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Ind. Eng. Chem. Res. 2008, 47, 7118–7129
Energy and Hydrogen Coproduction from (Athabasca Bitumen) Coke Gasification with CO2 Capture S. Nourouzi-Lavasani,† F. Larachi,*,‡ and M. Benali‡ Department of Chemical Engineering, 1065, AVenue de la Me´decine, LaVal UniVersity, Que´bec, QC, Canada G1V 0A6, and Varennes CANMET Energy Technology Centre, Natural Resources Canada, 1615 Lionel-Boulet, Varennes, QC, Canada J3X 1S6
Performance and economic assessments of exploitation of Athabasca bitumen coke (ABC) have been conducted to alleviate the dependence toward natural gas in bitumen recovery and upgrading. Power and hydrogen production from ABC-fed integrated gasification with combined cycle (IGCC) with CO2 capture or sequestration islands, namely, CO2 physical absorption in the Selexol process and CO2 mineral trapping (MT) with Ca(II)bearing natural brines from local aquifers, have been analyzed. Simulations show that production costs of power (electricity and heat) and H2 from the IGCC/Selexol process are 0.0584 $/kWhe, 0.046 $/kWhh, and 1.4 $/kg H2, which could be competitive with current natural gas technologies. IGCC/Selexol outperforms the IGCC/MT process, which is reflected in larger production costs for power and H2 due to the cost of the pH-controlling reagents. Introduction The Athabasca oil sands are among the largest in situ and minable hydrocarbon resources in the world. According to an estimation of crude oil reserves, Canada is second to Saudi Arabia in recoverable reserves.1,2 However, most of these reserves exist as deposits, also referred to as bitumen, which require special extraction methods and upgrading processes. Some of these deposits are close to the ground surface to be readily mined while others are deep deposits requiring “in situ” recovery methods. Advanced in situ methods, such as “steamassisted gravity drainage” (SAGD), are based on steam injection for lowering bitumen viscosity to enhance bitumen mobility and to facilitate its migration toward the production wells. In a SAGD operation, several horizontal well pairs, ∼5 m apart vertically, are drilled from the same pad extending as long as 1000 m horizontally into the oil sands. The top well is used to inject steam to warm up an area beneath the injector, reducing the viscosity and displacing an expanding zone of bitumen, which is collected through the lower well.3 In conventional technology, natural gas is used for supplying the required energy for steam generation and transportation into the oil sands reservoir. After extraction, bitumen is transferred into primary and secondary upgrading plants where sands and water are first separated from bitumen before it continues its way to various cokers and hydroprocessors. The end product of an upgrading plant is a synthetic crude oil (SCO), which is suitable for marketing.1 Nowadays, oil sand projects are overwhelmingly dependent on natural gas use for energy and power generation for bitumen recovery and hydrogen production for upgrading. Though historically this dependence was born of past low prices of natural gas in Alberta, this situation is currently changing as natural gas price has risen at diapason with the price of oil. Alternative technological options are foreseen to take off to mitigate the dependence toward the rise in natural gas prices.1 Gasification is an existing technology that might be used to * To whom correspondence should be addressed. E-mail: faical.larachi@ gch.ulaval.ca. † Laval University. ‡ Natural Resources Canada.
consume the least valuable residue from bitumen for power and hydrogen generation. Although this fuel exhibits lower heating value (lower heating value (LHV) ) 34.7 MJ/kg)4 equivalent to 70 ( 3% of the natural gas LHV, currently most of it is stocked because of its unsuitability to be used as a feed for energy generation through conventional power production technologies. As Athabasca oil sand recovery and processing operations require electricity, hydrogen, and steam in a simultaneous manner, a comprehensive plant to supply extemporaneously all these required needs from the same fuel is highly conceivable. With production rates for oil sands foreseen to climb by 2030 to 5 MMbpd,1 gasification-based energy generation could turn into a suitable intermediate for responding to these growing energy needs. Another factor of considerable impact in an oil sands sustainable economy is greenhouse gas emissions. The main greenhouse gases of concern for oil sands consist of CO2, CH4, and N2O, which are referred to as CO2-equivalent (CO2E). The CO2 portion of CO2E emissions from oil sands industry is 85-95%. It has been estimated that, for mining-based and in situ recovery, 40 and 60 kg of CO2E are emitted in the production of each barrel of bitumen.1 Concerns for climate change are irremediably pushing for implementing environmentally acceptable technological solutions to ensure perennial exploitation of oil sands. The present study analyzes some sustainability and economic issues of gasification as an alternative technology to alleviate the dependence toward natural gas in bitumen recovery and upgrading. An integrated gasification combined cycle (IGCC) power plant has the potential to provide the required energy and power for bitumen extraction and hydrogen for upgrading. Self-sufficient oil sands exploitation could rely on bitumen-coke, which is an upgrading byproduct, as a feed to the IGCC plant. The CO2 management is a crucial aspect in this study; hence, the inclusion of capture or sequestration islands in the IGCC plant has been considered to make the process friendly to the environment. In this study, two different CO2 interception processes are scrutinized. In the first, CO2 is removed by physical absorption in a Selexol process, a technology proven at the commercial scale. The second process concerns CO2 sequestration using mineral trapping, where CO2 is chemically
10.1021/ie800773a CCC: $40.75 2008 American Chemical Society Published on Web 08/19/2008
Ind. Eng. Chem. Res., Vol. 47, No. 18, 2008 7119
Figure 1. Schematic of an IGCC power plant with precombustion CO2 capture, with and without pure hydrogen production.
stored as solid carbonate. This end product is environmentally benign and thermodynamically stable; therefore, the sequestration of CO2 is permanent and safe, and its rerelease to the atmosphere is not an issue. Furthermore, the carbonation reactions are exothermic and occur spontaneously in nature in addition to large sequestration capacity because of large suitable mineral feedstock deposits available worldwide. As a mineral feedstock, rocks that are rich in alkaline silicates can be used. Brines that are rich in mineral cations are the other source of minerals for CO2 mineral carbonation.5-7 Although numerous experimental studies have been conducted at a laboratory scale on this method, studies on its application for CO2 trapping at an industrial scale are not reported. In this work, both the performance and economic aspects of CO2 mineral trapping with natural brine from local aquifers have been investigated based on available data. For the performance, emissions, and energy study, different configurations of the proposed IGCC plant have been simulated by the Hysys process software, and an economic analysis has been carried out based on commercially available technologies; this allows us to utilize technical and economic data found in many analyses of similar systems for IGCC electricity production. The present Athabasca bitumen-coke IGCC has been simulated based on a detailed coal-based 400 MW-IGCC plant flow sheet illustrated by “IEA Greenhouse Gas R&D Programme”.8 Plant Configurations IGCC systems involve gasification of the fuel, cleaning the gas produced, and combusting it in a gas turbine generator to produce electricity. Residual heat in the exhaust gas from the gas turbine is recovered in a heat recovery boiler as steam, which can be used to produce additional electricity in a steam turbine generator.8 A simple schematic of an IGCC power plant, which includes CO2 capture/sequestration islands, is depicted in Figure 1.
The configurations considered in this assessment are categorized based on the type of the plant production. (1) Singleproduction plants: a single-production plant is referred to IGCC with a single product with no side product for sale. Singleproduction plants include (a) power plant that produces power in the form of electricity, (b) hydrogen plant that produces pure H2 as its product, and (c) energy generation plant that produces energy in the form of heat. (2) Coproduction plants: In these cases, the plant produces two sellable products divided into a main and a side product. The coproduction plants include electricity-hydrogen, heat-hydrogen, and electricity-heat plants. (3) Multiproduction plants: According to our definition, a multiproduction plant produces all three possible products of an IGCC plant simultaneously, namely, electricity, hydrogen, and heat. In addition, all these plant configurations are examined with two different CO2 removal methods: (1) physical absorption with a Selexol process; (2) mineral carbonation with local naturally occurring brines. Figure 1 shows that all configurations share the basic features of an IGCC, air separation unit (ASU), gasifier, gas cooling, desulfurization, shift reactor, and combined cycle. Differences basically lie in further syngas treatment. In the cases with CO2 physical absorption, the dissolved CO2 is recovered from the solution by reducing the pressure and then CO2 is compressed for disposal or storage. In the cases with pure H2 production, the pressure swing adsorption (PSA) and purge gas compressor are adopted in the plant. Process Description In this process, the feed of the plant is bitumen-coke; Table 1 shows the composition and heating value of this fuel. In view of the similarity between the properties of bitumen-coke and petroleum-coke, and based on the technical literature regarding various types of feeds and relevant gasifier technologies as practiced commercially, it was concluded that an entrained bed
7120 Ind. Eng. Chem. Res., Vol. 47, No. 18, 2008 Table 1. Bitumen-Coke Composition and Heating Value4 ultimate analysis
wt % (dry basis)
C H N S O ash
84.9 3.9 1.3 6.0 0.8 3.1
proximate analysis
wt %
moisture volatile matter fixed carbon ash
1.8 11.9 83.3 3.0
heating value (MJ/kg)
34.7
gasifier would be a conceivable option for bitumen-coke gasification. Among the commercial entrained bed gasifier licensors, Texaco and Shell claim to have experience with oil sand coke;9 therefore, in the present study, a Shell gasifier with its specific working conditions has been inserted in the proposed power plant. Shell gasification technology is a dry fed, entrained bed gasifier, operating at 2.7 MPa and 1613 °C. The gasifier converts coke to syngas that is quenched at the exit of the gasifier to a temperature of 900 °C. Recycled and cooled down syngas is used to quench the hot syngas in the gasifier.8 To enable gasification of coke, oxygen from the air separation unit and steam are provided to the gasifier. The cryogenic air separation produces 95% pure oxygen. The ASU liquefies the air and separates it into nitrogen and oxygen. These gases are compressed to the desired pressure levels. The gas produced by the gasifier is directly quenched and cooled down to ∼220 °C prior to the first cleaning step. The heat extracted from the syngas is used for generating and superheating “intermediatepressure” (IP) and “high-pressure” steam, which is supplied to the steam turbine for generating power. A treatment of the syngas produced in the gasifier is required to make the gas suitable for combustion in the gas turbine. The gas turbine requirements are, among others, to be particulates-free and low in sulfur. Sulfur in the coke is converted to H2S. The desulfurization process takes place at 38 °C. H2S is removed from the syngas by physical absorption in Selexol. After a desulfurization unit, the syngas enters a double-shift reactor, where the CO/H2 syngas is shifted into a mixture of H2 and CO2 in two separate steps. To enable the shift reaction, the IP steam is added to the syngas stream entering the first shift reactor. The entering steam/ gas mixture is heated to 350 °C. Heat is recovered in the shift reactors due to the exothermic water gas shift reaction. The H2/ CO2 mixture then enters the CO2 removal section after which H2-rich fuel gas proceeds through the saturator where water is added to enhance the performance of the gas turbine and reduce NOx emissions. The remainder of the N2 from the air separation unit is added to enhance the cycle performance, and then the gas mixture (N2 + syngas) is combusted in the gas turbine. Residual heat in the exhaust gas from the gas turbine is recovered in a heat recovery steam generator (HRSG) section. The HRSG is a nonfired double-pressure natural circulation boiler that supplies steam to the steam turbine.8 In the case of pure hydrogen production, decarbonized syngas might partly or totally pass two extra sections: PSA unit and purge gas compressor. High-purity hydrogen (99.999%) is assumed to be extracted from the H2-rich syngas at 35 °C using PSA, a process commonly used in syngas processing.10,11 A typical application is natural gas steam reforming where H2 separation efficiency is in the range 85-90%. Based on the available information on this process, the operating pressure is assumed at 6.0 MPa to get a separation efficiency of 85%. Pure hydrogen exits the PSA after a pressure drop of 0.05 MPa, while the purge gas, which contains the remaining 15% H2, H2O, and a small amount of CO and CO2, is discharged at 0.15 MPa.12 Thereafter, the purge gas is compressed and burned in a gas turbine to generate the coproduct, electricity or heat. In the case of energy generation
in the form of heat, the same process as depicted for electricity generation is assumed to take place; unless in the HRSG section, the excess energy of the exhaust gas from the gas turbine is recovered as heat instead of electricity through steam turbines. As previously mentioned, two different CO2 removal methods are investigated: physical absorption with Selexol and mineral trapping with brine. In both cases, the abatement level of total CO2 capture from the plant has been set at 85%. In the case of CO2 physical absorption, the Selexol solution physically removes CO2 from the mixture with a mass efficiency of 98%. The CO2 is recovered from the solution by reducing the pressure in two steps. The CO2 then enters the compressor to be compressed to 11 MPa, ready for storage. In the Selexol recovery process, the energy is required for pumping the Selexol to the absorber.8 In CO2 mineral trapping with brine, CO2 gas reacts with a brine rich in calcium cations, to form stable calcium carbonates. Reactions 1-5 show the various physicochemical steps involved:13-15 CO2(g) f CO2(aq) (CO2 gas dissolution)
(1)
CO2(aq) + H2O f H2CO3 (formation of carbonic acid) (2) H2CO3 f H+ + HCO3(dissociation of carbonic acid to form bicarbonate)
(3a)
-
CO2(aq) + OH f HCO3(formation of bicarbonate in alkaline pH) -
+
HCO3 f H + CO3
2-
(3b)
(bicarbonate ion dissociation) (4)
Ca2+ + CO32- f CaCO3 V
(calcite precipitation)
(5)
In order to enhance precipitation of mineral carbonates, the environment should be basic. High pH conditions (pH > 9) provide an abundant supply of OH- and help shift rightwise the equilibrium reactions (3aa, 3b) and (3b4), leading finally to the precipitation of CaCO3. Conversely, the dissolution of carbonates increases as the solution pH drops toward acidic values.15 The parameters that affect the efficiency of carbonate formation are pH, pressure, temperature, and brine composition. Soong et al.13 conducted experiments to identify the optimum reaction conditions that favor the formation of mineral carbonates. According to their experimental results, although other metal cations were available in the examined brine (such as Mg and Fe), the major precipitate in the CO2/brine reaction was calcite (CaCO3) and the other mineral carbonates were not detected as the product of these reaction sequences. On the other hand, it was concluded that mineral trapping is controlled by CO2 pressure and temperature though to a lesser extent when compared to pH. The experimental results suggest that temperatures above 50 °C and pressures in excess of 0.34 MPa no longer play a major role in brine carbonation. To be efficient in CO2 mineral trapping with brine on an industrial scale, it has been suggested to control the brine pH in the alkaline region by continuously adding the pH-adjusting reagents to the system.13,14 According to the CO2/brine reaction sequence, proton-producing reactions include dissociation of carbonic acid to bicarbonate (3aa) and dissociation of bicarbonate to carbonate (3b). Therefore, a continuous amount of OHshould be added to neutralize the produced protons, besides the extra amount required to raise the acidic pH of the extracted natural brine. Soong et al.13 and Druckenmiller et al.15 used caustic potash (KOH) for brine pH adjustment in their autoclave
Ind. Eng. Chem. Res., Vol. 47, No. 18, 2008 7121 Table 2. Conditions of the Gasifier Inlet Streams stream
temperature ( °C)
bitumen-coke oxygen steam
30 180 350
fuel input (LHV)
1150 MW
pressure (bar)
flow rate (kg/s)
31.24 41.00
33.14 36.3 5.0
experiments. Other options can be caustic soda.14 Both are strong electrolytes used industrially for pH adjustment. Obviously, lower mass flow rate of caustic soda is required in comparison with caustic potash to produce the same amount of OH-. In this study, NaOH and pH ) 11 have been assumed as pH-controlling agent and target value for pH adjustment, respectively. It is assumed to have a mass efficiency of 98% for CO2 removal with brine. Simulation Development Simulation through Hysys process software is performed by specifying (1) flow rates, compositions, and performance conditions of the operation units inlet streams; (2) operating
Figure 2. Location of the investigated area, Alberta province, Canada (from Underschultz et al.17). Table 3. Basic Economic Assumptions bitumen-coke price
0.3 $/GJ LHV26
capital charge rate interest during construction O&M costs contingencies cost plant life CO2 transportation and disposal cost (after physical absorption CO2) cost of pH adjusting chemicals (NaOH) (in CO2 mineral trapping)
15% per year21 12.3% overnight capital cost21 4% of overnight capital cost21 10% of overnight cost 25 years 5 $/ton CO221 30 $/ton
conditions of units used in the process; and (3) heat or work inputs into the process. Stoichiometric calculations have been assumed. Based on these data, Hysys calculates flow rates, compositions, and state conditions of all outlet material streams, as well as heat and work output of all energy streams. A coal-based 400 MW-IGCC plant, illustrated in detail flow sheet by IEA Greenhouse Gas R&D Programme,8 has been first selected as the simulation base case to trace the final purpose of a simulated bitumen-coke IGCC plant. After consistent results for mass and energy balances between simulated and published coal plant data were obtained, the required modifications to transpose the simulations to bitumen-coke IGCC plant were applied. Table 2 shows specifications of the gasifier inlet streams, which are assumed to be constant in all plants configurations. The flow rates of gasifier inlet streams were estimated by assuming ∼98% consumption of the carbon contained in the fuel. The proposed bitumen-coke power plant for supplying the required energy and hydrogen for bitumen recovery and upgrading must be located near the oil sands reservoirs. In this study, the feasibility of Alberta natural brines for CO2 sequestration via mineral carbonation is assessed. For geographic proximity requirements, northeastern and eastern Alberta (Athabasca oil sands region) was spotted particularly (Figure 2). Four Devonian aquifers are present in the Alberta area, which form two aquifer systems, a Middle-Upper Devonian Aquifer System (MUDAS) consisting of the Elk Point and WoodbendBeaverhill Lake aquifers and an Upper Devonian Aquifer System (UDAS) consisting of the Winerburn and Wabamun aquifers.16 Formation waters in Lower Elk Point strata of northeastern Alberta contain a high concentration of Ca2+. In this area, resource of calcium in formation waters is in the order of 200 000-600 000 tonne/km2. The geographic region, for which industrial mineral resources are estimated, covers ∼210 000 km2. Lower Elk Point aquifer has been selected to use its specific characteristics as a basis for simulation of CO2 mineral trapping with natural brine. This aquifer lies 1000-3000 m below the ground. At the depth of 2000 m, the average concentration of calcium ions is 60 000 mg/L.17 At this depth, typical pH of the aquifer is ∼ 7.0 and its temperature and pressure are approximately 50 °C and 15 MPa, respectively.18 The thickness of the related formation differs from 20 to 100 m, and its porosity ranges from 8 to 20%.17 For the purpose of CO2-brine process investigation, the average thickness and porosity were assumed as much as 40 m and 14%, respectively. As stated earlier, an optimum temperature for CO2/brine reaction has been reported as high as 50 °C. Elk Point aquifer at a depth of 2000 m has a temperature of ∼50 °C. Since the fluid temperature will diminish during its rise from the underground to the surface, the makeup power to warm the brine to 50 °C was estimated. Related aspects such as (1) enthalpy evaluation for CO2/brine reaction, (2) solution enthalpies of a chemical that is used for pH adjustment, and finally (3) required sensitive heat for CO2/brine system to gain 1 °C were accounted for, from which it can be concluded that using NaOH as pHadjusting chemical, the dissolution of NaOH and reaction enthalpies could compensate temperature of the brine up to a 12 °C drop. Otherwise, if the brine reaches the surface at a temperature of
