bluuebunny/crossref_metadata_2025_split huggingface dataset:
Decreased T‐Cell Responses to Influenza Vaccination in Patients with Heart Failure
Authors: Vardeny Orly , Moran John J. M. , Sweitzer Nancy K. , Johnson Maryl R. , Hayney Mary S. 
Published: December 2009

Study Objective. To determine whether T‐cell immune responses to influenza vaccination in patients with chronic heart failure (CHF) are less vigorous than the responses of healthy control subjects.Design. Prospective, single‐center studySetting. University hospital and research laboratoryParticipants. Eighteen adults with stable CHF receiving optimal treatment and 16 healthy control subjects.Intervention. Participants were immunized with the 2006–2007 trivalent inactivated (killed) influenza vaccine during October‐December of 2006.Measurements and Main Results. Blood samples were taken from the participants before and 2–4 weeks after vaccination to measure antibody titers, which were measured with a hemagglutination inhibition assay, then 3–4 months after vaccination to assess T‐cell responses, measured by using the trans vivo delayed‐type hypersensitivity method. As part of this method, which mimics physiologic conditions, peripheral blood mononuclear cells were isolated from the blood samples. The cells were mixed with influenza vaccine antigens A/H1N1, A/H3N2, and B type and injected into the footpads of SCID mice (mice with severe combined immunodeficiency), as their resulting swelling is an index of human T‐cell sensitization. Median T‐cell‐mediated immune responses to A/H3N2 were less vigorous in patients with CHF than in control subjects (62.5 vs 87.5 μm, unadjusted p=0.031, age‐adjusted p=0.006). Median responses to A/H1N1 were not significantly different between the groups (56.3 vs 75 μm, p=0.11). Median responses to B type were also similar between the groups (62.5 vs 75 μm, p=0.47). All participants mounted an antibody response to the influenza vaccine.Conclusion. Patients with CHF had reduced T‐cell responses to the influenza vaccine compared with healthy control subjects, as demonstrated by a lower response to A/H3N2, the newest antigen in the 2006–2007 vaccine. However, differences in T‐cell immune responses to the A/H1N1 and B type strains were not found to be significant between the two groups, which suggests that patients with CHF can mount an appropriate response to vaccine antigens to which they have been previously exposed, but less so to new antigens. These findings suggest that patients with CHF may be at increased risk for influenza infection, and clinicians may want to investigate other or additional strategies for influenza vaccination.
Effects of Acetaminophen, Naproxen, and Acetylsalicylic Acid on Tapentadol Pharmacokinetics: Results of Two Randomized, Open‐Label, Crossover, Drug‐Drug Interaction Studies
Authors: Smit Johan W. , Oh Charles , Rengelshausen Jens , Terlinden Rolf , Ravenstijn Paulien G. M. , Wang Shean‐Sheng , Upmalis David , Mangold Bernhard 
Published: December 2009

Study Objective.To evaluate the effects of acetaminophen, naproxen, and acetylsalicylic acid on the pharmacokinetics of the centrally acting analgesic tapentadol in healthy subjects.Design.Two randomized, open‐label, crossover, drug‐drug interaction studies.Setting.Clinical research facilities in the United States and Belgium.Participants.Twenty‐four healthy adults (2‐way crossover study) and 38 healthy adults (3‐way crossover study).Interventions.In both studies, tapentadol immediate release (IR) 80 mg was administered as a single oral dose alone. In the 2‐way crossover study, tapentadol IR was also given with the fifth of seven doses of acetaminophen 1000 mg; in the 3‐way crossover study, tapentadol IR was also given with the third of four doses of naproxen 500 mg and the second of two doses of acetylsalicylic acid 325 mg. All treatments were separated by a washout period of 7–14 days.Measurements and Main Results.Overall, mean serum concentrations were similar after administration of tapentadol IR alone and after coadministration with acetaminophen or acetylsalicylic acid, and the 90% confidence intervals (CIs) for the ratios of the mean area under the serum concentration‐time curve (AUC) from time zero to time of the last measurable concentration (AUC0‐t) and from time zero extrapolated to infinity (AUC0‐$iF) and the maximum serum concentration (Cmax) of the combined treatments to those parameters of tapentadol alone were well within 80–125%, representing the accepted range for bioequivalence. Coadministration of naproxen did not significantly alter the Cmax of tapentadol, although a slightly higher serum tapentadol exposure relative to tapentadol alone was observed. Coadministration of naproxen resulted in a mean increase of 17% in AUCs, and the upper limits of the 90% CIs for the ratios of the mean AUC0‐tand AUCo‐$iFwere slightly outside the upper limit of bioequivalence range of 80–125% (126.47% AUC0‐tand 126.14% AUC0‐$iF).Conclusion.No clinically relevant changes were noted in the serum concentrations of tapentadol, and accordingly, no dosage adjustments with respect to the investigated pharmacokinetic mechanism of interaction are warranted for the administration of tapentadol given concomitantly with acetaminophen, naproxen, or acetylsalicylic acid.
Once‐Daily Gentamicin Dosing in Children with Febrile Neutropenia Resulting from Antineoplastic Therapy
Authors: Inparajah Miriam , Wong Cecile , Sibbald Cathryn , Boodhan Sabrina , Atenafu Eshetu G. , Naqvi Ahmed , Dupuis L. Lee 
Published: December 2009

Study Objectives. To evaluate an existing once‐daily gentamicin dosing guideline in children with febrile neutropenia resulting from antineoplastic therapy and, if necessary, to develop a new simulated dosing guideline that would achieve pharmacokinetic targets more reliably after the first dose.Design. Pharmacokinetic analysis of data from a retrospective medical record review Setting. Hematology‐oncology unit of a university‐affiliated pediatric hospital in Canada.Patients. One hundred eleven patients aged 1–18 years who received once‐daily gentamicin between April 2006 and 2008 for the treatment of febrile neutropenia resulting from antineoplastic therapy, and who had plasma gentamicin concentrations determined after their first dose.Measurements and Main Results. Demographic data, gentamicin dosing information, blood sampling times, and plasma gentamicin concentrations were noted. Plasma gentamicin concentrations were determined at approximately 3 and 6 hours after the start of the 30‐minute infusion of the first dose. Pharmacokinetic parameters were calculated according to standard first‐order, one‐compartment equations. The proportion of children who achieved pharmacokinetic targets after the first gentamicin dose was used as a measure of dosing guideline performance; the guideline achieved maximum concentration (Cmax) values below the target range (20–25 mg/L) in 51% of patients. Ideal dosing guidelines were then developed using the mean dose required to achieved a Cmax of 23 mg/L for each patient. Univariate analysis or the Student t test was used to determine the existence of significant relationships between pharmacokinetic parameters and patient age and sex. The recursive binary partitioning method was used to determine critical values of age for dosage guideline development; analysis of variance was then used to compare the different levels obtained after use of this technique. Simulated administration of once‐daily gentamicin in the following doses achieved a Cmax within or above target in 73% of patients: 1 year to < 6 years, 10.5 mg/kg/dose; girls > 6 years, 9.5 mg/kg/dose; and boys > 6 years, 7.5 mg/kg/dose. Doses were based on actual body weight for children who weighed less than 125% of ideal body weight or based on effective body weight for children 125% or more of ideal body weight.Conclusion. The initial gentamicin dosing guidelines were not effective in achieving Cmax. The new proposed dosing guidelines are predicted to achieve a Cmax within or above the target range in almost three quarters of patients. Subsequent dosing should be tailored according to plasma gentamicin concentrations.
Lack of Association Between Excretion of Sorafenib in Sweat and Hand‐Foot Skin Reaction
Authors: Jain Lokesh , Gardner Erin R. , Figg William D. , Chernick Milica S. , Kong Heidi H. 
Published: December 2009

Study Objective. To determine if excretion of sorafenib in sweat is associated with hand‐foot skin reaction in patients receiving sorafenib.Design. Prospective pilot study.Setting. Outpatient clinic of a cancer research institution.Patients. Two patients who were receiving sorafenib and developed a hand‐foot skin reaction of at least grade 1 and two healthy subjects (controls).Intervention. Sweat production was stimulated in both the patients with hand‐foot skin reaction and the healthy subjects by means of pilocarpine iontophoresis.Measurements and Main Results. Sweat samples were collected from the patients with hand‐foot skin reaction and from the healthy subjects. Using liquid chromatography‐tandem mass spectrometry, sorafenib concentrations were measured in the sweat samples. Sweat samples from the healthy subjects were spiked with known concentrations of sorafenib to determine the lower limit of quantification of the assay, which was determined to be 5 ng/ml. Sorafenib concentrations in the samples from the patients with hand‐foot skin reaction were undetectable based on the assay's sensitivity.Conclusion. Our results suggest that hand‐foot skin reaction in patients receiving sorafenib is not associated with excretion of sorafenib in sweat. Further studies are needed to understand the mechanism of hand‐foot skin reaction, a treatment‐limiting adverse effect of multikinase inhibitors.
Laboratory Investigation on the Effect of Water Injection Process on Rock Structure and Permeability Reduction
Authors: Abbasi S. , Tavakkolian M. , Shahrabadi A. , Oskui G. P. 
Published: December 2009

Abstract
The nature of some water injection processes can cause unavoidable formation damage. In most cases, by optimal design of the process, the formation damage can be minimized or avoided. The estimation and assessment of formation damage on reservoir core samples is an important measurement which will be presented in this paper by monitoring rock permeability changes.
Laboratory tests were set up to investigate the effects of injection pressure, flow rate and also induced fracture on the rock sample with respect to formation damage. Reservoir core nature, structure and its heterogeneity make the phenomenon of formation damage more complex. In this research, selected rock samples from one of Iranian giant oil fields, which is undergoing water injection, were used as the laboratory physical model. Using injection water samples, different scenarios were performed on this model. Permeability reduction was observed for un-fractured samples: however, it was more interesting that no injection pressure build up was detected in fractured samples. It appears that fractures in sandstones, especially with weak cementation, can play the role of an agent for particle movement in causing damage to different parts of the formation. Over a long period of time, this phenomenon can cause more complicated situations in the reservoir, the degree of which being a function of several parameters, such as rock type and structure, pore size distribution and reservoir heterogeneity.
Screening Potential Production Technologies for the Lower Fars Heavy Oil Asset in Kuwait
Authors: Oskui G. P. , Al-Naqi A. , Dusseault M. B. 
Published: December 2009

Abstract
The Lower Fars (LF) sandstone reservoir in Northern Kuwait( NK) is probably the single largest accumulation of heavy oil (HO, μ &gt; 100 cP) in Kuwait, containing somewhere in the range of 12-15 Bb distributed over an area of ~1000 km2 northwest of Kuwait City against the Iraqi border. There are other heavy oil accumulations in Kuwait, mainly in naturally fractured carbonate strata, but they are of smaller size and of lower quality. Although a small resource in comparison to Canadian and Venezuelan HO resource, the Lower Fars reservoir nonetheless represents a significant fraction of Kuwaiti resources.
Compared to viscous oil deposits elsewhere in the world, the LF asset is shallow, of generally higher porosity and permeability, and of lower viscosity with a significant variation in fluid properties with depth and with location in the large reservoir. These characteristics will lead to the deployment of a number of production technologies similar to but somewhat different from Canadian experience, with the potential for generally greater recovery factors and lower costs than in Canada. Furthermore, a general situation is emerging in the Kuwait region that may be unusually favorable for heavy oil development, and these positive factors include: Availability of diluents and natural gas for production process,Capital availability for upgrading investment,Sources of low-cost heat.
This confluence of excellent reservoir properties, existing commercialized technologies with a reasonable history of commercialization, a good infrastructure, and supportive emerging supportive conditions will make the development of the LF a less costly venture than comparable cases in Canada and Venezuela.
In this paper the latest studies in reservoir evaluation and various screening techniques for selection of optimal production technologies will be presented. We will revisit the concept of deliberate sequencing of processes, planning in advance for such strategies. We will even speculate on how local heat sources might be integrated into production processes.
Hydrate Problems in Gas Lift Production: Experiences and Integrated Inhibition
Authors: Nengkoda Ardian , Reerink Hendrikus , Hase Alfred , Supranto Supranto , Prasetyo Imam , Purwono Suryo , Budhijanto Budhijanto 
Published: December 2009

Abstract
Currently, there are more than 10 oil producing station, in both North and South area operation of Petroleum Development Oman, which facing a unique gas hydrate problems. Most of these wells are producing by the support of gas lift. Therefore, it is very important that the gas lift network is kept optimally operating to maintain the intended production. The ambient temperature in Sultanate of Oman desert drops to as low as 5°C during the coldest 3 months in winter, when hydrates form in several gas lift lines. This causes affected wells to cease production and results in unscheduled deferment. So far, the problem was partly controlled by the use of methanol as hydrate inhibitor (a proven method used worldwide to restrict gas hydrate formation), however there are resulted many issues mainly HSE associated with the use of methanol. The main objectives of this project are to look the other chemicals alternative as hydrate inhibitor – move from methanol to another cost effective and safe chemical inhibitor and the goal is to ensure that the system is adequately inhibited against hydrate formation and that inhibitor injection is optimized. The second goal is to develop a warning system should hydrate start to form (prior to hydrate build up and pipeline blockage). The paper also defines laboratory testing as mandatory requirement to test an alternative hydrate inhibitor and practical facilities up grade.
Comparison Study of Models for Calculating Absolute Permeability Using Nuclear Magnetic Resonance Imaging Log Technology in Tight Sandstone Gas Zones
Authors: Xiao Liang , Mao Zhi-qiang , Wang Zhao-nian , Jin Yan , Liu Xing-gang , Xie Bing 
Published: December 2009

Abstract
Tight sandstone gas zones displayed such characteristics as low porosity and low permeability. At present, it was a challenge for log analysts to gain reservoir absolute permeability precisely in such zones because of the poor correlation between formation porosity and permeability parameters. Classical SDR model and Tim-Coates model from nuclear magnetic resonance (NMR) log data also losed their advantage. In this condition, 21 core samples were chosen to run mercury-injection and NMR log experiment simultaneously, whose porosity ranged from 2.7% to 16.1% and permeability ranged from 0.019 × 10−3μm2 to 131.0 × 10−3μm2. With the analysis of mercury-injection data, correlations were established between rock absolute permeability and the pore structure parameters, such as the average pore throat radius. The inflexion parameter of capillary pressure curves (the Swanson Parameter) was also associated with the rock absolute permeability. By using these relationships, the rock permeability could be calculated from mercury-injection data. Considering the problem that mercury-injection capillary pressure data was limited by their quantity because of the expensive test cost and the environmental concern, based on the fact that NMR T2 distribution and mercury-injection capillary pressure curves all reflected reservoir pore structure, two novel models were established to gain the average pore throat radius and the Swanson parameter from nuclear magnetic resonance T2 distribution. So, these parameters could be calculated from NMR imaging log data and then rock absolute permeability could be gained respectively by combining NMR total porosity. It had demonstrated that these clues could be expandeded to reservoir conditions, and then reservoir absolute permeability could be calculated along the intervals with NMR imaging measurement. At last, an in-situ example from southwest oil and gas field of China was exhibited of calculating reservoir absolute permeability consecutively in tight sandstone gas zones by using these two models and the validity of these models were compared. The Swanson parameter model was suggested in calculating reservoir absolute permeability in this paper. The result shown that absolute permeability calculated by using the Swanson parameter model matched much better with core data than the average pore throat radius model.These two models were also effective and accurate in detecting the thin sand with high porosity and high permeability because a core sample used in these models came from these zones.
Foam Assisted Enhanced Oil Recovery at Miscible and Immiscible Conditions
Authors: Farajzadeh R. , Andrianov A. , Zitha P. L. J. 
Published: December 2009

Abstract
We report an experimental study of CO2 and N2 foam flows in natural sandstone cores containing oil with the aid of X-ray Computed Tomography. The study is relevant for Enhanced Oil Recovery (EOR). The cores were partially saturated with oil and brine (half top) and brine only (half bottom) to mimic the water-oil transition occurring in oil reservoirs. The CO2 was used either under sub- or under super-critical (immiscible and miscible) conditions, whereas N2 remained subcritical. Prior to gas injection the cores were flooded with several pore volumes of water. In each experiment water flooding was followed by the injection of 1-2 pore volumes of a surfactant solution with Alpha Olefin Sulfonate (AOS) as the foaming agent. We visually show how foam propagates in a porous medium containing oil.
At low-pressure experiments (P=1 bar) in the case of N2, weak foam could be formed in the oil-saturated part. Diffused oil bank is formed ahead of the foam front, which results in additional oil recovery, compared to pure gas injection. CO2 hardly foams in the oil-bearing part of the core, most likely due to its higher solubility. Above critical point (P=90 bar), CO2 injection following the slug of surfactant reduces its mobility in absence oil. Nevertheless, when the foam front meets the oil it becomes highly diffuse. The presence of the surfactant (when foaming super-critical CO2) hardly improves oil recovery and or modifies the pressure drop profile, indicating the detrimental effect of oil on foam stability in the medium in this specific case. However, at miscible conditions, injection of surfactant prior to CO2 injection significantly increases the oil recovery.
Oil Fields Scale Deposition Prediction Methodology
Authors: Refaei M. I. , Al-Kandari I. A/Karim 
Published: December 2009

Abstract
Oilfield scale costs are high because of drastic oil and gas production decline, frequent pulling of down-hole equipment for replacement, re-perforation of the scaling producing intervals, reaming and re-drilling of the plugged oil wells, stimulation of the plugged oil-bearing formation and other remedial work-over. As scale deposits around the well-bore, the porous formation becomes plugged and may be rendered impermeable to any fluids.
In most of oil and gas fields scale deposition in surface and subsurface production equipment has been recognized to be one of the major operational problem. Problem will be more critical in Water flooded fields where wells will suffered from flow restriction because of scale deposition within the oil producing formation matrix and the down-hole equipment, as well as scale deposits in the surface production equipment.
Some of the Oil Fields have been water-flooded with formation seawater. Compatibility tests have indicated probable deposition of scale in surface and subsurface production equipment. This paper outlines the physical and theoretical prediction for down-hole scale deposition in the water flooded fields.
Water is the main substance, which is responsible for scale build up problem. In order to study the circumstances behind the scale build up problem, following the new methodology which can be applied to predict the different types of scale build up before start to be precipitated. From the samples of the complete water analysis reports, Scale Indexes were calculated to define the different scales that can be precipitated at different production nodes/conditions.
This paper showed that different types/amounts of scale accumulation can be precipitated from the selected water samples since the super saturation conditions of water occurred. It also described the control of scale inhibition programs which could be carried out to control down-hole scale deposition and scale inhibition treatment that could be implemented to overcome the scale deposition, before scale problem will be occurred. Scale control can also been controlled/managed properly by continues updating the new scale index calculations methodology described in the probable problematic water flooded reservoir.