bluuebunny/crossref_metadata_2025_split huggingface dataset:
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 The paper has not been peer reviewed.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).