Abstract Creation of Strategic Petroleum Reserves (SPRs) is one of the contingency measures adopted by Government of India (GoI) to meet energy security mandate. SPRs are oil stocks stored in large underground storage facilities with intrinsic advantages on economic, environmental and strategic safety considerations. The inventories are used to mitigate economic supply disruptions. The crude oil storage alternatives include Salt and Rock caverns, while for natural gas storage, depleted reservoirs, deep aquifers and salt caverns are used. Though salt caverns are the cheapest storage alternative, adoption of storage technology involves availability of suitable geological setting viz. salt formations or competent rock formations with supplementing groundwater regime. Under Phase I storage program, GoI, through a SPV - Indian Strategic Petroleum Reserves Ltd. (ISPRL), under Ministry of Petroleum & Natural Gas, has created SPRs at three locations viz. Vishakhapatnam, Mangalore and Padur for a total storage capacity of 5.33 MMT, involving storage of crude oil in underground unlined rock caverns. Engineers India Ltd (EIL) has been the Project Management Consultant for these coveted projects. The storage installation at Vishakhapatnam and Manglore has already been commissioned in 2015 &2016, the installation at Padur is being commissioned by Q3 of 2017. Apropos Integrated Energy Policy of India; DPRs for the Phase II storage program have been completed and the proposition is under consideration for establishment of additional storage capacity of 10.0 MMT comprising of 4.4 MMT & 5.6 MMT storage capacities at two additional locations, namely Chandikhol, Odisha and Bikaner, Rajasthan entailing storage of crude oil in underground rock caverns and salt caverns respectively. The present paper outlines the storage technologies, concept of SPRs, emergency stock holding pattern and experiences gained during implementation of these projects of national importance and the lessons for emerging oil dependent economies to establish similar storage inventories.

Abstract Worldwide petroleum refining industry is entering into a significant era due to the depletion of light crude. The light crude sources are turning into heavy or extra heavy, which contains large amount of contaminates (S, N, metals, asphaltene etc.) and produce large fraction of residue. Thus, future crude slate is a key issue facing refiners to invest strategically in order to process larger quantities of sourer crude. Refinery operations have to evolve and include next-generation processes and catalysts to fulfill the demand for high-quality transportation fuels. Since the quality of these products has to be improved to satisfy stringent environmental regulations, refineries, which have been traditionally processing light crude oils, face drastic changes in petroleum feed properties, which stubborn great challenges to refining industry to process heavier crude oils. The global trend indicated that the world oil refining industry has to face several challenges for demand as well as supply. At the same time refineries are expected to be under great deal of pressure to accomplish the market demand of high quality fuels (i.e., gasoline and diesel). The world demand for diesel fuels is increasing while fuel oil demand is decreasing. Therefore, the need to convert heavy, extra heavy or residue fraction into valuable products (middle distillate) will increase in order to satisfy market demand. This paper will be focus on examples of the quality parameters that is impending due to the quality of crude oil and presence of high levels of impurities during the processing poor feedstocks in processes such as diesel and resid hydrotreating units. In addition, the understanding of such feedstock by detailed characterization at their molecular level and its impact on the processing will be also highlighted.

Abstract MOL Group is an integrated, international oil and gas company headquartered in Budapest, Hungary, with lead position in its core markets within Central and Eastern Europe. Its northern region downstream business consists of two complex refineries and three steam crackers at two locations. To be able to exploit synergies thus to maximize potential profitability of assets via transfer connections, current downstream planning activities are performed on group level in a multi-site linear planning model resulting in simultaneous optimization possibility of petrochemical and refinery sites. In such a planning model system, next to internal asset constraints, specific utility costs and market purchase or sales conditions drive the optimization result. It does not only support optimal feedstock selection for both refinery (different crude oils provide different yield structure) and petrochemicals (LPG against naphtha feedstock) together with their most profitable asset configuration, but it also enables proper setting of refinery product portfolio against polimer production. In current MOL Group solution, an additional aspect has been implemented for improving the refinery-petrochemical connection: next to its volumetric effect, specific quality of produced petrochemical naphtha feedstock is also considered within the optimization as this information is channeled into the olefin plants in order to better estimate monomer yields of the steam cracker. It provided another milestone of this simultaneous optimization challenge thus improved on its delivered results. The paper focuses on our current best practices by demonstrating how above planning system features support MOL Group Downstream to derive right business decisions. It furthermore explains how our development roadmap puts emphasis on further refinement of the refinery-petrochemicals connection, utilizing state-of-the-art technologies like upgrading our linear optimization models with non-linear correlations.

Abstract Iran has discovered a considerable amount of oil and gas reserves at its territory in the Caspian Sea. The reserves are estimated to contain of about 10 billion barrel of crude oil and 50 trillion cubic feet of natural gas. After some exploration studies, Iran may start production from the said resources. In this article, after reviewing the petroleum activities of the Caspian Sea region, some conceptual approaches have been made on production, refining, and distribution of the above reserves as follows: –It is estimated that priority will be given to the four Iranian coastal provinces at Caspian Sea to be fed from the above sources. Therefore, an oil and gas refinery will be constructed at one of these states. –In case of higher oil production rate, the excess of extracted oil may be sent to Tehran and Tabriz refineries for supplying to other parts of Iran. –Ultimately, the surplus of higher rate will be available for export. However, construction of a large terminal including an oil & gas refinery and a petrochemical complex at Caspian Sea coast is proposed for all activities. The environment impact of the said changes shall also briefly be described. Author: Farrokh Kamali, Advisor at Iran LNG Company (ILC), Iran Inroduction At present, the requirements of petroleum products and natural gas of Northern states of Iran near the Caspian Sea are being provided from oil and gas supplied from South fields of Iran. The crude oil is refined in Tehran and Tabriz refinery and natural gas is processed in Bidbolad and Hasheminejad gas refinery and supplied to the Northern states. However, providing the petroleum products from these refineries and natural gas from far away gas fields are very costly because of consuming energy and heavy investments for transferring installations. Iran recent discoveries at Caspian Sea are an opportunity for the Northern states of Iran because of receiving petroleum products at low cost and being ensured of supply security. The estimated rates of productions, the required facilities for installations, environment impacts of changes and mitigation measures for environment protection are described in this article.

Abstract The 2009 global recession, which reduced oil demand and created tight credit conditions, has largely receded. Oil demand, which had declined, has since begun to grow again. Some of the large projects related to heavy crude production, upgrading and refining that had been suspended have been revived. Oil prices have rebounded and investments in higher cost non-conventional oil resources are again being made in many parts of the world. The lower costs that were seen during the recession have also rebounded, though the costs for labor and services are still lower than before the recession.recession. This presentation will take these changes into consideration. This presentation will highlight conventional heavy oil as well as extra-heavy oil and bitumen production projections. This presentation will provide: * Detailed analysis of North American PADD regions * Disposition by region - internal market vs. export * Country-by-country analysis Resources and state of development Costs and economics Political, environmental and regulatory considerations Production forecasts * New heavy oil projects and expansions * Technology, constraints and environmental impacts * Pricing analysis, cost of processing different quality crudes Refer to http://www.hartenergy.com/Downstream/Research-And-Consulting/Heavy-Crude-Oil-A-Global-Analysis-And-Outlook-to-2030/ Global Heavy Crude Oil Outlook to 2035 Mrs Kristine Klavers Mrs Laura Atkins The 2009 global recession, which reduced oil demand and created tight credit conditions, has largely receded. Oil demand, which had declined, has since begun to grow again. Some of the large projects related to heavy crude production, upgrading and refining that had been suspended have been revived. Oil prices have rebounded and investments in higher cost non-conventional oil resources are again being made in many parts of the world. The lower costs that were seen during the recession have also rebounded, though the costs for labor and services are still lower than before the recession.recession. This presentation will take these changes into consideration. This presentation will highlight conventional heavy oil as well as extra-heavy oil and bitumen production projections. This presentation will provide: * Detailed analysis of North American PADD regions * Disposition by region - internal market vs. export

Abstract The closing of the light/ heavy crude spreads and generally high crude prices have made production of very heavy crudes economically attractive. The next challenge refineries will face is converting heavy, sour, and high metal content feedstocks into high quality transportation fuels (e.g. Euro V). This paper will consider alternatives including traditional configurations to be considered by new refineries, low-cost alternatives for implementing higher conversion capacity in existing refineries, and some of the newer technologies which will likely be considered in refineries of the future. For grassroots refineries, depending on the heavy crude slate to be processed and the specific market trends (maximum gasoline or maximum diesel production), there are several traditional configurations that allow flexibility. These include a fluid catalytic cracker (FCC) with a hydrocracker (HCU) and a delayed coker (DCU) or residue hydroprocessing unit (RHP). Existing refineries without heavy-end conversion configurations can consider evaluating the purchase of existing delayed coking capacity (or components from units never built) at low prices rather than investing in new thermal upgrading capacity. Non-traditional new or ‘novel’ technologies may consider over-cracking at the FCC unit to produce larger quantities of light olefins that can be polymerized to produce a high quality diesel product. Another newer approach is gasifying heavy residue or upgrading petroleum coke to produce synthesis gas that can be converted into high quality diesel via Fischer-Tropsch technology. Producing "green diesel" via hydrotreating or trans-esterification vegetables oils will also make-up a portion of the future global diesel pool. Longer term, bioengineered microbes may be produced to selectively convert heavy hydrocarbons into diesel.

Abstract Long distance transportation of crude oil and refined products by ship and pipeline is expected to grow in the future given the increasing geographic mismatch between demand growth and sources of incremental oil supply. The Middle East, Eurasia and Africa in particular are expected to fuel demand growth in China, India and Europe which will require new pipeline and marine transportation capacity. This Best Practices session will feature successful case studies of new pipeline and shipping solutions that have met the challenges of geopolitics (including piracy), stakeholder support, funding, technology, cost and environmental impact. Introduction Over the past four decades, the tanker industry has taken major steps to improve its safety level and environmental performance. As the transported volumes of cargo have steadily increased on a tonne-mile basis, the industry has managed, through regulations and voluntary performance schemes, to significantly reduce the number of navigational accidents and the sizes and consequences of oil spills. In many respects, we can call this a success story. From the graphs below, it is easy to see the positive trend. Although the tanker industry's performance has improved, the industry should not be complacent and satisfied and rest on its laurels. During the last five to ten years, another challenge has emerged. Emissions to air are increasingly influencing the tanker industry and other shipping segments - and the need to meet the future requirements and expectations of regulators and society at large has become ever more important. The revision of MARPOL Annex VI and, not least, the establishment of Emission Control Areas (ECAs) imply strict limitations on SO X , NO X and Particulate Matter emissions to air from ships. More ECAs are expected to be established over the next few years. In addition to emissions to air from the fuel combustion processes, oil tankers release large amounts of cargo vapours, so-called Volatile Organic Compounds - VOC. Once the pressure inside cargo oil tanks exceeds established limits, these hydrocarbon gases (VOC) are released to the atmosphere.

Abstract Heavy oil and bitumen are found in many places worldwide, with the largest deposits in the world being in Canada (Alberta), Venezuela and the former Soviet Union. Other countries having such deposits include U.S.A., Russia, Cuba, Indonesia, Brazil, Trinidad and Tobago, Jordan, Madagascar, Colombia, Albania, Romania, Spain, Portugal, Nigeria and Argentina. The main methods for extraction are generally mining and in situ. Within the insitu methods are the following processes: ? Steam Assisted Gravity Drainage (SAGD) ? Cyclic Steam Stimulation (CSS) ? The Vapour Extraction Process (VAPEX) ? Toe to Heel Air Injection (THAI) ? Cold Heavy Oil Production with Sand (CHOPS) The recovered bitumen may be upgraded at the plant site or diluted and sent through pipelines for production of synthetic crude. Bitumen and Heavy Oil are deficient in hydrogen, compared to typical crude oils. Upgrading is the process that changes bitumen into synthetic crude oil. There are four main steps to the upgrading process: Thermal Conversion, Catalytic Conversion, Distillation and Hydro treating. Different companies use these processes in different ways and at different stages in the transformation of bitumen/ heavy oil into synthetic crude but the basic principles behind this transformation remain the same. The state of the art of the industry worldwide will be described in this Best Practice Keynote.

Abstract The refining business is essentially all about the ability to efficiently transform crude oil into the quantity and quality fuels that the market demands. What is going to be the contribution of crude oil to the primary energy sources allocation? What are the expectations for crude oil demand in the coming years? Which is the type of crude oil that will be mostly available? Is there any room left for additional refining capacity in Europe? What are the demand pattern and quality requirements for the products of the refinery of the future? Answering these questions is nothing more than finding out the very market drivers for the future refining business. What refining scheme is to be used to maximize profitability? Is deep conversion the route to follow? What technologies are readily available? What to do with the ‘pitch’ produced in the carbon rejection technologies? What is the capital and variable costs associated with the hydrogen addition technologies? Is residue gasification a competitive alternative? Which are the key local and global conditions that might impact the decision on the refining scheme to be selected? This paper answers these questions giving a refining business outlook and analyzes the crude and products markets, products specifications, and conversion technologies available. The conclusion of the analysis is the most fascinating and challenging project in Repsol YPF refining history: the expansion of the Cartagena refinery. Essentially a 100 kbpd hydro-skimming refinery is to be converted into a 220 kbpd full conversion refinery conceived to deal with heavy sour and acidic crude oils and devoted to maximize high quality middle distillates output. The reasons that support a delayed coker'hydrocracker conversion configuration are thoroughly analyzed to conclude that this scheme combines the carbon rejection and hydrogen addition technologies in the most efficient way possible for the Repsol YPF Cartagena refinery. Introduction The Repsol YPF industrial complex in Cartagena, with an approximate surface of 180 hectares, is located within the "Valle de Escombreras" area, in the municipality of Cartagena. Its construction started during the 40's, when it was known as the Escombreras Oil Refinery (or REPESA by its Spanish acronym). The refinery had an initial distillation capacity of a million two hundred tons/year, barely more than twenty-five thousand barrels per day (bpd). Today, after more than sixty years of history, the refinery has reached a distillation capacity of five million tons/year (100.000 bpd), which represents around 8% of the refining capacity in Spain, 14% of the capacity of Repsol YPF in the Iberian Peninsula, and an 8% of the distillation capacity of Repsol YPF in the world. Featuring a "hydro-skimming" process configuration, the current refinery includes two heavy naphtha reformer units, one benzene hydrogenation unit and two middle distillates desulphurization units, as well as other auxiliary process and utility units, including one cogeneration unit that produces 40 MW, half of which is incorporated into the national grid. The refinery's "conversion" level is set by the vacuum distillation of the atmospheric residue for the production of lubricants, aromatics, waxes and paraffins. The refinery also produces marginal amounts of asphalt, and exports vacuum gas oil to feed conversion units in other refineries.

Abstract Heavy Residue Hydroconversion (HRH) is developed and designed to convert any type of heavy residual oil as well as extra heavy crude oil. This technology is based on nano catalyst and having this new concept, all problems related to asphaltene micelles and choking of catalyst pores are solved. Chemical structure of this catalyst enables HRH to utilize any amount of sulfur and reduce it at least 60 % and also any amount of heavy metals and convert almost all heavy metals to metal oxides as by product. Conversion of HRH process is high (up to 95%) and it can upgrade feedstock from less than 5 API to more than 34 API with more than 100 vol% yield. The HRH process includes catalyst regeneration unit for recycling up to 95 % of spent catalyst. This unit boosts the economy of HRH process and due to nature of catalyst, this process do not need any sophisticated processing for catalyst preparation. Metal compound precursors are raw materials for HRH process so this plant is self-sufficient with minimum dependence to sophisticated chemical supply. It makes HRH an attractive process for wellhead application in remote areas. Light gases produced in this process are useable as feedstock of its hydrogen plant. HRH also produces steam; these two by products make HRH more attractive for wellhead applications. Beside wellhead applications, this technology is suitable for refinery application. New residue free refinery schemes are developed based on HRH. This technology is also suitable for revamping existing refineries. Some real cases are developed by utilizing HRH and the results indicating higher added value. HRH has developed in different capacities. It is investigated in pilot scale, 200 bbl/d demo plant and a full scale 10,000 bbl/d plant was designed and is under construction in Iran. Now another 180'000 bbl/d extra heavy crude refinery is being designed in Iran. Promising economic prospects of HRH and its flexibility to feed contaminants like sulfur, heavy metals and asphaltene make HRH as a new alternative for wellhead application, new residue free refinery designs and also revamping existing conventional refineries. References: 1-S.N.Khadzhiev; J'zarkesh; K.M.Kadiev; R.Hashemi; V.K.Mezhidov; S.K.Masoudian; ‘Process for hydroconverting of a heavyhydrocarbonaceous feedstock’ United States Patent 20070045156 2-J. Zarkesh S. Khadziev R. Hashemi H. Kadiev G. Rhodey ‘A New Concept to Maximize Heavy Hydrocarbon Upgrading’ NCUT, 4th Upgrading and Refining of Heavy Oil, Bitumen, and Synthetic Crude Conference Edmonton September 25-27,2006

Abstract Depleting conventional oils makes more evident the limitations that the use of diluents has for carrying extra heavy oils (EHO) and bitumen to processing facilities. An alternative to dilution is field upgrading which involves an increased level of operations at production sites. With the deployment in Canada of thermal in situ bitumen production technologies such as Steam Assisted Gravity Drainage (SAGD), a different engineering approach to the conventional oil exploitation is resulting. SAGD allows the development of a confined liquid and gas chamber along the length of the production wells. This chamber could be used as a reactor for in situ upgrading processes or as a complement of field upgrading technologies, eventually resulting in environmentally economically sound options. Additionally, temperature levels in the reservoir can be increased with existing new technologies, raising expectations of moderate/medium upgrading of bitumen and EHO. Efficient hybrid recovery processes can be quickly realized with a concerted effort of multidisciplinary R&D and demonstration teams. The Alberta Ingenuity Centre for In Situ Energy (AICISE) at the University of Calgary researches on a wide variety of novel hybrid processes to create effective in-reservoir processing elements in a close interaction with industry. The centre is creating a versatile array of bench scale or small pilot plants to test hybrid processes conceptions with continuous delivery of dispersible catalysts, adsorbents and reactants. They have the potential to upgrade petroleum in situ with reduced needs of energy introduction to the reservoir while selectively transforming contaminants into harmless products. EHO and bitumen require twice more hydrogen than light crude oils to achieve fuel products. This is a strong motivation to develop lower-cost hydrogen generation in the places where these resources are abundant. AICISE includes an effort on in situ/field hydrogen production from residual oil and fractions of the recovered in situ upgraded crude oil.

ABSTRACT At the current price levels of conventional crude oils, there is a renewed interest in nonconventional hydrocarbon sources that could serve as feedstocks to existing or modified refineries. The most prominent representatives of such feedstocks are extra-heavy crude oils and syncrudes from oil sands. The session will be devoted to all aspects related to the production of syncrudes from oil sands, the transportation of such syncrudes and their use as feedstocks in conventional refineries. Likewise, the salient features of extra-heavy crude oils will be discussed along with the available technologies for their conversion into today's high-quality refinery products.

Abstract: According to a widely accepted forecast all together 250–260 109 t of crude oil has to be produced during the next century. The stunning consequence of this demand is that only 380 109 t crude oil may exist in proven and probable reservoirs. Namely, the production will meet the world-wide demand by application of such methods which are characterized by 65–70 % recovery efficiency being twice as high as the present average value. Theoretically, the low recovery efficiency can be attributed to the fact that the reservoirs are usually heterogeneous and the available formation energy falls short to cover fully the thermody-namic threshold potential (activation energy) of the displacement process. Although reduction of that thermodynamic potential is a general requirement, some factors (e.g. heterogeneity of the reservoirs) are reasoning the application of such IOR/EOR methods (polymer flooding, gel treatments, etc.) which rather increase the threshold potential in the porous systems. That obvious fact makes a novel theoretical approach timely if we want to proceed towards a more effective technological scenario. Therefore, comparing the different IOR/EOR methods by their thermodynamic flow character, an attempt is made to classify the basic chemical and non-chemical recovery procedures. One of the main conclusions of this new approach is that both convergence and divergence exist between the reservoir engineering and the thermodynamic preconditions. Despite such contradictions we may predict that those chemical methods will exclusively provide radical step forward the higher recovery efficiency which are able to decrease the resultant activation energy of viscous flow, deformation of interfaces, wettability alteration, adsorption/desorption, etc. The general thermodynamic treatment of processes put the earlier efforts into new light, gives a plausible energetical interpretation of both the negative and positive phenomena in reservoirs and forms a common basis for evaluation, classification, screening and application of the appropriate recovery techniques. INTRODUCTION "Energy demand is expected to grow in the 21 st century. The energy demand will be met by a global energy mix that is undergoing a transition from the current dominance of fossil fuels to a more balanced distribution of energy sources. Motivation of energy diversification includes population growth, quality of life, clean energy, resources/reserves... An understanding of the energy options available to us in the 21 st century requires an understanding of a range of scientific theories. The scientific revolution will be based on fundamental change of old paradigms," John R. Fanchi in "Energy in the 21 st Century," Gulf Professional Publisher, Austin (in print). That citation not only strongly demonstrates the conceivable energy scenario, but also the well-based prediction of the future role of crude oil and natural gas production/consumption situation The world energy demand was about 400 EJ (10 18 J) at the end of the last century and the share of hydrocarbons was roughly 60% (Figs 1 and 2). A major part of the energy, however, came from utilization of crude oil, which in itself represented about 50%. That fact clearly demonstrates that the western world and the highly developed countries are oil and gas dependent and that dependency is steeply increasing today.

ABSTRACT Degradation of oil is a most important part of the MEOR. This procedure can reduce the oil's viscidity and freezing point and improve the oil's fluxion in-situ. This paper shows the encouraging results of the microbial degradation on the heave oils gathered from Qihai and Xingjiang oil fields in China. The results show that the bacteria can efficiently improve the property of the oils. After microbial treatment, the gum & asphalt content of the oils are lowered at above 9% and their structure is also changed. The ΣnC21-/ΣnC22+ of the oils are enhanced through the microbial treatments and the shapes of oils in solution are changed greatly. The oils' viscidity and freezing point are reduced about 15% and 20% respectively, with production increments ranging from 8.53% additional ratio from 35.72% additional ratio and the hot oiling frequencies of oil wells reduced at least 2.3 times. The average date production of the test wells in Xingjiang oil fields from 2.39 T before the treatment to 14.196T after the treatment, the ratio of cost to output with is 3.14 time higher than that of the microbial treatment. This technology proves to be feasible and economical in these oil fields. Heavy oils are rich in gum and asphaltene, and they have the characters of high freezing point, low flow ability, difficult oil recovery and high recovery cost [1] . Microbe can improve the physical features of heavy oil in two aspects: by degrading the components with big molecular of heavy oil, microbe can decrease the average molecular weight of heavy oil; and the metabolite derived from microbe, such as biological surface active substance, acid, gas and so on, can decline the viscosity of oil considerably. Gum and asphaltene are components with biggest molecular weight and most serious polarity in heavy oils, meanwhile they are one of the main factors making the difficulty of oil recovery [2] . Usually, microbe can hardly degrade them [3] . Confronting this situation, the authors separated and bolted lots of microbe from environments rich in petroleum microbe, and through the bolting conditions control, drew out a series of mix bacteria, which can effectively degrade heavy oil, even gum and asphaltene; these microbe has been used to lower the viscosity and freezing point of heavy oil for the goal to improve physical and chemical characters of heavy oils. Several experiments of microbial enhancing oil recovery (MEOR) have been carried out in Qinghai Oilfield and Xinjiang Oilfield, China. Samples and experimental method The effective mix bacteria bolted are mainly bud bacillus, bacillus brevis, pseudomonas and coccus [3] . In the experiments, the crude oils are mainly mentioned and analyzed from Well Xian 19, Well Qizhong 22 respectively belonging to Huayanshan Oilfield and Qigequan Oilfield of Qinghai Oilfield Corporation, and from 97 and 98 Block of Xinjiang Oilfield Corporation; the crude oils are used in repeatability experiments from Qinghai Nanyishan Oilfield, Shengli Dongxin and Jinjia Oilfield, and Liaohe Ciyutuo Oilfield; density of the oils is 0.93 to 0.96g/cm 3 , and the content of gum and asphaltene is more than 35%.

Abstract: Ethylene (20 Wt%) and Propylene (25 wt%) from Fuel Oil is now a reality using advanced Fluid Catalytic Cracking Unit (FCCU) technology. Integrated sites with FCCU and Steam Cracking maximise the conversion of crude oil to petrochemicals. This paper describes the advances made in: FCCU, (Fluid Catalytic Cracking Unit) Steam Cracking, Site Integration, Types of feed that are suitable for this process, Preparation of feeds Shaw Stone & Webster in combination with Total, Axens and Sinopec have developed world leading technology for the production of Olefins INTRODUCTION Ethylene and Propylene are light olefins that form the primary building blocks for many modern plastic materials including polymers such as Polyethylene and Polypropylene. The market for plastics and polymers is forecast to grow at or ahead of world GDP. Oil and Gas are the primary raw materials to make olefins and converting them into plastics is an economic alternative to producing road fuels. Natural gas contains Ethane and a number of companies, particularly in the Middle East, are currently investing in significant additional capacity to convert Ethane to Ethylene. Crude Oil and Condensate are the primary sources of Naphtha that is a traditional feed for conversion to Ethylene and Propylene. Fuel Oil in oil refineries is converted into Propylene using Fluid Catalytic Cracking Units (FCCU). There is a trend to use lower cost Ethane and Fuel Oil as feeds to produce olefins as Naphtha is increasingly expensive. The continued growth in the production of olefins and the diversification of feedstocks is supported by technology advances in Fluid Catalytic Cracking Units (FCCU) and Steam Cracking (SC). Background Currently the most widespread method of producing olefins uses Steam Cracker technology where paraffins are heated inside tubes in a furnace to above 800 deg C in the presence of steam where they thermally crack. There are two main types of Steam Cracker, Naphtha and Ethane: Naphtha is a mixture of hydrocarbons in the C3 to C10 range and is a by-product of oil refining or is sourced from Condensate from gas and oil fields. Naphtha cracks to produce olefins and aromatics. Naphtha is also in demand to produce Gasoline and the price of Naphtha is closely linked to that of Gasoline. There are times when it is not economic to crack Naphtha. Ethane is co-produced with LNG and as such its availability is growing. Converting Ethane to Ethylene is a cost effective upgrade route that is being adopted in the Middle East where several new large Ethane Steam Cracker projects are being implemented. The product of cracking Ethane is predominantly Ethylene not Propylene. Increased Ethylene demand is forecast to be met from cracking Ethane, but this will not meet the forecast demand for Propylene. There are several technologies other than Naphtha cracking for producing Propylene including Propane De-hydrogenation but the most common production route is Fluid Catalytic Cracking. Approximately one third of the world's propylene for chemicals is currently produced as a byproduct in Fluid Catalytic Cracking (FCC) units in oil refineries.

Abstract: This presentation will review the main factors reshaping refining: changes in transportation systems _ the availability of a wider range of raw materials _ the blurring of boundaries between oil production and oil refining _ the development of innovative new processes and catalysts _ the ever-pressing need to better safeguard people and the environment _ and the inexorable advances in automation. The paper will give the reader a picture of the refinery of the future - a place where advanced technologies and highly skilled workers will raise to new levels the standards for efficiency, safety and plant intelligence. INTRODUCTION A little over 100 years ago, Chevron's Richmond, California, refinery started operation, producing lamp oil (kerosene) for lighting, fuel oil for heating, and lubricants for horse-drawn carriages and wagons. In those days, the company hauled oil in wooden wagons, and farming and agriculture dominated the economy. Today, we have grown into a global refining and marketing behemoth, with refinery runs of 2 million B/D and refined product sales of 3.7 million B/D. Yet, there are many more changes to come. What are the main factors reshaping refining? Consolidations … Changes in transportation systems … the availability of a wider range of raw materials … the blurring of boundaries between oil production and oil refining … the ever-pressing need to better safeguard people and the environment. First, let us look at some changes at the macro scale. I think the refinery of tomorrow will be big; this is a natural evolution as the business matures and reaches for economies of scale. The trend charts in the U.S., for example, clearly show that the number of refineries has shrunk from ~400 in 1945 to ~130 today, while their average size has grown, from ~12 MBPD in 1945 to 130 MBPD today. Another question: "Where will the refinery of the future be located?" In the olden days, refineries were located near the product markets and crude was transported to the refinery. With the rise of National Oil Companies, new refineries were built in countries where the oil is located, and products were transported to market. In the future, with the advent of heavier, more difficult to process crudes, new "refineries" in the form of upgraders will be located at or near upstream sites. Now, let's examine what the refinery of the future will look like - a place where advanced technologies and highly skilled workers will raise to new levels the standards for efficiency, safety and … yes … plant intelligence. When I consider industry changes in my 28-year career, it's not huge leaps in refining technology that come to mind. How we make fuels from crude oil … distill, reform, transform, and crack molecules - the underlying chemistry and the basic unit operations - hasn't changed all that much. However, each of those fundamental processes has become more efficient. Some of the other, more significant changes have to do with technology from other industries.

Abstract: This paper will highlight the challenges faced by licensees building refineries in Nigeria with limited energy infrastructure, weak banking capacity, and a regulated petroleum products market. It will also highlight policy changes by the Nigerian government aimed at achieving a deregulated petroleum products market as soon as possible. BACKGROUND: COUNTRY/REGIONAL OVERVIEW Nigeria's democratic government in 2001 embarked upon a programme to encourage private investments in the Oil and Gas industries in order to sustain long-term economic growth. The Government's reform plan includes privatization of the existing refineries, Liberalization/Deregulation of the oil industry, and the removal of subsidy on petroleum products. One aspect of the on-going liberalization and reform of Nigeria's oil industry is the issuance of permits and licenses to private investors for the establishment of Private Refineries, Gas Recovery and Processing Plants, as well as Natural Gas and Independent Power Projects(IPP) The Government, through its 100% state-owned company - NNPC, controlled the oil industry with its shareholding in the major producing companies involved in the industry. The NNPC through its subsidiary - Pipelines and Products Marketing Company (PPMC), buys crude oil for the refineries at prices set by the Government and then sells the refined products to the marketing companies. The subsidiary company also handles all imports of refined products through nominated contractors. Nigeria has four (4) Crude Oil Refineries located in Port Harcourt, Warri and Kaduna, with a total nameplate refining capacity of 445,000 BPD. Port Harcourt has two refineries, one with a capacity of 60,000BPD and the other 150,000BPD' Warri Refinery - 125,000BPD and Kaduna Refinery - 110,000BPD. In theory, Nigeria's refining capacity should be able to meet its domestic consumption requirements, estimated at approximately 400,000BPD (Source: Nigerian National Petroleum Corporation - NNPC). In practice however, the country continues to experience perpetual shortages of refined products due in part to poor configurations and inefficient operations of the refineries, resulting in frequent breakdowns occasioned by poor or lack of Turn Around Maintenance (TAM) (Source: The World Bank). The government had issued three Refinery Construction Licenses: Amakpe Refinery (6,000BPD with future plans for another 6,000BPD), Brass Refinery (100,000BPD) and Qua Refinery (100,000BPD). Though the Brass and Qua Refinery Licenses were issued as far back as 1996, the scope and large financial outlay required for the project, means that neither of them has been able to break ground. Another remote reason for them not taking off was the allocation of crude to them to refine at overseas affiliate facilities and then re-import back to Nigeria. This allocation of crude at discounted prices effectively meant they became instant crude merchants instead of potential refiners. NEW POLICY THRUST : The Nigerian government in 2001 started a 3-stage refinery licensing policy : License To Establish(Acceptable feasibility report) Approval To Construct(After detailed engineering review within 2 years of (1)) 3) License To Operate(After installing plant to specifications) All above process is being managed by one government agency … the Department Of Petroleum Resources(DPR)

Abstract. Many different types of crude oils are extracted from Mexican wells and mixed to produce commercial mixtures that are well known and highly demanded in the export market. These mixtures are also used as feed in Mexican refineries. However, to make the best out of our refineries, crude oils should be mixed according to the particular characteristics of each refinery. It is also possible to define optimal operating conditions for a particular refinery as a function of the crude mixture. Processing of heavy crude in existing refineries can not be significantly increased because of limitations such as: a decrease in the yield of light products, equipment metal restrictions, and greater environmental impact. However, it is our belief, that the efficiency of the oil industry can be significantly increased. This paper visualizes one approach: improving the productivity of individual refineries in order to increase heavy crude refining capacity and reduce costs. We develop an optimization model of a typical FCC-configuration refinery and analyze alternative ways of improving heavy crude processing efficiency. Our modeling efforts concentrate on the selection of the ideal mixture of crude and on hydrotreating and catalytic cracking of atmospheric and vacuum gas oils. Introduction The demand for gasoline is affected by many factors including quality of available crude oils and environmental regulations influencing finished products. The demand for lighter products and middle distillates has grown steadily as a result of transportation demand and the lack of economically viable alternatives. Optimum conversion capacity provides refiners with flexibility to process heavy crudes and acts as a hedge against high-cost light crudes. This flexibility is required to be more competitive in the marketplace. However, the refiner must select the appropriate process configuration that best fits the combination of crude supply and market demands. The principal rationale for upgrading gasoline, particularly for production of low sulfur gasoline, is to observe new stringent regulations on gasoline fuel quality1–3. Changes in regulations governing gasoline composition continue to focus on reducing sulfur levels. Examples include those counties like USA and Canada, that mandating 30 ppm S, will become effective between 2004–2006, and 50 ppm S will be required in the EU in 20054, 6. The overall impact of such regulations on the makeup of the USA and Mexico gasoline pool can be illustrated in Figure 1, which combines historic and forecast specification to levels of sulfur in gasoline. In 2001, with new regulations in several northern European countries, and overall growth in demand, low sulfur gasoline will likely make up about 3.3 thousands of barrels per day (MBD),

Abstract. The Mexican refining industry is facing the challenge of producing ultra-clean fuels, while processing increasingly proportions of heavy and sour crude oil. Of particular relevance in the strategies devised for optimising the overall domestic petroleum industry, are the actions for assuring the supply of low sulphur diesel within a schedule that considers different stages for achieving reductions from 500 to 300 ppm in the near future, to 50 ppm for the year 2006. Other specifications considered are cetane, aromatics, density and distillation points. The Mexican Refining System includes 6 refineries with a total processing of 8,140.6 m3/h. Diesel feedstock is mainly constituted by atmospheric gasoil; all streams are hydrotreated in 14 units operating in average at 52.6 × 105 N/m2 g. that produce diesel fuel with less than 500 ppm sulphur. Future streams to be incorporated, resulting from ongoing projects, include cracked products from coking and FCC plants. Additionally the refinery reconfiguration in progress will permit the processing of a higher proportion of heavy crude oil, representing a movement from 2.2% to 2.6% sulphur in the crude blend. The reported strategies in this paper are based on a formal mathematical model and an optimisation exercise, considering operating condition adjustments, catalyst replacement, revamp and new installations. Technology projects for process and catalyst development were considered as scenarios for the decision taking process. Introduction The environmental legislation that affects fuel specifications vary from country to country and even (Diesel specification in the same country may be different for particular regions or jurisdictions. In any case, the overall scenarios). trend is towards a severe reduction of sulphur content, with limits that will surely evolve in response to the combination of the economies and environmental problems of each region and the progress in process and catalyst technologies. In particular for diesel, an ultra-low sulphur product is foreseen, looking for a drastic reduction of SO2 emissions and the possibility of applying advanced catalytic converter technologies for NOx reduction in the exhaust gases. There are some other diesel specifications which future is more difficult to predict. BLOCK 2 - - FORUM 8 67 OPTIMISATION OF THE MEXICAN REFINING SYSTEM FOR LOW SULPHUR DIESEL PRODUCTION Region USA European Union Sweden Mexico EPA California (1) Year 1994 2006 1993 2006 2000 2005 1991 2000 2006 Sp. gr. min. 0.83 0.83 0.8 Sp. gr. max. 0.876 0.876 0.86 0.86 0.845 0.825 - 0.82 0.85 0.845 Sulphur, ppm max 500 15 500 15 350 50 10 500 50 Cetane Index min. 40 40 50 Cetane Number min. 48 48 51 54 - 58 48 48 Aromat, vol% max. 35 35 10 10 5 30 20 PNA, wt. max. 1.4 1.4 11 1-6 0.02 vol. 11 5 T90, K max. 611.15

Abstract Some Shell has developed a breakthrough offshore development solution, called Floating Oil and Natural Gas (FONG) which integrates Floating Production, Storage and Offloading (FPSO) technology with advanced deepwater and gas technologies for delivery of both oil and Liquified Natural Gas (LNG) products to market. FONG consists of a floating production unit with a fully rotating external turret, complete with on-board processing facilities, utilities, storage and offloading for oil and LNG. Introduction A typical FONG configuration enables development of a single field or several smaller oil accumulations, clustered as shown in Figure 1. Through an innovative gas processing system, FONG is able to accommodate a wide range of Gas/Oil Ratios (GOR) which could dramatically expand the development scope of oil fields with appreciable amounts of associated gas. In this way, an associated gas problem can be transformed into gas profits with up to 30% improvement in Net Present Value (NPV) across a broad spectrum of oil field sizes. As a consequence, the economic oil reserves threshold is lowered, allowing smaller fields to be developed economically. Implementing a FONG development offers benefits to a range of stakeholders. Environmental impact is minimized by eliminating the need to continuously flare gas, and without re-injection in a producing field, long-term reservoir management can be enhanced. FONG can provide the stimulus for the creation of new in-country support opportunities. Exhaustive engineering studies conducted throughout 2000/2001 demonstrated both technical feasibility and high levels of safety compliance. FONG is ready for implementation and project deployment studies commenced early 2002. Shell is positioned to leverage its proven track record in both global LNG operations and major deepwater developments to deliver FONG. This paper highlights the business drivers that support the FONG case for action and describes the technology innovations applied to deliver a safe, reliable and economically viable stand-alone offshore field development solution for delivery of both oil and gas revenue streams. BLOCK 1 - - FORUM 1 19 FONG: FLOATING OIL AND NATURAL GAS CONVERGING PROVEN TECHNOLOGIES TO INNOVATIVELY DELIVER NEW ECONOMIC DEVELOPMENT OPPORTUNITIES Figure 1: Typical FONG Cluster Development Case for Action FONG unlocks Oil & Gas Industry Growth Opportunities The world's oil and gas industry is facing significant challenges in the offshore hydrocarbon basins. In the last 5 years, several "hub" class fields (> 500 million barrels) were discovered in deep water in West Africa (Bonga, Akpo, Girassol, Dahlia, etc.). These field