

U

0

0

0

0

D

0

0

0

0

K

0

0

0

0

R Electricity produced (GW) Total fuels (kBPD)

0

0

0

0

0.53

0.55

0.51

5.52

200

200

200

200

200.00

136.25

200.00

140.00

Diesel (kBPD)

0

41.25

0

37.50

Kerosene (kBPD)

0

22.50

0

22.50

Total LHV output

1.10

1.14

1.10

1.14

0.58

0.58

0.57

0.58

Gasoline (kBPD)


6.08

5.90

5.99

0

0

0

0

Investment cost

7.89

7.61

8.36

8.13

Product trans.

0.76

0.73

0.74

0.72


0.01

0.01

0.01

0.01


0.69

0.65

0.89

1.12

Propane sale

1.97

1.28

1.97

1.34

Electricity sale

0.82

0.81

0.77

0.77

Natural gas trans.

59


5.86


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

UT

CO

KS

NM

AZ

IL

MO

AR

_ ^ " " TX

"

0

MS

_ " "" _ ^ "^ " ""

" ^ _ " _ ^ " _ ^

KY TN

OK

" " _ ^ "

Page 60 of 79

40 80

AL

LA

FL

^ _ _ ^ "

160

240

320

400

480

560 Miles

Legend

Texas (200,000 BPD) - Unrestricted Fuel Ratio Natural Gas Feed Source Plant size (BPD) 1000 5000

10000 50000

_ ^


Flow (mscf/day)

" " " "

8.738000

8.738001 - 43.690000

43.690001 - 86.614100

86.614101 - 444.753100

Figure 25: Graphical representation of the supply chain case study for the state of Texas with unrestricted fuel ratio (TX-50-U). The facilities and natural gas sources must be located within the state, and the liquid fuels can be delivered to other states. The facilities must be located at a location where enough natural gas is available and no inter-county natural gas transportation is allowed.

60


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include all refinery capacities, these case studies have higher levelized investment costs and lower electricity production, but similar natural gas usage. Figure 26 displays the geographical layout of the statewide supply chain, showing that more facilities are selected in the northern and eastern parts of Texas as well as four additional refineries along the southwestern border of Texas. Note that case study (TX-50-R-10) selects the same locations for its 20 refineries. UT

CO

KS

NM

AR

_ ^ _ ^ "

"" "" TX

"" ""

"

MS

_ _ "" ^ "^ " ""

_ ^ Legend

KY TN

OK

" _ " ^ AZ

IL

MO

AL

LA

FL

_ ^

_ ^

Plant size (BPD)

_ ^

"

10000

_ ^


"

86.614100

Flow (mscf/day)

0

40 80

160

240

320

400

480

560 Miles

"

Figure 26: Graphical representation of the supply chain case study for the state of Texas with unrestricted fuel ratio and only 10 kBPD facilities allowed (TX-50-U-10). The facilities and natural gas sources must be located within the state, and the liquid fuels can be delivered to other states. The facilities must be located at a location where enough natural gas is available and no inter-county natural gas transportation is allowed.

11.4

Overall Comparison

The importance of the geographical scope of the supply chain studies is highlighted in the average cost or BEOP values obtained from the nationwide, regional, and statewide case studies. Comparing the nationwide case study (N-50-U) with the regional equivalent of the formulation (i.e., case studies NE-50-U, SE-50-U, MW-50-U, SW-50-U, CE-50-U, and WE-50-U), the BEOP value is lower for the nationwide supply chain compared to the individual regional case studies

61



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(i.e., $65.05/bbl compared to $65.60/bbl-$106.27/bbl). In the nationwide formulation, there is no restriction in the flow rates across regional and state boundaries and thus a more optimal network can be achieved. However, the benefit of analyzing the regional case studies lies in the practicality of implementing a regional management of potential GTL supply chains. Extending the pattern further to the statewide supply chain case studies, it can be observed that the cost of fuel production can vary from state to state or from region to region depending on the amount of local resources and the geographical layout of the natural gas counties and the existing oil refineries. The state of Texas is an ideal state for GTL refineries due to the synergistic combination between all of the supply chain components, yielding an overall BEOP ($55.58/bbl) that is lower than the nationwide average.

12

Conclusions

This paper proposed and reported results on the nationwide, regional, and statewide GTL supply chains for the United States transportation sector. Multiple segments of the supply chain from the acquisition of the natural gas feedstock, transportation costs of feedstock and fuel products, investment costs of GTL refineries, and environmental constraints such as water, electricity, and CO2 sequestration resources are taken into account simultaneously. The optimization problem is formulated as a MILP that minimizes the total cost of the supply chain and yields the locations and capacities of GTL refineries as well as feedstock and product connections to their respective locations. This MILP is solved for the nationwide supply chain, six United States regions, and for the state of Texas. Two modes of fuel production are applied, one in which there is no restriction in the fuel ratios and one in which minimum portions of liquid fuels are imposed. The resulting average costs of fuel production for the case studies suggest that GTL supply chains can be highly profitable in the United States. The nationwide case studies have BEOP values ranging from $65.06/bbl-$80.25/bbl and the regional case studies have BEOP values from $65.60/bbl-$90.97/bbl, except for the Western region at $106.27/bbl-$123.09/bbl. Results show that the Southwest and Central regions of the United States are the most profitable regions for GTL supply chains, and that a state GTL supply chain can have a high economic performance in the state of Texas. 62


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Acknowledgments The authors acknowledge partial financial support from the National Science Foundation (NSF EFRI-0937706; CBET-1158849).

Notation Index s = State Index c = County Index f = Feedstock Index p = Product Index t = Plant Size Index l = Plant Location Index m = Transportation Mode Index r = Port Index q = Carbon Conversion Level Index

Sets S = U.S. States C = U.S. Counties F G = Natural Gas Feedstocks F = Feedstocks P = Products (i.e., gasoline, diesel, kerosene) CF = Feedstock-County Pairs CP = Product-County Pairs CSQ = Carbon Sequestration Sites CW = Locations of Water Resources LF = Candidate Plant Locations LS = Candidate Locations with Solar Plant Capacities

63



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LW = Candidate Locations with Wind Plant Capacities M = Modes of Transportation (i.e., truck, rail, pipeline, barge) MF = Feedstock-Mode Pairs MP = Product Mode Pairs G MPipe = Natural Gas Pipelines P = Product Pipelines MPipe

R = 50 U.S. ports with high liquid fuels capacity T = Plant Sizes (i.e., 1 kBD, 5 kBD, 10 kBD, 50 kBD, 200 kBD) Q = Fuel Product Ratios (i.e., commensurate with US demands, maximized diesel, maximized kerosene production, unrestricted) EFL = Enumerated Facility Locations FL = Candidate Facility Locations FT = Feasible Feedstock Flow Quadruplets PT = Feasible Product Flow Quadruplets

64


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Set Definitions

f ∈ F = FG FC = {( f ) | f ∈ F G } MF = {( f , m) ∈ F G × pipeline} MP = {(p, m) ∈ P × {pipeline,truck,barge}} EFL = {( f ,t, l, q) ∈ FC × T × L × Q} FT = {( f , c, l, m) | (p, c) ∈ CF , l ∈ L, FE ( f , m) ∈ MF ,Cost FE f ,c,l,m ≤ MaxCost f }

PT = {(p, l, c, m) | (p, c) ∈ CP , l ∈ L, PE (p, m) ∈ MP ,Cost p,c,l,m ≤ MaxCost pPE }

CF = {( f , c) | ( f , c) ∈ F ×C, FA f ,c > 0} CP = {(p, c) | (p, c) ∈ P ×C, DM p,c > 0} CW = {c | c ∈ C,WAc > 0} CSQ = {c | c ∈ C, SCAPc > 0} LS = {l | l ∈ LF ,CapSl > 0} LW = {l | l ∈ LF ,CapW l > 0} Parameters N = Maximum number of GTL plants built in the United States Ntmax = Maximum number of GTL plants for size t Ntmin = Minimum number of GTL plants for size t LC f ,t,q = GTL levelized investment cost for feed ( f ), size t, and fuel ratio q FRGf,t,q = GTL natural gas requirement for feed ( f ), size t, and fuel ratio q ER f ,t,q = GTL electricity requirement for feed ( f ), size t, and fuel ratio q EPf ,t,q = GTL electricity produced for feed ( f ), size t, and fuel ratio q FW f ,t,q = GTL freshwater requirement for feed ( f ), size t, and fuel ratio q

65



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SQ f ,t,q = GTL CO2 sequestration flow for feed ( f ), size t, and fuel ratio q FA f ,c = Availability of feedstock f in county c DM p,c = Demand of product p in county c PR p,t,q = Amount of liquid fuel product p for a plant of size t and fuel ratio q WAc = Water availability in location c SCAPc = CO2 sequestration capacity in location c MaxCost FE f = Maximum delivered cost of feedstock f MaxCost pPE = Maximum delivered cost of product p CapSl = Maximum capacity of solar generated electricity at location l CapW l = Maximum capacity of wind generated electricity at location l CapG = Maximum grid electricity usage for the country Cost Ff,c = Cost per unit mass of feedstock f at county c Cost FT f ,c,l,m = Cost per unit mass flow to transport feedstock f from county c to facility l using mode m PT Cost p,l,c,m = Cost per unit mass flow to transport product p from facility l to county c using mode

m CostEl,G = Total investment cost per unit energy of grid electricity CostEl,P = Total profit per unit energy of produced electricity CostEl,S = Total investment cost per unit energy of solar electricity CostEl,W = Total investment cost per unit energy of wind electricity CostcW P = Cost of water purchase at location c per unit flow rate W T = Cost of water transportation by pipeline from source c to facility l Costc,l CO2 ,T Costc,l = Cost of CO2 transportation by pipeline from facility l to sequestration site c CO2 ,In j

Costc

= Cost of CO2 injection at sequestration cite c

Continuous Variables CostlI = Levelized investment cost of facility l FR f ,l = Amount of feedstock f required at facility l EllT = Total electricity required at facility l EllP = Total electricity produced at facility l 66


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EllS = Solar electricity required at facility l EllW = Wind electricity required at facility l EllG = Grid electricity required at facility l W Fl = Freshwater requirement for facility l SFl = Sequestered CO2 amount from facility l wc,l = Freshwater flow from source c to facility l seqc,l = CO2 sequestration flow from facility l to injection site c x f ,c,l,m = Flow of feedstock f from county c to facility l using transportation mode m z p,l,c,m = Flow of product p from facility l to county c using transportation mode m

Binary Variables y f ,t,l,q = GTL plant binary at location l with feed ( f ), size t, and fuel ratio q

67



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