We study the gas flow processes in ultra-tight porous media in which the matrix pore network is composed of nanometre- to micrometre-size pores. We formulate a pressure-dependent permeability function, referred to as the apparent permeability function (APF), assuming that Knudsen diffusion and slip flow (the Klinkenberg effect) are the main contributors to the overall flow in porous media. The APF predicts that in nanometre-size pores, gas permeability values are as much as 10 times greater than results obtained by continuum hydrodynamics predictions, and with increasing pore size (i.e. of the order of the micrometre), gas permeability converges to continuum hydrodynamics values. In addition, the APF predicts that an increase in the fractal dimension of the pore surface leads to a decrease in Knudsen diffusion. Using the homogenization method, a rigorous analysis is performed to examine whether the APF is preserved throughout the process of upscaling from local scale to large scale. We use the well-known pulse-decay experiment to estimate the main parameter of the APF, which is Darcy permeability. Our newly derived late-transient analytical solution and the late-transient numerical solution consistently match the pressure decay data and yield approximately the same estimated value for Darcy permeability at the typical core-sample initial pressure range and pressure difference. Other parameters of the APF may be determined from independent laboratory experiments; however, a pulse-decay experiment can be used to estimate the unknown parameters of the APF if multiple tests are performed and/or the parameters are strictly constrained by upper and lower bounds.

Summary Physics of fluid flow in shale reservoirs cannot be predicted from standard flow or mass-transfer models because of the presence of nanopores, ranging in size from one to hundreds of nanometers, in shales. Conventional continuum-flow equations, such as Darcy's law, greatly underestimate the fluid-flow rate when applied to nanopore-bearing shale reservoirs. As a result of the existence of nanopores in shales, the molecular mean free path becomes comparable with the characteristic geometric scale, and we hypothesize that under this condition, Knudsen diffusion, in addition to correction for the slip boundary condition, becomes the dominant mechanism. Recently, a few models have been developed that use various empirical parameters to account for these modifications (Javadpour 2009; Civan 2010; Darabi et al. 2012). This paper aims to provide a different approach to modeling apparent permeability in shale reservoirs. The proposed model is analytical, free of any empirical coefficients, and has been derived without invoking the assumption of slip flow at the pore wall. Our model of apparent permeability represented by a single analytical equation, depends only on pore size, pore geometry, temperature, gas properties, and average reservoir pressure. The proposed model is valid for Knudsen numbers less than unity and it stands up under the complete operating conditions of a shale reservoir. Our model reasonably predicts results as reported by other models. Finally, the model shows that pore-surface roughness and mineralogy have a negligible influence on gas-flow rate, whereas pore geometry and pore size play a significant role in the proportion of diffusion in total flow rate. Our study shows that a combination of Darcy flow and Knudsen flow—ignoring the Klinkenberg effect—can describe gas flow for a range of Knudsen flow applicable to a shale-gas system.

Pantothenamides are N-substituted pantothenate derivatives which are known to exert antimicrobial activity through interference with coenzyme A (CoA) biosynthesis or downstream CoA-utilizing proteins. A previous report has shown that replacement of the ProR methyl group of the benchmark N-pentylpantothenamide with an allyl group (R-anti configuration) yielded one of the most potent antibacterial pantothenamides reported so far (MIC of 3.2 μM for both sensitive and resistant Staphylococcus aureus). We describe herein a synthetic route for accessing the corresponding R-syn diastereomer using a key diastereoselective reduction with Baker's yeast, and report on the scope of this reaction for modified systems. Interestingly, whilst the R-anti diastereomer is the only one to show antibacterial activity, the R-syn isomer proved to be significantly more potent against the malaria parasite (IC 50 of 2.4 ± 0.2 μM). Our research underlines the striking influence that stereochemistry has on the biological activity of pantothenamides, and may find utility in the study of various CoA-utilizing systems. Keywordspantothenamides; antibacterial; antiplasmodial; baker's yeast; coenzyme A Infectious diseases remain a major contributing factor to worldwide mortality. Moreover, the development of antimicrobial resistance is raising significant concerns about the increasingly limited efficacy of currently available treatments. 1 There have been considerable efforts towards discovering and characterising novel therapeutic targets for antimicrobial drugs. One such target which has emerged as a promising point-of-attack is

The purpose of this study is to assess the effects of propacetamol on attenuating hemodynamic responses subsequent laryngoscopy and tracheal intubation compared to lidocaine. In this randomized clinical trial, 62 patients with the American Anesthesiologists Society (ASA) class I/II who required laryngoscopy and tracheal intubation for elective surgery were assigned to receive propacetamol 2 g/I.V./infusion (group P) or lidocaine 1.5 mg/kg (group L) prior to laryngoscopy. Systolic and diastolic blood pressures (SBP, DBP), mean arterial pressure (MAP), and heart rate (HR) were recorded at baseline, before laryngoscopy and within nine minutes after intubation. In both groups P and L, MAP increased after laryngoscopy and the changes were statistically significant (P < 0.001). There were significant changes of HR in both groups after intubation (P < 0.02), but the trend of changes was different between two groups (P < 0.001). In group L, HR increased after intubation and its change was statistically significant within 9 minutes after intubation (P < 0.001), while in group P, HR remained stable after intubation (P = 0.8). Propacetamol 2 gr one hour prior intubation attenuates heart rate responses after laryngoscopy but is not effective to prevent acute alterations in blood pressure after intubation.

Wettability is a key property, which controls multiphase fluid flow in oil recovery processes. It is well known that the asphaltene deposition on rock surface changes the wettability of the rock. Although many experiments in the literature have been conducted to understand the physics underlying wettability alteration in crude oil/brine/rock (COBR) system because of asphaltene deposition; a sophisticated mathematical model describing this phenomenon is absent. In this paper, based on available experimental data in the literature and known physical mechanisms of asphaltene deposition on the rock in the COBR system, a model for wettability alteration due to asphaltene instability in crude oil is presented. Contact angle is introduced as a function of asphaltene stability index (ASI), which is determined thermodynamically based on the difference between the fugacity of asphaltene and the heaviest component in the oil. The shape of this function depends on pH, salinity and cation valency of brine, and asphaltene content of crude oil. We implemented our proposed model along with asphaltene precipitation, flocculation, and deposition models into an in-house compositional simulator, UTCOMP, developed at The University of Texas at Austin. Permeability and porosity reduction due to asphaltene deposition are also considered. Furthermore, relative permeabilities and capillary pressure are modified because of contact angle alteration during simulation. Although the amount of asphaltene deposition in the reservoir may not be comparable to the wellbore, a significant change in wettability occurs after the deposition of first layer of asphaltene on the rock surface. The result of our simulation shows that wettability alteration affects oil recovery, specifically when the brine produces unstable water film on the rock surface. In this case, rock wettability can change from 30° (water-wet) to 150° (oil-wet) and yield change in recovery depending on absolute permeability reduction magnitude and change in trapped oil saturation as well as end-point relative permeability.

Asphaltene precipitation, flocculation, and deposition in the reservoir and producing wells cause serious damages to the production equipment and possible failure to develop the reservoirs. From the field production prospective, predicting asphaltene precipitation, flocculation, and deposition in the reservoir and wellbore essentially avoids high expenditures associated with the reservoir remediation, well intervention techniques, and field production interruption. Since asphaltene precipitation and deposition strongly depend on the pressure, temperature, and composition variations (e.g. phase instability due to CO2 injection), it is important to have a model that can track the fluid behavior during the entire production process from the injection well to the production well, which is absent in the literature. In this paper, a comprehensive thermal compositional coupled wellbore/reservoir simulator with a capability of modeling asphaltene phase behavior in the reservoir and the wellbores is presented to address the wellbore/reservoir interaction, the effect of asphaltene deposition on the flow prediction and long-term reservoir performance. Indeed, the simulator models multiphase fluid flow in the reservoir and the wellbore to enable comprehensive production system analysis. In addition, wettability alteration due to the asphaltene deposition on the rock surface is considered in our models. We present primary production and CO2 flood simulation cases to investigate the effect of asphaltene deposition on oil recovery. The results show that injection of the light components into the reservoir significantly increases the instability of asphaltene components in the reservoir where they can precipitate further around the wellbore and in the wellbore. The precipitated asphaltene in the reservoir can be carried into the wellbore and be combined with excess asphaltene formation and deposit in the wellbore. In addition, our simulation shows that well productivity decreases significantly in case of asphaltene precipitation and deposition during the production life of a reservoir.

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Asphaltene deposition during oil production may partially or totally plug the wellbore, and results in significant reduction in well production and frequent asphaltene remediation jobs. It is well-known that injection of lighter hydrocarbons into an asphaltic oil (e.g. during gas lift) may decrease the stability of asphaltene particles in the solution and increase the risk of asphaltene precipitation and deposition. Although a great deal of research has investigated the effect of gas injection on the phase behavior and mechanism of asphaltene deposition in the wellbore, we lack a comprehensive dynamic model that can track the behavior of asphaltene during gas lift process. Therefore, a comprehensive model is required for evaluating the risk of gas lift on asphaltene deposition in production wells. This paper presents a comprehensive thermal compositional wellbore model with the capability to model asphaltene phase behavior during gas lift and determine the effect of the injected gas on asphaltene deposition in the wellbore. In the developed wellbore simulator, various numerical approaches are used to model multiphase flow in the wellbore. An equation of state was used to calculate the thermodynamic equilibrium conditions of the phases. In addition, several deposition mechanisms were incorporated to study the transportation, entrainment, and deposition of solid particles in the wellbore. Various case studies investigated the effect of gas lift on asphaltene deposition. To predict where and when the most severe damage would occur in the wellbore, we used field data of a Middle East crude oil and an injection gas. The results showed that the injection of light gas composition can negatively affect the production facilities by intensifying asphaltene precipitation in the well, which eventually results in significant reduction in the wellbore production. We believe that this comprehensive thermal compositional wellbore model can facilitate the design of work-over operation plans for asphaltic wells operating under gas lift.