bluuebunny/crossref_metadata_2025_split huggingface dataset:
Abnormalities of Vascular Structure and Function in Children With Perthes Disease
Authors: Perry Daniel C. , Green Daniel J. , Bruce Colin E. , Pope Daniel , Dangerfield Peter , Platt Mary Jane , Hall Andrew J. , Jones Helen 
Published: June 2012

BACKGROUND AND OBJECTIVES:
Perthes disease is a childhood precipitant to osteoarthritis of the hip, for which the etiology and mechanism are unknown. There is mounting evidence to suggest a vascular insult is responsible for disease, and it is suggested that this may have long-term implications for the vascular health of affected individuals. This study sought to use ultrasound measures to investigate vascular structure and function in children affected by Perthes disease.

METHODS:
This case control study encompassed 149 cases and 146 controls, frequency matched for age and gender. Endothelial function was measured by using the technique of flow-mediated dilation of the brachial artery, and alterations in arterial flow were recorded in response to an ischemic stimulus.

RESULTS:
There was a significant structural alteration in the vasculature among individuals with Perthes disease (resting brachial artery diameter (cases 2.97 mm versus controls 3.11 mm; P = .01), which remained even after adjusting for height. In addition, there was a notable reduction in blood velocity (cases 33.84 cm/s versus controls 37.83 cm/s; P = .01) and blood flow (cases 149.82 mL/min versus controls 184.67 mL/min; P = .001), which was independent of baseline arterial size. There was no evidence to suggest that flow-mediated dilation of the brachial artery was impaired among affected individuals (P = .71).

CONCLUSIONS:
Children with Perthes disease exhibit small artery caliber and reduced function, which is independent of body composition. These data imply that that Perthes disease may reflect a wider vascular phenomenon that could have long-term implications for the vascular health of affected individuals.
Self-Reported Adolescent Health Status of Extremely Low Birth Weight Children Born 1992–1995
Authors: Hack Maureen , Schluchter Mark , Forrest Christopher B. , Taylor H. Gerry , Drotar Dennis , Holmbeck Grayson , Youngstrom Eric , Margevicius Seunghee , Andreias Laura 
Published: June 2012

OBJECTIVES:
To compare the self-reported health of extremely low birth weight (ELBW, &lt;1 kg) adolescents with that of normal birth weight (NBW) controls and the children’s assessments of their general health at ages 8 versus 14 years.

METHODS:
One hundred sixty-eight ELBW children and 115 NBW controls of similar gender and sociodemographic status completed the Child Health and Illness Profile–Adolescent Edition at age 14 years. It includes 6 domains: Satisfaction, Comfort, Resilience, Risk Avoidance, Achievement, and Disorders. At age 8 years, the children had completed the Child Health and Illness Profile–Child Edition. Results were compared between ELBW and NBW subjects adjusting for gender and sociodemographic status.

RESULTS:
ELBW adolescents rated their health similar to that of NBW adolescents in the domains of Satisfaction, Comfort, Resilience, Achievement and Disorders but reported more Risk Avoidance (effect size [ES] 0.6, P &lt; .001). In the subdomain of Resilience, they also noted less physical activity (ES −0.58, P &lt; .001), and in the subdomain of Disorders, more long-term surgical (ES −0.49) and psychosocial disorders (ES −0.49; both P &lt; .01). Both ELBW and NBW children reported a decrease in general health between ages 8 and 14 years, which did not differ significantly between groups.

CONCLUSIONS:
ELBW adolescents report similar health and well-being compared with NBW controls but greater risk avoidance. Both ELBW and NBW children rate their general health to be poorer at age 14 than at age 8 years, possibly due to age-related developmental changes.
Dynamic Evolution of Practice Guidelines: Analysis of Deviations From Assessment and Management Plans
Authors: Farias Michael , Friedman Kevin G. , Powell Andrew J. , de Ferranti Sarah D. , Marshall Audrey C. , Brown David W. , Kulik Thomas J. 
Published: June 2012

OBJECTIVE:A Standardized Clinical Assessment and Management Plan (SCAMP) standardizes the care of patients with a predefined diagnosis while actively inviting and collecting data on clinician deviations (DEVs) from its recommendations. For 3 different pediatric cardiac diagnoses managed by SCAMPs, we determined the frequency of, types of, and reasons for DEVs, which are considered to be a valuable source of information and innovation.METHODS:DEVs were collected as part of SCAMP implementation. DEVs were reviewed by the SCAMP committee chairperson and by a separate protocol deviation committee; they were characterized as either justifiable (J), possibly justifiable (PJ), or not justifiable (NJ).RESULTS:We analyzed 415 patients, 484 clinic encounters, and 216 DEVs. Eighty-six (39.8%) of the DEVs were J, 21 (9.7%) were PJ, and 109 (50.4%) were NJ. The percentage of NJ DEVs relative to the number of opportunities for DEV was 4.1%. J and PJ DEVs were mostly due to management of unrelated conditions (11% overall) or special circumstances (22% overall). NJ DEVs primarily involved follow-up intervals (66%) and deleted tests (24%). The reason for deviating from SCAMP recommendations was not given for 31% of DEVs, even though such information was requested.CONCLUSIONS:The overall low rate of NJ DEV suggests that practitioners generally accept SCAMP recommendations, but improved capture of practitioners' reasons for deviating from those recommendations is needed. This analysis revealed multiple opportunities for improving patient care, suggesting that this process can be useful in both promulgating sound practice and evolving improved approaches to patient management.
Application of 3-D Geosteering Capabilities in Geologically-Complex Shale
Authors: Reddy Srinivas , Pitcher Jason 
Published: June 2012

Abstract
On a recent well in the Middle Bakken Dolomite, Williston Basin, North Dakota, an operator struggled to effectively geosteer a horizontal well. The geology, while usually relatively simple, proved to be more complex than anticipated. While drilling, the wellbore was steered out of zone, requiring an open-hole sidetrack. After successfully sidetracking, the well was steered out of zone a second time, requiring a repeat of the sidetrack.
At this point, the operator elected to deploy a comprehensive geosteering service, which consisted of an azimuthal resistivity tool, dedicated geosteering software, and associated geosteering personnel. Once the tools were delivered to the rig site, all data was transmitted offsite to the geosteering specialists for analysis in real time.
The second side track was successfully drilled to TD with no further sidetracks. This demonstrates the ability to rapidly deploy, on short notice, a fit-for-purpose solution to assist operators in accurately positioning wells in the Middle Bakken with a substantial reduction in cost and risk.
Engineered Perforation Design Improves Fracture Placement and Productivity in Horizontal Shale Gas Wells
Authors: Walker K. , Wutherich K. , Terry J. 
Published: June 2012

Abstract
Perforating a horizontal well in the Marcellus shale is typically performed using bare essential technology. Simple rules-of-thumb for perforation cluster spacing and interval length are applied, most likely derived by trial and error, and rarely validated by methods such as production logging and microseismic monitoring. Conversely, a perforating method that is gaining notoriety is an engineered approach in which perforation clusters are placed in each fracture interval of rocks that have similar properties. The reasoning for this method is that it will ensure equal injection rates and volumes of the hydraulic-fracture treatment into each of the perforation clusters; maximizing reservoir contact and production from each cluster.
The completion engineer might base the perforation design on gamma ray measurements with additional support of a mud log. While these measurements add some clarity to the perforation design, there is no evidence that either of these measurements have a direct impact on the breakdown stress of the rock, which is the primary driving force that dictates flow distribution of a hydraulic fracture treatment. Current logging technology does allow us to measure compressional, fast- and slow-shear, and Stoneley slowness waves in 3D along the horizontal cased borehole. These data can then be used to calculate stress and provide a stress profile along the lateral, which can provide an accurate basis for completion design.
Fluid distribution is predicted by way of both basic orifice-flow calculations and 3D hydraulic-fracture models (using actual stress data) and then verified using observations from microseismic monitoring results.
This paper presents a field case in which production improved using the perforation design method described above vs. one using conventional geometrically spaced perforations. In this case study, the operator made the new design technique part of their standard completion program.
Barnett Shale Horizontal Restimulations: A Case Study of 13 Wells
Authors: Craig Mark , Wendte Steve , Buchwalter Jim 
Published: June 2012

Abstract
This case study will review performance and costs of thirteen Barnett Shale horizontal well restimulations located in the “Core” area of Wise County, Texas. This area has produced about 1 TCF gas and is considered one of the most productive areas in the Barnett Shale.
Locator Map – 13 Horizontal Well Restimulations in Wise County, Texas
Devon Energy has performed nine hundred vertical well fracture restimulations (refracs) across the entire Barnett Shale and is now beginning to focus its refrac efforts on the horizontal wells. About thirteen horizontal wells have been restimulated in this area since 2008. Initial results were mixed, but the economics have gradually been improved by developing candidate selection criteria, and modifying the stimulation design to contain costs.
This paper will address the well performance of the horizontal refracs, the costs involved, the restimulation design, and the evolution of candidate screening criteria. We will also briefly touch on some possible reasons for improved refrac well performance, based on computer simulation / history matching.
Microseismic Clouds: Modeling and Implications
Authors: Palmer Ian D. , Moschovidis Zissis A. , Schaefer Aaron 
Published: June 2012

Abstract
Microseismic measurements provide qualitative information about where a fracture stimulation goes. However, there is also quantitative information, which has largely been neglected. We have developed a geomechanical model to predict the extent of shear failure during fracture stimulation of a well. It is a “screening model” meaning point-by-point details of the natural fracture distribution, fluid leakoff, and failure prediction are not emphasized. By matching this to the microseismic cloud of shear failure, we obtain the injection permeability and porosity, which characterize the stimulated reservoir volume (SRV). The model identifies different types of failure, tensile and shear, which will occur on vertical planes of weakness or natural fractures.
The model can be applied to any formation in which the microseismic data demonstrates a substantial spread away from the expected main fracture plane, as occurs in many tight shales. A number of different geometries have been modeled: horizontal vs vertical wells, and transverse vs longitudinal fractures. Not all wells have microseismic data, but the first few wells usually do, and modeling of these cases can provide useful directives for future wells. For example, the injection permeability can provide information on average fracture spacing and aperture width for the induced fracture network (SRV). These can be important for choosing proppant type, size, and concentration for optimal fracture treatments in gas and oil plays in tight shales.
We find the injection permeabilities are relatively high, and these must be associated with fracture-controlled flow. From our case histories, a high injection permeability (&gt;200 md) is required to pressure the formation and achieve failure out as far as the microseismic events extend. Low porosity (≪ 0.1%) is required for the frac fluid to leak off that far. Reports on interference with offset wells support this interpretation. As a case history, the method and results for sequential stimulation of two sister horizontal wells in the Barnett shale are described.
Most of the injection permeability is lost when a well is turned on, and ways to offset this are suggested. One of these ways is to tailor the proppant to the width and spacing of the induced fracture network, to prop more effectively the network of induced fractures. We illustrate some initial guidelines for choosing proppant type, size, and concentration which may improve fracture treatments in tight shales.
Improved Evaluation of Microseismic Data Through the Use of Cumulative Frequency Plots of Microseismic Event Source Parameters
Authors: Downie Robert 
Published: June 2012

Abstract
The engineering evaluation of microseismic events data acquired during hydraulic fracturing treatments can be influenced by factors that affect both the number of events detected and the quality of the waveforms used to locate the microseismic events. Variations in microseismic response that are observed during multistage stimulation treatments might be related to changes in rock properties or the stimulation treatment design or might be caused by detectability limitations related to distance, monitoring tool performance, and signal quality.
Magnitude-versus-distance plots are routinely used to determine detectability limits. Data filters based on a combination of measurement parameters of the detected waveforms can be used to reduce location uncertainty. The selections of filters to be used and the thresholds for filtering need to undertaken with care. Inadequate filtering can allow monitor well bias and microseismic events with low location confidence to adversely affect the evaluation. Aggressive filtering can introduce additional detection biases and might limit full characterization of the hydraulic fracture.
Frequency-versus-magnitude data from multiple treatments can be used to make comparative evaluations of microseismic data that have been acquired over a large range of monitoring distances during multiple stimulation treatments. The events from each treatment can be evaluated to determine a minimum event magnitude that can be used to minimize monitor well bias.
The use of cumulative-frequency-versus-magnitude data can be used to improve the engineering evaluation of microseismic events. This approach to evaluation is quantitative rather than qualitative and increases confidence that observations and analyses based on microseismic events are directly related to the stimulation procedure and properties of the reservoir.
Formation-Tester Pulse Testing in Tight Formations (Shales and Heavy Oil): Where Wellbore Storage Effects Favor the Determination of Reservoir Pressure
Authors: Hadibeik Hamid , Proett Mark , Chen Dingding , Eyuboglu Sami , Torres-Verdín Carlos , Pour Rooholah A. 
Published: June 2012

Abstract
Tight formation testing when mobilities are lower than 0.01 mD/cP poses significant challenges because the conventional pressure transient buildup testing becomes impractical as a result of the large buildup stabilization time. This paper introduces a new automated pulse test method for testing in tight formations that significantly reduces testing time and makes the determination of formation pressure and permeability possible. A pulse test is defined as a drawdown followed by an injection test, and the source is shut in to record the pressure transient. Based on pressure data during the shut-in period, the next drawdown or injection test is designed, such that the flow rate is a fraction of the initial pulse rate, followed by another shut-in test. This procedure continues until the difference in pressure at the beginning and at the end of the shut-in period is reduced to within a specified limit of pressure change; then, an extended transient is recorded to a stabilized shut-in pressure. The overall advantage is to reduce the pressure stabilization time by implementing an adaptive pressure feedback loop in the system. The method can be applied to a straddle packer test using conventional drillstem testing tools or formation testers, using either straddle packers or probes.
The effects of wellbore storage and fluid compressibility are found to reduce the pressure drop and positive pressure pulse in the drawdown and injection tests, respectively; they also affect the decay rate to the asymptote of the shut-in pressure response. Consequently, the combined pulse test method with the pressure feedback system and wellbore storage effect reduces the reservoir pressure testing time in tight formations.
The automated pulse-test method has been successfully validated with consideration of the effects of wellbore storage and overbalance pressure in tight gas and heavy oil formations. In addition, the effects of invasion with water- and oil-based mud filtrate were considered in the modeling. The method uses successive pressure feedbacks and automated pulses to yield a pressure to within 0.5% range of the initial reservoir pressure while decreasing the wait time by a factor of 10 for a packer type formation tester.
To account for various tool options and storage effects, the packer-type, oval probe, and standard probe-type formation testers have been simulated in various tight formation conditions. The method enables a rapid appraisal of pressure measurements in comparison to conventional testing. Simulations also indicate that the analytical spherical model can be used to analyze a pulse test, even when encountering multi-phase compositional fluid effects.
Gas Flow Tightly Coupled to Elastoplastic Geomechanics for Tight and Shale Gas Reservoirs: Material Failure and Enhanced Permeability
Authors: Kim Jihoon , Moridis George J. 
Published: June 2012

Abstract
We investigate coupled flow and geomechanics in gas production from extremely low permeability reservoirs such as tight and shale gas reservoirs, using coupled dynamically porosity and permeability during simulation. The intrinsic permeability is a step function of the status of material failure, and is updated every time step. We investigate the reservoirs with vertical and horizontal primary fractures, employing the single and double porosity models. We modify the multiple porosity constitutive relations for modeling double porous continua for flow and geomechanics. The numerical results indicate that production of gas causes redistribution of the effective stress fields, increasing the effective shear stress and resulting in plasticity. Shear failure occurs away from the primary fractures as well as near the fracture tips, which indicates generation of secondary fractures. These secondary fractures increase the permeability significantly, and change the flow pattern, which in turn causes a change in distribution of geomechanical variables. When the double porosity flow model is used, we observe a faster evolution of the enhanced permeability area than that obtained from the single porosity model because of the higher permeability of the fractures in the double porosity model. Additionally, we find that the complicated physics for stress sensitive reservoirs cannot properly be captured by uncoupled or decoupled methods, and thus tightly coupled flow and geomechanical models are highly recommended to accurately describe the reservoir behavior during gas production in tight and shale gas reservoirs.
Probabilistic Forecasting of Unconventional Resources Using Rate Transient Analysis: Case Studies
Authors: Anderson D. M. , Liang P. , Okouma V. 
Published: June 2012

Abstract
Reliable, early determination of long term production and ultimate recovery in oil and gas reservoirs is of utmost importance to E&P companies, reserves auditors and investors. In conventional reservoirs, the EUR can be reliably estimated once the drainage volume (hydrocarbon pore volume) has been established. This can be done using Rate Transient Analysis (RTA) if the presence of boundary dominated flow can be observed in the data. Unfortunately this approach is not easily applied to tight, fractured reservoirs because of the complexity of these reservoirs (which leads to non-unique reservoir characteristics) and the presence of persistent transient flow (which leads to non-unique estimations of ultimate recovery). In some instances, boundary dominated flow may not be observed until several years have elapsed during the producing life of the well.
In recent years, there have been numerous contributions to the science of well performance-based methods for estimation of ultimate recovery of unconventional resources. Wattenbarger et al. (1998) and Brown et al. (2009) propose analytical techniques while Ilk et al. (2008), Valko and Lee (2010) and Duong (2011) have each proposed new empirical decline curve equations. While each of these methods has value, they do not specifically address the problem that underpins all unconventional well analysis, uncertainty. In 2011, the authors proposed the use of probabilistic rate transient analysis to help quantify this uncertainty. This approach acknowledges the non-uniqueness inherent in the RTA model inputs and allows for the systematic investigation of an allowable parameter space based on acceptable ranges of inputs such as the conductivity, spacing, complexity, length and height of the fractures and the matrix permeability. The result is the full set of possible production forecasts (in as much as the model can be said to capture the physics of the problem) from which the "most likely" production profile can be extracted and that help define the uncertainty in long-term recovery for the play. In this paper, we will further explore probabilistic rate transient analysis by presenting a case study from the Montney play in Canada. The primary objective of this work is to illustrate that a probabilistic approach can be practical, reliable and systematic, offering a viable alternative (or complement) to the standard deterministic techniques.
Use of Drill Cuttings for Improved Design of Hydraulic Fracturing Jobs in Horizontal Wells
Authors: Ortega Camilo , Aguilera Roberto 
Published: June 2012

Abstract
Drill cuttings are powerful sources of information that have been used for several decades by well site petroleum geologists for qualitative evaluation of reservoir rocks. Additional cuttings work is carried subsequently in the laboratory. This includes, for example, the preparation of thin sections for petrographic work, and the evaluation of intergranular and microfracture porosity.
Drill cuttings, however, have not been used to full advantage in horizontal wells drilled through tight formation. This study proposes a method for quantitative determination of porosity, permeability and rock mechanics properties from drill cuttings collected in horizontal wells. These properties are determined through a combination of laboratory, analytical and 3D simulation work. The laboratory work includes the determination of porosity and permeability in cutting samples with sizes equal to 1 mm or larger. The results are used for determining key geomechanical properties such as Poisson's ratio and Young's modulus; and the estimation of a brittleness index. The data extracted from the previous two stages are useful in 3D hydraulic fracturing simulation for designing multi-stage hydraulic fracturing in horizontal wells.
Data extracted from drill cuttings are important as the amount of information collected in horizontal wells drilled thought tight formations, including cores and well logs, is rather limited in most instances.
It is concluded that the proposed method provides a useful tool for evaluation of direct sources of information that are available in many cases (drill cuttings) but are rarely evaluated quantitatively. The proposed method allows improved design of multi stage-hydraulic fracturing jobs in horizontal wells.