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Abstract Digital Energy (DE) describes broad initiatives to improve asset performance and boost corporate value through operational excellence and engineering design. It has been described in many papers presented at SPE meetings such as Digital Energy in Houston and Intelligent Energy in Europe and the Middle East. Digital energy introduces new principles and information technology (IT) tools, frequently requiring new work processes, workforce adoption, and changes in behavior. One description of digital energy (Davidson and Lochmann 2011) includes: Fully-integrated, multi-disciplinary operations Task and process automation Digitally-enabled technology Business or operational intelligence Innovative, efficient methods to maximize performance The move from โgood enoughโ practices to operational excellence is a transformational change (evolving from one โlookโ to another or one culture to another)and poses challenges and opportunities for organizations. Applying DE principles to promote operational excellence inevitably leads to new ways of working and unfortunately, organizational stress. Some of the challenges include aligning people, technology, and the organization to the new vision. The first step in the digital energy process, regardless of a projectโs size, should bean assessment of an organizationโs current state including its level of understanding of DE, readiness to change, and what a digital energy initiative may contain. An assessment is a way to look into the world of DE and identify the functionality that may be best suited for a companyโs operating environment and assess its impact on performance. Assessments have proven essential for success when organizations undertook major projects to improve asset performance and increase corporate value. Assessments often uncover unexpected paths to better performance. The objective of an assessment is to identify and articulate the organizationโs operational vision (different than broad IT or engineering objectives) and follow a structured approach to uncover and identify how DE initiatives can support and solidify the organizationโs strategic objectives. During an assessment, information is gathered to identify and understand business drivers and goals while analyzing business priorities and developing value propositions. Through the evaluation and analysis of this information, a working solution roadmap is produced. Because E&P organizations are largely unfamiliar with the practical aspects of DE, the assessment step is often undervalued and, in some cases, skipped altogether. This means suboptimal results, increased project risk, and diminished returns.
- Europe (0.87)
- North America > United States > Texas (0.68)
- Energy > Power Industry (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
- Information Technology > Information Management (0.68)
- Information Technology > Data Science (0.68)
- Information Technology > Communications (0.46)
Abstract Declining global economic conditions and increased pressure to find new, affordable sources of energy create a turbulent macro environment for oil and gas companies. Stakeholders present conflicting goals of increased return on investment while simultaneously reducing risk and providing greater transparency into project performance. The traditional models of large scale investment into major capital projects can no longer guarantee success; instead, organizations must focus on capital management throughout a project's life cycle. Significant effort, time, and resources are invested in project delivery. However, poor decisions during the planning phases may result in loss of value during execution. By combining decision analysis tools and techniques with integrated, dynamic planning systems, companies are able to carefully manage their capital across the project life cycle to understand their costs, resources, and schedules. These companies benefit from increased collaboration leading to more informed decision making balancing risk and reward. This paper presents an innovative method for evaluating and dynamically planning the development of uncertain upstream investments. It centers on a paradigm shift in the way upstream managers assess investments, toward an approach that incorporates decision analysis tools and techniques with integrated dynamic planning systems. Case study examples are provided to illustrate key principles.
Abstract The Reserve Technical Potential Management System (RTPMS) is divided into 5 main stages and associated together with the Petroleum Reserve Management System by SPE. The main aim by merging these two concepts is to improve understanding of the reserves pool and therefore provide a practical guideline on a standard definition for high level planning and day-to-day operations. The concept is being developed with major focus on the rehabilitation of mature fields where each barrel of oil counts and uncertainty, both technical and economical, are becoming more challenging at industry level. High decline in productivity and increased operational challenges are common issues for mature fields. Recurrently, lower recovery factors are mainly driven by reservoir characterization uncertainty and management, geological complexity, limited resources and operational efficiency. This paper addresses some of these challenges in an integrated manner. Each stage is mapped and associated with the SPE Petroleum Reserve Management System, the project management control level, the time cycle (short: operation efficiency, medium : production optimization and long: reservoir management), a digital oilfield concept, the roles and responsibilities of the stakeholders, the technology groups and their key technologies. The five stages are defined as; 1) Actual Potential, 2) Operational Technical Potential, 3) Constrained Technical Potential, 4) Theoretical Technical Potential and 5) Ultimate Technical Potential. The concept has been developed based on lessons learnt and best practices acquired in mature field rehabilitation projects.
Abstract This paper tells the story of the steps that an E&P company took in implementing a methodology to plan, deliver and execute capital projects predictably. It addresses the challenges that any organization faces in effecting change, as well as the actions taken to ensure success for the initiative. This story can serve as a blueprint for any organization that wishes to improve capital performance. The focus of the paper is not so much the solution implemented, but rather the steps the organization took to ensure a successful implementation. In this paper, the terms "project delivery system" and "asset development system" will be used interchangeably. The company wanted to improve the predictability of its delivery of major capital projects. The company felt that to meet its business objectives, one of many things it needed to do was improve its capital execution or asset development performance. E&P companies have many paths to growth while achieving sustainability. A traditional approach is to grow via exploration while producing efficiently. Exploration and production are recognized critical competencies for E&P firms. What is often not appreciated is that the path from exploration to production must go through asset development or capital project execution. The figure below illustrates the three major competencies that an E&P company needs to grow. Often, firms choose the acquisition path in lieu of exploration. Nonetheless, short of acquiring fully mature assets, there is always some exploration work necessary
Abstract Most oil and gas executives and financial analysts have long believed that minimizing the time to first oil is one of the most important parameters to maximize the economic value of exploration and production (E&P) projects. This belief has driven project teams and oil company executives to push ever faster schedules. Our data show that chasing fast project schedules inadvertently destroys more value than it creates. We use a detailed database of oil and gas projects to conduct a rigorous statistical analysis, comparing project economics promised at sanction to the actual results achieved. Using performance data from the database, we can statistically quantify the change in expected outcomes (cost, production, reserves), and therefore the net present value (NPV) realized, as a result of different schedule targets. The results show that chasing aggressive first oil dates has a consistent negative effect on NPV because of worse than expected cost and production attainment. These effects are more damaging than the loss of value that occurs if a project is slowed down early in the project cycle to improve the quality of front-end preparation and planning that helps to mitigate cost and production attainment shortfalls. When speed becomes paramount, reservoir appraisal and project definition phases are shortened projects proceed without high-quality basic subsurface data, and often short-cut crucial planning phases. As the quality of data and planning degrades, teams are forced to make more assumptions, which increases uncertainty in cost, production, and reserves estimates. During execution, these major uncertainties, along with incomplete data and planning, drive cost growth, reserves downgrades, production shortfalls and, ironically, schedule slip. The poor than expected outcomes have a negative influence on the project economics, but are often ignored by economic models. In all projects there are choices to be made that lead to trade-offs between cost, schedule and production. Many companies prioritize their focus primarily on meeting their schedule and then, cost targets in order to achieve maximum economic returns. The reason production is often not part of the trade-off is because because of the belief that there is no trade-off between schedule and production, only between schedule and cost. Our analysis provides evidence to the contrary leading us to conclude that the order of priority should be reversed. We go beyond this observation and provide the reader with insights into how the unintended consequences of certain project drivers can be incorporated into more realistic economic models.
- North America > United States (0.46)
- North America > Canada (0.28)
An Efficient Decision Framework for Optimizing Tight and Unconventional Resources
Wehunt, C. D. (Chevron Corp.) | Hrachovy, M. J. (Chevron North America Exploration & Production Co.) | Walker, S. C. (Chevron North America Exploration & Production Co.) | Padmakar, A. S. (Chevron Energy Technology Co.)
Abstract Making an efficient and wise concept selection decisionโquickly selecting the right projectโis often of equal or greater importance than later design and execution tasks for determining project success. Value lost from a suboptimal concept selection decision or from a needlessly prolonged decision process is independent of value generation opportunities during design and execution, and cannot be recouped during later project phases. This paper presents decision framework and production forecasting processes that complement one another, and promote an efficient and high-quality concept selection decision for tight or unconventional resources. The method is for both oil and gas resources, and is especially useful for assessing and developing large contiguous tracts. High quality production forecasting is very important during concept selection. Better quality concept selection decisions will also result if the alternative conceptual plans are equally optimized when the decision is made, and our assessment process facilitates both accurate forecasting and equal optimization of the various development alternatives. Our method includes symmetry element reservoir simulation models and an efficient economic spreadsheet model with an optimizer. The sector simulation models run fast and can evaluate many cases, but they still explicitly address the physical effects relevant to flow in porous media with vertical, transverse, hydraulic fractures intersecting horizontal wells. The decision framework is structured so that some decisions are independent of the simulation model, and those decisions are rapidly optimized within the economic model. We introduce a fracture efficiency factor which may be important for modeling the diminished performance observed as the number of stages increase in multi-fractured horizontal wells. This fracture efficiency factor may also be an important discriminator of performance between wells fractured using aqueous vs. non-aqueous fracturing fluids. We also show how to use meaningful constraints with a symmetry element model to ensure that the economic forecasts are both realistic and achievable.
- North America > Canada (0.68)
- North America > United States > Colorado (0.67)
- North America > United States > Colorado > Skinner Ridge Field (0.99)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Horn River Shale Formation (0.99)
- (3 more...)
Abstract Many papers have been written concerning the energy industry's need to become more efficient in its methodologies and operations.The shrinking qualified workforce and global economic factors are placing further pressures on the energy sector to streamline processes.This requirement extends itself to all phases of the energy industry, especially with multi-disciplinary multi-organizational teams. [1โ5] For the past 5 years a major private equity player has successfully exploited the digital oil field to streamline its asset management processes.This company manages its 2.3 billion dollar oil and gas portfolio with a staff of 5 professionals by utilizing a web-based portfolio management tool.This same staff of 5 annually approves over $100 million in AFE's. Since inception this web-based application has been successfully deployed to manage 36 different partnerships across the United States.This system has benefited by the proactive input of over 300 industry professionals throughout the application development and deployment cycles.The software currently consists of over 60 different analytical tools to analyze the performance of a portfolio. This paper examines the use of web based technologies to build a portfolio management system.There are many pitfalls and challenges to overcome to ensure the success of an application designed to monitor performance and measure value.From specifications through rollout to E & P companies aspects of design and deployment are thoroughly explored. Introduction Professionals in the oil and gas industry spend inordinate amounts of time and effort to gather, organize, format, and synthesize data into useful reports for subsequent analysis. Precious efforts, which should be directed towards proactive actions to improve value, are often diverted to lesser-valued services. A web-based portfolio management tool can assist E&P companies in adding value to a project while at the same time keeping investors, partners or managers informed as to the performance of a project or an entire portfolio. In most circumstances, the operator is the only party in possession of data required to understand and evaluate a project.A mandate or requirement of the operator to provide the necessary production and financial data to investors/lenders can be counter productive to the overall objectives of the project.The operator's primary focus should be on higher valued services (effective operations and adding value to a project) not on data assimilation. Constraining an operator with excessive reporting requirements is a good way to ensure that project performance objectives are missed. Conflicting requirements of timely analysis versus a focus on higher valued services makes the prospect of portfolio management rather bleak.Many have attempted to solve this problem with excessive man power and herculean efforts.Others simply settle for analysis which is old and outdated. Traditional efforts usually involve attempts to utilize spreadsheets to communicate and track productivity.However, the limitation of spreadsheet technology to track and manage a portfolio becomes evident once an organization begins to handle multiple projects.
- Asia (0.94)
- North America > United States > Texas (0.28)
- Information Technology > Software (1.00)
- Information Technology > Security & Privacy (1.00)
- Information Technology > Communications > Web (0.70)
Abstract The time between discovery and development of a petroleum asset is wrought with many decisions, all with an aim to reach first oil with minimum expenditure, and maximum value. Not surprisingly, sorting through all the decisions and uncertainties is a daunting task for asset teams worldwide and lends itself to the use of a systematic approach. The focus on this phase is obvious. The majority of investment in a petroleum asset is in the appraisal and development phases, where the potential for value degradation due to lengthy, unfocused evaluation or sub-optimization of the project is great. Key to accomplishing the goal of maximizing discovered asset value is the development of an appropriate appraisal and delineation strategy - ideally, geared toward gathering information, which adds value by optimizing development strategy selection. This requires a clear understanding of the development decisions ahead, and the existing uncertainties in the field, making the selection of development strategy difficult. Only with a clear understanding of the direct linkages between appraisal and development strategy, can teams set up their evaluations correctly. This requires a practical process and tools to identify and understand those interrelationships. This paper proposes a practical methodology to frame (set up) appraisal and development strategy evaluations, and provides an illustrative example utilizing the approach. The methodology combines classic decision analysis with a new team-based, efficiency tool, referred to as "Decision Mapping". Decision Mapping is a simple framing tool, which helps multi-discipline teams identify the development decisions facing them, the key choices "in play" for each of those decisions, the interrelationship between those choices and the key uncertainties driving their value. The Decision Map focuses teams on "why they cannot make each development decision today". This in turn helps them identify the inter-related decisions and key uncertainties, around which appraisal needs to focus. As appraisal and flexibility decisions are both "Valuing Information" decisions, the proposed approach also incorporates previously described methodologies to frame and value information-gathering decisions1 and expands them to address related project sanction decisions. One of which, valuing appraisal well placement, will be addressed specifically. Introduction The Decision Mapping approach promotes the use of two levels of "problem frames" (i.e. problem perspectives) to structure the evaluation of appraisal and development strategies. The large number of decisions and complexity of this phase drive the need for the two levels of frames, referred to as the "High-level Frame" and the "Next-level Frame". An asset has only one high-level frame, but will have many next-level frames. The high-level frame consists of all the issues (e.g. anything of concern, such as decisions, facts, and uncertainties) associated with selecting the optimum strategy to pursue, and the structure of those issues for evaluation.
Abstract The biggest development in the North Sea for a decade has attracted industry attention as one of the most innovative projects to date. Seven economically marginal fields with different owners and different hydrocarbons have been brought together to create the ยฃ1.6 billion Eastern Trough Area Project (ETAP). Innovation on both technical and commercial fronts has been created by an unprecedented level of co-operation between companies. This paper outlines the basis of the project and the approach adopted to its formulation which resulted in novel technical and commercial solutions. The challenge for today's North Sea, with ever decreasing field size, is to reduce development costs/bbl to acceptable levels and to do this through working the two available levers: cost and the number of barrels. The ETAP solution to reduce cost and add barrels is to combine small fields into a single project with development cost/bbl similar to a single giant field, but with the reservoir risk mitigation inherent in accessing multiple independent reservoirs. This approach created many hurdles, both technical and commercial, and has stimulated innovative solutions. Technical hurdles include the need for long distance sub sea multiphase tiebacks in excess of 35 Km which have innovative chemical control and multiphase metering. Commercially, the project presented a major challenge as all parties agreed that a conventional unitisation of all the fields into unified ownership interests was neither practical or desirable in light of the range of fluid types and reservoir uncertainty. Accordingly a structure was developed to a) share Capital and Operating costs equitably, b) provide for production rights and production allocation and c) encourage full utilisation of the shared facilities. The significant cost savings needed to make ETAP viable were largely achieved in the conceptual design phase by designing shared and centralised facilities for both oil and gas field management. In the current project execution phase additional cost savings are being delivered through further application of "alliance contracting" with the contractors for design, fabrication and installation of the facilities and for the development drilling. Introduction Located within the Eastern Trough in the UK Central North Sea, the project encompasses the simultaneous development of seven accumulations (Marnock, Mungo, Monan, Machar, Heron, Egret and Skua) which lie approximately 140 miles east of Aberdeen in water depths of around 85 to 95 metres, and separated by distances of between 3 and 35 Km. Field interests are held by BP, Shell, Esso, Agip, Total, Murphy and Moex. While no one company holds an interest in all seven fields, BP, Shell and Esso have the widest interest across the fields. The Marnock field contains gas condensate and the Skua, Heron and Egret fields contain oil, all of which occur in over-pressured Triassic sandstone within tilted fault blocks. Mungo and Monan are diapir flank oil fields with separate gas caps reservoired primarily within Palaeocene sandstone. Machar is also a diapir field containing oil within fractured Chalk and in overlying Palaeocene sandstone. The seven fields have total combined reserves of 400 million barrels of oil, 35 million barrels of Natural Gas Liquids and 1.1 trillion cubic feet of sales gas and thus is equivalent to the largest oil field to be developed in the North Sea in the last 10 years. In terms of off take, the fields will produce over 180mbd (annual average) of oil on plateau for 3 years. In addition, gas produced from each field, after processing and planned injection will be exported at around 350mmscfd (annual average) with an anticipated plateau of 5 years with a peak rate on plateau of up to 450mmscf/d. Project Description - Facilities The design principle was to consolidate facilities into a single Central Processing Facility (CPF) which provides the processing requirements of all the fields. The location of the CPF over the Marnock field was selected as it provided the lowest overall development cost for the project. Such a development concept enabled all but the Mungo field to be developed as sub sea tie-backs. Mungo is developed through a minimum facilities - Normally Unmanned Installation (NUI) in light of the well numbers and anticipated intervention requirements. This resulted in an overall reduction in cost in comparison to separate "standalone" development of the fields and also to a reduction in operating costs. The facilities have been designed to satisfy all regulatory and BP corporate requirements in respect of health, safety and the environment.
- Europe > United Kingdom > North Sea > Central North Sea (1.00)
- North America > United States > Alaska > North Slope Borough > Beaufort Sea (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.64)
- Geology > Structural Geology > Tectonics > Salt Tectonics (0.44)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 23/27 > op (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 23/22a > op (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 23/16a > Eastern Trough Area Project > Mungo Field (0.99)
- (14 more...)
Abstract The Baram Delta is one of Malaysia's oldest and most prolific oil-producing areas. On the 31st October 1988, PETRONAS Carigali Sdn Bhd (PCSB) took over the operatorship of the nine oil fields in Baram Delta from Sarawak Shell Berhad(SSB). From its cluster of nine oil fields in the South China Sea, lying off the coast of Miri, Sarawak, the Baram Delta produces one-sixth of Malaysia'scrude oil production. After PCSB took over the operatorship of the Baram Deltafields, it implemented a number of large and economically attractive development projects. Existing platforms were revisited and wells worked-over or side-tracked. Furthermore, 5 new platforms were placed, to allow drilling of new wells. Typically 6 to 14 wells were drilled from these newly installed engineering structures. The two main development projects implemented during this phase were the Baronia project (two platforms; 21 wells) and Baram Field development project (two platforms and a jacket; 33 wells). Currently all major attractive projects have been implemented and further development is by the implementation of remaining smaller and more marginal projects. Typically, wells are side-tracked or additional conductors placed on existing structures. During the transition from the implementation of the large attractive projects to the current situation, where we implement smaller projects, our attitude towards the application of new technology changed. When implementing the economically very attractive and large projects we merely optimized these projects by the application of world-wide existing proven technology that was new to us in our operations. Driven by the marginal to unattractive economics of the smaller remaining projects, mere optimization is not sufficient. The current projects are only attractive when new technology is applied. Furthermore, we cannot just anymore apply new technology proven elsewhere, but new to us. In the revisits of the Bokor and Tukau fields, we have and plan to implement technology new to the industry. In the Bokor Field we have drilled a triple-lateral horizontal well, while in the Tukau field we plan to use the dual completion splitter wellhead. Since these technologies are unproven, implementation carries considerable risk, but when successful, large volumes of reserves can be economically developed extending the life of the existing fields. Instead of optimization, new technology now drives the value creation. In this paper, we will show the impact of this change in the application ofnew technology on project economics and the potential impact on our reserves base. Introduction The Baram Delta is one of Malaysia's oldest and most prolific oil-producing areas. From this cluster of nine oil fields in the South China Sea, lying off the coast of Miri, Sarawak, the Baram Delta produces one-sixth of Malaysia'scrude oil production (Fig. 1). The first offshore oil production in the Baram Delta Area was from the West-Lutong Field in 1968 operated by Sarawak Shell Bhd (SSB) under a concession, which granted SSB the license to explore, develop and produce the hydrocarbon resources discovered. Following the 1974 Petroleum Development Act(PDA), this concession was replaced by the Production Sharing Contract (PSC) in 1976. In 1985, SSB signed a new PSC with PETRONAS for the five fields in the BaramDelta area (Bakau, Baram, Baronia, Fairley Baram and West-Lutong), whose PSChad expired. The 1985 PSC extended SSB's operatorship of these five fields until 1988. P. 31^
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Malaysia Government (0.46)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Baram Delta Province > Block SK307 > West Lutong Field (0.99)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Baram Delta Province > Block SK307 > Tanjung Baram Field (0.99)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Baram Delta Province > Block SK307 > Baronia Field (0.99)
- (3 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Management > Strategic Planning and Management > Project management (1.00)
- Management > Asset and Portfolio Management > Project economics/valuation (1.00)
- Data Science & Engineering Analytics > Research and Development and Emerging Technology Programs (1.00)