Global Refining Strategies So in Refining Text

8/8/2019 Global Refining Strategies So in Refining Text

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CANSOLV SO2 Scrubbing

in Refinery Applications

By: R.W. Birnbaum

Sales Manager

CANSOLV Technologies Inc.

400 Boul. De Maisonneuve Ouest, Suite 200

Montreal, QC, Canada

H3A 1L4

Ph: +1 514 382 4411 ext 225

[email protected]


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Cansolv Technologies Inc. - Page 2

Abstract

CANSOLV SO2 Scrubbing in Refinery Applications

Tighter regulations, an increasing spread between sweet and sour crude prices and attractive

revenue opportunities for sulfur and its byproducts have led refiners to increase their use of highsulfur fuels internally and install flue gas desulfurization systems to capture SO2.

The CANSOLV SO2 Scrubbing system has been in use commercially since 2002 and a total ofnine units are now operating worldwide. These units capture SO2 from fluid cat cracking (FCC)unit regenerator offgas, fluid coker CO Boiler offgas, lead and copper smelter offgas, sulfur planttail gas and sulfuric acid plant tail gas.

This paper will illustrate how the CANSOLV SO2 Scrubbing system can be used effectively inthe refinery to control emissions and capture additional byproduct value from flue gas streamsgenerated by the FCC, refinery process heaters, sulfur plants and spent acid regeneration units.

Process flow sheet information and specific utility consumption guidelines will be provided toallow the refiner to consider how a CANSOLV SO2 Scrubbing System will fit into applicationsat his location.


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Various technical issues must be addressed in order to take advantage of the price gap betweenlight and heavy crudes, however. By definition, heavy crudes produce a heavier slate of productscontaining greater amounts of sulfur. Major investments in bottoms processing capacity arerequired that would also need additional investments in hydrogen and hydroprocessing capacityfor all products, and additional sulfur conversion capacity. Processing schemes must also bereviewed to ensure that product quality does not suffer. Additional investment may be needed to

preserve octane, cetane and vapor pressure requirements of distillate products or to removebenzene and other aromatics generated by new bottoms processing units.

Changing markets for bottoms products, tighter environmental regulations and increasing costsfor natural gas will require renewed examination of utility systems.

- Shrinking markets for high sulfur residuum or coke will incent the refiner to incorporatethese materials into his refinery fuel balance. Co-gen or heater re-fueling projects canabsorb part of an unmarketable bottoms stream, but additional SOx, NOx and particulatecontrols will be needed to accommodate the use of poorer quality fuels.

- Increasing prices for natural gas or refinery gas will incent the refiner to conserve thesecommodities for use as hydrogen plant feed. Converting process heaters from gas to oilmay be justifiable.

- Demand for fertilizers by India, China and the worldwide biofuels markets, is expected tocontinue to exert pressure on sulfur and its byproducts for the foreseeable future. Ifbyproduct sulfur prices remain high, regenerable SO2 capture projects will be betterpositioned to serve refinery wide emission reduction campaigns.

- Higher alkylate demand, higher sulfuric acid costs and tighter markets for acid mayincent the refiner to install stand alone spent sulfuric acid regeneration (SAR) systems.Excess acid capacity, beyond alkylation needs, would provide an additional outlet forH2S generated by the refinery, a partial backup to existing sulfur recovery units and asecond revenue stream for sulfur.

Environmental pressures also must be addressed. Permits to expand or modify processing unitswill void grandfathered emissions allowances and force the installation of additional end ofpipe wastewater and flue gas treatment systems. Tighter environmental emission limits can bemet by re-directing sulfur compounds that are now discharged into the wastewater and the air toother disposal points, such as the SRU.

Many of the strategic pressures facing the refiner will require additional attention to be paid to itsoverall sulfur balance. Non regenerable SO2 scrubbing systems will only increase costs as thecost for reagents such as sodium hydroxide, lime or limestone increase. Further, tighterenvironmental controls will likely limit the ability to dispose of gypsum to landfill or to disposeof sodium sulfate into refinery wastewater streams. Regenerable SO2 scrubbing systems canhelp ease many of the environmental and market induced pressures that are associated with theuse of greater quantities of opportunistic crudes.

The CANSOLV SO2 Scrubbing System, operating commercially since 2002, has proven itself tobe able to satisfy all of the SO2 capture needs described above.

- CANSOLV SO2 Scrubbing Systems have been in operation in FCCU and Fluid CokerCO boiler flue gas SO2 Scrubbing applications since 2006.


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- CANSOLV SO2 Scrubbing Systems have been in operation in a Claus Sulfur RecoveryUnit and a SAR tail gas unit since 2002.

- A CANSOLV SO2 Scrubbing System will soon be operating in a 240 MW coal firedcogeneration power facility in China. This unit captures SO2 and directs it to a sulfuricacid unit.

- CANSOLV SO2 Scrubbing systems have been licensed to two refiners who will use it tocapture SO2 from flue gas generated by resid fired crude unit process heaters and utilityboiler systems.

CANSOLV SO2 Scrubbing in the Refinery

Figure 2 shows the overall processing trend for a hypothetical 250,000 BPD refinery today. Itassumes a 60%, 30%, 10% split between light distillate, heavy distillate and bottoms productdistributions. For simplicity, volumetric shrinkages or gains between feed and product streamsare not considered. Refinery gas production is ignored. A 250,000 BPD refinery is assumed toproduce 250,000 BPD of products from the same volume of crude.

Figure 2 Crude and Sulfur Scenario for Average US Refinery in 2008

Figure 2 also shows the overall sulfur balance that might apply to such a refinery. A total of535 short tons of sulfur are contained in the crude feed. 5%, 25% and 70% of the sulfur enteringthe refinery with the crude is assumed to flow to air and water waste streams, product streamsand to the SRU, respectively.

Figure 3 Crude and Sulfur Scenario for Average US Refinery in Future

Figure 3 shows the overall processing trend for the same refinery as it might appear in the future.The crude mix is heavier and contains more sulfur. The product volumetric split is now 58%,30% and 12% between light, intermediate and bottoms products, respectively.


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Figure 3 also shows how the overall sulfur balance might look, assuming that sulfur emissions toair and water have been curtailed, FCCU SO2 is captured in a regenerable scrubber and cogenfacilities have been installed to burn up to 15 kBPD of residuum or its equivalent in coke. Thetotal amount of sulfur fed to the refinery increases to 697 short ton per day. 0.1%, 14% and 86%of the sulfur entering with the crude leaves with waste streams, product streams or via the SRUrespectively.

Four significant changes to the refinery utility and sulfur systems are assumed to support thesulfur distribution scenario for the future refinery:

1) Half of the 30,000 BPD bottoms stream is retained as fuel due to soft markets for highsulfur fuel oils. The balance is sold to remaining markets for high sulfur fuels. SO2 iscaptured from the combusted resid flue gas stream in a CANSOLV SO2 ScrubbingSystem and directed to the SRU.

2) FCCU regen gas SO2 is captured and directed to the SRU through the installation of aCANSOLV SO2 Scrubbing System.

3) A SAR has been installed to regenerate spent alkylation acid catalyst and to act as acontingency disposal point for acid gas in the refinery. SO2 is directed to the acid plantfrom a CANSOLV SO2 Scrubbing System to secure a sulfur emission rate of less than 0.3lb of sulfur per ton of acid made.

4) A SRU CANSOLV SO2 Tail Gas unit is assumed to be required that increases therefinery SRU conversion efficiency to over 99.9%. SO2 is routed back to the SRU.

In each case, an SO2 scrubbing system is required to manage the additional SO2 that is emitted asa consequence of the changes. By directing resid to fuel systems, an additional 95 tons of sulfurmust be captured as SO2. Re-directing SO2 from the FCCU scrubber away from the wastewatertreatment systems increases the sulfur load on the SRU by 31 tons per day. The tail gas systemadds an additional 15 short tons per day of SO2 load on the SRU.

Four cases have been developed to illustrate how a CANSOLV SO2 Scrubbing System can beused for each case described above. Inside battery limits (ISBL) costs have been estimated andoperating costs have been derived to satisfy utility, operations and maintenance costs of the SO2system. Revenue from sulfur byproducts is also estimated to illustrate how byproduct revenuescan impact project economics.

Byproduct Values

Changing crude prices have rippled through the economy and created similar, related waves insulfur byproduct pricing. In 2007, prices for sulfur were in the $45 per short ton ($50 per metricton) range. In late 2008, sulfur prices rose to as high as $630 per short ton ($700 per metric ton).Sulfuric acid values have been similarly variable and have increased from $90 per short ton($100/metric ton) to as high as $329 per short ton ($360 per metric ton). Future byproductvalues fell at the end of 2008 and specific values are difficult to predict. For this paper, it isassumed that sulfur prices will average $250/short ton for the next 15 years.


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Case 1 SO2 Scrubbing in Co-generation application

Cogen firing Basis:

Resid Feed Rate: 15 kBPD

Sulfur in Feed: 3.6 wt%Heating Value: 17,100 BTU/lb fuelTotal Firing Rate: 3,402 MMBTU/hr 350 MW equivalent at 9,700 BTU/kW Heat Rate

In this example, residuum is fired to a utility type boiler. Steam is raised to feed power turbinesand to supply steam to the refinery. Flue gas is directed to an air to air preheater and then to anelectrostatic precipitator, where solids are removed. The cool gas flows to the prescrubbingsystem and then to the CANSOLV SO2 Scrubbing System.

The overall flue gas management systems are broken down into three discrete parts:

1)

The combustion system2) The flue gas pretreatment system3) The SO2 Management System

Cost and utility data have been established for the flue gas prescrubber and the SO2 Absorptionand regeneration system as identified as being contained in the CANSOLV Battery Limits inFigure 4.

Figure 4 - Cogen System Flue Gas Treating Flow Diagram


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Table 1 CANSOLV SO2 Cost and Utility Consumption Table Cogen Case

Resid Feed Rate - kBPD 15.0

Firing Rate - MMBTU/hr 3,402

MW Equivalent 350

SO2 Captured - short t/hr 7.9

Annual Sulfur Equivalent - short

t/yr 34,602

Flue Gas Flow Rate - kscfm 884

Flue Gas SO2 - vppm 1,833

Capital Cost - $MM1 42.0

Annual Op Cost - $MM2 14.6

Annual Byproduct Credit - $MM 8.4

Net Operating Cost 6.2

Utility Consumption

Power - kW-hr/ton SO2 970

Steam - '000 lb/ton SO2 23.3

Cooling Water - '000 gal/ton SO2 234

Note 1 Capital cost refers to inside battery limits (ISBL) total installed costs for a high laborefficiency, low material cost location. Owners costs, incremental utility capital costs andoverheads are NOT included. Costs are to be considered as ball park estimates only, for the fourcases identified.

Note 2 Operating costs are based on $3.63/000 lbs for steam, $0.06/kWh for power and

$0.08/000 gallons for cooling water. Operating and maintenance costs are estimated at 4% ofcapital annually, as is typical for low corrosion, petrochemical applications.

The inside battery limits costs for the CANSOLV SO2 Scrubbing system amount to 42.0 MMUSD and the annual operating cost is 14.6 MM USD for utilities, consumables, operation andmaintenance. The revenue opportunity for sulfur generated from the capture of SO2 amounts to$8.4 MM annually.

Case 2 - FCCU Regen Gas SO2 Scrubbing

FCCU SO2 Scrubbing Basis:

Gas Oil Feed: 87 kBPDSulfur in Feed: 2.4 wt%Regen Gas Generated: 256 scfmFlue Gas SO2 Concentration: 2,100 vppmSO2 Content of Regen Gas: 2.6 short ton/hr

This scenario is based on the refinery generating up to 87 kBPD of Cat Feed from the crudecharge of 250,000 BPD. If the sulfur content of the feed is 2.4 wt% and 10% of this is carried in


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the coke to the catalyst regenerator, a total of 2.6 short tons per hour of SO2 must be removedfrom the regen gas.

Particulate management in the FCCU is critical because particulate emission concentrations canchange quickly from low concentrations (0.04 gr/scf of gas, or 100 mg/Nm3 or) to several grainsof particulate per standard cubic foot of gas as a result of regenerator cyclone failure or catalyst

flow reversal. A venturi prescrubbing device in the flue gas conditioning system, canaccommodate these swings in particulate content of the flue gas.

Figure 5 Process Flow Diagram FCCU CO Boiler Flue Gas DeSOx Unit

Unlike the co-gen case, additional flue gas cooling is required to ensure that the gas enters theCANSOLV SO2 Scrubber at a low enough temperature for sufficient SO2 removal.


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Table 2- Operating Parameters for the FCCU CO Boiler Flue Gas DeSOx Unit

FCCU Feed Rate - kBPD 87.5


SO2 Captured - short t/day 62.4

Annual Sulfur Equivalent - short

t/yr 11,388



Capital Cost - $MM 20.0

Annual Op Cost - $MM 5.7

Byproduct Credit - $/ton S 250

Annual Byproduct Credit - $MM 2.9

Net Operating Cost - $MM 2.8

Utility Consumption

Power - kW-hr/ton SO2 1,290

Steam - '000 lb/ton SO2 17


The specific steam consumption for the Co-gen case is higher than for the FCCU case becausethe gas is not cooled and higher amine circulation and steam flow rates are needed to be sure thatthe gas is treated to specification levels of SO2. The cooling water demand is greater for theFCCU case to reflect the additional cooling load in the prescrubber system.

Table 2 shows that the ISBL TIC capital cost of the CANSOLV SO2 Scrubbing System amounts

to USD 20 MM and that the annual operating cost is estimated to be USD 5.7 MM.

Case 3 - Spent Acid Regeneration

Spent Acid Feed Basis:

Acid Plant Production Rate 400 short tons per dayTail Gas Flow Rate 22 kscfmTail Gas SO2 Concentration 4,500 vppmRecovered SO2 12 short tons per day


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Figure 6 Spent Sulfuric Acid Unit Flow Sheet

Greater thermal processing and hydrotreating of cracked products reduces the octane content oflight distillate streams. To maximize its return on octane, the refiner will wish to considerupgrading its alkylation system, resulting in the consumption of greater amounts of fresh acidand the generation of increasing volumes of spent acid. Incorporating an acid plant into therefinery process scheme reduces the reliance on outside contractors to process spent acid andallows the refiner to direct some of his byproduct H2S or elemental sulfur to the acid plant andengage in what is now a lucrative market for sulfuric acid byproduct. Alkylation units consumebetween 15 lb and 20 lb of acid per barrel. Hence a 200 short ton per day spent acid regenerationunit would be required to satisfy the local requirements of the alkylation unit. For this paper, it isassumed that an additional 200 short tons per day of acid can be sold to external customers toenhance the value proposition for the project.

Sulfuric acid plants are normally configured as single absorption and as double absorption flowschemes. Single absorption plants are generally regarded as being able to achieve in excess of99% conversion with fresh catalyst and double absorption plants can achieve conversions inexcess of 99.9%. Addition of an absorption step essentially is considered to be an equivalentprocess option to the use of a tail gas SO2 capture and recycle flow scheme.


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The CANSOLV SO2 Scrubbing system allows conversions of greater than 99.9% of the feed tosulfuric acid and it is capable of meeting a sulfur emission specification below 0.33 lbs sulfur perton of acid produced. Further, the integration of the CANSOLV System into the acid plantdesign disconnects emission values from catalyst performance and allows lean CANSOLVsolvent to be sourced from a common refinery SO2 Regeneration system. Figure 6 illustrates theflow scheme used for a spent acid regeneration unit and its CANSOLV SO2 Tail Gas Unit.

Table 3 shows some of the performance characteristics for CANSOLV SO2 Scrubbing in ahypothetical 400 short ton per day H2SO4 Spent acid facility.

Table 3 - Operating Parameters for the SAR DeSOx Unit

Acid Plant Production short t/day H2SO4 400


SO2 Captured - short t/day 12

Annual Sulfur Equivalent - short t/yr 2,200



Capital Cost -$MM 4.7

Annual Op Cost -$MM 0.4

Utility Consumption




Specific consumption rates of steam and cooling water per ton of SO2 are very much advantagedin this system as compared to FCCU and Co-Gen absorption because acid plant tail gas isconcentrated in SO2, contains no water, requires no external cooling in the prescrubber and isfree of particulates. Furthermore, the elimination of a circulated prescrubber in this design avoidsthe need for a tail gas ID fan to push tail gas through the CANSOLV SO2 Scrubbing System.

Impact on the SRU

The transition from the 2008 hypothetical refinery processing case to the 2028 case requires thatthe SRU be modified to increase elemental sulfur production from 376 short tons per day to 600short tons per day. This represents a 60% increase in SRU capacity.

The SRU design is greatly defined by gas residence time and temperature considerations in thereactor and space velocity and sulfur rundown considerations in the sulfur condensers.


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Table 4 Comparative SRU Performance at 376 short t/d and 600 short t/d

376 Short t/day SRU 600 Short t/day SRU

SRU Configuration 3 Stage 3 Stage

Conversion 100% of Equil. 98.6% 99.1%

Acid Gas Feed 1,100 lbmol/hr H2S 1,254 lbmol/hr H2S

Rxn Furnace Comb. Air 3,000 lbmol/hr 2,000 lbmol/hr

External SO2 to Rxn Furnace 0 190 lbmol/hr (dry)

Extenal SO2 to 1st

Stage Claus 0 120 lbmol/hr (dry)

Rxn Furnace Temp 2,635 Deg. F. 2,050 Deg. F.

When air is used to oxidize the necessary amount of H2S to SO2 to satisfy the sulfur reaction, theair to acid gas ratio needed to satisfy the O2 demand amounts to 2.37 moles of air per mole ofH2S converted to SO2 in the reaction furnace of the SRU. The introduction of air to the reactionfurnace introduces 1.87 moles of inert N2 per mole of H2S converted to SO2. If 60% more

capacity is required and the reaction furnace residence time must remain below a threshold level,then more than 60% of the volume of reactants must be eliminated from the reaction furnacefeed. This can be accomplished by eliminating N2 from the feed.

The primary concern in SRU design is to ensure that temperatures remain above 2,300 Deg. F.where NH3 is a component of the SRU feed, or to keep conversion temperatures above 2,000Deg. F. where only hydrocarbons are present in the acid gas. Acid gas and air preheat can beused to increase reaction furnace temperatures and part of the SO2 can be bypassed to the 1

stClaus stage to prevent flame cooling. This case is configured to ensure that the reaction furnacetemperature does not drop below 2,000 Deg. F.

Table 4 illustrates the operating conditions of a 3 stage Claus SRU, designed to produce 376short t/day of sulfur and the 600 short t/day unit that is fed 310 lbmol/hr of externally sourcedSO2. For the 376 t/day case, a total of 4,100 lbmol/hr of air and acid gas is fed to the SRUreaction furnace. For the 600 t/day case, a total of 3,564 lbmol/hr of air and acid gas is fed to theSRU reaction furnace.

Similarly, the feed to the first stage Claus reactor for the 376 t/day and 600 t/day cases is 3,900lbmol/hr and 3,400 lbmol/hr, respectively.

The conclusion to be drawn from Table 4 is that the existing SRU reaction furnace and reactorsare sufficient to handle increased sulfur loads in the future refinery if NH3 is not a feed

component of the SRU. It will be important, however, that design checks of items such as sulfurcondenser duties, rundown and pumpout capacities and the approach to the sulfur dew pointtemperature in the reactors be performed.

Case 4 - CANSOLV SRU Tail Gas Scrubbing

In some cases, the upgrade of the refinery will require the addition of an SRU tail gas cleanupsystem. This can also be satisfied by the installation of a CANSOLV SO2 Scrubber as part of theSRU expansion.


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Table 5 - Operating Parameters for the SRU CANSOLV Unit 97% Conversion Basis

SRU Production short t/day Sulfur 600


SO2 Captured - short t/day 36.0

Annual Sulfur Equivalent - short t/yr 6,570



Capital Cost -$MM 7.1

Annual Op Cost -$MM 1.2

Utility Consumption




In this case, operating costs do not include a natural gas consumption cost and steam productioncredit for the tail gas thermal oxidizer, which are outside of the CTI scope.

Extensive flue gas cooling is required to cool the gas to absorber conditions and to remove thewater formed from the Claus reaction. The prescrubbing system must purge 44 gpm, or 7.3 tonsof water per ton of SO2 captured by the tail gas system. On an SRU basis, this translates to 0.4tons of water per ton of sulfur directed to the pit.

Comparison to Non Regenerable Systems

Byproduct Management

Non regenerable SO2 Scrubbing systems that are in wide use today most often use sodiumhydroxide, lime (calcium oxide) and limestone (calcium carbonate) as reagents to remove SO2from flue gas streams. Prices for reagents have varied greatly. NaOH has ranged between$200/t to $800/t. Its supply is tied to energy prices and markets for chlorine, a byproduct ofNaOH. Lime has varied between $129/t and $170/t since 2006 and limestone has held steady at acost of between $10/t and $20/t at the quarry, delivery costs are extra. The delivered costs ofNaOH, lime and limestone might average $300/t, $100/t and $30/t for the purposes of thisexample.


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Table 6 Non Regenerable SO2 Scrubbing Reagent Requirements

Product Consumption lb reagent

per pound of

SO2

Equivalent

Consumption/Cost

(st/d; $MM/yr)

of Reagent for Co-

Gen Case185 t/d SO2

Equivalent

Consumption/Cost

(st/d; $MM/yr)

of Reagent for

FCCU Case62 tpd SO2

Calcium carbonate (limestone) 1.56 300/$3.2 MM 100/$1.2 MM

Calcium hydroxide (lime) 1.15 220/$7.9 MM 70/$2.6 MM

Sodium hydroxide solid 1.25 240/$26.0 MM 80/$8.5 MM

Non Regenerable Waste Management

SO2 is absorbed as the sulfite or bisulfite of the sodium or calcium salt. It must be oxidized tothe sulfate form of the salt in an air blown contactor and discharged to waste in order tominimize its chemical oxygen demand (COD). As shown in Table 7, a ton of SO2 generates over

two tons of waste (dry basis) when converted to the sulfate of the salt.

Table 7 Waste Production/Disposal

Pounds of dry Waste

Material Generated (as SO4)

per pound of SO2 Removed

Co-Gen Case

Waste Generated st/d;

$MM/yr at $20 per

ton dry basis

FCCU Case

Waste Generated st/d;

$MM/yr at $20 per ton dry

basis

Calcium carbonate

(limestone)

2.13 (solid waste) 403/ $3.0 MM 132/ $1.0 MM

Calcium hydroxide

(lime)

2.13 (solid waste) 403/ $3.0 MM 132/ $1.0 MM

Sodium hydroxide 2.22 (liquid waste) 419/ $3.0 MM 137/ $1.0 MM

Waste management costs represent a significant portion of the overall operating cost for a nonregenerable SO2 scrubbing system.

Conclusions

Overall, CANSOLV SO2 Scrubbing Systems installed in four locations in the refinery willcapture 300 short tons per day of SO2 (150 short tpd sulfur equivalent) that will balance thegrowing load of H2S generated by the hydrotreaters. The addition of both SO2 and H2S to theClaus plant feed will help avoid major additional investment in sulfur recovery facilities.

A total of nearly USD 74 MM of capital is required to install four SO2 capture and solventregeneration systems in this hypothetical 250,000 BPD refinery. Incremental annual operatingcosts of $23 MM for the SO2 capture systems is expected, but most of this cost will be offset bya byproduct revenue stream that could generate up to $14 MM annually.

The net operating cost for CANSOLV vs non regenerable solvents, inclusive of byproductrevenues, is lower than that for lime and sodium hydroxide based non-regenerable systems. It is


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greater than for limestone based scrubbing systems, if the delivered price of limestone is $30 perton or if the average sulfur price over the life of the project exceeds $250/t.

Capital cost savings can be obtained in this example. This scenario has considered that four SO2Absorbers and Regenerators are required to satisfy this project and a stand alone island designconcept has been considered. An island concept is not essential to the design. CANSOLV SO2

Absorbers can be located remotely from the regenerator and lean and rich CANSOLV DS pipingcan be run through the refinery to serve each island. A common SO2 solvent regenerationsystem, located adjacent to the H2S Amine regenerator, SRU and SAR areas, will allow the SRUand SAR to back each other up as disposal points for either excess H2S or SO2 produced by therefinery.

The maturity of the CANSOLV SO2 Scrubbing system and its successful use in a number ofindustries now allows the refinery to consider SO2 capture as simply another utility system. Itcan be applied on a refinery wide basis, much as is already done for H2S capture systems.

R. Birnbaum

December 1, 2008

References

1) Blume, A.M. and Yeung, T.Y. Analyzing Economic Viability fo Opportunity Crudes Petroleum Technology Quarterly Q3, 2008 p.p. 67 732) Couch, K.A.; Glavin, J.P.; Johnson, A.O. UOP LLC Impact of Bitumen Feeds on the

FCCU: Part 1 - Petroleum Technology Quarterly Q3, 2008 p.p. 23 283) Energy Information Administration - World Crude Oil Prices, website

tonto.eia.doe.gov/dnav/pet/pet_pri_wco_k_w.htm4) Energy Information Administration Crude Oil Input Qualities website

tonto.eia.doe.gov/dnav/pet/pet_pnp_crq_dcu_nus_m.htm

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