bluuebunny/crossref_metadata_2025_split huggingface dataset:
Economics of Hydrogen Production From Natural Gas
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 101703, "The Hydrogen Economy: Economics of Hydrogen Production From Natural Gas," by D. Seddon, SPE, Duncan Seddon & Associates Pty. Ltd., prepared for the 2006 SPE Asia Pacific Oil & Gas Conference and Exhibition, Adelaide, Australia, 11–13 September.
Hydrogen is a principal fuel for high-efficiency fuel-cell vehicles that produce zero emissions. Hydrogen-fuel-cell vehicles can be fueled competitively with conventional fossil-fuel vehicles if hydrogen is produced in large central facilities with access to low-price natural gas. In times of high oil price, the production cost of hydrogen should be comparable to the price of petroleum fuels. Although improvements to the technology of production are being researched, breakthroughs will not make a major difference to the production costs. Great unknowns are the cost of hydrogen transport and delivery and the distribution pressure required.

Introduction
Hydrogen from sustainable nonpolluting sources such as wind or solar energy is touted as the transport fuel of the future. The cost of hydrogen production from such sources is very high and is uneconomic given the price of electricity produced by these methods. Conventional wisdom assumes that fossil-fuel-derived hydrogen will be used in the interim. Natural gas is an obvious candidate for this role. Small-scale hydrogen production is unlikely to be economic and to be viable; production needs to be focused on large-scale hydrogen production.
A series of engineering-concept studies for hydrogen production on a large scale has been published by the US National Academy of Science (NAS). Rather than using methanation as a step in hydrogen production, the NAS study used an alternative approach with a pressure-swing-absorption (PSA) unit to separate hydrogen.
The full-length paper focuses on development of a relationship between the production cost of hydrogen and the cost of natural gas for the mass production of hydrogen in a large central facility by use of the PSA method.

Technology
Hydrogen is produced commercially from natural gas for the chemical and refining industries. In the typical method to produce hydrogen, natural gas (methane) is steam reformed to produce a "synthesis gas" comprising hydrogen and carbon oxides [a mixture of carbon monoxide and carbon dioxide (CO2)]. The amount of methane "slipping" through the reformer is minimized by operation at high temperature and low pressure. Fuel for the reformer is provided by a fuel-gas-stream addition to the feedstock gas. The next step is to convert all of the carbon oxides into CO2 by use of the water-gas-shift (WGS) reaction.
Comments: Brazil's New Finds
Authors: Donnelly John 
Published: February 2015

Editor's column
For an example of one of the new breed of successful national oil companies, look no further than Petrobras. Well known for technology expertise and innovation—the company has won two Offshore Technology Conference (OTC) awards for technical achievement—the Brazilian company is now making news for what could be some of the biggest oil discoveries in years.
Petrobras' Tupi discovery, located more than 150 miles in deep water off the Brazilian coast, has estimated recoverable reserves of between 5 and 8 billion bbl. That would make it one of the most significant finds in the past 20 years, according to analysts Wood Mackenzie, rivaling the 2000 Kashagan discovery in Kazakhstan and surpassing the largest deepwater finds, including those in the US Gulf of Mexico and offshore west Africa. Initial production of 100,000 BOPD could begin in 2010.
Petrobras has announced a series of oil discoveries in the Santos basin in recent months, including the natural gas field Jupiter and the subsalt field Carioca, which has drawn considerable speculation about its size. At this year's OTC, Petrobras Chief Executive Officer Jose Sergio Gabrielli, while acknowledging the importance of the deepwater discoveries, would not speculate on potential reserve figures.
If the promise of Tupi holds, Brazil would boost its reserves by 50% and join the ranks of the world's most significant producers. Already there is speculation that Brazil might eventually join OPEC. Petrobras' rise has been steady since it was partially privatized by the Brazilian government in the late 1990s. The country only recently became energy self-sufficient and now produces more than 2 million BOPD, almost 90% of it offshore. The company expects output to rise to 3 million BOPD by 2012 and 4 million BOPD by 2015. Petrobras believes that Tupi may be just part of a huge subsalt cluster extending hundreds of miles along the Brazilian coast.
Brazil's new oil finds will not be easy, or inexpensive, to develop. Although Brazil is considered a global leader in offshore development, the Tupi basin is located under 7,000 ft of water and then under 9,200 ft of shale and salt. Seismic imaging will be difficult and may hamper accurate estimation of reserves, and drilling challenges are common in subsalt. With regard to the Carioca area, Petrobras is at the beginning of its evaluation plan and will not have precise volume estimation until after finishing the plan.
The company's success could put a strain on already tight equipment and talent markets. Petrobras, which already has leased most of world fleet of vessels for deepwater drilling, plans to lease more and also hire thousands of upstream personnel as it creates a new division for subsalt drilling.
NMR Logging System Profiles Reservoir Fluids In Situ
Authors: Leveridge Robert 
Published: February 2015

Technology Update
For many years, petrophysicists have been differentiating reservoir fluids by means of wireline logging instruments. However, this process has been time consuming, and for a number of environments, challenging. For nuclear-magnetic-resonance (NMR) measurements there have been further obstacles, such as job-preparation issues, availability of expert knowledge, and nonroutine workflows. The use of NMR fluid-identification methods, therefore, usually has been restricted to specialists.
Petrophysicists and reservoir engineers have long wanted to identify formation-fluid types, estimate their volumes, and determine their in-situ properties. A key goal has been to characterize formation hydrocarbons, regardless of variations in formation water salinity, thin beds, or low-contrast pay zones. With such information, it becomes possible to make a continuous log of oil viscosity for completion optimization, to determine fluid-storage volumes by means of lithology-independent porosity measurements, and to determine residual oil saturation in all mud types. An additional objective has been the ability to take measurements in rugose boreholes, or in zones with thick mud cake.
A new-generation NMR wireline logging tool developed by Schlumberger is able to meet these and other needs. Called the MR Scanner, the tool uses a multifrequency, multiantenna, deep-reading measurement at logging speeds up to 3,600 ft/hr to perform precise radial profiling of fluids surrounding the borehole (Fig. 1). Tool performance is unaffected by hole rugosity or variations in lithology, and measurements are obtainable regardless of borehole size or geometry, with axial resolution as good as 7.5 in. Most important, the use of the tool saves rig time because all measurements are made simultaneously.
A variety of quick-look outputs in user-friendly formats are made available onsite, including oil and water saturations, total and effective porosity, bulk volume irreducible water, crude oil and brine transverse relaxation time (T2) distributions, and hydrocarbon-corrected Timur-Coates permeabilities. In addition to T2, the longitudinal relaxation time (T1) is available for vuggy porosities, or in zones containing light hydrocarbons.

Tough Tests Prove Technology's Value
Recently, a North Sea operator needed to determine if gas condensate, light oil, and water were present in a well drilled with oil-base mud. While that was challenging enough, the operator also wanted to identify the contact level of these fluids, if present. Conventional logs had been run in the well, but the interpretation results were inconclusive, largely because of the invasion of oil-base mud filtrate.
Pioneering Oilfield Technology
Authors: Reid David 
Published: February 2015

Management
Talk to industry old-timers about technological changes in the oilfield decades ago and their comments will likely be low-key, despite where they worked geographically or for which companies. While technology has evolved dramatically in the last 50 years, there was not a steady stream of "eurekas" echoing innovations. Instead, workplace-changing big ideas only bubbled to the surface every now and then.
We now have a decidedly quicker pace of innovation. Imagine going back in time—even only 20 years—and telling operational personnel that in 2008 one major oilfield service company currently has more than 230 technologies in active development.
This proliferation of new product development has delivered remarkable new efficiencies to rigs while requiring that management gain an enhanced understanding of how brand-new technology fits into overall drilling operations and how to best introduce the technology.

Innovation as Part of the Whole
The importance of innovation, in terms of how it goes beyond new product capabilities, is illustrated by a recent roundtable of representatives from majors, independents, and oilfield service companies, addressing the ramifications of technological innovation. Topics ranged from influences on the innovation process to where innovation fits in mergers and acquisitions, from the always critical technology adoption challenge to risk mitigation—all key management issues that transcend what is going on in the laboratory.
As a result of forward-looking management at companies, innovative R&D is not occurring in a corporate vacuum. Rather, potential innovations are "valued" at technology forums where presentations are given on a company's latest trends. From feedback out of the forums, tools and systems are refined and new ones developed, enabling operations personnel to produce better results out of existing assets or to find new assets.
In other words, the purpose of these presentations or fact-finding is, or should be, to discuss where investment money ought to be best-focused regarding the impact on current or new product lines, so that R&D actually makes a drilling performance difference—not simply introducing new technology for technology's sake. Because the development of new technology for field usage can be extremely expensive, these informational exchanges include focusing on which technologies can feasibly become immediate introductions and which are long term.

Clear Understandings
Developing and implementing new oilfield technology demands a clear understanding of how the overall process should work to be genuinely effective. Specifically, instead of a general game plan about taking ideas from concept to customer usage, management needs to delineate new product focus along the lines of delivering diversity, quality, and value. In so doing, each new technology or comprehensive drilling solution should ideally include technically advanced, field-proven systems that increase drilling efficiency; enhance health, safety, and environment programs; and maximize customers’ lifecycle economics.
Technology Focus: Formation Evaluation (August 2008)
Authors: Kennedy Martin 
Published: February 2015

Technology Focus
There is a perception in our business that we have a poor track record of introducing new technology. At various times, I have seen unfavorable comparisons with pharmaceuticals and personal electronics. Is this fair? Consider two examples of the introduction of new technology to well logging.
There are practical restrictions on which measurements can form the basis for a logging tool. Nearly all possibilities had been tried by 1960, at least in an experimental tool, and many have been in use ever since. The last measurement to enter service was nuclear magnetic resonance, which exploited an effect first demonstrated in 1946. Even for this technology, the potential had been realized in the 1950s, about the same time as the first laboratory instruments exploiting the effect went on sale. The medical profession began to make use of magnetic-resonance-imaging scanners in the early 1980s; shortly afterward, a logging tool was brought into service. This tool was not a great technical or commercial success, and it was another 10 years before a viable logging tool appeared. Nowadays, the measurement is routine and new applications are announced every year. Is this an example of us being slow on the uptake? Absolutely not—the potential was realized early, but several individual technical hurdles had to be overcome before it became a viable logging tool. For example, laboratories and hospitals are not constrained by space or power and can use powerful electromagnets (often superconducting). Those sources are not real-istic in the borehole environment, and small strong permanent magnets had to be developed before the effect could be exploited satisfactorily.
Consider individual components rather than a whole system. Microprocessors went downhole in the 1980s, having appeared only a decade earlier. The Intel 8080 processor, arguably the first commercial device that contained the functionality needed for a logging tool went on sale in 1974 (at a cost of USD 385). This time scale is similar to the time required for a novel digital audio-encoding technology to appear as MP3.
I could go on and on, but space is limited. A bit of self-criticism is a good thing, but claiming we are slow to introduce new technology is damaging and does not stand up to scrutiny. Papers highlighted here demonstrate how our industry is taking advantage of the latest technologies to find better answers and make more-informed decisions.
Formation Evaluation additional reading available at the SPE eLibrary: www.spe.org
IPTC 11201 • "Identifying Fluid Type and Contacts in Carbonate Reservoirs" by Hsin-Yi Tseng, ExxonMobil, et al.
IPTC 11308 • "Carbonate-Rock Physics: Analytical Models and Validations Using Computational Approaches and Laboratory/Log Measurements" by Shiyu Xu, ExxonMobil, et al.
SPE 105353 • "Crosswell Electromagnetic Resistivity Tomography: Pushing the Limits" by M.L. Sanni, Saudi Aramco, et al.
SPE 105605 • "Nuclear-Magnetic-Resonance Logging: While Drilling, Wireline, and Fluid Sampling" by Douglas J. Seifert, Saudi Aramco, et al.
Estimation of Variable Fluid-Mixture Density With 4D-NMR Logging
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 109051, "Estimation of Variable Fluid-Mixture Density With 4D-NMR Logging," by Chanh Cao Minh, SPE, Schlumberger; Emmanuel Caroli, Total; and Padmanabhan Sundararaman, SPE, Chevron, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November. The paper has not been peer reviewed.
No technique is available to estimate the apparent fluid density measured by the density log. In wells drilled with oil-based mud (OBM), the near-wellbore-fluid composition and distribution can be very complex. Current practice for computing density porosity is to use an ad hoc constant fluid density. This method could lead to erroneous estimation of porosity. Radial fluid profiling with advanced magnetic-resonance tools provides radial information that can be inverted jointly with conventional 3D nuclear-magnetic-resonance (NMR) data to determine fluid mixture and radial distribution.

Introduction
Computing total porosity corrected for hydrocarbon effect from density/neutron logs gives an estimate of the hydrocarbon density when the matrix density is known. It assumes that the fluids are distributed uniformly within the investigated zones. Noting that near-wellbore fluids can vary radially and accounting for the different depths of investigation (DOIs) of the density and neutron logs enable computing total porosity in gas-bearing formations.
Density and NMR log data can be combined to estimate total porosity in gas-bearing formations in the so-called DMR technique. However, the various sensors assess the same fluids. In spite of their shallow DOI, each sensor has a distinct DOI and fluid-averaging scheme. For example, NMR has a shallow DOI on the order of 1 in. to a few inches and a narrow sensitivity zone in the formation. Classical nuclear tools have deeper DOIs, ranging from a few inches for the density tool to 1 ft for the neutron tool, along with much broader investigation zones than NMR tools. Even though NMR and density logs might agree in many circumstances, they may not assess the same fluids.
3D NMR is a standalone technique to evaluate near-wellbore fluids at a fixed DOI. In some cases, complex fluid mixtures including water, oil, OBM filtrate, and gas are observed. Slow logging speed and unfavorable vertical resolution prevent routine use of the technique to estimate total porosity.
4D-NMR logging adds a radial dimension and can deliver continuous fluid mapping at multiple DOIs called shells, typically at 1.5, 2.7, and 4 in., as shown in Fig. 1. The simultaneous processing of data from all shells is intended to optimize the fluid results.
Therefore, the variable fluid-mixture density can be estimated with 3D NMR at multiple DOIs and then used in the density-log-porosity computation, assuming that the matrix density is known.
Technology Focus: Subsea Technology (August 2008)
Authors: Salies Jacques B. 
Published: February 2015

Technology Focus
The 2008 Offshore Technology Conference (OTC) was a record-breaking event: Attendance (75,000+, the highest in 26 years), participating companies, and, as a friend noticed, iron on the ground (I do not believe there are statistics on this issue, but…). Technical-session attendees were treated with projects and technologies for regions that ranged from the Arctic offshore to the deep water of east Asia—a rather broad array of applications.
The StatoilHydro subsea-to-shore gas development, Ormen Lange, received an OTC award for overcoming significant technical challenges to become Norway's deepest offshore development (800–1100 m). Although a subsea-compression system is yet to be developed to solve the challenges completely, Ormen Lange offers pioneering innovative solutions that will enlarge the industry's knowledge and improve confidence to face demanding tasks ahead that will test our ability to implement technological advances.
As of the first week of June, we reached record oil prices and an overall cost escalation in the oil industry. The implications are diverse. However, I believe it underscores how the ever-growing costs of drilling/completion/intervention rigs will put a very high burden on the development of any field, mainly subsea, that is heavily dependent on mobile offshore drilling units. Overcoming such cost escalation is a major challenge. At the same time, it is also a major opportunity for improvement.
To contemplate this quest for innovate solutions and the state-of-the-art technology in exploration and production, the highlighted papers vary from classical developments by Petrobras in its Roncador field offshore Brazil to Murphy Sabah's Kikeh field in Malaysia. In the case of Roncador, you will get to know an innovative pendulum method for installing manifolds in ultradeep water; in Kikeh, you will get an idea of the innovations necessary that were implemented to overcome the challenges of Malaysia's first deepwater development. In addition, a paper from BP outlines its successful track record of subsea developments, challenges facing the next generation, and the company's approach to technology to ensure success.
It is definitely an impressive collection of papers for their scope, content, and effect on the industry. I feel especially pleased to invite you to read them.
Subsea Technology additional reading available at the SPE eLibrary: www.spe.org
SPE 108970 • "Ormen Lange Subsea-Condition and Leakage Monitoring" by Jens Abrahamsen, Bjørge A/S, et al.
SPE 112723 • "Requirements for a Full-Drill-Through Subsea Wellhead and Tree System" by Sterling Lewis, SPE, ExxonMobil, et al.
Additional reading available at OnePetro: www.onepetro.org
OTC 19139 • "Managing Flow Assurance and Operation Risks in Subsea-Tieback System" by Shanhong Song, Chevron
Technology Focus: Health, Safety, and Environment (August 2008)
Authors: Veil John 
Published: February 2015

Technology Focus
Health, safety, and environment (HSE) continue to be integral parts of all sectors of the oil and gas industry. Individual companies and industry associations strive continually to develop more-effective systems for managing HSE.
In the May 2008 issue, JPT editor John Donnelly wrote a column about how safety performance could be strained as worldwide drilling demand continues to grow at unprecedented rates. Nobody in the business wants to see this happen, but the safety (and health and environmental) challenges of operating faster and in more-difficult situations cannot be overlooked.
This year, as the HSE feature coordinator, was far more complicated than in past years. The JPT staff sent me more than 350 abstracts from HSE papers presented during the past year. Out of that thick pile, I had to select only a few for featuring here. I have encouraged splitting the three HSE disciplines into three, or at least two, separate features. The first gradual movement in that direction happened this year, as a new feature (CO2 Applications) was created, which considers carbon-capture and -sequestration papers. In a second small shift, this year's HSE feature offers papers for additional reading separately in each of the three areas. Your input regarding the split of these disciplines into separate features is encouraged, especially in the next reader survey.
Health, Safety, and Environment additional reading available at the SPE eLibrary: www.spe.org
Health
SPE 108551 • "Occupational-Health Aspects of Emergency Preparedness and Response" by D.S. Jones, ExxonMobil
SPE 111545 • "The Other Infectious Diseases of Concern" by Jean-Marie Moreau, ConocoPhillips, et al.
Safety
SPE 111563 • "Technology and Innovations Contribute to Safety and Efficiency in Storm-Disaster Recovery" by J.F. Mailey, SPE, Chevron
SPE 111845 • "Our Sustained Efforts—‘Hand and Finger Campaign’" by Rune Hobberstad, Halliburton, et al.
Environment
SPE 110118 • "Mercury-Removal Project: Issues and Challenges in Managing and Executing a Technology Project" by Muhamad Rashid Sainal, Petronas, et al.
SPE 111973 • "Emerging Issues in Produced-Water Management: Total E&P Norge's Approach" by Pierre Goud, Total, et al.
SPE 112861 • "Oil and Gas Producers’ E&P Waste-Management Guidelines" by E. Garland, SPE, Total, et al.