Operators of Oil & Gas assets have long struggled with the issue of managing so-called "safety stocks" of spare part inventory. Within Shell, this problem sits within the materials management discipline whichcovers the ordering, storage and utilisation of material assets such as subsea facility equipment or pipeline parts. Across all assets globally, Shell carries a huge stock of such items which ties up large quantities of working capital. Observations over time have noted significant issues such as unrealistic supplier lead times, rising inventory levels and associated carrying cost for some assets, andincreasing demands on warehouse space in certain locations. In response to these challenges, over the past 2 years an interdisciplinary project team has produced a tool, based on advanced analytical methods, that helps assets optimise stock levels and purchase strategies. This approach reduces the risk of deferment due to stock outs and prevents excessive stock carrying costs. It also supports on-time execution of maintenance schedules and so helps to maximise asset uptime.

The United Kingdom Continental Shelf (UKCS) is a mature region with around 42 billion barrels of oil equivalent produced since the late 1960s. The majority of the remaining estimated 15 billion barrels of oil equivalent reserves lie in more technical and challenging areas. To produce these reserves, access to existing infrastructure through subsea tiebacks for new and incremental projects or as new standalone development projects remain key to the future of UKCS and slowing the recent production decline. Currently, about 60 percent of all new fields in the UKCS are subsea tiebacks to existing infrastructure and there is an increasing interdependence for both production facilities and transportation infrastructure 1 . Many recent discoveries have been comparatively small and are not large enough to support their own infrastructure. This paper attempts to answer this critical question: how does the separation of infrastructure and field ownership affect economic recovery in a mature oil basin? We explore how possible different ownership structures and access arrangements might affect the economic viability of the remaining UKCS reserves by applying a mixed integer-programming model to field data from the Northern North Sea. Specifically, we consider the impact of a changing tax regime in a way that is relevant and consistent with unbundling infrastructure provision through cost sharing arrangements and how this affects the long-term economics of hubs and their user fields. The model is used to maximize the net present value of regional production (the maximum economic exploitation of the region) by determining the optimal set of new developments, tiebacks from fields to hubs, and timings of hub and field shutdowns. The effects of the separation of infrastructure and field ownership are captured by individual field and infrastructure viability conditions constraints.

The UK Oil & Gas (O&G) faces significant challenges to ensure future economic potential is maximized. Current issues include escalating maintenance backlogs, facility unreliability; an inability to liquidate production-enhancing or important asset integrity workscopes and uncertainty of the rationale justifying existing maintenance programs. This paper presents the application of a novel maintenance optimization technology that has delivered performance improvement through the deterministic consideration of both commercial and reliability criteria when determining planned maintenance intervals. Real case studies are presented alongside the concomitant benefits. The technology was used to determine an optimized planned maintenance program for deployment in both existing operations and new facilities, and has delivered benefits when compared with traditional approaches to determining maintenance intervals. The technology marries both technical and commercial considerations when determining optimized planned maintenance and, in this way, the modulation of planned maintenance programs in response to changes in production, commodity value or equipment reliability is easily achieved. Based on results of the work carried out using the technology, it is proposed that there are significant benefits available to the UKCS through the adoption of similar techniques, as it is understood that many operators currently struggle to justify existing planned maintenance regimes, and to demonstrate a defensible means by which to alter these regimes in response to a changing economic and reliability criteria. Application of this new technology may provide a means of modulating maintenance in response to changing criteria and offer potential concomitant benefits in helping tackle backlog, bed space and production efficiency challenges.

BP has been operating in the Caspian Sea and associated area (AGT Region - Azerbaijan, Georgia and Turkey) since the early 1990's and today the area is one of the world's leading hydrocarbon provinces. The assets consist of 7 offshore platforms, one of the world's largest terminals and export pipelines. The topic of this paper is a description of a practical implementation of an assessment procedure for determining optimum inspection frequencies (endorsement interval) for pressure relief devices protecting pressure system equipment. We describe the development process, the resulting solution and work processes, the challenges related to the data requirements and dependency of the maintenance and inspection organizations to record and collate such data. Within the AGT Region there are in excess of 5,800 pressure relief devices. Pressure relief devices provide a key layer of protection for the process safety of oil and gas fields and installations and need to operate on demand as and when required. All need to be inspected, tested and recertified on a regular basis. The objective of the exercise from the outset was to increase the process safety protection and reliability on the installations. Flow charts were developed to ensure the methodology was clear, simple, repeatable and auditable. This methodology was then combined with knowledge and expertise on the failure mechanisms of safety devices and the consequences of an uncontrolled release to atmosphere to determine an optimal endorsement interval and verify that the device was functioning properly thereby preventing the over-pressuring (or under pressuring) of equipment during abnormal operating or emergency conditions or leakage past the seat during service. The output from the work showed that around 70% of the pressure relief devices could have their maintenance and inspection intervals increased, by up to 6 years. The work was initiated when the oil price was in excess of 100US$ per barrel and on BP facilities that are top of the league in terms of production efficiency (greater than 90%). The primary objective was to improve the safety, reliability and integrity of the installations, however the resulting benefits of performing the assessments aligned to the ability to increase inspection intervals are to significantly reduce maintenance costs, reduce offshore and onshore interventions and increase availability and production efficiency. The team also reviewed and enhanced the management procedure for the testing, repair and recertification of pressure relief devices, to provide additional guidance to the maintenance teams in the areas of data collection and recording and witnessing pressure relief device testing and re-certification.. To the authors knowledge this is the first practical implementation of the assessment procedure that embraces the total combination of asset integrity information and work process data sources within a whole oil and gas producing region.

Enhanced oil recovery (EOR) schemes have been slow to evolve in the exploitation of hydrocarbons from the UK Continental Shelf. They are generally much more expensive to execute offshore than in onshore USA where they are relatively common. This paper provides a detailed analysis of the economic aspects of several EOR projects namely low salinity waterflood, polymer flood, and miscible gas injection. Detailed economic modelling of example schemes finds that, in current circumstances in the UKCS, prospective returns, while worthwhile in undiscounted cash flow terms, are only very modest at discount rates reflecting the cost of capital. It is also noted that there are several significant investment risks. Further tax incentives relating to the purchase of polymer and miscible gas could enhance returns to these EOR projects without introducing any distortions.

After a period of nearly 10 years absent from the North Sea oil and gas sector, in 2012 Cairn Energy re-entered the UK Continental Shelf, and for the first time entered the Norwegian North Sea through the combined corporate acquisitions of Agora Oil and Gas AS (a private Norwegian company) and Nautical Petroleum (an AIM-listed E&P company), respectively. Cairn had upstream experience in both the UK and Dutch sectors of the North Sea and was an active non-operating partner in the Gryphon heavy oilfield in Quad 9 and in the P6 and P12 gas fields in the Netherlands. This paper outlines the method and approach taken to rebalance Cairn’s portfolio after sustained success in South Asia and the sale of Cairn’s majority shareholding in Cairn India and the subsequent need to rebuild a portfolio with a cash flow generating base to underpin exploration and appraisal opportunities, both internationally and in the North Sea itself. It explains Cairn’s rationale and key drivers for entry and (re)-investment in the North Sea versus other possibilities. It also discusses the importance and value of preserving knowledge and expertise within the acquired companies and the process of integration. The paper will also investigate: (i) the technical aspects of Cairn’s acquired interest in two key oilfields, Kraken and Catcher which, in gross terms, will deliver approximately 10% of the UK's oil production when onstream and (ii) Cairn's remaining exploration portfolio in the North Sea and subsequent plans and opportunities for growth.

The ability to efficiently install subsea modules in increasing water depths is a major condition for the cost-effective development of deep-water oil and gas reserves. The weight of a steel hoisting wire exponentially increases with the working depth and is a significant cost driver for water depths beyond 2,000 metres. The obvious solution is to utilise other types of cable that are not as heavy. Using fibre rope as an alternative to steel wire for deep-water operations is attractive, because its weight is close to being neutrally buoyant. However, the challenges involved with the handling of fibre rope have limited the availability of commercial systems and the application of fibre ropes in offshore installation operations is still not common practice. Fibre rope is sensitive to internal and external wear, and to the high temperature caused by friction as a result of the rope slipping and bending. Consequently, winch systems designed for steel rope cause the rapid wear of fibre rope. On the other hand, existing systems for the handling of fibre rope are relatively slow, work discontinuously and/or require a complex design and intricate control systems. Developing a new type of fibre-rope handling system – without these drawbacks – requires a knowledge of fibre-rope behaviour and insight into rope-handling system interaction. In 2010, a joint-industry project was set up to model fibre rope in a finite element study, which simulated the behaviour of the rope during interaction with the handling system. For a comparison between different ropes and handling system concepts, heat generation, dissipation and abrasion are considered as consequences of energy dissipation in this model. A new fibre-rope handling system was developed by selecting the concept with the lowest dissipated energy and optimising the design towards increasing the rope’s lifetime and cost effectiveness. This project resulted in the design, manufacturing and testing of a 50mT-prototype winch. Factory acceptance tests (FATs) have demonstrated the functional performance. In the second half of 2013, the prototype will be installed on board an offshore construction vessel for further tests at sea.

Duty holders and operators of major hazard assets should have in place the required processes, programmes and procedures which coherently: Prevent major accidents; ensuring risks from major hazards are reduced to as low as reasonably practicable Ensure asset integrity is a continuous process throughout an asset's life Ensure asset life extension is properly managed using defined processes and procedures This paper describes how, collectively, these processes, programmes and procedures are aligned to a major accident prevention process which is a core element in the management of an asset at all stages of its life cycle. The primary goal is to ensure that plant and equipment does not, and is not allowed to fail in such a way as to cause or substantially contribute to a major accident. The requirement to manage assets throughout their life including any life extension period should be mandated by company policy and standards which in ConocoPhillips case recognises the design, operation and maintenance of an asset should be such that its integrity is preserved at an acceptable level of risk throughout its operating life. Asset life extension is a process that begins when an asset's components wear out, requiring maintenance or repair to maintain a satisfactory operating condition. This begins soon after the asset enters operation for the first time and continues throughout the life of an asset. However, with increasing age, unchecked asset degradation can become widespread and gradually escalate to a point where significant restoration is required. Consequently, major accident risks may be increased requiring an asset operator's management system to be carefully designed to contain them. By embedding the Major Accident Prevention Process in the way we design and manage our assets, we ensure that asset integrity is a continuous and forward looking process that supports the case for asset life extension.

Apache discovered the Maule field in October 2009 with the 21/10-A52 wellbore drilled from the Forties Alpha production platform. The discovery of a 14m TVD net oil column in Eocene aged Brimmond sands led to the development of the Maule field under the UK government's small field allowance scheme. The field was taken from completion of the discovery well to first oil from a horizontal production well in under 9 months. The Maule field is located on the western margin of the Brimmond Formation turbidite fairway where re-mobilised sands are also present. Steep dips as seen in the development well and steep seismic features indicate that the Maule field reservoir was formed by remobilsation of Brimmond sands. The A52 exploration well was drilled on the basis of a seismic amplitude anomaly. This seismic data along with LWD density image data was used to successfully place the horizontal production well which accessed a 114m MD pay section and flowed in excess of 11,500 bopd. A 2010 4D snapshot taken in early July 2010, 5 weeks after production started, identified the source of the well's rapidly increasing water-cut and identified further infill locations. Despite modest production for an offshore North Sea development the first Maule producer has been an economic success for Apache as a result of integrated subsurface technical work, drilling performance, small field allowance incentives and a sense of urgency.

Lifecycle energy modeling can be used as a primary design input during early project development. This requires a life of field facility model adapted to early concept design which allows operational costs and revenue collection to be considered against capital cost impact. Significant overall project savings can be discovered with this analysis even in cases where CAPEX impact is unfavorable. A design model based on a production depletion curve is used to set facility capacity requirements and to allow calculation of operational data such as yearly production achieved, fuel gas usage, carbon emissions value, and deferred production due to downtime. Production concepts can then be subjected to a quantitative analysis of external influences, such as effect of carbon emissions cost on project economics. A sensitivity case is developed using a production concept based on an all electric facility with major users (gas injection compressors and water injection pumps) employing variable frequency electric motors. Calculated carbon emissions, fuel gas usage, and expected availability for this case are compared against a base case utilizing discrete gas turbine drives. These lifecycle cost methods and analyses can supplement the conventional CAPEX focus during initial design phases of onshore and offshore facilities, a period in which some of the most important facility design decisions are made.

Long subsea tie-backs are increasingly considered for offshore step-out field developments, which often have intermediate or smaller reserves and complex flow assurances issues. In such cases, the flowline architecture either faces prohibitive cost for insulation requirements or, curtailment of prospect development due to the physical limits of insulation systems being exceeded. Hence, in addition to the passive thermal insulation, the heat losses must be compensated by active heating. The Total Group has identified, beside other available technologies, the Electrical Trace Heating of subsea pipelines as a promising solution, with higher energy efficiency, and ability to be energized from host platform with a limited impact, thus leading to economic optimisation. During the last decade, anticipating the interest of the industry, Technip have run a comprehensive R&D programme on an Electrical Trace Heating solution for reeled Pipe-in-Pipe (ETH-PiP) ( Denniel and Laouir, 2001 and Denniel et al, 2005 ) and have joined Total’s qualification programme in 2008. After more than two years of successful qualification ( Denniel et al 2010 and de Naurois, et al, 2011 ), Total and its partners have considered the technology mature enough to allow the next step of the development: Industrialization. Located in the Northern North Sea sector, the Islay Project, recently awarded as a full EPCI contract to Technip, has been selected as a pilot project for this technology. Whilst ETH-PiP is not the primary hydrate mitigation strategy - this is achieved by an innovative seabed conditioning strategy seeking to minimise the methanol injection requirements - Islay is an opportunity to perform full scale offshore testing and can be considered as the final qualification process for future large scale projects in both the North Sea and worldwide. This paper details the industrialization process undertaken for ETH-PiP as part of the overall Islay Project delivery. Specific attention is drawn to the concept assessment, detailed design, project trials, assembly and offshore installation sequence to be carried out through 2010 and 2011.

Production Petrophysics plays a key role in reservoir surveillance and field management. This is particularly true for mature assets which present several challenges related to fluid contact movement, connectivity of reservoir layers and well productivity. Identification of infill targets therefore requires an integration of all sub-surface data. This paper presents examples from a mature North Sea field where cased-hole surveillance helped minimize risks in a high cost infill project. The Machar field, located in the UK Central North Sea is a fractured Cretaceous chalk and Palaeocene sandstone oil reservoir. The field development has been carried out in a phased manner due to a high degree of reservoir uncertainty, especially in the eastern flank. Enhancing the seismic sufficiently to fully assess prospects on the east became a priority, and ultimately led to drilling the east flank of the field in 2008. Machar is a subsea field development and therefore petrophysical surveillance has been restricted due to limited well access and logistical challenges. During the infill drilling, it was therefore decided to use the opportunity and capture cased-hole saturation and production logs in existing wells. This data enabled the asset teams to understand fluid displacement mechanisms and upon integration with LWD and other logs provided the basis for the side track strategy. In particular, location of the imbibition flood front, fracture conduits and differentiation between formation and injection water were critical in the delivery of a successful producer. Two wells have been drilled on the eastern flank, one in 2008 and another in 2010. Baseline petrophysical surveillance was part of the data acquisition program in both wells. The initial objective was to use such data in Time Lapse mode with later surveillance. However, in-depth work identified immediate use when integrating with LWD and Wireline data.

This paper discusses the differences between Process Safety Management and Asset Integrity Management. It demonstrates how Asset Integrity is defined and managed simultaneously across a wide range of asset types –oil and gas, offshore production, onshore terminal, fixed platform, FPSO, NUI, new and mature assets. The process is based on simple yet established principles which give clarity to areas that require attention. At its centre is a tool which defines the current vulnerability of the assets against engineering, production, maintenance, systems and human factors parameters. The vulnerability of an asset is ‘benchmarked’. The information is displayed in different formats to meet the requirements of each level of risk management and accountability in the Duty Holder organization. This accelerates understanding of the current risks against Major Accident Hazards as both single and combined events. Remedial actions can be prioritized and resourced. Senior Management can interrogate the process to a detailed level in order to challenge the effectiveness of the interventions. The process is based on the Barrier Model and uses Process Safety Performance Indicators selected to monitor Asset Integrity based on the company’s experience of managing offshore oil and gas assets. Each barrier is different and has an appropriate weighting. Calibration against a standard defines the strength of the barriers which in combination should prevent Major Accident Hazards on a site. Lagging and Leading PSPI are treated as ‘Holes’ and ‘Cracks’ in the barriers respectively. Weekly performance against the PSPI is recorded and used to derive the Vulnerability Index for the asset for that week. After any event against a PSPI, a simple Root Cause Analysis is carried out to determine which individual barriers were involved. Combined Risk is displayed in a number of different formats. The process is adaptable, and can be scaled to suit a wide range of different types and size of facilities. It can be adapted for use in Process Safety Management This process has evolved over three years. Asset Integrity Management is now imbedded in the organization. The implementation journey has not been easy. The paper gives an insight into the traction factors on this journey. Asset Integrity is a status; you either have it or do not have it. Process Safety Management may deliver Asset Integrity. Asset Integrity Management is specifically designed to deliver Asset Integrity on a facility. Process Safety Management has the benefit of being applied to a wider range of industries and size of facilities. Appendix D discusses the above and the company’s journey in terms of Asset Integrity Management up to 2008.

The Frigg Cessation Project was the largest decommissioning project undertaken in the past decade and included the removal of six topsides, three steel jackets and sealines with an estimated weight of 87.000 metric tonnes. The magnitude of the project and the fact that the field straddles the border between Norway and UK makes it unique. Both British and Norwegian statutes apply on Frigg, depending on the location of the platforms. It had been therefore necessary to find an agreement with the relevant authorities of both countries so that the decommissioning of the Frigg field can be handled as a single unit observing both sets of national statutes. This paper presents a brief description of the Frigg field with its installations to be decommissioned and disposed of, the process and schedule followed by TOTAL to define the decommissioning scope including public consultation of the stakeholders and preparation of the cessation plans for submission to the regulatory bodies. It will also describe the contracting process followed for the award of the main contracts. Furthermore the paper will describe the main execution phases from the offshore hook down, the removal and transportation to the onshore disposal of the installations and will conclude with some lessons learned from this project.

Abstract Forties is the largest oil field in the United Kingdom Continental Shelf, with approximately 5 billion barrels of oil originally in place and 2.6 billion barrels of oil produced since start-up in 1975. After acquiring Forties and taking over as Operator in 2003, Apache rejuvenated the field with an active programme of infill drilling, workovers and facilities upgrades. Since 2003, 50 new targets have been drilled and projects to upgrade power generation, export pumps, and water injection systems have been completed. By 2008 the combined impact of these activities had increased production from 40,000 to a peak of 81,000 barrels per day and an annual average production in 2008 of 61,700 barrels per day While these activities had been successful and profitable, Forties faced the ever increasing challenges common to mature field development - increasing well numbers and shortage of wells slots, increasing water production, variable drilling results, and ageing infrastructure beyond its original design life. Because of this, in 2008 Apache prepared a development plan for the long term future of the field. At this point it was important to take stock of the opportunities and challenges to confirm the forward direction and priorities. Creating the plan required a multi-disciplinary effort spanning geology through to production operations. The target inventory and conditions of the facilities were reviewed and options to enhance the facilities and remove bottlenecks were identified. The interdependencies among disciplines and the implementation of the activities on the platforms were also key considerations, as were using the reservoir model and economic analysis to inform development decisions. Preparing the development plan for a mature field, especially one as large and complex as Forties, brings its own unique set of challenges. These challenges and the approach used to address them are described here. Introduction The Forties field is a Palaeocene reservoir in the central North Sea, United Kingdom Continental Shelf ( Fig. 1 ). It is the largest oil field in the UKCS with cumulative oil production through to the end of 2008 of 2.6 billion barrels. In 2003 Apache took over as Operator, rejuvenating the field with an active programme of infill drilling, workovers, and facilities upgrades. By 2008, the combined impact of these activities had increased production from 40,000 to a peak of 81,000 barrels per day and an annual average production in 2008 of 61,700 barrels per day ( Fig. 2 ). Apache experience of the reservoir management aspects of the rejuvenation is described in SPE 109012. While the activities carried out between 2003 and 2008 had been highly profitable, and were easily identified and mostly self-evident areas for investment, further development faced the challenges common to many mature fields. The infrastructure was ageing. Infill targets were getting smaller and more difficult to predict and drilling results were variable. Reservoir pressure was falling and water production was increasing. Facility limits were increasingly constraining production - some platforms were constrained by liquid and gas lift capacity, others by well capacity, and some were reaching their slot limit for new wells. Space and bed constraints limited the ability to execute simultaneous drilling and project work offshore and striking the balance between short and long term projects was becoming increasingly difficult. An assessment was required to identify the options which combined to give the greatest value.

Abstract Many works on dynamic models for the maximization of the Net Present Value (NPV) on upstream projects have been published in recent years, originating in the academy as well as the industry. These models usually treat the effort considering either the exploration stage or the development stage of the petroleum field, but not both together. This paper will investigate of the optimum net present value in the upstream project considering both exploration and development efforts simultaneously. This model will enable to address some of the following question: What is the optimum exploratory effort for a petroleum field? What is the optimum time span which the exploratory efforts deserve investment before the beginning of the development stage? What is the appropriate value of the reservoir recovery factor? The maximization of the NPV is represented by an objective function. The influence of the parameters in the estimation of the proposed objective function is shown by means of sensitivity analysis. Among the companies in the world exploring petroleum, several do not usually adopt a methodology combining the exploration and development efforts. Filling this gap in the methodology is the main motivation for this work, which intends to disseminate the use of the combined model in the analysis of the economic viability project of the upstream area. Introduction The present work has one main purposes: investigating the optimum exploration and development effort of a petroleum field by the maximization of the net present value of the investment. The optimum effort, both in the exploration and the development stages, is simultaneously assessed using a dynamic simulation model. Recent paper presented by Marques et al (2007) made a comparison between the impact of the Hotelling approach (1931) and the dynamic model. In this paper we presented a simple maximization dynamic model for exploration and production efforts tha posses more practical applications for the industry. This type of modeling is not yet widely used in the petroleum industry; instead, these maximizations are in general treated separately. The issues in any search for optimization of exploration and development activities are: what is the optimum exploratory effort of a field, expressed in number of wells? What is the optimum exploration phase before start development phase? Which optimum rate of the field reserve should be extracted per year? Of course some simplifying assumptions will be made, in order to allow appropriate simulations of the models, but care will be taken not to distance the model from reality. The first assumption is that there is a relationship between the value of the discovered reserves of a petroleum field and the exploratory effort spent in the discovery. This is reasonable, and it is observed in practice by all hydrocarbon exploration and production companies in the world. Due to the complexity and the number of variables involve in each stage, it is common to find models that deal with exploration and development optimization efforts in a sequential way. A combined treatment of both efforts is certainly possible, although the parameters needed for a combined model are difficult to measure. Some important contributions can be found in Liu and Situnen (1982), Pakravan (1977), Peterson (1978), Pindyck (1978), and Nilssen and Nystad (1986). The model adopted in the present work has similarities with Nilssen and Nystad (1986), but some of the simplifying assumptions were employed in order to facilitate the treatment of both phases (exploration and development). The two main assumptions are: production starts immediately after the end of exploration; and a long-range approach should be used to forecast oil price behavior. For the oil price -- the most complex variable - some classical approach can be used, such as the arbitrage pricing theory, Varian (1987) and real options models (Black-Sholes, McDonald & Siegel 1986, Dixit and Pindyck 1994, Trigeorgis 1996).

Abstract Intellectually all those associated with the Exploration and Production business can articulate the critical role that people play in an industry which is risk based and capital intensive. With demographic pressures and fewer students pursuing science and technology in the developed world the criticality of attracting, developing and retaining people is paramount. In the developing world there is often an ample supply of graduates however the challenge of building real capability and experience cannot be underestimated. Against the background of the global challenges it is proposed that people be viewed much more as a part of sustainable development. The classic sustainable development model, comprising of economics, the environment and the community has people at every level. To achieve the goal of a long term sustainable contribution from the people currently in the industry and those considering joining will take a major shift from some of the development models currently employed. This paper examines the significance of a competent trained and motivated workforce against the background of the SD principles. The themes developed are based on extensive contact and discussions with both National and International oil and gas companies around the globe. Getenergy as an independent broker of training and development (learning) has gathered a fascinating insight to the challenges, and some of the possible solutions. The concept of building on the model of sustainable development has been raised and tested at many forums around the world and it is felt that bringing it to OE2007 will enhance the debate and help drive the concept forward. Introduction Wherever one looks in the global upstream oil and gas business the challenges of developing people are frequently mentioned as key issues. Given the capital intensive nature of the industry and the development life cycle of most projects, it is intriguing to examine the role of the people and the connections between the two. Increasingly society is using the expression "sustainability" to indicate that what we do today must be extendable into the future without sacrificing that future. This fundamental tenet is encapsulated in the quote by Gro Harlem Bruntland, "Sustainable development is development that meets the needs of the present without compromising the ability of future generations to meet their own needs." (Our Common Future - 1987) This paper takes the classic three elements of the sustainable development model, comprising economics, the environment and the community and looks at them in the context of the development of people. Background Fossil fuels have been used for many hundreds of years. One of those, coal, was the foundation of the Industrial Revolution which spawned so many technological advances in the 18th and 19th Century. With the advent of the internal combustion engine and the development of petrochemicals, oil and gas consumption has grown to a stage where it provides about one third of all the world's energy requirements. Our society has taken the opportunities to heart. Specifically the motor car and low cost air travel forms a major part of our lives. With predictions of increasing demands for oil and gas there are multiple challenges, such as: Emissions and the issue of global warming. The management of finite resources of oil and gas. The exploitation of the "easy to find and produce" and the move towards more complex settings and environments. The economic potential of locked-up hydrocarbons and tar-sands. Geo-political factors linked with the global disposition of major sources of hydrocarbons. Market forces driven by global events. Societal desire for renewable energy sources. The continued development of the people and skills to deliver a hydrocarbon based economy.

Abstract An analysis framework is presented that unifies the subsurface and surface disciplines involved with developing offshore projects. The method treats the complex interactions between surface and subsurface aspects of a production problem as a single system. The framework optimizes and assesses the risks and uncertainties associated with facility concept selection and sizing, with consideration of relevant subsurface and surface uncertainties and risks. There is considerable uncertainty in the subsurface; this manifests itself in terms of a range of reservoir deliverability and reserves. In many projects, this subsurface uncertainty is not properly conveyed to the surface teams who are charged with selecting the best facilities design for the project. Often, the result of this disconnect yield suboptimal facilities followed by expensive retrofitting. The framework presented automates optimization of the concept design with rigorous reservoir and facilities modeling. Two case studies are presented, both with multiple reservoirs connected through a common pipeline network. The first case is a typical deepwater U.S. Gulf of Mexico project. The second case is more typical of a medium water depth development in northern Europe. Full scenario analyses of multiple production platform alternatives and number of wells optimization is evaluated within a context of reservoir volumetric and drive mechanism uncertainties. This framework accomplishes the following: it links physics-based reservoir deliverability and expert-system based facilities screening tools with the economics analysis in a unified workflow, and it applies advanced non-linear optimization to deliver better decisions regarding facilities selection and sizing. Introduction In a field development life cycle for new large offshore developments, a key decision occurs early in the life cycle, that is, selection of viable facility concepts that can be taken forward into pre-FEED (Front-End Engineering and Design). Selecting offshore facility concepts is a complex endeavor, associated with high risk. The facilities engineer must provide management with a high-return proposal for field development in a situation with large capital investment, often a billion dollars or more, given large subsurface, well, production, and surface uncertainties. The most common practice in the industry takes a linear, deterministic, case study approach, wherein the facility engineer considers a few concepts by analogy, given a range of reserves estimates from geology and reservoir engineering with considerations for drilling, water conditions, etc. The practice may lead to sub-optimal selections, as it tends to ignore the full range of alternative scenarios and uncertainties, leading to higher risk of over- or under-design. We present an integrated decision framework anchored by a commercially available expert system that evaluates and then ranks facility concepts. Figure 1 a diagram of the integration of subsurface models with multiple reservoirs, wells, surface gathering network, production system, and economic evaluation. The key calculation components are an expert system for concept selection and costing, a coupled reservoir and network flow simulator, an uncertainty calculator, an optimizer, and an economics calculator. In this work, for each case study we present two decision procedures which take advantage of the core components to integrate field development planning decisions with risk analysis. The approach has at its core a powerful expert system with an extensive worldwide database of offshore project metrics used for generating, ranking and then selecting concepts, based on a discounted cash flow analysis. The first procedure connects the expert system to a high-resolution uncertainty and optimization calculation engine which enables a more complete evaluation of risk in identifying and selecting optimal concepts. The first procedure provides a valuable "quick-look" capability, but it has some limitations, for example, the accuracy for production profile and reserves predictions and the granularity of economic analysis. In the second procedure, we address the limitations by integrating the expert system and the uncertainty and optimization engines with high-resolution physics-based reservoir and network flow simulation and fiscal models.

Abstract The large amount of material of HC isotope composition of over 330 samples allow to restore the history of oil and gas deposits formation within the South-Caspian Depression. Maps of isotope composition changes according to area extent, as well as graphs of HC distribution depending upon stratigraphic age, including rocks, graphs of isotope composition change on sampling depth were compiled for HC study and oil-gas deposits formation. Comparison of mud volcanoes gases, oil and gas fields, gas-hydrates and bottom sediments were conducted. Gases genesis according to M. Shoelle and A. James methodic were studied. Model of area paleoconstruction was studied. Two stages of formation were distinguished as a result of gases study of various forms of their manifestation (gases of mud volcanoes, oil and gas fields, gas hydrate, bottom sediments) as well as isotope gases composition distribution in area of extent including stratigraphic age of deposits, depth of sampling and application of M. Shoelle and A. James. There were determined basic ways of HC migration as well as estimated oil-gas content prospective. The first stage has begun in the underlying PS deposits and continued up to PS deposits. At this stage one various kind of tectonic fluctuations can observed. The second stage of HC formation has started from PS and characterised with a change of geodynamic conditions in region. Avalanche sedimentation, predominance of descending movements over ascending ones promoted the accumulation of thick sediments in PS age. As a result of sediments accumulation and tectonic processes (down warping) in the deep-seated basin led to the complication of thermobaric conditions in the sedimentary series. The studied chemical and HC gases isotope composition showed that basic source of oil and gas formation is located in the deep areas of central and near-flank parts of depression. HC migration has mainly occurred upward. Study of HC migration trend in time and area as well as areas of generation etc. allows to reveal some structures where there is evidence of HC accumulation with large and gigantic reserves. Geological review South-Caspian depression covering Caspian Sea basin and adjacent to it Azerbaijan and Turkmenian land represents a large intermountain trough which is delineated by mountainous constructions of the Greater and Lesser Caucasus, Kopetdag, Pribalkhan, Elbrus and Talysh. Deposits from Anthropogenic to Jurassic age inclusive take part in the geological structure of the South Caspian depression. Large tectonic elements relating to near-flank framing and fold zones of the internal part of depression are distinguished within the South-Caspian depression. Fold zone within Baku archipelago, Abhseron-Pribalkhan zone, West-Turkmen depression and Pre-Elburs marginal trough. Near-flank framing composes form Low-Kura depression. In the oil-gas bearing relation lithological and tectonic heterogeneity of structures within the South-Caspian depression testify to heterogeneity of this basin. Productive Series (PS) is the main oil-gas-bearing complex with the outcropped part of the section containing over 90 % of discovered oil and gas reserves. Insignificant commercial deposits have been found in deposits of Akchagyl, Absheron, Chokrak and Maycop series.

Abstract Despite having been explored for over 40 years, 3.6 billion barrels of oil equivalent have been discovered in the last five years in north west Europe. On average US$2.4 was spent on exploration for each barrel found in the offshore region. This unit finding cost is comparable to that in the deepwater Gulf of Mexico over the same period, one of the global hotspots for exploration. The largest volumes of reserves were found in Mid Norway where 1 billion barrels of oil equivalent has been discovered in the last five years. Despite this apparent success, only one of the 11 fields found in the sector is currently expected to be developed before 2012. Gas export capacity from the region remains an issue. The North Sea itself attracted 75% of the exploration expenditure over the last five years and 2 bn boe of reserves were discovered. Finding costs ranged between US$2.5/boe for the Norwegian North Sea to US$3.5/boe for the UK Southern Gas Basin. Although significantly higher than the US$1.5/boe unit finding costs in Mid Norway, over 50% of these reserves are expected to be developed within five years. Industry cost inflation and lower discovery sizes have resulted in the finding costs of the last five years doubling from the previous five. However, with a record number of exploration licences being held, US$2.5 billion being spent on exploration last year and substantial finds still being made, there will be many more exploration success stories to come in the region. Introduction The offshore regions of north west Europe have been explored for more than 40 years, over which time 4,000 exploration wells have been drilled. The core areas of the North Sea in particular, have undergone intensive exploration with 30 exploration wells drilled on some blocks. Unsurprisingly the average size of new discoveries has reduced since the early days and in the late 1990s and early part of this decade there was a significant drop in the number of wells drilled in the region. The dramatic drop in oil price and the mega-mergers at that time caused companies to rethink their global exploration strategies and the perception of the North Sea as a mature province, coupled with the opening up of new global provinces, resulted in a smaller proportion of exploration budgets being allocated to the sector. More recently interest in north west Europe exploration has returned and the number of companies holding licences in the region has risen by 50% since 2002, from 163 to 248. This has been driven primarily by the increase in oil and gas prices, but has also been encouraged by fiscal incentives, regulatory changes plus a number of high profile discoveries. Countries and regions are effectively competing for exploration spend. Overall, north west Europe has been successful over the last five years in attracting exploration investment despite global cost inflation and a reduction in the volume of reserves discovered. North west Europe offers a wide spectrum of exploration drilling opportunities from frontier regions such as the Barents Sea, to step out wells from existing developments. Recent exploration wells have been drilled in water depths ranging from 20 metres to nearly 2 kilometres. In addition, new play concepts are still being tested and technology is constantly being pushed. Notably, major steps forward have been made in high pressure / high temperature (HP/HT) drilling. Methodology The numbers in this paper are based on Wood Mackenzie's upstream database. The information is collated from a range of public domain sources plus feedback from operators and participants across the North Sea. The final numbers that are in the database are Wood Mackenzie's view based on analysis of the information that was available. Well cost data is based on estimated costs per well which has been compared to reported government and company figures in each country or region. Wood Mackenzie's global well cost database includes 190 countries where any significant exploration has taken place. The only notable provinces excluded are the onshore US, the US Gulf Shelf and Eastern Europe.