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Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality. All three can lead to poor decisions regarding which work to undertake, what issues to focus on, and whether to forge ahead or walk away from a project. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders. Examples are provided including corporate, business unit and department case studies. This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets.
A new regulation includes provisions related to the timely abandonment of "dormant sites," a new site classification that refers to inactive wellsites operated by solvent companies. A new integrated modeling tool helps Canada analyze methane emissions to get a better understanding of the economic and environmental implications. "I have some patients whose symptoms I can’t explain," physician Ulrike Meyer said, describing nosebleeds, rare cancers, and respiratory illness among a dearth of data. British Columbia is seeking to enhance its regulatory spill response regime across the province by way of a phased approach. Phase 2 is currently under way, and comments on this process are due by the end of April 2018.
With declining trends in production and dwindling reserves for a 35-year-old offshore field, the Samarang Redevelopment Project was initiated with a vision toward implementing integrated operations as an asset-management decision-support tool. This paper describes a case study in which four reservoir models were coupled with a production-network model, with the objectives of maximizing recovery factors, identifying operational problems, and evaluating water-production effects.
The basic objective of this course is to introduce the overview and concept of production optimisation, using nodal analysis as a tool in production optimisation and enhancement. The participants are exposed to the analysis of various elements that help in production system starting from reservoir to surface processing facilities and their effect on the performance of the total production system. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
This paper presents the basic concepts and architecture of the Eni Reservoir Electromagnetic Mapping borehole electromagnetic mapping system that integrates borehole EM methodology with surface EM methods to provide real-time mapping of reservoir-fluid distribution during production or injection. An intelligent drilling optimization application performs as an adaptive autodriller. In the Marcellus Shale, ROP improved 61% and 39% and drilling performance, measured as hours on bottom, improved 25%. With their gee-whiz—albeit artificial—intelligence, robots may be the industry’s answer to jobs deemed dangerous, dirty, distant, or dull. A test showing that it’s possible to automate the billing process for produced water hauling has opened the door for tracking a wide range of field activities.
A recent panel discussion highlighted the industry’s progress in achieving significant digital advances. Barriers remain, however, and the measurement of success is being defined in this evolving technological step change. The contract continues the two companies’ 8-year working relationship; in 2012, they performed the world’s-first underdeck inspection. Despite streams of data being available on platforms about the condition of topside and drilling equipment, most experts agree that only a small fraction of such data is used. Whether for a fleet or single platform, AI can transform an offshore enterprise.
Petroleum Engineers and Geoscientists are trained to offer substantive expertise in engineering the development of subsurface natural resources and the management of their production for commercial use. These professionals, by their educational training and experience, have specialized knowledge of subsurface geology, drilling, well completion, subsurface reservoir characterization, reservoir management, and production operations. They are the most qualified to take on the tasks of locating, mapping, selecting, monitoring, testing, and managing such operations. These professionals have experienced the pains and rewards of past several price cycles of oil and gas. The dependence of their employment opportunity on the inherent volatility of oil and gas prices has created extended periods of employment and career uncertainty,
The Digital Transformation of the industry. Changing educational requirements for petroleum engineering and geoscience. Expanding career opportunities for petroleum engineers and geoscientists.
The Digital Transformation of the industry.
Changing educational requirements for petroleum engineering and geoscience.
Expanding career opportunities for petroleum engineers and geoscientists.
The transformation taking place in oil and gas operations by digital technologies is perhaps the clearest example of both new opportunities and new challenges being presented to petroleum engineers and geoscientists. The content knowledge, specific expertise, and experience are essential for the successful application of rapidly advancing digital technologies, while at the same time displacing many traditional technical functions. The ongoing energy transition will alter the mix of future energy sources, and changes in supply and demand will like to continue the era of price volatility; however, hydrocarbons will continue to be a primary source of supply for the world's fuel and power needs. Critical domain expertise will continue to be needed for developing, operating, and abandoning oil and gas resources for many decades to come. The transformation of the energy supply chain will also create new opportunities, such as the re-purposing of subsurface structures to make them suitable for the storage of energy products or for the safe disposal of waste. The expertise need will heavily rely on this brand of graduates.
This includes issues related to subsurface storage of natural gas, oil, and compressed air, hydrogen, and disposal of carbon dioxide and further focuses on the recovery of geothermal fluids as a non- hydrocarbon source of energy. Additionally, these subsurface specialists can help with managing the recovery of fresh subsurface waters for many communities. The future is also like to see the use of hydrocarbons as feedstocks for advanced industrial materials. In this study, we also discuss the role that the companies and government organizations can play to ensure attracting talent and maintaining the educational institutions essential for the professional development of subsurface experts who can address these important and evolving areas.
Goh, Kim Fah Gordon (Schlumberger Technology Corporation, Houston US) | Biniwale, Shripad (Schlumberger Abingdon Technology Center, UK) | Musayev, Rashid (Schlumberger Technology Corporation, Houston US) | Ahmed Elfeel, Mohamed (Schlumberger Abingdon Technology Center, UK)
Intelligent Completions (IC) are deployed with the high hopes of frequent data utilization and zonal selectivity maneuver to optimize production continuously. The permanent downhole presence of measurements like pressure, temperature, rate, water-cut, gas-break provide downhole indicators and trending analysis of production performance and injection conformance. These are utilized not only to maximize hydrocarbon production but also to reduce surface handling of water and/or gas, improve injection efficiency, and reduce carbon and environmental footprint. However, the reality could be different from the evaluation stage to the application stage. The asset production engineers or the reservoir engineers face real challenges when it comes to design, downhole installation, data transmission, real-time analysis, and optimization to deliver the real value of the initial investment. These suboptimal application factors, multiplied by the complexity of IC deployment and execution with existing hardware constraints, have limited the progression towards digital well technology. By analyzing such trends, a new advanced completion optimization methodology has been devised, leveraging the latest technology and innovation, IC deployment simplification, and electrification efforts in the industry.
This paper analyses the underutilization reasons of digital well technology, such as - the ability of design and implementation, the downhole data measurement, complexity of modeling and optimization, and the bottlenecks in applying the learning from the Intelligent Completions data to optimize production. It is then compared to the easing transition to the future digital-wells, advanced modeling capabilities that are driving the oilfield digitalization by next-generation Intelligent Completion. This digital transition ranges from ease-of-deployment to ease-of-optimization and eventually towards cloud-enabled decision making. The new era of IC electrification deployment and digital solutions are twinning to provide an integrated platform to maximize value and justification for more future digital wells.
A fully digital system to control reservoir and optimize the product is becoming a reality with the transformation of modeling capability and enabled by simplification of IC deployment, and this is the digital future of IC optimization. This digital solution is continuously feeding asset subsurface, modeling, and optimization team with productivity or injectivity indexes and other inputs required for reservoir steady-state and transient evaluation. The IC industry continues to be integrating into the new solution frontiers of logging-while-producing, the testing-while-producing capability to the eventual optimizing, modeling-while-producing future, leading towards a true digital oilfield of the future.
This work describes the use of integrated production modeling (IPM), along with digital platforms, as reliable tools to increase liquid yield, reduce operational expenditures ($/BOE) and maximize the project's net present value (NPV) in the Appalachian Basin. The results of the work, as applied to a real field show that the liquid yield for the gas condensate produced fluids can be increased by 3-5%; compression energy and process heating requirements can be reduced significantly.
The condensate to gas ratio (CGR) in Marshall County, West Virginia (WV) changes rapidly from southeast to northwest. For example, on a single pad (8-10 wells) the CGR of the northwestern wells is ~40% higher than the CGR of southeastern wells. Moreover, the CGR decreases with production time. A fixed-pressure, two-stage separation process is suboptimal for this area. Calibrated physics-based models leveraged to an integration platform can significantly improve the facilities performance.
The facilities set up is as follows: the gas produced from a well is fed to a line heater followed by a surface choke. The fluid then enters a gas processing unit (GPU) separator. The separated fluids from each well's GPU in the well pad are processed at common facilities consisting of separation and compression. The processed gas is exported to a sales gas line and the liquids are transported separately.
A fully integrated model has been built for eight wells on a pad. The reservoir and well models were history matched and then integrated with the surface network and facilities (compressor, heater) using network modeling and integration platforms. Various scenarios were run to identify the optimal pressure setting for a given month. The optimization exercise yielded 5-10% additional natural gas Liquids (NGLs) on a pad by increasing the GPU pressures by 100-200 psi. The higher GPU pressures reduced the well choke pressure drop, thereby reducing the heating requirements by 50% as the Joule-Thomson cooling across the choke was minimized. The reduced cooling also minimized flow assurance risks due to hydrate formation and reduced inhibitor injection costs. Finally, the compression energy requirement was reduced via better management of the pressure staging.
The developed integrated models, combined with digital platforms, offer novel and versatile capabilities for efficiently operating an asset to maximize liquids and reduce operational expenditure (OPEX). The deployment of a physical model-based digital oil field will facilitate the validation of these models on a continuous basis. This in turn will allow changes to be made in the field to keep the system optimized as the characteristics of the producing fluids change with time.