bluuebunny/crossref_metadata_2025_split huggingface dataset:
A comparative study of total quality management of health care system in India and Iran
Authors: Heidari Gorji Ali Morad , Farooquie Jamal A 
Published: December 2011

Abstract

Background
Total quality management (TQM) has a great potential to address quality problems in a wide range of industries and improve the organizational performance. The growing need to take initiatives by hospitals in countries like India and Iran to improve the service quality and reduce wastage of resources has inspired the authors to develop a survey instrument to measure health care quality and performance in the two countries.

Methods
Based on the Baldrige health care criteria for performance excellence 2009-2010 and the guidelines proposed by the American Hospitals Association for hospitals in pursuit of excellence, compared health care services in three countries. The data are collected from the capital cities and their nearby places in India and Iran. Using ANOVAs, three groups in quality planning and performance have been compared.

Result
Results showed there is significantly difference between groups and in no case the hospitals from India and Iran are found scoring close to the benchmarks. The average scores of Indian and Iranian hospitals on different constructs of the IHCQPM model are compared with the major results achieved by the recipients of the MBNQ award.

Conclusion
In no case the hospitals from India and Iran are found scoring close to the benchmarks (Baldrige health care criteria for performance excellence 2009-2010 and the guidelines proposed by the American Hospitals Association for hospitals). These results suggested to health care services more attempt to achieve high quality in management and performance.
Biomarkers in Cardiovascular Clinical Trials: Past, Present, Future
Authors: Halim Sharif A , Newby L Kristin , Ohman E Magnus 
Published: December 2011

Abstract

BACKGROUND
Cardiovascular (CV) clinical trials are instrumental in understanding treatment effects and offer insights into the natural progression of CV disease. Biomarkers are a critical component of patient selection, end point definition, and safety monitoring, and clinical trials provide a platform for the discovery and validation of new biomarkers that may augment the understanding of disease mechanisms, risk stratification, and/or clinical decision-making.

CONTENT
We review the roles that biomarkers have played in CV clinical trials and roles that CV clinical trials have played and will continue to play in the discovery and validation of biomarkers and their implementation in clinical practice. Large biobanks containing multiple specimen types are increasingly being created from patients enrolled in clinical trials, and such biobanks, when coupled with advances in molecular techniques and bioinformatics, promise to accelerate our understanding of CV disease mechanisms and to help fuel the discovery and development of novel therapeutic targets and biomarkers of risk and treatment response.

SUMMARY
The past, present, and future of biomarkers and clinical trials have been and will remain intertwined. Biomarkers were once the workhorses of patient selection and end point definition in clinical trials; more recently, clinical trials have been the proving ground for individual biomarkers. Attention to biobanking and the application of modern informatics and molecular techniques to samples collected within clinical trials will usher in the era of stratified and personalized medicine.
Multiscale Finite-Volume Formulation for the Saturation Equations
Authors: Zhou H.. , Lee S.H.. H. , Tchelepi H.A.. A. 
Published: December 2011

Summary
Recent advances in multiscale methods have shown great promise in modeling multiphase flow in highly detailed heterogeneous domains. Existing multiscale methods, however, solve for the flow field (pressure and total velocity) only. Once the fine-scale flow field is reconstructed, the saturation equations are solved on the fine scale. With the efficiency in dealing with the flow equations greatly improved by multiscale formulations, solving the saturation equations on the fine scale becomes the relatively more expensive part. In this paper, we describe an adaptive multiscale finite-volume (MSFV) formulation for nonlinear transport (saturation) equations. A general algebraic multiscale formulation consistent with the operator-based framework proposed by Zhou and Tchelepi (SPE Journal, June 2008, pages 267–273) is presented. Thus, the flow and transport equations are solved in a unified multiscale framework. Two types of multiscale operators—namely, restriction and prolongation—are used to construct the multiscale saturation solution. The restriction operator is defined as the sum of the fine-scale transport equations in a coarse gridblock. Three adaptive prolongation operators are defined according to the local saturation history at a particular coarse block. The three operators have different computational complexities, and they are used adaptively in the course of a simulation run. When properly used, they yield excellent computational efficiency while preserving accuracy. This adaptive multiscale formulation has been tested using several challenging problems with strong heterogeneity, large buoyancy effects, and changes in the well operating conditions (e.g., switching injectors and producers during simulation). The results demonstrate that adaptive multiscale transport calculations are in excellent agreement with fine-scale reference solutions, but at a much lower computational cost.
Automation of Drawworks and Topdrive Management To Minimize Swab/Surge and Poor-Downhole-Condition Effects
Authors: Cayeux Eric , Daireaux Benoît , Dvergsnes Erik Wolden 
Published: December 2011

Summary
Careless axial and rotational movement of the drillstring can cause formation fracturing or fluid influx, resulting in costly remedial actions. With increasingly complex wellbore geometries and narrow geopressure windows, it is not always obvious for the driller how to estimate accurately the real maneuvering limits of the drawworks and the topdrive, especially under poor downhole conditions. The solution presented in this paper uses continuously updated safeguards applied to the drilling-control system to maintain a downhole pressure within the acceptable limits of the openhole formations. It automatically stops the movement of the drillstring in the case of abnormal hookloads or surface torques. Because automatic actions can be triggered in the case of an unexpected situation, some standard procedures have been fully automated, including friction tests and back reaming.
Numerical models are used to constantly calculate the maximum accelerations and velocities, which can be applied to the drillstring in the current drilling conditions. The resulting envelope of protection is dependent on many factors. Therefore, a proper evaluation of the downhole conditions is of paramount importance for the quality of the calculated safeguards. An automatic calibration of the physical models, on the basis of surface measurements, is at the heart of the system. The calibrated mechanical models are used to determine the limits for abnormal surface torques or hookloads. It is, therefore, possible to take actions automatically in the case of overpull, set-down weight, or high torque.
In 2008, a preliminary version of the system was tested during the drilling of a well in the North Sea. Even though the control algorithms did work well at that time, it was noticed that, in some circumstances, the drilling-control system would not be ready in time for fast-changing drilling conditions. An improved version of the drawworks and topdrive automation system has been tested during the drilling of three North Sea wells in the spring of 2009. In this last version, the response time of the system has been optimal at all times. The drillers involved in the testing of the system have found the system useful and user friendly.
Analytical Upgridding of Geocellular Mode in the Presence of Gravity-Dominated Displacement
Authors: Rittirong Ake , Kelkar Mohan 
Published: December 2011

SummaryIn simulating enhanced-oil-recovery (EOR) processes, it is critical that all the flow behaviors be properly accounted for in the simulation. Because of computation limitations, long calculation time, and complexity of physics, geological models cannot be directly used for fieldwide simulations. Upgridding reduces the number of gridblocks in the simulation model and therefore makes the simulation more efficient. An appropriate upgridding process needs to preserve the dynamic behavior of the fine-scale model.We propose such an analytical methodology. Our new technique is based on preserving the characteristics, which are based on the fractional-flow concept specifically modified for vertical flow between the layers. We develop our method with a specific application to gravity-dominated displacement. In upgridding the fine-scale model, we have developed a criterion by which the sequence in which the fine-scale layers are combined is proposed such that fractional-flow characteristics based on the fine-scale model are honored. Using this methodology, we can determine not only the sequence in which layers are combined, but also to what extent we can upgrid the fine-scale model.The proposed methodology is developed for two-phase, 2D flow under the effect of gravity-segregated displacement. However, it is also tested for three-phase, 3D flow in gravity-dominated displacement with moderate effect of viscous and capillary forces. The proposed solution is analytical; therefore, it is computationally efficient. We have validated the methodology with both synthetic and field examples and demonstrate that the proposed methodology is superior to conventional proportional layering and variance-based methodologies.
Investigation of Pore-Scale Mixed Wettability
Authors: Kumar Munish , Fogden Andrew , Senden Tim , Knackstedt Mark 
Published: December 2011

Summary
The efficiency of secondary and tertiary-recovery processes can be improved by properly taking into account the reservoir's true wettability state. Most reservoirs are assumed to be mixed-wet, based on core-scale indices such as Amott-Harvey and USBM. Oil/brine/ mineral contact-angle measurements on smooth substrates offer some molecular-scale input and estimates for network modeling. However, direct experimental techniques to characterize wettability and validate the mixed-wet model at the pore scale in real or model rocks remain elusive. One promising avenue is the use of microtomography (µ-CT) to map the pore-scale distribution of multiple phases in miniplugs. A second, complementary approach involves the study of model rocks based on bead packs to probe the surface chemistry of the minerals exposed to crude oil and brine in pore confinement. Integrating the two approaches described in the current study provides a promising means of explaining the observed multiphase-fluid occupancy in pores by combining the detailed knowledge of the 3D pore structure and information on the surface chemistry of its walls.
Thermomagnetic Analyses of the Permeability-Controlling Minerals in Red and White Sandstones in Deep Tight Gas Reservoirs: Implications for Downhole Measurements
Authors: Ali Arfan , Potter David K. 
Published: December 2011

Summary
Our recent work on deep tight gas reservoirs containing red and white sandstones (Potter et al. 2009) has suggested that the presence of small amounts of hematite in reservoir samples can have a dramatic effect on permeability. Such conclusions were made using laboratory-based low- and high-field magnetic-susceptibility measurements on reservoir-rock samples and by comparing these measurements with the permeability data. These rapid, nondestructive magnetic measurements have been applied previously in clastic reservoir samples (Potter 2007; (Ivakhnenko 2006; Ivakhnenko and Potter 2008; Potter and Ivakhnenko 2008) and carbonate reservoir samples (Al-Ghamdi 2006; Potter et al. 2011). However, such laboratory-based analyses are not representative of the downhole in-situ conditions, especially in deep gas reservoirs where the temperature can reach quite high values. Typical tight-gas-reservoir depths can reach approximately 4000 m (Abu-Shanab et al. 2005) and 6000 m (Tang et al. 2008), and the equivalent temperatures would measure 131 and 192°C, respectively, if one assumes the normal geothermal gradient (Mayer-Gurr 1976).
This paper investigates the in-situ magnetic properties of deep tight gas reservoir samples (containing permeability-controlling reservoir minerals hematite and illite) by means of laboratory experiments to model downhole temperature conditions. We perform magnetic hysteresis measurements at various temperatures in order to identify and quantify mineralogy and model changes in the magnetic behavior of these minerals at in-situ downhole conditions. From these measurements, we are able to show whether the mineralogy or domain state of the permeability-controlling minerals is likely to change with temperature in deep gas reservoirs. These changes can potentially have a major effect on permeability.
We also demonstrate that there are strong correlations between core-permeability and magnetic-susceptibility data in these tight-gas-reservoir samples. The permeability is low in red sections of the core wherever there is hematite.
Shale Gas-in-Place Calculations Part I: New Pore-Scale Considerations
Authors: Ambrose Ray J. , Hartman Robert C. , Diaz-Campos Mery , Akkutlu I. Yucel , Sondergeld Carl H. 
Published: December 2011

SummaryUsing focused-ion-beam (FIB)/scanning-electron-microscope (SEM) imaging technology, a series of 2D and 3D submicroscale investigations revealed a finely dispersed porous organic (kerogen) material embedded within an inorganic matrix. The organic material has pores and capillaries having characteristic lengths typically less than 100 nm. A significant portion of total gas in place appears to be associated with interconnected large nanopores within the organic material.Thermodynamics (phase behavior) of fluids in these pores is quite different; gas residing in a small pore or capillary is rarefied under the influence of organic pore walls and shows a different density profile. This raises serious questions related to gas-in-place calculations: Under reservoir conditions, what fraction of the pore volume of the organic material can be considered available as free gas, and what fraction is taken up by the adsorbed phase? How accurately is the shale-gas storage capacity estimated using the conventional volumetric methods? And finally, do average densities exist for the free and the adsorbed phases?We combine the Langmuir adsorption isotherm with the volumetrics for free gas and formulate a new gas-in-place equation accounting for the pore space taken up by the sorbed phase. The method yields a total-gas-in-place prediction. Molecular dynamics simulations involving methane in small carbon slit-pores of varying size and temperature predict density profiles across the pores and show that (a) the adsorbed methane forms a 0.38-nm monolayer phase and (b) the adsorbed-phase density is 1.8–2.5 times larger than that of bulk methane. These findings could be a more important consideration with larger hydrocarbons and suggest that a significant adjustment is necessary in volume calculations, especially for gas shales high in total organic content. Finally, using typical values for the parameters, calculations show a 10–25% decrease in total gas-storage capacity compared with that using the conventional approach. The role of sorbed gas is more important than previously thought. The new methodology is recommended for estimating shale gas in place.
A New Deconvolution Technique Based on Pressure-Derivative Data for Pressure-Transient-Test Interpretation
Authors: Onur Mustafa , Kuchuk Fikri J. 
Published: December 2011

Summary
In this paper, we present a new deconvolution method that removes the dependency of the deconvolved constant-rate drawdown responses on the initial reservoir pressure. It is well known that the late-time periods in particular of the deconvolved responses from the recent pressure-rate deconvolution methods are dependent on the initial reservoir pressure. A small error in the initial reservoir pressure could make a significant difference in the late-time periods of the deconvolved responses that can lead to an incorrect interpretation model, particularly misinterpretation of the boundaries. The new method presented is based on pressure-derivative data rather than pressure data that are used in all published deconvolution algorithms. Using pressure-derivative data in deconvolution leads to a nonlinear least-squares objective function that is different from those used in the earlier deconvolution methods and eliminates the dependency of the deconvolved responses on the initial reservoir pressure. Therefore, the new method minimizes incorrect interpretation because of an error or uncertainty in the initial reservoir pressure. We apply the new method to both simulated and field pressure-transient data sets. The results show that the new method offers a significant advantage over the earlier deconvolution methods for pressure-transient-test interpretation in cases where the initial reservoir pressure is unknown or uncertain.
Numerical Simulations of Sand-Screen Performance in Standalone Applications
Authors: Mondal Somnath , Sharma Mukul M. , Chanpura Rajesh A. , Parlar Mehmet , Ayoub Joseph A. 
Published: December 2011

Summary
The selection of optimum screens for standalone screen (SAS) applications has historically been based on experimental data, rules of thumb, or correlations. Recent sand-retention tests conducted in various laboratories offer empirical screen-selection criteria on the basis of different sand-size-distribution parameters. Unfortunately, these experiments have their own limitations. They provide substantially different results, depending on how the tests are conducted and interpreted, leading to significant differences in the recommended screen type and screen-opening size for any given sand sample. To resolve these inconsistencies and to understand the physics of the problem better, this paper presents 3D numerical simulations to evaluate the performance of wire-wrapped sand screens and ultimately to develop systematic screen-selection criteria.
In this paper, a new method is presented to estimate the mass and size distribution of the solids produced through wire-wrap screens. The method uses the entire particle size distribution of the formation sand and is validated with experimental and numerical data. The new method allows us to evaluate the performance of different screens without running expensive and sometimes inconclusive experiments, enhances our understanding of screen performance, and helps to design sand screens better to meet performance criteria under a wide variety of conditions.
We first present results from 3D, discrete-element computer simulations of sand screens placed in contact with granular sand-packs of approximately 100,000 particles. The numerical model computes the mass and the size distribution of the solids produced. The effect of the most important parameters, such as friction coefficient, fluid viscosity, pressure gradient, and ratio of screen-opening size to sand size, on the mechanism of bridge formation and amount of sand produced is studied using both monodispersed and polydispersed systems.
The results have helped resolve some key questions about the physics of sand bridge formation. Numerous simulations are conducted to replicate the experimental conditions over a wide range of screen-opening/sand-size ratios for wire-wrap screens. Good agreement is observed between laboratory experiments and the simulations.
Field-/Well-Integrity Issues, Well-Abandonment Planning, and Workover Operations on an Inadequately Abandoned Well: Peace River, Alberta, Case Study
Authors: Diller C.. 
Published: December 2011

Summary
Maintaining well integrity for field life-cycle operations is a major factor that must be taken into account in the planning and execution of all well-engineering activities. Some legacy wells are not properly abandoned to prevent the contamination of secondary reservoirs or groundwater from other producing hydrocarbons or from emerging carbon-capture and acid-gas-storage projects being planned by both oil and gas operators and government research groups. If these wells are not identified and abandoned properly, there is a high risk of negative impact to the environment, operator reputation, and the economics of field operations.
This case study will examine the complex re-entry and reabandonment of a well in the Peace River region of Alberta, Canada. In the process of developing the plan to re-enter and abandon this well, a methodology for abandonment planning was adopted with three essential attributes: The abandonment should provide effective isolation of all critical zones; operations should allow for evaluation and confirmation of zonal isolation; and the final condition of the well should allow for a simple re-entry to remediate future isolation problems. Throughout the planning and execution of the program, the regulating agency was integrated into the decision-making process. To complete the abandonment, technologies such as casing drilling, downhole cameras, and magnetic ranging were employed along with directional-drilling, coiled-tubing, and fishing operations. Upon completion, the effectively executed abandonment program met or exceeded prescribed technical and regulatory requirements. The positive results of performing this operation included mitigating environmental impacts, delaying the capital-intensive construction of a future sour-gas-treatment plant, and allowing the extended operation of the Peace River complex (PRC).
Development of Water-Based Drilling Fluids Customized for Shale Reservoirs
Authors: Deville Jay P. , Fritz Brady , Jarrett Michael 
Published: December 2011

Summary
Drilling activity has increased dramatically in unconventional shale gas reservoirs. The drilling fluid of choice in these shale plays is often nonaqueous-based fluid (NAF). While NAFs can provide advantages such as shale stabilization, lubricity, and contamination tolerance, environmental consequences and associated costs are an issue. These disadvantages cause operators to seek water-based muds (WBMs) for drilling many of these gas reservoirs.
Despite some operational similarities, a wide variety of unique downhole conditions can be found in the shale plays. Shale mineralogy and bottomhole temperature (BHT) represent just two highly variable critical factors in unconventional gas reservoirs. Therefore, a single water-based solution for addressing shale plays globally is not a realistic option. Instead, a customized approach that delivers WBMs formulated specifically for a given shale play has been pursued.
Customization relies on detailed analysis of the well parameters of a given shale play. This analysis includes not only the shale morphology and lithology but also well drilling program plans, environmental factors, and other reservoir-specific considerations. Applying appropriate drilling-fluid chemistries on the basis of this detailed analysis has led to the successful field deployment of a number of new shale fluids.
Details of the process used for customizing a WBM for a shale play, as well as specific examples of new fluids developed for the Barnett, Fayetteville, and Haynesville shales, are presented in this paper. Full laboratory development and testing are described. Additionally, field-trial results are presented that show that specially designed WBMs can provide performance comparable to that of NAFs, but with enhanced environmental and economic benefits. Application of the customization process to develop WBMs for other shale plays around the globe is also discussed.