bluuebunny/crossref_metadata_2025_split huggingface dataset:
Digital Oil Field 2.0: Maturity and Paradigms
Authors: Holland Dutch 
Published: February 2015

Management
Globally, the digital oil field (DOF) in its relatively brief lifespan has strikingly transformed how the oil and gas industry works. What may not be quite so obvious, however, is that the curtain is coming down on DOF's "overnight" introduction of dazzling new technology and the simultaneous integration challenge. From 3D visualization to revolutionary sensors it has been quite a ride.
In a new industrywide phase coined "DOF 2.0" by Bart Stafford of Science Applications International Corporation, a Fortune 500 scientific, engineering, and technology applications company, the science-fiction DOF concept is maturing. Instead of primarily showcasing ever-newer technological "bells and whistles," now management can actually plan and execute the entire DOF solutions life cycle. With much at stake as to increasing production and maximizing recoverable reserves, it is worth examining this new direction, including the obstacles to its maturity.

Maturity for DOF
Companies reach the watershed point of DOF maturity through a process of "getting all the juice possible out of the orange." Although flashy technology will still emerge from R&D, companies’ DOF initiatives have fulfilled their organic growth and achieved some kind of finality, continuing at a generally even growth rate. In other words, for years DOF innovations have spewed out of R&D with minimal attention directed toward managing the new technology. The next wave will not be marked by exotic development but rather about how to manage solutions into operations.
Keys to effectively making the transition into DOF 2.0 are the sevenfold Dimensions of Maturity. First, and particularly noteworthy in discussing maturation, is the codifying aspect. DOF 2.0 usage and the accompanying transformation of daily operations are now getting written down as a legitimate part of a company's business strategy. This contrasts sharply with the previous corporate thinking that DOF cannot be considered as a strong enough business factor to be formalized into how business is planned and conducted. Therefore, more executive key performance indicators (KPIs) and compensation structures now include specifically using DOF as a means to increase production and maximize recoverable reserves. The three key DOF roles are (1) senior management, (2) asset management, and (3) DOF technologies (i.e., R&D or information technology [IT]). Each of these roles now has more specific KPIs that directly relate to the use of DOF. For example, asset managers must be responsible for two KPIs: "reliable production" as well as the "incorporation of new DOF technology," and R&D must be responsible for two KPIs: both "DOF innovation" and "full implementation" of DOF innovations (Fig. 1).
Technology Focus: Bit Technology and Bottomhole Assemblies (December 2009)
Authors: Mensa-Wilmot Graham 
Published: February 2015

Performance Drilling—Moving Beyond the Basics
The industry's continuous push into harsher and more-challenging drilling environments, in terms of formation types, depths, and well profiles, presents several performance challenges. Performance drilling is accepted widely as one of the enablers that will help reverse the high-cost implications of this trend. Consequently, the drive to understand the basics, as it relates to this realization, has preoccupied the industry for some time now.
This effort, which has focused primarily on elements such as rock mechanics and failure mechanisms, bottomhole-assembly (BHA) design, drilling mechanics and hydraulics, and the operational environment, has proved highly beneficial. Extensive amounts of data have been collected as a result of this focus. Additionally, several performance-enhancing tools and processes have been developed.
Having deepened our understanding of the basics, we now must question data to reveal how and why events occur—successes as well as failures. Through this process, we must identify trends, behaviors, and relationships. These observations must be explained because we have the basics. We cannot expect to improve, and effectively confront our looming challenges, when we merely recycle the basics. Performance-improvement objectives will be met only if we turn data into action-able information.
There are tools to help design and understand BHA performance. In addition, there is agreement on the different vibration modes. Field data clearly establish the need for different bit technologies and for different drive mechanisms [e.g., positive-displacement motor, rotary-steerable-system (RSS) "push the bit," or RSS "point the bit"]. Contrary to what computer programs and models sometimes tell us, reality must always be considered as an option. We have the data and the understanding—now we need to move beyond the basics.
Bit Technology and Bottomhole Assemblies additional reading available at OnePetro: www.onepetro.org
IPTC 11945 • "State-of-the-Art BHA Program Produces Unprecedented Results" by David C-K Chen, SPE, Halliburton, et al.
SPE 119375 • "Roller Reamers Improve Drilling Performance in Wells Limited by Bit and Bottomhole-Assembly Vibrations" by Steven F. Sowers, SPE, ExxonMobil, et al.
SPE 119302 • "Experimental Study of MSE of a Single PDC Cutter Under Simulated Pressurized Conditions" by Navid Rafatian, SPE, Schlumberger, et al.
MWD Vibration Measurements: A Time for Standardization
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119877, "MWD Vibration Measure ments: A Time for Standardisation," by Svein Magne Osnes, SPE, StatoilHydro ASA; Per Amund Amundsen, SPE, University of Stavanger; and Tore Weltzin, SPE, Erik Nyrnes, SPE, Brita Lucie Hundstad, SPE, and Gaute Grindhaug, SPE, StatoilHydro ASA, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed.
Since downhole vibration measurements were introduced in the early 1990s, these measurements have become extremely useful for improving drilling efficiency. Most operators will specify a vibration sensor of some sort to be run with most measurement-while-drilling (MWD) and logging-while-drilling (LWD) applications. Unlike most other downhole measurements, there is no industrial standard for how to sample, process, and present the vibration data. This raises a few issues that the full-length paper attempts to address.

Introduction
The lack of standardization of vibration measurements and vibration-data methodology recently has become apparent from several different points of view:Vibration readings cannot be correlated easily and compared from well to well, making it difficult to learn from experiences with different drill bits and drilling tools.It is difficult to use a fair and consistent policy to handle charges from service companies for tools that allegedly have been damaged or scrapped as a result of severe vibrations.Tool specifications from different service companies cannot be compared easily during tender evaluations.It is difficult to perform any form of quality control of contractor's vibration data, including calibration of vibration sensors.It is difficult for drilling engineers or drilling-contractor personnel to develop any universal skills in real-time drilling optimization on the basis of vibration data because the data are not comparable.
Unlike vibration measurements, most other MWD and LWD data have been subjected to strict standardization.
Similar standards exist for other formation measurements such as neutron porosity logging, density logging, and sonic logging, but no industry procedure or standards exist for the calibration, measurement range, or measurement principle of downhole vibration tools.

Background
During drilling, bottomhole equipment is subject to severe accelerations in the form of single or repetitive shocks and as sustained vibrations of the drillstring, both in the drilling direction and transverse to it. Such accelerations can interfere with the drilling operation and can cause equipment failures and destruction of downhole tools, which again has an undesirable effect on the operational costs as a result of time lost for tripping and charges for damaged equipment.
Technology Focus: Reserves/Asset Management (December 2009)
Authors: Hinkle Delores 
Published: February 2015

Technology Focus
While selecting the papers for this feature, I noticed two things. First, the topic is wide and varied. It includes everything from simulation models for new-field development to case histories of mature operations. In between, there were discussions of numerous types of sophisticated assessment tools presented for consideration and there was a consistent theme of the need for optimization. My second observation was that this group of papers provided fascinating reading and offers a wealth of diversified knowledge from a representative cross section of our industry. I never cease to be impressed by the intelligence and innovation of the members of our global oil and gas industry. I am honored to be part of a group with such capable and committed individuals.
I also noticed the difference between the two components of this feature. Reserves have been a dynamic component of our industry over the last few years, with the adoption of the SPE/World Petroleum Council/American Association of Petroleum Geologists/Society of Petroleum Evaluation Engineers Petroleum Resources Management System (SPE-PRMS) in 2007 and changes to reporting regulations in Canada, the USA, and other countries. In many cases, these new systems and regulations have resulted in step changes in the way reserves and resources are categorized and reported. Asset management, on the other hand, has exhibited a more continual growth toward identifying and capturing more-sophisticated processes and more-complex procedures in search of maximizing recovery while minimizing costs.
Because of the recent changes, the papers selected this year focus on reserves categorization and reporting, while the papers recommended for additional reading focus more heavily on asset management. As the industry becomes more familiar with SPE-PRMS and the new regulatory requirements, it is likely that future editions of the Reserves/Asset Management feature will focus more heavily on the asset-management component of our industry.
Reserves/Asset Management additional reading available at OnePetro: www.onepetro.org
SPE 123931 • "Managing a Giant—50 Years of Groningen Gas" by Niels Dijksman, Royal Dutch Shell, et al.
OTC 20125 • "I-Field Implementation Enables Real-Time Reservoir Management of Newly Developed Saudi Fields" by Said S. Al-Malki, SPE, Saudi Aramco, et al.
SPE 121426 • "Real-Options Analysis in Petroleum Exploration and Production: A New Paradigm in Investment Analysis" by B. Jafarizadeh, SPE, University of Stavanger, et al.
Multistage Plunger-Lift Systems Can Provide Economical Alternative to Pumping Units
Authors: Wienen Julie 
Published: February 2015

Technology Update
Plunger lift is a simple and economical artificial-lift (AL) system for wells that primarily produce gas. It is a widespread method of deliquefying wells with high gas-to-liquid ratios (GLRs), for lifting production from wells in which natural depletion has reduced flow rates below critical levels, or for producing from wells with high accumulations of solids, such as sand, salt, coal fines, paraffin, and scale.
However, for some wells, plunger lift by itself may not add enough energy to the wellbore to produce gas in economic volumes. Deep gas and low-GLR wells, with ratios 1:1, may have lift requirements exceeding the capabilities of conventional plunger AL systems. Gassy oil wells often fall into the latter category. Frequently, pump jacks are installed on wells where conventional plunger lift is considered inadequate. Foaming methods to reduce the density of flowstream liquids may also be employed, but these are typically most effective in wells producing primarily water. A more effective strategy for increasing production from gassy oil wells and other wells where conventional plunger lift may be insufficient can be to install a multistage plunger-lift system.
In these systems, a downhole tool is used to create multiple plunger-lift systems in one well. This multistage tool allows the liquid load to be lifted in sequences, a process that uses the well’s own energy to remove even large accumulations of liquids, or heavy liquids, efficiently.
Multistage Plunger-Lift Tool
The multistage tool (Fig. 1) is placed by wireline roughly 40–70% of the way down the tubing above an installed plunger-lift system, typically composed of a bottomhole bumper spring and a plunger above it. Then a second plunger is set on top of the tool.
The system is operated like a conventional plunger-lift system. During the first sales cycle, the lower plunger carries fluids up the tubing and delivers them to the tool. They flow through the tool and are held above it by gas flow. Upon shut-in, the ball check in the tool engages, retaining the fluids until the upper plunger falls from the surface, settles through the liquids and lands at the tool. Simultaneously, the lower plunger falls back to the bottom.
During the next sales cycle, the upper plunger delivers its fluids to the surface, while the lower plunger delivers more fluids to the tool. Both plungers work in tandem in subsequent cycles. In this way, the multistage tool acts like an intermediary standing valve. This process lifts smaller and more frequent liquid loads in stages, allowing the well to more efficiently use its own energy to remove liquids and increase productivity.
The “nodding donkeys” visible at many wellsites demonstrate the popularity of using pump jacks as an AL method. Pump jacks (also known as sucker-rod pumps or beam-pumping units) are typically powered by fossil fuels or an electric motor. They require a significant upfront investment in equipment and installation, and maintenance costs can be considerable.
Beyond Macondo: SPE's Continuing Role in Offshore Drilling Operations
Authors: Beckwith Robin 
Published: February 2015

Post-Macondo response
SPE has responded to the Macondo disaster by forming a task force whose ongoing mission is to examine how the Society can best use its resources to tackle the myriad issues that are arising in the disaster’s wake. In addition, the Society developed guidelines to aid in complying with a new Bureau of Ocean Energy Management (formerly the US Minerals Management Service) requirement that companies requesting permits to drill offshore in the US estimate worst-case discharge.
Within a few weeks of the 20 April disaster, SPE 2010 President Behrooz Fattahi appointed a task force (see sidebar), drawn from the SPE Board of Directors, to clarify the Society’s role in addressing technical issues related to the blowout. After meeting several times, the Gulf of Mexico (GOM) Incident Response Task Force drew up a report, which member Paul Jones, global technology center manager at Chevron, presented at the SPE Annual Technical Conference & Exhibition to the board of directors and to SPE’s Industry Advisory Council (a 14-member body representing top management at major and independent oil and gas operators and service companies worldwide).
The report spelled out several efforts being conducted by industry, governmental, and academic bodies (see sidebar), differentiating these from SPE’s mission, which is to “collect, disseminate, and exchange technical knowledge concerning the exploration, development and production of oil and gas resources, and related technologies, for the public benefit.”
Future SPE events, workshops, training, and publications will be devoted to discussing results of the various forensic analyses now under way, and to dissecting and interpreting new standards compliance and best practices. These are dependent on results, standards, and best practices yet to be issued by governmental bodies and such organizations as the American Petroleum Institute, Det Norske Veritas (DNV), and the International Association of Drilling Contractors.
In the meantime, the task force recommended that SPE develop mini-forums to address key issues, such as robust deepwater well design, deepwater well control, and spill mitigation and cleanup. The intent of a mini-forum on robust deepwater well construction, for example, would be to connect deepwater well construction personnel to create a common vision of all the factors that combine to create a robust well design. The objective is to remain focused not on what went wrong with Macondo, but on how a well can be designed such that a blowout will never happen again. A 3- to 5-day mini-forum would cover all aspects of well design—such as hole program and casing design, cementing and zonal isolation, well control, and human factors—from a cross-section of operators, drilling contractors, and service companies. The suggested format would be presentations along with focused discussion, without notes or publication of a report.
Improving Reserves Systems With Continual Reserves Management
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 130174, ’Improving Reserves Systems Through Continuous Reserves Management,’ by Tim Loser, Energy Navigator, prepared for the 2010 SPE Hydrocarbon Economics and Evaluation Symposium, Dallas, 8-9 March. The paper has not been peer reviewed.
Traditionally, “reserves season” begins in the fall and occupies many man-weeks of effort for most oil and gas companies worldwide. With the new US Security and Exchange Commission (SEC) guidelines for reporting reserves, this activity will become more complicated in the absence of new processes. The concept of continual reserves management is presented, in which reserves are reviewed continually and updated during the year.
Introduction
Companies track production volumes with varying intervals. However, reserves typically are handled as an end-of-year endeavor. This activity is dictated largely by governmental- and financial-reporting requirements and may reflect the business process and tools in place at these companies. As a result, the process of monitoring reserves is reactive, adding little value to the company and providing only compliance.
The full-length paper details the concept of continual reserves management, in which reserves are reviewed and updated regularly throughout the year. Engineers closest to the operations can capture reserves revisions as they occur rather than defer this important task to the end of the year and perhaps delegate it to a reserves coordinator. With continual and proactive management of the reserves and their revisions, the business will have greater insight before the end-of-year roll-up, enabling better intrayear and year-end decisions. This type of system will also result in more-accurate accounting of the reserves revisions and will reduce the resources needed to complete the year-end process.
Continual Reserves Management
Reserves necessarily change with production and market fluctuations. Continual reserves management is a collection of business rules, strong corporate philosophy, improved technology, and business workflows. The most important component is corporate commitment to accurate and timely updates to the system. As with any system, there will be many differences between companies, but any continual-reserves-management system will need some basic building blocks.
Business rules—To ensure smooth operation, these rules must include management and control provisions for regulatory compliance and the rules must define roles and timing for all updates.
Regular reporting—In accordance with the business rules, regular reports to interested parties must be created. Reports to those updating reserves need to be generated automatically to indicate entities showing deviation from plan and other items that need updates. Other regular reports must be available to management throughout the year.
Flexible and simple reserves-update tools.
Open data structures.
Vigorous training.
Visible and strong corporate commitment.
Techbits: SPE/SEG Workshop on Injection-Induced Seismicity
Authors: JPT staff _ 
Published: February 2015

Techbits
In September, SPE and the Society of Exploration Geophysicists (SEG) cohosted a workshop on injection-induced seismicity in Broomfield, Colorado. The goal of the workshop was to determine industry knowledge about seismicity accompanying injection activities, identify the gaps in knowledge, and to discuss ways to improve understanding of such seismicity. Approximately 115 participants gathered to share knowledge from diverse regions and experiences. Attendees were evenly split between service companies and research organizations, and while a majority of the participants described themselves as geophysicists, about 20% were engineers. Encouraging an open discussion between engineers and geophysicists was one of the reasons for holding the workshop.
The opening session set the stage for the workshop, and included presentations about case studies of induced seismicity associated with several types of human activities. The benefits and risks of induced seismicity to subsurface and surface facilities were discussed as a basis for understanding what information is needed to better understand and mitigate potential risks associated with the seismicity.
A poster session (chaired by Jamie Rich) highlighted topics related to characterizing and mitigating fluid-induced seismicity. Other sessions included:
Underground Mines–In Situ Laboratories for Injection-Induced Seismicity (cochaired by Mark Willis).
This session focused on investigations into the established field of mining-induced seismicity, including case studies from fluid injections in underground mines and the opportunity to perform controlled studies.
Induced Seismicity Associated with Enhanced Geothermal Systems (EGS)—From Understanding to Hazard Control (chaired by Serge Shapiro and Ahmed Abou-Sayed).
This session included discussions about seismicity accompanying the development of EGS reservoirs and how public and regulatory concerns about induced seismicity risk have been addressed particularly through the United States Department of Energy EGS-induced seismicity protocol.
Looking Back at Induced Seismicity—Case Histories Examining Wastewater Disposal and Induced Seismicity—What is Known (chaired by Julie Shemeta and Dicky Hall).
This session consisted of presentations about wastewater disposal operations, observations of the comparison of seismicity with various injections, and potential interaction with existing faults.
What Do We Know About Fraccing-Induced Seismicity (co-chaired by Jamie Rich).
This included presentations about characterizing hydraulic fractures through microseismicity, the types of measurements that are made to characterize induced seismicity, and applications of those measurements. Statistical analysis methods for investigating the attribution of induced seismicity were discussed.