Executive Summary. (Edited for RFP) A-1

Transcription

1 Executive Summary (Edited for RFP) A-1

2 Background The Provincial government of Alberta continues to study, develop and establish new industries to capture value from its vast natural resource of oil in the Alberta Oil Sands. In an effort to further promote value creation, Alberta Innovates Energy and Environment Solutions ( EES ) and Alberta Finance and Enterprise ( AF&E ) are interested in evaluating the feasibility of converting petroleum coke (petcoke) that is currently produced and stored by industry Upgraders into marketable products. In Phase 1 of the envisioned two-phase study, Jacobs Consultancy Canada Inc. ( Jacobs Consultancy ) has provided factual data including capital costs and indicative economics of a large-scale gasification complex located in Alberta s Industrial Heartland (AIH) for the production of various higher-value products. The gasification-based complex is often called a polygen gasifier, referring to the capability to produce a variety of products ranging from electrical power and hydrogen to petrochemical feedstocks and transportation fuels from syngas. Syngas is a mixture of carbon monoxide and hydrogen and is the primary product from gasification. AF&E and EES have not decided to proceed with Phase 2 of the study and a scope is yet to be developed, but based on the conclusions from this Phase 1 study, screening and evaluating new technologies and investigating other means of reducing the capital costs associated with gasification appear to be most beneficial. Highlights The purpose of Phase 1 was to build on conceptual work previously completed by Alberta to establish a petrochemical cluster in the AIH and answer the following questions: How much petcoke is available? What is the impact of scale on the capital investment of potential facilities? How do the synergies that exist among potential products in the polygen concept impact cost competitiveness? Which products ought to be considered for a large-scale complex? What are the indicative economics and what are the economic gaps? How does the cost of carbon (CO 2 capture) affect costs for alternate manufacturing routes? With regard to the questions above: A-2

3 Alberta has sufficient petcoke production and storage, even without any expansion to current upgrading capacity, to feed a gasification complex of mammoth proportions. Around 57 million metric tonnes (MMT) are available in storage and approximately 6 MMT are currently produced each year (MMTA) by Syncrude, Suncor and CNRL near Fort McMurray. By 2016, roughly 100 MMTA is available in storage, and with staged investment, a gasifier operating on 12 MMTA petcoke could be supported. The following facts add perspective to the scale of the proposed gasifier: Equal to 66% of the world s petroleum-based gasification capacity in 2010 Equal to 23% of the world s coal- and petroleum-based gasification capacity in 2010 If producing all hydrogen, it would produce enough to satisfy 17 upgraders If producing all diesel and naphtha, it would be nearly as large as Sasol s South African Coal to Liquids complex If producing all power, it would be equivalent to a little more than eight 500 MW power facilities Depending on the pace of new and expanding upgrading capacity, the petcoke availability could be more than 18 MMTA. It was originally anticipated that the large size would bring unprecedented economies of scale. With limits imposed by current technology, however, such as limitations on equipment sizes, we found that the economies of scale level out after about 4 MMTA of petcoke capacity. Although this is much smaller than the expected petcoke supply, on the upside, 4 MMTA is still a large-scale facility, and, perhaps, most importantly, allows an opportunity for phased development with minimal additional costs. A gasification complex is extremely expensive from an initial capital investment standpoint due to all of the various components involved, including an air separation unit, a feed system, the gasifier, black water system, syngas conversion and cleaning, and sulphur removal. We found that the costs of the downstream facilities to convert the syngas, though significant, do not have sufficient leverage on their own to reduce per unit capital costs by achieving world-scale capacities. In other words, achieving world-scale on the gasification components was much more important from an economic standpoint than achieving capital savings for size and configuration of the downstream components. Therefore, the focus on new technology and sizing of equipment should be to the core gasification components instead of the downstream syngas conversion facilities. A-3

4 We discovered that because of the very high capital costs and the limits of current commercial technology, the gasification complex economics look favorable only at high natural gas prices or high CO 2 costs that have the potential of directly impacting the sales price of the various products in representative markets. Depending on the price scenario, anticipated market demand and gasifier size, lower cost products such as methanol and hydrogen tend to be more economic. However, at gasifier complexes larger than 4 MMTA of petcoke feed, other products are necessary to consume all of the syngas made by the plant. In most of the cases, internal power production along with naphtha and diesel from Fischer-Tropsch (FT) are more economic than ammonia, urea or exported power production. In almost all cases, ammonia and urea are not selected products unless naphtha, diesel and power are eliminated as possible products and methanol and hydrogen demands have been met. There is, however, the possibility of selling hydrogen-rich syngas to fertilizer plants in Alberta as a means of producing ammonia and urea, if the price that the fertilizer plant is willing to pay for feedstock is high enough. The development of new technology has the capability to transform gasification economics. Although a single innovation does not, by itself, significantly improve the economics, due in large part to the large number of interrelated processes in a gasification complex, the combination of several technologies can improve on the overall economics. Based on licensor claims, we selected nine to ten technologies that together have the potential to reduce the cost of production for syngas by nearly 50%, provide environmental benefits, and expand the product mix. The technologies are as follows: Pratt and Whitney Rocketdyne (PWR) gasifier Claimed to reduce the cost of syngas by 21% via a combination of smaller and less expensive equipment with a slight increase in efficiency. This technology is in the pilot plant stage and is being tested with Alberta petcoke. Air Products ITM Claimed benefits of 0.5% for the production of syngas due to substantial savings on the ASU for the production of nearly pure oxygen for the gasifier. Warm Gas Clean-Up Eastman Chemicals and RTI are developing two different technologies focused on removing both sulphur and CO 2 compounds from the syngas. Based on licensor claims, each has the capability to reduce the production cost for clean syngas by 14% and 16% for sulphur and CO 2, respectively. Solid Feed Pumping Both PWR and General Electric are developing solid feed pumps that will increase gasifier efficiency and reduce the cost of syngas by a claimed 0.5 percent. Organic Feed Slurry Slurrying the petcoke with an organic liquid instead of water could save another 0.5% from the syngas production costs. A-4

5 Slurry Transport of Petcoke Slurrying the petcoke with vacuum bottoms, supercritical CO 2 or tailings pond liquid and transporting by pipeline to AIH could provide environmental or efficiency improvements. Methanol to Olefins (MTO) Along with Methanol to Propylene (MTP), this technology has the capability to provide an offtake of methanol production and produce olefins or polyolefins in Alberta. Conceptual Design For the indicative economic analysis of the gasification complex, Jacobs Consultancy, in conjunction with the Steering Team, agreed on a poly-generation concept (polygen), meaning the gasification complex could produce a variety of products designated to capture perceived synergies associated with cascading offgas and multiple use of downstream capital equipment. For example, installation of a Pressure Swing Absorber (PSA) for hydrogen could be utilized for hydrogen and ammonia production and ammonia synthesis could also be utilized for urea production. Therefore, at a high level the flow scheme shown in Figure A-1 was utilized: Figure A-1. Conceptual Polygen Gasification Complex Air Power Process Water Fluxant ASU O 2 O 2 to Claus Plant Process Water CO 2 Comp Combined Cycle Power Block CO 2 Power Petcoke GASIFICATION GASIFICATION Shift, Gas Cooling and Clean Up PSA H 2 Ammonia Urea Slag Sour Gas Methanol Synthesis Methanol (Methanol Derivatives) Liquid and Solid Wastes Claus Sulfur Removal F-T Diesel and Naphtha Sulphur (Disposal undetermined) A-5

6 Since prior studies had been done by AF&E on market potential for the various products, we did not perform a full bottoms-up market analysis on each product. To determine realistic long- term product pricing, we estimated prices for each scenario based on a price setter formula dependent on several factors: Competitive market location - We agreed with the Steering Team that the competitive market location for each product is North America, and, for some products like hydrogen, the available market was localized even further to regions in Alberta. Feedstock price - The price scenarios established for natural gas and crude oil were used for feedstock prices for the competitive price setting producer. Demand growth - The long-term expectation for demand in the competitive market and the balance of available supply dictated if the price setter would have to cover capital costs or not. For example, fertilizer use in North America is expected to be flat in the long term because the available land is fairly constant and fertilizer intensity is flat to declining due to environmental pressures and improvements in productivity from new seed technology. Therefore, fertilizer production from the gasification complex would back out existing fertilizer production, in which the price setter only covers the cash costs of production related to feedstock, utilities and operating costs. Economic scenarios were employed to avoid the pitfalls associated with making decisions based on a single forecast. The scenarios were used to set commodity prices for oil and natural gas, which then determined feedstock prices under the price setter formula. The three oil prices selected were $60, $85, and $105/BBL in 2010 US dollars, WTI (Cushing). Based on historical statistical data relating natural gas prices to crude, we calculated nine natural gas prices ranging from $4.52/MMBTU to $17.08/MMBTU (2010, US$, Henry Hub). For this phase of the study, we focused on the natural gas prices corresponding to the lowest, highest and a midpoint price of $9.38/MMBTU. Configuration, Cost and Indicative Economics From a competitive standpoint, the cost of production from the gasification complex was compared to the competing conventional technologies, as represented in Figure A-2. Figure A-2. Products and Competing Technologies A-6

7 Petcoke Gasification Complex Products Power Hydrogen Ammonia Urea Methanol Diesel/ Naphtha Conventional Technologies Coal- / NG- Based Power Steam Methane Reforming SMR & Ammonia/Urea synthesis Coal, nat gas via Syn Gas Refining/ Upgrading Based on the costs of production for each of the competing technologies which includes the feedstock cost, operating cost, transportation cost, CO 2 penalty and, in some cases, capital recovery we estimated the cost of production for each of the products from the competing technologies with the cost of production from the gasification complex. For convenience, Figure A-3 summarizes the results for all products in a single graph. To standardize the comparison for all products, the Y (vertical) axis shows the percent of the high feedstock cost of production for the competing technology. Therefore, by definition, the highest cost of production via the alternate production method is 100 percent. For example, in the high natural gas price scenario, the cost of production for hydrogen from SMR is $3973/tonne; at the mid price scenario for natural gas it is 61% of the high scenario, or about $2430/tonne. The cost of the production for the gasification complex is around $2120/tonne (Location Factor = 1.3) or about 55% of the high cost of production from SMR, and, because it is produced from petcoke and is independent of the oil or natural gas price scenario, is the same at each of the different feedstock price scenarios. The sensitivity for the cost of production to the feedstock price for each commodity is shown in Section H. Figure A-3. Comparative Costs of Production A-7

8 % of Product Price at High energy cost scenario at $15/Ton CO2 200% 180% 160% 140% 120% 100% 80% 60% 40% 20% 0% Low Power Hydrogen Mid NG Combined SMR Cycle from NG Conventional Coal High Low Mid High Ammonia Low NH3 Synthesis from NG Mid High Low Urea Urea Synthesis from NG Mid High Low Methanol F-T Fuel Methanol Synthesis from NG Methanol Refinery/ Synthesis Upgrader from Coal Mid High Low Mid High Gasifier Complex An LP was developed to determine the most profitable configurations. For our preliminary economics, we ran a series of cases to identify the most profitable configurations of the gasification complex. In total, we ran more than 60 different cases including the different price scenarios. Some of the key polygen cases are summarized as follows. 4, 12 and 18 MMTA petcoke feed cases that were required to be self-sufficient on power, with limits on hydrogen and methanol demand 4 and 12 MMTA petcoke feed cases exporting hydrogen, ammonia and urea 4 and 12 MMTA petcoke feed cases allowed to import power 12 MMTA petcoke feed cases with no production of naphtha and diesel The 12 and 18 MMTA cases correspond roughly to the coke availability in the long term under both of the Upgrading scenarios identified above. We added the 4 MMTA cases midway through the study to help outline possibilities consistent with the minimum size necessary to achieve most of the economies of scale as indicated above. A-8

9 Key Variables and Uncertainties For a project of this scale, reaching far into the future, it is not surprising that there are a number of variables and uncertainties that could affect project economics significantly. This is one of the key reasons why we recommend Quantitative Decision and Risk Analysis below as a valuable exercise for future phases of the study. Some of the most important variables and the ranges covered in this analysis are as follows: Capital Cost Purchased equipment costs and construction costs cannot be defined tightly until the project reaches an advanced stage of execution. As the project proceeds toward an advanced stage of execution, many other unknown scope issues will be identified and resolved. For now, we assume an uncertainty of -30% / +50% in our order of magnitude estimates. It is too often an unfortunate experience that capital costs increase as project definition improves and the scope increases; decreases in capital costs are rare. Capital cost risk is often handled via Quantitative Risk Analysis (QRA). Location Factor Construction costs in Alberta are significantly higher than on the US Gulf Coast. Jacobs Engineering Group data suggest that costs in AIH will be 1.3 to 1.5 times higher than US Gulf Coast costs, which is the range assumed in this study. We note that there has been a reduction of 10% in the location factor for Ft. McMurray in the last two years, driven by reduced construction activity during the last recession. Timing of the gasification complex project will determine the location factor, and its significant impact on capital costs, but can be studied via a correlated risk with QRA. Cost of Petcoke Transport We assumed that similar US rail coal transport costs would apply here. We did not include capitalized charges for rail infrastructure improvements, including a bridge across the Athabasca River or the extension of rail along the west side of the river. We note that at this point, petcoke transport cannot be transported easily from the mines to the Lynton terminal. Rail infrastructure will need improvement and that will impact transportation costs. However, without the cost of rail improvements, the transportation costs are relatively low compared to the capital costs for the gasification complex. Nevertheless, we have identified alternatives for consideration in future stages of the product which could avoid some of the initial and ongoing concerns relating to rail transportation of the petcoke. Cost of Carbon - We assumed current costs of $15/tonne and looked at sensitivities up to $120/tonne. We then estimated the effect on expected market prices if higher costs are forced on the industry. As the project proceeds, the actual cost of carbon should become clearer and can be handled via QRA. Oil Price - We created scenarios around constant dollar (2010) prices of $60/bbl, $85/bbl and $105/bbl for WTI crude. Oil price uncertainty is best handled by QRA. A-9

10 Natural Gas Price - We considered historical ratios of gas price to oil price and chose P10, P50 and P90 ratios. Natural gas price uncertainty is best handled by QRA. Market Size - We assumed limitations on certain products depending both on known constraints for certain cases (for example, the relationship between upgrading expansions and hydrogen requirements) and stretch constraints [such as a significant quantity of MeOH going to polyolefin generation via Methanol to Olefins (MTO) or equivalent]. We note, however, the scale of this project could provide supply additions over a short period of time equivalent to several world-scale units for some of the products considered. This can be considered by utilizing QRA. Path Forward Alberta holds one of the largest stockpiles and production capabilities of petcoke in the world. While the exact recoverable amount is unknown due to storage conditions and overburden, with current production and potential recovery of the stored petcoke, Alberta has enough petcoke to support a large-scale gasification complex for many years. If built to consume 12 MMTA of petcoke, the gasification complex would increase the world s coal- and petroleum-based gasification capacity by 23% based on 2010 capacities. However, based on our analysis of current commercialized gasification technology, a gasification complex of this size is extremely expensive and the economies of scale diminish above a capacity of 4 MMTA, even using the largest capacity GE slurry fed gasifiers in the world. Therefore, only at sustained high natural gas prices do the economics of the gasification complex appear favorable. Fortunately, there is hope in the form of new technology that promises to dramatically lower the costs of gasification. Based on licensor claims, we have identified nine to ten technologies that, in combination, have the potential to reduce the capital costs associated with syngas production by approximately 50 percent. In addition, particularly regarding novel transportation methods, Alberta may reduce the environmental liability associated with the tailings ponds in the long term. Therefore, we recommend that, first and foremost, further study of the gasification complex include screening and evaluation of the following technologies: PWR Gasifier WGCU options for sulphur and CO 2 Solid Feed Pumping by GE and PWR A-10

11 Air Products Ion Transport Membrane Organic feed slurry options Pipeline options for transport of the petcoke from Fort McMurray to Edmonton Methanol to olefins The impact of the new technologies, if they perform as claimed and if they are all incorporated in one complex, is transformative. Although detailed discounted cash flows and full economics were not in our work scope, we calculated preliminary net present values (NPV) to show the dramatic impact of the new technologies on profitability. Figure A-4 shows the preliminary NPV for the 4 MMTA petcoke case producing either methanol or hydrogen. In the figure, the mid price case producing methanol (blue bar on left) is consistent with the LP s selection shown in Table A-2 above, while the high price case producing hydrogen (maroon bar on right) is consistent with the LP s selection.. The other cases are the non-optimized, or forced, production cases for comparison purposes. Figure A-5 shows the NPV of the same six cases reflecting the potential impact of new technology. The impact is dramatic, as indicated in Figure A-5, and the NPV for each case increases between $3,000 MM and $4,500 MM. A-11

12 Figure A-4. Preliminary NPV for Selected Cases Current Technology Approximate NPV ($MM) 4 MM TA Gasification Complex $MM $5,000 $4,000 $3,000 $2,000 $1,000 $0 ($1,000) ($2,000) ($3,000) ($4,000) ($5,000) Methanol Hydrogen NPV ($65/B oil, $4.52 gas) NPV ($85/B oil, $9.38 gas) NPV ($105/B oil, $17 gas) Figure A-5. Preliminary NPV for Selected Cases New Technology (based on licensor s performance data) Approximate NPV ($MM) 4 MM TA Gasification Complex With New Technogy Claims $11,000 $9,000 $7,000 $MM $5,000 $3,000 $1,000 ($1,000) NPV ($65/B oil, $4.52 gas) NPV ($85/B oil, $9.38 gas) NPV ($105/B oil, $17 gas) ($3,000) ($5,000) Methanol Hydrogen A-12

13 We have determined that the expected product values and capital costs have the largest impact on the indicative economics and also contain much uncertainty. Together they echo the importance of considering different economic scenarios. Therefore, further study should incorporate quantitative analysis of the risks (especially regarding market scenarios, capital costs, and the impacts of technology improvements) to the overall economics and allow for investigation of mitigating strategies and informed decision making. Due to the small capital cost penalties associated with phased investment at increments of at least 4 MMTA petcoke capacity, Alberta could achieve both world-scale economies of scale and the benefits of phased investment. In addition, the incremental investment strategy has the option of providing the best testing ground for new technology. We also recommend that the Alberta Government carefully consider the benefits of industry participation outside of new technology providers and preliminary industry feedback at this stage. It may be more prudent to define a more compelling economic story through technology screening and evaluation and quantitative risk evaluation before engaging industry. A-13