bluuebunny/crossref_metadata_2025_split huggingface dataset:
Novel Miniaturized Antenna Designs for In-traffic Air-coupled Ground Penetrating Radar Systems
Authors: Li Ming , Vilbig Reid , Birken Ralf , Busuioc Dan , Sun Nian X , Wang Ming 
Published: February 2015

Ground penetrating radar (GPR) antennas are key elements for the operation of air-coupled, compact, low-cost systems that can be operated at road speeds to map subsurface defects such as corroded rebar, trapped moisture, voids, and pavement layers. This paper presents requirements and tradeoffs for such antennas, as well as a brief methodology for the design process to frame the context and boundary conditions of the antenna problem. Furthermore, the paper discusses a number of planar antennas that have been designed in printed circuit board (PCB) technology using low-cost, glass-reinforced epoxy laminate sheets such as FR4.The ultra-wide-band operation of antennas, along with other key parameters such as gain and beam width, is very important in the design of a useful GPR antenna for air-coupled operation. The interconnected relationship between antenna parameters limits the designs and constrains the upper bounds of the performance that can be achieved. Regulatory specifications such as FCC compliance create additional burden on the specifications and requirements.A rounded bowtie antenna, a slotted bowtie antenna and two types of Vivaldi antenna are designed, simulated, fabricated, and characterized. All are intended to operate within the 1.1–3.5 GHz frequency band and benefit from compact size while providing high gain to allow for the detection of pavement layers and rebar in bridge decks to a depth of up to 2 feet. In-field measurements of the antennas, together with the GPR system, are presented for static testing scenarios such as buried rebar in a sand box and concrete slab. The antenna testing over the sandbox and concrete slab demonstrates the great potential of utilizing the proposed antennas in air-coupled GPR systems, especially the compact rounded bowtie and slotted bowtie antennas.
Challenge and Opportunity in the Maturing North Sea
Authors: Sword Graeme 
Published: February 2015

The North Sea has arrived at a challenging stage in its development. Exploration activity has declined over the past decade, and production has been falling from its peak in 1999. At the same time, competition for investment is intensifying, with supermajors such as BP and Shell channeling more of their exploration budgets away from the North Sea to newer discoveries in the Gulf of Mexico, Brazil, and west Africa.
However, the North Sea remains one of the world’s great energy provinces. In the U.K., the Dept. of Trade and Industry estimates that 30 billion bbl of oil equivalent (BOE) has been produced but the remaining reserves base is 22 to 31 billion BOE. Norway estimates that only 40% of its oil has been produced and that remaining reserves are 85 billion BOE. Both countries’ governments recognize the need to develop effective strategies to extend the productive lifespan of the province.
The past 6 years have witnessed massive restructuring and consolidation in the industry. With the supermajors continuing to squeeze their suppliers on price, service companies are left seeking new opportunities for growth. For service companies in the North Sea, the key challenge is how to market their expertise on a global stage. Service companies could gain from the emergence of an even stronger independent sector, provided that they can address the needs of smaller oil producers.

The Need for Technological Innovation
Technology is critical to the long-term future of the North Sea, and the prize is considerable, given the scope to boost recovery rates from mature and marginal fields. The onus of developing and driving new technologies into the marketplace will remain with the operators, large service companies, and governments. Certainly, technical innovation requires a robust and inventive contracting and service/supply sector, and we are witnessing the emergence of a cluster of companies that are leading this drive. The challenge is not just to sustain but to grow this side of Europe’s upstream energy sector.
But with the largest operators now focusing their finances elsewhere, a larger share of that responsibility will fall on the state. It is time for governments to step up funding of new technology or face the prospect of the North Sea losing its position as a world leader in the hydrocarbons industry.
Greater Effective Propped Areas Derived From Proppant/Partial Monolayer Combination
Authors: JPT staff _ 
Published: February 2015

Optimization of slickwater-fracturing treatments using recently developed ultralightweight (ULW) proppants to facilitate proppant placement throughout the entire fracture area has found success. Wells treated with newly developed ULW proppants and refined placement techniques are experiencing stimulation increases (as much as 700%). The observed stimulation increases in wells stimulated by BJ Services with these ULW proppants have yielded payouts in a few weeks or months compared to years under previous methods.
The resurgence of low-cost slickwater-fracturing treatments in wells that have been uneconomical to fracture with conventional methods has led to implementing new technologies to maximize the effective propped-fracture area. The reduced settling tendencies afforded by the ULW proppants have proved beneficial in that endeavor. A desire to maximize the conductivity of the fracture within that effective area has led to rekindled interest in the decades-old theory of partial proppant monolayers.
Before the use of ULW proppants, fracturing-mechanics and -design experts tried to achieve desired fracture conductivity through the creation of fractures with partial monolayers of prop-pant but had been unsuccessful because of an inability to obtain uniform and complete coverage of the fracture; loss of fracture width as a result of proppant embedment; potentially deleterious non-Darcy flow effects; and, in the case of untreated walnut hulls, insufficient proppant strength to support the load.
In 1959, SPE paper 1291-G authors S.R. Darin and J.L. Huitt discussed the results of a study on the factors affecting fracture conductivity, demonstrating that there is an areal proppant concentration less than that of a full proppant monolayer in which the resulting conductivity is much higher than that of a full monolayer. In 1970, an SPE Monograph titled Hydraulic Fracturing, Volume 2, by G.C. Howard and C.R. Fast examined the conductivity benefits associated with partial monolayers but noted that, when using conventional methodologies, a partial monolayer had been very difficult to achieve in the field, particularly in a vertical fracture. The authors suggested that monolayers could be attained in the field by placement of a full monolayer consisting of a blend of proppant particles and oil-soluble resin particles, subsequently dissolving the resin particles to leave only a partial proppant monolayer. Contemporary experts have treated partial proppant monolayers as a technical curiosity but dis-miss the concept as having not been proved to be widely successful.
The advent and early success of ULW proppants in slickwater fracturing applications have provided evidence of longer effective propped fractures where the partial-monolayer technique was employed. Evaluation of these results indicates that the use of ULW proppants overcomes previous limitations for obtaining partial proppant monolayers.
Reservoir Management Tenets: Why They Matter to Sustainable Supplies
Authors: Saleri Nansen G. 
Published: February 2015

The growing global demand for energy and, in particular, crude supplies has brought into focus the twin issues of production sustainability and reliability. The question “What are the constituent elements that determine the sustainability of a set target from a typical field?” resonates with new urgency. A school of thought within the industry views reservoir attributes as the sole controlling factor in the equation. But there might be another element, often taken for granted, that could prove to be the critical link—prudent governance in the form of reservoir management tenets. Stated differently, underachievement of expected production levels or ultimate recoveries may often reflect unintended, although predictable, consequences of management practices unconstrained by due-diligence provisions. The tenets described in this article have played a definitive role in Saudi Aramco’s experience with its fields and may offer a useful platform for discussion. The case here is not to argue that the noted tenets are universally applicable. Instead, the intent is to point to their indispensable business value as a framework for all.

What Is Different About Today’s Subsurface
Three issues rise above all others in matters involving the subsurface: reserves, cost management, and sustainability and reliability of production.
A meaningful discussion of these items, however, calls for a close look at the emerging characteristics of the subsurface and what they portend for tomorrow. There is a confluence of trends, namely increasing complexity of well architectures, higher levels of well intelligence, and the arrival of real-time information in well-placement and field operations. The latter two events, artifacts of global information technology advances, have two predictable consequences for our industry: an exponential increase in availability of real-time data and the heightened expectation of commensurate speed and accuracy in decision making and forecasting. The question that begs to be raised is, “How do we transform the massive volumes of data into intelligent decision making with business value?” Do we need a process or a formalized framework to influence the outcomes emerging from fields in terms of expected ultimate recoveries, costs, and sustainability?
In their insightful article “Delusions of Success,” Lovallo and Kahneman argue that business and project failures stem from consequences of flawed decision making and specifically from a lack of an objective perspective (regarding underlying project assumptions). In this context, how can we ensure that the appropriate level of “objective perspective” is injected into field performance forecasts?
Gecko Wells: Bringing Sand to Surface, A Change in Well-Design Philosophy
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87956, "Gecko Wells: Bringing Sand to Surface, A Change in Well-Design Philosophy," by Fadillah Hj Ahmad, Mike Ward, SPE, and Antony Fisher, SPE, Brunei Shell Petroleum, prepared for the 2004 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Kuala Lumpur, 13-15 September.
A fundamental change in well design was proposed following an energetic, low-unit-development-cost (UDC) workshop with cross-discipline, service company, and other low-cost-operator input. As with most brownfield sites, continued production faces a constant challenge to keep UDC economical. One of the major costs and well-design requirements in this shallow oil field is downhole sand control. If well design could be slimmed down and simplified and sand produced to the surface, a significant reduction in well costs could be possible.

Introduction
Brunei Shell Petroleum (BSP) Darat assets comprise onshore and near-shore hydrocarbon-production fields, principally the Seria field. The Seria oil field is a billion-bbl field that has been producing for more than 60 years. More than 159×106 m3 of oil has been produced since the field came on stream in the 1930s. Approximately 186×106 m3 of bypassed moveable oil in the Seria field has been identified. Because of the compartmentalized, highly stratified nature of the reservoir, numerous reserves are unlikely to be developed economically at current UDC.
The catalyst for attempting to produce some of the untapped hydrocarbons was the Darat Low-Cost-Well Workshop held in May 2003. Significant preparation went into this event to ensure a healthy mix of BSP disciplines, Shell Group expertise in mature-well technology, and most importantly, service-company representation from a diverse range of companies with much experience in non-Shell-operated low-cost environments around the world.
A Low-Permeability Case Study of 5 Years of Continuous Well-Performance Improvement
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90792, "Integrated Process Improves Production of the Almond Formation in the Wamsutter Field, Wyoming: A Low-Permeability Case Study of 5 Years of Continuous Improvement in Well Performance," by Mike Mullen, SPE, Rich Dickerman, SPE, and Jack Stabenau, Halliburton, and Martin Dobson, SPE, and Charles Ohlson, SPE, Marathon Oil Co., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Common concerns regarding mature low-permeability gas reservoirs include: “How much will the new designs cost?” and “Will the new designs increase recoverable reserves?” To answer these questions, the reservoir must be studied and analyzed before a reasonable prediction can be made regarding its maximum potential. An effective approach is to form an integrated team, made up of specialists from both the operating and service companies, to gather and process comprehensive information. This information should include data from reservoir engineering, drilling, petrophysics, geology, stimulation design, and production and completion operations.

Introduction
A team approach was applied to the low-permeability Almond and Lewis sands in the Wamsutter field in southwest Wyoming. The team began studying the reservoir in 1998 to better understand the problems that prevented wells from producing at their maximum potential. The team was challenged with the following tasks.
- Determine whether the wells were already performing at peak capacity.
- Establish a benchmark against which to measure the success of any changes.
- Identify major causes of underperformance.
- Apply new technologies and techniques to overcome the causes of underperformance.
- Prioritize pay zones on the basis of log evaluation, individual zone testing, and production logging.
- Design stimulation treatments that maximize the net present value of the well.
- Document the effect of specific changes in completion practices.
From the beginning, a benchmark of the 90-day-average production rate was established. As a result, the original benchmark has been exceeded by more than 100% over the past 5 years. The average production for these wells also has increased more than 50%.
Overview: EOR/IOR (January 2005)
Authors: Pitts Malcolm J. 
Published: February 2015

The thrust of any oilfield enhanced-recovery project is economical production of incremental oil. Three field projects are discussed in this feature that demonstrate incremental oil production by use of three different enhancement technologies: CO2, steam, and chemical injection. Each study provides insight into the enhanced-oil-recovery technologies: CO2 flooding of a 50-cp reservoir, surfactant enhancement of a carbonate reservoir, and adjustment of steamflood practices for environmental compliance. While we tend to focus on oil produced, these papers illuminate requirements to implement a successful project.
First, one’s homework must be done, which includes sound reservoir-engineering and geologic analyses to define the best technology for a particular reservoir. Laboratory evaluations that show technology feasibility and incremental oil production from reservoir rock are key to making an informed “go or no-go” decision. Numerical simulation is the next logical step to translate laboratory data into field performance, thus providing an oil-production forecast for use in calculating project economics. The final decision to move forward with a field project should come only after careful technical and economic analyses of the potential effects on project outcome. Next, proper facilities design and attention to detail by field operators are essential to success. Finally, and perhaps one of the most refreshing aspects demonstrated by these papers, comes continual monitoring of a project to react to what is happening in the field, to make adjustments as necessary, and to learn from performance. We, as engineers, are forced to make assumptions, which may or may not be correct as a project is developed. When a process does not perform as anticipated, we often conclude that the technology did not work rather than admit that the application was ill conceived or improperly implemented. However, with persistence and willingness to take a different viewpoint, success often can be achieved by changing our preproject conceptions.
Additional EOR/IOR Technical Papers
Available at the SPE eLibrary: www.spe.org
SPE 89457 - Artificial Intelligence Used to Evaluate 23 Single-Well Surfactant-Soak Treatments
SPE 88720 - Vertical Conformance in a Mature Carbonate CO2 Flood: Salt Creek Field Unit, Texas
SPE 88716 - Evaluation of IOR Potential Within Kuwait [See JPT (December 2004) 57]
SPE 89456 - A Novel and Successful MEOR Pilot Project in a Strong Waterdrive Reservoir, Vizcacheras Field, Argentina
SPE 89423 - Wettability Alteration During Surfactant Flooding of Carbonate Reservoirs
Overcoming Shallow-Gas Drilling Difficulties
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87179, "Overcoming Shallow-Gas Drilling Difficulties in the Gulf of Thailand," by Pornpoch Tiraputra, SPE, Pattanapong Thiravutpinyo, SPE, and Sunchai Pongorapin, PTT E&P; Bernard Fraboulet, SPE, Total E&P; and Mohammed Dooply, SPE, Walter Friedl, SPE, and Youssef Elmarsafawi, Schlumberger, prepared for the 2004 IADC/SPE Drilling Conference, Dallas, 2-4 March.
Shallow gas-bearing formations in the Gulf of Thailand present numerous drilling and cementing challenges. In the first three wells drilled on platform WP11 in Bongkot field, initial cementing of surface casing did not achieve effective zonal isolation of the shallow-gas zone. Use of conventional lightweight gastight cement slurries, two-stage cementing operations with conventional gas-migration-control slurries, and injection of sodium silicate to damage the shallow-gas sand failed to control the gas migration through permeable upper sand layers. The full-length paper presents case histories describing the solutions-oriented approach to this problem that resulted in changes to the drilling program and cementing operations.

Introduction
Bongkot field is in the Gulf of Thailand approximately 600 km south of Bangkok and 180 km off the coast of Songkhla province. Following discovery of the field in 1973, it was delineated by drilling 23 wells. In 1990, the concession development rights were transferred to a joint venture group comprising PTT E&P plc (PTTEP), Total E&P Thailand (TEPT), British Gas Thailand Ltd., and Statoil Thailand Ltd. The field was operated by TEPT from the beginning until mid-1998, when the operatorship was transferred to PTTEP.
In 1995, the shallow-gas anomaly was discovered in the Tonsak south area of Bongkot field. Drilling through the shallow gas was proved technically feasible and safe after a pilot hole, Tonsak SG, was drilled in 1996. The shallow-gas-anomaly characteristics were verified with logging-while-drilling information. This well was abandoned safely.
In 1998, the decision was made to set a platform over the shallow-gas anomaly. The motivation was a projected cost saving of approximately U.S. $20 million, in part because the gas could be drained with a single wellhead platform instead of three small wellhead plat-forms outside the shallow-gas anomaly.
Stand Tall and Speak Up: No "Free Lunches" in Energy
Authors: Sprunt Eve S. 
Published: February 2015

A few months ago, I read an online report that said "Automakers are all investing heavily in what they think will be the next big breakthrough in cars, emission-free fuel cells. These fuel cells, which run on hydrogen and produce nothing but water vapor, are expected to power a new generation of cars that will free the world from reliance on oil."
Many of us have read similar news clips or seen equivalent television coverage. If only it were so easy. Remember, there's no such thing as a free lunch. Everything has some kind of environmental impact. If a sunbeam is deflected from its previous path or if water is diverted, something changes. The issue is whether, in the grand scope of things, society finds the cost/benefit ratio of the change to be acceptable.
To compare different methods of powering transportation, the correct approach is to look at the full life cycle and to compare all the options on a common basis. Evaluation of everything involved in all the components that lead to the end product is a huge undertaking, so usually the comparison focuses on specific aspects—for example, the fuel supply chain. The differences in the emissions associated with manufacturing different components of the vehicle—for example, fuel cells or batteries as opposed to an internal combustion engine—are not included.
In the example quoted, the hydrogen fuel-cell vehicle is like an electric vehicle. It is not a zero-emission vehicle when evaluated on a full life-cycle basis, but rather a remote-emission vehicle. Just as the emissions associated with an electric vehicle depend on the source of the electricity, the emissions involved in use of hydrogen depend upon how the hydrogen is generated.
On earth, hydrogen is almost always found in combination with other elements, as for example in water. Therefore, it is more appropriate to view hydrogen not as an energy source, like hydrocarbons, but rather as an energy carrier, like electrons. Decarbonization of the energy supply may lead us not to a hydrogen economy, but to an electron economy.
With current technology, the most cost-effective method of producing hydrogen is from natural gas and water at high temperatures in catalytic reactors using a process called steam reforming. The hydrogen is subsequently further purified to minimize damage to fuel-cell membranes from contaminants. Worldwide, extensive research is underway to produce hydrogen from renewable sources on a cost-competitive basis, but additional technical breakthroughs are needed to achieve that goal.