bluuebunny/crossref_metadata_2025_split huggingface dataset:
Coiled Tubing Advances Improve Extended Reach Drilling Operations
Authors: Dunnahoe Tayvis 
Published: February 2015

Coiled Tubing
Fast setup and depth specific capabilities make coiled tubing (CT) the fastest growing technology in the oilfield services sector. Small diameter tubing spooled on a reel make for easy transportation, especially in remote areas. The main driver for CT usage stems from its ability to operate without a rig, which reduces an operator’s time and cost extensively. Because of its flexibility, the use of CT in horizontal and extended reach drilling operations has increased dramatically over the past few years.
While CT can achieve efficient results at lower costs in less time, it is not a perfect solution. Small tubing size increases the chances of lockup during intervention. CT also suffers from a reduction in stiffness. In horizontal and highly deviated wells, tubing is exposed to high frictional forces as it is dragged against the wellbore and this can lead to buckling.
The extended reach capabilities of CT have been extended by several methods including tractor technology and rollers, which add force at the end of the tubing, pulling it deeper into the hole. Designed in the planning phase, tapered strings can improve the efficiency of an operation, but may limit its use in subsequent intervention projects. Improved friction reduction is one of the key features to ensure against early lockup. Whether done chemically, lubricating the drillstring and the wellbore, or through buoyancy reduction, new technology is achieving results in extended reach CT applications.
Horizontal Application
The Bakken play in North America covers a 200,000 square mile region from Montana and North Dakota in the United States to southern Saskatchewan in Canada. Second only to Texas in oil production, the play has an estimated ultimate recovery of 24 billion bbl of oil, according to Continental Resources. The company has been active in the North Dakota Bakken since it completed the first commercially successful horizontal well, the Robert Heuer 1-17R, in March 2004.
Since 2008, Continental and Sanjel have successfully performed more than 200 CT mill outs in the Bakken with more than 3,000 plugs milled. Traditionally, completion technology has drastically increased the number of fracture stages per well. Early this year, a Bakken record was set of 39 plugs in a single trip while reaching out to 10,024 ft in a lateral. Mill outs in the Bakken routinely reach more than 19,000 ft using downhole water hammer tools (WHT) and different CT string designs. As CT depths approach 20,000 ft, friction reducers are among several other technologies being sought by operators in the region.
Fluid- and Rock-Property Effects on Reserves Estimation
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148717, ’Effects of Fluid and Rock Properties on Reserves Estimation,’ by Kegang Ling, SPE, Zheng Shen, SPE, Texas A&M University, prepared for the 2011 SPE Eastern Regional Meeting, Columbus, Ohio, 17-19 August. The paper has not been peer reviewed.
Precise reserves calculation is fundamental for production forecasting. Great efforts are made to obtain fluid and rock properties such as porosity, permeability, saturation, rock and fluid compressibility, viscosity, fluid gravity, gas z-factor, saturation pressure, reservoir pressure, and temperature. There is always uncertainty regarding the information because of instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. A systematic study on the effects of fluid and rock properties on reserves estimation was conducted.
Introduction
Fluid and rock properties control the volume of original hydrocarbon in place and the recoverable oil and gas. Uncertainty and error exist because of the instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. Measuring rock properties under reservoir conditions is very difficult. A synthetic field was built to study the effects of fluid and rock properties. It is an oil field with aquifer support. The initial reservoir pressure is above the bubblepoint pressure.
Initially, five producers were drilled to produce oil. With time, reservoir pressure declined. As the reservoir pressure declined below the bubblepoint with production, solution gas was released from oil. When the gas saturation reached critical saturation, it began to flow with the oil and water. This three-phase flow in the reservoir represents the middle and late production periods.
Model Description
The simulation model divides the reservoir into 93×93×2 gridblocks. The reservoir is modified to an irregular shape by assigning zero porosity and permeability to gridblocks at the reservoir edge. To populate the rock properties, different porosities, permeabilities, depths, and pay thicknesses were assigned to each gridblock. Initially, a uniform oil/water contact divided the porous sand into oil and water zones. Pressure at datum was assigned such that pressure above and below the datum can be calculated according to in-situ fluid density. Initial water saturation was assigned to respect the real oil reservoir. Rock and water compressibilities were incorporated and were assumed to be constant at different pressures. Oil viscosity varied with the pressure because solution gas has a significant effect on it. Water viscosity was kept constant. Oil gravity, gas specific gravity, water specific gravity, formation-volume factor (FVF) for oil and gas, and solution-gas/oil ratio were assigned with values often found in real oil fields.
Manage Fields With Intelligent Surveillance, Production Optimization, and Collaboration
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150079, ’Managing Fields Using Intelligent Surveillance, Production Optimization, and Collaboration,’ by Frans G. Van den Berg, SPE, Andrew Mabian, SPE, Ronald Knoppe, Edwin Van Donkelaar, Frans Terlaan, and Valentin Koldunov, SPE, Shell, and Rufina Lameda, Science Applications International Corporation, prepared for the 2012 SPE Intelligent Energy International, Utrecht, The Netherlands, 27-29 March. The paper has not been peer reviewed.
Asset professionals in Shell use advanced technologies and processes for field management and optimizing production performance. Real-time monitoring of wells and compressors has become the norm, delivering higher uptime and increased production. Wells and facilities with events or deviations (i.e., exceptions) are highlighted, enabling staff to focus on fixing critical wells and facilities. The information is brought together in collaborative work environments (CWEs) with a video connection to streamline communication between field and office, and to expedite decision making.
Introduction
In general, all of Shell’s new field developments, and redevelopments of existing fields, are equipped with appropriate smart-fields solutions. The elements selected in each field depend on its features and conditions. A screening process is carried out in the early stages of the project to identify requirements and opportunities for implementation. In some cases, application has changed the development concept completely (e.g., field development with smart wells and a remotely controlled platform). In other cases, solutions help improve field management.
Salym Development
Applications were implemented in the West Salym field in western Siberia, Russia. West Salym is the largest of three fields in the Salym Petroleum Development (Fig. 1). Since 2003, approximately 600 wells have been drilled, of which approximately 450 are producers and 150 are water injectors. Field production peaked in 2011 at approximately 180,000 B/D. Production decline would start within 5 years, and production was expected to continue for another 10–15 years. The wells were drilled from drilling pads, each with 16–20 well slots.
Each production well was equipped with an electrical submersible pump (ESP) and a variable drive control. The frequency of the ESPs (and, hence, the pump rate) was optimized weekly for production optimization and ESP-performance optimization and to keep the drawdown on the wells constant and the reservoir pressure above the bubblepoint. Frequent adjustments of the ESP settings were required because the reservoir responded fast to any changes in injection rates.
Comments: The Embargo at 40
Authors: Donnelly John 
Published: February 2015

Editor's column
Forty years ago, the global oil market faced shortages, price shocks, and unanswered questions about security of supply. The global oil landscape is drastically different today, and many of the changes grew out of the events that occurred 4 decades ago.
The most dramatic recent change is the growth in US production, revitalized by shale and tight oil output. The United States has drastically reduced its reliance on imported oil and is predicted to soon be the largest producer in the world, surpassing Saudi Arabia and Russia. US oil production has grown more than 50% in the past 5 years, and petroleum imports have fallen from a high of 60% in 2005 to 35% today, according to IHS CERA. That 35% figure is the same as in 1973, when the so-called Arab oil embargo jolted the US and other developed countries into realizing the significance of their dependence on oil supplies from the Middle East and the political and economic ramifications of that reliance.
In addition to oil, US natural gas production has risen by a third since 2005, and shale gas now accounts for more than 40% of total gas output. Long thought a reliable future customer of natural gas, the US is now retrofitting import terminals into gas export facilities.
The 1973 oil embargo—along with consumer governments’ reactive policies such as price controls—helped create gasoline shortages and political panic. It also spawned the encouragement of technological innovation and the opening of new frontiers for oil exploration and production. Developments in the North Sea, Alaska, deepwater US Gulf of Mexico and west Africa, and Canadian oil sands, as well as the growth of other non-OPEC production followed. Since 1973, OPEC production has remained relatively flat at 30 million BOPD, while non-OPEC production has doubled from 27 million BOPD. The crisis also led to increased consumption efficiency and research into alternative forms of energy. After the oil crisis, the leading consuming countries created the International Energy Agency to help guide the need to increase energy security and developed initiatives, such as the Strategic Petroleum Reserve to guard against shortages and potential price spikes.
While OPEC members and national oil companies (NOCs) have lost market share since that time, they still own the vast majority of the world’s reserves and are much less beholden to private international oil companies (IOCs). NOCs have become much more technically and financially savvy, calling the shots inside their countries and competing head to head outside their countries. NOCs no longer have to rely on large operators to develop their resources. They have the ability to manage projects and apply the latest technology, or can seek help from the large service companies, which are increasingly offering one-stop shop project expertise.
Workforce Competency and Organizational Health Key Drivers in Workforce Optimization
Authors: Glasscock Bill 
Published: February 2015

Talent & Technology
In recent years, many energy companies have sought to “cut costs at any cost,” leading in some cases to arbitrary staff reductions with unintended consequences, including reduced productivity, undermined safety, and lower profitability. These companies frequently end up paying a price that exceeds the apparent cost savings. To move beyond simple quantitative formulas and across-the-board cuts, a growing number of energy operations are employing a highly data-driven staffing assessment approach within the context of the business process.
The Workforce Optimization Consulting approach consists of a proprietary methodology, tools, and seasoned consultants focused on helping operators determine and implement the optimum workforces for their facilities. The methodology is grounded in industry best practices and requires a thorough analysis of the total workforce that embraces both quantitative and qualitative criteria. It uses databases of actual, validated oil and gas facility performance. Comparing work practices at a particular site with the top performers in the world yields staffing recommendations that are both realistic and sustainable.
Two key drivers of this smarter, more nuanced approach to managing staffing levels are workforce competency and organizational health. These two different but related criteria directly drive required staffing levels.
From a practical viewpoint, workforce competency comprises a number of factors:
Achieving targeted business objectives: safety, environmental, and financial
Visible and strong leadership at all organizational levels: management, supervision, and workers
Consistent and efficient use of leading performance work processes
Continuous and sustained use of best practices supporting the work process implementation
Individual employee competency: knowledge, training, qualifications, and experience
Employee utilization
These factors must be considered when modifying existing organization structures and staffing levels, and when developing organization and staffing plans for new facilities. Achieving maximum performance for each of these factors takes time. Implementing a Workforce Optimization Consulting solution considers the time required to achieve both individual and organizational maximum competency when determining recommended organization structure and staffing levels. Actual individual employee competency must be considered when determining the number of employees required to perform identified workloads within reasonable time frames and at sustainable work rates.
Comparing North Sea and Deepwater Gulf of Mexico Produced-Water-Treating Systems
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 159713, ’Produced-Water-Treating Systems: Comparison Between North Sea and Deepwater Gulf of Mexico’ by J.M. Walsh, SPE, Shell, and W.J. Georgie, SPE, Maxoil Solutions, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed.
In terms of platform technologies and extraction strategies, there are fundamental differences between the North Sea and the deepwater Gulf of Mexico (GOM). We consider these systems in light of best practices in water-treating-system design and consider the reasons for deviation from those practices. This process provides insight into the design of water-treating systems in general, emphasizing the importance of carrying out effective water treatment early in the process and the necessity of using large end-of-pipe equipment when this is not possible.
Introduction
Generally speaking, there is a perception that water-treating systems in the North Sea are different from those in the deepwater GOM. Specifically, North Sea systems involve greater use of hydrocyclones, with either no flotation or compact vertical flotation. Deepwater GOM systems are associated with the use of hydrocyclones (but to a lesser degree than in the North Sea) and the use of large horizontal multistage flotation. While these differences are often noted, even greater differences are observed by considering the oil/water/gas-separation system as a whole. The oil/water-separation system includes dehydration of oil and deoiling of water. From the standpoint of the overall integrated oil/water-separation system, the water-treating system is only a part. If a water-treating system is considered an add-on to the overall separation-system (oil/water/gas) design, rather than an integral part, then it will invariably be tasked with a much more difficult challenge (smaller droplets, more-stable emulsions). In that case, it will require large multistage flotation and perhaps tertiary end-of-pipe equipment such as media treatment or filtration.
As shown in Fig. 1, a typical North Sea oil/water-treating system consists of inlet heating where necessary (not shown), followed by first-stage three-phase separation. The produced water is separated from the first-stage separation with enough pressure and is treated through hydrocyclone units.
As shown in Fig. 2, typical deep-water GOM oil/water systems consist of one- or two-stage two-phase separation, followed by three-phase separation. Inlet heating is often not used. The produced water is separated toward the end of the process at lower operating pressure. The produced water is processed through hydrocyclones through a common collecting vessel operated at a lower pressure and, in many cases, a lower temperature.
Selection for Increased Fiber Length in Cotton Progenies from Acala and Non‐Acala Types
Authors: Paulo de Carvalho Luiz , Correia Farias Francisco José , Isabela da Silva Rodrigues Josiane 
Published: February 2015

ABSTRACTCotton (Gossypium hirsutum L. r. latifolium Hutch.) is one of the crops of greatest economic importance in Brazil. The changes in weaving technology, competition with synthetic fibers, and the globalization of cotton and textile production have increased the demand for better quality fibers. One of the characteristics to be improved is fiber length. Brazil traditionally produced and exported longer cotton fibers through the production of G. hirsutum L. r. marie galante, but this race has not been produced during the last 10 yr because of its perennial growth habit, which hinders control of the cotton boll weevil, Anthonomus grandis. This work studied some genetic aspects of fiber length in segregating generations of crosses between two upland cultivars, Guazuncho 2 (PI 606819) and Acala SJ4 (PI 529538). Single‐seed descent protocol and pedigree breeding procedures were used to advance generations. The fibers of the recombinant inbred lines (RILs) and those originated by pedigree procedure were evaluated by high‐volume instrument for length, lint percentage, and strength. The results suggest that it is possible to select materials with improved upper‐half mean length (UHML) that have values approaching a commercial extra‐long staple upland cultivar. A high percentage of the RILs also exhibited a UHML greater than 32 mm. Genetic gain for fiber length from the F4 to the F5 generation was 6.8%, indicating significant variability for UHML. The result indicates that simple methods of intrapopulational breeding may lead to genetic gains in UHML.
Confirmation of a Seed Yield QTL in Soybean
Authors: Fox Carolyn M. , Cary Troy R. , Nelson Randall L. , Diers Brian W. 
Published: February 2015

ABSTRACTExotic germplasm can be an important source of genetic diversity for soybean [Glycine max (L.) Merr.] improvement. Previously, four yield quantitative trait loci (QTL) had been identified in a cross between the exotic soybean plant introduction (PI) 68658 and the U.S. cultivar Lawrence. The confirmation of these QTL in other genetic backgrounds will provide further evidence of their usefulness in cultivar development. To confirm the four yield QTL, a population of 117 recombinant inbred lines (RILs) was developed from a backcross using a line from the initial PI 68658 mapping study as the donor parent and LD00–3309, a high‐yielding elite cultivar, as the recurrent parent. The confirmation population was grown in Illinois at two locations in 2008, 2009, and 2010. One yield QTL, linked to marker Satt300 on chromosome (Chr) 5, was confirmed across the experiment (p < 0.01), and the high‐yield allele was contributed by exotic parent PI 68658. This QTL was given the confirmed designation cqSeed yield‐002. A second yield QTL, linked to Satt474 on Chr 14, was significant (p < 0.05) across the experiment, with the high‐yield allele contributed by LD00–3309. Analysis of yield components from one location showed a significant increase in the total number of pods per plant associated with both of these markers. Our results provide evidence that valuable yield QTL exist in exotic soybean germplasm and that these QTL could be used to increase yield in modern cultivars.
Recurrent craniopharyngioma after conformal radiation in children and the burden of treatment
Authors: Klimo Paul , Venable Garrett T. , Boop Frederick A. , Merchant Thomas E. 
Published: February 2015

OBJECT
In this paper the authors present their experience treating children with recurrent craniopharyngioma who were initially managed with surgery followed by conformal radiation therapy (CRT).

METHODS
A departmental oncology information system was queried to identify all children (< 18 years old) who received CRT for a craniopharyngioma between 1998 and 2010 (inclusive) and specifically those who experienced tumor progression. For each patient, the authors recorded the type of recurrence (solid, cystic, or both), the time interval to first progression and each subsequent progression, the associated treatment complications, and disease status at last follow-up evaluation.

RESULTS
Among the 97 patients that met criteria for entry into this study, 18 (18.6%) experienced tumor progression (9 cystic, 3 solid, 6 cystic and solid). The median time to first recurrence was 4.62 years (range 1.81–9.11 years). The subgroup included 6 female and 12 male patients with a median age of 7.54 years (range 3.61–13.83 years). Ten patients experienced first progression within 5 years of CRT. The 5- and 10-year treatment-free survival rates for the entire cohort were 89.0% (95% confidence interval [CI] 80.5%–93.9%) and 76.2% (95% CI 64%–85%), respectively. Seven patients had a single episode of progression and 11 had more than 1. The time interval between each subsequent progression was progressively shorter. The 18 patients underwent 38 procedures. The median follow-up duration for this group was 9.32 years (range 4.04–19.0 years). Three patients died, including 1 from perioperative complications.

CONCLUSIONS
Craniopharyngioma progression after prior irradiation is exceedingly difficult to treat and local control is challenging despite repeated surgical procedures. Given our results, gross-total resection may need to be the surgical goal at the time of first recurrence, if possible. Decompressing new cyst formation alone has a low rate of long-term success.