bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tooth Loss Strongly Associates With Malnutrition in Chronic Kidney Disease
Authors: Ioannidou E. , Swede H. , Fares G. , Himmelfarb J. 
Published: November 2013

Background: In chronic kidney disease (CKD), inadequate nutritional intake, inflammation, and increased oxidative stress have been the major contributing factors in malnutrition pathogenesis. However, there is still a paucity of evidence assessing the magnitude of the effect of tooth loss on malnutrition in CKD populations. The authors hypothesize that among patients with CKD, tooth loss may affect nutritional status, using the National Health and Nutrition Examination Survey 1988 to 1994 (NHANES III).Methods: Glomerular filtration rate (GFR) was estimated based on cystatin C levels using the relevant equation. Urinary albumin‐to‐creatinine ratio (albuminuria) was calculated in milligrams per gram with a cutoff point of 30 mg/g. CKD was defined based on estimated GFR <60 mL/minute/1.73m2 and albuminuria ≥30 mg/g. The cutoff point for serum albumin was set at 3.7 g/dL. Tooth loss categories were based on the number of missing and replaced teeth.Results: A total of 2,749 patients was included and stratified based on their oral health status. There was a statistically significant correlation between tooth loss and the proportion of patients with low protein and caloric intake (P = 0.02 and 0.01, respectively). Serum albumin reached a frequency peak in the fully edentulous group without dentures (group 4, 19.2%). In the same group, individuals had lower protein (30.1%) and caloric intake (30.2%) (P = 0.01 and 0.02, respectively). Furthermore, logistic regression analysis confirmed the significant role of tooth loss on serum albumin and protein and energy intake in this population even after adjusting for confounding variables.Conclusion: Tooth loss independently predicts low energy and protein intake, as well as serum albumin levels, biomarkers of malnutrition in CKD.
Bibliometrics Study on Authorship Trends in Periodontal Literature From 1995 to 2010
Authors: Geminiani Alessandro , Ercoli Carlo , Feng Changyong , Caton Jack G. 
Published: November 2013

Background: Biomedical research has grown considerably in the last few decades, and the authorship characteristics of the dental literature as a whole and of its specialty fields has changed significantly. Unfortunately, the bibliometrics of the periodontal literature have not been thoroughly investigated. The aim of this study is to investigate the bibliometrics of periodontal literature, assessing the geographic origin, study design, and topics investigated in periodontal research published from 1995 to 2010.Methods: Articles published in periodontal journals during 1995 to 2010 were retrieved through hand search. Inclusion/exclusion criteria were applied. The following variables were extrapolated from each article: number of authors, study design, topic investigated, financial support, and geographic origin. The general linear model assessed the influence of independent variables on number of authors per article, and χ2 test assessed the statistical difference of the variables over years 1995 to 2010.Results: A total of 2,260 articles were reviewed; 2,076 met the inclusion criteria. The number of authors per article increased (P <0.001) from 4.0 (1995) to 5.1 (2010). The proportion of articles published from North America and Europe decreased (P <0.001) from 84.3% (1995) to 58.6% (2010), whereas for Asia and South America the article proportion increased (P <0.001) from 13.8% (1995) to 40% (2010). Research targeting prevention and treatment of periodontal disease is decreasing (P <0.001) in favor of implant‐related research. Governmental research funding is increasing (P <0.001).Conclusion: Periodontal research significantly changed during the last 15 years.
The Correlation Analysis Method and Its Application in Hydrocarbon-Bearing Formation Identification in Tight Sandstone Reservoirs
Authors: Liang Xiao , Chang-chun Zou , Zhi-qiang Mao , Yu-jiang Shi , Gao-ren Li , Hao-peng Guo , Xiu-hong Xie 
Published: November 2013

Abstract
Hydrocarbon-bearing formation identification with conventional logs faces great challenge in tight sandstone reservoirs due to the low resistivity contrast and complicated oil/water system. The conventional methods, which are applicable in normal reservoirs in oil or gas identification, such as the porosity and resistivity crossplot of the Hingle and Pickett crossplots, lose their roles. In this paper, based on the analysis of the conventional log responses in hydrocarbon-bearing formations in the Chang 8 Formation in Longdong Region of Ordos basin, the positive correlation of porosity and resistivity in oil-bearing formation, and negative correlation in water saturated layers are observed. A correlation analysis method, which can be used to express the correlation of porosity and resistivity in formations with different type of pore fluids occupied, is presented, and the corresponding model which is used to calculate the correlation coefficient is established. For reservoirs with hydrocarbon-saturated, the value of the correlation coefficient ranges from 0.0 to 1.0, in pure water layers, the correlation coefficient ranges from −1.0 to 0.0, and in oil-water bed, the correlation coefficient is salutatory between −1.0 and 1.0. By using this correlation coefficient, hydrocarbon-bearing formations can be identified from pure water layers. This correlation analysis method can also be used in tight gas sands identification by establishing the correlation coefficients of porosity versus resistivity, density and neutron logs. Field examples illustrate that this method has played an important part in hydrocarbon-bearing identification in tight sandstone reservoirs.
Sichuan Basin Longmaxi Shale Gas Stimulation and Completion Case Study
Authors: Lv Zonggang , Wang Lin , Deng Sufen , Chong K. K. , Wang Qiang , Dumesnil Joe 
Published: November 2013

Abstract
The shale gas buzz in China continued in 2012. The Longmaxi Silurian age formation is one of three main target marine shales in China, the others being the Cambrian age Qiongzhusi and Niutitang. The Longmaxi serves as the more likely completion target for attempting to reach the production goals set forth by the government and state owned enterprises (SOEs). The Longmaxi is an interbedded mudstone/siltstone formation with an organic-rich carbonaceous interval at its base. It experienced widespread deposition and is predominantly found in what is currently known as the Sichuan basin in Sichuan province and the Chongqing municipality, with some evidence of its occurrence farther south and east into Guizhou and Hunan provinces. The lower organic-rich interval is the target for completion as it serves to store more hydrocarbon, which also lends itself to effective hydraulic fracture stimulation and flow capacity enhancement.
This paper is a case study of one Longmaxi horizontal well and the efforts that were made to benchmark the formation deliverability from a horizontal wellbore with multiple stages of completion. An analog formation was identified from the vertical pilot well logs to guide the stimulation design. A diagnostic fracture injection test (DFIT) was performed and analyzed, as well as some stimulation-related core testing being completed to further refine the proposed hydraulic fracture treatment. A summary of the treatments are presented, followed by conclusions and paths forward for further efforts with completing the Longmaxi.
A previous paper (Lv et al. 2012) cited completion of the first Cambrian age Qiongzhusi horizontal completion. This paper picks up from there, further detailing the shale gas development that is likely to be a major contributor to China's evolving energy mix.
An Assessment of Selected Rate-Decline Models for Horizontal Oil Wells in the Niobrara Formation
Authors: Savimaki Deborah , Seidle John P. 
Published: November 2013

Abstract
Horizontal well development targeting the Niobrara formation in the Denver-Julesburg (DJ) Basin in Colorado and Wyoming is gaining development momentum as the price of gas in the US has fallen and liquid rich plays have come into high demand. The low permeability Cretaceous age Niobrara formation is commonly encountered as three benches of naturally fractured limestones, marls and calcareous shale. The advent of horizontal drilling has allowed exploitation of this previously overlooked target in the DJ Basin.
Thermal maturity varies across the DJ basin, resulting in a variety of reservoir fluids in the Niobrara including dry gas (biogenic and thermogenic), wet gas, condensate, and oil. Two of the main oil fields in the DJ Basin are the Silo field, in Laramie County Wyoming, and the Wattenburg field, which is predominantly in Weld County, Colorado.
Oil has been produced out of the DJ Basin since 1901, however successful horizontal well development is still relatively recent in both fields. With the increased interest in Niobrara development, rate-decline analysis is used extensively by operators to estimate reserves and to evaluate potential locations for future drilling.
Various published models are available for rate-decline analysis. Arps rate-decline relationship has been the most widely used model, however subsequent authors have developed models modifying Arps, or in the case of unconventional and naturally fractured formations, developed completely new models, like Duong, for rate-decline analysis.
This paper will utilize production data for wells in Wattenburg and Silo fields to assess how appropriate different models are for rate-decline analysis in the naturally fractured Niobrara Formation.
A Workflow to Evaluate Mineralogy, Porosity, TOC, and Hydrocarbon Volume in the Eagle Ford Shale
Authors: Quirein John , Praznik Greg , Galford Jim , Chen Songhua , Murphy Eric , Witkowsky Jim 
Published: November 2013

AbstractThe Eagle Ford Shale hydrocarbon-fluid properties depend on the source rock maturity and, within the formation, occur in varying degrees of gas, gas condensate, and oil. Using conventional logs and pyrolysis data, several log-core regressions, such as delta log R, density, and uranium, can be derived to predict total organic carbon (TOC). TOC can be used with geochemical elemental measurements for a more accurate assessment of the formation kerogen and mineralogy, as well as hydrocarbon volumes. Nuclear magnetic resonance (NMR) porosity measures an apparent total porosity in the organic shale plays, measuring only the fluids present and excludes the kerogen. The complex refractive index method (CRIM) with the mineralogy log data can be used to compute accurate dielectric porosities, which exclude both kerogen and hydrocarbon. Integrating the core TOC, predicted TOC, mineral analysis, NMR, and dielectric information, a final verification of the kerogen volume, porosity, hydrocarbon content, and mineral analysis can be assessed.This paper will describe the integration of conventional logs, a geochemical log, an NMR log, and dielectric to predict TOC, kerogen volume, and hydrocarbon volume, as well as total porosity and mineralogy. The log data is compared to core data from three Eagle Ford wells. Based on the results from these three wells, a comprehensive workflow is developed for unconventional source rock reservoir interpretation. The workflow is then applied to two additional Eagle Ford wells and the results are compared to core data. While the workflow is demonstrated with Eagle Ford data it is believed that it will be applicable in other unconventional source rock reservoirs. It will be demonstrated how the proposed approach will help eliminate some coring operations and can be used to help make decisions on optimum lateral placement.
Integrated Geochemical, Geomechanical and Geological (3G) Study of Lower Baong Shale Formation for Preliminary Shale Gas Prospectivity in the North Sumatra Basin
Authors: Bahesti F.. , Subroto E. A. , Manaf N. A. , Sadirsan W.. , Wahyudin M.. 
Published: November 2013

Abstract
The most common fallacy in evaluating shale gas potential in a basin is treated similar to those produced in the United States. In fact, each basin has unique characteristics that influence shale facies type and depositional. Lower Baong shale is responsible for source rock filled up sandstones reservoir in the oil and gas field in the North Sumatra Basin. This study reveals the data and facts from the laboratory, drilling, wireline well logs and seismic through the integrated study of geochemistry, geomechanics and geological synthesis of Lower Baong Formation. An understanding of shale geochemistry, mineralogy and geomechanics is very important to understand how the shale reservoir has the potential to reserve and produce when carried out stimulation. Geochemical laboratory analysis is used to determine the richness, maturity and kerogen type. This information is limited to a certain depth point, so that it is necessary to conduct calibrations in order to estimate the shale productive reservoir interval on a wireline log scale. Limited core data and rock mechanics laboratory analysis represented by mineralogy then also calibrated with brittleness index. Thus, geochemical and geomechanical log model tied to the seismic data, is a very useful tool for formation evaluation and broaden the understanding of shale reservoir facies distribution. Understanding shale facies needed to design fracturing horizontal hole in more detail. This study also classify shale based on organic richness, maturity, type, shale strengthness, shale brittleness and clay content. Shale facies in Lower Baong shale can be divided into 3 facies of sweet spot area. Siliceous calcareous mudstone has high potential for shale gas with 2–3.5% of TOC, II-III of kerogen type, maturity depth from 2300m, 350–425m of sweet spot thickness, 10000–18000psia of UCS, 3000–4000 psia of Young modulus, 0.18–0.22 of Poisson ratio and associated with foreland basin fill deep. Silty-shaly calcareous mudstone has medium potential for shale gas which is associated with foreland basin fill slope. Silty-shaly dolomitic mudstone is associated with foreland basin fill edge that has high potential for shale. The integrated approach for geochemistry and geomechanics is expected to reduce risk in shale gas exploration.
Unconventional Completions - an Operational Comparison
Authors: Burton W. Aaron 
Published: November 2013

AbstractIn the last seven years the oil and gas industry has seen significant changes in the price and supply of hydrocarbons, and new production from low-permeability unconventional reservoirs that require multistage hydraulic fracturing is playing a major role in the additional supply. To effectively produce these reservoirs, reservoir characterization, horizontal drilling, multistage completions, and multistage hydraulic fracturing are requirements in most plays. Most of these technologies have been used in other applications for many years, but combined they provide the key to unlocking these reservoirs that were considered uneconomical in the past. This paper will focus on the wellbore completion technologies that enable hydraulic fracturing of multiple stages.Three completion techniques have emerged as the most effective and efficient in these types of formations: plug-and-perf, ball-activated frac sleeve completions, and coiled tubing-activated completions. All these wellbore completions serve the same functions of providing annular isolation, through-tubing isolation, and diversion needed to hydraulically fracture multiple stages, but each has different methods and devices of doing so. Recent advances in technology have enabled all three completions to use cement or openhole packers to provide the required annular isolation, so if one method of isolation is proven to be superior in one application, any of the three completion techniques can be used. Now the question is, "How do I choose the right completion for my application?" The deciding factors to answer this question now become operational efficiency, cost, logistics, flexibility, and application. This paper will present several scenarios where one type of completion system could be more beneficial or efficient in certain applications.The benefits and considerations of each completion must be analyzed to select the most efficient completion for certain applications. The primary purpose of this paper is to discuss these benefits and considerations and how they compare in different applications from an operations point of view.
Critical Comparative Assessment of a Novel Approach for Multi-mineral Modeling in Shale Gas: Results from an Evaluation Study of Marcellus Shale
Authors: Singh Sidharth , Qiu Fuming , Morgan Neal , Nath Gitashree , Pritchard Timothy 
Published: November 2013

Abstract
The highly heterogeneous nature of the micro fabric, and complex gas storage mechanisms, in shale formations can present significant evaluation challenges for unconventional formation evaluation. In this paper we present a new and robust methodology for shale formation characterization, termed "Simultaneous Core Log Multi-mineral Inversion (SCLMI)". This methodology executes a series of iterative processes, and computational logic, to provide an optimum solution for mineral volume, organic content, porosity and fluid saturation from the simultaneous inversion of log and core data utilizing an underlying physically consistent petrophysical model. The SCLMI methodology is flexible enough to accommodate advanced geo-mechanical log outputs, but also has the flexibility to deal with situations where datasets are more limited, and it can significantly reduce the data interpretation processing times required when analyzing complex formations. Critical factors for the successful implementation of the methodology, however, relate to the consistency in analysis and control over input parameters to ensure these outputs are consistent with the underlying petrophysical model. The methodology can also be extended to improve formation evaluation in conventional formations.
The flexibility and robustness of the SCLMI methodology has been demonstrated for a number of different shale gas and liquid rich plays, where it facilitates the development of optimized log interpretation parameters for calibration wells, which can then be readily applied to other geologically similar wells. In this paper, we illustrate the utility of the methodology using examples from the Marcellus Shale. The value of this methodology is further demonstrated by performing a rigorous comparative assessment against standard shale gas formation evaluation techniques – empirical correlations and geochemical logs based multi-mineral interpretations provided by a major service provider. The methodology works particularly well in the challenging lower Marcellus formation, which shows high gamma ray, total organic and heavy mineral content. In comparison, whilst empirical correlations provide reasonable predictive results for organic content and gas-filled porosity they are unable to accurately characterize mineral volumes, and un-calibrated geochemical log based multi-mineral interpretations are show to exhibit a significant and consistent bias in total porosity, water saturation and heavy mineral volume calculations.
Laboratory Permeability and Diffusivity Measurements of Unconventional Reservoirs: Useless or Full of Information? A Montney Example from the Western Canada Sedimentary Basin
Authors: Cui Albert , Brezovski Ron 
Published: November 2013

Abstract
Permeability is one of the most critical parameters characterizing unconventional (shale or tight) gas and oil reservoirs for resource evaluation and exploitation. Permeability is also perhaps the most difficult parameter to be accurately characterized because it is not just a single number but a complicate property with attributes that depend on many factors (namely sampling or testing scale, pore shape and size and distribution, different transport mechanisms, different test fluids, pore pressure, effective stress, and even temperature). Laboratory permeability measurements are mainly conducted on cores or smaller samples. The size and scale of laboratory measurements are hence severely limited as compared to the meters or kilometers scale of exploration or producing fields. Even in the scale of centimeters or less, for the same core samples, laboratory measurements likely yield variable permeability spanning several orders of magnitudes, leading to seemingly useless laboratory permeability for field applications. In this study, using samples from the Montney Formation in the Western Canada Sedimentary Basin as an example, we first present contrasting laboratory permeability measurements with different methods or experimental conditions. Explanations to the seemingly contradictory permeability measurements are then provided in context of different transport modes in highly heterogeneous microporous unconventional reservoir rocks, highlighting that the contrast laboratory measurements are not useless but full of information for understanding the complex characteristics of microporous unconventional rocks. Appropriate experiments to determine the appropriate permeability and their application to field problems are also discussed, which is helpful for petroleum geologists and engineers to better understand the unique permeability system of unconventional reservoirs and hence to make optimal decisions for successful unconventional resource exploitation.
Improving Hydraulic Fracture Geometry by Directional Drilling in a Coal Seam Gas Formation
Authors: Bentley Philip J. , Jiang Hui , Megorden Mike 
Published: November 2013

Abstract
Hydraulic fracturing has been widely used to develop coal seam gas (CSG) resources worldwide and improve gas production from CSG wells. An optimal stimulation in CSG, in particular with lower permeability coals lacking a well-developed cleat system, creates a fracture with sufficient length and orientation along the maximum horizontal stress (σHmax) direction such that the fracture intersects the existing hydraulically-conductive natural fracture network in an a way that maximizes the stimulation effect. In the Walloon Coal Measures (WCM) in the Surat Basin in eastern Australia, induced fractures have been observed to grow in a way which does not optimally intersect the natural fracture network or conform to the σHmax azimuth. This resultant stimulation of the natural fractures, as opposed to the construction of a conductive path crosscutting the natural fracture system and linking it to the wellbore, has proven to reduce the effect of stimulation in vertical wells.
This paper will present a two-well program in the WCM where the wells have been directionally drilled along the σHmax direction with different deviation angles from vertical. Both wells have been stimulated with a combination of treated water with a low proppant concentration, followed by crosslinked-gelled water with a higher proppant concentration. There are two microseismic observation wells and twenty one tiltmeters to map the fracture propagation and determine the fracture geometry.
The diagnostic results from microseismic wells and surface tiltmeters for each hydraulic fracturing stage will be outlined in this paper. These results, compared with similar diagnostic results from nearby offset vertical wells, are encouraging and indicate consistent fracture growth along the maximum horizontal direction for all stages. These results indicate that hydraulic fracture geometry can be improved by directional drilling.