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 In the last decades, many discoveries and field developments have been made in deepwater plays around the globe. Important lessons learned in more mature areas like the North Sea and the Gulf of Mexico - have been applied to more recent ventures worldwide. This presentation highlights technical learnings that supported success in these plays and application opportunities in Russia. In West Africa, over 22 billion oil-equivalent barrels were discovered in deepwater reservoirs in less than 20 years. This exploration success was due to the presence of robust petroleum systems, high quality reservoirs and efficient technology development and application. The Congo Basin and Niger Delta deepwater play areas were identified as active, oil-prone hydrocarbon systems and reservoir-prone long before any discoveries were made; under-scoring the importance of regional analysis. In these basins, companies entering the correct areas early captured most of the value. Exploration success rates were highest where 3D seismic was used and hydrocarbons could be directly detected. Many deepwater exploration discoveries have significant reservoir and trap complexity. With long construction lead times and high capital costs, early and accurate subsurface models are needed to deliver profitable deepwater developments. Subsurface characterizations leveraging highquality 3D seismic, more accurately predict reservoir and seal architecture. Fundamental understanding of deepwater depositional processes is a key enabler, especially when supported by an active research program. Later in production life, 4D (time-lapse) seismic, integrated with field surveillance data and history-matched reservoir models have been instrumental in identifying un-swept hydrocarbons and in-fill or re-development opportunies, resulting in increased hydrocarbon recovery. In Russia, Sakhalin Island and the Black Sea are areas with established and emerging deepwater exploration and development opportunities. Application of key learnings from a broad global experience base will aid exploration and help ensure profitable deepwater developments. Introduction The processes for finding, developing and producing oil and gas from deepwater reservoirs are different from other reservoir types in significant ways. First, often the environment in which these reservoirs form is the same in which they occur today - very deep water. There are many challenges associated with economic development of petroleum resources located in deep water. Robust risk and mitigation plans are needed due to the high cost environment and limited capability to recover from or drill out of subsurface "surprises". A second significant difference is that many deepwater clastic reservoirs, from slope channel to basin floor fan deposits, tend to have very complex reservoir and seal architecture which can be manifested during development and production by significant issues with reservoir connectivity and compartmentalization. Higher levels of geologic definition are often required.

Abstract In March 2013, Total officially launched its new High-Performance Computing (HPC) facility at its Scientific and Technical Centre in Pau, France. With a 2.4 Petaflops capacity, PANGEA as it is called is among the most powerful computers owned by IOCs worldwide. Today's Total acreage spans a broad range of depositional settings such as Rift Systems, Pre-Salt Carbonates, Abrupt Margins, Large Deltas and Foothills, where prospects and reservoirs are increasingly complex to image and to characterize. Meanwhile, shrinking exploration periods require accelerating cycle-times. Only days after starting PANGEA, CPU time for a WATS Reverse-Time-Migration (RTM) in a deep offshore field in Angola was reduced from one month to 54hr, and a Kirchhoff PSDM in Gabon pre-salt prospect ran in 3.5hr instead of 48hr before. Such time-saving power also allows running processes at levels thought unfeasible before: Full- Wave Form Inversion (FWI) on a field in Azerbaijan would have never been possible before. HPC also impacts our exploration operations: higher resolution velocity models help improving accuracy of well prognosis and thus reduce HSE-risks of sub-optimal well design. Another priority for Total is to shorten cycle times from Discovery to First Oil. Time-saving has to be achieved in a context where the simulated flow models tend to become geologically more complex - with an ever increasing number of grid cells - and where the physics to be simulated includes sophisticated thermal or chemical recovery processes. Next Generation Reservoir Simulator INTERSECT® takes full advantage of PANGEA thanks to its powerful parallelized capabilities. Total, co-owner of INTERSECT® source code, develops HPC customized versions and workflows to quickly respond to specific engineering needs on challenging fields. In the future, HPC will further contribute to Total's efforts for better understanding and characterization of complex flow mechanisms, for EOR or unconventional reservoirs, through numerical rock and pore network modelling, or molecular simulations. As technical and economic challenges keep evolving and growing, Total's R&D programs have been launched to address more and more precise and complex geophysics and reservoir physics, the solutions of which will in turn require increasing computing power, hence new facilities upgrade. This paper summarizes Total's strategic and operational motivations for the PANGEA project, describes its characteristics, and presents operational examples illustrating current internal geosciences applications with their benefits for the exploration and development of the group's assets.

Abstract Our industry lives on creativity and innovation. The tools and capabilities we need require rapid progression through the inventive process. That process is often assisted by borrowing from "the other guy's toolbox". Since 2007, ExxonMobil has co-sponsored (along with the Methodist DeBakey Heart and Vascular Center and the University of Houston) an initiative that brings together Houston's O&G and medical communities to explore topics of common interest and possibilities for technical collaboration. Its title, "Pumps and "Pipes", recognizes that heart and vascular surgeons have much in common with oil & gas engineers in that we are all in the "flow assurance business." We all work through long, thin tubes, depend on imaging and navigation, and place a high priority on keeping our conduits clean and intact. We are also interested in many of the same emerging technologies, including robotics and nano-materials. This paper describes ExxonMobil's experience with Pumps & Pipes collaboration and illustrates how cross disciplinary collaboration can be translated into business results. Several examples of successful innovation are described, including a new mitral valve simulator (O&G assisting medical researchers) and methods to detect and mitigate microbial induced pipeline corrosion (medical researchers assisting O&G engineers). Collaborations emerging from the first international Pumps & Pipes conference (in this year's WPC host city of Doha, Qatar) are also presented. This event is hosted by the Qatar Science and Technology Park with significant participation from Doha's Hamad Medical Center. Introduction As any homeowner or driveway mechanic knows, the best way to acquire a tool not owned is to borrow it from one's neighbor. That is certainly the case in the world of technology and ideas. The image of neighbors talking over the fence is the concept that drives Pumps & Pipes. The neighborhood is where pumps and pipes matter most - the physical health of people and economic health of societies. The neighbors are those who tend the pumps and pipes - the professionals of medicine and energy. The impetus for a collaborative initiative began in 2007 with the type of random airplane conversation that so often fosters creative beginnings. The seatmates were Alan Lumsden, Medical Director of Houston's Methodist DeBakey Heart and Vascular Center, and a drilling engineer with ExxonMobil's Sakhalin 1 project in Russia. By the end of the flight they agreed that the cardiovascular and oil and gas worlds do have much in common, and that underneath the specialized terminology "it's all pumps and pipes". They further agreed that ExxonMobil and the DeBakey Center should create a forum in which the conversation could continue. A third founding sponsor, the University of Houston, was recruited, and a striking logo (Figure 1) was created. For the past four years, Pumps & Pipes has been stimulating discussion, sparking ideas, and exploring synergies.

Abstract The Norwegian continental shelf (NCS) consists of vast areas with many different petroleum basins, stretching from the arctic archipelago of Svalbard in the north to the Danish border in the south. Petroleum activity started almost 50 years ago in the North Sea, which is the most explored area. The first year of production from the North Sea was 1971. The NCS is divided into three sub-areas: the North Sea in the south, the Norwegian Sea and the Barents Sea to the north. The continental shelf has gradually been opened for petroleum activity, in stages based on geological knowledge and technical experience. Most of the Norwegian petroleum production comes from the huge fields in the North Sea. Recent exploration shows that significant discoveries still can be made in this area. Exploration started in the deep water areas in the Norwegian Sea in 1995, and several discoveries have since been made. So far, only the Ormen Lange gas field is in production. Considerable areas with untested potential still remain unexplored. In the western part of the Vøring and Møre Basin, the sub-basalt geological play requires a technological breakthrough. Several discoveries have been made in the southern part of the Barents Sea. So far, the Snøhvit gas field is the only producing field. There are several unproven geological plays in this area, and nine exploration wells are planned in 2011. Both the Ormen Lange and Snøhvit fields are developed with subsea installations and transport to shore made possible by technological breakthroughs. In areas not yet opened for petroleum activity, the Norwegian Petroleum Directorate (NPD) estimates that there are considerable amounts of petroleum resources, both in the northern part of the Barents Sea and off the Lofoten and Vesterålen archipelagos in the Norwegian Sea. Data is also needed to estimate potential resources in the areas near Jan Mayen and in the eastern part of the Barents Sea, which will be a part of the NCS. Over the next two years, the NPD will acquire seismic data in the northern areas. Opening of new areas requires political decisions.

Abstract The greatest impediment to new discoveries is the certainty of what's impossible. Fortunately, in the realm of oil and gas exploration, the impossible becomes possible through innovation and creativity. The words "exploration" and "frontier" are typically linked in the minds of many as pushing the limits of technology and capability in new geologic basins that have had little to no previous exploration effort. And while significant opportunities still exist in these frontier areas, the risks are getting higher and the operating settings are growing more complicated. With the energy industry being challenged by the ever increasing demand for oil and gas, the definition of frontier has expanded over the years to include not only new areas, but also new geologic concepts in what had been considered thoroughly explored areas; unconventional plays in rock types never before considered commercial reservoirs; and even the frontier of new technology increasing recovery in existing fields. Success in all of these frontiers is critical if the industry is going to meet demand. Not so long ago, the Gulf of Mexico, for example, was declared the Dead Sea; salt signaled the basement and deepwater contained no reservoirs. Once conventional wisdom was turned on its head, both subsalt and deepwater settings became prolific new frontiers. And all of this success was in a basin long considered fully exploration. That story needs to be, and will be, told in many other areas as well. But technology and new geologic concepts might be the easiest frontiers to unlock as today's explorers are confronted with topics that have become more complex over time, including access, commercial terms, public policy and the environment. Add those "frontiers" to the mix and the challenge becomes even greater. A rock or an iPad: Which epitomizes innovation? A rock is, well, a rock. Dumb as a rock, the saying goes. What, on the other hand, epitomizes innovation more than Apple and the tablet it created? The iPad 2 has the computing power of a ม million Cray 2 – the 1985 supercomputer the size of a hot tub. Horsepower aside, the iPad revolutionized audiovisual delivery. It created a tool we never knew we needed, yet now cannot live without. The wafer-thin device has capabilities thought impossible a few short years ago. It's not alone. Many of the world's greatest innovations were written off as impossible. Consider the work of engineer Joseph Strauss. In the 1920s, he designed "the bridge that couldn't be built." Experts railed about insurmountable obstacles: more than a mile of water to cross, 60 mile-an-hour winds, piercing underwater currents, blinding fog, the Great Depression, and, not to be overlooked, occasional earthquakes. Yet Strauss' iconic Golden Gate Bridge, one of the seven engineering wonders of the world, was completed in 1937, on time, for less than ำ million …during worst part of the Depression. Does our industry - oil and gas exploration, in particular - have its own bridges that cannot be built? Sometimes, our greatest impediment to discovery is our certainty of what's impossible. Yet in the history of the oil and gas business, unconventional thinking has regularly turned the impossible into the possible, the industry frontier into the industry standard. In the span of this geologist's 32-year career, two of today's preeminent hydrocarbon plays - deepwater sands and onshore shales - materialized from the annals of the impossible.

Abstract Notwithstanding the odd reduction owing to specific financial or economic situations, the demand for hydrocarbons has grown steadily in the past and is set to follow the same trend in the future. In parallel to the increase in demand, the production from mature fields is regularly decreasing. The upstream oil industry now faces a major challenge to increase production through the continuous development of new hydrocarbon fields. The need to satisfy the world's growing thirst for hydrocarbons means producing from oil and gas fields at ever greater depths (deeply buried reservoirs), or under ever deeper water depths (-ultra- deep offshore). Our industry has begun to tackle developments that require considerable technological boldness to produce: ? either deeply buried reservoirs characterised by High Pressures and High Temperatures (HP/HT) with all the problems generated by these extreme conditions, ? or reservoirs located at great water depths: these fields have to be developed; sometimes satellite reservoirs have to be tied back to a very distant processing unit, while coping with the difficulties of producing more and more viscous oils. Through use of representative examples this session will illustrate some of the technical challenges that our industry has experienced, or still has to face, the ground-breaking solutions that have already been found, and the innovations we hope to see in the next few years.

Abstract This paper describes the latest R&D initiative from Petrobras, the PROCAP FUTURE VISION program. The objective of the program is to develop disruptive and innovative technologies to radically change the way we develop and produce oilfields offshore. The PROCAP FUTURE VISION program has a portfolio of 19 projects, encompassing all the disciplines in the E&P area, but approaching each one of them in an innovative way by combining the use of disruptive technologies and exploring the positive synergies among them in this process. A configurable FPSO - the "FUTURE FPSO"- with "plug and play" compact process equipment associated with subsea processing and power distribution is an example of such synergetic combinations. There is an extensive degree of use of nanotechnologies in several projects, from developing nanostructured materials, nanosensors to assure system integrity, nanoparticles to improve recovery or to helps gather information from the reservoirs. The use of augmented reality and robotics is being analyzed in the program as a way to reduce the number of crew members offshore, therefore enhancing safety and reducing logistic costs. Laser drilling is a very promising area that together with riserless drilling and the use of sensors to monitor the well integrity and optimize production will significantly improve economics. A study is being carried out to evaluate the economic impact of the combined use of all those technologies in a Pre-Salt field offshore Brazil. The qualitative results of this study will be presented. As part of the overall strategy of the Company, Petrobras is assuring that not only the technology is developed in a timely manner but also with the early involvement of suppliers and service provides installed in Brazil to allow the fulfillment of local content requirements while developing technology locally in a competitive basis. The paper will describe in detail the PROCAP FUTURE VISION program, the Strategy to execute the program and an evaluation of the benefits Petrobras expect to harvest from the application of those breaktrough technologies in an offshore development.

ABSTRACT The Paleogene Wilcox trend has emerged as an important frontier play in the deepwater Gulf of Mexico, as confirmed by several recent discoveries. The Wilcox trend is an onshore prolific producer along the Gulf Coast region, but its potential in deepwater settings has been recently recognized. At Repsol, a regional evaluation of the Wilcox depositional system was conducted using 2D seismic data sets and limited 3D surveys available from the western and central areas in the Gulf of Mexico. Most of the area is characterized by the presence of allochthonous salt, thus, seismic imaging is generally poor. Mapping of both Upper and Lower Wilcox sequences of more than 35,000 square miles indicate a widespread distribution for the Wilcox strata. These anomalously thick and extensive sedimentary deposits extend 200 miles downdip from the paleoshelf edge. Wilcox age-equivalent paleocanyons have been previously recognized and mapped along the Gulf coast, and they could have been the conduits for sediment transport and dispersal into the deepwater depositional environments. The Lower Wilcox records sand deposition in amalgamated channel a basin floor setting, whereas the Upper Wilcox seems to represent channelized sands in a slope setting. The deepwater interpretation was linked updip to the shelf area, and downdip into the abyssal plain to better understand the entire Wilcox depositional system. Regional isopachs shows the major depocenters and three major source areas in Texas and Louisiana. The western Gulf of Mexico areas were sourced from the Rio Grande and the Houston Embayment. The Eastern Keathley Canyon and Walker Ridge areas were sourced from Louisiana, via the ancestral Mississippi River.

Abstract: The opening of the deepwater areas in the mid 1990's launched a new and very successful phase in Angola's oil industry. To date, more than 10 billion barrels of oil have been discovered in deepwater blocks and production has reached 500,000 bopd. This paper reviews the progress of BP's exploration and production campaign in Angola's deepwater area over the last decade. Working with Sonangol, the state oil company, and in partnership with other major international companies, BP has enjoyed considerable exploration success. In the deepwater Block 18, all eight exploration wells drilled have been successful and in the ultra-deep Block 31 the success rate is six out of seven. Transfer of technology from around the globe, notably seismic imaging and deepwater drilling, has been key to these achievements. Similar success has been enjoyed in the exploration programmes carried out in our non-operated ventures. For BP the focus is now shifting to development and production. First deepwater oil production, from the Total operated Girassol Field, came in late 2001. This has since been augmented by production from Jasmin (again operated by Total) Xikomba and Kizomba A (both operated by ExxonMobil). Further developments are underway. The first BP operated production, from the Greater Plutonio Field in Block 18, is scheduled for 2007. All of these developments are in water depths of over 1,000 metres and again have benefited from the transfer and globalisation of technology. As well as reviewing the projects, the paper discusses examples of initiatives being undertaken by the industry to create the right environment for business delivery. The scale of activity being undertaken and planned is such that by the end of the decade Angola will be established as a world class petroleum province and BP Angola will be recognised as a major profit centre for the company. THE OIL INDUSTRY IN ANGOLA The oil industry in Angola can be considered to have two main phases. Although there were earlier oil and gas activities, the first major phase started when the Malongo fields offshore Cabinda started production in the late 1960's. In the 1970's and 80's a number of other major discoveries were made in the offshore Cabinda area (notably the giant Takula discovery in 1979 which came on stream in 1982). This area, now Chevron's Block 0 (formerly Cabinda Areas A and B1, see Figure 1), still accounts for a substantial proportion of Angola's oil production (400,000 bopd in 2003) and, with the extension of Block 0 announced last year, will continue to do so for some time to come. Success offshore Cabinda, and the enactment of new petroleum regulations post independence was followed by the award of a number of licences along the shallow water areas of the Angolan shelf. The first of these were Blocks 2, 3 and 6 which were awarded to Texaco, Elf and Total respectively in 1980. Subsequently Blocks 1, 4, 5, 7, 8 and 9 were also awarded to various consortia.

Abstract: The Takula Field is the most prolific oil field in the Republic of Angola. The field is located in the Block 0 Concession 40 km from the Malongo terminal in water depths of approximately 60 m. The Takula Field once accounted for one-third of Angola's total oil production. The Takula Field is comprised of seven stacked reservoirs. The field was discovered in October 1971 and placed on primary production in December 1982. Under primary production the field achieved rates of 130 MBOPD. A peripheral waterflood was initiated in the Vermelha reservoir in December 1990. The field achieved its peak production rate of 170 MBOPD in April 1995. In October 1992, Improved Oil Recovery technology was applied to the Mesa reservoir with horizontal infill wells. Well TK-F8 was the first horizontal well in Angola. Horizontal well technology was applied to the Vermelha reservoir and was followed by the first Angolan multilateral well in January 1998. In July 1999, the Mesa reservoir was placed on waterflood and became the first waterflood in Angola to rely solely on lateral wells. This reservoir management strategy was later applied to the Northwest Takula fault block and the S7 flow unit of the Vermelha reservoir to aid in the development of lower reservoir quality regions. Topics to be discussed include: Geology of the Greater Takula Area Exploration history of the field Primary Production including: fabrication, drilling, and production experiences; reservoir surveillance and management strategies Secondary Production including: transition experiences going from primary to secondary production, infrastructure modifications, and adjustments to the reservoir surveillance and management strategies Application of IOR technologies including: single- and multi-lateral infill wells and lateral-well developments of poorer reservoir quality regions and flow units Current challenges and future plans for the field including: maintaining base production from a mature reservoir with aging infrastructure and heightened environmental awareness INTRODUCTION The partnership between the Republic of Angola, its people, and the Cabinda Gulf Oil Company (CABGOC) began informally with geological reconnaissance surveys of the province of Cabinda in 1954. This partnership was formalized in 1957, with the award of exclusive hydrocarbon exploration and development rights in the province to CABGOC. During the 1990's, the Republic of Angola became one of the premier oil producing regions of the world. With oil production exceeding 900 MBOPD (143.1x103 m3/d) in 2003, the Republic of Angola is the second largest crude oil producer in sub-Saharan Africa and the seventh largest exporter of crude oil to the USA; exporting over 350 MBOPD (55.6x103 m3/d), approximately 5 percent of the total US demand. The Takula Field, situated in Blocks 44, 45, 56, and 57 of Area A in the Block 0 Concession (see Figure 1), is the largest producing oil field in the Republic of Angola. It is located approximately 28 km west of the nearest landfall and 40 km northwest of the Malongo terminal in water depths ranging from 55 to 65 m.

Abstract: This paper will focus on the vast deepwater areas of offshore South Africa; areas which require a challenging and expensive exploration effort. Latest exploration activities of Offshore South Africa, combined with a bit of exploration history will be discussed. This would then be compared with worldwide trends concerning deepwater exploration. Africa's important role within this new drive to exploit the world's deepwater hydrocarbon resources is also emphasized. General geology of the offshore basins will briefly be summarized, and the talk will coclude with the latest resource estimates of South Africa's deepwater areas. INTRODUCTION During the past 30 years, exploration of the Mesozoic basins of offshore South Africa was generally restricted landwards of the 200m isobath, with only a few wells exploring the Orange Basin on the West Coast in water depths deeper than 400m. Off the South Coast these rigs could only manage in water depths of up to 300m maximum. The strong Agulhas current and adverse weather conditions imposed restrictions on the use of the existing semisubmersibles. Exploration history The first offshore well in 1968 discovered the Superior gas field in the Pletmos Basin, which is a sub-basin of the Outeniqua Basin off the South Coast. Subsequently, most of the offshore exploration was then focussed in the Bredasdorp Basin, which led to production of the F-A, EM and satellite gas fields in 1992, which have been feeding the synfuel plant at Mossel Bay. First oil production from the Oribi oilfield followed in May 1997, a deep marine basin floor channel and fan complex (bff complex), and production was increased when the Sable oil, gas and condensate field came onstream in mid-2003. The Orange Basin is defined by the extent of a sedimentary wedge that occupies about 150 000 km 2 off the southwestern coast of Africa, and is more than 8 km thick in places. Although the basin is sparsely drilled with only 40 wells, most of which tested the shallow water areas, results thus far have been extremely encouraging. Two gas fields (Ibhubesi in South Africa, and Kudu in Namibia) with multi-TCF potential have been discovered within the younger geology, while the A-J1 well yielded an oil discovery in some of the oldest sedimentary fill. The Ibhubesi gas field has recently been defined by Forest Exploration International, through appraisal drilling in the area of the original A-K1 discovery well. The tested wells in this field yielded a high combined flow rate of dry gas and condensate. Analysis of 2D and 3D seismic surveys in the area has defined many new prospects and justifies the extension of this play for some distance to the north. The Durban Basin remains under-explored with only 4 wells testing the offshore areas close to shore, all of which were non-commercial. World trends Studies of oil discoveries made during the nineties indicate that giant oil discoveries are more frequently found in the deepwater areas of the world compared with the shallower water regions.

Abstract: INTRODUCTION The E-M Reservoir sands lie within a thick regressive ransgressive fluvio-deltaic to shallow marine part of the early Cretaceous synrift sequence. In the E-M field most of the hydrocarbons are found in the uppermost part of this sequence. Traps are sealed by thick marine claystones, which overlay the 1At1 unconformity. The general pre-1At1 E-M field structure is interpreted as a half-graben, with the main boundary fault to the North. The southern margin to the half-graben is complex in places, showing interaction of northerly dipping antithetic faults with southerly dipping boundary faults. Many of the faults may show normal net displacement at deeper levels, but reverse offsets at the top of the upper shallow marine. This indicates at least one episode of inversion at around 1At1 to 6 At1 times. The E-M gas field has been on production for 3 years. Dynamic data indicates that the reservoir is more complex than the present reservoir model predicted and that the compartments within which the wells lie are smaller than presently mapped field polygons. An assessment of the E-M structural model recognised that reverse faults may be more common than previously interpreted and that the field may be more compartmentalised. The present 3D seismic dataset is not of sufficient resolution to confidently map smaller compartmentalisation within the field polygons. Multiple problems below the reservoir reduce data quality and this makes interpretation of deeper structures ambiguous. Objectives The challenge is to target the multiple attenuation in the in-line direction whilst the multiples are more easily identifiable in cross line direction. Interpretation of this reprocessed dataset will focus on the development of a structural model that may aid the prediction of subtle and sub-seismic fault arrays. This will change some fault geometries (e.g. normal to reverse) and may introduce some subtle small-scale faults. Executive summary The offshore Cabinda, Angola Block 0 concession is operated by Chevron for partners Sonangol, Total, and ENI. The 5500 sq km concession produces nearly 400,000 bopd from 23 developed fields. Cumulative production in the block is 3.1 BBO. Eighty-four percent of production has come from fields located in less than 60 meters of water. The deepest water depth on the block is 200 meters, adjacent to the Congo River Canyon. Various play types exist in the block. The two play types responsible for the majority of production on Block 0 are pre-salt Lucula sandstone and Toca carbonates trapped along flanks of basements highs, and post-salt Pinda sandstone and carbonate and Vermelha sandstone trapped in rollover structures. Obtaining the best possible seismic image of these very different play types is critical to continued exploration and production success on the block. The historical exploration drilling success rate is approximately 40%; the main exploration risk elements for a given prospect on the block are reservoir and trap geometry. Source and hydrocarbon migration risk are low. The challenge in Block 0 is to make a step change improvement in seismic data quality.

Abstract: A review in Petrobras Strategic Plan in 1998 has outlined a new business model, where international activities would play a key role in the company's quest for growth. Target areas were selected to focus immediate efforts and, aiming to capitalize on the comprehensive deepwater expertise developed in Brazil, a material presence in West Africa deepwater market became one of the drivers for our expansion. The Gulf of Guinea, and more specifically, Nigeria is one of the booming areas in deepwater exploration and production, where all the majors and most international oil companies are present. Notwithstanding being a new comer in this highly competitive market, Petrobras had also aggressive near future targets for holding exploration acreage and developing production. Non-operated participation interests in three exploration blocks were achieved in the first two years of activity: OPLs 216 and 246, in Nigeria, and block E, in Equatorial Guinea. Major oil discoveries in the two Nigerian blocks, Agbami and Akpo, paved the way for establishment and growth. The 2000 bid round in Nigeria opened a window for new exploration areas, and Petrobras was also successful in securing participation in two ultra-deepwater blocks, OPLs 324 and 250, the former one as the operator. In a 5 year span, Petrobras was able to develop a significant and cost effective presence in Nigeria through exploration. This paper describes our experience in building this success case, where a combination of expertise, strategy focus and local presence was fundamental to achieve our challenging targets. History Petrobras, the Brazilian National Oil Company, was incorporated in 1954 and started its international activities in 1972, through its subsidiary Braspetro. Since then, Petrobras has been involved in E&P projects in Africa, Middle East, North Sea, US Gulf and Latin America. The company's mission was to supply oil and oil products to Brazil, in a monopolistic environment, this way being completely focused on the domestic market. Working internationally was not a priority at all, and used to be taken more as a learning opportunity for our professionals. Although growing in size, by a steep rise on domestic production and reserves due to deepwater discoveries from mid 80's, the company's approach to business outside Brazil continued to be very conservative and shy. Since 1995, reform movements inside the Brazilian Government were leading to an opening of the petroleum sector, where Petrobras would have to compete for territory and market share as any other oil company would be free to operate in Brazil, from upstream to downstream & marketing. Changes in the company's strategy became imperative in order to survive in a competitive environment. New Strategy Plan In 1998, for the first time in Petrobras' history, a focus on international activities was mentioned in the company's revised mission, vision and strategy plan. Implementation of the new corporate strategy was structured in three main lines of action: Consolidate competititve advantages in the domestic market; Maintain the leadership in the Brazilian gas market and develop integrated participation in the energy market.

Abstract: Deep marine basin floor channel and basin floor fan (bff) complexes are well developed in the third order Barremian (9A) to Aptian (13B) sequences in the Bredasdorp Basin, offshore the Southern Cape of South Africa. The bff com-plexes contain stratigraphically and structurally trapped hydrocarbons, within moderate to good reservoir quality turbidite channel sandstones. The Sable oil and gas fields are reservoired within the upper part of this turbidite system. The sequences fall within a stage of early drift history with a progressively enlarging basin that flooded and integrated the initial post-rift embayments with connections to the proto- Indian Ocean. Deposition of well-defined systems tracts together with associated type1 erosional unconformities developed. The third-order (onlap-fill) sequences reflect both thermal subsidence along the ba-sin axis and episodes of re-activated faulting. Generalized facies distributions, determined from log patterns, core data and maximum grain size data have assisted in generating geological models for the region. Poorer quality channel overbank and sheet sand (distal fan) deposits are not resolvable from seismic and geological models must take this into account so that allowances can be made for these ‘invisible’ volumes. Ideally, bff systems should be radial in shape but because deposition occurred in the relatively confined Bredasdorp Basin their shape is controlled by the ba-sin topography and as such are predominantly elongated. The provenance for these sandstones consisted of Table Mountain quartzites and Cape granites sourced from the mainland and the Agulhas Arch. The ba-sin maintained it's strong northwest - southeast elongation, inherited from the synrift sub-basins and was open to relatively free marine circulation to the southeast with the Southern Outeniqua Basin and the Indian Ocean. Sedimen-tation into the Bredasdorp Basin thus occurred predominantly down the axis of the basin with main input direction from the west. INTRODUCTION The Bredasdorp Basin, located on the southern continental margin off the coast of South Africa is mostly filled by marine Aptian to Maastrichtian deposits, which were deposited on pre-existing Late Jurassic to Early Cretaceous fluvial and shallow marine synrift deposits. Drilling for hydrocarbons in the Bredasdorp Basin commenced in 1973, leading to the discovery in 1980 of the F-A gas field in the Berriasian to Valanginian shallow marine synrift sandstones along the northern flank of the basin (Figure 1). Further discoveries led to the gas-to-liquids (GTL) project at Mossel Bay commissioned in 1992, which produces syn-fuels from gas and condensate production from the F-A and E-M fields. Most recently the South Coast Gas Project (SCG) has been ratified to make available several central basin Barremian (9A) to Aptian (13B) gas and condensate discoveries in order to sustain and extend production of syn-fuels at the GTL plant. The generally thin pre-Aptian central basin gas charged reservoirs, confined to narrow channels, have proven to be a challenge to model, both geologically and commercially and their contribution to the basin's success will soon be realised.

Abstract: The exploration activity on the Norwegian Continental Shelf (NCS) is too low according to a resource management's point of view, the Norwegian Petroleum Directorate's (NPD) view. The trend with a decreasing exploration activity is however not only a solely feature for Norway. We discuss possible reasons for the low exploration activity globally and the factors specifically related to the NCS. One important factor behind the low exploration activity on the NCS is the industry structure with the dominance of the Norwegian companies Statoil, Hydro and Petoro. To increase the exploration activity on the NCS the Norwegian Government wants a more varied portfolio of companies on the NCS. In this paper the oil and gas opportunities on the NCS is presented with special focus on the economic value of these opportunities. In spite of low exploration activity the economics of exploration on the NCS is still good. Large parts of the NCS are very little explored and there is still a huge resource potential in the region. About one third of total resources are yet to find. Introduction The global level of exploration activity has been low since 1998. Also at the NCS the exploration activity has been low compared to the history, and low taken into account the high oil price. The low numbers of exploration wells is a challenge for the resource management at the NCS. Though now one can see signs of increase in the exploration activity. We discuss why we have a low exploration activity both globally and nationally on the NCS. It's first of all the Super Majors and the Majors that has reduced their exploration activity while the Independents have been more aggressive. At the NCS there are few Independent companies present. One important goal for the government is therefore to increase the number of Independent companies active at the NCS. In this paper we present the oil and gas opportunities on the NCS which should be of interest for potential newcomers. We also present the economics of exploration in Norway and explain the recent changes in the tax system which should give newcomers strong incentives to explore for oil or gas at the NCS. Exploration activity - driven by the oil price Commodity price is the overarching driver of the upstream petroleum industry. From a historical perspective, post-1973, price has divided the upstream petroleum industry into two principal phases. The oil price cycle is shown in figure 1. The first price cycle includes the steep price rice through the 1970's and the subsequent decline during the mid 1980s. The second phase, involved an extended period of low oil prices through the late 1980's and the 1990's which bottomed in 1998. (Figure in full paper) The phase of rising oil price during the late 1970's and early 1980's resulted in a rapid expansion of global exploration. The oil price drop in the mid-1980's caused an immediate and precipitous reduction in exploration activity.

Abstract: The global demand for crude oil has risen dramatically in recent times, driven by sustained economic growth in industrialized economies, rapid industrialization in parts of the developing world, as well as continued political instability, particularly in the Middle East. This trend has sent shock waves into the global oil markets, triggering on upsurge in the market prices of the commodity, which has risen to its highest peak in the past couple of decades. The increase in the demand for crude oil has emerged against the backdrop of shifting global patterns of demand and supply, a development that presents policymakers with challenges and opportunities. Although the Middle East continues to dominate global oil production, policymakers in industrialized economies are intensifying efforts to diversify their sources of supply away from the crisis-prone region. Consequently, Africa has emerged as a region with growing reserve potentials to become an alternative source of crude oil supply, particularly in the Atlantic Basin. The discovery of huge crude oil reserves in a few African countries in recent times has enhanced the profile of the region as a potentially dominant source of supply to feed the rising global demand. Africa's oil reserves are concentrated north of the equator, with Angola as the major exception. Libya possesses the largest recoverable reserves in the continent, followed by Nigeria and Algeria. New oil reserves have also been discovered in Mauritania, Chad and Sudan, with steady increases in these countries projected into the future. In the Gulf of Guinea, where Nigeria is the dominant producer of crude oil, huge reserves have been discovered offshore, increasing the prospects of accelerated production in Angola, Equatorial Guinea and Gabon. CRUDE OIL ASSESSMENT: A GLOBAL OVERVIEW Global Reserves Global crude oil reserves are important measures of energy security and sustainability, which hold the key to global economic growth, increased industrialization and prosperity. In the course of the 20th century, global crude oil reserves increased steadily, spurred by the dominance of oil as the world's favored choice of primary energy source. Until the 1970s, the world's crude oil reserve increased steadily, aided by advances in seismic technology and novel exploration techniques. For many years, global oil reserves showed small but steady increases, a development that confirmed the discovery of new reserves, which kept pace with production (UNDP, 2000). However, industry analysts agree that relatively new oil fields have been discovered since the mid-1970s, and that most reserve increases have emerged from revisions of previously underestimated existing reserves, and improved recovery techniques. Global trends also revealed that peak production lags behind peak discovery by several decades. They also showed that larger and more obvious fields were found first, leading to an early peak in discovery and diminishing returns in exploration; the more that was fond, the less was left to find. Production therefore followed in fields that were smaller and harder to find and to exploit, leading eventually to the exhaustion of the fixed stock. Table 1 shows the state of global oil reserves and depletion trends.

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

Abstract After the several giant oil fields discovered in the Campos Basin deep water province, off the Rio de Janeiro State, Southeastern Brazil, it was generally believed that analogues should be soon discovered in other sedimentary areas along the Brazilian Continental Atlantic Margin. However, the last important oil discovery in the Campos deep water was the Roncador Oil Field in 1996. Despite the notice of an important discovery in Santos Basin and probably less important in Espirito Santo Basin, no other relevant or giant discoveries occurred since then, even though Petrobras has put a great effort in drilling several wildcats in Campos and also in the deep water areas of other Brazilian basins. Several studies, mostly derived from the interpretation of exploratory data, within the overall Brazilian deep water areas have led to some important conclusions about the high exploratory risks of this region. Even in the Campos Basin deep water, the risk in finding new oil giants in deeper seaward areas, could be related to the existence of reliable source rocks, useful migration pathways and adequate.timing of hydrocarbon generation / migration. Similarities to the Campos Basin are encountered to the north, in the Espirito Santo Basin, and to the south, in the Santos Basin, but do not extend far away from these areas. In the sedimentary basins, along the offshore brazilian northeastern margin, the most important source rock sequence in shallow water region tend to disappear into the deep water region, where they are eroded at the base of younger strata of the open marine sequences. Generaly, over mature source rocks and complex tectonic features characterize the so called Equatorial Basins. Assuming the presence of the deltaic Tertiary deep water source rocks, better expectation comes from the two large submarine fans situated in the extreme north and south Brazilian Margin, accordingly: the Amazonas Fan and; the Rio Grande Fan, in the Pelotas deep water. Similar possibility is also expected in the Pará-Maranhão deep water area where another submarine deltaic area is expected to occur. Introduction The Brazilian sedimentary area is analyzed with emphasis to the offshore and to the deep water region, in particular. The previous exploratory efforts were used to characterize the stage of knowledge of each area. After almost 1500 exploratory wells drilled in the brazilian offshore area by Petrobras, during the last three decades, some important conclusions can be now outlined. Considering the existing subdivision of the offshore area in large geographic sectors or in a large number of "basins" that, in fact, correspond more to geographic and operational compartments, the offshore Brazilian region was here divided into six distinctive provinces with proper exploratory history and geologic fram

Abstract The North Algeria is an under explored petroleum province. Significant oil and gas shows have been encountered, and oil seeps are well known in the most part of the area. Oil has been extracted for the century in the Cheliff basin (Tliouanet and Ain Zeft fields). The first oil commercial discovery in Algeria on 1948 is noted in Oued Gueterini field in the Hodna basin and it's produce until present time. The North Algeria is in a geologically complex area encompassing the Offshore, Tellian atlas, Saharian atlas and constitute the zones of alpine age deformation. Although petroleum exploration in the northern foldbelt has been unsuccessfull; several wells were drilled on surface structure without seismic control and understanding the shifting structure in the subsurface, whereas others were not drilled deep enough to reach the deeper targets. The northern foldbelt area is expected to have a similar geodynamic and tectonic as the Apennines (Italia), the Zagros (Iran), which contains important oil and gas discoveries. The Offshore is a continental shelf with a tertiary and quaternary formation. The petroleum target is the mio-pliocene sands reservoirs, sourced from the messinian shales with a TOC values 0.56 to 2.60% at HBB–1 well in the occidental part. A new seismic have been acquired on 2000 by Western Geco shows a thick sedimentary deposit in the deep water zone with a variety of trapping styles related to the conventional anticline, faults, salt dome... In the Tellian atlas, two main basins are developed, the Cheliff in the west (mointain basin) and the Hodna in the central part (for deep basin). The petroleum system is proved on this basins by small fields and oil seeps from the miocene sands (shallow reservoirs). The cretaceous could be an important deep target no reached by wells. The upper miocene reservoir is charged from the messinian shales; the lower miocene reservoir sands and upper cretaceous carbonates are charged from the cretaceous shales and marls source rocks. In the saharian atlas which is an elongate trough between the saharian platform in the south and the Tellian atlas in the north, a potential basin is developed in the oriental part (south east constantine basin) where four oil fields and one gas field have been discovered in the cretaceous play. The north province could be a promising area for hydrocarbons exploration, detailled structural work based on adequate and high resolution seismic is needed to define the model and geometry of traps related to this complex area. BLOCK 1 - - FORUM 2 131 ALGERIA, NORTHERN FOLDBELT AND OFFSHORE AREA: A FUTURE HYDROCARBONS PROVINCE Introduction Northern Algeria is an under explored petroleum province. Significant oil and gas shows have been encountered and a number of small discoveries were made over 40 years ago (Oued Gueterini, Djebel Foua and Djebel Onk)