bluuebunny/crossref_metadata_2025 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
Distributed Microchip System Records Subsurface Temperature and Pressure
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 159583, ’A Distributed Microchip System for Subsurface Measurement,’ by Mengjiao Yu, Sufeng He, Yuanhang Chen, Nicholas Takach, SPE, and Peter LoPresti, The University of Tulsa; and Shaohua Zhou, SPE, and Nasser Al-Khanferi, SPE, Saudi Aramco, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed.

A microchip system capable of measuring temperature and pressure over the entire wellbore was developed and tested in the field. When used in the field, tracers will be injected together with the drilling fluid. As the tracer travels through the wellbore, it will measure the temperature and pressure throughout the wellbore and store the data in the on-chip memory.

Prototype

The prototype of the instrument system is shown in Fig. 1. The instrument sys-tem developed in this work includes two major components: the surface devices (Fig. 1) and the tracers (Fig. 2). A tracer (approximately 7.5 mm in diameter) consists of a small system-on-chip integrated circuit (SOC IC), which includes sensors, microcontroller, memory, transmitter and receiver circuits, and density-control material (hollow spheres), all encapsulated in a protective-chemical-coating shell. The surface devices include an initiator to reset the circuit on the tracer be-fore the tracer is injected into the wellbore, and a data collector to retrieve data from the tracer’s on-chip memory when the tracer is carried back to the surface by the drilling fluid. The initiator and data collector will use wireless communication to reset the circuit and down-load data from the tracer, respectively. A magnetic tracer separator (see Fig. 1) will be installed after the data collector to recycle the tracers. A lithium cell (battery) used in the tracer contains stainless steel, which can enhance the separation of tracers from the drilling fluid in the magnetic tracer separator.

When used in experiments or in the field, tracers will be injected together with the drilling fluid. Before a tracer is injected into the flowline, it passes through an initiator, which will reset the circuit for recording data. As the tracer travels through the wellbore, it will measure the temperature and pressure throughout the wellbore and store the data in the on-chip memory at a sampling rate set by the initiator. When the tracers are carried out of the borehole by the drilling fluid, they will pass through a data collector (controlled by a computer) through which the tracer will communicate with the surface devices to send the data stored in its on-chip memory.
Integrated-Technology Approach Enables Successful Prospect Evaluations in Malaysia
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164576, ’Integrated-Technology Approach To Explore Carbonate Reservoirs in Malaysia Enhances PMCD Potential and Enables Successful Prospect Evaluations,’ by M. Noreffendy Jayah, SPE, Intan Azian A. Aziz, SPE, Zulhilmi Drus, SPE, Thanavathy Patma Nesan, Wong Han Sze, SPE, Abdel Aziz Ali Hassan, and Pungut Luntar, Petronas, prepared for the 2013 IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, San Antonio, Texas, USA, 17-18 April. The paper has not been peer reviewed.

The central Luconia gas province located offshore Sarawak houses numerous carbonate reservoirs (Fig. 1). Some of these reservoirs are characterized by the presence of karsts and fractures, contributing to total mud losses. Implementing the variant of managed-pressure-drilling technology called pressurized mud-cap drilling (PMCD) allowed targeted total depths (TDs) to be reached on several wells. However, reaching TD alone is insufficient for conclusive evaluation. Integration of technology applications is paramount in increasing the success rate of data delivery.

Introduction

Well-known for highly varying formation properties even within small sections of reservoir, the recently discovered Malaysian carbonate formations present a risk of drilling-fluid losses. Conventionally, these wells were drilled with overbalanced mud and losses were cured with lost-circulation materials (LCMs) or cement plugs to enable restoration of overbalanced condition for future drilling. Drilling a multiple total-losses zone conventionally proved to be highly uneconomical and likely to jeopardize the safety of the operation. To mitigate this inefficiency and associated safety risks, the PMCD technique was implemented and made ready for all of the operator’s carbonate drilling operations. Since 2010, PMCD equipment and personnel have been mobilized for 11 wells, but have been used only in six wells.

Introduction to PMCD

PMCD is applied in the total-loss condition. Once sufficient loss rates are encountered, the annulus is displaced from overbalanced drill-weight mud to underbalanced light annular mud (LAM). The LAM is generally designed to be under-balanced to the formation pressure at the topmost fracture by approximately 100 psi. This enables gas migration into the wellbore to be monitored closely. After casing pressure has increased to a limit, LAM is injected into the annulus to bullhead the migrated gas back into the formation. Upon each injection, the casing pressure will be restored to the original 100 psi. Drilling operations are performed while injecting seawater continuously down the drillstring and intermittently injecting LAM down the annulus. Drilled cuttings will be carried by seawater and fed into the fractures. Planning for successful PMCD operations not only revolves around equipment and engineering, but also depends on well placement and architecture, well engineering, rig equipment, training, and logistics.
Technology Focus: Field Development Projects (October 2010)
Authors: Rebelo Mauricio P.
Published: February 2015

Technology Focus

World demand for oil has moved the industry to increase its exploration in deep and ultradeep water, resulting in several oil discoveries. Brazil, West Africa, and the Gulf of Mexico are places where significant reserves have been found in recent years and where several deepwater fields are now producing oil.

The recent disaster in the Gulf of Mexico and its environmental effects call everybody’s attention to the risks involved in offshore operation, particularly in deep water. This accident will move the industry to find new solutions to minimize the risks to continue exploring for and producing oil from deepwater fields.

Changes in regulation, new equipment requirements, and safety procedures will be implemented to make operations in deep water safer. We should also expect increased costs, but this will allow the industry to develop and produce in deep water with less environmental risk.

Several fields are producing oil from deep water. For this feature, I have selected papers presenting interesting and successful field-development projects. Akpo field producing light oil in Nigeria, Parque das Conchas producing heavy oil in Brazil, and Azurite in the Republic of Congo are good references. Azurite is also the first development project to use a floating drilling, production, storage, and offloading vessel.

Field Development Projects additional reading available at OnePetro: www.onepetro.org

OTC 20395 • “Thunder Horse and Atlantis: The Development and Operation of Twin Giants in the Deepwater Gulf of Mexico,” by Simon Todd, BP plc, et al.

SPE 126598 • “IA for the Goliat Offshore Oilfield Development: World’s Northernmost Offshore Oil Development?” by Erik Bjørnbom, Eni Norge A/S, et al.

SPE 127819 • “High-Rate Gas-Well Completions in Egypt’s Mediterranean Sea: Tao Field Development Strategy and Case Histories,” by Ashraf Mekawy, Nospco, et al.
Interview with 2012 SPE President Ganesh Thakur
Authors: Thakur Ganesh , Donnelly John
Published: February 2015

President's interview

Ganesh Thakur, vice president, global adviser, and fellow of Chevron Energy Technology Company, is the 2012 SPE president. He will take office during the 2011 SPE Annual Technical Conference and Exhibition in Denver.

Thakur is a recognized leader in reservoir engineering and simulation, secondary recovery, reservoir and well productivity improvement, heavy oil, horizontal well technology, and enhanced oil recovery. He is also known for his work in the emergence of reservoir management, particularly waterflooding, as a key interdisciplinary practice. Thakur has published and taught widely around the world. He has designed and operated reservoir management programs, mentored technical professionals, and served as an ambassador of technology to national oil companies and government ministries.

Thakur is an SPE Distinguished Member and has served as technical director of Reservoir Description and Dynamics on the Board of Directors. He is an SPE Distinguished Lecturer, past chairman of the SPE Reprint Series Committee, and served on the SPE Editorial Review and Forum Series committees. Thakur was also a short course instructor on integrated reservoir management and waterflood management. He received the SPE Reservoir Description and Dynamics award in 2005, Pennsylvania State University Outstanding Alumni Achievement award in 2006, and Orange County (California) Outstanding Engineer of the Year award in 1994.

Thakur earned a BS degree in petroleum engineering from the Indian School of Mines. He earned MS and PhD degrees in petroleum and natural gas engineering, and an MA degree in mathematics, all from Pennsylvania State University. He also earned an MBA degree from Houston Baptist University.

How did you get involved in SPE?

It was as a student member, in the late 1960s, when I was going to school in India at the Indian School of Mines (ISM). I became a student member, although I do not think the student chapter was even formalized yet by SPE.

I became more involved when I went to graduate school at Penn State. I have remained active in student member-ship, local sections, the Editorial Committee, Distinguished Lecturer Committee, Forums, Applied Technology Workshops, the program for the SPE Annual Technical Conference and Exhibition, and more.

I have been working since 1973, the first four years for BP/Amoco and SSI and 34 years for Chevron. I was with Gulf Oil when it was acquired by Chevron in the 1980s.

As an undergraduate, oil prices were low and people asked me, “Why are you studying petroleum engineering? You are a good student.” They got me scared and they thought oil and gas would run out in 30 to 40 years. They were wrong, and today we will still have 30, 40, 50 or more years of oil remaining, especially as we go from conventional oil and gas to unconventional oil and gas. The sky is the limit, and we may have a whole new era coming up.
Comments: Reader Comments
Authors: Donnelly John
Published: February 2015

Editor's column

Every year, JPT surveys the SPE membership to get feedback on how well it is doing and to get suggestions on what improvements could be made to make the publication more useful to its readers. Past reader surveys have led us to increase the number and breadth of the technical topics, include more company and industry news briefs, generate more staff-written articles, and add more case studies. We will likely make additional improvements based on the findings in this latest survey.

To the more than 3,000 members who responded, thank you for taking the time to offer your opinions and comments. It will help us publish a magazine that is more useful to you in your jobs and careers. Just over 45% of the respondents work in North America; 77% had more than 10 years of experience in the oil and gas industry; and 29% had been an SPE member for more than 25 years. Just under 42% of respondents were engineers, while 32% were executives or managers. About 60% of respondents work for operating companies and 22% work for service/manufacturing firms.

The most popular features in JPT are Technology Update, the summaries of the technical papers, and Technology Applications, underscoring reader interest in both emerging technology and practical applications of existing technology. This is similar to findings in previous surveys. The summaries of SPE technical papers in JPT have routinely ranked high in reader surveys. JPT’s 42-person Editorial Committee, which consists of volunteer members representing all facets of the upstream oil and gas industry, reviews thousands of technical papers each year, recommending the best of them for condensed publication in the magazine.

Of the technical topics covered in the magazine, the most popular are mature fields and well revitalization, unconventional resources, multilateral/extended reach, reservoir performance and monitoring, field development projects, and formation evaluation. Asked what technical topics they would like to see more coverage of, respondents favored more papers/articles on various drilling topics, shale gas technology, and economics.

Just under 90% of respondents find JPT to be useful to very useful to them in their jobs, and 77% find JPT to be better to significantly better than other magazines serving the upstream oil and gas industry. Three-quarters (76%) rate the content of JPT either very good or excellent, up from 71% last year.

The publication’s biggest strengths are considered to be its technical depth and quality, its connection to SPE, and its breadth of coverage. Suggestions for improvement included publishing full-length technical papers rather than summaries, offering more coverage of natural gas projects and issues, and providing more technical detail in articles.
Managing Big Data: Cloud Computing and Co-Location Centers
Authors: Beckwith Robin
Published: February 2015

The oil and gas industry is among the top sectors contributing to the proliferation of a phenomenon known as “big data.” A recent McKinsey Global Institute report defines big data as “datasets whose size is beyond the ability of typical database software tools to capture, store, manage, and analyze.” This translates into datasets on the order of terabytes and petabytes (Table 1) in size, with the assumption that “as technology advances over time, the size of datasets that qualify as big data will also increase.”

Dataset increase follows what is known as Moore’s Law, first described by Intel co-founder Gordon Moore in the 1960s, which states that the number of transistors that can be placed on an integrated circuit doubles approximately every two years. This has tended to mean that the amount of computing power that can be purchased for the same amount of money doubles about every two years.

Managing big data calls for capitalizing on economies of scale in order to achieve efficiencies that ensure ongoing data security and virtual 100% accessibility. This is where cloud computing enters the picture.

The term “cloud” conjures up the image of vast amorphous forms that have a metaphysical, even mystical, relation to solid, three-dimensional substance. However, this vagueness is misleading. In reality, all data and the entire internet must reside on servers that in turn are housed somewhere.

Among the largest members of the cloud community are familiar companies such as Amazon.com, Apple, Facebook, Google, Hewlett-Packard, IBM, Microsoft, Twitter, and Yahoo, whose services are used by all industries, including oil and gas. Signaling a trend that cuts across all industries, these companies have consolidated their information on huge arrays of servers—servers capable of increasingly high-speed processing—housed in gigantic data centers ranging in size from 50,000 sq ft to half a million or more sq ft. These nine companies among them own or lease 47 data centers, most in the US.
Brine Management: Produced Water and Frac Flowback Brine
Authors: Burnett David
Published: February 2015

R&D Grand Challenges - This is the third in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE Research and Development (R&D) Committee. The R&D challenges comprise broad upstream business needs: increasing recovery factors, in-situ molecular manipulation, carbon capture and sequestration, produced water management, higher resolution subsurface imaging of hydrocarbons, and the environment. The articles in this series examine each of these challenges in depth. 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).

White papers covering these challenges are available at www.spe.org/industry/globalchallenges and allow reader comments and open discussion of the topics. White papers are currently available on the subjects of in-situ molecular manipulation, increasing hydrocarbon recovery factors, and carbon capture and sequestration with additional papers to be added in coming months. The world is changing. The transformation from onshore infill drilling and occasional field extension operations to the rapid development of super major gas fields throughout the United States is being called the great gas shale revolution. This disruptive change is as significant as the advent of rotary drilling in the 19th century.

Three issues drive this revolution:

The world’s energy needs are increasing at an exponential rate and, led by the US and the European Union, there is a major thrust to move toward clean energy.

In the US, vast reserves of unconventional gas are technically recover-able within its own boundaries and that energy security is one of its benefits.

Most important, technology to access these resources is advancing at an increasing rate.

Today we are seeing major developments—not only the Barnett Shale, but also the Fayetteville, Haynesville, Eagle Ford, and Marcellus shales in North America. Together, these and other developing and prospective gas shale plays offer the US more than a 400-year supply of this abundant, clean-burning fuel.

So why is there a controversy over development of these resources? One issue stands out—the environmental footprint of unconventional gas development. Along with this new awareness of the availability of abundant energy, the environmental impact of energy production is a critical part of the equation.
Automating the Oilfield Asset - Artificial-Intelligence-Based Integrated-Production-Management Architecture
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144334, ’Automation of the Oilfield Asset Through an Artificial- Intelligence-Based Integrated-Production- Management Architecture,’ by Cesar Bravo, SPE, Halliburton, and Luigi Saputelli, SPE, Hess Corporation; Jose Aguilar Castro, Addison Rios, and Francklin Rivas, Universidad de los Andes; and Joseph Aguilar- Martin, CTAE - Aerospace Research and Technology Center, prepared for the 2011 SPE Digital Energy Conference and Exhibition, The Woodlands, Texas, 19-21 April. The paper has not been peer reviewed.

Integrated asset management is highly complex and requires the combined effort of several disciplines and technological tools. Orchestration of disciplines, workflow tools, and available data are important issues. Resource negotiation, communication language, and decision-making protocols are minor issues that exacerbate the problem, resulting in poor and delayed decision making. This study approached these challenges through implementation of distributed-artificial-intelligence-based architecture designed for automated production management.

Introduction

As systems technology improves, oil-production-automation systems have become complex, and management of oil-production assets requires new methods of work and new technological tools that allow collaborative efforts between all those involved in the production process to support accurate and timely decision making. This collaboration has several names in literature. For this study, the phrase integrated production management (IPM) was used.

Many studies about IPM address enterprise-information-system integration as obtaining all information related to the production process to achieve the entire vision of the asset’s state. Several oil-production companies are developing projects oriented to IPM. IPM requires defining data models that enable information interchange between various applications of the enterprise. There are several ontological frameworks applied to the information interchange between production applications. This study proposed a complete approach over the technological tools required to support IPM and is based on the definition of an IPM architecture (IPMA).

Proposed IPMA

This architecture consists of the technological tools required for the acquisition, treatment, and analysis of the process information. The IPMA also considers business-process automation and decision-making support. The architecture has three layers, as shown in Fig. 1.
Designing Multistage Frac Packs in a Lower Tertiary Formation - Cascade and Chinook Fields
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140498, ’Challenges of Designing Multistage Frac Packs in the Lower Tertiary Formation - Cascade and Chinook Fields,’ by Ziad Haddad, SPE, FOI Technologies; Mike Smith, SPE, NSI Technologies; and Flavio Dias De Moraes, SPE, Petrobras, prepared for the 2011 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 24-26 January. The paper has not been peer reviewed.

Offshore frac-pack operational limitations include service-tool erosion, overall fracture-treatment-vessel capacity, boat-to-boat fluid transfers, and crew fatigue. Geological complexities were another major challenge in completing this very thick interval. Perforation intervals had to be placed in a manner to avoid a fault (and thus a potential early screenout), to avoid a water contact, and to comply with tool-spacing limitations, while maximizing contact with net pay. A specific approach was developed to design the fracture-stimulations for a Lower Tertiary formation in the Cascade and Chinook fields. 

Introduction

The Cascade and Chinook fields are 250 miles south of New Orleans in the Gulf of Mexico (GOM) in ultradeep-water depths between 8,200 and 8,900 ft. The oil-producing reservoir is in the Lower Tertiary Wilcox formation, with a gross sand thickness of 1,200 ft. The reservoir midpoint is at an average depth of 25,600 ft true vertical depth (TVD) with a bottomhole pressure of 19,500 psi and a bottomhole temperature of 260°F. The reservoir comprises vertically stacked thin beds of sand and fine-grained-siltstone intervals with no effective vertical permeability.  

It was recognized early on that dealing with the Lower Tertiary formation required a change in focus from a soft-rock frac-pack completion to a hard-rock hydraulic-fracturing completion, similar to those used in the Wilcox formation in south Texas. The secondary objective was to design a sand-control completion to retain the proppant pack and eliminate proppant flowback in screenless hard-rock fracturing completions.

To outline a basis of design for future Cascade and Chinook hydraulic-fracturing treatments, the initial planning phase was to develop a complete and comprehensive set of fracture-treatment-design data to be used in developing the preliminary treatment designs and evaluating the material-selection options, and to identify key questions for future wellsite data collection and execution. The full-length paper details this outline.

Design Challenges

The first well completed in the Cascade field was completed with three propped-fracture treatments in the upper and lower Wilcox zones. The challenge was to complete this very thick interval while avoiding fracturing the oil/water contact and avoiding placing perforations too near the fault at 25,832 ft measured depth (MD).