using the bottom of the barrel as refinery fuel' paper … · ‘using the bottom of the...
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CANSOLV Technologies Inc. 400 Boul de Maisonneuve, Suite 200, Montréal Québec H3A 1L4 Tél. (514) 382-4411 Fax : (514) 382-5363 E-mail : www.CANSOLV.com
‘Using the Bottom of the Barrel as Refinery Fuel’
Presented at the ERTC Conference, Vienna, 13th November 2012
By Joe Gelder, CANSOLV Technologies Inc (an affiliate of Shell Global Solutions BV)
The MARPOL Annex VI Regulation reduced the sulphur content in marine bunker fuel oil to 1.0wt% maximum in 2010 in SOx Emission Control Areas (SECAs) and this limit will reduce to 0.1wt% maximum in 2015. These SECAs include Northern Europe and US coastlines. Subsequently, the demand for heavy fuel oil is expected to fall dramatically and the future outlet for residue streams is reduced. Refiners which supply into the marine market, impacted by the regulation, without a sufficient degree of residue upgrading and de‐sulphurization capacity, must change crude diet, invest in residue (hydro) conversion capacity, rely upon blending high value distillates into the residue streams to meet the new sulphur specifications or continue to sell heavy fuel oil at an economic penalty. As a more economic alternative, refiners could use residue as refinery fuel oil, particularly in gas constrained regions, provided that they can meet local flue gas SOx emission targets. Cansolv Technologies Inc., an affiliate of Shell Global Solutions International BV, provides a proven technology to reduce SOx from flue gases to environmental limits and produce a pure, water saturated SO2 stream. This can either be recycled into the refiner’s Sulphur Recovery Unit (SRU) or converted into sellable Sulphuric Acid. This paper takes a typical European refinery configuration and discusses the refinery economics of burning refinery fuel oil in its existing units. The paper very briefly introduces the CANSOLV SO2 Capture and Recycling System and compares its capital and operating costs, to treat the flue gas produced when burning refinery fuel oil, against other non‐regenerable flue gas de‐sulphurization systems. Introduction The refining industry continues to be subject to supply side pressures to process more difficult crudes, while being forced to respond to ever tighter limitations on product sulphur content. It is expected that after 2015, a large percentage of the marine bunker fuel oil market in North America and Europe will move from high sulphur residue fuel oil to lower sulphur distillate material, because of the Marpol Annex VI Regulation. Investment in the bottom of the barrel hydrocracking or coking systems is economical for large volumes of residue, but options are limited when smaller volumes of high sulphur products must be accommodated. In addition to burning residue in Co‐generation Power Projects (1), of which CANSOLV has two projects under construction, mechanical conversion of certain refinery furnaces and boilers to burn residue, in addition to gas, provides flexibility to the refiner to take advantage of higher price differentials between natural gas and high sulphur residue. These projects require some minimal investment to the burners etc., to enable the burning of high viscosity material and they also require investment to install SO2 scrubbing, to meet SOx emissions limits to atmosphere. Combustion of modest quantities of residue streams inside the refinery reduces the refiner’s reliance on external, purchased balancing fuels, such as natural gas. It also increases the refinery planner’s ability to fill the refinery crude slate with cheaper, high sulphur crudes, to maximize margins, since the residue can be burnt rather than incurring the penalty of producing high sulphur Marine Fuel Oil (MFO), with a limited and low market value. Finally, the refiner will use less valuable cutterstock to achieve MFO viscosity and sulphur specifications, if there is less residue to sell.
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SO2 scrubbing can be achieved by non‐regenerable and regenerable means. Non‐regenerable systems consume an alkaline agent such as sodium hydroxide, limestone and dry lime and generate a waste stream of sodium sulphate or gypsum. Sodium sulphate is disposed of to wastewater treatment systems, while gypsum is disposed of in a landfill site. Regenerable systems use an alkaline agent such as sodium sulphite or CANSOLV DS Amine, to capture SO2 and release it in pure form from a regenerator that is designed to split the reagent from the SO2. The non‐regenerable systems transfer an air pollution problem to water or landfill. Regenerable systems produce a high value, marketable product such as elemental sulphur, or 98% sulphuric acid. In the refinery, a pure stream of SO2 from a regenerable system can help to de‐bottleneck existing refinery Sulphur Recovery Units (SRU), that are often under pressure to absorb greater quantities of H2S from new or modified hydrotreating systems elsewhere in the refinery. The recycled SO2 from an external source, such as that captured from a residue burning facility reduces the quantity of H2S combusted to produce SO2 in the Claus Unit (within its temperature limits). This in turn reduces air requirements and inert N2 ingress, which consequently enables higher throughputs of acid gas into the SRU. The CANSOLV SO2 scrubbing system has de‐bottlenecked one such SRU in a refiner in the USA and enabled it to increase its SRU capacity by 12.5%, without Claus Unit modifications. This paper reviews the ‘high level economics’ of burning high sulphur residue, instead of natural gas, in suitable furnaces (in this case, the Crude Unit ‐ CDU) on a typical European refinery configuration of average complexity (Nelson Index between 6 and 7), of average crude throughput (20,000 MT/day), processing 50% high sulphur (>1.0wt% sulphur) and 50% low sulphur (0.5wt% sulphur <) crudes. The refinery process units include a Thermal Cracking Unit (TCU) and a Fluid Catalytic Cracking Unit (FCCU). The capital and operating costs of the CANSOLV system and other non‐regenerable SO2 scrubbing systems are considered in the economics. CO2 capture and recycling in the CANSOLV DC‐103 Amine Unit is not considered in this paper in view of the fact that the price of 1MT of CO2 under the European Emissions Trading Scheme (ETS), is currently relatively low (approximately $20/MT) and expected to remain at this level for some time. The price of emitting additional CO2, however, is included in the economics. Case study no.1 assumes the refinery can still sell its MFO with its present sulphur content of 2.14wt%. It determines the maximum level of residue that can be burnt continuously in the CDU furnaces, with minimal investment to the burners etc. The residue is blended with Light Cycle Oil (LCO) or cracked gas oil (cutterstock) into internal Refinery Fuel Oil (RFO), to meet maximum viscosity limits. Any RFO that can be burnt is assumed to reduce the amount of imported fuel, assumed to be natural gas, to the refinery. The economic benefits of burning RFO include the differential in price between natural gas and cracked residue (as defined by its value in 2.14% sulphur MFO) and cutterstock savings. The study assesses the project Net Present Value (NPV) for six different scenarios, assuming different fuel price differentials and CO2 taxes, using CANSOLV and three non‐regenerable SO2 Scrubbing systems. Case study no.2 assumes the ‘Typical Refinery’ has no choice, but to produce MFO with a maximum sulphur spec of 1.0wt% and thus any residue, which is burnt, yields far greater cutterstock savings. SO2 Scrubbing Options SO2 Scrubbing systems are composed of five or six process blocks (Figure 1). The non‐regenerable system includes a reagent preparation area and a gypsum filtration area for lime and limestone. Caustic requires no reagent preparation or byproduct management block, since Caustic is sourced as a bulk liquid and sodium sulphate is discharged to waste water treating systems as a dilute solution of sodium sulphate. The non‐regenerable systems, by definition, do not have a regeneration block.
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The regenerable systems have little or no reagent preparation area, but dedicate significant resources and space to solvent regeneration. While both regenerable and non‐regenerable systems can produce a saleable byproduct, it is more common for the non‐regenerable systems to direct their product to waste, as markets for ammonium sulphate, sodium sulphate or gypsum are limited. This contrasts with the regenerable systems that direct SO2 into the sulphuric acid or elemental sulphur markets. Sulphur is a by‐product of most refineries and SO2 can often be readily absorbed by the existing SRU and product management systems that are already in place.
Figure 1 – Process Subsystems for Flue Gas De‐sulphurization Systems Table 1 compares the process areas required for several common non‐regenerable systems and the CANSOLV SO2 Scrubbing System. Area CANSOLV NaOH Limestone Lime Spray DryReagent Prep ‐ ‐ Grinding and
Storage Storage and Slaking
Pre‐scrubbing Upstream of Absorber
Incorporated in Absorber
Incorporated in Absorber
Incorporated in Absorber
Absorber Type Packed Multiple Spray Multiple Spray Spray AtomizationRegeneration Steam Strip ‐ ‐ ‐ Waste Management Minor blowdown
from prescrubber and amine purification system
Na2SO4 to Wastewater
CaSO4, Dry Filter Cake to landfill
CaSO4, Dry Filter Cake to landfill
Byproduct Recovery Sulphur Plant Sulphuric Acid Liquid SO2
‐ Gypsum ‐
Table 1 – Process Subsystem Requirements – Regenerable and Non‐Regenerable Scrubbing Systems Caustic systems have lower capital costs than other non‐regenerable systems, because the reagent is purchased as a concentrated liquid and wastes are directed to the refinery wastewater treatment system. Caustic is an expensive by‐product of chlorine manufacturing systems and its cost is quite volatile and depends on the world demand for chemical products such as vinyl chloride. Sodium carbonate and sodium bicarbonate are less expensive alternatives to caustic and can be substituted for caustic, but their cost is higher than for limestone or lime and they require investment for reagent materials management systems. Capital costs for limestone and lime based systems are advantaged versus the regenerable systems. Although investment is required for reagent preparation and by‐product or waste management, no investment is required for solvent regeneration systems.
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Regenerable systems have a higher capital cost than any of the non‐regenerable systems since complex solvent regeneration and by‐product conversion systems are required. Instead of consuming non‐regenerable reagents, the regenerable systems consume relatively large quantities of steam, electricity and cooling water to separate the SO2 from the reagent. In summary, site specific economics and the amount of SO2 that must be captured from a given flue gas stream, dictate whether a regenerable system is favoured over a non‐regenerable system or not. Regenerable systems are most incentivised over non‐regenerable systems when:
a. Fuel sulphur content in the fuel is high b. Low pressure steam costs are low c. Access to alkaline reagents is limited d. Access to wastewater or waste landfill systems is limited
Non‐regenerable systems are most incentivised over regenerable systems when:
e. Fuel sulphur content in the fuel is low f. Low pressure steam costs are high g. Free access to alkaline reagents is available h. Free access to wastewater and solid waste disposal sites is available
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Case Studies – ‘Typical Refinery’ – 20,000 MT/day Crude An economic comparison was made between the CANSOLV System and non‐regenerable systems’ CAPEX and OPEX costs to burn cracked residue, in the form of RFO, continuously on the Crude Unit furnaces of a typical European refinery. These costs and the additional gross margin to the refinery are used to determine project NPV, for a variety of scenarios. The following assumptions apply:
1) Refinery has a crude throughput of 20,000 MT/day. 2) ‘Medium’ complex refinery of Nelson Total Complexity Index between 6 and 7, including a TCU and FCCU. 3) Crude diet is a mixture of 50% high (>1.0wt% sulphur) and 50% low (0.5wt% sulphur<) sulphur crudes. 4) Average conversion level applied in the TCU ‐ residue make is 77.5%. 5) Cracked residue outlet for the base case is Marine Fuel Oil (MFO) ‐ specification RMG380. 6) The RMG380 specification is met by the addition of internal cracked gasoil and LCO as external cutterstock.
This equals 32% of the MFO blend for Case Study no.1 and 79% for Case Study no.2. 7) For internal RFO consumption, the RFO maximum viscosity is determined by the burners' tips and
temperature in the fuel oil system (<20 cSt). RFO specifications can be less conservative dependent on the refinery layout. If fuel oil heaters are available, higher viscosity of the RFO can be accepted with a bigger saving of cutterstock.
8) The fuel oil system is kept warm by low pressure steam (148°C). 9) Differential in price between high value products and MFO, for cutterstock, is $300/MT that produces
additional refinery margin, if cutterstock is not blended into MFO. Cutterstock, other than LCO, is possible dependent on availability. Margin gain due to cutterstock savings may change dependent on the effectiveness and price of cutter used.
10) Furnaces in which RFO could be fired are considered if they meet the following criteria: a. correct burner size b. fouling propensity will not interfere with furnace run length. CDU furnaces are found suitable for
fuel oil firing whereas TCU furnaces are not included as the furnace run length reduction would be significant.
c. only minor modifications required (i.e. burner change to enable 100% fuel oil firing) 11) Identified furnaces to burn RFO are approximately 50% of the refinery’s total standard refinery fuel (SRF)
requirement. 12) Furnaces requiring replacement, thus incurring high CAPEX, are excluded as potential RFO burning options
from this study. 13) 100% fuel oil firing (as RFO) is assumed for the furnaces considered in fuel oil firing service. Thus:
a. 14.3% of the produced cracked residue can be used as RFO in these furnaces (e.g. CDU furnaces) b. 85.7% of the produced cracked residue is sold as commercial fuel oil (such as MFO)
14) Extra operating cost for the furnaces (OPEX) is associated by fuel oil firing due to extra maintenance requirements.
15) Assumption that there is no surplus of refinery fuel gas in the refinery and that RFO firing will reduce the cost of import of natural gas.
16) Assumption that CDU operates 365 days/year and turnarounds are not included. 17) Assumption that natural gas price is 400$/t (~ $8/MMBTU). European natural gas spot annual average prices
are forecast to be between $8 and $10 / MMBTU, 2014 to 2020 (2). 18) Assumption that burning RFO produces twice as much CO2 per unit of energy than natural gas firing. 19) Assumption that the SRU has a capacity of 300MT/day sulphur. 20) Project has a 25 year life and has straight line depreciation. 21) Net Present Value is calculated over 25 years. 7% Discount Rate. 22) Price of utilities and chemicals (see Table 4 below) remains the same over the project lifetime.
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The following six scenarios have been run for case study no.1, which determines the economic benefit of burning RFO in the CDU furnaces, thus saving imported natural gas costs and saving the costs of using valuable cutterstock to produce MFO at a current sulphur content of 2.14wt%. :
(Case Study 1‐1) : Natural Gas Price – Residue Price = 200 $US/MT, CO2 Price = 20 $US/MT (Case Study 1‐2) : Natural Gas Price – Residue Price = 300 $US/MT, CO2 Price = 20 $US/MT (Case Study 1‐3) : Natural Gas Price – Residue Price = 400 $US/MT, CO2 Price = 20 $US/MT (Case Study 1‐4) : Natural Gas Price – Residue Price = 200 $US/MT, CO2 Price = 40 $US/MT (Case Study 1‐5) : Natural Gas Price – Residue Price = 300 $US/MT, CO2 Price = 40 $US/MT (Case Study 1‐6) : Natural Gas Price – Residue Price = 400 $US/MT, CO2 Price = 40 $US/MT
Additional gross margin to the refinery, from burning RFO in the CDU furnaces =
Imported fuel cost savings (as natural gas) + Extra gross margin from using cutterstock in high value fuels instead of blending into MFO ‐ The loss in sales value of the cracked residue (as MFO) ‐ The additional operating cost of burning RFO continuously in the CDU furnaces ‐ Cost of emitting additional CO2 ‐ The operating cost of the CANSOLV Unit
Table 2 – Case Study (1‐1) Economics – CANSOLV System (CAPEX and OPEX costs only refer to Furnace costs) For the different case study 1 scenarios, the feasibility of the project is dominated by the difference in value between the imported fuel and the cracked residue (assumed to be $US200 to $US400 / MT in this paper). Refiners which face high imported gas costs or which sell MFO at crude price or less may wish to evaluate residue burning as an option to increase profitability.
Viscosity at 50°C
Specific gravity [D15/4] Sulphur Amount
Additional Refinery Gross
Margin
CAPEX of Furnace
Modifications
[cSt] [wt%] [kt/year] (MUSD/year) [MUSD]1) Commercial Marine Fuel Oil (base case) 380 0.9892 2.14 1165.8 0 02) Residue Burning in CDU Furnaces Internal Refinery Fuel Oil 2251 0.9928 2.44 141.6 -32.6 Commercial Marine Fuel Oil 380 0.9892 2.14 998.6 0 Saved natural gas 140.4 56.2 Saved cutterstock 25.4 7.6 OPEX of Furnace Modifications -1.6 CO2 Cost -4.3 OPEX of CANSOLV Unit -7.4
17.8
20,000 MT/day Crude 'Typical Refinery'
4.2
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The following scenario has been run for case study no.2, which determines the economic benefit of burning RFO in the CDU furnaces, thus saving imported natural gas costs and saving the costs of using valuable cutterstock to produce MFO at a sulphur content of 1.00wt%. :
(Case Study 2‐2): Natural Gas Price – Residue Price = 200 $US/MT, CO2 Price = 40 $US/MT
Table 3 – Case Study (2‐2) Economics – CANSOLV System (CAPEX and OPEX costs only refer to Furnace costs) For the different case study 2 scenarios, the feasibility of the project is dominated by the difference in price between MFO and high value products (assumed to be $US300/MT in this paper). Refiners who have no choice but to blend high volumes of cutterstock, that could be used to make high value products, into residue in order for the MFO to be sold, should consider residue burning as an option to increase refinery profitability.
Additional CAPEX of20,000 MT/day Crude 'Typical Refinery' Viscosity at 50°C Sulphur Amount Refinery Gross Furnace
Margin Modifications[cSt] [wt%] [kt/year] (MUSD/year) [MUSD]
1) Commercial Marine Fuel Oil (base case) 8 0.9758 1.00 3827.4 0 02) Residue Burning in CDU Furnaces Internal Refinery Fuel Oil 2251 0.9928 2.44 141.6 -32.6 Commercial Marine Fuel Oil 8 0.9758 1.00 3278.4 0 Saved natural gas 140.4 56.2 Saved cutterstock 407.4 122.2 OPEX of Furnace Modifications -1.6 CO2 Cost -8.7 OPEX of CANSOLV Unit -7.4
128.1
4.2
Specific gravity [D15/4]
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The following charts present the NPV and Additional Refinery Gross Margin for each scenario stated above, for all the SO2 scrubbing options. All the $US values on the Y‐Axes of have been normalized, by dividing the calculated NPV and Additional Margin of each scenario, by the Total Installed Cost (TIC) of the CANSOLV SO2 Capture and Recycling System.
Case Study no.1 Economics – Normalized to the TIC of the CANSOLV SO2 Capture and Recycling System.
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CANSOLV Technologies Inc. 400 Boul de Maisonneuve, Suite 200, Montréal Québec H3A 1L4 Tél. (514) 382-4411 Fax : (514) 382-5363 E-mail : www.CANSOLV.com
The charts above indicate that the NPV for the project, using a CANSOLV SO2 Capture and Recycling System, is between 1.8 and 7.5 times the TIC of the CANSOLV System, over its lifetime of 25 years, using the assumptions stated in this paper. The NPV values depend very much upon the difference in price between the imported fuel and the cracked residue, as blended into MFO, or any other heavy fuel oil. The price of CO2 has a moderate impact upon the NPV of the project. The NPV values for the project are slightly higher for the CANSOLV System over the non‐regenerable SO2 scrubbing options. Case Study no.2 Economics – Normalized to the TIC of the CANSOLV SO2 Capture and Recycling System.
As can be seen above in the Case Study no.2 Economics, if the ‘Typical Refinery’ must blend cracked residue with cutterstock to produce a 1.0wt% sulphur MFO, the potential for cutterstock savings are very large and the NPV of the project is 25 times the TIC of the CANSOLV System. Alternatively, the refiner just processes low sulphur crudes to meet the MFO sulphur specifications and is penalized with higher crude prices. The NPV values for the project are very similar for the CANSOLV System and the non‐regenerable SO2 scrubbing options. The CANSOLV SO2 Capture and Recycling System
Figure 2 – CANSOLV SO2 Scrubbing System Process Flow Diagram
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Figure 2 shows the key elements of the CANSOLV SO2 Capture and Recycling System, which are downstream of the particulate removal system (Dry ESP, Water Scrubbers) and possibly a de‐NOx system.
• The flue gas is quenched in an open spray or venturi water pre‐scrubber to its adiabatic saturation temperature. A cooler on the circulating water loop may be sized to achieve sub‐cooling of the gas, depending upon the SO2 emission specifications from the SO2 Absorber.
• The flue gas may be directed to a Wet Electrostatic Precipitator (WESP ‐ not shown in drawing above), to reduce the SO3 content, before entering the SO2 Absorber.
• The SO2 Absorber may be integral or separate from the pre‐scrubber. SO2 is absorbed in the circulating CANSOLV amine to the required threshold for environmental compliance.
• Flue gas leaving the SO2 Absorber may be post treated in a caustic scrubber to comply with very low SO2 emission requirements or to precondition the gas for a future downstream CANSOLV CO2 Capture and Recycling System.
• Rich solvent containing the captured SO2 as an unstable salt flows to the SO2 Regenerator. • Low pressure steam is used to recover the SO2 from the unstable salt in the SO2 Regenerator. • Lean solvent is flows from the SO2 Regenerator back to the SO2 Absorber. • Pure, water wet SO2 (90‐95vol%) flows to the battery limits and on to by‐product processing systems. • An Amine Purification Unit removes sulphate, either absorbed from the flue gas as SO3 or generated via
disproportionation and other Heat Stable Salts (HSS) in the CANSOLV System. Figure 3 shows the capital and operating costs for all the SO2 Scrubbing options to treat the CDU furnace flue gas from the ‘Typical Refinery’ in the two case studies above when burning RFO continuously, all normalized to the TIC for the CANSOLV System. The chart illustrates that the capital cost for the CANSOLV system is higher than for the non‐regenerable systems, but that its operating cost is lower.
Figure 3 – Chart showing the relative CAPEX and OPEX of the different Flue Gas De‐sulphurization Systems, for the ‘Typical Refinery’ Case Study – all normalized to the TIC of the CANSOLV System.
The cost basis for the four cases is highly dependent on costing assumptions used for the analysis. Table 4 shows the economic assumptions and Basis of Design (BOD) used. For regenerable systems, steam represents 40% of the operating cost. For caustic scrubber systems, reagent makes up nearly 60% of the operating cost of the system. In limestone and lime systems, the reagent costs represent between 25% and 35% of the operating cost.
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BOD for CDU Furnace for ‘Typical Refinery’ Flue Gas BasisCDU Furnace ‐ RFO
Fuel Feed Rate – t/hr 16.2 Sulphur in Fuel – wt% 2.44
SO2 Capture Capacity – t/year 14,300 SO2 Content of Flue gas – vppm 2,800
Utility Costing Basis Cooling Water‐ $/m3 $0.02/m3 Steam ‐ $/ton $10.00 Electricity ‐ $/kW $0.085 DI Water ‐ $/m3 $1.80 Utility Water ‐ $/m3 $1.00 Chemicals NaOH ‐ $/t $300 Limestone ‐ $/t ‐100% NaOH $30 Lime ‐ $/t $100 Waste $/t ‐ Dry Basis Na2SO4;CaSO4 $20 Byproduct Credit – Elemental Sulphur ‐ $/t $60
Table 4 – Basis of Design (BOD) for SO2 Scrubber for CDU Furnace for the ‘Typical Refinery’ Conclusions for SO2 Scrubbing From these case studies, a regenerable CANSOLV SO2 Capture and Recycling System is competitive with non‐regenerable SO2 Scrubbing processes, to treat the flue gas from the CDU furnace at a ‘Typical Refinery’, when burning RFO at a sulphur concentration of 2.44 wt%. The additional sulphur produced in the ‘Typical Refinery’’s SRU, by recycling the SO2 into the Claus Unit, is ~ 6% of its present capacity, which should be well within the operating parameters of the Claus Unit. The NPV for the project to burn RFO in the CDU furnaces, which uses the CANSOLV System, is between 1.8 and 25 times the TIC for the CANSOLV System, depending upon the sulphur content required in the MFO, the difference in value between cracked residue and imported fuel, the difference in price between MFO and high value products and the cost per MT of CO2 emitted.
CANSOLV CO2 Capture System
The decision to burn RFO will require an evaluation of the cost impact of increased CO2 emissions on the facility. Carbon taxes are now in place in many jurisdictions that charge a penalty for each ton of carbon emitted daily. Until government levies increase, CO2 capture projects will be deferred in favour of payment of the relevant carbon tax, since CO2 Carbon Capture and Sequestration (CCS) projects are currently estimated to cost considerably more than the penalties assessed for emission of CO2. CO2 Capture technologies are being developed and implemented in a handful of demonstration projects around the world and these projects will demonstrate the feasibility and cost of capturing CO2 on a more accurate basis as they come on stream. Over the long run, capture technology costs are expected to drop as technology is demonstrated and improved. Cansolv Technologies Inc. has commercialized a CO2 capture process that is currently in construction at two demonstration sites. Figure 4 shows the process flow diagram for these projects. The first demonstration project is planned for start‐up in 2012, while the second is planned for completion in 2013 (Sask Power Boundary Dam 150 MW Coal Fired Boiler Facility). The CANSOLV CO2 Capture System is considered to be an “add on” technology to the
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CANSOLV SO2 Capture and Recycling System technology described earlier. Furthermore, the flow sheet of the SO2 system can be adjusted to integrate with the CO2 system and reduce energy consumption of the CO2 system significantly.
Figure 4 – Process Flow Diagram of the CANSOLV SO2 and CO2 Capture System For the ‘Typical Refinery’ CDU furnace case studies discussed above, approximately 430,000 t/year of CO2 would be emitted when burning RFO continuously, compared to approximately 215,000 t/yr, when burning natural gas. A CANSOLV CO2 Capture System could capture 90% of these emissions. The capital and operating costs for the CO2 system once again are driven by site specific considerations and must be evaluated on their own merit.
Conclusions Refiners of average total complexity or lower, which process high sulphur crudes and produce cracked residue for blending into a marine fuel oil market impacted by the Marpol Annex VI regulations, may want to consider burning the residue as refinery fuel oil, in its furnaces, boilers etc. Depending upon the difference between the price of imported natural gas and the value of its cracked residue, CO2 taxes, the project NPV will be approximately between 1.8 and 7.5 times the total installed cost of the CANSOLV System. The project NPV could be increased by providing flexibility to the refinery to process more high sulphur crudes or by installing fuel oil heaters to meet the viscosity specifications of the refinery fuel oil, so that it can contain even more high sulphur cracked residue.
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Refiners of average total complexity or lower, which process high sulphur crudes and produce cracked residue for blending into a marine fuel oil market that will only accept 1wt% sulphur, should consider as soon as possible burning the cracked residue as refinery fuel oil, in its furnaces, boilers etc. The project NPV is dominated by the very large savings from not having to blend valuable cutterstock into the marine fuel oil and the NPV will be approximately 25 times that of the total installed cost of the CANSOLV System. Alternatively, rather than blending large volumes of cutterstock to make low sulphur marine fuel oil, the refinery could process more expensive low sulphur crudes. In this case, the project NPV would be provided by avoiding the purchase of these more expensive low sulphur crudes. Project economics for either case study above will be more favourable for refineries which process more than 20,000 MT/day of crude. The CANSOLV SO2 Capture and Recycling System compares very favourably to other non‐regenerable De‐sulphurization Systems, when treating the flue gas produced by burning a refinery fuel oil blend of RMG380 specification. The refinery fuel oil blend is made from cracked residue streams, in a refinery which processes an equal mixture of low and high sulphur crudes. This is partly due to the receipt of sulphur credits. The recycled SO2 to the Claus Unit would increase the SRU’s capacity by approximately 6% and should be well within the capacity of the Claus Unit. The CANSOLV System also produces much less environmental waste to water or land, compared to the other systems. A CANSOLV CO2 Capture System can be installed downstream of the CANSOLV SO2 System, at a later date, when CO2 recovery economics become more favourable. Joe Gelder September 7, 2012 References
(1) Birnbaum, R. “SO2 and CO2 Emission Control with CANSOLV SO2 and CO2 Capture Systems”, Opportunity Crude Conference, 2010.
(2) Bloomberg New Energy Finance. “Q3 2012 European Gas Outlook”, 2nd August 2012.