bluuebunny/crossref_metadata_2025_split huggingface dataset:
Exogenous Glucagon-Like Peptide-1 for Hyperglycemia in Critically Ill Patients
Authors: Pinelli Nicole R , Jones Mathew C , Monday Lea M , Smith Zachary , Rhoney Denise H 
Published: December 2011

OBJECTIVE: To review literature evaluating the safety and efficacy of exogenous glucagon-like peptide-1 (GLP-1) for hyperglycemia in critically ill patients. DATA SOURCES: PubMed was queried (inception to September 3, 2011), using the search term glucagon-like peptide-1. The search was limited to studies published in English and conducted in humans. Regular and late-breaking abstracts from the American Diabetes Association Scientific Sessions in 2009 and 2010 were also searched using the same search term. STUDY SELECTION AND DATA EXTRACTION: All abstracts were screened for eligibility, which consisted of studies reporting the effects of intravenous GLP-1 administration on glycemic control in critically ill patients. Data extracted from eligible trials included study and population characteristics, measures of glycemic efficacy, and safety. DATA SYNTHESIS: Our search resulted in the identification of 2105 potentially relevant articles; of those, 7 were reviewed. All included publications evaluated the use of intravenous GLP-1 (1.2-3.6 pmol/kg/min) compared with insulin or placebo infused for 4.5-72 hours in critically ill patients. The majority (n = 4) of studies included only patients from a surgical intensive care setting, and 71% (n = 5) of trials included those with a history of diabetes. Relative to insulin or placebo, GLP-1 therapy effectively lowered blood glucose concentrations in all trials. Out of 81 total study participants receiving GLP-1, only 4 had documented hypoglycemia (<60 mg/dL), 4 reported nausea, and 2 experienced vomiting. No other serious adverse events were reported. CONCLUSIONS: All trials reviewed suggest that GLP-1 may be a promising agent for the management of hyperglycemia in critically ill patients, regardless of diabetes status. Additional studies in more heterogeneous intensive care settings comparing GLP-1 with insulin, the current standard of care, are necessary. These studies should evaluate long-term safety and effectiveness of GLP-1 therapy on morbidity and mortality outcomes in critically ill populations.
Estimating Glomerular Filtration Rates by Use of Both Cystatin C and Standardized Serum Creatinine Avoids Ethnicity Coefficients in Asian Patients with Chronic Kidney Disease
Authors: Teo Boon Wee , Xu Hui , Wang Danhua , Li Jialiang , Sinha Arvind Kumar , Shuter Borys , Sethi Sunil , Lee Evan J C 
Published: December 2011

Abstract

BACKGROUND
The Chronic Kidney Disease Epidemiology Collaboration (CKD-EPI) equation is most accurate for estimating glomerular filtration rate (GFR) but requires an adjustment for African-American patients. Estimation equations are also improved with the use of serum cystatin C combined with standardized creatinine. Combination equations have been derived by the CKD-EPI and Chinese investigators. We investigated whether these cystatin C–based equations improve estimation adequately, so that adjustments for ethnicity are not required in a multiethnic Asian population with chronic kidney disease (CKD).

METHODS
This was a cross-sectional study of 232 stable CKD patients who underwent GFR measurements using 3-sample plasma clearances of 99mTc-DTPA, and for whom serum cystatin C and creatinine were quantified.

RESULTS
For all patients, the median biases with cystatin C equations were generally greater than with the CKD-EPI equation, and precision and root mean square error (RMSE) were not significantly better. However, the combination serum creatinine and cystatin C equation improved the precision, RMSE, and percentage of estimated GFR to within 15% and 30% of the measured GFR (57.3% vs 50.0%, 88.4% vs 82.8%, respectively). The derived ethnicity coefficients for the combination equation were all &gt;1 (1.009–1.082) but small, suggesting that coefficients are not required. The Chinese-specific equations were more biased and performed more poorly than the CKD-EPI equation.

CONCLUSIONS
The use of a cystatin C and creatinine combination equation for estimating GFR in a multiethnic Asian population with CKD does not require ethnicity coefficients because the derived coefficients are very close to each other.
Multiple-Mixing-Cell Method for MMP Calculations
Authors: Ahmadi Kaveh , Johns Russell T. 
Published: December 2011

SummaryThe minimum miscibility pressure (MMP) is a key parameter governing the displacement efficiency of gasfloods. There are several methods to determine the MMP, but the most accurate methods are slim-tube experiments, analytical methods, and numerical-simulation/cell-to-cell methods. Slim-tube experiments are important to perform because they use actual crude oil, but they are costly and time consuming. Analytical methods that use the method of characteristics (MOC) are very fast and help to understand the structure of gasfloods. MOC, however, relies on finding the unique and correct set of key tie lines in the displacements, which can be difficult. Slim-tube simulation methods and their simplified cell-to-cell derivatives require tedious fluid and rock inputs, and their MMP estimates can be clouded by dispersion.This paper presents a simple and accurate multiple-mixing-cell method for MMP calculations that corrects for dispersion, and is faster and less cumbersome than 1D simulation methods. Unlike previous mixing-cell methods, our cell-to-cell mixing model uses a variable number of cells, and is independent of gas/oil ratio, volume of the cells, excess oil volumes, and the amount of gas injected. The new method only relies on robust P/T flash calculations using any cubic equation-of-state (EOS). The calculations begin with only two cells and perform additional cell-to-cell contacts between resulting equilibrium-phase compositions based on equilibrium gas moving ahead of the equilibrium liquid phase. We show for a variety of oil and gas compositions that all key tie lines can be found to the desired accuracy, and that they are nearly identical to those found using analytical MOC methods. Our approach, however, is more accurate and robust than those from MOC because we do not make approximations regarding shocks along nontie-line paths, and the unique set of key tie lines converges automatically.The MMP using our mixing-cell method can be calculated in minutes using an Excel spreadsheet and is estimated from a novel bisection method of the minimum tie-line lengths observed in the cells at four or five pressures. Our multiple-mixing-cell method can calculate either the MMP or the minimum miscibility for enrichment (MME) independent of the number of components in the gas or oil. Our approach further supports the notion that the MMP is independent of fractional flow because we obtain the same key tie lines independent of how much fluid is moved from one cell to another.
Dynamic Data Integration and Quantification of Prediction Uncertainty Using Statistical-Moment Equations
Authors: Likanapaisal P.. , Li L.. , Tchelepi H.A.. A. 
Published: December 2011

SummaryThe use of a probabilistic framework for dynamic data integration (history matching) has become accepted practice. In this framework, one constructs an ensemble of reservoir models, in which each realization honors the available (static and dynamic) information. The variations in the flow performance across the ensemble provide an assessment of the prediction uncertainty due to incomplete knowledge of the reservoir properties (e.g., permeability distribution). Methods based on Monte Carlo simulation (MCS) are widely used because of the generality and simplicity of MCS. As a black-box approach, only pre- and post-processing of conventional flow simulations are needed. To achieve reasonable accuracy in estimating the statistical moments of flow-performance predictions, however, large numbers of realizations are usually necessary. Here, we use a different, and direct, approach for model calibration and uncertainty quantification. Specifically, we describe a statistical-moment-equations (SMEs) framework for both the forward and inverse problems associated with immiscible two-phase flow. In the SME method, the equations governing the statistical moments of the quantities of interest (e.g., pressure and saturation) are derived and solved directly. We assume that statistical information and a few measurements are available for the permeability field. As for the dynamic properties, we assume that measurements of pressure, saturation, and flow rate are available at a few locations and at several times. For the forward problem, the flow (pressure and total-velocity) SMEs are solved on a regular grid, while a streamline-based strategy is used to solve the transport SMEs. We use a kriging-based inversion algorithm, in which the first two statistical moments of permeability are conditioned directly using the available dynamic data. We analyze the behaviors of the saturation moments and their evolution as they are conditioned on measurements, in both space and time. Moreover, we discuss the relationship between the widely used MCS-based Kalman-filter approach and our SME inversion scheme.
Non-Darcy Porous-Media Flow According to the Barree and Conway Model: Laboratory and Numerical-Modeling Studies
Authors: Lai Bitao , Miskimins Jennifer L. , Wu Yu-Shu 
Published: December 2011

Summary
This paper presents the results of our new experimental studies conducted for high flow rates through proppant packs, which show that the Barree and Conway (2004) flow model is capable of overcoming limitations of the Forchheimer non-Darcy equation at very high flow rates. To quantify the non-Darcy flow behavior using the Barree and Conway model, a numerical model is developed to simulate non-Darcy flow. In addition, an analytical solution is presented for steady-state linear non-Darcy flow and is used to verify the numerical-simulation results. The numerical model incorporates the Barree and Conway model into a general-purpose reservoir simulator for modeling multidimensional, single-phase non-Darcy flow in porous and fractured media and supplements the laboratory findings. The numerical model is then used to perform sensitivity analysis of the Barree and Conway flow model's parameters and to investigate transient behavior of non-Darcy flow at an injection well.
Practical Solutions for Pressure-Transient Responses of Fractured Horizontal Wells in Unconventional Shale Reservoirs
Authors: Brown M.. , Ozkan E.. , Raghavan R.. , Kazemi H.. 
Published: December 2011

Summary
This paper presents an analytical trilinear-flow solution to simulate the pressure-transient and production behaviors of fractured horizontal wells in unconventional shale reservoirs (Ozkan et al. 2009). The model is simple, but versatile enough to incorporate the fundamental petrophysical characteristics of shale reservoirs, including the intrinsic properties of the matrix and the natural fractures. Special characteristics of fluid exchange among various reservoir components may also be considered. Computational convenience of the trilinear-flow solution makes it a practical alternative to more rigorous but computationally intensive and time-consuming solutions. Another advantage of the trilinear-flow solution is the convenience in deriving asymptotic approximations that provide insight about potential flow regimes and the conditions leading to these flow regimes. Though linear- and bilinear-flow regimes have been noted for fractured horizontal wells in the literature on the basis of their diagnostic features, they have not been associated with particular reservoir characteristics and flow relationships. The trilinear-flow solution also provides a suitable algorithm for the regression analysis of pressure-transient tests in shale reservoirs.
CO2 Injection Performance in the Fruitland Coal Fairway, San Juan Basin: Results of a Field Pilot
Authors: Oudinot Anne Y. , Koperna George J. , Philip Zeno G. , Liu Ning , Heath Jason E. , Wells Arthur , Young Genevieve B. , Wilson Tom 
Published: December 2011

Summary
The Pump Canyon CO2-enhanced coalbed methane (ECBM)/ sequestration demonstration in New Mexico has the primary objective of demonstrating the feasibility of CO2 sequestration in deep, unmineable coal seams through a small-scale geologic sequestration pilot. This project is not the first of its kind; several small- or large-scale pilots were already conducted previously in the United States [Allison Unit (Reeves et al. 2003) in the San Juan, Appalachian, and Warrior basins] as well as internationally [the Recopol (Reeves and Oudinot 2002) project in Poland, and the Yubari project in Japan, Canada, and Australia]. Additional pilots are currently under way.
At the project site, a new CO2-injection well was drilled within an existing pattern of coalbed-methane-production wells. Primarily operated by ConocoPhillips, these wells produce from the Late Cretaceous Fruitland coals. CO2 injection into these coal seams was initiated in late July 2008 and ceased in August 2009. A variety of monitoring, verification, and accounting (MVA) methods were employed to track the movement of the CO2 in order to determine the occurrence of leakage. Within the injection well, MVA methods included continuous measurement of injection volumes, pressures, and temperatures. The offset production wells sampled gas-production rates, pressures, and gas composition through CO2 sensors, tracers in the injected CO2, time-lapse vertical seismic profiling, and surface tiltmeter arrays. A detailed study of the overlying Kirtland shale was also conducted to investigate the integrity of this primary caprock. This information was used to develop a detailed geologic characterization and reservoir model that has been used to further understand the behavior of this reservoir.
The CO2-injection pilot has ended with no significant CO2 buildup occurring in the offset production wells. However, a small but steady increase in CO2 and N2 at two of the offset wells may have been an indication of imminent breakthrough. More recent gas samples are, however, showing a decrease in CO2 and N2 content at those wells. This paper describes the project, covering the regulatory process and injection-well construction, the different techniques used to monitor for CO2 leakage, and the results of the modeling work.
Analysis of Data From the Barnett Shale Using Conventional Statistical and Virtual Intelligence Techniques
Authors: Awoleke Obadare O. , Lane Robert H. 
Published: December 2011

Summary
A Barnett shale water-production data set from approximately 11,000 completions was analyzed using conventional statistical techniques. Additionally, a water/hydrocarbon ratio and first-derivative diagnostic-plot technique developed elsewhere for conventional reservoirs was extended to analyze Barnett shale water-production mechanisms. To determine hidden structure in well and production data, self-organizing maps and the k-means algorithm were used to identify clusters in data. A competitive-learning-based network was used to predict the potential for continuous water production from a new well, and a feed-forward neural network was used to predict average water production for wells drilled in Denton and Parker Counties, Texas, of the Barnett shale.
Using conventional techniques, we concluded that for wells of the same completion type, location is more important than time of completion or hydraulic-fracturing strategy. Liquid loading has potential to affect vertical more than horizontal wells. Different features were observed in the spreadsheet diagnostic plots for wells in the Barnett shale, and we made a subjective interpretation of these features. We find that 15% of the horizontal and vertical wells drilled in Denton County have a load-water-recovery factor greater than unity. Also, 15 and 35% of the horizontal and vertical wells drilled, respectively, in Parker County have a load-recovery factor greater than unity.The use of both self-organizing maps and the k-means algorithm showed that the data set is divided into two main clusters. The physical properties of these clusters are unknown but interpreted to represent wells with high water throughput and those with low water throughput. Expected misclassification error for the competitive-learning-based tool was approximately 10% for a data set containing both vertical and horizontal wells. The average prediction error for the neural-network tool varied between 10 and 26%, depending on well type and location.Results from this work can be used to mitigate risk of water problems in new Barnett shale wells and predict water issues in other shale plays. Engineers are provided a tool to predict potential for water production in new wells. The method used to develop this tool can be used to solve similar challenges in new and existing shale plays.
Laminar and Turbulent Friction Factors for Annular Flow of Drag-Reducing Polymer Solutions in Coiled-Tubing Operations
Authors: Ogugbue Chinenye C. , Shah Subhash N. 
Published: December 2011

Summary
The challenge of theoretical and numerical studies of annular fluid flow with varying eccentricity is mainly a result of the required coordinate systems. Computational-fluid-dynamics (CFD) modeling provides the state-of-the-art approach of investigating fluid flow in such complex geometries. In this study, results from a series of numerical simulations for the fully developed laminar flow of non-Newtonian power-law fluids in concentric and eccentric annular geometries are used to investigate the effect of eccentricity, flow-behavior index, and diameter ratio (ratio of the outer diameter of the inner tubing to the inner diameter of the outer tubing) on axial frictional pressure losses.
The frictional pressure-loss gradients predicted by the CFD simulations were verified by comparing with the published studies and flow data from a field-scale experimental setup. At a constant flow rate, it is confirmed that frictional pressure losses decrease with increasing eccentricity. A good agreement was obtained with the Haciislamoglu and Langlinais (1990) correlation, and the results of this study, especially at low values of eccentricity. At very high eccentricities, data from the CFD model yield lower frictional pressure loss compared to Haciislamoglu and Langlinais (1990) correlation. This type of expression is obtained and the improved data of this study is incorporated.
Next, this paper presents the results of an experimental study carried out to investigate frictional pressure-loss behavior of drag- reducing polymer solutions, flowing turbulently through an eccentric annulus. The experimental setup includes 30 ft of 3½×2⅜-in., 200 ft of 3½×1¾-in., 69 ft of 5½ × 4-in., and 79 ft of 5 ×3½-in. fully eccentric annuli. Data analysis enabled the development of a new correlation using fluid apparent viscosity at 511 sec–1, generalized Reynolds number, and diameter ratio, all of which can be easily determined in the field as independent variables. These new correlations for laminar and turbulent flow of drag-reducing polymer solutions present an improvement to existing correlations, and also permit undemanding hydraulic-program calculations for varying annular configurations.
Production-Induced Stress Change in and Above a Reservoir Pierced by Two Salt Domes: A Geomechanical Model and Its Applications
Authors: Schutjens P.M.T.M.. M.T.M. , Snippe J.R.. R. , Mahani H.. , Turner J.. , Ita J.. , Mossop A.P.. P. 
Published: December 2011

Summary
Production decreases the pore-fluid pressure and increases the effective stress acting on the load-bearing-grain framework that makes up the reservoir. As a result, the reservoir deforms and compacts, and because it is connected to the rocks around it, there will be deformations and displacements in these rocks also. Well known geomechanical effects of production include surface subsidence, wells damaged by shear, and time shifts in 4D seismic. Less well known is how the changes in the stress field itself should be taken into account in operations—e.g., to design infill wells and to plan production stimulation by hydraulic fracturing or waterflooding of the reservoir.
We present a geomechanical model for the initial stress field and production-induced stress changes in and around a steeply dipping hydrocarbon reservoir penetrated by two large salt domes. The model integrates 3D seismic and geological understanding, geomechanical data from wells and analogues, and depletion patterns from fluid-flow (dynamic) simulation. Our model results confirm published models of principal-stress orientation in rocks pierced by salt domes. The depleted-model results show stress changes up to several MPa in magnitude compared with the preproduction stress state, but only limited changes in the stress orientations. The model highlights the influence of structural dip and time-dependent salt/sediment interaction on stress changes.
We then describe the application of the model in wellbore stress analysis for infill wells and in a water-injection scheme that has, we believe, been severely impacted by injection-induced fractures propagating in the reservoir from the injector wells toward the producer wells. We explain how the latter application uses a 3D flow-simulation model coupled to a dynamic fracture-propagation model. The geomechanical model provides key input: stress magnitude and stress orientation. Results are validated against a more conventional analysis of real-time pressure data.
In both applications, the integration of geomechanics in 3D static and dynamic models improved insight into the rock response to drilling and waterflooding, thus helping to optimize production.
Productivity Loss in Gas Wells Caused by Salt Deposition
Authors: Le Duc , Mahadevan Jagannathan 
Published: December 2011

Summary
Production of gas can result in drying of the near-wellbore region caused by gas expansion, which causes evaporation and hence salt deposition. The deposition of salt leads to a reduction in porosity and permeability of the rock in the near-wellbore region, which then leads to reduction in well productivity. The main objective of this work is to understand the role of capillarity on salt deposition and its impact on well flow efficiency.
We develop and solve the dimensionless-conservation equations for solid-salt saturation using numerical methods under radial-flow conditions. The results of the calculations show that when the capillary effects are strong, the salt accumulates near the wellbore, which leads to plugging and hence higher skin values. The salt saturation continues to evolve until a limiting value, in the rock pores, is reached. Higher values of the limiting saturation lead to a greater reduction in permeability and therefore result in a larger skin value for the gas well. The flow efficiency of a gas well, calculated as a dimensionless ratio of the flow with and without skin, decreases continually and asymptotically approaches a constant value.
In a simulation for a typical field case, we find that the largest increase in skin factor and corresponding decrease in flow efficiency occur in approximately the first 30 days, after which the changes are slower. When connate-water salt concentration is higher, the skin value is much higher and thus the well productivity is lower. Using the model developed in this study, the decline of gas-well productivity caused by salt deposition can be predicted and hence accurate timing of well operations, such as water wash, can be made. Also, the modeling study can be used to select remediation strategies such as wettability alteration to reduce capillarity or application of inhibitors, which can reduce the limiting salt saturation by preventing growth of salt crystals within the reservoir rock.