Regulation Effects on Sulfur Facilities

Mahin Rameshni, P.E. Chief Process Engineer

WorleyParsons 125 West Huntington Drive

Arcadia, CA, USA

Phone: 626-294-3549 Fax: 626-294-3311

E-Mail: [email protected]

Sulfur Recovery Symposium Brimstone Engineering Services, Inc.

Vail, Colorado, USA September 2001

and AICHE’S 5th International Conference

March 10-14, 2002

Regulation Effects on Sulfur Removal Facilities

Table of Contents

i

Page

Abstract......................................................................................................................... i

Section 1 Introduction .............................................................................................................1-1

Section 2 Global Petroleum Market .......................................................................................2-1

2.1 Overview.....................................................................................................2-1

2.2 Impacts from New Environmental Regulations in United States .............2-4

Section 3 Evaluation of Key Elements for Higher Sulfur Recovery .................................3-1

3.1 Process Knowledge ...................................................................................3-1

3.2 Existing Process Evaluation ......................................................................3-1

3.3 Process Modifications/Optimizations.........................................................3-2

3.4 Selection of New Technology to Increase Sulfur Recovery.....................3-3

3.5 Evaluation of Existing Process Control/Possibilities of Additional ...............

New Controls ..............................................................................................3-5

3.6 Process Monitoring.....................................................................................3-6

3.7 Capital and Operating Costs......................................................................3-7

3.8 Oxygen Enrichment Configurations...........................................................3-7

3.8.1 Low-level Oxygen Enrichment (<28% O2) ..................................3-7

3.8.2 Medium-level Oxygen Enrichment (28% to 45% O2) .................3-8

3.8.3 High-level Oxygen Enrichment (>45% O2) .................................3-8

3.8.3.1 Implementation of Oxygen Burning Processes.......................3-8

3.8.3.2 Conventional Configuration for High Capacity

Expansion................................................................................3-11

3.8.3.3 Innovative Configuration for High-capacity

Expansion................................................................................3-13

3.8.3.4 WorleyParsons Latest Development “PROClaus

Process” ..................................................................................3-16

Table of Contents

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Page

Section 4 Conclusions.............................................................................................................4-1

Section 5 Bibliography ............................................................................................................5-1

Appendix

Acronyms and Abbreviations................................................................................... A-1

Figures

2-1 Crude Capacity Conversion Units .............................................................2-4

3-1 Conventional SURE Double Combustion Configuration Reusing

Existing Reaction Furnace and WHB......................................................3-12

3-2 Conventional SURE Double Combustion Configuration with New

Two-pass WHBs.......................................................................................3-13

3-3 Parallel SURE Double Combustion Configuration Using Existing

Reaction Furnace and Waste Heat Boiler as Second Thermal Stage

Providing 150% Capacity Increase .........................................................3-15

3-4 Parallel SURE Double Combustion Configuration with New Reaction Furnace and Waste Heat Boilers Providing 150% Capacity Increase ..........................................................................3-15

3-5 Parallel SURE Double Combustion Configuration Using Existing Reaction Furnace and WHB as Second Thermal Stage Providing 300% Capacity Increase .........................................................3-17

3-6 Parallel SURE Double Combustion Configuration with New Reaction Furnace and Waste Heat Boilers Providing 300% Capacity Increase ..........................................................................3-18

3-7 Three-stage PROClaus Process Flow Diagram.....................................3-19

Tables

1-1 Worldwide Sulfur Recovery Requirements...............................................1-2

2-1 Crude Quality Profile for Western European Refineries...........................2-2

3-1 Typical Sulfur Species in Claus Tail-gas Unit ...........................................3-1

Table of Contents

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Page

3-2 Different Tail-gas Processes......................................................................3-4

3-3 Comparison of Tail-gas Cleanup Processes ............................................3-5

3-4 Tail-gas Cleanup Process..........................................................................3-5

3-5 Revamp Plants Comparison....................................................................3-10

Abstract

i

The U.S. Environmental Protection Agency (EPA) announced a proposal for a 97% reduction in diesel fuel’s sulfur content in mid-May 2000. This “touch” stance translates into dropping the current 500-ppm level to 15 ppm. Fuel provisions would go into effect in June 2006. The EPA believes it has designed its proposed reduction “to include significant lead time for the introduction of new cleaner fuel into the marketplace and to ensure no disruptions in fuel supply.” However, the industry’s National Petrochemical and Refiners Association (NPRA), which supports a 90% reduction in highway diesel sulfur levels (e.g., a new cap of 50 ppm), voices its concerns that investment requirements for compliance are “immense.” The refining industry is already implementing a budget program to reduce sulfur in gasoline in the same time frame. According to the NPRA, “uncoordinated environmental programs will lead to frequent market disruptions which affect all petroleum products.”

One objective of the Clean Air Act (CAA) in the United States is to improve air quality. Managing emissions from mobile sources is becoming a more complex situation. Processing methods to meet the recent sulfur-reduction specifications for gasoline might also reduce octane in the gasoline blending streams. The drive train of new car designs will actually determine future fuel specifications. The EPA notes that “Refiners and car manufacturers must work together to develop engine technologies and cleaner fuels so that the clean-air objectives are met. Fuel sulfur concentration is a problem for new engine designs; sulfur interferes with the proper functioning of advanced emission control technologies. Reductions to 30-ppm sulfur is viewed as a ‘great first step’.” The super-clean vehicles of the future will demand near zero or sulfur-free fuels. Refiners should be thinking about sulfur-free fuels, because future cars will eventually require sulfur-free fuels. Fuel cell systems for vehicles are being researched. Methanol and low-sulfur reformulated gasolines are the most promising fuels for fuel cells. However, many challenges remain. For example, fuel types, infrastructures, unit costs, and the size of fuel cells are yet to be resolved. Refineries are already pushing the limit of total U.S. operating capacity. The NPRA has stated that the EPA’s proposed rule to establish a 15-ppm sulfur cap in 2006 goes too far. The association expressed concern that a 15-ppm cap for diesel sulfur content effective in 2006 (from its current 500 ppm) will sharply reduce available fuel supplies, leading to higher prices and increased market volatility, which could have devastating consequences. Sulfur is the only diesel fuel property that should be regulated because it is the only fuel property that significantly impairs the efficiency of the heavy-duty engine emission control devices.

Because of the environmental legislation of the European Union (EU), Western European refiners will be required to make significant processing changes. Although most refiners did not have a serious problem meeting the year 2000 requirements, a significant investment will be needed to attain 2005 standards for gasoline and diesel. The current refinery configuration in Western Europe does not

Abstract

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support the production of the product slate demanded by local markets. European refiners will have to make adjustments and investments to meet the EU’s 2000/2005 “clean” gasoline and diesel specifications. Unfortunately, the European refining industry is plagued by gasoline surpluses that have contributed to low profit margins. The sulfur content in gasoline specifications under European law is 150 and 50 ppmw (from the current 200-ppm gasoline, 500-ppm diesel) for the year 2000 and 2005 limits, respectively.

In the United States, during the year 2005, the average legal limit for sulfur in gasoline will dip to 30 ppm from a current 300 ppm and during the following year, the limit for sulfur diesel will drop to 15 ppm.

One of the future options for diesel streams is a new type of catalyst, which could mean a simple change of catalyst rather than the introduction of new sulfur removal technology. A new desulfurization technology such as Phillips Petroleum’s S-Zorb process for diesel could be introduced.

In Europe, the sulfur limit in gasoline will be 30 ppm from 2005 and a sulfur-free limit of 10 ppm will be introduced between 2005 and 2011. Conformance to Auto-I leads to a six percent increase in CO2 emissions whilst lowering the sulfur content of gasoline to 10 ppm leads to a future 4.5 percent increase in carbon releases from refineries.

Using conventional HDS units to deliver very low levels of sulfur depends on design parameters such as operating partial pressure of hydrogen, which dictates level of sulfur removal as well as catalyst life. In general, every refinery would need to invest in additional HDS capacity plant to address the lower limits for diesel.

With the sulfur content of crude oil and natural gas on the increase and with the ever-tightening sulfur content in fuels, the refiners and gas processors will require additional sulfur recovery capacity. At the same time, environmental regulatory agencies of many countries continue to promulgate more stringent standards for sulfur emissions from oil, gas, and chemical processing facilities. It is necessary to develop and implement reliable and cost-effective technologies to cope with the changing requirements. In response to this trend, several new technologies are now emerging to comply with the most stringent regulations. These advances are not only in the process technology but also in the manner in which the traditional modified Claus process is viewed and operated.

Typical sulfur recovery efficiencies for Claus plants are 90% to 96% for a two-stage plant and 95% to 98% for a three-stage plant. Most countries require a sulfur recovery efficiency in the range of 98.0% to >99.9%. Therefore, the sulfur constituents in the Claus tail-gas must be reduced further.

The following key parameters affect the selection of the tail-gas cleanup process:

Abstract

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(1) Required sulfur recovery efficiency established by the environmental agency for different countries (e.g., the EPA or EU).

(2) Feed gas composition, including H2S content, hydrocarbons, and other contaminants

(3) Existing equipment and process configuration/modifications

(4) Concentration of sulfur species in the stack gas

(5) Ease of operation

(6) Remote location

(7) Sulfur product quality

(8) Minimum unit modification for existing units

(9) Costs (capital and operating)

Depending on the process route selected, an overall sulfur recovery efficiency of 98.0% to >99.9% is achievable. The latter recovery corresponds to less than 250 ppmv of SO2 in the offgas going to the thermal oxidizer before the offgas is vented to the atmosphere.

In United States, oil and gas refineries are required to reduce the emissions of sulfur levels to achieve 99.9% or higher sulfur recovery. The sulfur recovery requirements in Canada increase from 98.5% for plants with a capacity of 50 tpd up to 99% for plants with a capacity of 2,000 tpd. In South America, the sulfur recovery requirements vary from 99.0% to 99.9%, depending on where the plant is located.

The European countries are required to reduce the maximum levels of sulfur in diesel and gasoline by environmental regulation agencies. However, the overall sulfur recovery in most European countries is at least 98.5%. Germany requires sulfur recoveries of 99.5% for plants with a high capacity and 99.8% for plants with lower capacity.

This paper presents the regulation effects of sulfur removal on worldwide facilities, ways to increase sulfur recovery the capacity, the global petroleum market and the key parameters to improve the existing plants, as well as the design criteria for the new plants to achieve the emission requirements established by environmental regulatory agencies.

The major impacts on the sulfur recovery units worldwide are not more than a 15% to 30% capacity increase, and that could be corrected by the minimum modifications in sulfur plants. Oxygen enrichment seems to be the most cost-effective process to increase the capacity in existing sulfur plants.

Section 1 Introduction

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When crude oil is processed in refineries, sulfur contained in the oil is mainly recovered as H2S, which is converted to sulfur in the refinery Claus plant. Part of the sulfur in the crude oil accumulates in the refinery residues. The external use of heavy fuels is very restricted, and further upgrading the heavy residues to lighter hydrocarbons, or converting these residues to synthesis gas, requires additional processes and investment costs.

Combustion of refinery residues, as well as incineration of Claus tail gases, results in offgases containing SO2. The environmental regulations in many countries require that most of the SO2 is removed from these flue gas flows. In response to this trend, several new technologies are now emerging to comply with the most stringent regulations. However, government regulations are only effective if compliance is monitored and if the regulations are strictly enforced. If gasoline that is exported for sale outside the United States, that gasoline is not subject to the requirements of the gasoline sulfur rule, including gasoline produced by a refiner located within the Gas Processing Associations (GPA).

Whether the initiative arose from government inducement, public pressure, or internally from corporate philosophy, there has been a considerable increase in demand from industries for what are regarded as the key elements for achieving higher sulfur recovery efficiencies. These are:

(1) Process knowledge

(2) Existing process evaluation

(3) Process modifications/optimization/converting to a suitable process in order to meet the new emission requirements for any unit involved with the emission requirements

(4) Selection of a new technology for the new plant

(5) Evaluation of the existing process control/possibilities of additional new controls

(6) Process monitoring

(7) Capital and operating costs

To achieve the higher recovery expected of a modern sulfur recovery unit, advances in the modified Claus sulfur recovery process itself are being implemented. These process technology advances are as a result of the evaluation of the key parameters. Each key element will be evaluated individually in the following sections.

Table 1-1 represents the worldwide sulfur recovery requirements for selected countries.


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Table 1-1—Worldwide Sulfur Recovery Requirements

Country Overall Sulfur Recovery, %

Asia Australia 99.9

China 99.9

India 99.0

Indonesia 99.0

Japan 99.9

Kazakhstan 99.9

Korea 99.9

Pakistan < 99.0

Philippine 95.0 to 99.9

Singapore < 99.0

Taiwan 99.9

Thailand 99.9

Europe Italy 97.5 to 99.9

Most European Countries 98.5

Austria 99.8

Germany 99.5 to 99.8

Russia 99.9

United Kingdom (UK) 98 to 99.5

Middle East Abu Dhabi (UAE) 98.0

Egypt 99.0 to 99.9

Iraq 99.0

Kuwait 99.9

Qatar 99.0

Saudi Arabia 95.0

North America Canada 98.5 to 99

United States 99.9

South America Argentina 99.0 to 99.9


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Country Overall Sulfur Recovery, %

Jose Industrial, Venezuela 99.0

Mexico 98.5 to 99.9

Venezuela 98.5 to 99.5

Section 2 Global Petroleum Market

2-1

2.1 Overview

The crude capacity limit was adopted to ensure that only truly small companies who need additional time to comply can qualify for small refiner status. Refiners who have relatively large crude capacity will probably be in a better position to finance and install desulfurization equipment to meet national standards in 2004. The U.S. Environmental Protection Agency (EPA) interprets its regulations to require refiners applying for small refiner status to include only the crude capacity in 1998 at refineries it owned, including refineries owned by subsidiaries, parent companies and subsidiaries of the parent company, and partners in joint ventures. The sulfur rule states that a small refiner must produce gasoline by processing crude oil through a refinery-processing unit. American Society for Testing and Materials (ASTM) D-2622-98, the design method for testing for sulfur content of gasoline, will be used for this testing purpose by the year 2004.

In many respects, the new European specifications are similar to the Clean Air Act (CAA) requirements imposed by the United States but, although the objectives are compatible, the approach taken was different. In the United States, the general approach was to create predictive models to calculate emission values for volatile organic content (VOC), nitrogen oxides (NOX), and toxic compounds based on the physical properties of the product fuel. Although this methodology is more complex to understand and administer, it offers refiners greater flexibility in adjusting the formulations to meet the environmental goals. However, the one notable exception is that U.S. refiners are forced to use a minimum oxygen content for both reformulated and oxygenated fuel programs. The following factors affect the European refining industry:

(1) Crude oil and refined product supply (2) Demand (3) Global competition (4) Environmental year 2000 and 2005 legislation (5) Imports (6) Costs

With the sulfur removal rates in European refineries averaging 70%, there is plenty of scope for brimstone production for the future. In just 1 year, the targets set for refiners to cut sulfur levels in transportation fuels have reduced into the distance. In Germany, the new environmental laws require “sulfur-free fuels,” which means a 10-ppm sulfur level in gasoline. It may not be economical for some smaller refiners to remain in business, and others will need to make significant investments. Refiners must invest in new process units to process new clean fuels; these laws will also reposition refineries to supply a product mix that more closely matches the market’s demands. Table 2-1 represents the crude quality profile for Western European refineries.


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Table 2-1—Crude Quality Profile for Western European Refineries

Year 1995 2000 2005 2010

Average gravity, °API 35.1 35.1 33.9 33.4

Average sulfur, wt% 1.1 1.1 1.2 1.3

The European industries will have the new requirements spread uniformly across the entire continents. This contrasts to the United States, where a complicated patchwork was implemented with four gasoline types [reformulated gasoline (RFG), oxygenated, conventional, and California reformulated] and two diesel types (on- and off-road). RFG was required year-round in nine ozone nonattainment areas, with other areas having the option to use RFG as part of their plans to remain in compliance. Oxygenated fuels were required in the winter for nearly 40 metropolitan areas throughout the United States, some of which overlap with RFG areas. To further compliance of the U.S. program, baseline data from 1990 was used and antidumping provisions were enacted to prevent the quality of conventional gasoline from being degraded with undesirable components that the regulation had already removed from clean fuels. In addition, each company was given the option of meeting individual batch requirements or slightly more stringent average requirements.

The European refiners have rigid specifications for each physical property that must be satisfied for a common fuel. Although U.S. refiners have more flexibility in adjusting each physical property to meet the calculated emission values, they have the added complexities of balancing the production and distribution of multiple fuels, as well as the additional administrative efforts. Although the approaches are different, the results are similar enough for some generalized comparisons to be made. Some lessons learned from the U.S. experience will be applicable in Europe.

Sulfur has been identified as the critical component in gasoline that needs to be restricted by the federal Reformulated Gasoline specifications. Sulfur in gasoline does not affect engine emissions of HC, CO, and NOx, but it increases exhaust emissions of these pollutants by inhibiting catalyst performance. Sulfur inhibition is very sensitive to air/fuel ratio. The sensitivity of sulfur content on exhaust emissions is higher in newer advanced catalyst technology. The sulfur content in gasoline specifications under European law is 150 and 50 ppmw for the year 2000 and 2005 limits, respectively. The sulfur content in diesel specifications under European law is 350 and 50 ppmw for the year 2000 and 2005 limits, respectively. To comply with the CAA, the U.S. refiners invested in reformulating gasoline and diesel for low-sulfur content, in the oxygenates [methyl tert-butyl ether (MTBE)


2-3

and, to a lesser extent, tertiary amyl ether (TAME)], isomerization, naphtha/reformate/cracked gasoline fractionation, aromatics extraction/separation, and gasoline blending automation. Production costs have averaged around $0.03/gal to make the new reformulated gasoline and $0.01/gal for low-sulfur diesel.

The sulfur limits have the clearest definition with solid specifications for both years 2000 and 2005. Led by automakers, sulfur is being attacked worldwide because it interferes with catalytic converter performance. To put these new limits into perspective, typical gasoline sulfur content in Europe is currently at ~ 200 ppm, and average diesel sulfur levels are at ~ 500 ppm.

In the short term, increased North Sea production will flow primarily to Europe, displacing the Middle East and Former Soviet Union (FSU) volumes. Europe is also projected to absorb gradually more significant amounts of heavy Venezuelan production in order to supply feedstock-to-refinery conversion operations, as well as bunker demand. All of North Africa’s increased production is absorbed in the Mediterranean, and it is supplemented by the North Sea’s volumes and West African production. Iraqi production will also flow to Northern Europe. In the longer term, the crude market will become more constrained with respect to light, sweet crudes as North Sea production begins to decline. Supplies from Latin America and the FSU will increase, and the Middle East will become a much bigger shipper into the European continent. Essentially, all remaining refineries in Europe will need to add diesel desulfurization capability by year 2005. In addition, many will need to add expensive but versatile hydrocracking units to meet the low-sulfur, high-octane requirements of the new diesel fuel. It is expected that overall gasoline yields will drop as refiners respond to the tighter aromatic limits and adjust their heavy naphtha cutpoints upward.

The overall net impact will be an environment of modestly better, although still not stellar, refining margins for the Western European industry. Unlike the experience of the U.S. refiners during the 1990s, these margins should be adequate to cover the significant investments that must be made. Because domestic production will not be capable of satisfying the local demand growth, Western Europe will be increasingly reliant on imported products, resulting in greater price volatility in the future. Price volatility will occur with increasing frequency because any surge in demand or disruption in domestic supply will need to be replenished by offshore sources, which may have significant time lags in their delivery ability.

Figure 2-1 represents the crude capacity conversion units in Western Europe as 21% and in the United States as 52% when compared to the other countries in 1998.


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2.2 Impacts from New Environmental Regulations in United States

Maintaining diesel fuel supplies in the face of increasing product demand and tight refinery capacity will present refiners with a serious challenge by itself. The reduced production capability, which results from a 15-ppm highway diesel fuel sulfur limit, poses a considerable risk that diesel supplies will be inadequate to meet demand. The U.S. environmental regulations have the following impacts:

(1) Create inadequate diesel supplies (2) Increase fuel prices (3) Increase revamp activities for most refineries (4) Reduce net imported supplies (5) Produce a near-perfect operation (6) Lose product due to high severity desulfurization (7) Lose effective product due to reduction in product energy content (8) Maintain ability for 15-ppm cap diesel throughout the refinery’s distribution

system (9) Increase capital and operating costs

The new EPA Tier 2 emission regulations will require the following modifications:

(1) Additional Fluid Catalyst Cracker (FCC) fed pretreat

Figure 2-1—Crude Capacity Conversion Units


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(2) FC gasoline post-treat (3) Additional H2 production (4) Additional sulfur recovery (5) Possible additional alkylation capacity (6) Debottlenecking and utility upgrades

The refining industry is committed to providing cleaner, more environmentally acceptable products to consumers. However, our national environmental goals must be consistent with our national energy needs. Close attention must be paid to the impact of future regulatory requirements on product supplies and energy security because the U.S. product refining and distribution system is already stretched to its limit. It is preferable that the EPA establish a cost-effective standard for engines and fuels that substantially reduces emissions and, yet, is close to the European regulations.

Section 3 Evaluation of Key Elements for High Sulfur Recovery

3-1

The major impacts on the sulfur recovery units worldwide are not more than 15% to 30% capacity increases. To achieve the higher sulfur recovery in existing plants (with the possibility of additional changes), the actual performance test of the unit should be evaluated to determine how much improvement is required. The following key elements for higher sulfur recovery should be evaluated in a step-by-step process to maintain the capital and operating costs within an acceptable range.

3.1 Process Knowledge

The education of operators has taken a major step forward with the introduction in annual training and seminars on the subject of optimizing sulfur plants. These meetings not only deal intensively with the theoretical and practical aspects of sulfur plant operations but also provide opportunities for operators from diverse backgrounds to discuss and sometimes solve common problems.

The process knowledge could be gained from the experience of analyzing data obtained during detailed engineering evaluations of an operating plant. Most such tests are conducted on plants that are experiencing operational problems or have problems with low sulfur recoveries. Engineers and operators who have a hands-on understanding of the process are invaluable in conducting such trouble-shooting activities. Based on the analysis of numerous detailed sulfur plant tests, it has been reported that the potential causes of recovery efficiency losses can be divided into the following categories:

(1) Poor reaction stoichiometry (2) Catalyst deactivation (3) Operating the first converter when it is too cold (4) Operating the second and third converters when they are too hot (5) Bypassing gases around the conversion stages (6) High final condenser temperature (7) Liquid sulfur entrainment

3.2 Existing Process Evaluation

The thermodynamic limitations of the Claus equilibrium reaction do not allow the attainment of sulfur recovery efficiencies greater than 90% to 96% for a two-stage reactor plant and 95% to 98% for a three-stage reactor plant. In most existing plants, the actual sulfur recovery efficiency is unknown because the feed compositions to the sulfur recovery unit could vary as the result of the upset upstream units or the variation of the summer and winter feed compositions. However, if the existing equipment, piping, catalysts, and chemicals are not well maintained, the actual sulfur recovery efficiency will not be the same as had been


3-2

originally designed. The test itself consists of collecting all operational data and stream compositions between all vessels in the process where a change in chemical composition has occurred. For the average sulfur plant, this process requires taking samples from eight process streams. An analysis of process streams of upstream and downstream units (such as amine, sour water, and tail-gas cleanup units) often helps to identify process problems in the sulfur plant. Operational changes are accepted because they are usually simple and easy to implement without affecting operating costs. Indeed, the implementation of such changes has resulted in significant improvements in the sulfur recovery efficiencies of many plants. However, because modifications to process equipment could be expensive, the benefits from these modifications should be considered carefully. After the improved actual sulfur recovery efficiency takes place, a further evaluation could proceed.

3.3 Process Modifications/Optimizations

The acid gas composition leaving the acid gas removal system has an impact on sulfur recovery efficiency. To achieve the higher recovery expected of a modern sulfur recovery unit, advances are being implemented in the modified Claus sulfur recovery process itself. These advances are taking place in the process technology as the result of evaluating the following key parameters:

(1) Corrections (i.e., those listed previously as deficiencies in the process design basis)

(2) Optimization of the feed to the Claus unit by improving the upstream units (such as gas treating to reduce impurities)

(3) Providing an additional process downstream of the Claus unit (such as tail-gas unit)

(4) Switching from air to oxygen in order to destroy more impurities and increase the capacity/recovery

(5) Providing an acid gas and air preheater upstream of the reaction furnace

(6) Changing the Claus catalyst or combining it with a high-performance catalyst such as hydrolysis catalyst (with a ratio of 30% to 100%) and an oxidation and reduction catalyst in order to increase the sulfur recovery

(7) Converting the modified Claus process to WorleyParsons Beaven’s Sulfur Removal BSR Hi-Activity process

(8) Converting any SuperClaus, cold bed adsorption (CBA), Sub-dewpoint process by Delta Engineering (MCRC), or Sulfreen process to the latest technology WorleyParsons PROClaus process

(9) Adding a new reactor with an additional heater and condenser


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(10) Optimizing the sulfur recovery unit sulfur recovery unit (SRU) converter/condenser temperatures

(11) Converting the amine solvent in the gas treating unit and any tail-gas unit from a generic solvent to proprietary solvent to increase the volumetric rate and improve the emissions

(12) Optimizing the BSR reactor’s temperature and hydrogen consumption

(13) Optimizing the amine flow rate and temperature for amine absorbers

(14) Minimizing the steam consumption and stabilization of the acid gas’s quality for amine regenerators

(15) Minimizing the steam consumption stabilization of the acid gas’s quality for sour water strippers

3.4 Selection of New Technology to Increase Sulfur Recovery

Typical sulfur recovery efficiencies for Claus plants are 90% to 96% for a two-stage plant and 95% to 98% for a three-stage plant. Most countries require sulfur recovery efficiencies in the range of 98.5% to > 99.9%. Tail-gas processes include H2S absorption, recycling technologies, catalytic oxidation of H2S into elemental sulfur, and a tail-gas incinerator process. Therefore, the sulfur constituents in the Claus tail-gas must be reduced further.

The increasing standards of efficiency required by the pressure from environmental protection has led to the development of a large number of Claus tail-gas treatment units, based on different concepts, in order to remove the last remaining sulfur species. The choice of the tail-gas treatment processes depends on several criteria, including the sulfur recovery efficiency required, acid gas composition, configuration, and capacity of the existing Claus unit. Table 3-1 presents the typical amounts of sulfur-containing compounds to be treated in the Claus tail gas.

Table 3-1—Typical Sulfur Species in Claus Tail-gas Unit

Sulfur Species Value

H2S (vol %) 0.3 to 1.5

SO2 (vol %) 0.15 to 0.75

COS (ppmv) 200 to 5000

CS2 (ppmv) 200 to 5000

Svap Saturated at T&P


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When building a new plant, the feasibility study should be based on all the selection criteria, including the required sulfur recovery efficiency, minimum capital cost, and minimum unit modification. Table 3-2 presents the various tail-gas processes.

Table 3-2—Different Tail-gas Processes

Tail-gas Treating (H2S recycle and selective cat oxidation process Typical Solvent (MDEA, HS-101/103, Gas/Spec *SS, Sulfinol, Flexsorb)

BSR/Amine Process Shell SCOT/ARCO WorleyParsons BOC Recycle

Resulf Dual-Solve BSR/Wet Oxidation

BSR/Selectox BSR/Hi-Activity/PROClaus Super Claus

DOXOSulfreen

Incinerator Tail Gas

Wellman-Lord Clintox Elsorb

Claus Master Cansolv Bio-Claus

Clausorb

WorleyParsons proprietary PROClaus process combines the conventional Claus processing step with two selective reaction steps in a three or four-stage configuration that enhances the overall sulfur recovery up to 99.5%. The PROClaus process uses two highly selective catalysts for direct reduction of SO2 and direct oxidation of H2S to elemental sulfur. This innovative processing scheme overcomes the sulfur yield limitations dictated by the Claus equilibrium. In addition, it offers distinct advantages over other competing technologies:

(1) No need to operate the Claus stages off-ratio as in the Super Claus process, which reduces the recovery efficiency of the Claus stages, as well as increases the inlet H2S concentration to the last, direct oxidation stage.

(2) No need to operate at sub-dewpoint as in the CBA and MCRC processes, which require routine valves switching and bed regeneration.

(3) No need to require a hydrogenation step because SO2 is converted directly to elemental sulfur in the presence of the highly selective Lawrence Berkeley National Laboratory (LBNL)catalyst.

A demonstration unit for the PROClaus process is started in early 2001 at Puerto La Cruz, Venezuela. The PROClaus process’s technological, operational, and economic advantages over other commercial tail gas cleaning unit (TGCU)


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processes will certainly revolutionize how an efficient and cost-effective SRU/TGCU should be designed and operated in the future.

Tables 3-3 and 3-4 present the comparisons of tail-gas cleanup processes with the sulfur recovery efficiency.

Table 3-3—Comparison of Tail-gas Cleanup Processes

Process Converters Sulfur Recovery, %

Relative Cost

Modified Claus 3 97.0 1.00 PROClaus 3 –4 99-99.5 1.15 Sub-dewpoint 3 99.0 1.20 Sub-dewpoint 4 99.5 1.40 Direct oxidation 3 98.8 1.15 Direct oxidation 4 99.3 1.30 BSR/Selectox 4 98.5 to 99.0 1.45 BSR/Hi-activity 4 99.2 1.35 BSR/amine or SCOT 3 + amine 99.9 1.70

Table 3-4—Tail-gas Cleanup Process

Process Capital Cost Operating Cost Efficiency, %

BSR/Flexsorb 5 5 99.99 BSR/MDEA 6 5 99.99 HCR 6 5 99.99 Thiopaq 4 4 99.99 Clauspol 3 4 99.5 to 99.9 PROClaus 2 2 99.2 to 99.5 BSR/Hi-Activity 3 3 99.2 BSR/Selectox 4 3 99.0 ER Claus 1 1 99.0


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3.5 Evaluation of Existing Process Control/Possibilities of Additional New Controls

To improve the higher sulfur recovery efficiency, the existing process control should be evaluated first; additional new controls, along with the new equipment, might then be required. Because of the shortcomings of feed forward control, it is widely accepted that a tail-gas analyzer in closed loop control contributes from 3% to 5% to the overall recovery efficiency on the conventional Claus SRU. By comparison, a third conversion stage only contributes an additional 2% recovery at a capital cost of 15%, and an enhanced Claus process contributes an additional 2% to 2.5% at a capital cost of 15% to 25%. Thus, the tail-gas analyzer is certainly worthy of attention and merit in the overall scheme to attain high recovery efficiencies. The achievement and maintenance of high sulfur recovery efficiencies in the existing plants is a long-term commitment from all who are involved in operating the plant. The key parameters for the process control in the existing plants follow:

(1) Provide good process design

(2) Provide well-maintained equipment

(3) Provide well-trained operators

(4) Maintain the correct operating temperatures throughout the unit

(5) Maintain the correct feed ratio (acid gas, air, oxygen) to the reaction furnace/reactors for the main and side streams

(6) Provide appropriate instrumentation, especially analyzers

(7) Use active catalyst

(8) Compare actual sulfur recovery versus calculated sulfur recovery

(9) Correct any of above deficiencies to improve the sulfur recovery efficiency

The additional new control systems should be implemented in conjunction with the existing control systems to prevent any deficiencies.

3.6 Process Monitoring

Process monitoring is the final phase of the optimization process. Advances in process monitoring have given the operators and the regulatory authorities a better daily account of plant performance. Monitoring is essential for implementing good operating practices that emphasize preventive measures rather than corrective actions to keep the plant running at optimal efficiency.


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The expected long-term efficiency is the goal for each plant. The thermodynamic capability of the process determines the allowances for feed composition, process configuration, types of reheaters used, operation above the sulfur dewpoint, sulfur fog/mist losses, fluctuations in the air-to-acid gas ratio, and degradation of catalyst activity and plant equipment, plus an allowance for the effects of transitory upsets in upstream processes and equipment failures that occur from time to time. It is further assumed that the plant is optimized and a good operational practice has been established to maintain the optimal performance. Because the expected efficiency is not a thermodynamic limit, the efficiency can be exceeded at any time when circumstances result in the actual efficiency losses due to the factor being less than assessed in determining the expected efficiency.

3.7 Capital and Operating Costs

One of the main selection criteria for the chosen technology is to achieve minimum capital and operating costs. The easiest option is to select the technology with the minimum modifications and minimum changes to the operation procedures and, at the same time, to achieve the required sulfur recovery efficiency. Sometimes, revamping the SRU units can take place during general turnarounds to eliminate an additional plant shutdown. The existing plot plan should be evaluated to eliminate the need for designing long piping that contains the hot fluids and the need for new structures, and it should still be able to use the existing equipment as much as possible.

3.8 Oxygen Enrichment Configurations

In recent years, the drive towards clean air and clean fuels created great demand for additional hydrodesulfurization and sulfur recovery capacities in refineries and gas plants worldwide. For many operators, the most economical route to acquire incremental SRU capacities is to apply oxygen enrichment in their existing SRUs in lieu of building new SRUs. This technology application enables operators to realize significant cost savings in both capital investment and operating costs depending on the desired capacity expansion.

3.8.1 Low-level Oxygen Enrichment (< 28% O2)

For a desired capacity increase of up to 20% to 25% of the original design sulfur processing capacity, low-level oxygen enrichment technology is adequate. Low-level oxygen enrichment is accomplished by injecting pure oxygen or oxygen-rich air into the combustion air; i.e., oxygen is premixed with combustion air upstream of the burner. No equipment modification is required in the existing SRU, other than providing the tie-in point for oxygen injection in the combustion air line. An SRU capacity increase of approximately 20% to 25% is achievable with low-level oxygen enrichment. The capital cost investment is mainly in the installation of an


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oxygen supply system, which is usually an oxygen supply line added to the reaction furnace burner.

3.8.2 Medium-level Oxygen Enrichment (28% to 45% O2)

For a desired capacity increase of up to 75% of the original design sulfur processing capacity, medium-level oxygen enrichment technology is required. The combustion air piping in a conventional SRU is not suitable for handling oxygen-rich air above 28% oxygen. The burner designed for air-only operation might not withstand the higher combustion temperature. In any case, direct injection of oxygen through separate nozzles from combustion air is recommended; hence, special burners designed for direct oxygen injection should be installed.

The SURE burner is designed for efficient combustion in SRUs with oxygen enrichment. It can be used in either end-firing or tangential-firing designs The excellent mixing characteristics of the SURE burner, coupled with the higher combustion temperature attained in oxygen enrichment operation, allow the existing reaction furnace to be used with only minor modifications to accommodate the new burner.

Oxygen enrichment considerably raises the reaction furnace temperature, which ensures complete destruction of undesired heavy hydrocarbons and ammonia, reduces formation of COS and CS2, and shortens gas residence time requirements for contaminant destruction.

The capital cost investment is mainly in the installation of an oxygen supply system and a new oxygen-compatible burner.

3.8.3 High-level Oxygen Enrichment (> 45% O2)

For a capacity increase of up to 150% of the original design capacity, high-level oxygen enrichment is applicable. The thermal section of the existing SRU must be modified and/or have new equipment added, depending on which oxygen enrichment technology is chosen.

3.8.3.1 Implementation of Oxygen Burning Processes

Oxygen enrichment has been applied to Claus unit revamps because the economics are clearly favorable if an increase in sulfur production is required. New plants have been designed to use oxygen enrichment when a refiner sees a need for a “peak shaving” operation or the need to increase the capacity of a unit on a short-term basis to allow for the maintenance of a second unit. New Claus plants using oxygen without air are normally associated with gasification projects or gas plants, both of which can have a lean relatively constant composition feed.

The minimum modifications required for a typical revamp are listed below:


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(1) New burner (2) Revised control system (3) Revised shutdown systems (4) Oxygen storage (if not available) (5) Oxygen transfer line

Normally the existing reaction furnace and waste heat boiler (WHB) could be used for the oxygen-enriched operation if the design temperature of their refractory is suitable for the oxygen enrichment. For some of the revamps discussed here, a new combustion chamber was installed for each plant. There were various reasons for this, namely corrosion of the old combustion chamber, replacement of the WHB, and a requirement for ammonia burning, but the main determining factor is the time allowed for the work on site. The short time allowed for the mechanical implementation of a revamp (typically 3 weeks) means that operations such as re-bricking a combustion chamber on site are too time-consuming; therefore, provision of a new combustion chamber with its refractory is favored. In the case of employing WorleyParsons/BOC Gases Company (BOC) SURE Double Combustion technology, a new reaction furnace/WHB is installed upstream and in series of the existing reaction furnace/WHB. In this case, the preinstalled new reaction furnace/WHB could easily be tied in with its existing counter part within the plant shutdown schedule. Table 3-5 presents the plant comparison before and after revamp.

The SURE Double Combustion employs two combustion furnaces and WHBs arranged in series. All acid gas and combustion air are sent to the first furnace where the SURE burner is located. Part of the oxygen is injected directly into the first furnace through dedicated oxygen injection nozzles in the SURE burner. The combustion products from the first furnace are cooled in the first WHB and then flow into the second furnace. The remaining oxygen is injected into the second furnace by oxygen lances. The combustion products from the second furnace are cooled in the second WHB and then sent to the catalytic stages. The first WHB is designed to cool the combustion products to a temperature above 1,000 F (540 C), which is higher than the auto-ignition temperature of H2S and sulfur (about 500 F or 260 C), so that no igniter is required in the second furnace and there is no danger from buildup of an explosive mixture of acid gas and oxygen.


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Table 3-5—Revamp Plants Comparison

Before Plant Revamp, metric tons per day (MTPD) After Plant Revamp, MTPD

Refinery Item S NH3 O2 S NH3 O2 O2 %

Refinery A 60 — — 90 — — —

Refinery B 70 1.9 44.1 97 5.72 53.1 32.1

Refinery C 15 0 8.6 24 1.53 13.9 33.2

Refinery D 32 0.3 17.6 47 0.53 26.4 39.1

Refinery E 42 0.3 24.7 80 4.84 44.8 41.7

Refinery F1 48.9 1.9 27.3 45 6.34 32.3 29.8

Refinery G New — — 75 x 2 1.20 63.1 95.0

Refinery H 51 3.5 30.3 68 4.6 40.9 31.0

Refinery I 150 10.6 87.8 241 28.8 172.5 35.0

Refinery J 19 0 11.0 43 0 25.0 100.0

Refinery K 240 x 2 — — 426 x 2 — — 100.0

Refinery M1 250 — — 500 — — 100.0

Refinery N1 20 — — 50 — — 100.0

Refinery O 330 — — 450 — — 100.0

Refinery P 140 — — 250 — — 60.0

Refinery R 95/180 — — 165/295 — — 60.0 1The sulfur production requirement decreased and sour water stripper (SWS) processing requirement significantly increased.

The investment cost associated with an oxygen enrichment revamp is only 15% to 25% of a new air-based SRU. Oxygen enrichment also provides substantial cost savings for new SRUs by reducing the sizes of the equipment. Applying oxygen enrichment to a new SRU can cut the flow rate through the SRU by half at the same sulfur recovery capacity as compared to an air-only unit; this results in approximately 35% savings in investment cost, which excludes the cost of an onsite oxygen generation unit.

Using oxygen enrichment will improve the following factors in sulfur recovery units:

(1) Increase unit capacity.

(2) Eliminate the limitation of air blower discharge pressure and plant hydraulics.


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(3) Increase processing SWS offgas.

(4) Increase combustion chamber temperature, and increase the stability of the flame temperature for lean acid gases.

(5) Increase the tail gas unit capacity (cooling capacity of direct contact condenser should be evaluated, and the amine circulation rate should be examined to ensure adequate amine circulation for H2S absorption).

(6) Evaluate the existing degassing system and the sulfur rundown (required for large percentage of sulfur capacity).

(7) Evaluate the existing incinerator (required for large percentage of sulfur capacity).

(8) Facilitate the complete destruction of ammonia, heavy hydrocarbons [such as benzene, toluene, and xylene (BTX)], and other contaminants.

(9) Increase accuracy by computational fluid dynamic (CFD) program (means of predicting flame patterns for specified operating conditions).

Various configuration options for high-level oxygen enrichment with WorleyParsons/BOC’s SURE Double Combustion process are available to suit the requirements of the individual facility.

3.8.3.2 Conventional Configuration for High Capacity Expansion

The conventional configuration involves the addition of a new reaction furnace burner, reaction furnace, and WHB boiler upstream of the existing reaction furnace (Figure 3-1). Gas effluent from the new waste boiler is routed to the existing reaction furnace, which serves as the second thermal stage. With this configuration the SURE Double Combustion technology allows SRU capacity to be expanded at considerably lower costs compared to building new air-based SRUs. The operator could save substantial initial investment cost even for new SRUs if oxygen is available or can be imported across the fence. Moreover, oxygen enrichment reduces the plot area required and, in fact, for operating facilities limited by plot space, oxygen enrichment might be the most viable option for SRU capacity expansion.

Occasionally, existing reaction furnaces and WHBs cannot be reused because of original design limitations. In these cases, a two-pass WHB with an extended head can be designed in which the extended head serves as the second-stage reaction furnace and the second pass serves as the second WHB (Figure 3-2). This two-pass WHB configuration effectively reduces capital cost and conserves plot space requirement. In addition, the following benefits could be realized by operators:

(1) The new reaction furnace/WHB can be installed while the existing SRU is still in operation. The new equipment can be tied in with the existing


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reaction furnace/WHB during a short period shutdown or during the SRU turnaround time, thus minimizing the loss of plant throughput while the technology is implemented.

(2) The simple piping for the SURE design reduces the possibility of accidental H2S emission and equipment failure compared to other commercially available processes.

(3) The SURE Double Combustion design does not require shutting down and isolating a recycle loop when oxygen enrichment is not being used; this further improves the safety of the SURE process.

(4) Changing the mode of operation between air-only and oxygen enrichment is simple and smooth for the SURE process, which involves only the oxygen supply system. The SRU itself is always ready to receive oxygen.

BurnerH2S

Sulfur Pit

O2

New Existing

Air

NH3

Condenser

Converter

Reheater

WHB

RF RFWHB

Figure 3-1—Conventional SURE Double Combustion Configuration Reusing Existing Reaction Furnace and WHB


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Sulfur Pit

Condenser

Converter

ReheaterBurner

Reaction Furnace #1Reaction Furnace #2

Oxygen

Figure 3-2—Conventional SURE Double Combustion Configuration with New Two-pass WHBs

3.8.3.3 Innovative Configuration for High-capacity Expansion

When multiple SRU trains are involved, one set of common new equipment (burner, reaction furnace, and WHB) can be shared by the various trains. The existing reaction furnaces and WHBs of the individual trains can be used as the second thermal stage. The effluent of the new WHB is split and routed to each of the existing reaction furnaces (Figure 3-3). The new equipment could be installed onsite while the SRU is in operation. Only a short downtime is needed to tie in the new equipment for high-level oxygen enrichment. Typically, the revamp tie-in work has been accomplished within 1 to 2 weeks, which is normally within the schedule of a routine plant maintenance shutdown.

Having the hot effluent (>1,000 F) from the first thermal stage travel a very long distance is undesirable. Therefore, if the individual trains are far away from each other, it might be necessary to install a new common second thermal stage. Depending on the required capacity, the second stage will either be a two pass WHB sharing a common shell with the first stage or an individual boiler. The relatively cool gas from the new second stage WHB is then split and tied into each of the existing number one sulfur condensers (Figure 3-4). Oxygen consumption can be reduced by treating part of the acid gas in the existing reaction furnaces and WHBs of the individual units using air. The effluent gas is also routed to the number one condenser and joins with the effluent of the new WHB for the remaining Claus process. This configuration can also be applied when the sizes of the existing reaction furnaces and WHBs are not adequate to handle the required


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capacity increase alone. It can effectively reduce the pressure drop across the SRUs and hence provides greater flexibility in the event that additional Claus stage or tail gas treatment needs to be added to increase the sulfur recovery to meet more stringent emissions requirements. These common equipment configurations could be cost effective for the following revamp situations.

A. Spare Train Capacity Requirement

Refer to the process configuration described in Figure 3-3; when no additional capacity is required during normal operation, existing reaction furnaces of both trains can be operated with air while the new reaction furnace/WHB can also be operated with air at reduced capacity. This operation mode will save oxygen cost.

When one of the two trains is down, the reaction furnace of the operating train can be operated with air at reduced rate while the new reaction furnace/WHB is operated with oxygen to provide the spare train capacity with one single train operation. This operation mode will ensure that refinery or gas plant throughput is maintained and thus will avoid any loss of income.

B. Normal Capacity Expansion with Added Spare Train Capacity

If additional sulfur processing capacity is required during normal operation, existing reaction furnaces of both trains can be operated with air at reduced capacity while the new reaction furnace/WHB operates with oxygen to provide the required additional capacity to both trains.

When one of the two trains is down, the reaction furnace of the operating train can be operated with air at reduced rate while the new reaction furnace/WHB is operated with oxygen to provide the spare (double) train capacity with one single train operation. This operation mode will ensure that refinery or gas plant throughput is maintained and thus avoids any loss of income.


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WHB

oxygen

oxygen

Condenser1

Condenser1

Burner

RF

Converter2RF

~

~Converter

1

Condenser2

Condenser3

Converter2RF

~

~

WHBConverter

1

Condenser2

Condenser3

WHB

oxygenNew

ExistingAmine AGSWS AG

Figure 3-3—Parallel SURE Double Combustion Configuration Using Existing Reaction Furnace and WHB as Second Thermal Stage Providing 150% Capacity Increase

Amine AG

Condenser2

Condenser3

oxygen

oxygen

Condenser1

Burner

RF

~

Converter2RF

~

~~WHB

Converter1

~

Converter2RF

~

~~WHB

Converter1

Condenser2

Condenser3

SWS AG

Acid GasAir

Acid GasAir

Figure 3-4 – Parallel SURE Double Combustion Configuration with New Reaction Furnace and Waste Heat Boilers Providing 150% Capacity Increase


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C. Provide 300% Additional Capacity for Two Existing Parallel Trains

The new reaction furnace/WHB can be designed to provide up to 150% additional sulfur processing capacity for each of the two existing parallel SRUs resulting in a total additional capacity of 300%. This operation mode would require the reaction furnace/WHB to be operated with oxygen during normal operation. Figure 3-5 depicts the minimum cost configuration to double the sulfur processing capacity of both existing trains. Although this minimum cost configuration does not offer some desired operation flexibilities, it could be configured as described in Figure 3-6. If the new equipment is shut down, the existing reaction furnaces can be operated with up to 28% oxygen-enriched air and can still provide 125% of the original design capacity. This configuration and operation mode minimize the loss of sulfur processing capacity and still maintain more than half of the total required capacity if any one of the two trains is down or if the new equipment system is down.

D. Stage Wise Investment Option

Considering the fact that configurations described in Figures 3-3 and 3-5 offer limited plant operation flexibility as when the new reaction furnace/WHB is down, the sulfur processing complex may suffer reduced or total loss of capacity. However, this configuration does provide a viable option for stage wise investment. If the process configurations described in Figures 3-2 and 3-4 are the most desired configurations that fit well into the existing designed equipment, plot space availability, and/or budget target, such a configuration can be implemented as a first-stage investment to accommodate the immediate needs. A second reaction furnace/WHB can be considered to install for the second train at a later time when budget is available to provide the desired operating flexibility while achieving the required sulfur processing capacity.

3.8.3.4 WorleyParsons Latest Development – “PROClaus Process”

WorleyParsons proprietary PROClaus (WorleyParsons RedOx Claus) process combines three distinct processing steps into one processing scheme:

(1) Conventional Claus reaction (2) Selective reduction of SO2 (3) Selective oxidation of H2S

This evolutionary process does not rely on tail gas hydrogenation, H2S-shifted Claus operation, or cyclic sub-dewpoint operation. Instead, the PROClaus process is a continuous dry catalytic process that operates the reaction furnace and the first Claus stage (or the second Claus stage) just like a conventional modified Claus unit, and the stage Claus is followed by a selective reduction stage and a selective oxidation stage. In a 3-stage or 4-stage configuration, PROClaus can achieve up to 99.5% overall sulfur recovery pending the acid gas compositions. Figure 3-7 presents the PROClaus configuration.


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WHB

oxygen

oxygen

Condenser1

Condenser1

Burner

RF

Converter2RF

~

~Converter

1

Condenser2

Condenser3

Converter2RF

~

~

WHBConverter

1

Condenser2

Condenser3

WHB

oxygenNew


Figure 3-5—Parallel SURE Double Combustion Configuration Using Existing Reaction Furnace and WHB as Second Thermal Stage Providing 300% Capacity Increase


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Condenser1Air

Condenser2

Condenser3

oxygen

Condenser1

Burner

RF

~

Converter2RF

~

~~WHB

Converter1

~

Converter2RF

~

~~WHB

Converter1

Condenser2

Condenser3Air

New


Acid Gas

Acid Gas

oxygen

Figure 3-6—Parallel SURE Double Combustion Configuration with New Reaction Furnace and WHBs Providing 300% Capacity Increase


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ClausConverter

Sulfur Pit

LP Steam

BFW

LP Steam

BFW

SelectiveReductionConverter

LP Steam

BFW

ReheaterNo. 3

SelectiveOxidationConverter

LP Steam

BFW

BFW

M

Sulfur Pump

Liquid Sulfur

Tail Gas

Air Blower

Water

CondenserNo. 1

AC

AC

Air

Air

H2S/SO2

O2ReheaterNo. 2

ReheaterNo. 1

Acid Gas K.ODrum Condenser

No. 2

HP Steam

ReactionFurnace

WasteHeat

Boiler

CondenserNo. 3

CondenserNo. 4

Figure 3-7—Three-stage PROClaus Process Flow Diagram

Section 4 Conclusions

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Using conventional HDS units to deliver very low levels of sulfur depends on design parameters such as operating partial pressure of hydrogen, which dictates level of sulfur removal as well as catalyst life. In general, every refinery would need to invest in additional HDS capacity plant to address the lower limits for diesel.

The key features in the regulatory effects of the sulfur removal facilities should include the new environmental regulations in the United States and in Europe, which will have many impacts on fuel productions, global petroleum markets, global petroleum demand, global trade flows, the refining industry, market outlook, crude oil supply, and the business environment. The key features affecting the selection of the tail-gas treating processes should involve the application of the most common well-known technologies. To select the proper tail-gas cleanup, all of the key step-by-step parameters should be considered.

The new regulation will require increasing the sulfur capacity by 15% to 25%, which could be implemented by using oxygen enrichment in addition to other modifications to improve the sulfur recovery in order to meet the new EPA regulations.

The PROClaus process presents the latest WorleyParsons technology of a 3 or 4-stage air-based PROClaus to achieve up to 99.5 percent overall sulfur recovery improve the sulfur recovery in order to meet the new EPA regulations. The PROClaus process is the most cost effective sulfur recovery process since there is no need for additional equipment for the tail gas unit. The capital and the operating costs are significantly lower than for a SRU/TGTU unit.

Section 5 Bibliography

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1. EU Environmental Laws Impact Fuels Requirements, S.F. Venner, published in HC Processing Magazine, May 2000.

2. Improving Sulfur Plant Performance, Sulfur 266.

3. Optimizing European Sulfur Recovery Plants, a Perspective, J.A. Sames, and H.G. Paskall, Western Research, 1991.

4. PROClaus, New Performance in Sulfur Recovery, M. Rameshni, Brimstone, Canmore, Canada, 2001

5. Silicon Carbide Supports New Improvements in Sulfur Recovery, Sulfur 269.

6. State-Of-the-Art in Gas Treating, M. Rameshni, British Sulphur Conference, San Francisco, CA, 2000

Appendix

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Acronyms and Abbreviations

*SS symbology for Dow Solvent API American Petroleum Institute ARCO Atlantic Richfield Co. tail gas technology ASTM American Society for Testing and Materials BOC BOC Gases Company BSR Beavon sulfur removal BTX benzene, toluene, and xylene CAA Clean Air Act CBA cold bed adsorption CFD computational fluid dynamic DOXO DOXO Sulfreen Process EPA U.S. Environmental Protection Agency EU European Union FCC Fluid Catalyst Cracker FSU Former Soviet Union GPA Gas Processing Associations HCR HCR tail gas unit process LBNL Lawrence Berkeley National Laboratory MCRC Sub-dewpoint process by Delta Engineering MDEA methyldiethanolamine MTBE methyl tert-butyl ether MTPD metric tons per day NOX nitrogen oxides NPRA National Petrochemical and Refiners Association PROClaus WorleyParsons RedOx Claus RFG reformulated gasoline SCOT Shell SCOT tail gas unit SRU sulfur recovery unit SWS sour water stripper T&P temperature and pressure TAME tertiary amyl ether TGCU tail gas cleaning unit UAE United Arab Emirates UK United Kingdom VOC volatile organic content WHB waste heat boiler

Regulation Effects on Sulfur Facilities

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