System Model of Small-Scale Gas-to-Methanol Conversion by Engine Reformers

By

Angela J. Acocella

B.S., Mechanical Engineering Rensselaer Polytechnic Institute, 2012

Submitted to the Engineering Systems Division in partial fulfillment of the requirements for the degree of

Master of Science in Technology & Policy

at the

Massachusetts Institute of Technology

June 2015

© 2015 Massachusetts Institute of Technology, All rights reserved

Signature of Author...... Technology & Policy Program; Engineering Systems Division May 8, 2015

Certified by...... Daniel R. Cohn Research Scientist, MIT Energy Initiative Thesis Supervisor

Accepted by...... Dava J. Newman Professor of Aeronautics and Astronautics and Engineering Systems Director, Technology and Policy Program

2 System Model of Small-Scale Gas-to-Methanol Conversion by Engine Reformers

by

Angela J. Acocella

Submitted to the Engineering Systems Division On May 8, 2015 in partial fulfillment of the requirements for the degree of Master of Science in Technology & Policy

ABSTRACT

As global energy demands grow and environmental concerns over resource extraction methods intensify, high impact solutions are becoming increasingly essential. Venting and flaring of associated natural gas represents significant environmental and financial losses yet it continues in the North Dakota Bakken oil play. The valuable gas resource is wasted due to unfavorable economics and limited pipeline capacity. Similarly in India, underdeveloped gas transport infrastructure and restrictive regulatory frameworks prevent distribution and marketing of natural gas from the northeast regions, leaving it stranded in marginal fields.

This thesis establishes a techno-economic model, utilizing Aspen Plus chemical processing software, and a discounted cash flow model to estimate economic feasibility of implementing MIT engine reformer-based gas-to-liquids (GTL) systems in the US or India. The system reforms natural gas via partial oxidation into synthesis gas (syngas) in the cylinders of an internal combustion engine, and can significantly reduce capital costs over conventional GTL reforming processes. The engine is operated in fuel rich conditions to generate the syngas, which is synthesized into methanol and dimethyl ether (DME). Once produced on-site, these liquids are more easily transported than gases.

This study assesses the regulatory structures surrounding the upstream methane resource and downstream end product marketability for three scenarios: use of DME to replace existing local (1) diesel and (2) liquefied petroleum gas (LPG), or (3) sale of methanol as a commodity chemical on domestic or global markets.

The analysis shows the system is economical in both locations. In the US, the minimum economically efficient production capacity with a 1-2 year payback period is 400,000- 860,000 standard cubic feet per day (scfpd) of natural gas for the range of end use scenarios considered. Differences in costs and product market characteristics in India result in a minimum efficient capacity of 330,000-810,000 scfpd of natural gas for the three scenarios.

Thesis Supervisor: Daniel R. Cohn Title: Research Scientist

3

4 Table of Contents

ABSTRACT ...... 3 Table of Contents ...... 5 List of Figures ...... 7 List of Tables ...... 8 Acknowledgments ...... 9 NOMENCLATURE ...... 10 1. INTRODUCTION ...... 11 1.1 Natural Gas Availability & Infrastructure ...... 11 1.1.1 United States ...... 11 1.1.2 India ...... 12 1.2 Solutions ...... 16 1.2.1 Traditional & Existing Technologies ...... 16 1.2.2 The Engine Reformer ...... 18 1.2.3 Small Modular Plant Design ...... 19 1.2.4 Implementation ...... 20 1.3 Fuels Background ...... 21 1.3.1 Fuel Comparison ...... 21 1.3.2 Natural Gas Vehicles (NGVs): CNG & LNG ...... 23 1.3.3 LPG ...... 25 1.3.4 DME ...... 26 1.3.5 Methanol ...... 28 2. POLICY OVERVIEW ...... 31 2.1 United States and North Dakota ...... 31 2.1.1 Gas Flaring Regulations ...... 31 2.1.2 Fuel Specifications ...... 32 2.1.3 Clean Air Act & Energy Policy Act ...... 33 2.1.4 Alternative Fuel Tax Credit ...... 34 2.1.5 Vehicle Fuel Economy And GHG Emissions Standards ...... 34 2.1.6 Vehicle Conversion Standards ...... 34 2.2 India ...... 35 2.2.1 Natural Gas Strategies ...... 35 2.2.2 Fuel and Vehicle Standards & Regulations ...... 37 2.2.3 LPG Subsidies ...... 38 2.2.4 Direct Benefit Transfer (DBT) ...... 38 2.2.5 Emissions ...... 39 2.26 Bharat Stage IV Vehicle Emission Standards, 2010 ...... 39 2.2.7 Air (Prevention and Control of Pollution) Act, 1981 ...... 39 2.2.8 Environmental (Protection) Act, 1986 ...... 40 3. LITERATURE REVIEW ...... 41 3.1 Feedstock: Location, Type, and Availability ...... 41 3.1.1 US ...... 41 3.1.2 India ...... 41

5 3.2 Engines ...... 42 3.2.1 Engine Combustion ...... 42 3.3 Gas-to-Liquids ...... 43 3.3.1 Reformation ...... 43 3.3.2 Methanol/DME Production & Distribution ...... 43 3.4 Chemical Processing Design & Economics ...... 44 3.4.1 Conventional Design Economics ...... 44 3.5 Mass Manufacturing ...... 45 3.6 GTL Applications ...... 45 3.7 Compact GTL Technologies ...... 47 3.8 DME Promotion ...... 49 3.9 Domestic Fuel Trends in the Developing World ...... 50 4. METHODOLOGY ...... 51 4.1 Aspen Plus Model ...... 52 4.1.1 Gas Conditioning: Air Separation Unit ...... 54 4.1.2 Gas Conditioning: Natural Gas Preparation ...... 54 4.1.3 Engine Reformer Block: ...... 55 4.1.4 Syngas Cleaning ...... 58 4.1.5 Compression ...... 58 4.1.6 Water Gas Shift ...... 59 4.1.7 Methanol Synthesis ...... 60 4.1.8 Aspen Plus Economic Analysis ...... 61 4.2 Economic Model ...... 61 4.2.1 Investment Model ...... 61 4.2.2 Baseline System Assumptions ...... 62 4.2.3 Upstream Manufacturer’s Cost & Considerations ...... 66 4.2.4 Downstream End User Cash Flow Analysis ...... 68 4.2.5 Downstream Costs ...... 69 4.2.6 Downstream Revenues ...... 71 4.2.7 Fixed Capacity Approach ...... 73 4.2.8 Fixed Payback Period Approach ...... 74 5. RESULTS & ANALYSIS ...... 75 5.1 United States ...... 75 5.1.1 Base Case: Fixed Capacity Approach ...... 75 5.1.2 United States: Fixed Payback Period Approach ...... 78 5.2 India: Fixed Payback Period Approach ...... 80 6. DISCUSSION & CONCLUSIONS ...... 82 7. FUTURE WORK ...... 85 7.1 Industry Cooperation ...... 85 7.2 Alternative Product Options ...... 85 7.3 Implementation Locations ...... 86 REFERENCES ...... 88 APPENDIX A: Aspen Plus Stream Results ...... 94 A.1 ASU Block Aspen Stream Results ...... 94 A.2 Natural Gas Prep Block Aspen Stream Results ...... 96 A.3 Engine Reformer Block Aspen Stream Results ...... 98

6 A.4 Cleaning Block Aspen Stream Results ...... 100 A.5 Compression Block Aspen Stream Results ...... 102 A.6 Water-Gas-Shift Block Aspen Stream Results ...... 104 A.7 Methanol Synthesis Block Aspen Stream Results ...... 106

List of Figures

Figure 1: Map of Bakken Shale Play and Williston Basin in the American Midwest . 12 Figure 2: Map of India's Oil and Gas Pipeline Network ...... 14 Figure 3: Map of India's Hydrocarbon Deposits and Field Production Status ...... 15 Figure 4: Rendition of Skid-Mounted Engine Reformer-Based GTL System ...... 20 Figure 5: Methane to Methanol GTL System Aspen Flow Sheet ...... 55 Figure 6: Air Separation Block Flow Sheet ...... 56 Figure 7: Natural Gas Prep Block Flow Sheet ...... 57 Figure 8: Engine Reformer Block Flow Sheet ...... 59 Figure 9: Syngas Cleaning Block Flow Sheet ...... 60 Figure 10: Syngas Compression Block Flow Sheet ...... 61 Figure 11: Water Gas Shift Block Flow Sheet ...... 59 Figure 12: Methanol Synthesis Block Flow Sheet ...... 62 Figure 13: North Dakota Flare Gas Flow Rate & Distribution ...... 64 Figure 14: India Flare Gas Fields and Flow Rates ...... 65 Figure 15: India Stranded Gas Fields and Capacitied ...... 66

7 List of Tables

Table 1: Summary of Small-, Medium-, and Large-Scale GTL Developments ...... 18 Table 2: Fuel Properties Comparison ...... 24 Table 3: Emissions Reduction (%) of New NGVs Compared to New and In-Use Diesel Vehicles ...... 25 Table 4: Engine Reformer-Based GTL System Components ...... 51 Table 5: Baseline System and Economic Assumptions ...... 65 Table 6: Differences in Assumptions for US vs. India ...... 73 Table 7: North Dakota - Fixed Capacity Approach Results ...... 77 Table 8: North Dakota - Fixed Payback Period Approach & Capacity Sensitivity Analysis Results ...... 81 Table 9: India - Fixed Payback Period Approach & Capacity Analysis ...... 83

8 Acknowledgments

One of the most critical lessons I must remind myself of is that no great accomplishment can be done without the help of others. My time at MIT has been one of the most challenging and rewarding experiences, which has had everything to do with the people surrounding me throughout the process.

I would like to thank my thesis supervisor, Dan Cohn, for all of his guidance and support over the past two years. When I started at MIT, I did not have energy, economics, business, or systems engineering research experience. While giving me the flexibility to explore and change directions as needed, our discussions and his questions helped direct my line of thinking and teach me to fully scrutinize and understand my findings and results.

I have great appreciation for having been able to work and travel with my research partner, Emmanuel Lim. From landfills, to manure processing plants, to corporate and government offices, to yoga guru’s studios, our time traveling in India was never boring and our collaborative efforts always came through in the end. I would also like to sincerely thank Srini Seethamraju for all of his time and patience in answering my questions and teaching me everything I could possibly retain about chemical process design and Aspen modeling.

This research project would not exist without Leslie Bromberg’s inspiration and leadership. His methods and ideas continue to amaze me. I’d also like to thank Rob Stoner for his vested interest in our project and for all his help connecting us with key industry contacts that proved to be pivotal in obtaining data in India.

I am so grateful for the opportunities the MIT Tata Center for Technology & Design has made possible though my research fellowship. The Center’s value placed on field research and implementation-focused design is very well aligned with my goals. I have been able to travel around the world and make the valuable connections all while helping in the development of an exciting new technology.

I am so lucky to have been a part of TPP. The faculty, staff, and students are an amazing community. One of the best decisions I made was to apply to TPP and I am thankful for all who have made it so special, especially my fellow Class of 2015.

Finally, I want to thank my parents for their unconditional love and support. Throughout my life they have taught me that I can do anything, as long as I keep trying and do my best. Their faith in me has been crucial during all life’s ups and downs and I could not have made it this far without them. And I would like to thank my sister for being such an inspiration to me. Her enduring drive to reach her professional goals has never ceased and I truly admire her for that.

9 NOMENCLATURE

APEA Aspen Process Economics Analyzer ASU Air Separation Unit bbl Barrel (volume) Btu British thermal unit CAPEX Capital costs CI Compression Ignition CNG Compressed Natural Gas Ct Total costs DME Dimethyl Ether E&P Exploration and Production GHG Green House Gas GTL Gas-to-Liquids GVWR gross vehicle weight rating HCCI Homogeneous Charge Compression Ignition LHV Lower Heating Value LNG Liquefied Natural Gas LPG Liquefied Petroleum Gas MMBtu Million Btu MMscfpd Million scfpd Mscfpd Thousand scfpd MT Metric Ton MTO Methanol-to-olefins NGV Natural Gas Vehicle NPV Net Presents Value O&M Operation & Maintenance OEM Original Equipment Manufacturers P Pressure Phi Fuel/air Ratio, Equivalence Ratio scfpd Standard cubic feet per day SI Spark Ignition T Payback Period (economics) t period (year) T Temperature (reforming & chemical synthesis) TPD Tons per day TPY Tons per year WGS Water-gas-shift X Capacity, chemical processing plant component

10 1. INTRODUCTION

This economic feasibility study focuses on two cases: flared associated natural gas from oil fields in the United States, specifically the Bakken Shale Formation in the Williston Basin (Figure 1), and stranded, or marginal natural gas reserves in the Northeast (NE) regions of India. The motivation for the selection of these two locations is driven by the effort to illustrate two dissimilar scenarios based on characteristics such as natural gas availability, location, infrastructure, costs, end user preferences, market prices, private versus public sector participation, and government incentives and policies. The goal is to develop an economic model for the MIT engine reformer-based GTL system, determine the economic feasibility for the two cases and extend the analysis to additional locations in future studies.

1.1 Natural Gas Availability & Infrastructure 1.1.1 United States North Dakota holds 17% of the total crude oil reserves in the United States, however over one third of the natural gas that is produced is flared or otherwise not marketed. Extraction of crude oil in the Bakken shale play releases associated natural gas, but the necessary natural gas infrastructure such as gathering pipelines, processing plants, and transportation pipelines, to bring this gas to market is underdeveloped, leaving the gas stranded. Several natural gas pipelines cross the state, but production still outstrips pipeline capacity. The North Dakota Pipeline Authority advocates expanding the pipeline system to help mitigate the problem but economic and temporal barriers exist. Further, North Dakota’s Industrial Commission has implemented regulations limiting the flaring, but with no means to store or transport the gas, producers are forced to pay fines or apply for exemptions.

The North Dakota Department of Mineral Resources is looking to all solutions that capture and use the gas. Some options include utilizing combined flare gas and

11 diesel to fuel drill rigs, compressing the gas on small trailer-hitched compressors to produce CNG, and producing power for on-site requirements on distributed electricity grids.

Figure 1: Map of Bakken Shale Play and Williston Basin in the American Midwest (Opteryx Mineral Management, 2011)

1.1.2 India India imports over 20% of its natural gas it consumes. While the country’s oil pipelines extend from the refining sector in the western regions to the Northeast regions’ hydrocarbon reserves, national gas pipeline infrastructure does not. Due to the insufficient pipeline connections, the natural gas deposits are largely stranded from domestic markets and producers must rely on local demand. Figure 2 depicts this situation; the green line shows existing liquids pipeline infrastructure, while the red line shows the gas pipeline, which does not reach the Northeaster region. GAIL (India) Limited has surveyed the area to begin a pipeline plan to connect Haldia in West Bengal to the existing natural gas line that currently ends in Jagdishpur, but in

12 the event the plan is successful, the Assam Basin will remain stranded (Press Information Bureau of North Dakota, 2015); (Cabinet Committee on Economic Affairs, 2014).

The Assam Basin holds 20% and 23% of India’s crude oil and natural gas reserves, respectively, but only 14% and 7% of each resource is produced. Further, 25% of the total natural gas produced in Assam oil fields is flared or otherwise wasted (Kalita, 2012). Figure 3 shows the location of major hydrocarbon deposits in the country and their relative production status. The orange section in the northeast region is the Assam Basin. The remote location of this basin together with the extent of existing and planned pipeline development indicates that the flaring will continue.

The petrochemical industry has expanded in the NE region, with significant activity in urea production for nitrogenous fertilizer. The State Government of Assam and Assam Industrial Development Corporation Limited established Assam Petrochemicals Limited in a public-private partnership (PPP) to address natural gas flaring at the Upper Assam oil fields. The company mainly produces methanol and formalin (Assam Petrochemicals Ltd, 2008). Other petrochemical refineries in the region produce LPG, naptha, high-speed diesel, and kerosene.

13

Figure 2: Map of India's Oil and Gas Pipeline Network (U.S. Energy Information Administration, 2014)

14

Figure 3: Map of India's Hydrocarbon Deposits and Field Production Status (Directorate General of Hydrocarbons, 2010)

15 1.2 Solutions

Conventional gas-to-liquids processes are typically at large centrally located facilities to capitalize on economies of scale – the cost advantage that arises as the cost per unit of output of a plant decreases with increased output or capacity because fixed costs are spread out over a greater number of units of output. Operational efficiency also tends to be greater at larger scale. In chemical engineering process design and economics, this phenomenon is explained through an understanding of how fixed capital expenses are determined. The capital costs of large reactor vessels and tanks required in these processes are determined based on the amount of material required in their manufacturing, which can be approximated by their surface area (SA) (Eq. – 1), assuming a spherical reactor vessel for demonstration, where R is the radius); but their capacity, and thus throughput, is determined by their volume (V) (Eq. – 2). (Eq. - 1) �� = 4��! (Eq. – 2) 4 � = ��! 3

The ratio between surface area and volume is a proxy for the cost per unit of production, which predicts that the capacity of a vessel increases with the cube of its radius, while its costs increase at a slower rate, with the square if its radius. Thus, for typical chemical process design, a “two thirds” rule governs economic analysis and describes economies of scale (Ulrich, 1984).

1.2.1 Traditional & Existing Technologies Existing large-scale GTL technologies dominate the field. Shell and Texaco Gasification offer non-catalytic technologies that operate in excess of 1000 °C and 35 bar (Griesbaum, 1985). Catalytic routes to partial oxidation of methane are also possible with transition metal or noble metal catalysts. The economics of these

16 technologies are bound by the high capital investments, while an engine performing partial oxidation may not be constrained in the same way (Acocella, et al., 2014).

Conventional GTL technologies are subject to economies of scale. Large GTL plants, such as the Shell Pearl GTL plant in Qatar produces 140,000 barrels of oil equivalent per day (boepd) of GTL products (Shell, 2015). Capital costs of large methanol plants are estimated to be $700/MT/yr. (Sills, 2013), while a 30 ton per day methanol plant using an engine reformer to produce syngas is projected to cost $360/MT/yr. based on the same economic assumptions (Acocella, et al., 2014). Industry estimates for large-scale plants show that the reformer accounts for about 30% of total capital costs and the methanol synthesis process accounts for 60%, with the remaining 10% representing compressors and miscellaneous equipment. Assuming the same cost per unit production for the methanol synthesis process, the engine reformer GTL system would bring the percentage allocated to methane reforming down to about 5% of total capital costs. Larger plants, especially on the scale of Shell Pearl, are also associated with long construction times and cost escalation over time. Market conditions can change substantially during the construction period, increasing the economic risks.

Several small-scale GTL approaches have been demonstrated, namely by Oberon, Hydrochem, and Gas Technologies (summarized in Table 1). However these processes cannot address the even smaller flow rates from gas flares, which may begin at 1,400,000 scfpd for the first 6-9 months of production, but rapidly decline to 400,000 scfpd after the first year, and decline further and approach 200,000 scfpd for the remainder of the well life (North Dakota Department of Mineral Resources, Oil and Gas Division, 2012).

17

Natural Gas Processing Company Scale Capacity (scfd) MIT Engine Reformer Small 330,000 Oberon1 Small 1,240,000 HydroChem2 Small 1,968,000 Gas Technologies3 Small 30,000,000 Shell (Pearl)4 Large 1,600,000,000 Table 1: Summary of Small-, Medium-, and Large-Scale GTL Developments

1.2.2 The Engine Reformer To approach chemical processes from the small scale, radically innovative solutions are required and thus, researchers at MIT have developed the engine reformer. Engines are inexpensive to mass-produce and are designed to perform chemical reactions at high pressures and high temperatures. The engine reformer concept has been investigated and proven in the MIT Sloan Automotive Lab. Using slightly modified engines, methane (CH4) is combusted under extremely fuel-rich regimes, which promotes partial oxidation (POX) of the methane to syngas without the need for a catalyst. Engines also offer flexibility in plant design. Altering the size of the engine cylinder and the total number of cylinders allows the total gas processing flow rate to be tailored to match the gas source.

The traditional role of the internal combustion engine is in production of power by converting chemical energy in fuel to useful work. Complete combustion is desired to maximize the combustion efficiency and minimize hydrocarbon emissions.

Products of complete combustion are carbon dioxide (CO2) and water (H2O) (Eq. – 3). Instead, for methane reformation to syngas, the engine is used as a chemical reactor. At high fuel to oxidizer ratios, equivalence ratio (�), methane is partially oxidized, generating hydrogen (H2) and carbon monoxide (CO) (Eq. – 4). Although the engine is performing partial oxidation as the chemical reactor, partial

1 (Oberon Fuels, 2014) 2 (Linde, 2007) 3 (Gas Technologies LLC) 4 (Shell, 2015)

18 combustion also takes place and the engine retains its utility as a power producer as well. Thus, it is possible to harness the mechanical power produced and the heat generated from the engine reformer and integrate them into supplementary system processes. MIT holds the patent for this technology (US 20140144397, filed March 14, 2013) (Bromberg, Green, Sappok, Cohn, & Jalan, 2014)5. (Eq. – 3) ° ��� + � �� ↔ ��� + � ��� ∆���� = −��� kJ/mol (Eq. – 4) ° ��� + �. � �� ↔ �� + � �� ∆���� = −�� kJ/mol

Lim et al. show reliable operation of the engine reformer running on atmospheric air with equivalence ratios up to 2.0. An equivalence ratio of 2.2 with 5% H2 recycle from downstream processes provides an acceptable balance of high H2:CO ratio

(1.8) and high CH4 conversion efficiency (85%). Lower than this equivalence ratio leads to a dramatic reduction in H2:CO ratio. Because methanol synthesis requires an H2:CO ratio of 2.0, low H2:CO ratios from the engine exhaust are to be avoided because this would require significant water-gas shift in the downstream to boost the ratio closer to the desired 2.0. Higher equivalence ratios than 2.2 this leads to a significant reduction in CH4 conversion efficiencies (Lim, et al., 2015).

1.2.3 Small Modular Plant Design The engine reformer-based GTL system is envisioned as a skid-mounted processing plant, containerized and trucked to the stranded resource. Rather than transporting the gas, the processing system is manufactured in a central facility and brought to the field already assembled. Two shipping containers will be required to house the air separation unit (ASU), engine reformer, methanol synthesis reactor, distillation columns, compressors, auxiliary units, and other miscellaneous equipment, as depicted in Figure 4.

5 See (Lim, et al., 2015) for a detailed patent review of similar work.

19

Figure 4: Rendition of Skid-Mounted Engine Reformer-Based GTL System [Credit: E. Lim]

1.2.4 Implementation Once the skid-mounted system is trucked to the oil or gas field, it is connected either to one large gas flare, an existing gas collection network that connects the flare gas from multiple wells on the given field, or any gas production infrastructure that may be in place at marginal fields. (Refer to Chapter 4: Methodology section for specifics of on-site characteristics in North Dakota and NE India.) The GTL unit produces methanol or produces DME by catalytically dehydrating the methanol (Eq. – 5). The methanol dehydration is trivial step in the overall GTL process with insignificant costs. (Eq. – 5)

2��!�� → ��! !� + �!�

The end product generated depends on the end user’s consumption scenario. Three consumptions scenarios are considered in this thesis:

20 (1) DME is used to replace or supplement diesel; either diesel that is required on-site for fuelling trucks and drill rigs, powering generators and pumps, or diesel that is used locally in the transportation and domestic sectors. (2) DME is used to replace or supplement local LPG use in domestic applications such as heating and cooking, or in the transportation sector. (3) Methanol is distributed for sale on the domestic or global market.

On-site use of DME incurs no costs for transportation of the product. However, the costs associated with short transport distances of the DME are applied to the local use scenarios and those associated with the transport of methanol to the nearest central hubs for distribution are applied to the third scenario.

1.3 Fuels Background 1.3.1 Fuel Comparison DME could supplement or potentially replace either diesel or propane for heating, cooking, power generation, and transportation applications. Methanol also has fuel applications and is a chemical commodity as the feedstock to thousands of other chemicals, including formaldehyde for plastics, paints explosives and plywood; olefins in the methanol-to-olefins (MTO) process; synthetic gasoline in the methanol-to-gasoline process; and DME. Table 2 summarizes the comparable attributes of DME and Methanol and other fuel options. A fuel’s cetane number indicates its combustion speed, or how quickly combustion begins upon injection and compression. Higher cetane numbers indicate better combustion performance in compression ignition (CI) or diesel engines. A fuel’s octane number measures its ability to withstand compression before igniting. This is a desirable characteristic for fuels running in spark ignition (SI) engines, which have higher compression ratios and ignite the compressed fuel-air mixture using a spark plug.

21

product of renewable - y Fuel Material Feedstock Crude Oil Crude Oil Underground reserves and renewable biogas Underground reserves and renewable biogas B petroleum refining or natural gas processing Natural gas, coal or biogas Natural gas, coal, or woody biomass

=

=

CNG =

3 gasoline diesel gasoline DME methanol

gal. gasoline

1 gal. diesel Gasoline/Diesel Gallon Equivalent 1 gal. gasoline = 1 gal. gasoline 1 gal. diesel = 1 gal. diesel 5.66 pounds or 123.57 ft 1 gal. gasoline 5.38 lbs. LNG = 1 gal. 6.06 lbs. = 1 gal. 1.37 gal LPG = 1 gal. 1 gal. 1 gal. 2.02

116,090 -

Energy Content (LHV) 112,114 Btu/gal 128,488 Btu/gal 20,160 Btu/lb. 21,240 Btu/lb. 84,250 Btu/gal 68,930 Btu/gal 57,250 Btu/gal Properties Comparison

: Fuel 2

55 60 Table - - Cetane Number N/A 40 N/A N/A N/A 55 N/A

93 - Pump Octane Number 84 N/A 120+ 120+ 105 N/A 112

ignition

950 F - Auto Temperature 495 F 600 F 1,004 F 1,004 F 850 662 F 897 F

Gasoline/E10 Low Sulfur Diesel Compressed Natural Gas (CNG) Liquefied Natural Gas (LNG) Propane (LPG) Dimethyl Ether (DME) Methanol

22 1.3.2 Natural Gas Vehicles (NGVs): CNG & LNG CNG and LNG are widely used in light- (gross vehicle weight rating, GVWR, 0-14,000 lb.), medium- (GVWR 14,001-26,0000 lb.), and heavy-duty (Class 7: 26,001-33,000 lb. & Class 8: above 33,000lb) transportation applications. CNG has a 20-30% lower greenhouse gas (GHG) emission rate than diesel, however is 10-20% less efficient than diesel on an energy basis (Brusstar, Stuhldreher, Swain, & Pidgeon, 2002). Its fuel economy is closer to that of conventional gasoline.

A variety of dedicated CNG and LNG heavy-duty vehicles exist on the market supplied by Freightliner Truck, Volvo, International, Kenworth, Peterbilt, and Mack. Cummins Westport ISL G 8.9L, Cummins Westport 11.9L ISX-G SI, and Westport Innovations GX (LNG) engines are the most popular for heavy-duty application, used for refuse trucks, transit buses, cement trucks, and long-haul tractors (NGV America, 2015). However SI engines have lower efficiency than their CI counterparts. CI natural gas engines that are available cost $30,000-$120,000 more than a diesel truck purchase ($100,000) (Rocky Mountain Institute, 2015). The Westport compression LNG engine retails for $70,000 more than its diesel counterpart (Krupnick, 2010). Smaller HD vehicle differential costs are closer to $40,000. Existing fleets of HD vehicles can be modified to run on natural gas. The modifications of a heavy-duty diesel truck to run on CNG would cost on average $70,300. However, dedicated NGV engines have not scaled into the market in the way that gasoline and diesel engines have, so these estimates could be reduced with greater circulation.

Due to cost and packaging constraints, CNG and LNG may not provide adequate vehicle range without container and storage innovation. CNG cylinders must be highly pressurized (200-250 bar) and will require improvements to achieve high capacity and ultra lightweight storage. LNG has higher energy content per unit volume than CNG because it is in liquid phase. More fuel can be stored onboard so LNG vehicles can have longer range applications. Storage containers for LNG consist

23 of double-walled, vacuum-insulated pressure vessels, which must be able to contain the high pressure, very low temperature fuel. CNG & LNG fuel tanks are 500 lbs. heavier than their diesel counterparts.

Natural gas refueling systems must also see advancements. CNG refueling stations employ either fast-fill or time-fill dispensing. Retail stations typically tend to be fast- fill, while central fleet refueling time-fill because the process can be completed overnight. The cost for CNG fueling stations range from $10,000-$1.8 million (Smith & Gonzales, 2014). LNG fueling stations are structurally similar to those for gasoline and diesel. LNG is dispensed at 2-8 bar and is supercooled to -160 deg. C, which requires operators to wear protective clothing, face shields and gloves. Several options exist for LNG refueling stations: mobile stations in which a tanker truck with on-board metering and dispensing equipment delivers the LNG; starter or containerized stations consisting of a storage tank, dispensing equipment, and metering in a single container shipment; and customized large stations. Costs for LNG fueling stations are between $1-$4 million.

Table 3 summarizes CNG and LNG emissions as compared to diesel in heavy-duty (HD) applications. Both CNG and LNG show a 13% reduction in GHG emissions and a 40% reduction in nitrous oxides (NOx) emissions as compared to new HD diesel vehicles in 2012. CNG also shows a reduction of 25% in GHG emissions, 95% and 88% reduction in NOx emissions, and 98% and 22% reduction in PM10 emissions, as compared to existing HD diesel vehicles on the road in 2002 and 2007, respectively.

24 HD CNG HD CNG HD CNG HD LNG Truck (vs. Truck (vs. Truck (vs. Truck (vs. 2002 Diesel 2007 Diesel 2012 Diesel 2012 Diesel Truck) Truck) Truck) Truck) GHG 25 25 13 13 NOx 95 88 40 40 PM10 96 22 - - Table 3: Emissions Reduction (%) of New NGVs Compared to New and In-Use Diesel Vehicles (NGV America, 2015) 1.3.3 LPG LPG, also called propane or autogas, is used for light- and medium-duty transportation and construction vehicles, and is growing in heavy-duty trucking applications where CI engines with a diesel pilot spark are utilized, or where conventional SI engines are used (such as the dedicated Cummins B5.9LPG engine). Over 10 million trucks run on LPG globally, of which 2 million are active in the US (2012) (Sills, 2013). LPG is stored at about 10 bar onboard and vaporizes for combustion when injected into the engine cylinder. Due to its high octane rating (104-112) compared to gasoline (84-93), LPG is a good replacement for SI applications. Its high octane also helps prevent engine knock. LPG burns cleaner than gasoline, allowing longer engine lifetime and potentially lower maintenance costs. However, because LPG has a lower energy content than gasoline (about 85,000 Btu/gal. vs. 120,000 Btu/gal. for gasoline), more fuel is required onboard to achieve the same range.

LPG vehicles can cost several thousand dollars more than comparable gasoline vehicles. Examples of dedicated heavy-duty LPG engines and fueling systems include Ford Motor Co. 6.8L V-10 engine, General Motors 8.0L V8 engine, and the CleanFUEL USA liquid propane injection (LPI) system (U.S. Department of Energy, 2014).

LPG production, storage and bulk distribution capabilities are well established, however automotive dispending infrastructure is limited. It is estimated that LPG dispensing and filling stations would cost roughly 33% more than traditional diesel stations (Fleisch & Sills, 2014). Many suppliers offer an inexpensive lease of the

25 tank, pump, and dispensing equipment in return for a fuel supply contract. The remaining private infrastructure costs $37,000 for a 1,000-gallon skid-mounted station up to$175,000 for a 30,000-gallon storage tanks (U.S. Department of Energy, 2015).

LPG is widely used for heating and cooking. According to UN data, China and India are the top two consumers of LPG for domestic applications, with the United States ranking third (Factfish, 2011). The distribution infrastructure for LPG in the domestic sector would not require expansion.

1.3.4 DME As compared to LPG, DME has similar energy density (68,930 Btu/gal for DME vs. 84,250 Btu/gal for LPG), compression requirements, and safe storage and handling characteristics. The same pumps, compressors, valves, flow meters, and containers that are used for LPG are used for DME. Modification of seal O-ring elastomer material to ensure compatibility with DME is required. However DME has the superior engine combustion and efficiency properties that characterizes diesel while maintaining the clean-burning properties of natural gas-based fuels. DME performs sootless combustion, due to the lack of carbon-carbon bonds, and does not emit harmful sulfur-oxides, due to the lack of sulfur. Diesel has a high cetane number (50-55), and high rate of combustion, making it well suited for CI engines. DME has a cetane number of 55-60, which makes it an excellent replacement for diesel in heavy-duty CI trucking applications.

The most recent attention DME has received as an alternative fuel for Class 8 trucks has been due Volvo’s announcement to be the first manufacturer to commercialize DME-powered heavy duty vehicles with fleet test roll out in 2015. The company has developed the Volvo VNL tractor with an adjusted Volvo D13 diesel engine (Volvo Trucks, 2015). Modifications of existing diesel vehicles and engines to run on DME are minimal. These include the addition of a second fuel tank, as diesel has 1.88

26 times the energy density of DME, slight alterations to the lining materials of fuel injection systems, adaptations to the temperature management systems, and modification of the fuel lubricity additive packages (fatty acid-based lithium, which is an existing commercial product used for low-sulfur diesel fuel). Additionally, because DME is cleaner burning than diesel, its use does not require a diesel particulate filter to adhere to environmental emissions regulations (International DME Association, 2015). In addition to Volvo, international organizations developing DME vehicles include the Japan DME Association, Haldor Topsoe, ENN Energy Holdings Ltd. and Jiutai Energy (China), and KOGAS (Korea) (Fleisch, Basu, & Sills, 2012).

DME filling station costs are estimated to be roughly that of LPG filling stations as because existing tanks and dispensers can be used. Slight modifications to seal O- ring elastomers (such as Kalrez, Butyl Rubber, or Neoprene rather than Viton) and transfer hoses are required (Frauenheim, 2014). DME can also be blended with LPG, up to 20% by volume, without any modification requirements to distribution infrastructure. This has been demonstrated extensively in China (Fleisch, Basu, & Sills, 2012).

With storage, transport, and other chemical properties similar to LPG, DME can also readily supplement LPG as a heating and cooking fuel, especially in blends. A range of traditional LPG cookstoves and burners with LPG/DME blends has been studied by ENI, Total, and the Japan LPG Center, and demonstrated in Chinese households (Fleisch, Basu, & Sills, 2012).

Another possible application of DME outside the transportation sector is to replace diesel for power generation. Diesel generators (which combine a CI diesel engine with an electric generator or alternator) are widely used to produce electricity for off-grid applications, such as personal home generators used in the US for back-up generation, in developing countries in areas that have unreliable or no electricity

27 access, or remote oil and gas field generators, where grid connectivity is not possible.

1.3.5 Methanol Methanol as a fuel has significant barriers. It has chemical and physical properties similar to ethanol, but lacks the strong industry advocates or policy initiatives that are associated with ethanol to help support widespread use in transportation. Methanol’s high octane achieves similar efficiencies to diesel, while having the clean-burning properties of other natural gas-based fuels in order to meet pollution emissions regulations. Its use in vehicles has dramatically declines since the early 1990’s, when its consumption peaked at 6 million gal. gasoline equivalent of M100 or M85 annually in the US. Automakers no longer manufacture methanol vehicles in the US.

Methanol has however been highlighted as a possible alcohol fuel in modified CI engines for diesel-methanol dual-fuel medium- (Class 6) and heavy-duty (Class 8) applications. In 2012, pursuing its focus on high-efficiency, clean medium-duty engines, UPS demonstrated diesel-methanol dual fuel delivery trucks (Brusstar, 2014).

The dual-fuel diesel-methanol engine requires only minor modifications to a diesel engine. These alterations include the addition of a second fuel tank to store methanol, an additional port fuel injection system, and revisions to the engine control unit (ECU). The diesel-fuel system and the exhaust gas recirculation (EGR) system would be retained, and no NOx after treatment system is required. The use of methanol would require special lubricants, not currently used in diesel engines. These dual-fuel engines would be about 5% more efficient than standard diesel engines, with add-on costs estimated at about $6,000 (Kargul, 2012).

28 The EPA estimates that fueling stations for methanol, which is liquid and can utilize conventional filling nozzles and equipment, would cost $30,000-$55,000 for simple in-ground or above-ground tanks (Kargul, 2012). However, there are significant challenges to methanol’s consumption as an alternative fuel. The existence of many, more commercially established alternative fuels and their respective technologies, coupled with the dilution of engineering efforts for methanol, are major hindrances to its adoption (Brusstar, 2014).

Another opportunity for methanol use in the transportation sector is by cargo ships. The shipping industry is rapidly looking to find alternative fuels that fulfill strict sulfur emissions control area guidelines, which aim to minimize the sulfur oxide (SOx), NOx, ozone depleting substances (ODS) and volatile organic compounds (VOC) emissions from marine vessels. Methanol has become a competitive option because it is liquid at room temperature (no need for pressurized tanks), can be stored onboard, similar to oil products, and does not require the large volume and costs associated with LNG. As discussed previously, conversion costs from diesel engines to dual-fuel engines are considerably lower than those for LNG utilization (Westling, 2013). Marine engines are available for both large 2-strole and 4-stroke engines, and conversion costs are about 220-270 USD/kW (Marine Methanol, 2014). The alterations for methanol dual-fuel engines are to the cylinder head, fuel injector, fuel pump, high-pressure (HP) fuel oil pipe, ventilation system, inserting system and fuel tank.

Sweden is leading the way in development of methanol as a shipping fuel. One major project uses biomass and organic wastes to produce fuel-grade methanol for this application. Stena RoRo is piloting a full-scale project to test alternative non-oil- based options such as methanol and DME. They plan to continue with the full conversion of all four main engines of one of their ferry lines to methanol-diesel dual-fuel operation by the end of 2015, and plan to roll out an additional 55 ships by the end of 2018 (Westling, 2013).

29 Methanol is one of the top chemical commodities produced in the world, with a global demand of 61 MMT/yr. There is no barrier to its use in the chemical industry. Methanol and DME production are both prominent in the NE region of India, specifically from Assam Pretrochemicals Ltd., which has several methanol plants at 100, 200, and 500 TPD, and DME plants at large-scale. This company has paved the way for infrastructure and market development for the region and for export, cutting down many of the significant barriers to entry that could exist otherwise.

30 2. POLICY OVERVIEW

International and domestic fuels standards address a range of issues. Fuels must meet purity and composition specifications, emissions standards, and storage, handling, and distribution infrastructure requirements. Subsidies, tax credits, and other incentives may be applied to the fuels, their producers, or their end users. Incentives may also apply to manufacturers of vehicles that achieve industry- applicable standards.

2.1 United States and North Dakota 2.1.1 Gas Flaring Regulations The North Dakota Century Code [section 38-08-06.4] restricts the flaring of natural gas produced with crude oil (associated gas). Gas may be flared up to one year from the beginning of production, but after that time period the well must be (a) capped; (b) connected to a gas gathering line; (c) connected to an electric generator that consumes at least 75% of the gas from that well; (d) equipped with a system that intakes at least 75% of the gas and natural gas liquids for beneficial consumption (compression to liquid for use as a fuel, transport to processing facility, production of petrochemicals or fertilizer, or conversion to liquid fuels); or (e) equipped with other value-added processes as approved by the industrial commission that reduce the volume or intensity of the flare by more than 60%. Violators of this provision must pay royalties based on the value of the flared gas and pay gross production tax on the flared gas at the rate imposed under the pricing section of the N.D. Century Code. However, the producer may be exempt from the flaring restrictions if it can show that connection to a gas line is economically infeasible, that a market for the gas is not available, and that installing an electric generator or other collection system is also economically infeasible (North Dakota Department of Mineral Resources, 2012).

31 Under section 43-02-03-60.2 of the N.D. Century Code, to apply for an exemption, the producer must prove that an alternative option to flaring is economically infeasible. It must show that the direct costs of connecting the well to a gas collection line and the direct costs of operating the facilities connecting the well to that line during the lifetime of the well are greater than the revenues the operator would likely receive from the gas, less production taxes and royalties, if the well were to be connected. The calculations may include a 10% addition to the cost of well connection and operating costs, which considers the cost of money and other overhead costs that are not otherwise included in the direct costs. The application for exemption must also demonstrate the rationale for gas price used in the calculations, the costs of connecting the well, the operating costs, the current daily rate of the gas flared, the size of gas reserves and the amount of gas available for sale (North Dakota Department of Mineral Resources, Oil and Gas Division, 2012).

The North Dakota Industrial Commission has established individual well gas capture goals to reduce flaring 85% from January 1, 2016 through September 30, 2020. The Commission’s goals aim to approach 90% beginning October 1, 2020 and to reach 95% moving forward from there6. If these goals are not met, wells will be restricted to produce 200 barrels of oil per day (if at least 60% of the monthly associated gas is being captured) otherwise to 100 barrels of oil per day (North Dakota Industrial Commission).

2.1.2 Fuel Specifications CNG, LNG, LPG, and methanol have longstanding standards as fuels in the US and globally. In February 2014, ASTM International, an internationally recognized standards organization that publishes industry consensus technical standards, released specifications for DME as a fuel (Standard No. ASTM D7901-14). The US Department of Energy (DOE) has been in partnership with industry players in the

6 The gas capture percentage is calculated by summing the monthly gas sold, monthly gas used on lease, and monthly gas processed in a Commission-approved beneficial manner, divided by the total monthly volume of associated gas processed.

32 testing and development of DME as a transportation fuel to replace diesel as well. In February 2015, California became the first state to legalize the use of DME in vehicles.

2.1.3 Clean Air Act & Energy Policy Act Under the Clean Air Act (Public Law 91-604) and the Energy Policy Act (EPAct) (Public Law 102-486), the US Environmental Protection Agency (EPA) controls air pollution and sets motor vehicle emission and fuel standards (U.S. Environmental Protection Agency, 1990), (U.S. Congress, 1992). The EPA’s Clean Fuel Vehicles program focuses on alternative fuels and petroleum-based fuels that meet low emission vehicle (LEV) levels. CNG, LNG, LPG, DME and methanol all fall within this category. Although DME is not explicitly included, the most recent EPAct, updated in 2005, define alternative fuels to include pure methanol, ethanol, and other alcohols; blends of 85% or more of alcohol with gasoline; natural gas and liquid fuels domestically produced from natural gas; LPG; coal-derived liquid fuels; hydrogen; electricity; pure biodiesel (B100); fuels, other than alcohols, derived from biological materials; and P-Series fuels. DME falls under the category defined by liquid fuels produced from domestic natural gas. The DOE may specifically designate other fuels as alternatives so long as they are non-petroleum-based, and show substantial energy security and environmental benefits (US Code 13211) (U.S. Congress, 1992).

The EPAct established a grant and loan program to government agencies to reduce emissions for diesel engines by replacing or retrofitting vehicles used in public fleets. It also established a tax credit of 50% of the incremental vehicle cost for new, dedicated alternative vehicle purchases, plus 30% of the incremental cost for vehicles that meet or exceed the most stringent emissions standards available under the Clean Air Act (or that meet California’s Super Ultra Low Emission Vehicles standards). CNG, LNG, LPG and methanol qualify. The EPAct also established tax credits up to 30% of the cost of building alternative fueling equipment infrastructure, up to $30,000 to incentivize alternative fuel distribution.

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2.1.4 Alternative Fuel Tax Credit A tax incentive from the Internal Revenue Service (IRS) for alternative fuels of $0.50/gal is available for CNG, LNG, and LPG. The IRS’ definition of alternative fuels differs from that of the EPA. In order to qualify for the tax credits or incentives from the IRS, the fuel must be LPG, CNG, LNG, liquefied hydrogen, liquid fuel derived from coal through the Fischer-Tropsch (FT) process, liquid hydrocarbons derived from biomass, and P-Series fuels. Further, biodiesel, ethanol, and renewable diesel are explicitly excluded from the IRS definition. Methanol and DME are not included in the IRS definition either and thus would not qualify under existing laws for tax credits as alternative fuels. (US Code 6426)

2.1.5 Vehicle Fuel Economy And GHG Emissions Standards The Department of Transportation’s (DOT) National Highway Traffic Safety Administration (NHSTA) and EPA regulate the fuel economy and GHG emissions for on-road heavy-duty vehicles. Increasingly stringent emissions standards are put in place, which drive manufacturers to comply with better, more efficient technologies, or fuel producers to look to cleaner fuels. Emissions limits for heavy-duty applications are as follows: particulate matter (PM): 0.01 grams per brake horsepower-hour (g/bhp-hr); non-methane hydrocarbons: 0.14 g/bhp-hr; nitrogen oxides (NOx): 0.20 g/bhp-hr; and a regulation requiring the use of low and ultra-low sulfur diesel (U.S. Department of Energy, 2013). (FR Doc No: 2011-20740 (National Highway Traffic Safety Administration, 2011))

2.1.6 Vehicle Conversion Standards In order to retrofit or convert conventional vehicles to run on alternative fuels, which involves replacing or rebuilding the engine and adding the appropriate fuel storage systems, the new engine design must meet existing emissions and safety regulation and standards instituted by the EPA, the NHTSA, and the National Fire

34 Protection Agency’s NFPA 52 Vehicular Gaseous Fuel Systems Code (National Fire Protection Association, 2013).

Section 203(a)(3) of the Clean Air Act prohibits tampering with the original configuration of a certified vehicle or engine. However, licensed conversion manufacturers may seek exemption by demonstrating that emission control systems will continue to function properly after the retrofit as not to result in increased pollution or emissions (U.S. Environmental Protection Agency, 2010). 2.2 India 2.2.1 Natural Gas Strategies The Government of India regulates oil and natural gas resources through the Directorate General of Hydrocarbons (DGH) under the Ministry of Petroleum and Natural Gas (MoPNG). The DGH has authority over environmental protection, safety, technological and economic development of petroleum, and its public-private partnerships. Production Sharing Contracts (PSC) and the newly created Revenue Sharing agreements for discovered fields and exploration blocks are also regulated by the DGH. Under the PSCs the E&P contractor bears the exploration risks and production and development costs and is allowed to recover those costs before sharing its production revenues with the government. In 2015, a new Revenue Sharing Agreement model was proposed and phased in, where the E&P contractor develops the field but the revenue is shared with the government as soon as production commences.

Under the New Exploration Licensing Policy (NELP), which began in 1999, the E&P sector has been opened up to private competition and evened the playing field for their participation with the two National Oil Companies (NOCs), Oil and Natural Gas Corporation Limited (ONGC) and Oil India Limited (OIL). Under NELP, Petroleum Exploration Licenses (PEL) for oil and gas blocks are granted through a bidding process, where private companies and NOCs compete equally.

35 Gas fields in the northeast (NE) region of India include Assam (22 blocks), Manipur (2 blocks), Tripura (3 blocks), Nagaland (2 blocks), Arunachal Pradesh (1 block), and Mizoram (3 blocks). In order to incentivize exploration in the region, the government has implemented a 40% subsidy on gas operations in addition to other policy interventions (Ministry of Petroleum and Natural Gas, 2014).

MoPNG implements guidelines for the utilization of domestic natural gas resources. Highest priority is to fulfill local gas distribution requirements for CNG as a transportation fuel and piped natural gas for domestic applications. Urea production for fertilizers, production of power, and supply of LPG comprise the remaining priority sectors (Ministry of Petroleum and Natural Gas, 2014). Domestic natural gas production only satisfies about 70% of domestic consumption. All domestically produced natural gas must be supplied to domestic demand, in order of priority and none may be exported. LNG imported under open general license policies fulfills the remaining demand.

The price for domestic natural gas is determined by MoPNG and reviewed by the Prime Minister’s Cabinet Committee on Economic Affairs. It is set by calculating the weighted average of the annual average daily price of natural gas from four major global natural gas hubs and the annual volume of natural gas consumed by the country in which the hub is located . See Eq. – 6. (Eq. – 6)

�!!�!! + �!"�!" + �!"#�!"# � = !!!! �!! + �!" + �!"# + �! Where

�!! = ����� ������ ������ �� ������� ��� �������� �� ��� & ������ �!" = ����� ������ ������ �� ������� ��� �������� �� ������ �!"# = ����� ������ ������ �� ������� ��� �������� �� �� & ��� �! = ����� ������ ������ �� ������� ��� �������� �� ������ �!!��� �!"# = annual average daily prices at Henry Hub and National Balancing Point, less the transportation and treatment charges �!"��� �! = annual average monthly prices at Alberta Hub and Russia, less the transportation and treatment charges

36

Gas from small and isolated fields, such as in the Assam Basin, is subject to specific regulations established by MoPNG for customer selection (Ministry of Petroleum and Natural Gas). These guidelines apply to fields which have peak production if less than 3.5 MMscfpd (million scfpd) and are more than 10km from a gas grid, or fields in that same capacity range at pressure less than that of the grid. Entities may express their interest in becoming customers through the submission of a bid indicating their sector. Priority is given to gas-based urea fertilizer plants, LPG plants, power plants that supply power to the grid or state utilities, city gas distribution systems for the domestic and transport sector, steel, refineries and petrochemical plants, city gas distribution systems for industrial and commercial consumers, and then “other,” in that order.

2.2.2 Fuel and Vehicle Standards & Regulations Fuel standards in India are regulated through the Central Pollution Control Board (CPCB), MoPNG, Ministry of Environment and Forest (MoEF), Ministry of Road Transport and Highways (MoRTH), and Bureau of Indian Standards (BIS). Under the MoPNG, the Petroleum and Natural Gas Regulatory Board (PNGRB) regulates fuel quality standards for import, production, refining, distribution, and sales and has the authority to enforce fuel quality standards at retail outlets (Transport Policy, 2014). India has adopted the European model for vehicle emissions and fuel standards. The country implements two different fuel quality standards, one for advanced cities, which limits sulfur content to be under 50 ppm for gasoline and diesel, and one for the rest of the country, which allows 150 ppm sulfur content for gasoline and 350 ppm sulfur for diesel (Transport Policy, 2014)7.

7 In the US, 500 ppm diesel sulfur content is considered “low sulfur” diesel, which was used for general heavy-duty vehicle applications to meet the 1994 EPA emissions standards. “Ultra low sulfur” diesel has a sulfur content limit of 15 ppm, is used for heavy-duty applications to meet the 2007-2010 emissions standards (Transport Policy, 2015).

37 Of the total CNG consumption in India, 48% is used for the transport sector, 50% is piped gas to commercial and industrial uses, and 2% is piped to households.

2.2.3 LPG Subsidies The three main public sector oil-marketing companies (OMCs) registered with the MoPNG as LPG distributors are Indian Oil Company Limits (IOCL), Bharat Petroleum Corporation Limited (BPCL), and Hindustan Petroleum Corporation Limited (HPCL). The Government of India subsidizes domestic LPG with the intention to provide affordable clean cooking and heating fuels to the people. These subsidies cost the government millions of dollars every year. The retail price of LPG cylinders is subsidized through two mechanisms: direct subsidies, which are recorded as direct budgetary expenses as a flat rate per domestic LPG cylinder, and oil marketing OMC under-recoveries, which is the difference between the cost to produce the fuel and the price that is set by the government. In September 2012, the government implemented a cap on the number of subsidized 14.2 kg household LPG cylinders a household could purchase in a given year in order to reduce its expenditures and to more equitably distribute the direct benefits from subsidies to the least wealthy households. Once a household has reached its quota of subsidized LPG cylinders, it must pay full retail price. As a result of political pressure, the cap has been raised twice since its first implementation. Upon implementation of the policy on September 13, 2012 the limit was set to 6 cylinders per household per year. The quotas was then raised to 9 cylinders per year on January 16, 2013, and finally to 12 cylinders per household per year on January 30, 2014, despite the recommendation by the government-appointed Expert Group fuel pricing advisory board to reduce the cap back to 6 cylinders per year to control budgetary spending (International Institute for Sustainable Development, 2014).

2.2.4 Direct Benefit Transfer (DBT) A new method for users to pay for subsidized LPG cylinders, Direct Benefit Transfer (DBT), established in January 2015 under the Finance Ministry, intends to reduce

38 inefficiencies in the payment process. DBT is an electronic payment system in conjunction with a voluntary national identity program (Unique ID, UID, or Aadhaar)8. Under this mechanism, households order LPG cylinders from their gas distributor, receive the amount of the subsidy in their bank account through an electronic transfer of funds, and pay the full, unsubsidized, price for the cylinders in cash upon delivery. The program is currently in its rollout phase (International Institute for Sustainable Development, 2014).

2.2.5 Emissions As the third largest emitter of carbon dioxide, India operates coal-, gas-, and oil-fired power plants that produce 50-120% more CO2 per kWh produced than their counterparts in the EU (International Energy Agency, 2014). Its transportation sector suffers from similar inefficiencies and is a major cause of pollution from the country.

2.26 Bharat Stage IV Vehicle Emission Standards, 2010 Based on the European regulations, the Bharat standards have brought down pollution levels, but as a result, increased the cost of vehicles due to required improvements in technologies. The Bharat standards set emission limits for heavy- duty vehicles and off-road diesel applications, and set fuel specifications, which align with the current European standards (Central Pollution Control Board).

2.2.7 Air (Prevention and Control of Pollution) Act, 1981 The Air Act gives State Pollution Control Boards (SPCBs) authority to prohibit burning of fuels that have shown to lead to air pollution. Specifications differ state- to-state.

8 Aadhaar launched in 2009 to record biometric details and assign an UID number for all residents (International Institute for Sustainable Development, 2014)

39

2.2.8 Environmental (Protection) Act, 1986 The Environmental Act gives the Federal government and State governments the authority to regulate activities deemed harmful to the environment. This could include burning of fuels, but fuels are not specifically mentioned in the Act.

40 3. LITERATURE REVIEW

The goal of this thesis is to develop a model to study the effects of feedstock characteristics, system optimization and integration, product markets, and implementation scenarios on the economic feasibility for the engine reformer-based GTL system. Thus, the topics for review span across multiple fields of research, including methane feedstock source (broken down into associated gas at oil fields and stranded natural gas reserves) and location (US vs. India), engine combustion, methane reformation processes, methanol and DME production processes, and technical and economic evaluation of fuel and chemical production plants.

3.1 Feedstock: Location, Type, and Availability 3.1.1 US The North Dakota Department of Mineral Resources presents the current oil and natural gas scenario in the Bakken. The rate of wells drilled per year is steadily growing, with close to 200 operational in 2013-2014. Gar flares are increasingly problematic and wasteful but new or expanding gas plants are expected. The challenges to bringing the gas to market are more complicated than the limitations in existing infrastructure (North Dakota Department of Mineral Resources, Oil and Gas Division, 2012).

3.1.2 India Researchers at the Harvard Kennedy School’s Belfer Center for Science and International Affairs have investigated the geopolitics of Natural Gas in India. It is a valuable indicator of the current status of the Indian natural gas landscape and challenges. The study shows that there is a growing gap between the amount of natural gas produced in the country and the amount consumed, which is filled by LNG imports predominantly from Qatar. The country is looking into unconventional methods of gaining access to some of their reserves. The report also indicates that some of the challenges are not technical, but based in economic policy structures.

41 The gas pricing structure is a complex web and is reflective of who produced the gas. The Government of India has announced a new formula for domestic price of natural gas, effective April 2014, which reflects the trailing 12-month volume- weighted average price of LNG imports into India and the volume-weighted price of the US Henry Hub, UK National Balancing Point, and Japanese Crude Cocktail prices (Ebinger & Avasarala, 2013). The report also cites political regulations as added complications to the natural gas pricing sector.

Similarly, the US EIA compiled a report on India’s energy consumption patterns and trends. This report corroborates many of the findings of the Ebinger report on the natural gas sector and adds information on India’s consumption patterns of biomass and waste as fuel sources. The author shows trends that traditional solid cooking fuels such as firewood, crop residue, and cow dung cake are predominantly used in rural locations, and LPG is the leading fuel type in urban areas (Das, 2013).

3.2 Engines 3.2.1 Engine Combustion The engine reformer utilizes the high in-cylinder temperatures and pressures that occur during combustion to perform partial oxidation and partial combustion of the mixed methane-air intake feed. John Heywood, Professor of Mechanical Engineering at MIT and expert on internal combustion engines, has written a highly comprehensive textbook in this field, Internal Combustion Engine Fundamentals (Heywood, 1988). Heywood’s text explains different engine operating modes, combustion characteristics, pressure and temperature cycles, and supporting theory that characterizes how the partial oxidation of methane occurs in this context.

Ghazi A. Karim first introduced non-catalytic partial oxidation of methane to syngas in an internal combustion engine into literature. Karim showed that successful POX could be performed with very rich mixtures of methane and oxygenated air and that power is also produced. He demonstrated the process in both compression ignition

42 engines and spark ignition engines. However, Karim tested equivalence ratios (fuel to oxidizer, specifically, methane to oxygenated air) up to 2.5 (Karim, 1980). The system developed at MIT, which is proposed in this thesis, extends the limits of the engine to an equivalence ratio of 2.8, with further development up to 3.4.

3.3 Gas-to-Liquids 3.3.1 Reformation Commercial syngas generation from methane reformation in generally performed via steam methane reforming (SMR), autothermal reforming (ATR), or partial oxidation (POX). Wilhelm, et al. give an overview of these syngas production process technologies, challenges, and future. They find that despite the various hydrocarbon feedstock options (coal, petroleum coke, biomass, etc.), the lowest cost option stems from natural gas, and industry has focused on associated, stranded, or remotely located natural gas reserves. The authors find that the reforming process in the overall system accounts for almost 30% of the total capital costs, and the oxygen plant accounts for roughly 25% of the total capital costs and predict that significant decreases in reforming capital costs and technological breakthroughs which eliminate the need for an air separation unit without reducing overall system efficiency or performance will be the main directions industry pursues in the near future of GTL systems outlook (Wilhelm, Simbeck, Karp, & Dickenson, 2001).

3.3.2 Methanol/DME Production & Distribution Lovik presents a model to determine optimal operation of methanol synthesis under catalytic deactivation (Lovik, 2001). The report details its synthesis model and is helpful in gaining insight into how the industry builds methanol synthesis models using Aspen Plus software.

Issues associated with the widespread implementation of methanol as a fuel, including existing distribution infrastructure, technical and economic characteristics

43 of methanol distribution and total distribution capacity required to deploy methanol as an alternative fuel are presented in a technical report for the EPA. The study predicts that distribution of methanol will be significantly higher than distribution of synthetic gasoline, which can utilize existing fuel distribution infrastructure, due to limited infrastructure currently in place. The while investment in distribution infrastructure would be significant, capital costs of methanol production are low compared to gasoline production facilities. The author concludes however, that the fuels market is highly complex and accurate predictions are difficult to make (Atkinson, 1982).

Khalilpour & Karimi present a decision analysis for a stranded gas owner with the option to bring the resource to market through a pipeline, convert to LNG, CNG, GTL liquids, gas-to-solids, or convert to electricity. With net present value (NPV) as the decision criterion, their model calculates the expected NPV of each alternative and determines the most economical options for LNG, CNG, and GTL for relative reservoir capacities and market distances. The study finds that at short distances to market, CNG is the best option, regardless of reservoir capacity. At distances to market above 4,700 km, LNG serves the producer better at reservoir capacities up to 6-8 trillion cubic feet (tcf), while GTL is the optimum product above this range. The authors claim that anything below 0.5 tcf amasses a negative NPV, and thus is uneconomical (Khalilpour & Karimi, 2012). Important to note, however, that the system presented in this thesis proposes considerably smaller capacities of gas, showing a real opportunity for its implementation due to its innovative design.

3.4 Chemical Processing Design & Economics 3.4.1 Conventional Design Economics Gael D. Ulrich presents a comprehensive guide on industry practices and fundamentals for the design and economic evaluation for chemical engineering. Ulrich explains proper flow sheet preparation, specifications and design of equipment, and standard economic practices in chemical engineering. He describes

44 the basis for estimating component capital costs as a function of capacity with specific scaling parameters for different types and categories of equipment, presents system component cost data, and assumptions for manufacturing cost estimations. He concludes with conventional industry economic optimization strategies and demonstrates cash flow analyses and industry standard rate of return criteria (Ulrich, 1984).

3.5 Mass Manufacturing

Researchers from Columbia University argue that it is possible to capitalize on “economies of mass production” rather than the conventional economies of scale (Dahlgren, Göçmen, Lackner, & van Ryzin, 2013). They claim that capital costs can be reduced by applying knowledge of mass manufacturing process to develop small- scale processes. Thus, cost reduction associated with scaling up in size can be matched by reductions associated with scaling up in numbers.

3.6 GTL Applications

A review of commercially viable GTL technologies in the Journal of Natural Gas Science and Engineering, finds the F-T processes are the leading technologies in the sector, both in large- and small-scale production, and that production of DME from coal and natural gas are becoming more prevalent in Asian markets as LPG substitutes. There are also developments in production processes which directly convert syngas to DME, eliminating the methanol production step and potentially increasing overall process efficiency (Wood, Nwaoha, & Towler, 2012). The authors also point out that there are significant challenges faced by the GTL industry such as high capital costs, complexity or process, which affect efficiency and reliability, and uncertainties and volatility in crude and natural gas markets.

Several economic evaluations of fuel process plants have produced considerably detailed reports that include data to inform the GTL economic in this thesis. A report from the National Renewable Energy Lab (NREL), details their flow sheet process

45 design processes: wood gasification, methanol synthesis, and methanol-to-gasoline, with complete Aspen Process modeling results. The report also discusses the plant feedstock and capacity assumptions and efficiencies and describes their process economics summary from Aspen’s APEA (Aspen Process Economics Analysis) software with assumptions, cost scaling calculations, and data sources. The report estimates what the plant gate price (PGP) for the gasoline product and concludes that for the plant described to produce fuel for a competitive PGP, significant technical milestones must be achieved. These improvements include increasing performance of methane-to-syngas conversion processes, driving down capital costs of new methanol synthesis reactors, increasing potential uses for tail gases, and improving overall plant energy efficiency (Phillips, Tarud, Biddy, & Dutta, 2011).

Another similarly detailed Ph.D. dissertation from the Department of Mechanical Engineering at the Technical University of Denmark, proposes technical and economic designs of a DME/methanol plant based on biomass gasification. The report provides useful insight on methanol and DME plant designs to improve total synthesis energy efficiency, lower plant CO2 emissions, and improve overall conversion and plant energy integration (Clausen, 2011).

The US Department of Energy has provided a detailed cost evaluation for transportation fuels (methanol via the liquid-phase methanol process, compressed natural gas (CNG), liquefied natural gas (LNG), gasoline or diesel via the Fischer- Tropsch (FT) method, and DME via the Haldor-Topsoe steam methanol reformation method). This report reviews research from pilot plants, demonstration plants, and commercial plants to break down the cost per gallon produced for feedstock and other operating costs, capital costs, and cost factors for these processes. These cost quotes are from industry sources. The report finds that the cost per gallon of gasoline equivalent for commercially proven liquid phase methanol GTL production

46 is half that of F-T gasoline and diesel, and only about 1% higher than gasoline production costs9 (Hackworth, Koch, & Rezaiyan, 1995).

The IEA World Energy Outlook report breaks down some of the comparative costs of cooking fuels, including biogas, DME and LPG and financial implications of switching from one cooking fuel to another. The authors report that as income increases, households do not tend to switch from one type of fuel to another, they tend to “fuel stack” modern fuels on top of the traditional fuels, with the most energy demanding energy applications, heating and cooking, as the last to switch to the modern fuel. Much of this has to do with reluctance to change a cooking style due to taste preferences (OECD, 2006). The study also presents the harmful health and environmental impacts of traditional domestic fuels use and points to the challenges associated with implementing the modern options. It suggests that other fuel options including DME (citing its expanded use in blends with LPG in China) will likely become more available and cost effective over the next few decades. Updates to this report show that investments in energy access for all in India have been focused on electricity access rather than domestic fuels and suggest that clean fuels should become a greater priority than they currently are (International Energy Agency, 2012).

3.7 Compact GTL Technologies

The compact gas-to-liquid space has seen an increase in R&D in recent years. Several commercial entities have emerged with new production units. R3Sciences presented its modular gas-to-methanol technology at the GTL Technologies Forum in July 2013. They have developed an experimentally proven gas-to-liquid methanol process utilizing a homogeneous catalyst, which allows production at the 3-30 TPD scale. After the roll out of their pilot project at about 0.15 TPD, they plan to implement a 6 TPD prototype unit with a commercial ready product by the end of 2015 (Ambatipati, 2013). Another such company working on compact gas-to-

9 Based on USD (2005)

47 methanol production units, GasTechnologies, has developed their “GasTechno” process to directly convert methane to methanol, skipping syngas production (Gas Technologies LLC). Both R3Sciences and GasTechnologies are optimistic about the potential of their products but it is still quite early in the development stages for conclusive predictions regarding the level of their success and entry into the market. Research groups in Japan have also established a direct DME synthesis process, which converts syngas to DME in one step, foregoing the intermediate methanol production step (Yotaro, Masahiro, Tsutomu, Osamu, Takashi, & Norio, 2006).

Volvo has announced it will launch a fully bio-DME powered trucking fleet in North America by 2015, partnering with Oberon Fuels using compact skid-mounted DME production units. Oberon’s process has begun with a 2-skid pilot plant, which converts purchased methanol to DME with a proprietary catalyst (Oberon Fuels, 2014).

A report for the IEA performed at the Center for Energy and Environmental Studies at Princeton University presents a review of leading small-scale methane reforming technologies for hydrogen production. The study finds that recent trends in the design of small-scale reformers show POX and AMR to have simpler first stages, but more complex purification systems than SMR routes, and that major oil companies are engaged in joint venture developments of these technologies to become suppliers of future fuels (Ogden).

The North Dakota Department of Mineral Resources and the North Dakota Pipeline Authority present emerging technologies that specifically address flared natural gas. Options include using the gas on-site to power drill rigs, conversion to chemicals such as ammonia for fertilizer production, providing grid power, site power, micro- grid or private electrical grids, conversion to methanol, “ultra-small-scale” LNG plants, and natural gas liquids recovery (North Dakota Department of Mineral Resources, Oil and Gas Division, 2012). The Energy & Environmental Research Center at the University of North Dakota are conducting a study funded by the North

48 Dakota Industrial Commission and the US Department of Energy with commercial support from Continental Resources to assess the technical viability of technologies utilizing associated gas and identifying economic conditions that enable commercial deployment. The researchers compare the targeted gas use range, natural gas liquids removal requirement, scalability to resource, ease of mobility, and likelihood of deployment for small-scale natural gas liquids recovery, CNG and LNG for heavy- duty vehicles, electric power generation and chemicals production for fertilizer. They find that power for grid support and for local loads are the most likely to be deployed and at small scale, starting at 300,000 scfpd, while deployment of CNG and fertilizer production are possible the technologies are not as scalable to the resource capacity constraints (North Dakota Department of Mineral Resources, Oil and Gas Division, 2012).

3.8 DME Promotion

A number of research groups are interested advancing DME as a clean fuel on the global market. A 2012 report by the DME Institute, a consulting company interested in the development of alternative fuels options with specific interest in DME, presents a comprehensive overview of DME production and introduction and advancement as a fuel. They find that the introduction of a new fuel on the global market is a complicated endeavor and requires support from many different organizations. However, the use of DME is growing rapidly in Asia, particularly China, and the growing demand will help with wide spread adoption. They also find that DME production and use has significant fuel efficiency, GHG emission and economic advantages over other fuel choices (Fleisch, Basu, & Sills, 2012). In addition, researchers have launched a joint program between the Australia Commonwealth Scientific and Industrial Research Organization (CSIRO), and India’s Council of Scientific and Industrial Research (CSIR) in efforts to produce and advance the implementation of DME as a fuel. These research efforts show trends that both DME production and demand as a fuel are growing on a global scale, which will encourage the adoption of low cost DME production processes.

49

3.9 Domestic Fuel Trends in the Developing World

A report by TERI University provides trends fir fuel consumption in India (Sehgal, Garg, Goel, Mohan, & van der Hombergh, 2010). A similar report done by the International Energy Initiative presents supply and demand trends of LPG as a cooking fuel in India and some of the challenges in extending the fuel to be more accessible and affordable for households (D'Sa & Murphy, 2004). This is helpful in determining the opportunities that may be capitalized on by introducing DME as a fuel competitor in the developing context. It highlights the complexity that characterizes the LPG market in India, which is exacerbated by the government subsidy programs.

50 4. METHODOLOGY

A techno-economic model of the MIT engine reformer-based methanol synthesis GTL system is developed in this thesis. Critical components and non-critical components are identified, and summarized in Table 4. The system is modeled in an Aspen Plus simulation to develop an Aspen Process Economics Analyzer (APEA) tool, used to determine bare equipment costs for non-critical system components. The APEA software is capable of developing very complex economic analyses applying current industry assumptions and practices. However, this type of economic analysis is not applicable to the MIT engine-reformer GTL system because these proposed systems would be small-scale, modular, and skid-mounted. The economic analysis for this study requires site-, time-, and end user- specific assumptions for the given applications. Critical component costs are determined through vendor quotes, communications with appropriate retailers, and public datasheets and advertising material.

Critical System Component Non-Critical Components Natural gas prep compressor Natural gas prep heat exchanger Air separation unit Air separation unit heat exchanger Air separation unit oxygen compressors Syngas cooling heat exchangers Engine Syngas cooling flash vessels Engine reformer compressors Water gas shift heat exchangers Syngas compressor Water gas shift flash vessel Water gas shift reactor Water gas shift splitters Methanol synthesis pumps Methanol synthesis expanders Methanol synthesis mixers & splitters Methanol synthesis heaters Methanol synthesis reactor Methanol synthesis flash vessels Methanol synthesis distillation columns Table 4: Engine Reformer-Based GTL System Components

51 Critical and non-critical component costs are combined with applicable chemical processing and petroleum refining industry data to develop the full system economic model. Industry data is collected through private and collaborative communications between MIT and industry experts and from public data records. A cash flow model is developed in Microsoft Excel as a tool for system manufacturers to determine how to price their systems, and for potential GTL system end-users, oil and gas E&P companies, to determine if converting their stranded, associated, or otherwise non-marketed gas is economical over a reasonable payback period.

4.1 Aspen Plus Model

Aspen Plus chemical process engineering simulation software version 8.0 is utilized in this study. Gaseous methane and air are converted to liquid methanol. The purpose of the Aspen Model is to appropriately size and cost system components such as compressors, heaters, coolers, flash vessels, and pipes. While all components must be modeled to complete the system and achieve convergence, the model represents experimental results and is not to be utilized as a predictive chemical process model. The system process overview is depicted in Figure 5.

52

: Methane to Methanol GTL System Aspen Flow Sheet 5 Figure

53 4.1.1 Gas Conditioning: Air Separation Unit

Air enters an air separation unit (ASU) block at atmospheric conditions (�!"#,!" =

1.013 ���, �!"#,!! = 30 °�), the nitrogen is extracted through a separator and the resulting oxygen stream is boosted back up to atmospheric pressure via an isentropic compressor and heated (stream OXY2ENG in Figure 6). See Appendix A.1 for ASU stream results.

Figure 6: Air Separation Unit Block Flow Sheet

4.1.2 Gas Conditioning: Natural Gas Preparation For a baseline model, pipeline grade natural gas at standard temperature and pressure (�!!!,!" = 30°�, �!!!,!" = 1.013 ���) is heated to 427°C (NGAS2ENG stream in Figure 7). See Appendix A.2 for Natural Gas Prep stream results.

54

Figure 7: Natural Gas Prep Block Flow Sheet

4.1.3 Engine Reformer Block: The Engine Reformer Block is designed to simulate the combustion conditions in a four-stroke internal combustion engine cylinder: mixing at or before intake; compression by piston; combustion at or before top dead center, which initiates the power expansion stroke; and exhaust of the partial oxidation resultants.

The oxygen and methane are mixed and compressed to 40 bar. An RPlug reactor, which assumes that perfect mixing occurs in the radial direction of the reactor and none in the axial direction, performs partial combustion (Eq. – 7) at a specified temperature of 1,800°C (COMBUST stream in Figure 8). (Eq. – 7)

��! + 2�! → ��! + 2�!�

Partial oxidation is performed through a combination of a second RPlug reactor (EXPREACT1) and an REquilibrium reactor (EXPREACT2) with the available reactions set:

55 (Eq. – 8) 1 �� + � → �� 2 ! ! (Eq. – 9)

�!� + ��! → �� + 3�! (Eq. – 10) 1 � + � ⇌ � � ! 2 ! ! (Eq. – 11)

�� + �!� ⇌ ��! + �!�

This final gaseous stream is expanded (EXP2), representing the exhaust out of the engine reformer cylinder. To improve H2 production, and achieve required H2:CO ratio of 2, a percentage of the exhausted syngas is recycled back to the engine inlet (XHSTRECY stream). See Appendix A.3 for Engine Reformer stream results.

56

Block Flow Sheet : Engine Reformer 8 Figure

57 4.1.4 Syngas Cleaning The exhaust syngas is cooled and passes through a pressure flash evaporator to regulate pressure and eliminate liquid components as necessary. See Figure 9 for syngas cleaning flow sheet and Appendix A.4 for stream results.

Figure 9: Syngas Cleaning Block Flow Sheet

4.1.5 Compression Methanol synthesis requires pressures of 30-100bar, depending on the process. To adjust to the required pressure, a two-stage isentropic compressor pressurizes the syngas, depicted in Figure 10. As the goal of the Aspen model is to simulate the gas- to-liquid process in order to estimate non-critical component sizes and costs, and the compressor is considered a critical component, the purpose of the syngas compressor in the simulation is to ensure the methanol synthesis process is calculated properly, not to determine an accurate size and cost of the compressor itself.

58 Figure 10: Syngas Compression Block Flow Sheet

4.1.6 Water Gas Shift

The methanol synthesis reaction requires an H2:CO ratio of 2:1. To ensure optimal conversion, a water gas shift (WGS) reactor boosts the hydrogen content of the stream entering the methanol reactor (Figure 11). A splitter sends 50% of the inlet syngas (SHFTINLT) to the REquil reactor, where it is mixed with high-pressure steam (likely to have been created through heat recovery from the exothermic partial oxidation in the reformer, or from other previous stages of the process that release heat) and the WGS reaction (Eq. – 11) ensues. The exit gas stream from the WGS reactor mixes with the un-shifted syngas steam to produce a final syngas stream with a 2:1 H2:CO ratio (SHFTSNGAS).

Figure 11: Water Gas Shift Block Flow Sheet

59 4.1.7 Methanol Synthesis The shifted syngas is enters the methanol synthesis block (shown in Figure 12) at high temperature and pressure. The stream is cooled and enters the RGibbs methanol reactor. The reactor is set up to restrict chemical equilibrium at a maintained temperature of 40°�. The possible products are identified as methanol

(CH3OH), carbon monoxide (CO), water (H2O), carbon dioxide (CO2), hydrogen (H2), and nitrogen (N2), where N2, ethane (C2H6), propane (C3H8), and n-butane-1 (C4H10- 1) are inert to the process. The crude methanol stream exits the reactor, is cooled, and enters a flash vessel. 30% of the vapor portion of the stream is purged, and the remaining 70% is compressed and recycled back to mix with fresh syngas before re- entering the methanol reactor. The liquids are distilled out. Two distillation columns refine the crude liquid methanol to chemical grade, 99.98% purity. The first distiller, a 15-stage RadFrac column, achieves 85% methanol purity, and the second, a DSTWU column, achieves the 99.98% purity.

Figure 12: Methanol Synthesis Block Flow Sheet

60 4.1.8 Aspen Plus Economic Analysis The process simulation is initialized and run and the APEA economic evaluation is performed. System components are mapped and sized appropriately. While APEA software runs highly rigorous analysis to determine components’ volume, material requirements, and construction requirements, and from this establishes component costs, utility requirements, installation costs, labor costs and maintenance costs, many of these estimates are based on conventional chemical industry practices. The engine reformer-based GTL system considered in this study differs greatly from industry standards and thus, only bare equipment costs of components for which vendors have not provided quotes, are obtained from the APEA results. The system in this study is designed to be assembled in a central mass-manufacturing facility and does not incur individualized construction and installation costs for each component. The construction and installation costs of the full system are incorporated elsewhere in the economic analysis and thus, the bare equipment costs are the relevant variables to be taken from the APEA results.

4.2 Economic Model 4.2.1 Investment Model Under the proposed business model, an independent GTL producer manufactures skid-mounted systems, leases them to oil and gas E&P companies, and transports the systems to the gas sites. The E&P company owns the natural gas feedstock and the methanol produced. Accordingly, the economic model accounts for the costs of both investment entities: the upstream GTL system producer, and the downstream E&P company system end user. The upstream system producer incurs the initial capital expenses of the system. It is concerned with the fixed and variable costs of producing the GTL systems. The downstream end user must consider the marginal costs and revenues associated with methanol production, in addition to its recurring fixed lease investment, amortized over the lease payback period.

61 4.2.2 Baseline System Assumptions Methane gas flow rate for US baseline modeling is set to 330,000 scfd. Data from the North Dakota state government shows that for January of 2015, the average amount of gas flared at each oil well that was in operation was 33,000 scfpd. This is also presented in the graph in Figure 13 with the distribution of gas flare rates based on the number of oil wells flaring in that bracket (North Dakota Department of Mineral Resources Industrial Commission, 2015). In North Dakota, there are roughly 10-20 oil wells on a given oil field or pad (Ellerd, 2013). This suggests that in order to characterize the scenario in which one compact GTL system serves a single oil pad, a 330,000 scfpd base case capacity should be used. The analysis also considers capacities of 660,000 scfpd. To understand economic implications of future applications for the engine-based GTL system, such as for larger oil or gas deposit in the US, 1 MMscfpd, 3 MMscfpd and 6 MMscfpd are also studied.

Figure 13: North Dakota Flare Gas Flow Rate & Distribution (North Dakota Pipeline Authority, 2013)

62

The gas scenario for India is modeled slightly differently. Industry data in Figure 14 shows that the opportunity for flared gas is significantly smaller than in the US. Considerable amounts of flaring are not reported as widely. However, the presence of stranded gas at substantial quantities, shown in Figure 15, suggests an Indian context for implementation of the engine reformer-based GTL system that is slightly different from the US situation. Based on these assumptions, two approaches for the economic model are developed. The Fixed Capacity Approach, utilized for the US, is designed to determine the most cost-effective way to design the system given a 330,000 scfpd feed gas flow. The Fixed Payback Period Approach, utilized for India, is designed to determine the minimum efficient scale, or minimum gas flow rate capacity, required to make the GTL system economical over a given payback period.

Flared Gas by Field Data from Jan. 2014

140 120 100 80 60

'000 cfpd 40 20 0

Flaring Field Name

Figure 14: India Flare Gas Fields and Flow Rates

63 Table 5 summarizes the variables and baseline assumptions for the Fixed Capacity economic model, applied to the US. Parameters denoted with an asterisk signify variables that are not flow capacity-dependent but may require different

Marginal Fields Inplace 30,000

25,000

3 20,000

15,000

Million ft 10,000

5,000

0

Marginal Field Name

Figure 15: India Stranded Gas Fields and Capacities

assumption to characterize the baseline scenario in India for the Fixed Payback Period approach. India-specific values are in parentheses. Well gas flow and composition are determined from open government data in order to determine appropriate methane flow rates for Aspen Plus simulations (which establishes system components’ size and bare equipment costs, as discussed above). Aspen- determined component costs apply to the syngas cleaning, water gas shift, and methanol synthesis processes. The Aspen-derived equipment sizes and costs are subject to the chemical industry’s conventional estimates for scaling of components’ costs with capacity, called the “0.6 Rule,” as described in Eq. – 12, where C1 and C2 are the costs of two components and X1 and X2 are their respective capacities. This rule of thumb originates from the idea that the costs of certain types of equipment is a function of surface area or material used to enclose the volume, which is directly

64 related to the component’s capacity (see Chapter 1: Introduction for further explanation) (Moore, 1959). (Eq. – 12) !.! �! �! = �! �!

In this analysis, only the “miscellaneous equipment” and methanol reactor from the APEA results are subject to this estimation. All other component costs are vendor- based quotes.

System Specification Baseline Value Well gas flow 0.3310 MMscfpd Engine Displacement 8 L Number of Engines 1 Methanol production 12.2 TPD 3,565 TPY 97 bbl/day 28,318 bbl./yr. Plant Availability 80% (292 days/yr.) Upstream Engine Cost (per engine) $22,000 Misc. equipment, methanol $1,595,300 reactor, etc. Syngas Compressor $900,000 Air Separation Unit $300,000 Contingency 20% of CAPEX System Transport Cost $8,000,000 Capital Cost Factor* 1 (0.70) Downstream Engine Overhaul Cost $1,500 Engine time between overhauls 5,000 hrs. Engine operating time 7,013 hrs./yr. Engine total lifetime 2.1 yrs. Methanol catalyst replacement $25/kg Plant refurbishment period 2 yrs. Variable Operation & Maintenance 7% of CAPEX Natural Gas Cost* 11 $0 ($2) /MMBtu Table 5: Baseline System and Economic Assumptions

10 The initial baseline Fixed Payback Period approach does assume a 330,000-scfpd initial capacity for comparison purposes. 11 Natural Gas Cost represents the costs to the E&P company associated with getting the gas out of the ground. Associated gas that is already produced with the liquid products has “zero costs” while stranded gas will have some cost to the block/field owner (Murthy & Malik, 2015)

65

Engine displacement is determined by throughput calculations based on the desired feed gas flow, MIT engine experimental results, and data on commercially available manufactured engines. The engine is operated at 1200 rpm. 330,000 scfpd methane intake would require an engine displacement of 6 L. Many factors above and beyond displacement requirements go into engine selection. The teams at MIT and the Research Triangle Institute (RTI) are working with Mainstream Engineering in selecting and commissioning the appropriate engine. Engine selection is based on weighting of several characteristics. The following decision criteria of higher importance: availability of a generator set, ignition type (SI vs. CI), compression ratio, and displacement. For these reasons, the baseline engine displacement has been set to 8 L. With plant availability set to 80% to account for scheduled downtime for maintenance and other production interruptions, and baseline assumptions summarized in Table 5, the GTL plant will produce 12.2 TPD (96 bbl./day on a volume basis) of methanol.

4.2.3 Upstream Manufacturer’s Cost & Considerations In addition to the engine cost and equipment costs from the APEA, other upstream manufacturer’s economic responsibilities include the air separation unit, the syngas compressor between the engine exhaust and the methanol synthesis inlet, and contingency. Reduction or elimination of system component costs is crucial to minimizing system production expenditures and achieving “reverse economies of scale” (Dahlgren, Göçmen, Lackner, & van Ryzin, 2013). The air separation unit is one such component. While pure oxygen as the reformation oxidizer achieves optimal combustion and conversion, it requires the use of an expensive ASU. Vacuum-pressure swing adsorption12 ASUs are costly ($300,000-$400,000 (Adsorptech, 2013)), however eliminating the ASU introduces nitrogen as an inert

12 A VPSA (vacuum pressure swing adsorption), as opposed to a PSA (pressure swing adsorption) air separation unit is chosen in the interest of reducing net power requirements, and thus operational costs of the overall system. Although initial costs of VPSAs are higher due to their more recent introduction as a developed technology, they have a more simple design and work at a lower pressure than PSA units, reducing the cost of energy required to operate. Additionally, VPSA units are typically the technology of choice in chemical and refining plants.

66 throughout the process. Not only does the inert typically break down methanol catalysts ad reduce lifetime, but it significantly decreases overall system conversion due to the inability to integrate high recycle in the methanol synthesis process. Methanol conversion decreases by 50% without the ASU (Bromberg, et al., 2014). The effects of the additional cost of the ASU included in the GTL system production cost must be compared to the decrease in both throughput and revenue seen by the end user, the E&P company, if the component is eliminated.

The system’s syngas compression requirement is also under examination in this study. The methane gas feed inlet pressure from well head to the reformer is at high pressure, typically on the order of tens of bar (Murthy & Malik, 2015). Exhaust from the engine reformer cylinder can be much higher by altering the valve timing. However there are limitations in the engine’s in-cylinder peak pressure allowance and there are tradeoffs between opening the exhaust valve early to achieve higher exhaust pressures and overall reaction conversion. Opening the valve early reduces the amount of time available for combustion and partial oxidation to take place. It has been proposed to use the engine’s produced mechanical work, or brake power, to operate the ASU. Bromberg et al. observe that the engine brake power and the air separation unit power requirement ratio is independent of syngas productivity. The authors find that the production of high-pressure syngas (30 bar, required for methanol synthesis) by opening the exhaust valves early still produces sufficient power (40kw/L); twice that required to drive the ASU (Bromberg, et al., 2014).

Alternatively, it may be possible to reroute the exhaust from the engine cylinder to another engine cylinder, which acts solely as a compressor to boost the syngas up to appropriate pressures. This addresses the theory of utilizing inexpensive and mass- manufactured engines at small scale to perform operations that would otherwise require large expensive components and high throughput capacity to be economical, which is the central argument for performing partial oxidation in an internal combustion engine instead of in conventional methane reformation reactors

67 (Bromberg, Green, Sappok, Cohn, & Jalan, 2014), (Dahlgren, Göçmen, Lackner, & van Ryzin, 2013).

Optimal pressure for the methanol synthesis reaction is dependent on the catalyst used. The most widely used is a copper, zinc oxide, and alumina mixture and typically operates between 50 and 100 bar. In partnership with MIT, RTI is developing a methanol synthesis catalyst that can operate at 30 bar to pair with the MIT engine reformer. The baseline scenario for this analysis conservatively assumes additional compression is required between engine reformer block and the methanol synthesis process. The effects of adding or removing syngas compressors are addressed in the results and discussion sections.

Contingency is included to account for unforeseen costs that might occur during the manufacturing process. For the economic evaluation of similar small- and medium- scale GTL systems at flared and stranded natural gas locations, contingency is set to 5% of the total capital expenditures (Vedhara, 2015). However, this analysis assumes a 20% contingency addition to the bare equipment costs and quotes.

4.2.4 Downstream End User Cash Flow Analysis To determine a system user’s return on investment period, a discounted cash flow analysis is developed based on Eq. – 13 and Eq. – 14, where Ct is the net cash flow during the period, r is the discount rate, and t is the number of periods, in years, to calculate the net present value (NPV) of the E&P company’s yearly system investments, future costs, and revenues. (Eq. – 13)

�! = ���� − ������� (Eq. – 14) ! � ��� = ! 1 + � ! !!!

68 This method uses future cash flow projections and discounts to represent the current valuation of investments. It can be used to determine attractiveness of investment opportunities. Typically, initial investments tend to dominate in the first few years of a project. The rate at which the future revenues make up that initial investment and the recurring costs is the internal rate of return, IRR. This analysis assumes a 20% IRR, which is generally an attractive IRR when selecting investment projects from a firm’s perspective. Corporate income taxes are included in the analysis to demonstrate that governments levy a firm’s profits, applied to operating earnings, with different rates for different levels of profit. This study incorporates a 40% corporate income tax for the US and 30% for India (KPMG, 2014). The tax is applied to the cash flow (Eq. – 13) for each period in the NPV analysis. Table 6 summarizes the microeconomic assumption for this analysis.

4.2.5 Downstream Costs The downstream E&P company assumes the total cost of the system over the investment period. This is its yearly lease. The yearly lease is calculated according to Eq. – 15, where YL is the E&P company’s yearly lease established by contract between the upstream manufacturer and the E&P company, CTotal is the total system plant cost incurred by the upstream manufacturer, and T is the return on investment period (the number of years it would take the E&P company to have an NPV equal to zero, thus paying off their investments. Any cash flow after that payback period is additional profit.). Once calculated, the yearly lease is included as a cost in the E&P company’s cash flow model. (Eq. – 15) � �� = !"#$% �

The E&P company also assumes the end product transport costs. For this analysis, the company is assumed to be operating in one of three scenarios: (1) E&P company produces DME as its sole end product for diesel replacement either on-site use, such as running pumps and generators or fueling on-site trucks (note: no methanol

69 demand on-site). In this scenario, there is no product transport cost, or for local diesel replacement; (2) E&P company produces DME as its sole end product, which replaces or supplements LPG use in the immediate surrounding area. (Further analysis could determine the optimal or most economically efficient balance between substituting diesel and LPG in each location). The US “local” market is defined by the demand for LPG and diesel in the state of North Dakota, while the local market for India is defined as the consumption for the northeastern state of Assam. The DME is brought by truck to local distribution facilities. For the US case in North Dakota, a conservative assumption is used: that the product transport distance would be no more than the entire width of the state, 500km. For the India case, the local market is defined as the population for the northeastern state of Assam, which would be within a 200km radius (Shah, Bhatia, & Chugh, 2015); (3) Domestic and global demand is assumed to be solely for methanol because it is the feedstock to many other chemicals, including synthetic gasoline, formaldehyde, plastics, and paints, and can be sold at a higher price than DME (higher value product means higher revenues for the E&P company, so a more economical product to sell). If DME were demanded domestically or globally, the market would determine the efficient quantity to produce from methanol at the central facilities, which may be more or less than could be produced at the individual GTL plant. Thus, the realistic product for the domestic and global markets would be methanol, not DME. Based on consulting reports for the North Dakota oil and gas sector, products from wells must be transported roughly 300 km to reach local distribution hubs (Couture & Auers, 2013). Interviews with Indian oil and gas companies state that products from Assam would have to be transported roughly 1,000 km to the nearest hub in Kolkata (Shah, Bhatia, & Chugh, 2015). Table 6 summarizes the costs and transport distances associated with each scenario. The EPA has calculated the methanol transport cost in this capacity range is $0.01/MT/km, which is used in this study as well. The annual product transport cost is calculated by multiplying the cost per unit energy per km by the production capacity and by the distance the product is shipped for each scenario.

70 4.2.6 Downstream Revenues The E&P company’s revenue is determined by multiplying it’s production capacity by either the “cost avoided” when using DME instead of LPG or diesel in the on-site and local scenarios, or by the Methanex-reported methanol market price at which the E&P company can sell the product in its region of the world. For on-site use of DME, 20-80 gal/day of diesel is used per well during the first year of drilling and production. With 10-20 wells per pad, the opportunity is to replace up to 1,600 gal/day of diesel, which retails at $2.82/gallon (U.S. Energy Information Administration, 2015). In India, the wells are conventional well, not shale deposits. Horizontal drilling technology is not utilized for this type of deposit, and thus it is assumed that there is one well per pad. The potential on-site diesel replacement in India is assumed to be 80 gal/day. LPG use in North Dakota is reported to be 113,00 gallons of diesel equivalent per day, with a price of $2.20/gallon diesel equivalent ($1.43/gallon of LPG (U.S. Energy Information Administration, 2015)). Diesel use in North Dakota is reported at 26,000 million gallons per day (U.S. Energy Information Administration, 2013), with a price of $2.82/gallon, as stated above (U.S. Energy Information Administration, 2015). LPG consumption in Assam reaches 300,000 gallons of diesel equivalent per day, at an unsubsidized price of $2.36/gallon diesel equivalent, and subsidized price of $1.47/gallon diesel equivalent (Petrol Diesel Price, 2014)13. (This analysis uses the unsubsidized price of LPG because the government of India limits the quantity of subsidized LPG that households are allotted. Further, the government has been pressured by budgetary constraints to decrease this allowance. Many households consume more LPG than they can purchase at the government-subsidized level, and must pay the full price for additional fuel anyway.) Diesel consumption in Assam is 140,000 gallons per day at a price of $3.09/gallon (Petrol Diesel Price, 2014). Domestic consumption of methanol in the US is at 10 million MT per year, at a price of $416/MT (April 2015), while India consumes 1.4 million MT per year of methanol (60-70% of which is currently imported), at the Asian posted contract price of $365/MT (April, 2015)

13 Price per kg for the 14.2L cylinders. Price per kg for 5-kg size is around Rs70/kg

71 (Methanex, 2015). Global consumption is at 60 million MT, 50% of which is consumed by China, at the Asian posted contract price noted above.

72 US India Economic Assumptions Natural Gas Price $0/MMBtu $2/MMBtu Manufacturing Costs 30% less than in US Product shipment cost $0.01/MT/km $0.01/MT/km LPG Price (unsubsidized) $2.20/gal. diesel equiv. $2.36/gal. diesel equiv. Diesel Price (unsubsidized) $2.82/gal. $3.09/gal. Methanol Price $416/MT $365/MT Corporate Income Tax 30% 40% Internal Rate of Return (IRR) 20% Product Transport Distance On-site use (DME) 0 0 Local use (DME) 200 km 200 km Domestic/global use 300 km*14 1,000 km*15 (Methanol) Product Substitution On-site use (DME) Diesel: 1,600 gal/day Diesel: 80 gal/day Local use (DME) LPG: 113,000 gal diesel LPG: 300,000 gal diesel eq./day eq./day Diesel: 26,000 gal/day Diesel: 140,000 gal/day Domestic (Methanol) 10M MT/yr. 1.4M MT/yr. Global (Methanol) 60M MT/yr. Table 6: Differences in Assumptions for US vs. India

*To closest central hub

4.2.7 Fixed Capacity Approach The Fixed Capacity Approach to determine the E&P company’s payback period is used for the US scenario because detailed data on of gas flare rates and frequency of these sites exists. The capacity is set to 330,000 scfpd, to target oil pads in North Dakota that contain 10 wells. A sensitivity analysis is run to determine how different system design parameters effect the overall payback period. The variables of interest include the tradeoff between increased throughput and capital costs with the addition of an ASU versus elimination of the ASU, which severely reduces system conversion efficiencies; reduction of compression requirements through precision engine valve timing; and ability to integrate mechanical power produced by the

14 (Couture & Auers, 2013) 15 (Shah, Bhatia, & Chugh, 2015)

73 engine to reduce net power and compression requirements. Table 7 in Chapter 5: Results & Analysis, summarizes the sensitivity analysis matrix. Because there are roughly 10-20 oil wells on a given oil field or pad, this analysis also considers capacities of 660,000 scfpd. To understand economic implications of future applications for the engine-based GTL system, such as for larger oil or gas deposit in the US, 1 MMscfpd, 3 MMscfpd and 6 MMscfpd are studied.

4.2.8 Fixed Payback Period Approach The Fixed Payback Period Approach is applied to India because data in specific wells and opportunities is incomplete. The motivating question for this approach is in determining the minimum efficient scale of this system (i.e. the smallest capacity in the given scenario required to achieve the desired payback period). This question is more relevant to Indian stranded gas than associated gas at oil sites in the US because stranded gas sites are specifically natural gas deposits, not gas associated that is with deposits consisting predominantly of oil. The stranded gas fields are much larger capacity (see Figure 15). However, the same Fixed Payback Period Approach can be applied to the US or other locations of stranded gas (given the appropriate location-specific assumptions) to determine the economical minimum efficient capacities required for those opportunities. In this approach, the economic assumption for India’s stranded or marginal fields, summarized in Table 6, are applied to the most economical system identified in the Fixed Capacity Approach analysis. The capacity is increased in the model until the NPV for the set payback period reaches zero, thus simulating that the E&P company has paid off its investments in the desired amount of time. For completeness, and to understand further applications of the US-based GTL system, the fixed payback period approach is applied to the base case system (includes gas compressor and ASU). A 2-year payback period is the target period and the minimum quantity of methane required to achieve an NPV of 0 during that period is determined.

74 5. RESULTS & ANALYSIS 5.1 United States

Table 7 summarizes the Fixed Capacity approach parameters for the North Dakota scenario and the payback period in years for each of the given end product replacement scenarios (on-site, local and domestic/global markets). The top line in each cell is the payback period and the second number is the NPV at the end of that period. The second line is the NPV of the plant at the end of the first year.

5.1.1 Base Case: Fixed Capacity Approach The base case utilizes methane at 330,000 scfpd, an ASU, and gas compressors to produce 1,836 gal. diesel eq./day (gdepd) of DME. The payback period is greater than 10 years for on-site DME replacement of diesel (for this analysis a payback period over 10 years will be considered an infinite payback period because the GTL system would not be producing at one location for that long). Local use of DME to replace diesel gives a 3-year payback period with an NPV of $347,000 at the end of that period, while local use for LPG replacement has a 4-year payback period, with an NPV of $200,000 at the end of that period. It should be noted that the local use assumption includes the option to use the amount of the DME required to replace diesel on-site (800 gal./day per pad - much less than the amount of DME produced) and sell the rest. The on-site-only modeled scenario describes a scenario in which the amount of diesel used on-site is all replaced by DME and the remaining DME that is produced is not sold or used in any way. This would never be a realistic situation. A producer would sell the remaining DME on the local market. This is all captured in the local-use scenario. Thus, the infinite payback period for all on-site scenarios is trivial. The sale of methanol on the domestic and/or global market also has a 4-year payback period with an NPV of $224,153 at the end of that period. The target payback period deemed economically viable is 2 years. While the base case assumptions are approaching economic viability for the local, domestic and global

75 scenarios, improvements in the system design may have significant economic impacts.

Reducing capital costs by eliminating the ASU is one such possible design improvement, however it sacrifices overall system performance and efficiency. Table 7 shows the effect of eliminating the ASU, which causes the throughput to drop 50%. The payback period and NPV are 7 years at $95,588; 12 years at $1,800; and 12 years at $27,729 for domestic diesel replacement, local LPG replacement, and domestic or global methanol sales, respectively. The results of eliminating the ASU show that the benefit of reducing capital costs is sharply contrasted by the reduction in throughout. The ASU should be retained in the overall GTL system.

An opportunity to reduce compression requirements and drive down capital costs is through the production of high-pressure syngas directly from the engine via early exhaust valve timing, as discussed in Chapter 4: Methodology. This does, in fact improve the economic viability over the base case system. Local use for diesel replacement gives a 2-year payback period with NPV of $373,489; local use for LPG replacement has a 3-year payback period with NPV of $437,764; and domestic or global methanol sales have a 2-year payback period with an NPV of $7,008. It can be concluded from this analysis that in the given scenarios for North Dakota, 330,000 scfpd methane feedstock would require a system configuration with an ASU and with compression integration for economic viability.

76

System Base Case No ASU Engine as Specification Value Compressor (w/ ASU) Well gas flow 0.33 MMscfpd 0.33 MMscfpd 0.33 MMscfpd Engine 8 L 8 L 8 L Displacement Number of Engines 1 1 1 Production 12.2 TPD 6.1 TPD 12.2 TPD Methanol or Methanol or Methanol or 8.5 TPD DME 4.3 TPD DME 8.5 TPD DME (1,836 gal (918 gal diesel (1,836 gal diesel eq./day) diesel eq./day) eq./day) Upstream Engine Cost $22,000 $22,000 $22,000 Misc. equipment, $1,595,300 $1,595,300 $1,595,300 methanol reactor, etc. Syngas Compressor $900,000 $900,000 - Air Separation Unit $300,000 - $300,000 Downstream Natural Gas Cost $0/MMBtu $0/MMBtu $0/MMBtu Annual O&M $515,774 $463,346 $358,489 Annual Product $35/km $18/km $35/km Transport Cost Payback Period, NPV On-Site (replace Inf. Inf. Inf. diesel) 1, -$1.7M 1, -$1.4M 1, -$778,842 Local (replace 3, $360,000 7, $95,588 2, $373,489 diesel) 1, -$1.5M 1, -$2M 1, -$582,000 Local (replace LPG) 4, $216,000 12, $1,800 3, $437,764 1, -$1.9M 1, -$2.2M 1, -$928,518 Domestic /Global 4, $224,153 12, $27,729 2, $7,008 Methanol 1, -$1.9M 1, -$2.7M 1, -$915,423 Table 7: North Dakota - Fixed Capacity Approach Results

77 5.1.2 United States: Fixed Payback Period Approach To understand further applications of the US-based GTL system, the fixed payback period approach is applied to the base case system (includes gas compressor and ASU). A 2-year payback period is set for the local diesel replacement, for local LPG replacement, and for domestic or global methanol sale, and the minimum quantity of methane required to reach an NPV of 0 during that period is determined. For local diesel replacement, a payback period of 2 years would be achieved at 400,000 scfpd, with an NPV of $11,057 at the end of the second year; 600,000 scfpd for local LPG replacement with an NPV of $8,760; and 860,000 scfpd with NPV of $17,245 for the domestic or global methanol markets.

The economic returns of the engine-based GTL system at even larger capacities of 1,000,000 scfpd, 3,000,000 scfpd, and 6,000,000 scfpd are tested, with results in Table 8. These results are aligned with the previous cases – increasing capacity to flow rates above the base case scenario (while still considered too small to warrant conventional production technologies or infrastructure development) increases the NPV of the GTL project. This implies that the system could apply to small- to medium- scale gas deposits in the US and be economically profitable for the E&P company.

78

.

$11M

- 6 MMscf 145.45 L 18 222 TPD Methanol or 155.27 TPD DME (33,384 gdepd) $264,000 $9,022,000 $1,800,000 $400,000 $0/MMBtu $2,143,694 $648/km/yr Inf. 1, 1, $9.2M 1, $5.4M 1, $5.6M

.

$8.0M -

3 MMscf 72.73 L 9 111 TPD Methanol or 77.64 TPD DME (16,692 gdepd) $198,000 $5,952,896 $1,800,000 $400,000 $0/MMBtu $1,536,345 $324/km/yr Inf. 1, 1, $2.9M 1, $1.0M 1, $1.1M

.

$4.6M $1.2M $2.2M $2.2M - - - -

1 MMscf 24.24L 3 37 TPD Methanol or 25.88 TPD DME (5,564 gdepd) $66,000 $3,079,325 $1,800,000 $400,000 $0/MMBtu $977,271 $108/km/yr Inf. 1, 2, $1.5M 1, 2, $351,110 1, 2, $394,762 1,

.

L $2.4M -

0.86 MMscfpd 20.85 3 31.8 TPD Methanol or 22.26 TPD DME (4,785 gdepd) $66,000 $2,812,902 $1,800,000 $400,000 $0/MMBtu $925,966 $93/km/yr - - - 2, $17,245 1,

.

Fixed Payback Period Approach & Capacity Sensitivity Analysis Results

- $1.7M -

0.60 MMscfpd 14.55 L 2 22.2 TPD Methanol or 15.53 TPD DME (3,338 gdepd) $44,000 $2,266,450 $900,000 $300,000 $0/MMBtu $646,291 $65/km/yr - - 2, $8,760 1, - Dakota

: North

8 .

Table

$1.4M -

0.40 MMscfpd 9.7 L 1 14.8 TPD Methanol or 10.35 TPD DME (2,226 gdepd) $22,000 $1,777,016 $900,000 $300,000 $0/MMBtu $552,707 $43/km/yr - 2, $11,057 1, - -

flow

Site - System Spec. Well gas Engine Displ. No. Engines Production Upstream Engine Cost Misc. equip. Syngas Comp. ASU Downstream Nat. Gas Cost Annual O&M Product Transport Payback Per. On (diesel) Local (replace diesel) Local (replace LPG) Dom./Global Methanol

79 5.2 India: Fixed Payback Period Approach

Table 9 summarizes the parameters and results for the India cases and each scenario. A throughput of 330,000 scfpd of methane to produce 8.5 TPD of DME or 12.2 TPD of methanol is run as a baseline. This system is identical to the US base case (includes an ASU and gas compressors) but with India-specific parameters, summarized in Table 6.

The payback period is then set to 2 years and the throughput is increased to determine the capacity at which the NPV becomes positive. This happens simultaneously for local use to replace diesel, for local LPG replacement, and for domestic or global sale of methanol, when the throughput capacity reaches 810,000 scfpd, which produces 29.9 TPD Methanol or 4,507 gal diesel eq./day of DME. Figure 15 shows the range of marginal or stranded gas field reserves. Assuming these fields produce for 10 years, a reasonable approximation for predicted gas flow rate from these fields would produce 400,000-6,000,000 scfpd. In fact, the Kharsang field in Arunachal Pradesh, considered to be a medium-sized field, was reported to produce 1.6 million scfpd (Ministry of Petroleum and Natural Gas, 2014).

It is therefore feasible that the India-based system could be implemented with a minimum efficient scale of 810,000 scfpd. At this scale, the local replacement of diesel has a payback period of 2 years with an NPV of $2.1M, local replacement of LPG has an NPV of $826,363 at the end of the second period, and the sale of methanol to the domestic or global market has an NPV of $15,315 at the end of the second year.

The capacity is increased further to study the economic returns. Flow rates of 1,000,000 scfpd, 3,000,000 scfpd, and 6,000,000 scfpd are examined, with results summarized in Table 9. Unsurprisingly, the increased capacity improves the economics. This implies that the marginal fields in India at the upper end of the capacity range are also economical.

80

.

$11.9M

- $13.5M

6 MMscf 145.45 L 18 222 TPD Methanol or 155.27 TPD DME (33,384 gdepd) $264,000 $9,022,000 $1,800,000 $400,000 $2/MMBtu $1,501,988 $648/km/yr Inf. 1, 1, 1, $8.3M 1, $5.0M

.

$7.9M -

3 MMscf 72.73 L 9 111 TPD Methanol or 77.64 TPD DME (16,692 gdepd) $198,000 $5,952,896 $1,800,000 $400,000 $2/MMBtu $1,076,844 $324/km/yr Inf. 1, 1, $5.4M 1, $2.8M 1, $1.1M

.

$4.5M $644,726 $1.4M - $413495 - -

1 MMscf 24.24L 3 37 TPD Methanol or 25.88 TPD DME (5,564 gdepd) $66,000 $3,079,325 $1,800,000 $400,000 $2/MMBtu $685,493 $108/km/yr Inf. 1, 1, 2, $1.5M 1, 2, $457,235 1,

Capacity Sensitivity (w/ syngas Comp and ASU)

3 .

TPD DME Fixed Payback Period Approach & Capacity Analysis

- gdepd)

L TPD Methanol

00,000

$4.2M $7,374 $1.0M $1.6M 713,604 20.96 - - $826,36 - $15,315 - 4,000 00,000

4,507 0.81 MMscf 19.64 2 29.9 or ( $5 $2, $1,8 $4 $2/MMBtu $636,211 $87/km/yr Inf. 1, 2, $2.1M 1, 2, 1, 2, 1, : India 9

Table

.

TPD DME

TPD Methanol 6 gdepd)

$2.2M $610,000 $1.0M $1.3M

8.5 - - - $250,842 - /MMBtu L

2 1.83 Base Case (w/ syngas Comp and ASU) 0.33 MMscfpd 8 1 12.2 or ( $22,000 $1,777,016 $900,000 $300,000 $ $362,444 $35/km/yr Inf. 1, 2, $414,543 1, 3, $380,000 1, 4, 1,

.

Site - System Spec. Well gas flow Engine Disp. No. Engines Production Upstream Engine Cost Misc. equip Syngas Comp. ASU Downstream Nat. Gas Cost Annual O&M Product Transport Payback Per. On (diesel) Local (replace diesel) Local (replace LPG) Dom./Global Methanol

81 6. DISCUSSION & CONCLUSIONS

E&P companies with access to natural gas, whether it is flared or stranded, have a variety of opportunities to develop that resource. Gas may be compressed to produce CNG, liquefied to produce LNG (both processes which are energy and cost intensive, especially at small scale) or transported through a gas pipeline (which may not currently exist) to central facilities for processing. Among other limitations, these options vary in commercial readiness, capacity applicability, technical and economic uncertainties, and regulatory drivers. The most significant constraint is infrastructure development costs. This study has addressed limiting factors for an engine reformer-based GTL system, a new technology in development at MIT.

This system model analysis shows that the engine reformer-based GTL system is economically favorable in a variety of scenarios. Design specifications do not require the elimination of the ASU and in fact, the analysis shows that the ASU is required to achieve the conversion efficiencies. Further, the use of a VPSA ASU, though may incur a higher capital cost than an alternative PSA ASU option, has lower water, power, and compression requirements, which are advantageous characteristics for use in this GTL system. It has also been proposed that in order to further reduce capital costs, the elimination or reduction in costs of large and expensive gas compressors may be required and possible if the integrated system can utilize the engine to either compress the syngas or to exhaust at high pressures. The results show that regardless of the technical feasibility of this proposition, it is not required for the system to be economical. The total capital costs of the system have been reduced sufficiently by using mass-manufactured engines rather than costly reactors, so that the economic feasibility is not sensitive to the individual component costs. However, the bulk cost considered for the aggregate of non- critical miscellaneous equipment from the Aspen APEA results in this analysis could have a significant impact on overall economic feasibility. Thus, specific vendor quotes for each non-critical component, such as those obtained for critical system components, would reduce the uncertainty for improved model’s accuracy.

82

While individual component costs do not prove to be deterministic for a reasonable payback period, the results are highly sensitive to the specific economic assumptions. Throughput capacity or well gas flow rate is one of the most significant factors. The analysis shows that below 400,000 scfpd in the US, the payback period for any of the market scenarios is greater than 2 years. However, at 860,000 scfpd, the 2-year payback period is achieved for all three non-trivial scenarios (local DME use to replace diesel, local DME use to replace LPG, and domestic or global sale to methanol markets). Under the conditions in India, the base case capacity of 330,000 scfpd only achieves the 2-year payback period for the local diesel replacement scenario. The minimum efficient capacity for all three scenarios to achieve a 2-year payback period is reached at 810,000 scfpd. While India has a higher cost of natural gas than the US and lower price for methanol, the lower manufacturing costs and the higher prices of diesel and LPG (representative of opportunity costs) balance out the increased feedstock costs and decreased product revenues.

The price of end product sold, or the cost avoided by replacing an existing fuel, also impacts economic outcomes. The scenarios characterizing local use of DME to replace diesel versus local use to replace LPG are identical apart from the price of the two fuels (diesel is priced at $2.82/gal. and $3.09/gal in the North Dakota and Assam, respectively; and LPG is priced at $2.20/gal. diesel equiv. and $2.36/gal. diesel equiv. in North Dakota and Assam, respectively). Due to this price differential, to reach a 2-year payback period by replacing diesel, a flow rate of 400,000 scfpd is required in the US and a flow rate of 330,000 scfpd is required in India. The same flow rates only achieve a positive NPV for LPG in the third year. A 2-year payback period with LPG replacement requires 600,000 scfpd in North Dakota and 810,000 scfpd in Assam.

While this analysis shows significant potential for the proposed GTL system from the upstream E&P company’s supply side, the fact remains that DME is not an existing fuel option in either the United States or India. Specific policies,

83 infrastructure and vehicle fleets or household stoves and heaters are not currently in place for the immediate adoption of this particular system. Therefore, the most immediate application would be in the domestic or global methanol market, which is a reasonably economic option based on natural gas feedstock availability, implementation costs, industry capabilities, and methanol market opportunities studied in this analysis.

84 7. FUTURE WORK

Further developments in the engine reformer experimentation to benchmark the chemical process modeling and in establishment of economic assumptions to be applied to specific oil or gas fields will further enhance this system model.

7.1 Industry Cooperation

The current model’s limitations are derived from the uncertainty of information about upstream oil and gas industry features. Unfortunately the industry can tend to be hard to penetrate from the academic perspective and E&P producers are hesitant to offer too much information or engage too closely with an outside entity before the technology option is farther along in development stages. While initial interviews with industry experts have informed the development of this model, feedback on the model and cooperation from incumbent E&P companies or governments to obtain detailed and site-specific information will be essential to improving the accuracy of the analysis. Such information might include precise costs incurred by E&P companies to extract the gas, or fines they must pay for flaring; composition of gas, which could affect GTL system pre-treatment requirements; on-site fuel consumption; access to utilities and on-site power requirements; and improved estimates of distances to nearest fuel distribution hubs. Data on variations in the well production rates based on age, size, location, and implemented infrastructure will be necessary for more specified analysis. This information, along with more precise trends such as number of wells per pad, will aid in enhanced characterization of specific flare or stranded locations.

7.2 Alternative Product Options

The market for DME as a fuel in local applications is only budding. The methanol market is extensive due to its status as a commodity chemical. This still leaves communities close to the gas resource underserved. While the overall system considered in this analysis has been for the production of methanol and DME, the

85 MIT engine reformer produces syngas as the first step of the process. The ratio of hydrogen and carbon required for methanol synthesis is 2:1, however syngas of different ratios is the feedstock for countless other products.

In India, one of the government’s indicated highest priority products from natural gas is urea for fertilizer to serve their extensive agriculture industry. Urea is produced from syngas with a H2:CO ratio of 3:1. Alterations in the Aspen Plus model and application of urea and fertilizer industry specific technical and economic specifications can produce a model to analyze the economic feasibility for this alternative highly demanded product.

Fischer-Tropsch (FT) synthesis is a commercially established method that utilizes syngas at an H2:CO ratio of 1.8-2.1 to produce liquid fuels such as gasoline and diesel, among a variety of other products16. Several companies are attempting to commercialize systems for the flared gas scenarios addressed in this study. As the current local demand for FT fuel products is more immediate than local demand for DME, extension of this analysis to include FT processes as they develop could prove to be an intermediate step before widespread DME use is established.

7.3 Implementation Locations

The model has been created to examine two considerably different locations, the Bakken Oil Play in the American Midwest, and the Assam Basin in Northeastern India. Future analysis should include modifications of the model’s location-specific variables that apply to other sites. Africa holds substantial oil and natural gas deposits in certain areas while hundreds of millions of people still lack basic access to energy. While large-scale LNG plants are ideal for some scenarios, flared gas at Nigerian oil fields, smaller-scale gas fields, and flared natural gas during the large LNG terminal build-up process could demand smaller, on-site solutions that are

16 This technology is currently only commercially available from medium- to very large-scale; larger than the capacity of gas sources considered by this analysis.

86 more flexible in capacity and roll-out time than conventional technologies offer. China is another area for potential application. With its large coal supply comes associated coal bed methane. Moreover, China is the leader in DME implementation for transportation, cooking and heating. The country has distributed DME blended with LPG for domestic use and for heavy-duty vehicles. Like China, Australia has sizeable coal deposits and opportunity for the utilization of coal bed methane. Australia also has extensive LPG storage and distribution infrastructure as a transportation fuel, which could be used for DME distribution as well reducing the barrier to entry for DME as a transportation fuel.

The system model established in this study should be considered a tool. It can be modified to analyze numerous locations and desired products for the engine reformer and is a working instrument to demonstrate the integrated relationship between variations in the system’s technical and economic features.

87 REFERENCES

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93 APPENDIX A: Aspen Plus Stream Results A.1 ASU Block Aspen Stream Results

AIR (IN) NITROGEN OXY2ENG LPOXYGEN LPOXYGEN HPOXYGEN (OUT) (OUT) Mole Flow kmol/hr H2 0 0 0 0 0 0 CO 0 0 0 0 0 0 CO2 0 0 0 0 0 0 N2 67.8452 66.4883 1.356904 1.356904 1.356904 1.356904 H2O 0 0 0 0 0 0 O2 18.0348 0 18.0348 18.0348 18.0348 18.0348 AR 0 0 0 0 0 0 H2S 0 0 0 0 0 0 C2 0 0 0 0 0 0 C3 0 0 0 0 0 0 C4 0 0 0 0 0 0 C2H4 0 0 0 0 0 0 C2H2 0 0 0 0 0 0 C 0 0 0 0 0 0 METHA-01 0 0 0 0 0 0 N-BUT-01 0 0 0 0 0 0 ISOBU-01 0 0 0 0 0 0 METHA-02 0 0 0 0 0 0 Mole Frac H2 0 0 0 0 0 0 CO 0 0 0 0 0 0 CO2 0 0 0 0 0 0 N2 0.79 1 0.069973 0.0699734 0.0699734 0.0699734 H2O 0 0 0 0 0 0 O2 0.21 0 0.930026 0.9300266 0.9300266 0.9300266 AR 0 0 0 0 0 0 H2S 0 0 0 0 0 0 C2 0 0 0 0 0 0 C3 0 0 0 0 0 0 C4 0 0 0 0 0 0 C2H4 0 0 0 0 0 0 C2H2 0 0 0 0 0 0 C 0 0 0 0 0 0 METHA-01 0 0 0 0 0 0 N-BUT-01 0 0 0 0 0 0 ISOBU-01 0 0 0 0 0 0 METHA-02 0 0 0 0 0 0

94 A.1 ASU Block Aspen Stream Results (cont.)

AIR (IN) NITROGEN OXY2ENG LPOXYGEN LPOXYGEN HPOXYGEN (OUT) (OUT) Mass Flow kg/hr H2 0 0 0 0 0 0 CO 0 0 0 0 0 0 CO2 0 0 0 0 0 0 N2 1900.58 1862.569 38.0116 38.0116 38.0116 38.0116 H2O 0 0 0 0 0 0 O2 577.092 0 577.092 577.092 577.092 577.092 AR 0 0 0 0 0 0 H2S 0 0 0 0 0 0 C2 0 0 0 0 0 0 C3 0 0 0 0 0 0 C4 0 0 0 0 0 0 C2H4 0 0 0 0 0 0 C2H2 0 0 0 0 0 0 C 0 0 0 0 0 0 METHA-01 0 0 0 0 0 0 N-BUT-01 0 0 0 0 0 0 ISOBU-01 0 0 0 0 0 0 METHA-02 0 0 0 0 0 0 Total Flow 85.88 66.4883 19.3917 19.3917 19.3917 19.3917 kmol/hr Total Flow kg/hr 2477.67 1862.569 615.1036 615.1036 615.1036 615.1036 Total Flow 2135.55 1653.532 1114.152 1628.868 1628.868 752.0808 cum/hr Temperature C 30 30 426.85 30 30 199.4248 Pressure bar 1.01325 1.01325 1.01325 0.3 0.3 1.01325 Vapor Frac 1 1 1 1 1 1 Liquid Frac 0 0 0 0 0 0 Solid Frac 0 0 0 0 0 0 Enthalpy 0.13802 0.1382264 12.45933 0.1440798 0.1440798 5.22302 MJ/kmol Enthalpy MJ/kg 0.00478 0.0049342 0.392791 0.0045422 0.0045422 0.1646605 Enthalpy MW 0.00329 0.002552 0.067113 0.0007760 0.0007760 0.0281342 Entropy J/kmol- 4735.41 461.9141 28350.64 12709.04 12709.04 15876.81 K Entropy J/kg-K 164.136 16.48899 893.7799 400.6642 400.6642 500.5309 Density 0.04021 0.0402098 0.017404 0.011905 0.011905 0.025784 kmol/cum Density kg/cum 1.16020 1.126418 0.552082 0.3776264 0.3776264 0.8178689 Average MW 28.8504 28.01348 31.71993 31.71993 31.71993 31.71993 Liq Vol 60F 4.59954 3.560967 1.038577 1.038577 1.038577 1.038577 cum/hr

95 A.2 Natural Gas Prep Block Aspen Stream Results

NATGAS (IN) NGAS2ENG HPNATGAS (OUT) Mole Flow kmol/hr H2 0 0 0 CO 0 0 0 CO2 0 0 0 N2 0 0 0 H2O 0 0 0 O2 0 0 0 AR 0 0 0 H2S 0 0 0 C2 0 0 0 C3 0 0 0 C4 0 0 0 C2H4 0 0 0 C2H2 0 0 0 C 0 0 0 METHA-01 0 0 0 N-BUT-01 0 0 0 ISOBU-01 0 0 0 METHA-02 30.6 30.6 30.6 Mole Frac H2 0 0 0 CO 0 0 0 CO2 0 0 0 N2 0 0 0 H2O 0 0 0 O2 0 0 0 AR 0 0 0 H2S 0 0 0 C2 0 0 0 C3 0 0 0 C4 0 0 0 C2H4 0 0 0 C2H2 0 0 0 C 0 0 0 METHA-01 0 0 0 N-BUT-01 0 0 0 ISOBU-01 0 0 0 METHA-02 1 1 1

96 A.2 Natural Gas Prep Block Aspen Stream Results (cont.)

NATGAS (IN) NGAS2ENG HPNATGAS (OUT) Mass Flow kg/hr H2 0 0 0 CO 0 0 0 CO2 0 0 0 N2 0 0 0 H2O 0 0 0 O2 0 0 0 AR 0 0 0 H2S 0 0 0 C2 0 0 0 C3 0 0 0 C4 0 0 0 C2H4 0 0 0 C2H2 0 0 0 C 0 0 0 METHA-01 0 0 0 N-BUT-01 0 0 0 ISOBU-01 0 0 0 METHA-02 490.9085 490.9085 490.9085 Total Flow kmol/hr 30.6 30.6 30.6 Total Flow kg/hr 490.9085 490.9085 490.9085 Total Flow cum/hr 759.632 1600.193 712.476 Temperature C 30 426.85 39.23295 Pressure bar 1.01325 1.11325 1.11325 Vapor Frac 1 1 1 Liquid Frac 0 0 0 Solid Frac 0 0 0 Enthalpy MJ/kmol -74.71291 -56.07913 -74.38048 Enthalpy MJ/kg -4.657111 -3.495604 -4.636389 Enthalpy MW -0.6350597 -0.4766726 -0.6322341 Entropy J/kmol-K -80140.96 -42894.6 -79841.77 Entropy J/kg-K -4995.459 -2673.767 -4976.81 Density kmol/cum 0.0402826 0.0191226 0.0429488 Density kg/cum 0.6462451 0.3067807 0.6890176 Average MW 16.04276 16.04276 16.04276 Liq Vol 60F cum/hr 1.638869 1.638869 1.638869 QVALNET MJ/kg 50.03004 50.03004 50.03004

97 A.3 Engine Reformer Block Aspen Stream Results

NGAS2ENG OXY2ENG EXHAUST FROMEXP FROMEXP TOCOMP XHSTRECY (IN) (IN) (OUT) 1 2 Mole Flow kmol/hr H2 0 0 56.54621 44.49849 66.52496 9.97877 9.978744 CO 0 0 29.67409 4.530911 34.91069 5.23660 5.236604 5 CO2 0 0 0.898430 18.33514 1.056977 0.15854 0.1585465 N2 0 1.356904 1.356904 1.596358 1.596358 1.59635 0.2394536 H2O 0 0 4.598847 1.233634 5.410408 0.81156 0.8115612 O2 0 18.0348 0 1.78E-05 0 18.0348 0 AR 0 0 0 0 0 0 0 H2S 0 0 0 0 0 0 0 C2 0 0 0 0 0 0 0 C3 0 0 0 0 0 0 0 C4 0 0 0 0 0 0 0 C2H4 0 0 0 0 0 0 0 C2H2 0 0 0 0 0 0 0 C 0 0 0 0 0 0 0 METHA-01 0 0 0 0 0 0 0 N-BUT-01 0 0 0 0 0 0 0 ISOBU-01 0 0 0 0 0 0 0 METHA-02 30.6 0 0.027482 13.13395 0.032332 30.6048 0.0048499 Mole Frac H2 0 0 0.607357 0.5340129 0.607357 0.15023 0.6073579 CO 0 0 0.318726 0.054374 0.318726 0.07883 0.3187268 CO2 0 0 0.009649 0.2200344 0.009649 0.00238 0.0096499 N2 0 0.069973 0.014574 0.0191574 0.014574 0.02403 0.0145743 H2O 0 0 0.049395 0.0148044 0.049395 0.01221 0.0493958 O2 0 0.930026 0 2.13E-07 0 0.27152 0 AR 0 0 0 0 0 0 0 H2S 0 0 0 0 0 0 0 C2 0 0 0 0 0 0 0 C3 0 0 0 0 0 0 0 C4 0 0 0 0 0 0 0 C2H4 0 0 0 0 0 0 0 C2H2 0 0 0 0 0 0 0 C 0 0 0 0 0 0 0 METHA-01 0 0 0 0 0 0 0 N-BUT-01 0 0 0 0 0 0 0 ISOBU-01 0 0 0 0 0 0 0 METHA-02 1 0 0.000295 0.1576166 0.000295 0.46076 0.0002951

98 A.3 Engine Reformer Block Aspen Stream Results (cont.)

NGAS2ENG OXY2ENG EXHAUST FROMEXP FROMEXP TOCOMP XHSTRECY (IN) (IN) (OUT) 1 2 Mass Flow kg/hr H2 0 0 113.9904 89.70362 134.1063 20.116 20.11595 CO 0 0 831.1831 126.9126 977.8625 146.679 146.6794 CO2 0 0 39.53973 806.9258 46.51733 6.97761 6.977599 N2 0 38.0116 38.0116 44.71953 44.71953 44.7195 6.70793 H2O 0 0 82.84952 22.22427 97.47002 14.6204 14.6205 O2 0 577.092 0 0.0005684 0 577.092 0 AR 0 0 0 0 0 0 0 H2S 0 0 0 0 0 0 0 C2 0 0 0 0 0 0 0 C3 0 0 0 0 0 0 0 C4 0 0 0 0 0 0 0 C2H4 0 0 0 0 0 0 0 C2H2 0 0 0 0 0 0 0 C 0 0 0 0 0 0 0 METHA-01 0 0 0 0 0 0 0 N-BUT-01 0 0 0 0 0 0 0 ISOBU-01 0 0 0 0 0 0 0 METHA-02 490.9085 0 0.440900 210.7048 0.518706 490.986 0.0778059 Total Flow 30.6 19.3917 93.10197 83.3285 109.5317 66.4214 16.42976 kmol/hr Total Flow 490.9085 615.1036 1106.015 1301.191 1301.194 1301.19 195.1792 kg/hr Total Flow 1600.193 1114.152 3357.444 450.7839 3949.934 3900.65 592.4901 cum/hr Temp C 426.85 426.85 516.2168 2091.091 516.2168 442.333 516.2168 Pressure bar 1.11325 1.01325 1.820765 36.477 1.820765 1.01325 1.820765 Vapor Frac 1 1 1 1 1 1 1 Liq, Frac 0 0 0 0 0 0 0 Enthalpy -56.07913 12.45933 -36.2190 -16.03355 -36.21907 -31.156 -36.21907 MJ/kmol Enthalpy -0.476672 0.067113 -0.93668 - -1.101983 -0.57485 -0.165297 MW 0.3711256 Density 0.0191226 0.017404 0.02773 0.1848524 0.02773 0.01702 0.02773 kmol/cum Density 0.3067807 0.552082 0.329421 2.886508 0.329421 0.33358 0.3294218 kg/cum Average MW 16.04276 31.71993 11.87961 15.6152 11.87961 19.5899 11.87961 Liq Vol 1.638869 1.038577 4.823042 4.419088 5.674167 3.52857 0.851125 60Fcum/h QVALNET 50.03004 0 19.97606 17.35675 19.97606 21.8715 19.97606 MJ/kg

99 A.4 Cleaning Block Aspen Stream Results

EXHAUST (IN) TOCOMPR1 (OUT) TOSYNCOO Mole Flow kmol/hr H2 56.54621 56.54621 56.54621 CO 29.67409 29.67409 29.67409 CO2 0.8984301 0.8984301 0.8984301 N2 1.356904 1.356904 1.356904 H2O 4.598847 4.598847 4.598847 O2 0 0 0 AR 0 0 0 H2S 0 0 0 C2 0 0 0 C3 0 0 0 C4 0 0 0 C2H4 0 0 0 C2H2 0 0 0 C 0 0 0 METHA-01 0 0 0 N-BUT-01 0 0 0 ISOBU-01 0 0 0 METHA-02 0.0274828 0.0274828 0.0274828 Mole Frac H2 0.6073579 0.6073579 0.6073579 CO 0.3187268 0.3187268 0.3187268 CO2 0.00964996 0.00964996 0.00964996 N2 0.0145743 0.0145743 0.0145743 H2O 0.0493958 0.0493958 0.0493958 O2 0 0 0 AR 0 0 0 H2S 0 0 0 C2 0 0 0 C3 0 0 0 C4 0 0 0 C2H4 0 0 0 C2H2 0 0 0 C 0 0 0 METHA-01 0 0 0 N-BUT-01 0 0 0 ISOBU-01 0 0 0 METHA-02 0.00029519 0.00029519 0.00029519

100 A.4 Cleaning Block Aspen Stream Results (cont.)

EXHAUST (IN) TOCOMPR1 (OUT) TOSYNCOO Mass Flow kg/hr H2 113.9904 113.9904 113.9904 CO 831.1831 831.1831 831.1831 CO2 39.53973 39.53973 39.53973 N2 38.0116 38.0116 38.0116 H2O 82.84952 82.84952 82.84952 O2 0 0 0 AR 0 0 0 H2S 0 0 0 C2 0 0 0 C3 0 0 0 C4 0 0 0 C2H4 0 0 0 C2H2 0 0 0 C 0 0 0 METHA-01 0 0 0 N-BUT-01 0 0 0 ISOBU-01 0 0 0 METHA-02 0.4409001 0.4409001 0.4409001 Total Flow kmol/hr 93.10197 93.10197 93.10197 Total Flow kg/hr 1106.015 1106.015 1106.015 Total Flow cum/hr 3357.444 2392.189 2392.189 Temperature C 516.2168 40 40 Pressure bar 1.820765 1.01325 1.01325 Vapor Frac 1 1 1 Liquid Frac 0 0 0 Solid Frac 0 0 0 Enthalpy MJ/kmol -36.21907 -50.55938 -50.55938 Enthalpy MJ/kg -3.048843 -4.255979 -4.255979 Enthalpy MW -0.9366852 -1.307549 -1.307549 Entropy J/kmol-K 58253.78 36471.66 36471.66 Entropy J/kg-K 4903.677 3070.105 3070.105 Density kmol/cum 0.02773 0.0389191 0.0389191 Density kg/cum 0.3294218 0.4623443 0.4623443 Average MW 11.87961 11.87961 11.87961 Liq Vol 60F cum/hr 4.823042 4.823042 4.823042 QVALNET MJ/kg 19.97606 19.97606 19.97606

101 A.5 Compression Block Aspen Stream Results

TOCOMPR1 (IN) HPSYNGAS (OUT) Mole Flow kmol/hr H2 56.54621 56.54621 CO 29.67409 29.67409 CO2 0.8984301 0.8984301 N2 1.356904 1.356904 H2O 4.598847 4.598847 O2 0 0 AR 0 0 H2S 0 0 C2 0 0 C3 0 0 C4 0 0 C2H4 0 0 C2H2 0 0 C 0 0 METHA-01 0 0 N-BUT-01 0 0 ISOBU-01 0 0 METHA-02 0.0274828 0.0274828 Mole Frac H2 0.6073579 0.6073579 CO 0.3187268 0.3187268 CO2 0.00964996 0.00964996 N2 0.0145743 0.0145743 H2O 0.0493958 0.0493958 O2 0 0 AR 0 0 H2S 0 0 C2 0 0 C3 0 0 C4 0 0 C2H4 0 0 C2H2 0 0 C 0 0 METHA-01 0 0 N-BUT-01 0 0 ISOBU-01 0 0 METHA-02 0.00029519 0.00029519

102 A.5 Compression Block Aspen Stream Results (cont.)

TOCOMPR1 (IN) HPSYNGAS (OUT) Mass Flow kg/hr H2 113.9904 113.9904 CO 831.1831 831.1831 CO2 39.53973 39.53973 N2 38.0116 38.0116 H2O 82.84952 82.84952 O2 0 0 AR 0 0 H2S 0 0 C2 0 0 C3 0 0 C4 0 0 C2H4 0 0 C2H2 0 0 C 0 0 METHA-01 0 0 N-BUT-01 0 0 ISOBU-01 0 0 METHA-02 0.4409001 0.4409001 Total Flow kmol/hr 93.10197 93.10197 Total Flow kg/hr 1106.015 1106.015 Total Flow cum/hr 2392.189 304.4149 Temperature C 40 900 Pressure bar 1.01325 30 Vapor Frac 1 1 Liquid Frac 0 0 Solid Frac 0 0 Enthalpy MJ/kmol -50.55938 -23.95263 Enthalpy MJ/kg -4.255979 -2.01628 Enthalpy MW -1.307549 -0.6194547 Entropy J/kmol-K 36471.66 47553.16 Entropy J/kg-K 3070.105 4002.922 Density kmol/cum 0.0389191 0.305839 Density kg/cum 0.4623443 3.633249 Average MW 11.87961 11.87961 Liq Vol 60F cum/hr 4.823042 4.823042 QVALNET MJ/kg 19.97606 19.97606

103 A.6 Water-Gas-Shift Block Aspen Stream Results

HPSYNGAS SHFSNGAS FROMSHFT SHFTBYPS SHFTINLT STM2WGS TOWGSRXN (IN) (OUT) Mole Flow kmol/hr H2 56.54621 57.76476 8.210076 49.55469 6.991526 0 56.54621 CO 29.67409 28.45554 2.450434 26.0051 3.668984 0 29.67409 CO2 0.8984301 2.11698 1.329634 0.7873458 0.1110843 0 0.8984301 N2 1.356904 1.356904 0.1677713 1.189133 0.1677713 0 1.356904 H2O 4.598847 6.480667 2.450434 4.030233 0.5686138 3.10037 4.598847 O2 0 0 0 0 0 0 0 AR 0 0 0 0 0 0 0 H2S 0 0 0 0 0 0 0 C2 0 0 0 0 0 0 0 C3 0 0 0 0 0 0 0 C4 0 0 0 0 0 0 0 C2H4 0 0 0 0 0 0 0 C2H2 0 0 0 0 0 0 0 C 0 0 0 0 0 0 0 METHA-01 0 0 0 0 0 0 0 N-BUT-01 0 0 0 0 0 0 0 ISOBU-01 0 0 0 0 0 0 0 METHA-02 0.0274828 0.0274828 3.40E-03 0.0240847 3.40E-03 0 0.0274828 Mole Frac H2 0.6073579 0.6004507 0.5618819 0.6073579 0.6073579 0 0.6073579 CO 0.3187268 0.2957884 0.167703 0.3187268 0.3187268 0 0.3187268 CO2 9.65E -03 0.0220055 0.0909976 9.65E-03 9.65E-03 0 9.65E-03 N2 0.0145743 0.0141046 0.0114819 0.0145743 0.0145743 0 0.0145743 H2O 0.0493958 0.0673649 0.167703 0.0493958 0.0493958 1 0.0493958 O2 0 0 0 0 0 0 0 AR 0 0 0 0 0 0 0 H2S 0 0 0 0 0 0 0 C2 0 0 0 0 0 0 0 C3 0 0 0 0 0 0 0 C4 0 0 0 0 0 0 0 C2H4 0 0 0 0 0 0 0 C2H2 0 0 0 0 0 0 0 C 0 0 0 0 0 0 0 METHA-01 0 0 0 0 0 0 0 N-BUT-01 0 0 0 0 0 0 0 ISOBU-01 0 0 0 0 0 0 0 METHA-02 2.95E -04 2.86E-04 2.33E-04 2.95E-04 2.95E-04 0 2.95E-04

104 A.6 Water-Gas-Shift Block Aspen Stream Results (cont.)

HPSYNGAS SHFSNGAS FROMSHFT SHFTBYPS SHFTINLT STM2WGS TOWGSRXN (IN) (OUT) Mass Flow kg/hr H2 113.9904 116.4468 16.55053 99.8963 14.09408 0 113.9904 CO 831.1831 797.051 68.63763 728.4134 102.7697 0 831.1831 CO2 39.53973 93.16788 58.51695 34.65093 4.888798 0 39.53973 N2 38.0116 38.0116 4.699857 33.31175 4.699857 0 38.0116 H2O 82.84952 116.751 44.14525 72.60578 10.24374 55.85404 82.84952 O2 0 0 0 0 0 0 0 AR 0 0 0 0 0 0 0 H2S 0 0 0 0 0 0 0 C2 0 0 0 0 0 0 0 C3 0 0 0 0 0 0 0 C4 0 0 0 0 0 0 0 C2H4 0 0 0 0 0 0 0 C2H2 0 0 0 0 0 0 0 C 0 0 0 0 0 0 0 METHA-01 0 0 0 0 0 0 0 N-BUT-01 0 0 0 0 0 0 0 ISOBU-01 0 0 0 0 0 0 0 METHA-02 0.4409001 0.4409001 0.054514 0.3863861 0.054514 0 0.4409001 Total Flow 93.10197 96.20234 14.61175 81.59059 11.51138 3.10037 93.10197 kmol/hr Total Flow 1106.015 1161.869 192.6047 969.2645 136.7507 55.85404 1106.015 kg/hr Total Flow 304.4149 324.8146 38.45626 287.1426 40.51211 327.6548 cum/hr Temp. C 900 938.5323 671.3141 989.9996 989.9996 220 990 Press. bar 30 30 30 30 30 30.3975 30 Vapor Frac 1 1 1 1 1 0 1 Liquid Frac 0 0 0 0 0 1 0 Enthalpy -23.95263 -29.04402 -73.98625 -20.99548 -20.99548 -270.7363 -20.99548 MJ/kmol Enthalpy -0.619454 -0.7761395 -0.3002968 -0.475842 -0.067135 -0.233161 -0.542978 MW Density 0.305839 0.2961761 0.3799576 0.2841466 0.2841466 0.2841465 kmol/cum Density 3.633249 3.577022 5.00841 3.375551 3.375551 3.37555 kg/cum Average 11.87961 12.07735 13.1815 11.87961 11.87961 18.01528 11.87961 MW Liq Vol 60F 4.823042 4.922271 0.6955635 4.226708 0.5963338 0.0559616 4.823042 cum/hr QVALNET 19.97606 18.97257 13.92261 19.97606 19.97606 0 19.97606 MJ/kg

105 A.7 Methanol Synthesis Block Aspen Stream Results

Mole SHF- MEOH FD2- CRD- 2RECY PURGE RCY- DIST- DST HTFL- Flow SNGAS -2ST RXR MEOH -CMP MEOH CO2 H20 LIQ kmol/hr (IN) (OUT) H2 57.764 0 154.0 137.5 137.4 41.248 96.24 4.7E-3 0 4.7E-3 CO 28.455 0 58.11 42.37 42.37 12.712 29.66 1.9E-3 0 1.9E-3 CO2 2.1169 0 18.55 23.53 23.48 7.0460 16.44 0.052 0 0.052 N2 1.3569 0 4.522 4.522 4.521 1.3565 3.165 3.7E-4 0 3.7E-4 H2O 6.4806 1.3E-3 6.706 1.697 0.321 0.0965 0.225 5.7E-3 1.36 1.375 O2 0 0 0 0 0 0 0 0 0 0 AR 0 0 0 0 0 0 0 0 0 0 H2S 0 0 0 0 0 0 0 0 0 0 C2 0 0 0 0 0 0 0 0 0 0 C3 0 0 0 0 0 0 0 0 0 0 C4 0 0 0 0 0 0 0 0 0 0 C2H4 0 0 0 0 0 0 0 0 0 0 C2H2 0 0 0 0 0 0 0 0 0 0 C 0 0 0 0 0 0 0 0 0 0 METHA-1 0 8.292 4.756 15.54 6.795 2.0386 4.756 0.415 0.04 8.748 N-BUT-01 0 0 0 0 0 0 0 0 0 0 ISOBU-01 0 0 0 0 0 0 0 0 0 0 METHA-2 0.0274 0 0.027 0 0 0 0 0 0 0 Mole Frac H2 0.6004 0 0.624 0.610 0.639 0.6395 0.639 9.8E-3 0 4.6E-4 CO 0.2957 0 0.235 0.188 0.197 0.1970 0.197 4.0E-3 0 1.9E-4 CO2 0.0220 0 0.075 0.104 0.109 0.1092 0.109 0.108 0 5.1E-3 N2 0.0141 0 0.018 0.020 0.021 0.0210 0.021 7.7E-4 0 3.6E-5 H2O 0.0673 1.6E-4 0.027 7.5E-3 1.5E-3 1.5E-3 1.5E-3 0.011 0.97 0.135 O2 0 0 0 0 0 0 0 0 0 0 AR 0 0 0 0 0 0 0 0 0 0 H2S 0 0 0 0 0 0 0 0 0 0 C2 0 0 0 0 0 0 0 0 0 0 C3 0 0 0 0 0 0 0 0 0 0 C4 0 0 0 0 0 0 0 0 0 0 C2H4 0 0 0 0 0 0 0 0 0 0 C2H2 0 0 0 0 0 0 0 0 0 0 C 0 0 0 0 0 0 0 0 0 0 METHA-1 0 0.999 0.019 0.069 0.031 0.0316 0.031 0.864 0.03 0.859 N-BUT-01 0 0 0 0 0 0 0 0 0 0 ISOBU-01 0 0 0 0 0 0 0 0 0 0 METHA-2 2.8E-4 0 1.1E-4 0 0 0 0 0 0 0

106 A.7 Methanol Synthesis Block Aspen Stream Results (cont.)

Mass SHF- MEOH FD2- CRD- 2RECY PURGE RCY- DIST- DST HTFL- Flow SNGAS -2ST RXR MEOH -CMP MEOH CO2 H20 LIQ kg/hr (IN) (OUT) H2 116.44 0 310.4 277.1 277.1 83.152 194.0 9.5E-3 0 9.5E-3 CO 797.05 0 1627 1186 1186 356.08 830.8 0.054 0 0.054 CO2 93.167 0 816.7 1035 1033 310.09 723.5 2.296 0 2.296 N2 38.011 0 126.6 126.6 126.6 38.001 88.66 0.010 0 0.010 H2O 116.75 0.024 120.8 30.57 5.800 1.7402 4.060 0.103 24.6 24.77 O2 0 0 0 0 0 0 0 0 0 0 AR 0 0 0 0 0 0 0 0 0 0 H2S 0 0 0 0 0 0 0 0 0 0 C2 0 0 0 0 0 0 0 0 0 0 C3 0 0 0 0 0 0 0 0 0 0 C4 0 0 0 0 0 0 0 0 0 0 C2H4 0 0 0 0 0 0 0 0 0 0 C2H2 0 0 0 0 0 0 0 0 0 0 C 0 0 0 0 0 0 0 0 0 0 METHA-1 0 265.6 152.4 498.0 217.7 65.324 152.4 13.29 1.33 280.3 N-BUT-01 0 0 0 0 0 0 0 0 0 0 ISOBU-01 0 0 0 0 0 0 0 0 0 0 METHA-2 0.4409 0 0.440 0 0 0 0 0 0 0 Flow 96.202 8.293 246.7 225.1 214.9 64.499 150.4 0.48 1.40 10.18 kmol/hr Flow 1161.8 265.7 3155 3155 2847 854.39 1993 15.77 25.9 307.4 kg/hr Flow 324.81 0.435 332.5 219.4 558.4 167.52 206.4 4.022 0.03 0.454 cum/hr Temp C 938.53 94.26 210 250 40 40 218.4 95.37 128. 40 Press bar 30 3 30 45 10 10 30 3.5 3 10 Vap. Frac 1 0 1 1 1 1 1 1 0 0 Liq. Frac 0 1 0 0 0 0 0 0 1 1 Enthalpy -29.04 -233.8 -60.53 -70.53 -71.09 -71.095 -65.51 -217.3 -276 -247.4 MJ/kmol Enthalpy -0.776 -0.538 -4.148 -4.411 -4.245 -1.2737 -2.738 -0.028 -0.1 -0.699 MW Density 0.2961 19.03 0.741 1.025 0.385 0.3850 0.729 0.119 41.6 22.40 kmol/m3 Density 3.5770 609.7 9.489 14.37 5.100 5.1002 9.657 3.920 767 676.3 kg/cum Average 12.077 32.03 12.79 14.01 13.24 13.246 13.24 32.86 18.4 30.19 MW Liq Vol 4.9222 0.334 12.91 11.79 11.41 3.4240 7.989 0.020 0.02 0.380 60Fm3/h QVALNET 18.972 19.91 17.98 17.48 17.40 17.408 17.40 16.90 1.02 18.16 MJ/kg

107