bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water loss in transit in an intermittent river in brazilian semi-arid
Authors: Toledo Cristian Epifanio , Moura Silva Almeida Emanuelly De , Lopes Neto Alexandre Vicente , Gonçalves Rodrigues Silva Thályta Lharyssa Gonçalves Rodrigues , Rodrigues Santos Filipe Augusto 
Published: October 2018

Riverwater often comes into contact with the underground flow in aquifers. When this contact
occurs, the river and aquifer are considered to be hydraulically connected. In recent decades, there has
been great interest in trying to to improve understanding of the interactions occuring between superficial and
subterranean water systems. A variety of analytical solutions have been proposed to describe the interaction of
confined and free aquifers with adjacent rivers, including the quantification of the decrease of river flow along
its course. The objective of the current study was to calibrate and validate a loss-in-transit flow model for rivers,
and to evaluate the minimum flow that still permits connectivity between water sources in the Alto Jaguaribe
basin. The methodology used was based on the equation of continuity and mass balance along the study river.
A modified Araújo and Ribeiro equation showed strong applicability to loss-in-transit generation, with a mean
loss in transit of 3.6% km-1, and a Nash and Sutcliffe Efficiency value of 0.29. On the other hand, the classbased
loss of upstream flow generated 4 classes with a mean of 2.6% km-1 and showed great improvement,
reaching an NSE of 0.74 - high efficiency. Minimum flows were below the regular flow recorded by the Ceará
Secretariat of Water Resources, showing that the ability exists in the region hydrological connectivity between
reservoirs in the Alto Jaguaribe basin and for alluvial aquifers to be recharged.
Initial growth of cassava plants cv. Mossoró under different water regimes
Authors: De Mélo Neto Domingos Ferreira , Coelho Daniel Gomes , De Andrade Moab Torres , Oliveira Alves Jandelson De 
Published: October 2018

The sprouting phase of cassava is critical for the establishment of the plant, with this phase
being dependent on soil moisture. As such, this study evaluated the effect of different irrigation levels on
the initial growth of cassava cv. Mossoró in semi-arid conditions. The experiment was conducted under
completely randomized design conditions with 5 replications. The treatments in pots containing one plant per
experimental unit consisted of 5 irrigation levels, 0, 25, 50, 75 and 100% of the reference evapotranspiration
(ETo, mm day-1), which corresponded to totals for the experimental period of 11.20; 42.15; 73.09; 104.03
and 134.97 mm, respectively. At 30 days after planting, the number of leaves and stems, as well as the
dry mass of the shoot and the root had increased sharply for irrigation levels up to 73.09 mm. For higher
irrigation levels there was a tendency for plant growth stabilization; however, above 104.03 mm there was
a decrease. Shoot and root dry mass ratio showed severe water stress at the 11.20 mm level, being more
damaging to root growth. Plant height showed a positive linear trend as the level of irrigation was increased,
as opposed to water use efficiency. Therefore, irrigation with 50% replacement of ETo (73.09 mm) provided
the best conditions for early growth of cassava.
YAŞLILARIN SAĞLIK/HASTALIK DURUMLARININ TOPLUM SAĞLIĞI AÇISINDAN DEĞERLENDİRİLMESİ
Authors: ASLAN Dilek , KOÇ Ekin , ÇOLAKLAR Merve 
Published: October 2018

“Bilgelik” ya da “ikinci çocukluk” olarak
da adlandırılan yaşlılık dönemi bireylerde fizyolojik, psikolojik, sosyolojik
vb. değişimler açısından önemli bir dönemdir. Bireylerin bu dönemi sağlıklı
geçirebilmeleri için yaşamlarının çok erken evrelerinden itibaren önleyici
davranışları içselleştirmeleri gerekir. Ülkemizde ve dünyada yaşlı birey
sayısının artma eğiliminde olduğu dikkate alındığında, bütün toplumların yaşlılık
konusunda sistem temelli değişiklikler yapma gereksinimleri öne çıkmaktadır.

Yaşlıların heterojen bir grup olduğu
bilinmektedir. Dolayısıyla, yaşlılık döneminde sağlık ve diğer gereksinimler de
birbirinden farklılaşabilmektedir. Bütün bu nedenlerle yaşlılar için planların
ve programların bireylerin ve toplumun öncelikli gereksinimlerine göre
yapılması uygun olur.

Bu yazı kapsamında; yaşlanınca nelerin
değiştiği ve özellikle sağlık/hastalık durumlarındaki farklılıklar
incelenmiştir. Bu inceleme sırasında yaşlılığın kavramsal olarak tanımı,
geçmişten bugüne kavramlardaki değişimler, sağlık/hastalık konularında öne
çıkanlar, sağlıklı bir yaşlanma için öneriler üzerinde durulmuştur. Hastalık
yükünün azaltılmasının yanı sıra yaşam kalitesinin iyileştirilmesi için koruyucu
ve sağlığın korunması yaklaşımlarının geliştirilmesi önerilmektedir.
Long Bone Union Accurately Predicted by Cortical Bridging within 4 Months
Authors: DiSilvio Frank , Foyil Sarah , Schiffman Brett , Bernstein Mitchell , Summers Hobie , Lack William D. 
Published: October 2018

Background:
Previous retrospective research found that the presence or absence of bridging callus within 4 months postoperatively discriminated accurately between eventual union and nonunion of fractures of the tibial shaft. However, there remains no consensus regarding early prognostication of long bone nonunion. We prospectively assessed the accuracy and reliability of the presence of any bridging callus within 4 months in a cohort that was expanded to include both tibial and femoral shaft fractures.

Methods:
We identified 194 consecutive fractures of the shaft of the tibia (OTA/AO type 42-A, B, or C) and femur (OTA/AO type 32-A, B, or C) that were treated with intramedullary nailing. Exclusions for inadequate follow-up (55), extended delay prior to nailing (10), and skeletal immaturity (3) resulted in a study population of 126 fractures (56 tibiae and 70 femora) in 115 patients. Digital radiographs made between 3 and 4 months postoperatively were independently assessed by 3 orthopaedic traumatologists. The accuracy of assessment of the presence of any bridging callus, bicortical bridging, and tricortical bridging to predict union or nonunion was assessed with chi-square analysis and by interobserver reliability (kappa statistic).

Results:
The nonunion rate was 4% (5 of 126 fractures). The presence of any bridging callus by 4 months accurately predicted union (121 of 122 fractures) and its absence predicted nonunion (4 of 4 fractures). There was 1 incorrect prediction of union for a fracture that failed to unite (p < 0.001). Bicortical or greater bridging predicted union when present (116 of 116 fractures) and nonunion when absent (5 of 10 fractures), incorrectly predicting that 5 healing fractures would go on to nonunion (p < 0.001). Tricortical or greater bridging predicted union when present (103 of 103 fractures) and nonunion when absent (5 of 23 fractures), incorrectly predicting that 18 healing fractures would go on to nonunion (p < 0.001). Interobserver reliability was calculated for any bridging (kappa value, 0.91), bicortical bridging (kappa value, 0.79), tricortical bridging (kappa value, 0.71), and the exact number of cortices bridged (kappa value, 0.67).

Conclusions:
The presence of any bridging callus within 4 months accurately predicts the final healing outcome for tibial and femoral shaft fractures treated with intramedullary nailing. This criterion is simple and reliable, and only standard radiographs are needed to make the determination. Basing the prognosis on the bridging of additional cortices risks overestimation of the nonunion rate and is associated with relatively poor reliability.
Technology Update: Optimizing Well Productivity: Horizontal Logs Unlock Critical Geologic Knowledge
Authors: King John 
Published: October 2018

Technology Update
With drilling on the rise, US oil production is expected to continue to increase. However, many industry professionals are concerned that the “brute force” model, which has seen a massive influx of capital flow into completion and hydraulic fracturing operations, is not an economically sustainable business model. There is a growing belief that better understanding of the effectiveness of completion designs and hydraulic fracturing strategies will require far greater subsurface geological understanding. Moreover, continued well productivity improvements will only be realized through improved reservoir characterization, and by applying formation petro-physical and geomechanical information to optimize methods of drilling, completing, and stimulating wells.
There has been considerable media attention focused on how the industry is drilling wells longer and more quickly, as well as applying higher-intensity fractures. Until recently, however, there has been less emphasis on constructing productive wells with less capital.
Traditional vertical well tool conveyance methods effectively addressed industry logging requirements for almost a century, but in today’s “horizontal” world, conventional methodologies are either not applicable or expensive and risky. Essentially, the multibillion-dollar logging market has not quite been turned upside down, but has toppled onto its side.
Using available industry data, the low-hanging fruit in the growing “big data” boom, geosciences departments have labored to build accurate high-resolution geological models. Given the nonhomogeneous nature of the geology in unconventional reservoirs, applying vertical offset well logs and interpolating field reservoir models is generally accepted as a good start, but hardly the complete solution. To develop an accurate reservoir model, the heterogeneous nature of shale plays requires far greater data resolution than most operators appreciate. If operators are going to efficiently exploit every stage of their wellbore, they need accurate, measured formation insights along every foot of the horizontal wellbore. Geometric completions and fracturing strategies are not practical or effective in these unpredictable heterogenous environments. Along the wellbore, operators are encountering highly variable rock properties that affect fracturing efficiencies, and result in poor or unexpected well production results.
This trend is forcing producers to evaluate stage-by-stage production contributions. They are finding that large portions of their wells are not contributing. There is a growing realization that improved well results that are repeatable and predictable are only going to come about by enhancing production at every stage in the wellbore. This requires engineered completions programs and tailored fracturing strategies that account for the considerable rock heterogeneity along the lateral.
A Look Into What Fractures Really Look Like
Authors: Rassenfoss Stephen 
Published: October 2018

Reports from the Hydraulic Fracturing Test Site offer a glimpse into what hydraulic fractures really look like.
The featured attraction in the 13 technical papers presented over two mornings at the Unconventional Resources Technology Conference (URTeC) was 600 ft of rock fractured in late 2015 near wells in the upper and middle Wolfcamp. Those core samples spawned a mind-boggling array of observations about the rock, proppant, and natural and hydraulic fractures, and how they all interact.
In the more than 2 years since the samples were gathered, the sections of core have been meticulously analyzed by teams of experts. More than 700 fractures were categorized based on whether each one was created by nature, hydraulic force, or the stress of drilling the slant well. And the majority of the 400 stages pumped were studied using tracers and/or monitored using advanced diagnostics.
The density and distribution of the fractures were measured as the scientists worked to understand how natural and hydraulic fractures interact. The bits of sand, calcite, and drilling mud found in and around the rock were collected and sorted. Automated imaging and painstaking manual examinations were used to measure the size, shape, and translucence of each grain in order to identify and quantify the grains.
The “incredible complexity” observed was “far beyond what current simulations can model and predict,” said Jordan Ciezobka, manager for research and development for the Gas Technology Institute (GTI), which managed the federal grant supporting test site 1 and is planning Hydraulic Fracturing Test Site 2 (URTeC 2937168).
Ciezobka predicted that findings from the first Permian test site hosted by Laredo Petroleum in the Midland Basin would be studied for years to come. The public-private partnership is just beginning to deliver the delayed reports of what it learned from the $25-million research project. Federal funding for the project requires the partnership to ultimately disclose its results, with data releases beginning later this year. The lag time rewards companies that supported the project with a long first look.
Cause and Effect?
The completion engineers in the room those two mornings likely left wanting more. With one exception, the talks avoided mentions of the ultimate measure of what works—production. Instead, they challenged widely held mental images of fracturing.
For one, fracture height is overrated. While microseismic testing indicated that fractures grew up about a 1,000 ft, the height of the propped fractures—the fractures most likely to produce oil and gas—was about 30 ft.
Proppant distribution was sporadic. While there were thick fractures full of sand inside, a paper describing fracturing (URTeC 2902624) said that only three of them were found among hundreds of propped fractures. And all of those were found in the upper Wolfcamp.
While the fractured lateral in the middle Wolfcamp was further from the slant well—135 ft vs. 90 ft from the nearest stage—the middle Wolfcamp core has a lot more proppant than the upper Wolf-camp core (URTeC 2902364).
What Happens When Facebook Technology Meets Oil Well Records
Authors: Jacobs Trent 
Published: October 2018

A former industry IT expert recently invented a program using open-source social media technology to make the work of inquisitive oil and gas engineers a little more like that of a special agent.
Named WellLine, it is the brainchild of Jeff Dalgliesh, the director of oil field digital transformation at Silicon Valley-based Maana, who previously spent 18 years at Chevron as a drilling and completions IT manager.
Though similar tools exist, WellLine reflects a couple of important trends taking place across the oil industry’s expanding digital landscape. The first is the speed at which big data solutions can be assembled—in this case, it took less than a single summer with just three people. The other is the expanding encroachment of free and open-source technology into the oil and gas enterprise software domain.
“This accelerated pace of development is going to become the norm because a lot of the stuff you’re doing is reusing application components,” Dalgliesh said. “The thing is, if there is good technology out there, just figure out how to use it. That’s Maana’s story—we integrate a bunch of technologies and build applications fast.”
Behind WellLine are several non-proprietary query languages, user interface toolsets, and natural language processing (NLP) systems. Each help to thread together thousands of well records from the industry’s most-popular well document management systems and other unconnected databases. This makes searching for well events about as easy and intuitive as checking up on friends and family using Facebook.
But instead of birthdays, vacation photos, and marriage announcements, WellLine extracts any desired detail from drilling, production, and intervention reports. A key feature of the product’s dashboard is a chronological timeline (hence the software’s name) of a well that shows every notable event ever recorded.
“If you’re a driller and want to see the life history of a well based on all these documents, databases, and production systems, right now you have to go through multiple systems,” Dalgliesh explained. He thinks that by intuitively and quickly unearthing historical data, operators will be better able to flesh out offset-well drilling plans, select workover candidates, or de-risk plug and abandonment operations.
Dalgliesh shared details of the new product line for Maana’s platform at the SPE Engenious symposium on upstream innovation in September. The 6-year-old startup has been involved in oil and gas projects since 2016, when it attracted $26 million in venture funding, part of which came from Chevron, Shell, and Saudi Aramco.
From the podium, he said that oil and gas companies should start using their data just like a state intelligence agency would. “They would run algorithms on it, and those algorithms would rip it apart, find out who is being talked about, what’s being talked about, and connect it all together,” he said.
Huff 'n' Puff Gas-Injection Pilot Improves Oil Recovery in the Eagle Ford
Authors: Carpenter Chris 
Published: October 2018

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189816, “Huff ’n’ Puff Gas-Injection Pilot Projects in the Eagle Ford,” by B. Todd Hoffman, SPE, Montana Tech, prepared for the 2018 SPE Canada Unconventional Resources Conference, Calgary, 13–14 March. The paper has not been peer reviewed.
The Eagle Ford formation has produced approximately 2 billion bbl of oil during the last 7 years, yet its potential may be even greater. Using improved oil-recovery (IOR) methods could result in billions of additional barrels of production. While a number of companies have field-tested an IOR method called huff ’n’ puff gas injection, most of the published results are from laboratory and modeling studies. This paper evaluates the results of these field tests and discusses the potential of the huff ’n’ puff method in the formation.
Introduction
The Eagle Ford formation, formed during the late Cretaceous, is a laminated calcareous organic rich shale. The shale was deposited in a low-energy anoxic marine shelf environment, which allowed for rapid deposition and burial of abundant organic material. The Eagle Ford is divided typically into two sections: the Upper, which was deposited during a regional marine regression, and the Lower, which was deposited during a transgressional period and tends to have more organic-rich black shale. The Eagle Ford is laterally continuous and spatially extensive throughout much of southern Texas.
The matrix permeability of the reservoir is low enough that typical hydrocarbon migration is restricted, causing the oil-rich rocks to be stratigraphically higher than the gas-filled ones.
Results of Previous Huff ’n’ Puff Pilot Projects
The huff ’n’ puff process involves injecting a miscible gas into a well and then, after some time has passed, producing back from that same well. Data have been collected on seven pilot projects in the Eagle Ford that have been completed during the last 5 years. Data from four of these seven are discussed in this synopsis. All of the pilots used hydrocarbon gas, but the composition of the gas varied across the locations. In addition, all of the field trials used a huff ’n’ puff injection scheme.
Pilot A. The first pilot was a single isolated well where the nearest offset producers were more than 2 miles away. This provided some assurance that the injected gas would not migrate to other wells. The oil rates for the well indicated a positive response to the process. Each cycle increased the production rate to approximately half of the well’s initial rate. Once the oil rate began to drop, another injection cycle was started. This is encouraging because not only the first cycle but also subsequent cycles were able to increase production.
Root-Cause Analysis of Offshore Pipeline Failures
Authors: Carpenter Chris 
Published: October 2018

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 188717, “Offshore-Pipeline-Failure Root-Cause Analysis,” by Emmanuel Iyeh, SPE, Addax Petroleum, and Grant Adams, JEE Subsea, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed.
This paper evaluates potential causes of failure for nine pipelines operating in shallow waters (8 to 14 m) in the Gulf of Guinea. The authors develop an analytical method to identify root causes and provide recommendations for pipeline design and placement.
Methodology
Once the subject pipelines had been identified, field visits and failed-section analyses were conducted. Pipeline properties and conditions are provided in Tables 1 through 5 of the complete paper. Mechanical-failure, hydrodynamic, and third-party-interference assessments were performed. Design-stability assessment was reviewed and gaps identified. A further stability assessment of the pipelines was performed in accordance with Det Norske Veritas- Germanischer Lloyd Recommended Practice (DNVGL-RP) F109. The authors then developed the best remedial option by use of a scoring matrix based on weighting with respect to business drivers.
For a new tie-in spool, a subsea flexible spool can be used. This approach has been used safely and successfully to accommodate instability. This approach may be adopted for pipelines, with the following caveats:
An unbonded subsea flexible spool verified for use in a multiphase system should be used.
A flexible spool should be combined with a rigid riser.
The flexible spool does not represent a solution to pipeline instability but rather a method to prevent failure of the riser caused by a mobile pipeline. The pipeline may continue to move over time, and the flexible spool may eventually enter tension and fail. An unstable pipeline is also at significant risk of fatigue if instability continues.
A flexible spool could be used with a concrete mattress. This will allow a degree of movement (e.g., if the mattresses take some time to settle into the seabed). The position of the flexible tie-in can also be monitored and, in the event that the pipeline continues to move after mattresses have been installed, will give warning that the pipeline is still unstable.
Analysis Results
The majority of the studied failures occurred between the months of May and October, the rainy season in the Gulf of Guinea. This season features the region’s most extreme weather, likely contributing to the failures. Most failures involved pipeline movement or riser kinks.