bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Reservoir Performance and Modeling (September 2011)
Authors: Vikane Erik 
Published: February 2015

Technology Focus
The Future Is Already Here, Today!
What are the future trends in reservoir management and monitoring, and how will new technology and new ways of communicating change the way we manage our reservoirs? Over the past couple of decades, we have seen significant progress in surveillance, data gathering, and computing capabilities. What are the biggest challenges and opportunities going forward? As the light-oil component of global production decreases, increasing the emphasis on heavy-oil, oil-sand, and natural-gas production will pose new challenges. The number of sensors is increasing, the amount of data is increasing, real-time data are common, and automated analysis is becoming commonplace. How do reservoir-management practices change to accommodate this trend? As technology advances and as nanotechnology enters the stage, our ability to translate data into information and our ability to make decisions on the basis of this information may improve. How will automation and closed-loop reservoir management influence our risk-handling and management decisions? These were among the questions discussed at the SPE Reservoir Surveillance and Data Acquisition 2020 Forum in Santa Fe, New Mexico, May 2011.
Automated adjustment of chokes and automated choking of zones are possible today. To use this automation fully, we need to trust the data flow, the analysis of the information, and that the correct action is implemented. Safety concerns are another key aspect to consider. Regardless of the challenges, automation is an emerging trend. Spatial gathering of data also is getting increasingly more focused. This gathering could be crosswell information, data along the well path, or a collection of time-lapse (4D) or electromagnetic data. Integration of different information and data is key to future success. Geological and reservoir models still are the most common way of integration, but generation of data-driven models honoring the physics is one of the new trends. Integration is mostly about the integration of people, making all data available to everybody at the same time and in a format that can be understood by everyone. The selected papers are excellent examples of emerging trends and represent the shape of things to come in reservoir management and performance monitoring.
Reservoir Performance and Monitoring additional reading available at OnePetro: www.onepetro.org
SPE 131370 • “Using Downhole-Temperature Measurements To Assist Reservoir Characterization and Optimization” by Zhuoyi Li, SPE, Texas A&M University, et al.
SPE 134313 • “Large-Scale Laboratory Testing of Petroleum-Reservoir Processes” by David P. Yale, ExxonMobil, et al.
SPE 136378 • “Selection of Decision Variables for Large-Scale Production-Optimization Problems Applied to Brugge Field” by Masoud Asadollahi, IRIS/NTNU, et al.
SPE 137750 • “Unconventional Imaging for Unconventional Reservoirs” by C.J. Leskiw, University of Calgary, et al.
Technology Focus: Drilling Management (September 2011)
Authors: Cunha J.C. 
Published: February 2015

Technology Focus
Drilling management—management of the drilling process or the process of managing well-drilling operations. Much of this activity is not easily perceived by the outside viewer. Even though the final result of an operation is easily observed, what almost always goes unnoticed is the complexity of the issues involved in the planning and execution of a drilling operation and the number of topics involved in such a process.
In recent years, I have been involved in several challenging deepwater-drilling operations, either as an operator or as a nonoperating partner. In all those cases, the planning phase required at least 1 year between the decision to drill on a certain location and the actual well spud-in. And that time frame was for well-established companies with most, or all, service and equipment contracts in place and all key personnel already hired. Off course, the time frame may double, or triple, if a company is initiating an operation in a new region or country where it never operated before.
Well planning alone will require (as it must) several months. And this is done before you can even begin to apply for the necessary drilling permit, which in its turn may take several months to be obtained. Also, there is the need for internal reviews, budget approval (internally and with partners), and a necessary peer review, which will result in the need for additional time for implementation of associated recommended changes in the well program. Equally important is a well-prepared risk-analysis study in which risky aspects of the operation will be identified so that preventive measures can be taken to avoid or manage those risks.
And then comes the most-visible part of the entire process, the drilling operation itself. Certainly, there must be good management during this phase, which includes the ability to make the necessary changes while dealing with the many aspects of the operation that may not develop exactly as initially planned. And most important, all this must be carried out within responsible and very-strict safety and environmental standards. Ideally, we want an operation to be concluded successfully without surprises or unexpected setbacks, or at least to keep those at a minimum. Careful planning certainly can help to achieve this task. As the famous Norwegian explorer Roald Amundsen once said, “Adventure is just bad planning.”
Drilling Management additional reading available at OnePetro: www.onepetro.org
SPE 140023 • “Integrated Prewell-Planning Process Improves Service Quality and Decreases Risk Through Cooperation Between Drilling and Geosciences” by J.M. Aldawood, Baker Hughes, et al.
SPE 139995 • “Can Safety Improvement Increase Drilling Efficiency?” by S.M. Boutalbi, SPE, Weatherford, et al.
SPE 136296 • “Real-Time Data Management and Information Transfer as an Effective Drilling Technique” by Steve Vogel, SPE, National Oilwell Varco, et al.
SPE 140145 • “Well-Construction Hydraulics in Challenging Environments” by A.L. Martins, Petrobras, et al.
R&D Grand Challenges - Reviewing the Five R&D Grand Challenges Plus One
Authors: Judzis Arnis , Poddar Anoop 
Published: February 2015

R&D Grand Challenges - This is the last in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE R&D Committee. The R&D Grand Challenges Series, comprising articles published in JPT during 2011 and 2012. The R&D Grand Challenges Series, comprising articles published in JPT during 2011 and 2012, is available as a collection on OnePetro (SPE-163061-JPT).
In May 2011, the SPE R&D Committee kicked off a series of guest articles in JPT to highlight the oil and gas industry’s major research and development (R&D) challenges. Defining these challenges is important because the committee’s primary goal is to encourage R&D and promote dialog between industry and research groups with the aim of matching industry needs with R&D activities.
The R&D challenges comprise five broad upstream business needs plus the environment:
Increasing recovery factors
In-situ molecular manipulation
Carbon capture and sequestration
Produced water management
Higher resolution subsurface imaging of hydrocarbons
Environment
Why Have Grand Challenges?
Exploiting hydrocarbons from the deep reaches of Earth has been no easy task. The scale of innovation required rivals those in any other high technology industry. As an industry, we have done well in finding and producing sufficient hydrocarbons to satisfy the world’s energy needs to date; however, the task becomes harder in the future as the resource base becomes more difficult to extract and our desire to minimize environmental impact strengthens.
Increasing Recovery Factors
Gary A. Pope, Texaco Centennial Chair in Petroleum Engineering at The University of Texas at Austin, kicked off the series of “R&D Grand Challenges” articles with his view on recent developments and remaining challenges of enhanced oil recovery.
He wrote, “There has been a renaissance in chemical EOR during the past few years because of major advances in the technology and high oil prices. Thermal and miscible gas methods are much more mature with the exception of processes such as coinjection of gases and surfactants for mobility control. The synergy between the EOR processes and improved reservoir characterization and formation evaluation, reservoir modeling and simulation, reservoir management, well technology, production methods, and facilities is significant and not as widely recognized as it should be.
“So what are the most significant constraints on any kind of EOR? My guess is the following in order of importance: a shortage of experienced engineers and geoscientists with a fundamental understanding of EOR, uncertainty in oil prices, and risk aversion due in part to out-of-date knowledge and in part to the complexity of EOR compared with more conventional oil recovery. There are also environmental concerns that must be addressed for each process and location. For these and other reasons, it may take many years to ramp up EOR production to millions of barrels per day.
Intelligent-Well-Monitoring Systems: Review and Comparison
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150195, ’Review, Analysis, and Comparison of Intelligent-Well- Monitoring Systems,’ by M.F. Silva Junior, Petrobras, and K.M. Muradov, SPE, and D.R. Davies, SPE, Heriot-Watt University, prepared for the 2012 SPE Intelligent Energy International, Utrecht, The Netherlands, 27-29 March. The paper has not been peer reviewed.
Despite the maturity of intelligent-well (IW) equipment, the concept of an integrated IW as a key element in the “digital oil field” is still not developed fully. Current practice is to evaluate the IW value chain in a fit-for-purpose manner rather than by an integrated-modeling workflow. An increasing variety of real-time downhole monitoring and measurement systems is available for deployment or is in development. A well-founded understanding of data that are actually needed, the most suitable sensor types and interfaces, and availability of data-reconciliation and -validation methodology are key factors for the success of an integrated IW project.
Introduction
A subsea integrated production frame-work treats the reservoir, wells, flowlines, risers, and topside facilities as a single system. IWs can provide reservoir control by use of continuous monitoring and valve actuation in real-time. Integrated modeling and optimization, in this context, aims to capture the physics of the complex interactions across the processes for true operations support. Actual data are fed into the optimizer after data analysis and assimilation for model calibration and uncertainty minimization.
The complete paper details how established concepts from control engineering and metrology can be used for reservoir management. Research and development efforts in permanent well monitoring are divided into two classes: deep-reservoir and near-wellbore. Additional value can be derived from these technologies because they also can identify and classify failures in downhole equipment.
Deep-reservoir sensing is related to 4D seismic, dynamic 3D resistivity, and streaming potential (electrokinetic) monitoring techniques that capture the dynamics of the entire reservoir. Near-wellbore sensing includes classical downhole measurements, such as pressure and temperature. Also, monitoring systems have become a distributed sensing network instead of an autonomous system, which requires an understanding of all errors and limitations in the signal path aside from the sensor itself.
IW-Monitoring Systems
The physical quantities measured by equipment from different manufacturers of sensors for downhole, near- wellbore permanent monitoring of an IW are very similar: pressure, temperature, flow, acceleration (seismic and acoustic), and strain. The differences between them and their limitations are related mostly to the equipment and its installation requirements. The measurement of new physical quantities for deep-reservoir monitoring, such as seismic, electromagnetics, and streaming potential, is in the early stages of development.
Interview with 2014 SPE President Jeff Spath
Authors: Spath Jeff , Donnelly John 
Published: February 2015

2014 SPE President Jeff Spath
Jeff Spath is a member of the Schlumberger executive management team as vice president of industry affairs and is the 2014 SPE President. He will take office during the 2013 SPE Annual Technical Conference and Exhibition, to be held 30 September–2 October in New Orleans.
Previously, he was president of the Schlumberger Reservoir Management Group and was president of Data and Consulting Services. He began his career with Flopetrol-Johnston Schlumberger as a field engineer conducting well tests onshore and offshore Louisiana and has worked for 30 years in various global positions in reservoir engineering, research, and management.
Spath is a recognized leader in the development and application of reservoir engineering and production enhancement techniques, including well testing, reservoir simulation, and nodal analysis. He is the author or coauthor of nearly 30 peer-reviewed publications and holds 14 patents.
An SPE member since 1983, Spath has served on many SPE committees and in many sections around the world. He was a Distinguished Lecturer during 1999–2000 and served as Technical Director of Management and Information during 2005–2008. He was elected an SPE Distinguished Member in 2011. Spath also currently serves on the Management Committee of the International Association of Oil & Gas Producers; the petroleum engineering advisory boards at Texas A&M University, the Colorado School of Mines, and the Natural Petroleum Council; and on the United Nations Global Energy Board.
Spath earned BS and MS degrees in petroleum engineering from Texas A&M University and a PhD degree in reservoir engineering from the Mining University of Leoben in Austria.

What are your goals as SPE president?
One goal would be to further globalize the Society. There is no doubt that SPE has made huge strides internationally from what was once a predominantly North American member society in the 1970s and 1980s. Today, more than half of our members reside outside North America. We have to continue to follow the upstream oil and gas business to the new frontiers, the new basins, and the new regions of exploration such as Greenland, east Africa, and the Caspian. Not just for the sake of member growth, but to make SPE more local and more relevant by adding professional sections and student chapters so critical to achieving success—both for industry and for individuals—in these new regions.
Secondly, we need to increase the degree to which SPE engages and collaborates with other organizations. We all accept that reservoirs are becoming more challenging to dis-cover and produce. They are smaller, more complex, and they exist in increasingly hostile terrains under more difficult temperatures and pressures. Not to mention the challenges created by nanoperm shales and ultraheavy oil.
Drilling in Extreme Environments: Space Drilling and the Oil and Gas Industry
Authors: Beckwith Robin 
Published: February 2015

Drilling in Space
The oil and gas industry is today drilling in environments that 50 years ago were viewed as extreme. Drilling fluids and equipment—including pipe, bits, motors, batteries, collars, MWD/LWD tools—as well as jars, fishing tools, wireline tools, cement, and hydraulic fracturing fluids, routinely tackle bottomhole temperatures up to 180°C, pressures of 10,000 to 15,000 psi and more, depths greater than 25,000 ft, and matrix permeabilities in the range of 100 nanodarcies. The oil and gas drilling environment remains inherently extreme, with dangers attached to managing flammable liquids and volatile gases under high pressure. However, huge leaps in knowledge, experience, science, and technology have increased safety through procedures and automation, increased certainty through modeling and real-time sensing, and increased reliability through research and development leading to sophisticated testing and ruggedized materials.
But while many fields today are drilled, re-drilled, or stimulated within the industry’s conquered range, the frontiers keep expanding. However, there are other environments—including space, geothermal, and deep Earth scientific drilling—whose frontiers have always been more extreme. Humankind’s desire to push physical limitations has led it to delve more deeply into outer space and within our planet. Drilling in these extreme environments is helping drive advances in the oil and gas industry and/or presents analogs that can be mined for insight. One such type of drilling is extraterrestrial drilling.
Designing Curiosity’s Actuator Electronics
According to the technical article, “Engineering Systems for Extreme Environments,” by Guy V. Clatterbaugh, Bruce R. Trethewey Jr., Jack C. Roberts, Sharon X. Ling, and Mohammad M. Dehghani, most of whom are members of The Johns Hopkins University Applied Physics Laboratory (APL), “Extreme environments in general can typically be categorized as involving abnormally high or excessive exposure to cold, heat, pressure, vacuum, voltage, corrosive chemicals, particle and electromagnetic radiation, vibration, shock, moisture, contamination, or dust, or extreme fluctuations in operating temperature range.” The authors point out that “These situations are made more extreme when, upon deployment, the system is no longer available for maintenance or repair.”
Technology Focus: Reservoir Performance and Monitoring (September 2013)
Authors: Vikane Erik 
Published: February 2015

Technology Focus
“All models are wrong, but some are useful.”
This famous quote by George E.P. Box illustrates both the challenge and the appreciation of building models. Models are needed to predict future performance of an oil or gas field, but, at the same time, models are often biased and inaccurate.
Most investment decisions rely on our ability to predict and to plan the future, and, in that regard, nothing is more important than accurately modeling future well performance. Consequently, three of the four chosen papers address different aspects of this topic.
The first paper deals with ways to improve the accuracy of our predictions. It offers readers a rigorous checklist of questions to ask when developing reservoir models to guide them toward less-biased forecasts.
The second paper deals with how we develop reservoir-prediction tools for asset management. Active reservoir management addresses the almost impossible task of maximizing short-term production while optimizing ultimate recovery. However, to evaluate the different reservoir-drainage mechanisms, one needs good models, and the more advanced the drainage mechanism is, the more crucial the model is. As an illustration, it is much easier to model a pressure-depletion scheme than to try to predict a secondary- or tertiary-recovery process. Assessing and quantifying uncertainties as part of the modeling are becoming increasingly common, and this practice improves the ability to develop a sound decision basis.
The development of unconventional shale resources has further challenged the ability to predict performance. Prediction of such unconventional resources does not necessarily require new tools but rather new assumptions and new experience-based calibration methods. More than 40% of the papers I reviewed for this issue dealt with prediction of production and ultimate recovery of shale gas, which clearly illustrates the increasing interest in this topic and the current challenges faced by today’s petroleum engineers. The lack of history and of good analogs further adds to the uncertainty. I am sure that more research and the availability of more production data will enable us to develop better models and, hence, increase the accuracy of our predictions. The third paper provides great insight into our understanding of unconventionals.
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 23949 In-Well Distributed Fiber-Optic Solutions for Reservoir Surveillance by Juun van der Horst, Shell, et al.
IPTC 16866 Uncertainty Assessment of Production Performance for Shale-Gas Reservoirs by Jiang Xie, Chevron, et al.
IPTC 16505 Joint Inversion of Time-Lapse Crosswell Seismic and Production Data for Reservoir Monitoring and Characterization by Lin Liang, Schlumberger, et al.
New Time/Rate Relations for Decline-Curve Analysis of Unconventional Reservoirs
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 162910, ’Practical Considerations for Decline-Curve Analysis in Unconventional Reservoirs - Application of Recently Developed Time/Rate Relations,’ by V. Okouma, SPE, Shell Canada Energy; D. Symmons, Consultant; N. Hosseinpour-Zonoozi, SPE, and D. Ilk, SPE, DeGolyer and MacNaughton; and T.A. Blasingame, SPE, Texas A&M University, prepared for the 2012 SPE Hydrocarbon Economics and Evaluation Symposium, Calgary, 24-25 September. The paper has not been peer reviewed.
This work presents a workflow that can be used to analyze and forecast time/rate data of wells in low- and ultralow-permeability reservoirs. The key component of the workflow is the application of diagnostic plots to guide the analysis and obtain model parameters for a given time/rate relation. Once model parameters are obtained, the production profile is extrapolated to yield the estimated ultimate recovery (EUR) at a specified time limit or abandonment rate.
Introduction
The starting point for any discussion of decline-curve analysis for unconventional reservoirs must be an understanding that no simplified time/rate model can accurately capture all elements of the performance behavior. In addition, no time/rate model can be expected to pro-vide a completely unique forecast of future performance or prediction of EUR. It is important to be both realistic and practical when attempting to characterize production performance from systems where the permeability is on the order of 10–500 nd, the reservoir flow system is complex, and, although the induced-hydraulic-fracture system enables (and dominates) the production performance, there is only the most rudimentary understanding of the flow structure in the fracture systems.
It is essential that these conditions be established as a starting point. Not doing so will inevitably lead the analyst to interpretations based on incorrect assumptions as well as significant bias. The authors assert that reasonable production forecasts and predictions of EUR can be made, but not in isolation, not solely looking at the data and the selected time/rate model. The analyst must consider the nature of the resource and the significant uncertainty in the ability to apply simple time/rate relations to a very complex reservoir system.
As an attempt to better represent the general character of time/rate production data for a multistage-fractured horizontal well in an ultralow-permeability reservoir, numerous authors have developed time/rate relations using certain specific bases to represent a particular scenario. These developments include the following time/rate relations:
Power-law exponential model
Stretched exponential model
Logistic growth model
Duong model