Serpentine channels are often used in microchannel reactors and heat exchangers. These channels offer better mixing, higher heat and mass‐transfer coefficients than straight channels. In the present work, flow and heat transfer experiments were carried out with a serpentine channel plate comprising of 10 units (single unit dimensions: 1 × 1.5 mm2 in cross section, length 46.28 mm, Dh 1.2 mm) in series. Pressure drop and heat‐transfer coefficients were experimentally measured. Flow and heat transfer in the experimental set‐up were simulated using computational fluid dynamics (CFD) models to understand the mechanisms responsible for performance enhancement. The CFD methodology, thus, developed was applied to understand the effect of various geometrical parameters on heat transfer enhancement. A criterion was defined for evaluation of heat transfer performance (heat transfer per unit pumping power), thus, ensuring due considerations to required pumping power. The effect of geometrical parameters and the corresponding mechanisms contributing for enhancement are discussed briefly. Based on the results, a design map comprising different serpentine channels showing heat transfer enhancement with pumping power was developed for Reynolds number of 200 which will be useful for further work on flow and heat transfer in serpentine channels. © 2012 American Institute of Chemical Engineers AIChE J, 59: 1814–1827, 2013

Matrix acidizing is a technique used for stimulating carbonate formations. Fluids used for this purpose are routinely characterized in the laboratory by means of core flood testing. Though several key insights can be obtained using the laboratory core flood technique, simulating exact downhole environments and extrapolation of the results obtained to field-scale has proven challenging. This paper addresses two specific topics related to acid wormholing-upscaling laboratory results to field scenarios and the interaction of reaction products in high pressure reservoirs.To study the upscaling of acid wormholing experiments in field scenarios, a radial core flood testing apparatus was set up to better mimic actual wellbore acidizing flow conditions. The effects of radial flow path and completion type (i.e. openhole versus cased hole) as well as the applicability of the upscaling wormhole propagation model were studied. Furthermore, CT scans of related core samples were performed to characterize wormhole patterns generated by acid dissolution. In addition, tests were performed at high pressures and flow rates to study the effects of the interaction of reaction products on the wormholing process at typical high bottomhole pressure values.Results from radial core flood techniques showed significant differences in terms of pore volume to breakthrough (PVBT) based on well completion type. Further, a current upscaling algorithm for wormhole propagation modeling was verified by comparison to corresponding experimental data, thus demonstrating the suitability of described linear core flow testing methods for fluid characterization and data modeling. The wormhole propagation model (based on the use of fitting coefficient) is well-justified by the probability of increased fluid loss from the wormhole in the case of deeper radial penetration, which overall reduces the efficiency of wormholing. CT scan results revealed nonuniform radial distribution of wormhole propagation, thus shedding light on challenges associated with achieving 360°stimulation around the wellbore. Experiments at higher pressures showed that, at higher flow rates investigated (or beyond optimum) wormhole propagation has a higher than one third dependence on interstitial velocity, signifying that high pressure reservoirs require greater volumes of acid for proper stimulation. Experimental observations are presented to correlate the results obtained thus far and help resolve controversies between various publications.Presented studies highlight the effects of higher pressure in acid wormholing and signify the need for proper volume accounting in terms of job design. A simple radial core flood technique has been developed in this work, and has an advantage in terms of diversion studies by providing a means of arranging high and low permeability core samples in the same order as formation layers and accounting for fluid entrance position.

With the advent of distributed temperature sensing (DTS), accurate and continuous monitoring of the wellbore-temperature profile is possible, which helps identify fluid flow from each reservoir layer. The reliable prediction of fluid flow during large drawdown requires an accurate value of the Joule-Thomson coefficient (JTC), which is a measure of the change in temperature (T) of a fluid for a given change in pressure (P) at constant enthalpy. The JTC also serves as an input for the interpretation of temperaturelog data, which can be used to identify water-or gas-entry locations. Furthermore, an accurate JTC value is important when modeling the thermal response of the reservoir.The equation-of-state (EOS) method can be used to predict the JTC of reservoir gas. However, this might not be an easy task because of the complexity involved. In contrast, a simple and reliable method to evaluate the JTC for reservoir gas is presented. Conditions under which this method is applicable are discussed in detail by referring to a typical phase diagram. In addition, a discretized approach to calculate the temperature change during a throttling process with the JTC is also presented.The methodology has been validated at three levels with experimental data available in the literature-comparison of experimental vs. predicted JTC values of mixtures, comparison of experimentally observed vs. predicted temperature drop for a given pressure drop with laboratory-scale data, and comparison of experimentally observed vs. predicted temperature drop for a given drawdown with actual reservoir data. A good match with experimental data was obtained within all three areas, demonstrating the reliability of the methodology.

With the advent of distributed temperature sensing (DTS), accurate and continuous monitoring of the wellbore temperature profile is possible, which helps identify fluid flow from each reservoir layer. Reliable prediction of fluid flow during large drawdown requires an accurate value of the Joule-Thomson coefficient (JTC), which is a measure of the change in temperature of a fluid for a given change in pressure at constant enthalpy. The JTC also serves as an input for interpretation of temperature log data, which can be used to identify water or gas entry locations. Furthermore, an accurate JTC value is important when modeling the thermal response of the reservoir. The equation-of-state (EOS) method can be used to predict the JTC of reservoir gas. However, this might not be an easy task because of the complexity involved. In contrast, a simple and reliable method to evaluate the JTC for reservoir gas is presented. Conditions under which this method is applicable are discussed in detail by referring to a typical phase diagram. In addition, a discretized approach to calculate the temperature change during a throttling process using the JTC is also presented. The methodology has been validated at three levels using experimental data available in the literature—comparison of experimental vs. predicted JTC values of mixtures, comparison of experimentally observed vs. predicted temperature drop for a given pressure drop using lab-scale data, and comparison of experimentally observed vs. predicted temperature drop for a given drawdown using actual reservoir data. A good match with experimental data was obtained within all three areas, demonstrating the reliability of the methodology.