Big policy changes are needed in the energy system.

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Today, refinery operators face a range of new technical, regulatory and commercial challenges: ensuring that their operations meet environmental standards; complying with new fuel specifications; and upgrading their refinery capability to meet capacity and quality targets.

At such a time, Shell Global Solutions says its hydrocracking technology help refiners around the world to deliver the products at the performance they need in today's market place and to meet stringent fuel quality regulations. John Baric, technology manager, Shell Global Solutions International, an expert on hydrocracking technology for clean fuels, in an exclusive interview with OGN, explains why CHGO (coker heavy gasoil) and DAO (deasphalted oil) hydrocrackers are a good option for conversion of residue directly into clean fuels and the benefits of hydrocracker designs that have the flexibility to process a variety of feedstocks for the industry. Baric joined Shell Canada in 1981 as a refinery process engineer and has since undertaken numerous roles covering activities such as commissioning and startup of a continues catalytic reformer (CCR) Platforming and Aromatics complex, technical specialist and consultancy roles in hydroprocessing, technology selection for achieving compliance with low sulphur fuels legislation, and support to refinery master planning. Baric is currently the licencing technology manager based in Shell Global Solutions' Amsterdam office, responsible for Shell's hydrocracking and distillate hydrotreating technology. He has 26 years experience with Shell, having held various positions in Shell's global refinery operations, technical services, project management and business development. Excerpts from the interview: What challenges do the increasing demand for transportation fuel products bring to companies like Shell? And how does Shell tackle these challenges? For the past year or so, demand for energy grew strongly, increasing pressure on supplies and prices. Energy-producing countries continued to assert greater control over resources, reinforcing fears in many energy-consuming countries about the security of their supplies. Concerns rose further about the threat of climate change. It has become clear that the world will need vast amounts of extra energy in the coming decades to support economic growth. Countries' supplies will have to be kept safe from disruption. And this energy will need to be produced in environmentally and socially responsible ways, including dealing with greenhouse gas (GHG) emissions. This is the energy challenge. Meeting it is becoming one of the defining tests facing society -- and our industry -- this century. Three hard truths make this challenge tougher. First, demand for energy is growing rapidly as several large countries enter the most energy intensive phase of economic development. Second, supplies of easily accessible oil and natural gas will probably no longer keep up with demand after 2015. To close the gap, the world will have no choice but to use energy more efficiently and increase its use of other sources of energy. This means more renewables like solar, wind and biofuels, more nuclear energy, more coal, and more oil and natural gas from difficult to reach locations or unconventional sources like oil sands. And third, that as a result, CO2 emissions from energy, responsible for more than half of man-made GHG emissions, are set to rise, even as concerns about climate change grow. Against this backdrop, it is clear that sustainable development is critical to everyone's future and to business success in the industry. Tomorrow's projects will be even more difficult, complex and capital-intensive. All will bring environmental and social challenges, with climate change foremost among them. Shell's ability to develop new technologies and to manage these projects in ways that reduce impacts and deliver local benefits in the communities where we work, are vital for us as we win new business and deliver existing projects. We are coming from and going forward to a position of strength. In 2007, we reported record income of $31.9 billion. We are reinvesting record amounts back into the business and strengthening our capacity to manage environmental and social impacts. Our safety performance -- always our first priority -- improved, though it must get better still. We decided to quadruple our rate of investment in transport biofuels, particularly in those using more sustainable second-generation technologies. Work continued to meet our aim of having the capability to capture and store carbon dioxide (CO2) -- a promising way to manage GHG emissions. Today, we are the only major oil and gas company still to have a target to reduce its total GHG emissions. But we don't believe relying on voluntary

caps by individual companies is the best way to tackle climate change. So instead, to get all companies and all sectors to act, we are encouraging government regulations that reward lower CO2 sources of energy and greater energy efficiency. We are also moving to targets for individual facilities to help our operations improve their energy efficiency and manage CO2. The ambition for most assets will be to have CO2 emission levels that are in the top 25 per cent of similar facilities. Achieving this will involve a combination of greater energy efficiency and further progress on carbon capture and sequestration (CCS). Because the changes needed in the energy system are so big -- and policy is so important to achieving them -- we have stepped up our advocacy efforts with governments. Advocacy for some may suggest companies blocking change or advancing their own narrow interests. But we are calling for change, lending our expertise and working cooperatively with governments, companies and other partners in society. We are sharing our technical knowledge, experience and understanding of the energy system directly with policy makers. For example, we are presenting our Strategic Energy Scenarios, that describe two routes the energy system could take between now and 2050, to governments and international institutions, to help them understand the challenges, trade-offs and urgency involved in building a responsible energy future. We are also helping to build the coalitions of companies, governments and non-governmental organisations (NGOs) needed to create support for effective policy. For example, we are part of the US Climate Action Partnership. We are on the steering board of the G8's Gleneagles Dialogue on Climate Change and we participate in the UK's Low Carbon Vehicle Partnership. In the wake of stringent mandates for sulphur reduction across all transportation fuel, how have refiners been impacted? How much investment do refineries need to invest to meet future specifications for fuels? The specifications of the products that come out of the refineries are getting tighter and tighter, meaning less and less sulphur allowable in the product. At the same time, due to increasing availability of lower priced heavy sour crudes replacing traditional light sweet crudes, the crude oil entering the refinery has sulphur content that has recently gone up. Therefore, refineries face a significant challenge in terms of the costs associated with reducing product sulphur, both from the capital cost on investing in new technology and increased operating cost. Geographically, refineries in the US, Japan and Europe are almost at the end of the specification reduction cycle, with sulphur in mogas and diesel varying between 10 to 15 ppm. These refineries have already made investments in naphtha and diesel hydrotreating and have absorbed the additional costs. For regions like the Middle East, India and China, this impact is coming very quickly. However, the real challenge for refineries moving forward will be the reduction of sulphur specs in fuel oils. In sulphur emission controlled areas, for example, governments are imposing restrictions on the sulphur content of fuel oil used by ships that are sometimes very significant. Typically, the sulphur levels of high sulphur crudes are 2.5 to 3.5 per cent and this will have to be reduced to 1 per cent or even less for the fuel oil product that comes out. That is difficult to achieve in today's refinery, and the impact of this is significant for refineries' operations because of the need to invest in appropriate technology to be able to treat such heavy products. As compared to naphtha and diesel hydrotreating, such residue upgrading technology has substantially higher capital and operating costs associated with it. These days one must be very cautious in quoting capital costs due to continued escalation in project costs, driven by an almost simultaneous worldwide demand for the same resources; engineering, raw materials such as steel, fabrication and of course the skilled labour needed for construction. As we speak, labour rates in the Middle East are increasing and labour productivity is decreasing. This follows the same trend already seen in the US Gulf Coast, Northern Alberta, Canada and Western Europe. However, using indicative cost estimates to 'paint the picture', a typical investment for a refinery in two new hydrotreating units, of 30,000 to 40,000 barrels per day (bpd) capacity, to achieve 10 ppm sulphur for mogas and diesel, including a small new hydrogen manufacturing unit (HMU), can be up to $500 million, when taking into account both inside (primary units) and outside (tankage, utilities, pipeline) battery limit investments. That same refinery will need to invest up to an additional $2 billion on a residue-upgrading project to deal with the high sulphur fuel oil. Such a project would typically include a primary residue-upgrading unit, such as a delayed coker, ebullated bed or solvent deasphalting unit, plus a hydrocracker, a much larger HMU, a sour water stripper plus gas treating, amine regeneration and sulphur recovery. Sulphur is of course a natural co-product to oil and gas processing. As we rely on more unconventionals, it is likely that there will be more supplies of sulphur. Shell has developed a dedicated sulphur business to utilise this excess sulphur. Shell Sulphur Solutions was launched in September 2007, reflecting Shell's commitment to developing responsible energy solutions. Backed by Shell's formidable research and development capability, the business is not only focused on global sulphur marketing but also on developing pioneering products and applications which will provide innovative uses for sulphur while being designed to meet social and environmental development targets. The range of sulphur-based products includes sulphur road applications, sulphur enhanced fertilisers and sulphur concrete. What are the alternative technology options for clean fuels available to refiners today and are they cost effective? The majority of commercially established technologies for producing clean fuels are hydroprocessing technologies; using catalysts at relatively high temperatures plus hydrogen. There are a number of licensors offering such technology and today's refiner usually has 3 to 4 commercially proven options to select from, both for mogas and diesel hydrodesulphurisation. For mogas, it is all about selective desulphurisation of fluid catalytic cracking (FCC) naphtha; removing the sulphur but retaining the octane. For diesel, it is all about managing hydrogen and energy consumption while producing ultra low sulphur product. It's a somewhat more confusing story for residue upgrading technology for eliminating or reducing high sulphur fuel oil. The available primary residue upgrading options are quite diverse in the technologies being employed and the impact on the existing refinery economics. In general, there are two main routes to residue upgrading; 1)carbon rejection, such as delayed coking, residue FCC, solvent deasphalting and visbreaking, which themselves do not consume hydrogen, although their products need further hydrotreating and/ or hydrocracking, which will consume hydrogen; and 2) hydrogen addition, such as residue hydrocracking, using ebullated bed or bunkeringbed, or residue hydrodesulphurisation, using fixed bed technology. Residue upgrading economics are complex and a rigorous feasibility study must be done for each application to ensure the most economical technology and configuration is selected. Similar to hydrotreating, there are several commercially proven options to select from. Most refineries use a tendering/bidding process to select a technology from a licensor based on their specific selection criteria. What exactly is hydrocracking technology? And what are its benefits? In today's global market, the products in highest demand are ultra low sulphur diesel (ULSD) and Jet fuel. Hydrocracking is an established and reliable process for transforming low-value, heavy oil fractions directly into these valuable products. hydrocracking technologies are essential in enabling refinery performance to be optimised cost-effectively. Today, the refinery operators face a range of new technical, regulatory and commercial challenges: ensuring that their operations meet environmental standards; complying with new fuel specifications; and upgrading their refinery capability to meet capacity and quality targets. Hydrocracking technologies help refiners around the world to deliver the products at the performance they need in today's market place and to meet ever-more stringent fuel quality regulations. For example, Shell Global Solutions' hydrocracking technology and expertise offer a range of commercial benefits for customers, including: * Technically and commercially competitive technologies; * Long-term sustained operational excellence; * Technical services and advice on unit optimisation that help refiners to meet fluctuating market demands and changing legislation; * Access to ongoing catalysts developments that provide continuous improvement in yield, stability and activity advantages; and * Integrated life-cycle catalyst service and advice. What are CHGO and DAO hydrocrackers? And why are they a good option for conversion of residue into clean fuels? The two primary residue-upgrading technologies most often employed worldwide are delayed coking and solvent de-Asphalting. delayed coking produces naphtha and diesel products, both of which need to be hydrotreated to meet product quality specifications, and coker heavy gasoil (CHGO), which must be further processed in a hydrocracker to produce ULSD and jet fuel. Solvent de-asphalting produces se-asphalted oil (DAO), which has historically been processed in FCC units to produce mogas but is now routed almost exclusively to new Hydrocracker units to produce ULSD and jet fuel. The Hydrocracker feed is therefore determined by the selection of the primary upgrading technology, done as part of the feasibility study. The hydrocracker technology is flexible enough to process a wide range of feed qualities, of diverse origin, at different conversion levels, while always producing on spec ULSD and jet fuel. What are the benefits of hydrocracker designs? The key requirement for the hydrocracker is to produce on spec ULSD and jet fuel from low value heavy oil fractions. The hydrocracker design, which includes catalyst selection and process configuration, will influence the amount of ULSD and jet fuel produced. The proper design can assist in optimising the margin of the hydrocracker and therefore the refinery by achieving higher capacities, less downtime, better yields and product properties, and lower operating costs. For example, by combining advanced process know-how, gained from more than 35 years as a worldwide owner and operator, with high performance catalyst systems and efficient reactor internal design, Shell Global Solutions' hydrocracking process technology can provide high levels of availability that deliver consistently high yields of quality products in an energy-efficient manner. What has Shell's role been in developing new alternative technology solutions for clean fuels? Shell considers technology as being key to its success as one of the world's leading energy companies. In response to its own refining needs, Shell has developed over decades of investment in process and catalytic R&D a very strong position as a hydroprocessing technology provider, not only to its own operations but also to third parties via its licensing organisation. At the same time however, Shell has expanded its R&D investment to technologies outside of hydroprocessing, developing alternative options such as use of biological processes to achieve clean fuels and use of bio feeds for production of ultra clean bio diesel. Could you tell us in detail about the new hydrocracker designs developed by Shell? The detailed aspects of our hydrocracker designs are of course proprietary in nature. However, our guiding principles for design and development are solidly embedded in our unique role as an Operator as well as licensor of technology. Shell is the largest hydrocracker operator in the world with a capacity of over 500,000 barrels a day. Shell Global Solutions provides technical support to over 50 sites around the world. Within Shell there is a drive for continuous improvement, with all refineries targeting for top quartile performance. Additionally, each process unit, including hydrocracking, is benchmarked over years of operation against 'best in class' performers in several parameters. The performance of the hydrocracker has a significant impact on the refinery margin, with key performance indicators such as; sustained capacity and utilisation, downtime, product yields and properties, and operating costs (energy efficiency, hydrogen, manpower, catalysts). Our hydrocracking processes and catalyst developments have undergone continual R&D since they were first developed over 40 years ago, with development and innovation driven by these benchmarking standards. Shell offers designs, whether single-stage (once-through and recycle mode) or two-stage unit, that match customer's product needs -- whether they are to maximise middle distillate or gasoline production, or to produce base oils, or FCC or ethylene cracker feedstocks. The combination of process conditions and catalyst performance is optimised for each unit to deliver maximum product yield and therefore maximum value to our customers. This includes selective production of low sulphur gasoline components and ultra low sulphur diesel, while efficiently using H2 and minimising low value gases. Operator proven technology, configuration, Shell's catalyst business -- Criterion Catalysts and Technologies' hydrotreating and hydrocracking catalysts, and best practices are incorporated into a total hydrocracking solution, which help provide a reliable and energy efficient operation. The market is quickly recognising the value-added capability of Shell's technology and technical service capabilities. As a recent third-party process licensor, Shell Global Solutions has made a strong impact on the hydrocracking market in a very short period. Since 2006, we have secured ten new hydrocracking licenses. The extent of Shell's operations gives us a clear insight into refining distressed crudes (those containing high nitrogen levels or with a high total acid number) and processing difficult hydrocracker feedstocks (those containing high nitrogen levels and having a high end point) while meeting ever-more demanding product specifications. Shell operates hydrocrackers processing these same feedstocks: coker gasoils, fluidised catalytic cracker cycle oils, deasphalted oils, thermally cracked distillates and hydroprocessed gasoils. Extra-deep straight-run vacuum distillates with true boiling point (TBP) cut points of up to 590 deg C (TBP 90 per cent wt of 570 deg C) are processed in several licensed units. Shell Global Solutions' in-house R&D programme has developed a suite of proprietary reactor internals that offer uniform gas/ liquid distribution to increase catalyst utilisation and efficiently quench the highly exothermic reaction. The state-of-the-art reactor internals take up less space, thus enabling higher reactor volume utilisation while maximising catalyst run length. Our internals have been commercially proven in numerous hydroprocessing applications since 1990, more than two-thirds of them outside Shell. The high efficiency of our proprietary feed inlet devices results in smaller separators and smaller fractionation columns, which offers reductions in capital costs. The performance of Shell Global Solutions' licensed and serviced units reflects Shell's focus on the key factors that deliver long-term operational excellence, energy efficiency and production optimisation. From industry studies covering unit performance from 1998 to 2004, a comparison of Shell units with the average industry performance shows a clear and sustained advantage in; Mechanical availability: 1 to 5 per cent above the industry average; On-stream factor: 2 to 9 per cent above the industry average; Utilisation: 5 per cent above the industry average; and Turnaround duration: 8 to 16 days better than the industry average Shell Global Solutions is the only licensor offering a hydrocracker product work-up section that features a single main fractionator. This unique configuration provides a 35 to 40 per cent reduction in fractionation furnace energy consumption when compared with the conventional stripper--fractionator configuration. What are the other innovations in the area of hydrocracking and distillate hydrotreating technology being developed at Shell? The priorities, which provide the 'roadmap' for all of our ongoing process and catalyst developments, come to us from our clients, who operate in a marketplace that today has become much more than just economic, with social and environmental drivers becoming much more important. Our development goals are therefore to minimise the 'footprint' of our technology, which we will achieve by offering designs having higher yields while consuming less resources to achieve them (less steel, less energy, less CO2). Even more significantly, we have challenged ourselves to reduce the footprint of the entire refinery, and we already offer a refinery having a different 'look' from the conventional. Significant components of such a novel refinery layout have already been commercially demonstrated, resulting in refinery sustained top-quartile performance for close to ten years of operation.

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