Licensing Solutions. for Tomorrow. Thriving in Uncertainty HYDROCARBON PROCESSING. Special Supplement to

Transcription

1 Licensing Solutions Thriving in Uncertainty Special Supplement to HYDROCARBON PROCESSING

2 Licensing Solutions CONTENTS Table of Contents 2 Thriving 4 Maximising 6 Revamping in uncertainty Süleyman Özmen VP Refining and Chemical Licensing, Shell Global International B.V. The challenges faced and the keys to success in today s downstream market. diesel production through integrated Hydroprocessing John Baric Licensing Technology Manager, Shell Global Solutions International B.V. and Justin Swain Technical Director, Criterion Catalysts and Technologies Ltd Well integrated hydroprocessing technology for hydrotreating and hydrocracking can give refiners an edge over their competition. a hydrotreating unit for improved hydrogenation of diesel A case study of Preem AB A key value driver for an EU refiner, including a novel process option developed by Shell Global Solutions aims to produce more diesel with improved quality and more propylene. Cost effective management of a High-Vacuum Unit revamp Alie Hoksberg Licensing Technology Manager, Shell Global Solutions International B.V. High-vacuum unit (HVU) revamp can have significant impact on vacuum gasoil yield improvement. Thermal conversion revamp boosts diesel production Okke de Boks Technical Director, Refining and Chemical Licensing, Shell Global Solutions International B.V. Thermal conversion is cost effective, versatile way to increase refinery s margins. Gas/liquid treatment and sulphur recovery Dave Clark General Manager Process, Refining and Chemical Licensing, Shell Global Solutions International B.V. and Rick Birnbaum Cansolv Technology Sales Manager, Shell Chemicals Americas Inc. Dave and Rick compare and contrast how these new additions to Shell s technologies can be exploited. 1 I Licensing Solutions

3 FOREWORD Licensing Solutions Thriving in uncertainty Today s downstream market faces significant challenges. Fortunately there are several keys to success which can enable refiners to thrive in uncertainty whether the market dips further, recovers quickly or enters another pattern, explains Süleyman Özmen VP, Refining and Chemical Licensing, Shell Global Solutions International B.V. Despite the economic crisis, there is consensus that energy demand will continue to grow in the long-term. There will be a step change as fast developing nations, like China and India boost energy consumption, particularly for personal transportation. Energy supply will struggle to keep pace as oil become more difficult to access and process. Refineries will face major challenges to meet growing energy demand, as well as upgrading different crudes to meet stringent environmental regulations, e.g. eliminating sulphur content in diesel and other fuel oils. Carbon dioxide emissions will also rise, despite global commitment to reduce carbon emissions. Consequently process engineers and project planners will have to take concerted action. Despite constrained capital expenditure, refiners must prepare for the upturn. New refining capacity is being added worldwide, with major projects underway in Russia and Spain in partnership with Shell, and a rapidly growing refining sector in China. However, demand for refining has stagnated in the last two years. Many assets are ageing, and no refineries have been built in the US for many years. Refiners have simply added units where necessary. In the current economic environment, financing for new projects has become hard to find. Refiners are short of cash even for basic revamps. The business case must be very well prepared highlighting, for example, whether the refinery will handle product for export or internal supply; whether an off-take agreement is in place; and arrangements for crude oil supply. Furthermore, well informed bankers are eager to determine whether the technology is well proven, and what service infrastructure is required. Admittedly, inefficiencies crept in during the boom years of high margins. With margins of $8-10, efficiency was not the main priority. These days, with margins close to $2, saving 20 cents a barrel makes a big difference. Shell Global Solutions proposes a strategy for operational improvement based on a pentagon-shaped model. Implementing business improvement processes can increase annual margin up to $50 million. First area of focus should be operational improvement with little or no capital expenditure required. The emphasis is on how to run things better. Five options for action include: improving reliability and onstream efficiency; hydrocarbon and supply chain optimisation; better work process efficiency; improved energy efficiency with lower CO 2 emissions; and streamlined operations. The choice is wide and offers potential savings of 5-20 cents and up to $1 a barrel. Faced with constrained capital expenditure, the next area of emphasis is revamps, with budgets typically targeted at $20 million or less. Basically there is a need to sweat existing assets. Licensing Solutions I 2

4 Licensing Solutions For example, a vacuum distillation unit could be upgraded to a deep-flash operation to generate more vacuum gasoil (VGO). Alternatively, the fluidised catalytic cracker (FCC) unit could be revamped to increase capacity. Upgrading thermal cracking and hydrotreater revamp, also offer significant benefits. A Shell client recently rerouted a VGO hydrotreater that was feeding an FCC, converting it into a mild hydrocracker. Looking longer-term, Shell recommends a pentagon of high capex projects. These include using deep-flash HVU in combination with thermal cracking to reduce fuel oil production. Conversion of residue gas oils to diesel, using heavier SR VGO deep flash, thermal cracking and delayed coker; deep flash HVU in combination with hydrocracker/ SDU or coker unit to maximise diesel production; upgrading of FCC LCO; production of winter diesel with optimised cold flow properties; or integrated ULSD with dewaxing HDS. There are also opportunities for short-term wins within days, e.g. by changing catalysts, reactor internals and the like. Even in a tight economic climate, the world needn t stop. Now is the time for pre-engineering and front-end engineering design (FEED) work. It is important to avoid stop-go behaviour. The refining sector has been like a roller coaster in recent years but business must continue. Demand for cleaner fuels will also rise, with increasing environmental regulation across the board. Today, sulphur-free diesel regulations are commonplace but soon similar fuel oil and marine diesel regulations will follow. Demand for deep-flash and vacuum units are climbing, because more product can be lifted. Shell has been involved in significant design work in this area over the last 12 months. Numerous hydrocracker projects are also underway. Solvent de-asphalting or coking may be appropriate, so long as an outlet can be found for the coke. For example, the Turkish market uses coke and pet-coke. However, China has no interest in coking technology due to plentiful supplies of coal. There is also opportunity for upgrading and de-waxing plant, particularly for upgrading diesel in cold climates. Scouting and front-end-studies can offer best value during the early stages. The rest follows smoothly so long as there is sufficient investment in front-end development. It is imperative that refiners plan well ahead for projects of years lifespan, and get the engineering fundamentals right now. With turnaround approaching, refiners should be thinking about how best to sweat the assets without extensive capex spending. Revamps can include work on a number of items from the FCC to a hydrocracker, as well as long-term options, such as adding new units, and grass-root refinery projects. Whatever happens, there will be long-term demand pressure, though the current economic climate makes investment more challenging. In the meantime, refiners have various options for incremental investment, for example, to meet demand for clean middle distillate. Act now. Prepare carefully and invest during the downturn to avoid regrets later. Süleyman Özmen VP Refining and Chemical Licensing, Shell Global Solutions International B.V. Planning for the future means to start investing now and focus on projects to be prepared for the upturn 3 I Licensing Solutions

5 Licensing Solutions Maximising diesel production through integrated Hydroprocessing Well integrated hydroprocessing technology for hydrotreating and hydrocracking can give refiners an edge over their competition. John Baric Licensing Technology Manager, Shell Global Solutions International B.V. and Justin Swain Technical Director, Criterion Catalysts and Technologies Ltd discuss specific technology differentiators and case studies which resolve key unit performance issues and boost margin for refiners. Hydroprocessing faces significant challenges as crude feeds get heavier; there will be more sulphur and nitrogen to extract; more aromatics to saturate; more metals to remove; and more coke to deal with. Refiners also have ageing facilities, which may not be designed and optimised to meet these new challenges. In an economic environment of constrained capex, many refiners have successfully revamped their existing hydroprocessing units with Shell s reactor internals technology and the latest generation of catalysts from Shell s partner Criterion the largest global supplier of hydroprocessing catalysts. In order to get maximum value from a revamped unit, the catalyst and the quality of the reactor internals must both be optimized. The catalysts have to be protected from particulates and foulants, and the reaction and catalyst utilisation must be maximised. In any multi-bed hydrocracking reactor, for example, particulates can accumulate even if sophisticated automatic backwash feed filters are present, affecting top bed catalyst performance. Optimum reactor internals design is vital. Shell installs filters into the top dome of all vacuum gas oil (VGO) hydrocrackers and residue hydrodesulphurisation (HDS) units, without effecting reactor size, cost or affecting active catalyst volume. The filters have proven to be extremely effective for coarse removal of particulates that could cause pressure drop and misdistribution in the catalyst bed. A liquid-vapour distribution tray beneath the filters ensures that vapour and liquid have full radial dispersion across the catalyst bed, resulting in nearly 100% utilisation of the catalyst. Effectiveness of the catalytic bed is measured by up to 36 thermocouples across the top and bottom of the bed. The High Dispersion (HD) tray controls temperature radial distribution to within 2-4 o C, confirming optimum catalyst utilisation. An Ultra-Flat Quench (UFQ) deck at the bottom of the bed, takes the reactants and mixes them with cold quench gas, and finally redistributes them into the next catalyst bed. The compact design minimizes vertical height, and offers up to 20% more catalytic volume in a multi-bed reactor. Over the last decade, improvements in catalyst formulations have more than doubled the relative catalytic activity while minimizing the hardware required. In 2000/2001 Criterion introduced Centinel Gold, which recently has been upgraded to the latest Centera platform. Criterion also offers in the Ascent platform, a cost-effective catalyst which balances Type II and Type I active sites. In addition to major increases in hydrodesulphurisation activity producing less than 10 ppm sulphur diesel regardless of the feedstock there has been improvement in winter diesel quality, with the use of dewaxing catalyst to improve the cloud point. Shell offers a single-stage, SDD 800, base metal catalyst to improve the cloud point by transforming long chain mono-alkyl or long chain paraffin molecules through isomerisation to retain a high level of diesel yield. Consequently, refiners can produce full range heavy diesel product with a significantly improved cloud point. Depending on the degree of cloud point improvement required, an HDS and hydrodenitrogenation (HDN) catalyst can be applied together with a dewaxing catalyst. Generally, a discrete small Licensing Solutions I 4

6 Licensing Solutions dewaxing bed is used where temperature, dewaxing and cold flow improvement can be controlled. Criterion produces a range of hydrocracking catalysts in partnership with Zeolyst International. Blends of zeolite differ according to the level of diesel selectivity required in different markets. The new 2000 series of zeolite catalysts offers refiners the flexibility to choose more diesel selectivity at the same operating temperature, or more activity for the same selectivity, achieving highest boost in diesel production within existing unit constraints. Catalyst shape is also an important performance variable. Criterion had replaced cylinders with trilobes to boost hydrocracking performance and increase diesel production. Over-cracking occurs if the reactants remain inside the catalyst too long, reducing diesel yield and creating more undesired product like naphtha and gas. Criterion s new Advanced Trilobe Xtreme (ATX) shape has further increased diesel yield by 1.5%. A 50,000 bpd hydrocracker can produce 750 bpd more diesel product simply by changing catalyst shape. Let us examine two case studies: a dewaxing project where Shell was asked to improve the cloud point of winter diesel by 14 o C and a revamp of a 30-year old hydrocracker with reliability issues. Many hydroprocessing assets worldwide are underperforming. A successful revamp project is low capex with quick payback, ideally within the subsequent catalyst cycle of the hydroprocessing unit. Typically, the project is scoped for new reactor internals and a new catalyst package and its far better to do them together than separately. For upgrading old, low-pressure HDS units, which do not have enough catalyst volume,adding a second reactor makes a significant improvement in performance. A review of the wash-water injection system is also important. Often feed rate and/or sour feed rate are increased triggering potential corrosion problems that can be avoided by additional/optimised wash water operation. At the back end, the refiner must ensure that separation, fractionation and workup sections can recover the additional diesel product. Depending on the scope, costs of a revamp hydroprocessing project range from $2-10 million with a second reactor at the upper end. A revamp can typically be carried out in a scheduled turnaround. Typical payback is within the next cycle and allows the refiner to process far more difficult feedstocks and/or produce better quality product. Case Study 1: An ultra-low sulphur (ULSD) unit was converted to dewaxing mode, capable of reducing the diesel cloud point from -5 to -19 o C, using a high activity nickel-molybdenum catalyst with SDD 800 dewaxing catalyst and some posttreatment, implemented within an existing reactor. Dewaxing requires operating flexibility, as cloud point improvement is not necessary in the summer. 5 I Licensing Solutions During the summer, dewaxing can be switched off by quenching, at a small yield penalty. Two-stage iso-dewaxing offers up to 35 o C cloud point improvement with minimal diesel yield loss. Case Study 2: A single-stage, 30-year old hydrocracker (with recycle) had become less reliable with age, mainly due to a high catalyst bed pressuredrop through deposition of solids, corrosion products upstream of the unit. A top bed skim was frequently required and the top bed catalyst was completely replaced during plant turnaround. Shell implemented new reactor internals technology, Over the last decade, improvements in catalyst formulations have more than doubled the relative catalytic activity while minimizing the hardware required. including; a filter deck, increasing the cycle length and eliminating the rapid pressure-drop build up, and integrated HD/UFQ decks, increasing catalyst utilisation for higher diesel yields. The total project cost was about $2 million for hardware, and outstanding reliability and yield improvement achieved. Maldistribution of catalyst is a common problem for reactors, creating local hotspots when liquids and vapors flow preferentially to one part of a bed, leaving other parts without proper flow. The resultant high temperatures and overcracking generates high gas and LPG yields, consuming hydrogen, at the expense of diesel product. Ultimately, the operation is constrained on cycle length, because the reactor mechanical temperature limit is reached much faster if radials are 50 C hotter in one part of the bed than another, so full cycle potential is never achieved. Installing HD tray and UFQ quench decks resulted in stable catalyst performance, both temperatures and yields, in the subsequent cycle. The reactor internals were complemented by tailoring a combination of high-activity catalysts with optimum selectivity resulting in increased conversion (by 2.5% on feed) and increased diesel yield (diesel yield actually increased by 10% weight on feed). Payback was less than a year, given increased unit performance worth $3.5 million annually. John Baric Licensing Technology Manager, Shell Global Solutions International B.V. Justin Swain Technical Director, Criterion Catalysts and Technologies Ltd

7 Licensing Solutions Revamping a hydrotreating unit for improved hydrogenation of diesel A key value driver for an EU refiner Refiners have enjoyed a period of high product demand and strong refining margins for the past few years Synopsis Preem AB has implemented the gasoil project, a major investment program to optimise conversion for middle distillate production at the refinery in Lysekil. After the start-up of this project, Preem AB recognised the need to reach a new level of operational excellence in order to maximise their return on investment. Shell Global Solutions was appointed to perform a Hydrocarbon Margin Improvement Program (HMIP), working closely with Preemraff Lysekil to identify, develop and deliver margin improving initiatives across the refinery. One of the margin improving opportunities identified by the HMIP was to increase the production of Swedish MK-1 diesel (Product Sulphur = 10ppm, Max T95 = 285 C, Max Density = 820 kg/m 3, Max Total Aromatics = 5vol%) from the 2-Stage Middle Distillate Hydrogenation (2-Stage MDH) unit operating at Preemraff Lysekil. Working closely with the Preemraff Lysekil technologists, the catalyst and reactor internals team from Shell Global Solutions and Criterion Catalysts & Technologies identified that the unit throughput could be increased by implementing a catalyst & reactor internals revamp on the 1st-stage pre-treat reactor (R1) of this unit. The expected increase unit throughput was 20 Sm 3 /h. With a refinery turnaround scheduled to happen within 7 months of identifying the opportunity, the project justification, design and confirmation (through pilot plant testing), of this solution had to be completed quickly and the project fasttracked for speedy implementation. The initial economic justification for the revamp project was based on recovering the cost of the reactor internals (a one-off cost Capital expenditure) and the on-going cost of extra catalyst, within the first 5-6 months of operation. Record production of Swedish Mk-1 diesel was reported soon after the unit started-up and the unit continues to perform at the level expected when the project objectives were set, with average throughput remaining 40 Sm 3 /hr higher than in the previous run. In the event, weaker than expected margins meant the break-even point on the project was pushed back by 3 months and the investment was recovered in the first 8-9 months of operation. After 20 months of an estimated 5 year cycle, Preem AB estimate the contribution will be close to 1.7 Million US$/annum on-going. At the heart of this success story is the fact that the ENCORE Centinel Gold catalyst in the first stage reduces not only the di+ aromatics but also the mono-aromatics in the feed to the 2nd stage (Reference 1). This allowed more feed to be treated through the second stage reactor, while still achieving the stringent < 5% wt aromatic specifications for Swedish MK-1 diesel. In this paper, we discuss how the ENCORE Centinel Gold catalyst and improved reactor volume and catalyst utilisation can help to promote chemistry that makes a significant difference to a refiner s profitability. Although specific reference is made to the work done on the Preemraff Lysekil project, it should be possible to use this approach to improve the efficiency of any hydroprocessing unit in a refinery where production is limited by initial process design, existing reactor hardware or catalyst. Furthermore, if there is surplus hydrogen in the refinery, this kind of revamp offers an excellent opportunity to fix hydrogen very selectively, increasing the volume of the middle distillate fractions that make up a refiners diesel pool. Additional benefits include higher feedrate, product density reduction, when processing cracked feeds and other product quality improvements that allow even greater flexibility to blend and upgrade the diesel pool; all of which add substantial value to a refiner s operations. Introduction Refiners have enjoyed a period of high product demand and strong refining margins for the past few years. During this time, maximising plant availability and throughput were key drivers to increasing margin. Refiners have focused on process units that make the biggest contributions to their profitability. Most typically these are the conversion units, such as Hydrocrackers and Fluid Catalytic Crackers (FCC s). Hydrotreating units on the other hand are regarded as pre-treatment or polishing units where hydrogen consumption only contributes to overall costs. There is a natural tendency for refiners to select catalysts that minimise hydrogen consumption in these units. Licensing Solutions I 6

8 Licensing Solutions Since the introduction of ultra-clean/low aromatic Swedish Mk-1 diesel in 1994, Preem AB has operated 2-Stage Middle Distillate Hydrogenation units (2-stage MDH) at both their refineries in Lysekil (1994) and Gothenburg (1997). A 2-stage MDH can be operated in block mode to produce either Ultra Low Sulphur Diesel (ULSD) or the low-aromatic Swedish Mk-1 diesel (a very clean, low aromatic diesel). Ahead of the EU diesel specifications changes in 2005, the pre-treat reactor (R1) on the 2-stage MDH unit in Gothenburg was revamped to maximise the production of ULSD grade Mk-3 diesel (Product Sulphur = 10ppm, Max Density = 845 kg/m 3, Max T95 = 360 C). The pretreat reactor, R1 was designed to help with Centinel Gold catalyst technology from Criterion and reactor internal technology from Shell Global Solutions, designed to maximise reactor catalyst inventory and improve catalyst bed utilisation. Their robustness to a wide range of operating conditions, combined with their modular ergonomic design has made them reactor internals of choice for well over 350 reactor revamp projects and newly licensed grass root units world-wide (Reference 2). One of the unforeseen benefits of the revamp was the higher than expected Aromatics saturation activity in R1. Regular and detailed monitoring of the unit allowed the team to recognise that the Centinel Gold NiMo catalyst was saturating all the di+ aromatics and more importantly a substantial amount of the mono-aromatics both the LAGO and full range Gasoil feeds. When Shell Global Solutions was appointed by Preem AB to do a Hydrocarbon Margin Improvement study at Preemraff Lysekil, one of the drivers identified to improve margin was to increase the production of Swedish MK-1 diesel. To achieve this, it was recognised that the aromatic saturation capability of the 2-stage unit would have to be increased. Building on the successful revamp and switching from a conventional NiMo to a Type-II catalyst in the 2-stage MDH unit in Gothenburg (Reference 3) with the resultant increase in the hydrogenation activity, Criterion Catalysts & Technologies and Shell Global Solutions proposed a similar reactor internals + catalyst revamp for reactor R1 for the unit in Preemraff Lysekil. To avoid any loss of MK-1 production and refinery margin, it became clear that the modifications required could only be completed during the down-time at a major refinery turn-around. With the planned refinery turn-around only seven months away the project had to be fast tracked and managed if all the design, manufacturing and quality control steps were to be implemented in time. A project team comprising the unit engineer, a reactor internals technician and a catalyst technician was assembled and empowered to ensure that all the modifications, including installation of new reactor thermocouples would be completed in time for the turn-around. All aspects of the reactor re-engineering and project delivery (including subcontracted work) were project managed by Shell Global Solutions. Strong team work with high customer involvement allowed the project to go from the initial conceptual phase through all the steps of design, manufacture and quality checks to installation and completion in 7 months. The catalyst loaded in reactor R1 of the 2-stage MDH unit in Lysekil was mainly a revitalised ENCORE Centinel Gold catalyst that had been previously installed in the 2-Stage MDH unit in Preemraff Gothenburg. Since the revamp, the MK-1 production has increased by 40 Sm 3 /hr, compared to the previous cycle, substantially in excess of the original expectation to increase the throughput by 20 Sm 3 /h. By installing state-of-the-art reactor internals and a very specific type of catalyst the Project Team was able to successfully address the constraint limiting the production of the Swedish MK-1 diesel in the 2-stage MDH unit in Preemraff Lysekil. The key to success was excellence in all aspects of project management, fast-track project execution and a flexible team approach on all sides, especially during the final delivery phase of the project. A Hydrocarbon Margin Improvement Program identifies the need to increase production of MK-1 diesel The refinery wide Hydrocarbon Margin Improvement Program (HMIP) in Preemraff Lysekil was carried out in close collaboration between Preem and Shell Global Solutions experts. A recommendation from the HMIP program, which became a high priority objective, was to identify opportunities to increase production of Swedish MK-1 diesel and to implement the changes needed to achieve this. Background Information on the Refinery, Middle Distillate Feeds and Products Preemraff Lysekil is one of two refineries in the Preem AB group. Both refineries are based in Sweden. The Lysekil Refinery is a 220,000 Barrel/day fully complex refinery processing mainly a blend Urals and occasionally low-sulphur North Sea crude. The Gasoil Hydrotreating unit was revamped to a 2-stage Middle Distillate Hydrogenation unit (2-Stage MDH) in 1994 to produce two types of diesel products; a Swedish 7 I Licensing Solutions

9 Licensing Solutions MK-1 grade (MK-1) from a Light Atmospheric Gasoil (LAGO) and a full range Ultra Low Sulphur Diesel (ULSD) manufactured to EN-590 specification from a full range gasoil. The properties of these products are described below: Name Description Specification MK-1 ULSD Swedish Environmental Class 1 Diesel Standard European ULSD Diesel Table 1: The specification of both MK-1 Diesel and ULSD Product Sulphur = 10ppm Max T95 = 285 C Max Density = 820 kg/m 3 Max Total Aromatics = 5vol% Product Sulphur = 10ppm Max Density = 845 kg/m 3 Max T95 = 360 C As there has been a strong demand for Swedish MK-1 the unit is operated primarily with the LAGO feed. All MK-1 produced at the refinery is sold in the Swedish market. The growing diesel market in Sweden was a strong driver to further increase production of MK-1 diesel from this unit the environmental benefit of MK-1 compared with Standard European ULSD (EN 590) is 10ppm Sulphur for reduced SOx emissions, 20% lower particulate emissions, 5% lower NOx emissions and it also has improved cold flow properties. Identifying constraints to the production of Swedish Mk-1 Diesel The production unit that came under scrutiny to achieve the objective identified in HMIP was the 2-stage MDH unit in Lysekil. This unit consists of a co-current 60-Bar Hydrodesulphurisation (HDS) reactor, R1 (containing a Base metal catalyst), an inter-stage stripper and a counter-current Hydrodearomitisation (HDA) reactor, R2 (containing noble metal catalyst), see Figure 1. The original design capacity was 200 Sm 3 /h when operating in MK-1 mode and 310 Sm 3 /h in HDS mode. As the unit already contained Criterion s catalysts there was already good understanding of the chemistry and operating parameters that were constraining the unit throughput in MK-1 mode. Unit Configuration and Process Flows The 2-stage MDH unit was initially designed to allow operation in two different feed modes, depending on whether MK-1 or ULSD is production is required. Feeds to the unit come from the Atmospheric unit via intermediate storage tanks. When producing the MK-1, the feed to the unit is configured as shown in figure 1, with R1 in series with R2. In view of the strong demand for MK-1, this has been the main operating mode for the unit in Preemraff Lysekil. Chemistry limiting production of MK-1 diesel Having monitored the performance of this unit using Criterion s CatCheckSM tools, it was recognised that production of MK-1 from this unit was limited by the overall capacity of the unit to reduce Aromatics in the feed. To increase throughput and production of MK-1, a stronger hydrogenating catalyst was needed for either R1 or R2. A combination of Centinel Gold catalyst technology and HDS reactor internals replacement was considered the best option to meet Preem s future objectives A state-of the art high activity Aromatic Saturation catalyst had been loaded to R2 in the previous cycle and to achieve further improvement, the focus shifted to increasing the hydrogenation activity in R1. Based on the experience from the Gothenburg unit, it was recognised that a Centinel Gold catalyst would not only increase the HDS and HDN activity in R1 (which would improve the hydrogenation activity in R2), but it would also substantially reduce the poly and some of the mono-aromatics in the feed. This in turn would relieve some of the HDA duty in R2 and allow a higher unit throughput to be achieved. MK-1 Feed LAGO HDS Reactor Hydrogen Two-Stage Unit Interstage Stripper HDA Reactor Hydrogen Sulphur MK-1 Product Total Aromatics 10 ppm 5 vol% Figure 1: MK-1 Mode Feed Sulphur and Nitrogen is removed in the Hydrodesulphurisation (HDS) Reactor and Aromatics Hydrogenation is achieved in the 2nd Hydrodearomitisation (HDA) reactor A solution based on the revamp of R1, that would allow improved utilisation of a more active hydrogenation catalyst was contemplated. This would involve a complete overhaul of all R1 reactor internals, as well as an upgrade from thermobars to flexible thermocouples, and the installation of Centinel Gold catalyst technology. These changes were geared to increasing the catalyst inventory, improving catalyst utilisation of a more active NiMo hydrogenation catalyst and better monitoring of distribution in R1. The resultant benefit was higher HDS/HDN and HDA in the 1st stage of the process. This allowed higher overall throughputs to be achieved in the 1st and 2nd-stage reactors without compromising product specification of < 5% vol Total Aromatics. Licensing Solutions I 8

10 Licensing Solutions Centinel Gold technology catalyst to increase aromatics saturation activity in the first reactor and Use of ENCORE Revitalised catalyst In order to develop the most cost-effective catalyst option, it was proposed to revitalise approximately 200mT of Centinel Gold NiMo catalyst that would become available after the first successful cycle in Preemraff Gothenburg. ENCORE is a Criterion proprietary revitalisation process for recovering the activity of Type-II catalysts, close to fresh activity (Reference 4). This part of the project was coordinated by a team of Criterion and Porocel Adsorbents, Catalysts and Services to ensure that the correct quality and quantity of catalyst could be delivered to Preemraff in a timely manner. This catalyst solution was evaluated to confirm that the main project goal of increasing the unit throughput by 20 Sm 3 /hr could be achieved. Pilot Plant testing confirmed that the proposed system would increase the aromatic saturation capability in the 1st stage, by up to 17%wt compared to conventional NiMo hydrotreating catalysts (Reference 1) and this would significantly reduce the duty required in the second reactor, allowing more feed to be processed through the unit. Back to back testing of Centinel Gold catalyst technology compared to a conventional NiMo catalyst indicated that conversion of monoaromatics could be increased by up to 17% with the Centinel Gold catalyst. It was estimated that this in combination with higher reactor volume and catalyst utilisation (Reference 5), would lead to a substantial improvement in overall performance of the unit; overcoming the chemistry limitation and allowing a higher throughput to be achieved. The Shell Global Solutions reactor internals, comprising the Shell HD tray (HD tray) Ultra-flat quench (UFQ) and bottom basket were installed to increase the catalyst volume by 34%. The actual increase in effective catalyst volume utilisation was higher than this, estimated to be close to 53% (Reference 5) because inherent in the design of the HD tray and the UFQ is a highly efficient gas/liquid mixing device that serves to maximise contact with the catalyst. The full reactor internals modifications are shown in Figure 2, below. The above mentioned modifications and modular design, through ease of handling, will deliver major safety improvements and cost reductions in future shutdowns. Based on the experience with Shell Reactor internals, installed in the MHC unit in 2003, the time required to open and close man-ways as a result of the boltless man-ways is expected drastically reduce the overall shutdown time and at the same time result in great improvement with regards to safety during the shutdown (Reference 6). The enhanced dispersion and ultra uniform distribution of the liquid over the full catalyst 9 I Licensing Solutions bed is also expected to reduce the risk of localised coking and catalyst plugging which can lead to considerable delay in unit turn-arounds. All of these are re-occurring cost savings for each turn-around. Project Management Excellence, a dedicated team and a flexible approach on all sides was key to successful delivery Part of Shell Global Solutions philosophy and quality system is assuring that all new internals are mounted correctly and in accordance to the high tolerances required to achieve an optimum performance of the unit. Prior to the installation of the new reactor internals all design drawings and quality documents from the reactor internals manufacturer were reviewed and commented by Shell Global Solutions. The total design and production phase is monitored. Upon completion of the products a comprehensive mock-up inspection is performed to ensure all individual items are correct and fit the required set out by Shell Global Solutions as well as all interfaces with the reactor and the existing supports inside the reactor. In addition to replacement of the reactor internals, the scope of the project included replacement of the existing thermowell in the reactor with new Gayesco Flex-R thermocouples. During the turn-around, installation of the reactor internals and the thermocouples was managed by Preemraff Maintenance Engineering team with 24-hour on-site support from the Shell Global Reactor Internals team. Strong teamwork and a flexible approach allowed this team to manage the unexpected problems encountered in dismantling the existing reactor internals and installing the new thermocouples. As a result the revamp of the reactor stayed off the critical path during the turn-around. Preem s objectives achieved! The combination of the high activity of the ENCORE Centinel Gold catalyst and Shell Global Solutions reactor internal modifications to the 2-stage MDH unit in Preemraff Lysekil have yielded the following results: MK-1 Throughput and Production (1) MK-1 H2 Consumption (Nm 3 /m 3 feed) (2) 1. MK-1 throughput and Swedish Class 1 Diesel production has increased by 40 Sm 3 /hr, mainly due to hydrogenation of aromatic compounds in the HDS reactor, relieving some of the duty of Original situation Thermowell (3x) Ceramic balls Quench distributor Quench box, tray Distributive packing Outlet collector and ceramic balls Figure 2: Hardware changes to improve reactor volume and catalyst utilisation Before Revamp After Revamp Actual Operation Base Base + 20 Sm 3 /hr Base + 40 Sm 3 /hr Base Base Base After internals revamp Inlet device and predistributor (1) HD Tray Elevation skirt Top bed grading (2) new quench distributor (gas or liquid only) (2) HD tray, new skirt Remove horizontal thermobars (3) new ultra flat bottom basket and ceramic balls

11 Licensing Solutions the HDA reactor (slight reduction in Sulphur and Nitrogen to the HDA reactor also has an impact, due to reduced poisoning, but this is less significant). See Graph 1, below. 2. Following the revamp of R1 with Shell reactor internals and installation of Centinel Gold catalyst, the level of hydrogen consumption in R1 increased from 50% of the total consumption to 64%. This confirmed the increased hydrogenation activity of R1. Within the accuracy of measuring the hydrogen mass balance over the whole unit and possible variations in feedstock quality, the overall chemical hydrogen consumption on a Nm 3 /Sm 3 feed remained unchanged. This is in line with expectation as under the mild operating conditions in the 2-stage MDH unit, the level of hydrogen consumption will depend primarily on the difference between feed aromatics and product specification. The higher hydrogenation activity in R1, reduced the duty required in R2, and this allowed the unit to be debottlenecked and more feed to be processed through the unit. Diesel Production during MK-1 Mode Cycle After Revamp Cycle Before Revamp 300 Average after revamp Sm 3 /hr Average before revamp Sm 3 /hr Days on stream Graph 1: MK-1 Swedish Class 1 Diesel production has increased by 40 Sm 3 /hr In summary, an opportunity identified from the Shell Global Solutions Hydrocarbon Margin Improvement Program at Preemraff Lysekil led to the revamp of an existing the 2-Stage Middle Distillate Hydrogenation unit to increase production of the highly valuable Swedish MK-1 Environmental Diesel. Working closely with Criterion Catalysts & Technologies and Shell Global Solutions, a solution combining market leading hydrotreating catalyst and reactor internals was designed, developed and implemented within the space of 7 months from initial conceptualisation to installation and production, without incurring any extra time loss for making the reactor modifications. This project has allowed Preemraff Lysekil to overcome the constraints limiting middle distillate production, in particular for Swedish Mk-1 grade. And this will make a significant on-going contribution to increased revenue and delivering on one of many initiatives identified in the original Hydrocarbon Margin Improvement Program. The on-going sustained improvement in unit performance has exceeded the original expectation from the program and the premise on which the revamp project was recommended and approved. Acknowledgement The authors would like to acknowledge the contributions of the following people during the Preemraff Study and implantation of the revamp project to maximise middle distillate production at Preemraff Lysekil refinery: Mats Hornfelt Preemraff Lysekil Morgan Svanberg Preemraff Lysekil Bernard Poussin Crealyst catalyst logistics support Volker Dreessen Buchen catalyst loading and management Carl van der Grift Porocel Adsorbents, Catalysts & Services Tom Smith Gayesco Gabe Garza Gayesco Ronald Klute CRI/Criterion Liz Allen Shell Global Solutions John Nickson Shell Global Solutions Jan Stolwijk Shell Global Solutions References 1. Bordogna, E., HDA activity of SC-50 vs. SC-1 under Preemraff Lysekil conditions, Confidential Report, April Schouten E.,Stolwijk, J.,Ouwerkerk, E., et al., Choosing Optimal Quench Interbed Technology:Shell Ultra Flat Quench, BBTC, Annual Meeting, September Egby, C., and R. Larsson, Leading-Edge Technology Combined with Team Approach Achieves Winning ULSD Solution for Preemraff, ERTC 11th Annual Meeting, Berlin, November Torrisi, S.P.,Street, R.D., DiCamillo, D.J., Smegal, J.A., Bhan, O.K., A. Et al., Catalyst advancements to increase reliability and value of ULSD assets, NPRA Annual Meeting, San Fransisco, California, March Maas, E., Bordogna, E., Part A Technical Proposal for the revamp of R-2851 in Preemraff Lysekil, Confidential Report, February Davé, D Axeborne, L., private communication between Shell Global Solutions and Preemraff Lysekil on experience with Shell reactor internals installed in the MHC unit in Licensing Solutions I 10

12 Licensing Solutions Cost effective management of a High-Vacuum Unit revamp High-vacuum unit (HVU) revamp can have significant impact on vacuum gasoil yield improvement, according to Alie Hoksberg Licensing Technology Manager, Shell Global Solutions International B.V. There are numerous options, so choosing the right one makes a big difference. About the technology Vacuum distillation revamp is one of the key opportunities, according to the Shell pentagon model of options for short-term revamps, during times of constrained capex. Shell s deep-flash high vacuum unit is considered to be at the leading edge, enabling significant diesel yield improvement. Vacuum units take the 350+ fraction out of crude oil and distil it into a light vacuum gas oil for diesel purposes; it might make a medium and a heavy vacuum gasoil or they might be combined. They can feed into thermal crackers, cat feed hydrotreaters, or into a hydrocracker. The vacuum residue can go off to delayed cokers, residue hydroconversion units or Visbreakers: i.e. a whole range of options. All products have their own limitations, and we will see just how we manage some of those. Basically, a vacuum distillation unit consists of a vacuum system, condensation and separation sections to produce diesel and VGO fractions, a vacuum residue (VR) in the bottom of the column, a VR de-entrainment section to keep the bottom of the column from coking and the furnace. Traditionally i.e years ago, the furnace outlet temperature was limited to o C because of coking issues. Every year or two the unit would have to be shutdown, steam-air decoked and the furnace cleaned out. Since that time, Shell has developed a technology called suppressed vaporisation that controls the flow regime in a furnace. The liquid coats the walls continuously throughout the furnace and there is vapour through the middle; completely avoiding the mist flow region where the droplets can hit the very hot walls and form coke. Consequently, the units can operate for up to five-year cycles problem-free and at much higher temperatures of 435 o C. Those process conditions are maintained in the transfer line from the furnace to the column, there are often multiple expansions in line diameter as it comes along, each one of them adjusting the flow pattern and keeping it correct. The transfer line itself can have quite a sizeable pressure drop, which keeps the furnace in the correct flow regime. At the end of the transfer line, you are typically running at 80% of sonic velocities The second part is quite critical; you have got to have a low vacuum. If you want to get a deep flash, you need a high flash zone temperature and very, very low flash zone pressure. Traditionally, people have tangential inlet devices coming into their vacuum columns. The problem is that they are high-pressure drop devices that use centrifugal force, so evaporation occurs progressively as you go around the column. Shell, on the other hand, now has used for about 40 years a Schoepentoeter device, which is effectively just a trumpet, vane-type inlet device. When Shell has done true in-column measurements of pressure drop, we have been unable to detect no pressure drop at-all across the Schoepentoeter inlet device. The actual distribution sweeps very rapidly backwards and forwards across these, achieving almost perfectly uniform distribution. Thus far, the largest column we have put them in was about 15.5 m in diameter. The next stage is that the rising vapours, which contain some entrained liquid, have to be cleaned. The droplets rise at very high velocity in the column, at a pressure of about 10mm of mercury in the flash zone, so vacuum residue entrainment occurs. The operator should avoid entrained materials that contain metals and conradson carbon, so an effective wash oil section is required. Shell recommends using a few layers of open structured packing. Separation occurs at the flash zone, removing all the light material and leaving heavy material at the bottom. A quantity of distillate is drawn off and pumped round for washing. Every time distillate is pumped round, material is condensed and some is lost, so it is important to minimise the wash oil flow rate; determined by the wetting rate of the packing and specific design rules. At Shell we can keep this wetting rate down to an absolute minimum whilst ensuring longer than 5 year run lengths. The percentage of flood in the column can be monitored online, showing the entrainment rate in comparison to the theoretical value. In order to get down to 10mm of mercury in the flash zone, very low pressure drop tools are required. 11 I Licensing Solutions

13 Licensing Solutions The column is also equipped with draw-off trays. Traditionally, many operators use huge drawoff trays with large sumps to hold product. This approach added to column height and restricted space in the column for vapours to travel through. However, the long established Shell double-decker total draw-off tray has a high open area, and a simple design. The Shell low pressure drop total draw off trays operate at about 0.5mm mercury per tray and are easily installed and changed. The draw-off trays are insulated, as high vacuum columns have hot rising vapour with temperature profiles ranging from 435 o C in the flash zone to o C at the top. Low in depth, at mm, the insulated trays boost yield about 1%. Vacuum columns have evolved considerably since the 1950s, from columns with trays to columns with structured packing for low pressure drop. The ideal vacuum column contains nothing. Shell have developed vacuum distillation technology with only two packed bed sections; one packed bed in the bottom to remove vacuum residue entrainment, and a second packed bed at the top for producing diesel fuel. All other sections, i.e. the condensation sections, are empty spray sections. The result is a typical run length of five years. Cut points, not TBP endpoints, are run between heavy VGO and vacuum residue of about o C, also producing on-grade for hydrocracker feed; with less than 1ppm of metals, for Arab light, medium and heavy type feeds. If a low pressure vacuum column can get down to these conditions with no metals present, this means more capacity for the hydrocracker and greater production of diesel fuel production. Let s look at an existing case study:- What was the problem? A conventional configuration consists of a crude distiller, vacuum column, a visbreaker and vacuum distillates or VGO side draws feeding a hydrocracker. Consider the case of a hydrocracker making little distillate. The customer s unit was running a cycle of three years on average, and probably in lower production years with fairly quick shutdown for decoking. Bad flow distribution of the wash oil meant issues with coking up of the packing. Once the packing is coked, metal and conradson carbon build up in the VGO products forcing a refiner to reduce the HVU cut point. In addition, the column was also running at maximum loading, i.e. at maximum velocity up the column. Shell columns can run liquid loads higher than most, but columns can still reach their limits pretty quickly. The furnace was operating at maximum load, so the refiner couldn t simply take advantage of increasing the temperature of the furnace. The customer wanted to boost VGO capacity; longer cycle length; quick payback; and to implement this work in a normal shutdown without penalty.. What was the proposed solution and results? To limit capex, the spray headers of the existing vacuum system were simply modified for good distribution. The wash oil bed was redesigned and a different type of packing installed with proper coverage and lower pressure drop. Shell also installed insulated draw-off trays and new stripping trays. Depending what type of furnace is upfront, whether a dry system with no steam or with steam, the incremental yield at the bottom may be minimal if deep cut points are achieved. With more steam injected, the harder it is to condense at the top. The customer started with a vacuum residue yield of just 47% and distillate yield of %. After revamp, distillate yield increased by 1.8%. For an installed cost of $1.1 million, the column produced about 78,000 t/y more heavy VGO feed to the hydrocracker, with margin gain of about $1.5 million, and payback in under a year (as it was requested by the customer). This is on a 350-day year basis if you run a five-year cycle with an average turnaround maybe of days for a high-vacuum unit. To keep costs down, several options were not pursued in this case. Shell could have installed a new dirty wash oil systems, with a new draw-off vessel and improved circulation, but the economics did not stack up. The column had already gained 1.8% yield, and the additional work would have lifted yield 0.5% (about $400,000 for another $2.3 million investment, meaning six-year payback), so it was not the right way to go. Conclusion While this pacesetting technology has been around for a few decades, column are getting bigger, capacities keep rising, and cut points get deeper and deeper. Revamps can be carried out during the normal shutdown period and payback is easily under one year. As a rule of thumb, careful selection of the right parts to upgrade in a vacuum unit will maximise returns. Alie Hoksberg Licensing Technology Manager, Shell Global Solutions International B.V. Licensing Solutions I 12

14 Licensing Solutions Thermal conversion revamp boosts diesel production Thermal conversion is cost effective, versatile and can handle a wide range of feed stocks for helping refineries margins along, with visbreaking, explains Okke de Boks Technical Director, Refining and Chemical Licensing, Shell Global Solutions International B.V. About the technology Thermal conversion offers flexible and cost effective opportunities to boost margins, by selective, phased investment based on incremental economic analysis. There are two distinct elements in a thermal gas unit (TGU): visbreaking, to convert the residual part of the cut, and thermal cracking which takes distillates and cracks them into diesel and other products. The two elements can be combined into one efficient process unit, called the thermal conversion process. Thermal cracker units revamps have been carried out by Shell since the 1960s and fit into multiple refineries configurations: from simple to complex, creating opportunities for continuous optimisation. The basic feature of a standard thermal gas unit (TGU) is the residue furnace, which is fed by atmospheric or short residue. Some have an optional soaker or reaction chamber to extend the residue residence time for continuous cracking (operating temperatures rise to 450 o C). The cracked products flow to a cyclone (used to separate the vapour and liquid efficiently at high temperature and prevent coking in the atmospheric column). Vapour from the cyclone is routed to the atmospheric distillation column and unconverted material is cooled to a lower temperature and fed into a vacuum distillation column. Traditionally, the visbreaking component and the thermal cracker were independent units. However, conversion of the two streams into one unit is very flexible in terms of feedstock including, extraction from vacuum gasoil (VGO), atmospheric and flash residue, deasphalted oil (DAO) and asphalt. For example, the VGO can be converted in a cracking furnace to gas oil and product in a recyclable process, which can be carefully controlled to select different products. Thermal conversion is cost effective and compares well to alternative revamp schemes such as fluidised catalytic cracking, hydrotreatment units, 13 I Licensing Solutions and residual hydrocracking. Generally, the capex is significantly lower for thermal conversion and the technology is well established. Thermal conversion also fits well in a phased development program, where raising capex is increasingly difficult. Case Study In the following case study, visbreaking and thermal cracking are core elements of a long conversion history. Today, as a zero fuel oil refinery the visbreaking and thermal conversion units are dominant. The residue conversion process has also been upgraded in combination with cogeneration gasification to produce 250MW of electricity a year, along with bitumen production. Since start up in 1952, the capacity of refinery has risen from 500,000 to 4 million t/y. Starting mostly as a fuel depot, conversion capacity was gradually increased to reduce fuel oil over the years and increase distillate output. In 2001, after extensive evaluation, the refiner decided to build a gasification plant to produce power, and reduce fuel oil to zero. In 1957, the refiner initially invested in a coil cracker. In 1973, a high vacuum unit was added. Coke intake increased. The refinery imported atmospheric residue and installed a high vacuum unit, revamped the product fractionator and installed larger coil cracker, which reduced fuel oil from 49 to 38%. Shell converted the coil cracker into a

15 Licensing Solutions soaker visbreaker in 1983, reducing fuel oil another 5%, with payback in less than three months. Thermal conversion is cost effective and compares well to alternative revamp schemes such as fluidised catalytic cracking, hydrotreatment units, and residual hydrocracking. In 1990, the soaker visbreaker was converted to a TGU followed but the high vacuum operation move to deep flash operation, for incremental recovery of distillates. An additional Shell distillate conversion stage took the VGO and cracked it through a furnace, using internal hydrogen transfer. The distillate cracking stage was able to convert up to 80% of the VGO into gasoil with minimal amount of residual material reducing the fuel oil from 33 to 26%. The cracked residue vacuum flasher is a key component of a deep conversion flow scheme and has consequences for the cracked residue and bitumen. The capacity of the TGU increased in 1995 and further reduced production of fuel oil. A second vacuum column was added at the backend to recover VGO from the converted vacuum gas oil. The biggest investment was made in 2000 with the installation of a gasification unit for electricity generation. Various flow schemes were also examined for hydrocracking, but the refinery decided with thermal conversion technology, which was the most valued flow scheme for power production. The refiner added another distillate stage with imported heavy gas oil as feed, which improved the overall profitability. This features two cracking stages, an additional furnace for residue conversion and a furnace for vacuum flash. This incremental approach to refinery conversion has been justified by incremental economics, rather than the aesthetics of good integration if design had started from scratch today. The refiner also had a journey towards reducing fuel oil that was economic for the last decade. Shell has been invited to do a study to identify better integration of some of the components in this refinery, because heat integration between all the different fuels is not necessarily optimal, driven also by the pressure to reduce carbon footprint. A feasibility study is currently underway, to improve energy balance by integration of certain columns. Shell also offers deep thermal conversion (DTC) process where the refiner can increase the severity of the furnace even further, to convert material into valuable distillates. This is often a fine balancing act, because if liquid residual fuel can t be utilised in the refinery, the conversion capability is limited. Some customers are considering DTC as an option for grass root refineries, as an alternative to coking. DTC can achieve conversion levels of 50-60%, and could have an application where coke is a constraint. The residue could possibly be combined with coke for power generation, as it is an extremely flexible process. So coke has a place in zero fuel oil refineries. Conclusion There are numerous options for thermal conversion. Margin can be increased by multiple options including feedstock change or technology: by debottlenecking, running furnaces at high temperature, modifying column internals, or increasing run length. Most of the current cracking furnaces have a constraint in terms of coking tendency, but special know-how is available to limit coking. Generally, thermal conversion is a very flexible process, offering good, fast payback not simply for revamp purposes but also for grass root refinery flow schemes faced with cash constraints and generation of substantial margins in short payback periods. Okke de Boks Technical Director, Refining and Chemical Licensing, Shell Global Solutions International B.V. Licensing Solutions I 14

16 Licensing Solutions Gas/liquid treatment and sulphur recovery Shell s suite of technology offerings for hydrotreating, sulphur recovery and sulphur recovery tail gas treating has been expanded to include liquid product desulphurisation capability and end of pipe flue gas desulphurisation technologies. Dave Clark General Manager Process, Refining and Chemical Licensing, Shell Global Solutions International B.V. and Rick Birnbaum Cansolv Technology Sales Manager, Shell Chemicals Americas Inc, compares and contrasts how these new additions to Shell s technologies can be exploited. The world is increasingly dominated by high sulphur, heavier crudes and a changing product mix. Tighter product specifications and more stringent environmental regulations, require refiners to adjust their sulphur management strategies, introduce new sulphur recovery solutions and upgrade existing refineries. Effective sulphur recovery is a vital tool for optimising environmental performance in refinery operations. Shell has provided high-level sulphur recovery unit (SRU) designs for many years based on the Shell Claus Off-gas Treating (SCOT) system. The SCOT process allows conversion of over 99.9% of the sulphur compounds fed to the SRU to elemental sulphur. New features in the SCOT Process allow it to consume less energy through better catalyst systems and to treat to lower 15 I Licensing Solutions concentrations of H 2 S in the treated gas through better amine management. Shell Global Solutions has expanded its ability to address sulphur problems through two initiatives. Shell recently signed a marketing agreement with Merichem, to improve its LPG treating ability. Shell also acquired Cansolv Technologies Inc., in November 2008, to expand its offerings to manage emissions of SO 2 in refinery stack gases. The Merichem technologies are designed to remove hydrogen sulphide, mercaptans, carbonyl sulphide and other contaminants from hydrocarbon streams. Regenerable caustic-based technologies, like Merichem s, have been used traditionally to remove carbonyl sulphate (COS) and mercaptan from LPG streams and to treat mercaptan and COS in both middle and heavy distillates. The CANSOLV SO 2 Scrubbing technology focuses on the end of pipe capture of sulphur compounds as SO 2 from refinery stack and tail gas streams. The sulphur that is captured as SO 2 is recycled to the Sulphur Recovery Unit and converted to marketable, elemental sulphur. Within Shell s pentagon model of operational improvement, sulphur dioxide treatment can have a marked effect on economics and refinery efficiency. Historically, there has been a price spread between sweet and sour crudes, ranging from $5 to

17 Licensing Solutions Effective sulphur recovery is a vital tool for optimising environmental performance in refinery operations. $40 a barrel. Refiners have historically utilised this differential to improve their profits by upgrading heavy fractions to more valuable products. The spread between sweet and sour crudes disappeared late in 2008 and refiners are now readjusting their refining strategies, reducing their purchases of heavy sour crudes and increasing their demand for sweet crudes. Refiners will need to be able to position themselves for an inevitable reversal of this trend, as the long term supply of sweet and light crude stocks decline. Upgrading heavier and sourer crudes to more valuable products requires investment either to add hydrogen to heavy bottoms products or to remove carbon from the bottoms stream. Both routes raise fuel consumption, increase the extent of hydrotreating practised by the refinery and directly or indirectly produce additional volumes of hydrogen sulphide that must be processed in the sulphur recovery unit (SRU). Shell s suite of process technologies is broad enough that it can be directed to many of the refiner s processing and environmental problem areas. Shell s partner, Criterion Catalysts, has considerable expertise in addressing complex hydrotreating issues. Shell s new relationship with Merichem introduces a new suite of products to treat product streams and Shell s SRU technologies can help de-bottleneck or add capacity and control sulphur emissions from the SRU with its SCOT technology and through its acquisition of CANSOLV SO 2 Scrubbing Technologies. Environmental Pressures on the Bottom of the Barrel Additional environmental pressures are on the horizon. Bunker fuel markets serve as an outlet for a large percentage of the organic sulphur fed to the refinery. The International Convention on the Reduction of Pollution from Ships (MARPOL) has mandated a staged reduction in the allowable sulphur content of maritime fuels, which will drop to less than 0.5% by Sulphur will either need to be removed from refinery bottoms, or refinery bottoms products will require new outlets. Air pollution regulations enacted in both Europe and the United States have taken effect, which have caused refiners to capture SO 2 in non regenerable SO 2 scrubbers and re-direct the resulting waste either to landfill or to the wastewater treating systems. Tighter limits for wastewater and landfill disposal practises will put pressure on refiners to consider regenerable SO 2 scrubbing systems, that direct sulphur into existing sulphur by-product market streams. SO 2 Scrubbing Options Refinery operators have two options to capture SO 2 from flue gas streams. Non regenerable scrubbing technologies use alkaline materials such as lime, limestone or caustic soda to generate sodium or calcium sulphate. Regenerable scrubbing technologies use alkaline agents to absorb SO 2 from flue gas and regenerate these agents to produce a pure SO 2 product that can be integrated into an existing sulphur conversion system. Regenerable processes ultimately produce less by-product than non regenerable processes. One pound of sulphur dioxide adsorbed from flue gas generates two or more pounds of waste as sodium or calcium sulphate but only half a pound of elemental sulphur, when converted to sulphur in the SRU. If plentiful supplies of alkaline reagent are available and there is large, environmentally acceptable capacity to dispose of the associated solid or liquid waste, (which is increasingly difficult in Europe and other locations worldwide), then a nonregenerable SO 2 scrubbing process is likely to have the lowest capital and operating costs in comparison to regenerable SO 2 scrubbing processes. FCCU Regen Gas Scrubbing Sulphur contained in the VGO fed to the fluid cat cracking unit (FCCU) distributes itself to product fractions, FCCU bottoms and to regenerator off gas. Caustic scrubbing is most often used to capture the SO 2 from the regenerator off gas, but this generates a wastewater stream of sodium sulphate that is directed to the wastewater treatment unit. A CANSOLV System can be used in place of a caustic scrubbing system, capture the SO 2 and direct it to the refinery SRU. If the sulphur load is sufficiently high, it can affect SO 2 scrubbing more economically than can be conducted by an equivalent caustic scrubbing system. Consider an 80,000 bpd partial burn FCCU, processing VGO containing 2.5% sulphur. In this case, flue gas exits the catalyst regenerator and flows to a carbon monoxide (CO) boiler. Particulate matter in the regenerator off gas is assumed to be caught in an electrostatic precipitator or a high efficiency particulate removal device upstream of the CANSOLV System. The Cansolv system in this hypothetical current year example of a U.S. refinery case, captures SO 2 and delivers it to the SRU for an inside battery limit, total direct cost, of about $20 million on a US Gulf Coast basis. The CANSOLV system consumes steam, costing about $5-6 million a year and contributes $2.9 million of revenue for by-product sulphur captured as SO 2 from the regenerator offgas. Payback is 1-2 years compared to using a non-regenerable system with caustic. The Cansolv SO 2 scrubbing flow sheet starts with a combustion and heat recovery unit, followed by gas cleaning and cooling, and finishes with an amine absorber and regenerator. The Cansolv SO 2 scrubbing system is similar to traditional amine systems for removal of H 2 S and CO 2 Licensing Solutions I 16

18 Licensing Solutions from gas streams. Prior to entering the SO 2 Absorber, the gas must be cooled to about 55 o C in order to allow the CANSOLV System absorb SO 2 to less than 100 ppm. Steam, used to regenerate the solvent, is the main consumable in the CANSOLV System. Resid Gas Combustion A refinery may choose to resolve the imbalance in heavy bottoms markets vs supply by converting on site fired heaters or steam generation systems to high sulphur, liquid fuels. A hypothetical, 250,000 barrel a day refinery which is faced with a weakening market for a high sulphur bottoms product, might choose to consume part of its bottoms products as refinery fuel in a cogeneration type of project. In a case in which 15,000 barrels a day of 4% sulphur fuel is burned, an investment of about $40 million would be required for a CANSOLV System, and add $14.6 million of operating cost to the project. If additional revenue of $8 million a year were generated from by-product sulphur, a one to two year payback would be generated in comparison to the lime or caustic option. CANSOLV SO 2 Scrubbing Systems have been selected by several refinery licensees for both boiler and FCC unit applications. One refiner chose to use CANSOLV SO 2 Scrubbing to capture SO 2 from all process heaters and steam generators. This user had no commercial outlet for its high sulphur bottoms products and natural gas was not available to serve as the balancing fuel for the refinery. A second licensee chose a CANSOLV SO 2 scrubbing system to capture SO 2 from its FCCU regen gas because local state regulations mandated that sodium sulphate, generated by a non regenerable process, could not be disposed of directly to its in waste-water effluent system. Improvements in SCOT SRU Tail Gas Treating The Shell Offgas Treating (SCOT) is in use at many refineries around the world. The SCOT system is ideal where there is a mandatory requirement to achieve in excess of 99.9% conversion efficiency. In response to additional pressures to reduce emissions, Shell has perfected the (LS) SCOT process, that can treat SRU tail gas to less than 10 ppm of H 2 S at the outlet of the amine absorber. Since the tail gas H 2 S content can be reliably maintained below 10 ppm of H 2 S, the thermal oxidiser can be operated in a hot standby mode, instead of in a continuous operation mode, saving significant amounts of thermal oxidizer fuel in the process. To improve SCOT economics, Shell has increased the energy efficiency of the SCOT process through the introduction of the new low-temperature SCOT reactor. 17 I Licensing Solutions In this configuration the use of a low temperature hydrogenation reactor allows the standard inline burner/reduced gas generator used by the SCOT process, to be replaced by a simple steam driven heat exchanger. Fuel demand is reduced and costs are lowered. Impact of External SO 2 on the SRU and CANSOLV SRU Tail Gas Treating CANSOLV SO 2 Scrubbing can also be used as a tail gas treating system. It can remove SO 2 to less than 100 ppm and return the SO 2 to the SRU for destruction. If our hypothetical 250,000 BPD refinery also uses the CANSOLV System to capture SO 2 from both the FCCU and from resid fired boilers and additional H 2 S has been generated by more aggressive hydrotreating elsewhere in the refinery, then the SRU capacity might be increased from 350 t/d to 600 t/d of sulphur without additional air blowers, reaction furnaces or claus reactors. If the CANSOLV System is used as a stand alone tail gas unit for the 350 t/day SRU, it would be expected to cost about $7.1 million with operating costs of about $1.2 million a year. Refiners now have to weigh up a range of options for sulphur management, bearing in mind whether they want to integrate SO 2, improve an existing SCOT or address caustic treatment of distillate and LPG streams to control refineries. Whatever the choice, Shell offers a one-stop shop. Dave Clark General Manager Process, Refining and Chemical Licensing, Shell Global Solutions International B.V. Rick Birnbaum Cansolv Technology Sales Manager, Shell Chemicals Americas Inc.

19 Shell Global Solutions is a network of independent technology companies in the Shell Group. In this magazine, the expressions Shell Global Solutions and Shell are sometimes used for convenience where reference is made to these companies in general, or where no useful purpose is served by identifying a particular company. The information contained in this material is intended to be general in nature and must not be relied on as specific advice in connection with any decisions you may make. Shell Global Solutions and Shell are not liable for any action you may take as a result of you relying on such material or for any loss or damage suffered by you as a result of you taking this action. Furthermore, these materials do not in any way constitute an offer to provide specific services. Some services may not be available in certain countries or political subdivisions thereof. *Engineering services in the United States of America are provided by Shell Global Solutions (US) Inc. For projects in the United States of America that entail engineering services, Shell Global Solutions (US) Inc. will retain appropriately licensed engineers as necessary. Please note that certain engineering projects are not offered and are not available to the public in any/some of the States and Territories of the United States of America. All the quotations in this document have been reproduced with the kind permission of our clients. Copyright 2010 Shell Global Solutions International BV. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical including by photocopy, recording or information storage and retrieval system, without permission in writing from Shell Global Solutions International BV.

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