Alberta Innovates- Energy and Environment Solutions & Bio. Report. Alberta Biomass and Gas to Liquids (BGTL) Scoping Study H

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1 Report H C Approved for Use E. Salehi/ S. Basu W. Nel S. Save D. du Plessis DATE REV. STATUS PREPARED BY CHECKED BY APPROVED BY APPROVED BY Discipline Lead Functional Manager Client

2 Table of Contents 1. Executive Summary Introduction BGTL Process Overview Biomass Preparation & Gasification Natural Gas Conditioning & Reforming Syngas Purification Fischer-Tropsch Synthesis FT Upgrading Technology Licensors Plant Performance Performance Summary Biomass Feedstock Natural Gas Feedstock BGTL Products FT Diesel FT Naphtha LPG Utilities Water Balance Steam Balance Power Balance Fuelgas Balance Effluents & Emissions Solid Effluents Liquid Effluents Gaseous Effluents Carbon Footprint Economic Evaluation Assumptions Natural Gas Pricing Biomass Pricing BGTL Products Pricing CO 2 offset Price Corporate Tax Capital Cost Estimation and Breakdown Operating Cost Estimate Exclusions High Level Economic Results Project Risks Page 1

3 7. Conclusions and Next Steps List of Tables Table 1: Biomass gasification technology licensors Table 2: SMR technology licensors Table 3: ATR technology licensors Table 4: FT Technology Main Reactions Table 5: FT Technology licensors Table 6: FT upgrading technology licensors Table 7: BGTL plant performance summary Table 8: Raw biomass characteristics Table 9: Biomass feedstock availability and costs in Alberta (Ref: Technical and Economic Study of Biomass Co-firing with Coal at Three Locations in Canada- Conducted by FPInnovations) List of Figures Figure 1: Diagram of the Biomass and Gas-to-Liquids (BGTL) Facility... 9 Figure 2: BGTL CAPEX breakdown Figure 3: Economic comparison between BGTL and GTL Figure 4: BGTL sensitivity analysis Figure 5: After-tax IRR against biomass cost and CO 2 offset price Page 2

4 Disclaimer / Qualification Statement This report was prepared by Hatch Ltd. ( Hatch ) for the sole and exclusive benefit of Alberta Innovates- Energy and Environment Solutions and Alberta Innovates Bio (jointly the Owner ) for the purpose of assisting the Owner to make a preliminary assessment of the feasibility of a biomass and gas-to-liquids (BGTL) facility for production of synthetic fuels from abundant biomass and natural gas sources in Alberta (the Project ). Any use of this report by the Owner is subject to Hatch s standard Professional Services Terms and Conditions, including the limitations on liability set out therein. Hatch makes no representation or warranty and assumes no liability in respect of: the use of this report by any third party; the use of this report by Owner in connection with any offering or sale of securities or any other financing transaction; and, any public disclosure of this report. This report includes, and has relied upon, information provided by the Owner and other third parties and Hatch has not verified, or rendered an independent judgment of, the validity of the information provided by others and disclaims any responsibility or liability in connection with such information. This report contains the expression of the professional opinion of Hatch, based upon information available at the time of preparation. The quality of the information, conclusions and estimates contained herein is consistent with the intended level of accuracy as set out in this report, as well as the circumstances and constraints under which this report was prepared, including the quality of the information supplied to Hatch by or on behalf of the Owner. Page 3

5 1. Executive Summary This report evaluates the techno-economic feasibility of an integrated biomass and gas-toliquids (BGTL) facility in Central Alberta. The facility will produce diesel, naphtha and LPG, and will be comprised of the following units: Biomass Preparation & Gasification Natural Gas Conditioning & Reforming Syngas Purification Fischer-Tropsch Synthesis FT Product Upgrading Utilities & Offsites The BGTL facility will operate on the same basic principle as other carbon-to-liquids facilities: decomposing carbon feedstock to produce syngas (carbon monoxide and hydrogen) and then reassembling these two compounds to produce high quality fuels. The CO-rich syngas produced from the biomass gasification is combined with H 2 -rich syngas from the natural gas reforming unit in order to achieve a H 2 :CO=2 required in the FT feed. Although the H 2 :CO of the biomass gasifier syngas could be adjusted through a shift unit, adding H 2 -rich syngas from natural gas reforming is more efficient and has less CO 2 footprint relatively. In choosing the appropriate ratio of natural gas and biomass for the BGTL configuration, the following factors were considered: Eliminating units that would be required for standalone BTL and GTL plants (but not needed for a BGTL facility) in order to reduce capex vs. the standalone plants. These include the shift units normally used to increase H 2 production for BTL and the external recycle/h 2 membranes used to decrease H 2 production in standalone GTL. Hence, the elimination of these units could be achieved by virtue of the fact that syngas generated from biomass is H 2 poor whereas syngas generated from natural gas is H 2 rich. Maximizing the biomass usage vs. natural gas on condition that the above consideration was met. Therefore in this study, it was assumed that a steam methane reformer (SMR) will be used to produce H 2 -rich syngas. Another option would be to use ATR (Autothermal Reforming) technology instead of SMR. The syngas from ATR will typically have a H 2 :CO ratio much closer to the targeted FT inlet ratio of 2 and therefore a much larger amount of ATR syngas will be required to correct the biomass syngas for the FT application. However, it must be noted that the large majority of the syngas in this case would be produced from natural gas and only a small fraction from Page 4

6 biomass. Due to this skewed relation and the main objective of converting biomass, the ATR case was not considered for this study. Designing a BGTL facility in Alberta will require integration between the different licensor technologies (namely gasification, natural gas reforming, syngas purification, and FT synthesis & upgrading). This report provides an overview of some of these technologies. The BGTL facility will produce 17,000 bbl/day of products (74% Diesel, 23% Naphtha, and 3% LPG). Based on the selected technologies for different units in the BGTL process, the facility will consume 2.9 million ton of biomass feedstock from Alberta s agricultural residues and woody wastes annually, and 72 t/h of natural gas. Initially a capacity of 11,000 bbl/d was investigated, however based on the amount of reasonably affordable biomass available in Central Alberta (see Section 5.3), the capacity used in this study was increased to 17,000 bbl/d to make use of the additional economy of scale benefit.. The facility will also have about 973,000 tons of CO 2 as the by-product which could be exported for enhanced oil recovery (EOR) or other industrial applications, or be sequestered. The facility will need to import about 1,100 m 3 /h of fresh water and 158 MWe power from the local grid. The integrated BGTL facility has several noteworthy advantages. The use of biomass as a feedstock combined with the high quality products from the BGTL process results in approximately 3.3 million tons reduction in CO 2 emission annually. Beside this environmental advantage, the project economics can be boosted through capturing the carbon credit. The Indicative Total Installed Cost (TIC) of the BGTL facility is estimated to be USD 3,147,000,000 (or a specific CAPEX of 185,000 USD/ bbl/d) on a generic basis. It must be noted that project specific costs may be heavily influenced by site and project specific assumptions as well as project execution. However it can be concluded that the BGTL facility is likely to be ~80% more expensive than a standalone GTL plant with similar project assumptions. This significant difference in capital costs between the BGTL and a standalone GTL is mostly because of the highly capital intensive biomass preparation & gasification and the syngas purification units. The biomass gasification unit combined with ASU, the biomass preparation, and the syngas purification units include up to 50% of the overall BGTL cost. Therefore, even a small improvement in this part of the BGTL process can impact substantially the overall economics. A financial model was developed to evaluate the economic viability of the proposed BGTL facility and compare it with a standalone GTL with the equal production capacity of 17,000 bbl/d. Results reveal that the economics of the BGTL facility, considering a biomass cost of 40 $/ton and CO 2 offset price of 20 $/ton, reaches close to a 10% after-tax rate of return when using commercially available technologies. In comparison, the BGTL rate of return may be around 5-7% lower than of a conventional GTL plant with a similar production capacity and project assumptions, which is mainly because of the higher capital cost for the BGTL plant. Page 5

7 When calculating the CO 2 reduction vs. conventional crude oil derived fuels, the following has been considered: All biomass input into the facility can be considered carbon neutral. 2/3 of the carbon in the feedstock to the BGTL facility is from this neutral biomass. The BGTL products emit less CO 2 per mile than conventional fuels. With these baseline considerations, the well to wheels CO 2 reduction vs. conventional crude derived fuels is around two thirds. The exact value may vary between GHG emission calculation methods. The conducted economic analysis shows that the capital cost and the projected oil price are the most sensitive parameters impacting the project economics. Although the oil price is defined by the global market, the BGTL CAPEX could be reduced to some extent by utilizing innovative technologies and an optimized process configuration. The CO 2 offset price and the biomass feedstock cost are the less sensitive variables in the BGTL economics, however the combination of a low cost biomass and a high CO 2 offset price can boost the BGTL economics roughly by 5%. This means the economic viability of the BGTL project would substantially improve if more stringent CO 2 emission policies were enforced in Alberta. For the future work, a more detailed technology evaluation is required to select the most viable technologies and to design the most optimized process configuration. Particularly, it is required to perform a screening study to define the most viable technologies for biomass preparation & gasification which has the highest contribution to the overall CAPEX of the BGTL facility.. In addition an increase in NG usage vs. biomass may be considered, for example by switching to ATR technology. However as mentioned earlier, the plant would start to resemble a GTL facility rather than BGTL facility, due to the small contribution the biomass would have in this case. When switching to ATR technology, the option of buying O 2 Over the Fence (OTF), in order to minimize capex becomes attractive (when using SMR the fraction of the Air Separation Unit is small relative to the overall capex). The economic model would need to be updated for a specific location in Alberta with more precise CAPEX and biomass pricing and availability data, in order to define the opportunity at an adequate level for potential investment decisions. It can be concluded that based on Alberta s extensive agricultural and forestry practice, BGTL has the potential to make a significant contribution in enabling a more environmentally friendly and renewable energy industry in Alberta, while also being economically sustainable. Page 6

8 2. Introduction The world s appetite for oil has reached record levels with increased consumption in developing countries such as India and China, and is projected to reach above 100 million bbl/d by Also, greenhouse gases (GHG) that result from the combustion of fossil fuels have been linked to climate change- particularly Global Warming. Therefore, reducing global dependence on fossil fuels and lowering adverse impacts throughout the lifecycle process are becoming important facets of today s energy portfolio. The global environment and energy challenge requires clean and renewable sources of fuel with minimal impact on the environment to maintain a sustainable development, and this can only be met with innovative technologies and an integrated approach to process design. In Alberta, biomass is one the main renewable sources of energy. Alberta has a booming agriculture industry, second largest industry in the province after Oil and Gas, and Alberta s forests are estimated to cover 38 million hectares. A study based on a typical blended forest of spruce and hardwood estimated average biomass yield in Alberta to be 84 dry tons of biomass per hectare. On the other hand, recent technological developments in shale recovery have significantly expanded the recovery of oil and natural gas from shale plays, and have depressed the natural gas price in North America. Canada is estimated to have 355 Tcf technically recoverable shale gas reserves. While the potential for Canadian shale gas production is still being evaluated, the size of the shale gas reserves shows the significance of the opportunity that shale gas recovery techniques have unlocked. The main proportion of the Canadian shale gas plays resides in Alberta and British Columbia. Diversification and utilization of forestry and agricultural infrastructure in the production of alternative biomass products in combination with the huge natural gas resources in Alberta offers the potential to produce clean fuels and transform Alberta into a world leader of clean fuels. An integrated technology which could be able to monetize Alberta s biomass and natural gas not only will provide a sustainable economic development but also will aid Alberta government to reduce GHG emissions. This study evaluated the feasibility of an integrated Biomass and Gas to Liquids (BGTL) facility in Central Alberta. A BGTL facility in Alberta has the potential to harness energy trapped in by-products and waste-products from Alberta s agricultural and forestry operations, and to monetize the significant natural gas resources residing in Alberta. The intention is to convert readily available biomass resources in Alberta into high quality transportation fuels, simultaneously reducing the greenhouse gas emissions and the dependence on fossil oil while providing a sustainable economy. Page 7

9 The purpose of this study is to evaluate the techno-economic feasibility of an integrated biomass and gas to liquids (BGTL) facility in Alberta. This report herein investigates the concept of producing liquid fuels from a BGTL facility and provides description of the different plant process units, summary of the different licensor technologies, and the key economic results. The BGTL facility is to produce roughly 17,000 bbl/day of liquid fuels and will be fed with a combination of biomass from agricultural residues and woody wastes, and natural gas. Liquid fuels produced from the BGTL facility will have significantly lower carbon footprint compared to crude derived fuels and will help Alberta become more energy independent. 3. BGTL Process Overview The BGTL facility uses gasification and reforming technologies to produce syngas from biomass and natural gas respectively. Syngases produced from the gasifier and reformer are combined in order to achieve desired H 2 :CO ratio in the FT feed. The syngas produced from biomass gasifier has typically a H 2 :CO ratio of <1 and it needs to be adjusted either through shift or to be blended with a source of H2-rich syngas (like reformed natural gas) to be ready for Fischer-Tropsch (FT) application. Natural gas reforming is selected for this study due to the fact that it is more efficient and has less CO 2 footprint compared to shift technology. The shift unit is mainly utilized to maximize the hydrogen production from natural gas steam reforming (SMR). The syngas leaving the SMR has typically a H 2 :CO ratio between 3 to 5. In the shift unit, downstream of the SMR, the carbon monoxide in the syngas reacts with steam over the catalyst in what is known as the water gas shift reaction to generate carbon dioxide and additional hydrogen. The reaction is mildly exothermic: CO + H 2 O H 2 + CO 2 (-41 kj/mol) The blended syngas from the biomass gasifier and natural gas reforming is washed to remove sulfur impurities and CO 2, and then the purified syngas is synthesized in the FT unit into long chain liquid hydrocarbons. At the last stage, the FT product is mildly refined in the FT upgrading unit to produce saleable products like diesel, naphtha and LPG. While the majority of the syngas from SMR is mixed with the syngas from biomass gasification, the remainder of SMR syngas is fed to the PSA where high purity H 2 is produced from the syngas for use in the FT upgrading unit. The PSA consists of multiple adsorption beds that adsorb contaminants in the syngas. The beds are regenerated through depressurization. An overall flow scheme of the BGTL facility is provided in Figure 1. The main areas of the BGTL facility will include: Biomass Preparation & Gasification Natural Gas Conditioning & Reforming Page 8

10 Syngas Purification Fischer-Tropsch Synthesis FT Product Upgrading Utilities & Offsites Biomass Feedstock BIOMASS HANDLING AND DRYING BIOMASS GASIFICATION SYNGAS CONDITIONING, COMPRESSION, PURIFICATION FT SYNTHESIS UPGRADING CO2 Diesel Naphtha LPG Natural Gas GAS TREATMENT NATURAL GAS REFORMING (SMR) PSA Hydrogen UTILITIES & OFFSITES BLOCKS STEAM SYSTEM COOLING WATER SYSTEM WATER TREATMENT FUEL GAS SYSTEM SLAG AND ASH DISPOSAL FLARE SYSTEM POTABLE WATER SYSTEM FIRE WATER SYSTEM TANK FARM SYSTEM INFRASTRUCTURE INSTRUMENT AIR SYSTEM CATALYST PREPARATION AND DISPOSAL Figure 1: Diagram of the Biomass and Gas-to-Liquids (BGTL) Facility 3.1 Biomass Preparation & Gasification Biomass, to be ready for gasification, needs to be dried and milled to the size required. Raw biomass typically contains a high moisture content, which must be reduced to an acceptable level ( 10%) before the biomass is fed to the gasifier. When the moisture content of the biomass is high, more energy is directed towards removing excess moisture from the biomass thereby decreasing the gasifier temperature. Lower gasification temperature produces lower energy syngas. Heated air is used to reduce moisture content in the biomass. Dried biomass can be fed to fixed bed, fluidized bed, or entrained flow gasifiers. Fixed bed reactors are available in the downdraft or updraft configuration. Downdraft gasifiers produce less tar but is more sensitive to biomass feed variations. Updraft gasifiers are less sensitive to variations in biomass feed, but produce large quantities of tar. Fixed bed gasifiers are suited for small-scale applications. Fixed bed gasifiers used in large scale applications can lead to uneven gas flow and non-uniform temperature distribution in the gasifier. Non-uniform bed temperature can cause hot spots in the gasifier. Most fixed bed gasifiers produce lower energy syngas which may not be suitable for Fischer-Tropsch applications. Fluidized bed gasifiers are less sensitive to variations in biomass feed, but are more complex and are typically used for large scale applications. In fluidized bed gasifiers, an inert medium Page 9

11 (eg: sand, dolomite, or alumina) is fed to the gasifier along with the dried biomass feed. Both the biomass feed and the inert medium enter the reactor from the bottom and flow upward in the reactor. The inflow speed determines whether the reactor is classified as bubbling fluidized bed (lower speed) or circulating fluidized bed (higher speed). A more homogeneous reaction takes place inside the fluidized reactor, when compared to the fixed bed reactor. Fluidized reactors thus have more uniform and lower temperatures and are less prone to developing hot spots. In addition, ash does not melt at the lower operating temperatures and can be easily removed from the reactor. Sulphur and chloride substances can also be absorbed in the inert medium, thereby reducing fouling and maintenance costs. In an entrained flow gasifier, powdered biomass is fed to the top of the gasifier with pressurized oxygen and/or steam. A portion of the biomass is burned at the top of the gasifier thereby releasing a large amount of heat. Since the residence time of the biomass in the entrained flow gasifier is approximately few seconds, the gasifier efficiency is improved by operating the gasifier at high temperatures. However the higher temperature causes the ash to melt and thus entrained flow gasifiers operate in the slagging regime. Generally, gasification occurs at a high temperature in the presence of oxygen and/or steam. It is a partial combustion process that produces syngas (CO and H 2 ) as well as contaminants such as carbon dioxide, hydrogen sulfide, ammonia, etc. Biomass and oxygen (O 2 ) are fed into a vessel where they react exothermically to produce heat, gases and particulates, similar to a boiler. However, the quantity of O 2 is limited such that the CO and H 2 cannot fully combust further to produce CO 2 and H 2 O, as in a boiler. Several biomass gasification licensors have been listed in Table 1 and have been classified in terms of the type of gasifier used. Table 1: Biomass gasification technology licensors Technology Fluidized Bed Gasifier Licensor Thyssenkrupp Uhde Synthesis Energy Systems U-GAS Andritz/Carbona Foster Wheeler Entrained Flow Gasifier Linde (Choren) Uhde PDQ The oxygen required for gasification is supplied from an air separation unit. ASU is used to separate air into its constituents (O 2, N 2, etc.). Several different licensor technologies are available including Air Liquide, Air Products, Linde and Praxair. The exact configuration of the ASU package will depend on the licensor technology selected. For a typical cryogenic ASU, Page 10

12 air is compressed, cooled and sent to high pressure and low pressure distillation columns to recover oxygen and nitrogen. Oxygen produced in the ASU is used in the gasification unit while the nitrogen is used for blanketing, purging, etc. 3.2 Natural Gas Conditioning & Reforming Natural gas can be reformed using steam methane reforming (SMR), auto thermal reforming (ATR), partial oxidation or a combination of these. For the purpose of this study, it was assumed that a steam methane reformer will be used which produces a syngas with a highest H 2 :CO ratio (typically > 5). The ratio between the size of the biomass gasifier and natural gas reformer is mainly a function of natural gas reforming technology and to a less extent the gasification technology and the biomass composition. In case of employing ATR technology instead of SMR, the syngas from ATR will typically have a H 2 :CO ratio <3, and therefore a larger amount of ATR syngas will be required to correct the biomass gasification syngas for the FT application. In this way, although the plant still would be a hybrid biomass and gas to liquids, the GTL side of the plant will have a much larger portion of the BGTL process and production capacity than the BTL side. An optimization study is required at the next stage of the study to select the most economic natural gas reforming technology to be paired with biomass gasification for the Fischer- Tropsch application. The most promising alternative to SMR technology could be ATR which has a higher methane conversion and less CO 2 production compared to SMR. To feed natural gas to the reforming unit, natural gas is conditioned to remove impurities like sulfur, and also pre-reformed to convert higher hydrocarbons (C 2 +) to methane, hydrogen, carbons oxides and steam. Pre-reforming takes place to reduce the risk of carbon deposition on catalysts in the reforming unit due to the presence of C 2 + components. Steam Methane Reforming Steam methane reforming is an exothermic, catalytic reaction that converts natural gas and steam to syngas in the presence of a nickel-based catalyst. Steam reforming is highly endothermic and requires an external supply of heat to the process. A typical outlet temperature of a steam reformer is about o C. The main reactions are shown below: CH 4 + H 2 O <-> CO + 3H 2 (+206 kj/mol) CH 4 + CO 2 <->2CO + 2H 2 (+247 kj/mol) The produced carbon monoxide also reacts with steam in the water gas shift reaction to produce carbon dioxide and hydrogen. The water gas shift reaction is slightly exothermic. CO + H 2 O <-> H 2 + CO 2 (-41 kj/mol) Steam reforming is widely used in the hydroprocessing applications in refineries, since it yields a higher H 2 :CO ratio and hence a higher hydrogen production. Table 2 lists the main commercialized steam methane reforming licensors: Page 11

13 Table 2: SMR technology licensors Licensor Toyo Lurgi Linde CompactGTL DPT Technology Conventional SMR Conventional SMR Conventional SMR Minichannel SMR Compact Reformer Autothermal Reforming Autothermal reforming is a non-catalytic reaction that exploits the benefits of both steam reforming and partial oxidative reforming. In this process, a mixture of oxygen (or air), natural gas and steam is first partially combusted in a burner and combustion chamber to raise the mixture temperature and provide energy for the endothermic reforming reactions, which takes place in a catalytic bed. It results in a lower H 2 :CO ratio (typically 2-3) than steam reforming. Several technology licensors have been listed in Table 3. Table 3: ATR technology licensors Licensor Technology Haldor Topsoe DPT (Johnson Matthey) Lurgi Syntroleum O 2 feed; Air or O 2 feed O 2 feed Air feed In addition, newer generation syngas technologies such as catalytic partial oxidation (CPOX), microchannel SMR, compact reforming (CPR) and heat exchange reforming (HER), are also under development. 3.3 Syngas Purification Raw syngas produced from biomass gasification is first sent through a scrubbing system, comprised of one or more wash columns, in order to remove solid particulate impurities in the syngas. The CO-rich syngas from biomass gasification is then combined with H 2 -rich syngas produced from the steam methane reforming unit in order to supply syngas with the correct H 2 :CO ratio of about 2:1. The combined syngas is sent to the Rectisol acid gas removal unit for purification. Page 12

14 Rectisol (licensed by both Linde AG and Lurgi AG) employs methanol to remove acid gases (H 2 S and CO 2 ) and trace contaminants such as ammonia from the syngas. Rectisol is commercially proven with respect to coal gasification and has been installed on the vast majority of coal-based chemical synthesis plants. The Rectisol process can operate selectively to recover hydrogen sulfide and carbon dioxide as separate streams so that the hydrogen sulfide can be sent to either a Claus unit for conversion to elemental sulfur or a WSA process unit for sulfuric acid production, while at the same time the carbon dioxide can be sequestered or exported. The CO 2 stream from the Rectisol process is greater than 98% pure and split into two streams. The alternative to Rectisol would be the Selexol process (licensed by UOP) which is similar to the Rectisol process but employs its own proprietary solvent (a mixture of the dimethyl ethers of polyethylene glycol) instead of methanol. 3.4 Fischer-Tropsch Synthesis The Fischer-Tropsch process is used to produce syncrude (synthetic crude oil) from syngas (CO and hydrogen). Dr. Fanz Fischer and Dr. Hans Tropsch developed the Fischer-Tropsch technology in the 1920s in Germany. The reaction is highly exothermic and takes place over cobalt or iron catalyst. The simplest form of the reaction is shown below: CO + 2H 2 CH 2- + H 2 O (-165 kj/mol) A breakdown of the main FT reactions is provided in Table 4, with the reaction to alkanes being the most prominent: Table 4: FT Technology Main Reactions Product Alkanes Alkenes Alcohols Carbonyls Carboxylic Acids Reaction nco + (2n+1)H 2 H(CH 2 )nh + nh 2 O nco + 2nH 2 (CH 2 )n + nh 2 O nco + 2nH 2 H(CH 2 )noh + (n-1)h 2 O nco + (2n-1)H 2 (CH 2 )no + (n-1)h 2 O nco + (2n-2)H 2 (CH 2 )no 2 + (n-2)h 2 O FT technologies can be classified into high temperature Fischer-Tropsch (HTFT) and low temperature Fischer-Tropsch (LTFT) based on operating temperature, final product slate, catalyst type and reactor type. Both HTFT and LTFT reactors require efficient removal of reaction heat from the reactor due to the exothermic nature of the FT reactions. HTFT results in an increased production of lighter components thereby requiring oligomerization in the upgrading unit to convert lighter products to transportation fuels. HTFT also requires a more expensive FT tail gas processing system. The higher operating temperature of the HTFT reactor allows for carbon formation Page 13

15 through the Boudouard reaction and results in frequent catalyst deactivation and increased catalyst costs. Lower cost iron catalyst is typically used in HTFT applications and more expensive cobalt catalyst is used in LTFT applications. High catalyst deactivation rate is also observed in iron catalysts used in LTFT reactors as the iron catalysts are less resistant to high water partial pressure when compared to cobalt catalysts in LTFT reactors. Cobalt catalyst based LTFT technology is usually preferred for GTL applications. LTFT reactors can be found in either fixed or slurry bed configurations. While the slurry bed configuration offers more uniform heat transfer, they are harder to scale up when compared to fixed bed configurations. Unlike slurry bed reactors, fixed bed reactors do not require any need for fine catalyst particle removal from the FT wax. Efforts to combine the benefits of both fixed bed and slurry bed reactors have led to the development of new technologies such as the micro/mini channel FT technologies. These new technologies improve catalyst productivity and heat transfer by reducing the sizes of the fixed bed reactor tubes. Table 5 lists the main FT technology licensors. Table 5: FT Technology licensors Licensor Sasol GTL.F1 Axens Synfuels China Rentech Syntroleum Shell DPT/BP Emerging Fuels Technology InfraXTL Velocys CompactGTL Technology Slurry Bed Slurry Bed Slurry Bed Slurry Bed Slurry Bed Slurry / Fixed Fixed Bed Fixed Bed Fixed Bed Fixed Bed Microchannel Minichannel FT liquid or condensate (C5- C20) and FT wax (C20+) streams from FT unit are sent to FT upgrading to produce saleable products. The FT tailgas stream is mainly sent to SMR unit to be used as a fuel gas. Page 14

16 3.5 FT Upgrading Hydrocarbon products from the FT units are processed in the upgrading unit to produce saleable products. The FT liquid from the FT unit contains dissolved gases such as H 2, CO, and CO 2. These gases must be stripped prior to sending it to the upgrader. If these gases are not stripped, they can poison the upgrading catalyst. If the FT liquid is being stored in intermediate storage, it can pose severe risk to operating personnel. Steam is used to strip the absorbed gases from the FT liquid. Overhead vapor from the stripper usually consists of hydrocarbons in the range of C2 to C5 and can be used as fuel gas while the liquid product (C5 to C20) can be sent to hydrotreater. The FT wax (C20+) is sent to the hydrocracker. Hydrogen from the PSA is fed to the hydrocracker and hydrotreater in order to maintain a partial pressure of hydrogen in the reactors. The liquid effluents from the hydrotreater and hydrocracker are flashed to obtain a H 2 rich gas stream which is recycled to the reactors and a liquid stream which is sent to a product distillation column. The product is fractionated into light ends, heavy ends, and diesel in the distillation column. Naphtha is recovered from the light ends in the naphtha stabilizer column while the light ends are used as fuel gas. Heavy ends from the distillation column are recycled to the hydrocracker. The refined products can include: LPG, naphtha, kerosene, diesel, lube oil, waxes and paraffins, and specialty products. Alternatively, the FT syncrude can be marketed as synthetic crude and delivered as a feedstock to a refinery at another location for further processing. Table 6 lists the main FT upgrading licensors. Table 6: FT upgrading technology licensors Licensor UOP Haldor Topsoe Chevron Shell BP Syntroleum Synfining TM Technology FT Upgrading FT Upgrading FT Upgrading FT Upgrading FT Upgrading FT Upgrading 3.6 Technology Licensors A detail and comparison of these technologies can be found in section 5 and 6 of the previous GTL study conducted by Hatch- Evaluation of GTL Technologies and Opportunities in Alberta. Page 15

17 4. Plant Performance 4.1 Performance Summary Performance of the BGTL facility is summarized in Table 7. Table 7: BGTL plant performance summary Parameter Unit Quantity Diesel bbl/d 12,580 Liquid Hydrocarbon Production Naphtha bbl/d 3,910 LPG bbl/d 510 Total bbl/d 17,000 Raw Biomass t/a 2,887,166 Natural Gas MMBTU/d 84,767 Oxygen t/d 106 CO2 for Export t/a 973,145 Power Import MWe 158 Fresh Water Import M3/h 1, Biomass Feedstock For the purposes of this study, a generic biomass composition was utilized as shown in Table 8. Approximately, 2.9 million ton/a biomass will be required for the BGTL plant to produce 17,000 bbl/d liquid hydrocarbon products. The type of the biomass feedstocks used for the BGTL facility is provided in Table 9. Parameter As Received Table 8: Raw biomass characteristics Wt.% Moisture content 43% Ultimate Analysis (Dry Basis) C 50% H 5% O 42% N S < 1% Ash 2% Page 16

18 4.3 Natural Gas Feedstock Natural gas is used in the SMR to produce H 2 rich-syngas, as previously described in Section 3.2. Natural gas is also used in the gasification unit as a fuel gas. Total natural gas consumption is 84,767 MMBTU/d. 4.4 BGTL Products There is a variety of GTL products that may be produced. The exact product slate depends on many factors like plant location, plant capacity, target market, extent of complexity of the FT product upgrading configuration, and the overall economics of the project. The BGTL facility will produce 17,000 bbl/d of saleable products of which 74% is diesel, 23% is naphtha, and 3% is LPG. The BGTL facility will also be able to produce other products like jet fuel, Wax, syncrude, base oils, paraffins and other specialty chemicals, FT Diesel The BGTL plant will produce 12,580 bbl/d of diesel. FT diesel has several desirable properties including a high cetane number and negligible sulphur and aromatics content. Cetane number is a measure of diesel s quality with a higher cetane number meaning better quality diesel. The high cetane number for FT diesel is in contrast to conventional diesel cetane number of about 40. This higher cetane number improves combustion, cold start properties and cuts down on noise. A high cetane number also indicates lower build-up of deposits in the engine which reduces engine wear and extends engine life. These qualities make FT Diesel ideal for blending with crude oil derived diesel. As a blendstock, FT diesel can help the refiner to extend the diesel pool to meet growing demand, upgrade lower grade material, enable increased biodiesel inclusion, increase ultra low sulphur diesel production capacity and enable reformulated diesel blending. The properties of the FT diesel (low density, low sulphur content and high cetane number) are such that they can improve the properties of heavy oil derived diesel (high density, high sulfur content, and low cetane number). The diesel fraction of synthetic crude oil (SCO) from oil sands upgrading typically has a cetane number of around 35. The low cetane number is due to the high aromatics content of about 45%. Such a low cetane number mandates the oil sands-derived diesel to be subjected to severe hydrotreating or blended with higher quality distillates/cetane enhancing additives. FT diesel presents an opportunity to increase the cetane number of oil sands-derived diesels above 40 through blending. The diesel market is steadily growing in Alberta with an average annual growth of 5% over the last 20 years. The diesel growth in Alberta is primarily due to the demand growth from the open pit mining oil-sands sector. Considering the amount of capital investments planned in Alberta oil sands, a strong demand for diesel in Alberta can be projected. Page 17

19 4.4.2 FT Naphtha The BGTL plant will produce 3,910 bbl/d of naphtha. FT naphtha s paraffinic nature together with the negligible aromatics, sulfur and metals content makes it ideal for naphtha cracking. Cracking FT derived naphtha also results in higher yields of ethylene and propylene when compared to crude derived naphtha (typically 10% higher). The Asia-Pacific region is one of the strongest future markets for FT naphtha due to the rapid growth of the petrochemical industry for olefins production. Alternatively, FT naphtha could be utilized as a bitumen diluent. Diluent is required to be blended with highly viscose bitumen to bring it to pipeline specification. As a rule of thumb, for every barrel of exported bitumen, 1/3 barrel of FT naphtha would be required. In addition to lowering the viscosity of bitumen, diluent aids in reducing Total Acid Number, sulfur/heavy metal contents and density of the dilbit, and consequently improves dewatering from bitumen. Currently, about 1/3 of the condensate required for dilution application in Alberta oil sands is imported from the US while forecasts show that the diluent market is expected to reach close to 700,000 bbl/d by LPG LPG (mix of propane and butane) comprises a small fraction in the BGTL product slate (510 bbl/d). Propane and butane have various industrial uses primarily as fuel or as petrochemical feedstock. New technological advancements in in-situ oil sands recovery (like N-solv, solventaided SAGD, etc.) have also provided a potential use for LPG. 4.5 Utilities Water Balance The BGTL facility requires approximately 1100 m 3 /h of fresh water import during normal operation. The facility also discharges approximately 210 m 3 /h of water which could be sent to an injection well or a river Steam Balance Steam is produced and consumed by a number of different units in the BGTL facility. The plant produces and consumes three levels of steam pressure: low pressure (LP), medium pressure (MP) and high pressure (HP). The HP steam is produced in the gasification unit through cooling the hot syngas stream leaving the biomass gasifier. The MP steam is produced from FT reactor cooling. The majority of the MP steam is consumed for biomass drying to provide heat for evaporating moisture from raw biomass. A number of heating duties throughout the facility utilize the majority of the remaining steam. The majority of the HP steam is consumed to drive the Air Separation Unit (ASU) turbine. Page 18

20 4.5.3 Power Balance Total power demand for the plant is approximately 158 MW e which is imported from the local power grid Fuelgas Balance The majority of fuel gas produced in the BGTL facility originates from the FT tailgas. A purge is required to maintain a consistent level of inert gases in the recycle. This fuel gas is consumed to provide heat for both the SMR and product upgrading heater, and it would not be any external FT tailgas recycle back to the syngas unit. 4.6 Effluents & Emissions Solid Effluents There are different sources of solid effluents from the BGTL facility: Spent catalysts and adsorbent: they can be collected and routed back to the originating manufacturer for recycling or to another facility for metal reclamation. Steel industry can also be looked as an alternative to buy used catalysts for upgrading various steels, where metal reclaiming is not economically attractive. Waste activated sludge: the water/ wastewater treatment unit produces activated sludge. Waste activated sludge is typically disposed of in a landfill after stabilization or utilized as a soil amendment. Ferromagnetic materials and high gravity solids: including metal gathered during transportation, rocks, etc. which are contained in raw biomass. It is assumed that the volume of this material is small and that they can be disposed of or recycled. Slag and filter dust are by-products from the gasification reaction. They are granulated and sent to on-site stockpiling Liquid Effluents Two main sources of produced water in the BGTL facility are the condensed water from the syngas cooling and the FT water which is the reaction water produced in FT synthesis unit. The majority of the water is treated in the water/ wastewater treatment unit and recycled to be used inside the BGTL facility. The discharge from water/ wastewater treatment can be disposed of in disposal wells and/ or rivers or be sent to evaporator and crystallizer which discharge crystals for land fill. BGTL plant like any other plants will also have stormwater discharge which could be sent to the stormwater pond Gaseous Effluents The gaseous emissions vented from the BGTL process consist of: Flue gases from several fired equipment Flue gas from biomass gasification unit Page 19

21 Flue gas from natural gas reforming (SMR) unit Flue gas from product upgrading Flue gas from steam boilers Flare off-gas during unplanned plant outages Nitrogen vent from air separation unit Air from wastewater aeration basins Air vent from biomass dryer The flue gas will contain mainly water vapor, N 2, CO 2, and small amounts of NOx, SOx, CO, and Particulate Matter (PM) Carbon Footprint The use of biomass as a feedstock significantly reduces GHG (or CO 2 equivalent) emissions as GHG emissions originating from the biomass are considered neutral. GHG emissions are also reduced by capturing CO 2 in the syngas purification system. This high pressure captured CO 2 could be exported for sale or be used for CO 2 sequestration. FT fuels are also of superior quality than crude derived fuels and are considered relatively a higher performance, lower emitting fuel. This means consumption/ combustion of FT fuels produce fewer particulates and GHG emissions. Considering all these factors about two thirds reduction in CO 2 footprint compared to crudederived fuels is achieved. This is translated to approximately 3.3 million tons CO 2 emission reduction annually. The CO 2 offset price (carbon credit) will affect the economics of the BGTL facility, while its economics will improve as more stringent GHG reduction policies are enforced in Alberta. 5. Economic Evaluation A high level economic model was put together by Hatch to evaluate the economic viability of a BGTL plant in comparison to a standalone GTL plant with the same capacity in Alberta. An indicative Internal Rate of Return (IRR) of the BGTL plant is compared with the IRR of the same size GTL facility. 5.1 Assumptions The economic results provided in this report are based on the assumptions provided below: A capacity of 17,000 bbl/d is used as the basis for the BGTL plant in regard to the less expensive biomass availability in Central Alberta (see Table 9). The GTL plant is the net importer of power and water. The plant location is assumed to be in central Alberta. Page 20

22 The plant life has been assumed to be 30 years. The plant is assumed to require a three year construction period from 2014 to A plant production ramp-up of 80% is assumed in the first operating year (2017) hrs of operation per year has been assumed. 5.2 Natural Gas Pricing EIA 2013 forecast (Henry Hub reference case) is assumed for natural gas on which a discount is applied to account the differential between Henry Hub and AECO benchmark (the Canadian benchmark). A transportation cost from AECO Hub to a generic BGTL plant in central Alberta is also included. The average forecasted Henry Hub price over the life of the plant ( ) used for this analysis is $6.15/MMBTU. 5.3 Biomass Pricing Referring to the recent study conducted by FPInnovations- Technical and Economic Study of Biomass Co-firing with Coal at Three Locations in Canada, a number of biomass feedstocks were defined available for co-firing with coal for power generation in a radius of up to 150 km from a Central Alberta location. Hatch categorizes these biomasses to five groups as listed below: Potential Short Rotation Energy Crops SREC Agricultural Residue Municipal Solid Waste Woody Biomass Wood Pellets The biomass availability from SREC depends on the land suitable to grow these crops and the willingness of farmers to participate in a SREC program. Therefore, it was assumed that no SREC biomass is available right now. Table 9 shows the availability and costs of these five categories of biomass feedstocks. There are a total of 6,716,689 ton/a of biomass available with a weighted average cost of 69 $/ton at the BGTL gate and a weighted average moisture content of 32%. However as mentioned in Section 4.2, for the BGTL plant proposed by Hatch, approximately 2.9 million ton/a of biomass is required. Therefore, the Less Expensive Biomass with a total availability of 4.5 million ton/a, a weighted average cost of 40 $/ton, and a weighted average moisture content of 43% is assumed for the BGTL study. Page 21

23 Biomass Type Potential Short Rotation Energy Crops SREC Agricultural Residue Table 9: Biomass feedstock availability and costs in Alberta (Ref: Technical and Economic Study of Biomass Co-firing with Coal at Three Locations in Canada- Conducted by FPInnovations) Biomass Cost Low ($/ODt*) Biomass Cost High ($/ODt) Reed Canarygrass Jerusalem artichoke Hemp Willow Poplar Miscanthus Barley Straw Wheat Straw Flax Straw Average Biomass Cost ($/ODt) Average Moisture content (%) Average Biomass Cost ($/ton) 88 51% Biomass Availability ( ton/a) They do not exist right now 12% ,917 Oat Straw Municipal Solid Waste MSW Pellets % ,173 Woody Biomass Wood Pellets Whole Tree biomass (WTB) Forest Residual biomass Wood Pellets from BC Wood Pellets from AB % 38 3,578, % 129 2,145,000 Total Biomass 95 32% 69 6,716,689 Less Expensive Biomass** 72 43% 40 4,571,689 *ODt: oven-dry tone **Including: Agricultural Residue, Municipal Solid Waste and Woody Biomass 5.4 BGTL Products Pricing The EIA December 2012 forecast (the latest released) was assumed for the Brent crude oil price forecast. Brent is used as the benchmark for crude oil pricing since diesel price is more linked to the global crude oil pricing (Brent crude benchmark). The main reason is that most refineries in the US are fed based on imported Brent crude oil. The average forecasted Brent Crude price over the life of the plant ( ) is $136/bbl. The FT diesel price forecast is determined based on a historical relationship derived by Hatch between diesel price in Alberta and Brent crude oil price. FT Naphtha is assumed as diluent for bitumen application. The FT naphtha when sold as diluent in Alberta can be priced vs. pentane plus (C5+) condensate using the condensate equalization model published by Canadian Association of Petroleum Producers (CAPP). LPG is priced based on a historical relationship derived by Hatch between C3/C4 prices in Alberta and Brent crude oil price. Page 22

24 5.5 CO 2 offset Price A CO2 offset price of 20 $/ton was used as the basis for the economic calculations. 20 $/ton CO2 offset price is used as the basis since an after-tax IRR of 10% is achievable for the BGTL project with this price. 5.6 Corporate Tax Corporate Tax rate of 25% for Alberta + Federal beyond 2012 was assumed as forecasted by the Alberta Finance and Enterprise and Tax Foundation. 5.7 Capital Cost Estimation and Breakdown The capital cost estimate is specific to the technology licensors used. Key assumptions for the CAPEX estimate include: Capital cost estimate (CAPEX) for the BGTL facility is based on Hatch in-house data and similar projects conducted by Hatch. Different Lang factors were assumed for the core process (biomass gasification, natural gas reforming, FT and upgrading) and utility & offsites (U & O)- a Lang factor of 3.5 for the core process units and 4.4 for the U & O. The Indicative Total Installed Cost (TIC) of the BGTL facility is estimated to be USD 3,147,000,000 and a breakdown of the total CAPEX is shown in Figure 2, though it must be noted that the costs could be heavily impacted through project specific considerations and project execution. This would be translated to a specific CAPEX of 185,000 $/ bbl/d which may be 80% more expensive than a standalone GTL plant with similar project assumptions, mostly because of the highly CAPEX intensive biomass preparation and gasification unit. 16% 26% 7% 31% Biomass Preparation Biomass Gasificationan ASU Natural Gas Reforming Syngas Purification FT & Upgrading U & O 5% 11% 3% Figure 2: Indicative BGTL CAPEX breakdown Page 23

25 5.8 Operating Cost Estimate Operating costs (OPEX) including chemicals and catalysts, water, operating labour, maintenance, SG&A, and insurance is estimated based on Hatch s in-house data. Maintenance costs are assumed to be 2% of total installed cost. Sales, general, and administrative (SG&A) costs are assumed to be 1% of total revenue while insurance costs are assumed to be 0.5% of total installed cost. Since basis pipeline gas was assumed, royalties were not included on the basis that royalties would already have been paid on the natural gas at extraction. 5.9 Exclusions Contingency and owner cost are not included due to the high level nature of the current analysis. Owner s cost of 10%, and contingency of 20-30% is typically assumed in front end studies for specific locations/projects High Level Economic Results Figure 3 compares the Indicative Internal Rate of Return of a BGTL plant against a GTL plant at a capacity of 17,000 bbl/d on a generic basis. Results show that the after-tax IRR of the BGTL plant may be about 7% less than a GTL plant at the same capacity and with similar project assumptions. This is translated to more than four years of additional payback period for the BGTL compared to GTL. The main reason for the significant difference between the economics of the BGTL and GTL is because of the capital intensive biomass preparation and gasification unit. A sensitivity analysis was conducted on the results in order to identify the relative importance of the key variables driving the project returns, and to quantify the impact of changes in the assumed values on the BGTL project economics. The sensitivity analysis shown in Figure 4 reveals that, in order of importance, the estimated capital costs and the projected crude oil price are the most sensitive variables affecting the project economics. The crude oil price is impacted by the global market and it is defined by the supply and demand balance. However, the project CAPEX could be reduced to some extent by utilizing innovative technologies and an optimized process configuration. At the second place, the natural gas price, the biomass feedstock cost, and the CO 2 offset cost have a same level of sensitivity on the BGTL economics. The biomass moisture content is the less sensitive variable affecting the BGTL economics since it mostly impacts the cost of the biomass preparation and drying unit. The biomass preparation and drying cost is less than 7% of the overall CAPEX. Page 24

26 After-tax IRR (%) After-Tax IRR Alberta Innovates- Energy and Environment Solutions & Bio 18% 16% 14% 12% 10% 8% 6% 4% 2% 0% BGTL- 17,000 bbl/d GTL- 17,000 bbl/d Figure 3: Indicative economic comparison between BGTL and GTL based on similar project assumptions 25% 20% 15% 10% 5% 0% -60% -40% -20% 0% 20% 40% 60% Biomass Cost CO2 offset cost CAPEX Biomass Moisture NG Price Crude Oil Price Figure 4: BGTL sensitivity analysis Page 25

27 CO2 offset price (USD/tonne) Alberta Innovates- Energy and Environment Solutions & Bio Figure 5 shows combinations of biomass costs and the CO 2 offset costs that result in attractive returns. As shown in Figure 5, a low biomass cost combined with a high CO 2 offset price can provide an after-tax IRR of greater than 15%. In another word, the BGTL economics will improve substantially as more stringent CO 2 emission policies are enforced in Alberta After-Tax IRR 15.0%-20.0% %-15.0% 5.0%-10.0% 0.0%-5.0% Biomass Cost (USD/tonne) 6. Project Risks Figure 5: After-tax IRR against biomass cost and CO 2 offset price A high level risk assessment of the project shows that the following parameters are the major considerations: Supply of feedstocks Market price of feedstocks and products Technology scale-up Government policy and support Process integration The inability to obtain biomass and any other required consumable has the potential to shutdown the facility. Plant trips pose a serious risk to the profitability and resulting economics of such capital projects. Page 26