Journal articles on the topic 'Capillary condensates'
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Gouveia, Bernardo, Yoonji Kim, Joshua W. Shaevitz, Sabine Petry, Howard A. Stone, and Clifford P. Brangwynne. "Capillary forces generated by biomolecular condensates." Nature 609, no. 7926 (September 7, 2022): 255–64. http://dx.doi.org/10.1038/s41586-022-05138-6.
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Christenson, H. K. "Liquid Capillary Condensates below the Freezing Point." Physical Review Letters 74, no. 23 (June 5, 1995): 4675–78. http://dx.doi.org/10.1103/physrevlett.74.4675.
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Takahashi, Hisayuki, and Masayasu Tanaka. "Statistical Analysis for Comparison of the Results Obtained by Capillary Columns and Packed Columns in the Determination of Water Yield in Smoke Condensates Analyzed in Cigarettes for the 24th Asia Collaborative Study." Beiträge zur Tabakforschung International/Contributions to Tobacco Research 29, no. 2 (September 25, 2020): 97–118. http://dx.doi.org/10.2478/cttr-2020-0010.
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SummaryRecently, capillary columns have been widely used in the methodology for the determination of water yields in smoke condensate, even though ISO 10362-1:1999, “Cigarettes - Determination of water in smoke condensates – Part 1: Gas chromatographic method” specifies a packed gas chromatographic column. As a result of a systematic review in 2015, ISO/TC126 decided to revise the standard to include the use of capillary columns.The goal of this study was to confirm the comparability of water yields obtained from capillary column methodology to those yields from packed columns by the statistical analysis of yield data from the 24th Asia Collaborative Study which included 86 datasets submitted by 64 laboratories. After the exclusion of outliers by Cochran’s and Grubbs’ tests, the datasets were classified by GC column type and then mean water yields, and their repeatability and reproducibility were calculated for each type of column. No significant differences were observed in water yields between capillary and packed columns. Repeatability and reproducibility of water yields using capillary column were comparable to those using packed columns as described in ISO 10362-1:1999. From these results, it was confirmed that the capillary columns are an appropriate alternative to packed columns for the gas chromatographic procedure described in ISO 10362-1:1999.
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Mott, R. E., A. S. Cable, and M. C. Spearing. "Measurements of Relative Permeabilities for Calculating Gas-Condensate Well Deliverability." SPE Reservoir Evaluation & Engineering 3, no. 06 (December 1, 2000): 473–79. http://dx.doi.org/10.2118/68050-pa.
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Summary Well deliverability in many gas-condensate reservoirs is reduced by condensate banking when the bottomhole pressure falls below the dewpoint, although the impact of condensate banking may be reduced due to improved mobility at high capillary number in the near-well region. This paper presents the results of relative permeability measurements on a sandstone core from a North Sea gas-condensate reservoir, at velocities that are typical of the near-well region. The results show a clear increase in mobility with capillary number, and the paper describes how the data can be modeled with empirical correlations which can be used in reservoir simulators. Introduction Well deliverability is an important issue in the development of many gas-condensate reservoirs, especially where permeability is low. When the well bottomhole flowing pressure falls below the dewpoint, condensate liquid may build up around the wellbore, causing a reduction in gas permeability and well productivity. In extreme cases the liquid saturation may reach values as high as 50 or 60% and the well deliverability may be reduced by up to an order of magnitude. The loss in productivity due to this "condensate banking" effect may be significant, even in very lean gas-condensate reservoirs. For example, in the Arun reservoir,1 the productivity reduced by a factor of about 2 as the pressure fell below the dewpoint, even though the reservoir fluid was very lean with a maximum liquid drop out of only 1% away from the well. Most of the pressure drop from condensate blockage occurs within a few feet of the wellbore, where velocities are very high. There is a growing body of evidence from laboratory coreflood experiments to suggest that gas-condensate relative permeabilities increase at high velocities, and that these changes can be correlated against the capillary number.2–8 The capillary number is a dimensionless number that measures the relative strength of viscous and capillary forces. There are several gas-condensate fields where simulation with conventional relative permeability models has been found to underestimate well productivity.1,9,10 To obtain a good match between simulation results and well-test data, it was necessary to increase the mobility in the near-well region, either empirically or through a model of the increase in relative permeability at high velocity. This effect can increase well productivity significantly, and in some cases may eliminate most of the effect of condensate blockage. Experimental Data Requirements Fevang and Whitson11 have shown that the key parameter in determining well deliverability is the relationship between krg and the ratio krg/ kro. When high-velocity effects are significant, the most important information is the variation of krg with krg/k ro and the capillary number Nc. The relevant values of krg/kro are determined by the pressure/volume/temperature (PVT) properties of the reservoir fluids, but typical values might be 10 to 100 for lean condensates, 1 to 10 for rich condensates, and 0.1 to 10 for near-critical fluids. There are various ways of defining the capillary number, but in this paper we use the definition (1)Nc=vgμgσ, so that the capillary number is proportional to the gas velocity and inversely proportional to interfacial tension (IFT). The capillary numbers that are relevant for well deliverability depend on the flow rate, fluid type, and well bottomhole pressure, but as a general rule, values between 10?6 and 10?3 are most important. Experimental Methods In a gas-condensate reservoir, there are important differences between the flow regimes in the regions close to and far from the well. These different flow regimes are reflected in the requirements for relative permeability data for the deep reservoir and near-well regions. Far from the well, velocities are low, and liquid mobility is usually less important, except in reservoirs containing very rich fluids. In the near-well region, both liquid and gas phases are mobile, velocities are high, and the liquid mobility is important because of its effect on the relationship between krg and krg/kro. Depletion Method. Relative permeabilities for the deep reservoir region are often measured in a coreflood experiment, where the fluids in the core are obtained by a constant volume depletion (CVD) on a reservoir fluid sample. Relative permeabilities are measured at decreasing pressures from the fluid dewpoint, and increasing liquid saturation. In this type of experiment, the liquid saturation cannot exceed the critical condensate saturation or the maximum value in a CVD experiment, so that it is not possible to acquire data at the high liquid saturations that occur in the reservoir near to the well. The "depletion" experiment provides relative permeability data that are relevant to the deep reservoir, but there can be problems in interpreting the results due to the effects of IFT. Changes in liquid saturation are achieved by reducing pressure, which results in a change of IFT. The increase in IFT as pressure falls may cause a large reduction in mobility, and Chen et al.12 describe an example where the condensate liquid relative permeability decreases with increasing liquid saturation. Steady-State Method. The steady-state technique can be used to measure relative permeabilities at the higher liquid saturations that occur in the near-well region. Liquid and gas can be injected into the core from separate vessels, allowing relative permeabilities to be measured for a wide range of saturations. Results of gas-condensate relative permeabilities measured by this technique have been reported by Henderson et al.2,6 and Chen et al.12 .
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Ruban, V. P. "Capillary Flotation in a System of Two Immiscible Bose–Einstein Condensates." JETP Letters 113, no. 12 (June 2021): 814–18. http://dx.doi.org/10.1134/s0021364021120110.
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Pope, G. A., W. Wu, G. Narayanaswamy, M. Delshad, M. M. Sharma, and P. Wang. "Modeling Relative Permeability Effects in Gas-Condensate Reservoirs With a New Trapping Model." SPE Reservoir Evaluation & Engineering 3, no. 02 (April 1, 2000): 171–78. http://dx.doi.org/10.2118/62497-pa.
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Summary Many gas-condensate wells show a significant decrease in productivity once the pressure falls below the dew point pressure. A widely accepted cause of this decrease in productivity index is the decrease in the gas relative permeability due to a buildup of condensate in the near wellbore region. Predictions of well inflow performance require accurate models for the gas relative permeability. Since these relative permeabilities depend on fluid composition and pressure as well as on condensate and water saturations, a model is essential for both interpretation of laboratory data and for predictive field simulations as illustrated in this article. Introduction Afidick et al.1 and Barnum et al.2 have reported field data which show that under some conditions a significant loss of well productivity can occur in gas wells due to near wellbore condensate accumulation. As pointed out by Boom et al.,3 even for lean fluids with low condensate dropout, high condensate saturations may build up as many pore volumes of gas pass through the near wellbore region. As the condensate saturation increases, the gas relative permeability decreases and thus the productivity of the well decreases. The gas relative permeability is a function of the interfacial tension (IFT) between the gas and condensate among other variables. For this reason, several laboratory studies3–14 have been reported on the measurement of relative permeabilities of gas-condensate fluids as a function of interfacial tension. These studies show a significant increase in the relative permeability of the gas as the interfacial tension between the gas and condensate decreases. The relative permeabilities of the gas and condensate have often been modeled directly as an empirical function of the interfacial tension.15 However, it has been known since at least 194716 that the relative permeabilities in general actually depend on the ratio of forces on the trapped phase, which can be expressed as either a capillary number or Bond number. This has been recognized in recent years to be true for gas-condensate relative permeabilities.8,10 The key to a gas-condensate relative permeability model is the dependence of the critical condensate saturation on the capillary number or its generalization called the trapping number. A simple two-parameter capillary trapping model is presented that shows good agreement with experimental data. This model is a generalization of the approach first presented by Delshad et al.17 We then present a general scheme for computing the gas and condensate relative permeabilities as a function of the trapping number, with only data at low trapping numbers (high IFT) as input, and have found good agreement with the experimental data in the literature. This model, with typical parameters for gas condensates, was used in a compositional simulation study of a single well to better understand the productivity index (PI) behavior of the well and to evaluate the significance of condensate buildup. Model Description The fundamental problem with condensate buildup in the reservoir is that capillary forces can retain the condensate in the pores unless the forces displacing the condensate exceed the capillary forces. To the degree that the pressure forces in the displacing gas phase and the buoyancy force on the condensate exceed the capillary force on the condensate, the condensate saturation will be reduced and the gas relative permeability increased. Brownell and Katz16 and others recognized early on that the residual oil saturation should be a function of the ratio of viscous to interfacial forces and defined a capillary number to capture this ratio. Since then many variations of the definition have been published,17–20 with some of the most common ones written in terms of the velocity of the displacing fluid, which can be done by using Darcy's law to replace the pressure gradient with velocity. However, it is the force on the trapped fluid that is most fundamental and so we prefer the following definition: N c l = | k → → ⋅ ∇ → ϕ l | σ l l ′ , ( 1 ) where definitions and dimensions of each term are provided in the nomenclature. Although the distinction is not usually made, one should designate the displacing phase l ? and the displaced phase l in any such definition. In some cases, buoyancy forces can contribute significantly to the total force on the trapped phase. To quantify this effect, the Bond number was introduced and it also takes different forms in the literature.20 One such definition is as follows: N B l = k g ( ρ l ′ − ρ l ) σ l l ′ . ( 2 ) For special cases such as vertical flow, the force vectors are collinear and one can just add the scalar values of the viscous and buoyancy forces and correlate the residual oil saturation with this sum, or in some cases one force is negligible compared to the other force and just the capillary number or Bond number can be used by itself. This is the case with most laboratory studies including the recent ones by Boom et al.3,8 and by Henderson et al.10 However, in general the forces on the trapped phase are not collinear in reservoir flow and the vector sum must be used. A generalization of the capillary and Bond numbers was derived by Jin 21 and called the trapping number. The trapping number for phase l displaced by phase l? is defined as follows: N T l = | k → → ⋅ ( ∇ → ϕ l ′ + g ( ρ l ′ − ρ l ) ∇ → D ) | σ l l ′ . ( 3 ) This definition does not explicitly account for the very important effects of spreading and wetting on the trapping of a residual phase. However, it has been shown to correlate very well with the residual saturations of the nonwetting, wetting, and intermediate-wetting phases in a wide variety of rock types.
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Barber, P., T. Asakawa, and H. K. Christenson. "What Determines the Size of Liquid Capillary Condensates Below the Bulk Melting Point?" Journal of Physical Chemistry C 111, no. 5 (February 2007): 2141–48. http://dx.doi.org/10.1021/jp066556b.
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Baek, Seunghwan, and I. Yucel Akkutlu. "CO2 Stripping of Kerogen Condensates in Source Rocks." SPE Journal 24, no. 03 (April 5, 2019): 1415–34. http://dx.doi.org/10.2118/190821-pa.
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Summary Significant research has been conducted on hydrocarbon fluids in the organic materials of source rocks, such as kerogen and bitumen. However, these studies were limited in scope to simple fluids confined in nanopores, while ignoring the multicomponent effects. Recent studies using hydrocarbon mixtures revealed that compositional variation caused by selective adsorption and nanoconfinement significantly alters the phase equilibrium properties of fluids. One important consequence of this behavior is capillary condensation and the trapping of hydrocarbons in organic nanopores. Pressure depletion produces lighter components, which make up a small fraction of the in-situ fluid. Equilibrium molecular simulation of hydrocarbon mixtures was carried out to show the impact of CO2 injection on the hydrocarbon recovery from organic nanopores. CO2 molecules introduced into the nanopore led to an exchange of molecules and a shift in the phase equilibrium properties of the confined fluid. This exchange had a stripping effect and, in turn, enhanced the hydrocarbon recovery. The CO2 injection, however, was not as effective for heavy hydrocarbons as it was for light components in the mixture. The large molecules left behind after the CO2 injection made up the majority of the residual (trapped) hydrocarbon amount. High injection pressure led to a significant increase in recovery from the organic nanopores, but was not critical for the recovery of the bulk fluid in large pores. Diffusing CO2 into the nanopores and the consequential exchange of molecules were the primary drivers that promoted the recovery, whereas pressure depletion was not effective on the recovery. The results for N2 injection were also recorded for comparison.
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Heath, David, Brian Moffatt, Roy Lowry, and Steve Rowland. "Quantification of the C30+ fraction of North sea gas condensates by high temperature capillary gas chromatography." Analytical Proceedings including Analytical Communications 32, no. 12 (1995): 485. http://dx.doi.org/10.1039/ai9953200485.
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Bouyssiere, Brice, Franck Baco, Laurent Savary, and Ryszard Lobiñski. "Speciation analysis for mercury in gas condensates by capillary gas chromatography with inductively coupled plasma mass spectrometric detection." Journal of Chromatography A 976, no. 1-2 (November 2002): 431–39. http://dx.doi.org/10.1016/s0021-9673(02)01151-2.
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Durand, J. P., A. Fafet, and A. Barreau. "Direct and automatic capillary GC analysis for molecular weight determination and distribution in crude oils and condensates up to C20." Journal of High Resolution Chromatography 12, no. 4 (April 1989): 230–33. http://dx.doi.org/10.1002/jhrc.1240120408.
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Chang, Tong-Bou, Bai-Heng Shiue, Yi-Bin Ciou, and Wai-Io Lo. "Analytical Investigation into Effects of Capillary Force on Condensate Film Flowing over Horizontal Semicircular Tube in Porous Medium." Mathematical Problems in Engineering 2021 (March 17, 2021): 1–10. http://dx.doi.org/10.1155/2021/6693512.
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A theoretical investigation is performed into the problem of laminar filmwise condensation flow over a horizontal semicircular tube embedded in a porous medium and subject to capillary forces. The effects of the capillary force and gravity force on the condensation heat transfer performance are analyzed using an energy balance approach method. For analytical convenience, several dimensionless parameters are introduced, including the Jakob number Ja, Rayleigh number Ra, and capillary force parameter Boc. The resulting dimensionless governing equation is solved using the numerical shooting method to determine the effect of capillary forces on the condensate thickness. A capillary suction velocity can be obtained mathematically in the calculation process and indicates whether the gravity force is greater than the capillary force. It is shown that if the capillary force is greater than the condensate gravity force, the liquid condensate will be sucked into the two-phase zone. Under this condition, the condensate film thickness reduces and the heat transfer performance is correspondingly improved. Without considering the capillary force effects, the mean Nusselt number is also obtained in the present study as N u ¯ | V 2 ∗ = 0 = 2 R a D a / J a 1 / 2 ∫ 0 π 1 + cos θ 1 / 2 d θ .
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App, Jeffrey F., and Jon E. Burger. "Experimental Determination of Relative Permeabilities for a Rich Gas/Condensate System Using Live Fluid." SPE Reservoir Evaluation & Engineering 12, no. 02 (April 14, 2009): 263–69. http://dx.doi.org/10.2118/109810-pa.
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Summary Measurement of gas and condensate relative permeabilities typically is performed through steady-state linear coreflood experiments using model fluids. This study addresses experimental measurement of relative permeabilities for a rich-gas/condensate reservoir using a live, single-phase reservoir fluid. Using a live, single-phase reservoir fluid eliminates the difficulties in designing a relatively simple model fluid that replicates the complicated thermodynamic and transport properties of a near-critical fluid. Two-phase-flow tests were performed across a range of pressures and flow rates to simulate reservoir conditions from initial production through depletion. A single-phase multirate experiment was also performed to assess inertial, or non-Darcy, effects. Correlations were developed to represent both the gas and condensate relative permeabilities as a function of capillary number. A nearly 20-fold increase in gas relative permeability was observed from the low- to high-capillary-number flow regime. Compositional simulations were performed to assess the impact of the experimental results for vertical- and horizontal-well geometries. Introduction Well-deliverability estimates for gas/condensate systems require accurate prediction of both gas and condensate effective permeability. This is particularly important within the near-wellbore region where the pressures often fall below dewpoint causing retrograde condensation. Within this region, pressure gradients in both flowing phases are large and the interfacial tension between the gas and condensate is low. This results in relative permeabilities that are rate sensitive. Under these conditions, both capillary number and non-Darcy effects must be considered in modeling of gas/condensate flows. The relative permeabilities increase with increasing capillary number and are reduced by inertial, or non-Darcy, flow effects. Gas and condensate relative permeabilities are typically determined by steady-state linear coreflood experiments. Numerous experimental studies have been performed demonstrating an improvement in both gas and condensate relative permeability at high velocities and at low interfacial tension (Henderson et al. 1998; Henderson et al. 1997; Ali et al. 1997). These studies used model fluids to represent the reservoir fluid, which generally represented leaner gas/condensate systems. Chen et al. (1995) performed similar experiments using a recombined gas/condensate system from a North Sea field. Proper recombination with surface gas and condensate samples, however, assumes that the correct condensate/gas ratio is known. Using single-phase downhole samples obtained at pressures above the dewpoint eliminates this uncertainty. Fevang and Whitson (1996) have shown that krg for a steady state process is a function of the krg/kro ratio, where the krg/kro ratio is a function of pressure. The dependency of krg on both the capillary number (Nc) and the krg/kro ratio for a pseudosteady-state process has been demonstrated experimentally by Whitson et al. (1999) and Mott et al. (1999). These studies used either model fluids or recombined reservoir fluids with krg/kro ratios primarily within the range of 1 to 90. The lower krg/kro ratios represent richer fluids, while the higher krg/kro ratios represent leaner fluids. The fluids studied in this paper, however, are significantly richer, with krg/kro ratios in the range of 0.05 to 0.15 on the basis of fluid compositions at initial reservoir conditions. Non-Darcy or inertial effects reduce relative permeabilities. This has been demonstrated through linear coreflood experiments by several investigators (Lombard et al. 2000; Henderson et al. 2000; Mott et al. 2000). Multirate non-Darcy single-phase experiments were performed as part of this study because of the anticipated high flow rates from this reservoir. The objectives of this study were (1) to experimentally measure gas and condensate relative permeabilities for a rich gas/condensate system using a live, single-phase reservoir fluid; (2) assess the magnitude of inertial effects through the measurement of the non-Darcy coefficient; and (3) evaluate the impact of the capillary-number-dependent relative permeabilities and non-Darcy effects on the performance of vertical and horizontal wells.
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Bozorgzadeh, Manijeh, and Alain C. Gringarten. "Estimating Productivity-Controlling Parameters in Gas/Condensate Wells From Transient Pressure Data." SPE Reservoir Evaluation & Engineering 10, no. 02 (April 1, 2007): 100–111. http://dx.doi.org/10.2118/94018-pa.
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Summary The ability to predict well deliverability is a key issue for the development of gas/condensate reservoirs. We show in this paper that well deliverability depends mainly on the gas relative permeabilities at both the endpoint and the near-wellbore saturations, as well as on the reservoir permeability. We then demonstrate how these parameters and the base capillary number can be obtained from pressure-buildup data by using single-phase and two-phase pseudopressures simultaneously. These parameters can in turn be used to estimate gas relative permeability curves. Finally, we illustrate this approach with both simulated pressure-buildup data and an actual field case. Introduction and Background In gas/condensate reservoirs, a condensate bank forms around the wellbore when the bottomhole pressure (BHP) falls below the dewpoint pressure. This creates three different saturation zones around the well. Close to the wellbore, high condensate saturation reduces the effective permeability to gas, resulting in severe well productivity decline (Kniazeff and Nvaille 1965; Afidick et al. 1994; Lee and Chaverra 1998; Jutila et al. 2001; Briones et al. 2002). This decline is reduced at high gas rates and/or low capillary forces, which lower condensate saturation in the immediate vicinity of the wellbore, resulting in a corresponding increase in the gas relative permeability. This is called the capillary-number effect, positive coupling, viscous stripping, or velocity stripping (Boom et al. 1995; Henderson et al. 1998, 2000a; Ali et al. 1997a; Blom et al. 1997). High gas rates, on the other hand, induce inertia (also referred to as turbulent or non-Darcy flow effects), which reduces productivity. Well productivity is thus a balance between capillary number and inertia effects (Boom et al. 1995; Henderson et al. 1998, 2000a; Ali et al. 1997a, 1997b; Blom et al. 1997; Mott et al. 2000.). Well-deliverability forecasts for gas/condensate wells are usually performed with the help of numerical compositional simulators. Compositional simulation requires fine gridding to model the formation of the condensate bank with the required accuracy (Ali et al. 1997a). Non-Darcy flow and capillary-number effects (Mott 2003) are accounted for through empirical correlations, which require inputs such as the base capillary number (i.e., the minimum value required to see capillary-number effects), the reservoir absolute permeability, and the relative permeability curves. These are usually determined experimentally, but laboratory measurements at near-wellbore conditions are very difficult and expensive to obtain. An alternative, as shown in this paper, is to obtain them from well-test data. Well-test analysis is recognized as a valuable tool for reservoir surveillance and monitoring and provides estimates of a number of parameters required for reservoir characterization, reservoir simulation, and well-productivity forecasting. In gas/condensate reservoirs, when the BHP is below the dewpoint pressure, the effective permeability to gas in the near-wellbore region and at initial liquid saturation can be estimated with single-phase pseudopressures (Al-Hussainy et al. 1966) and a two- or three-region radial composite well-test-interpretation model (Chu and Shank 1993; Gringarten et al. 2000; Daungkaew et al. 2002), whereas the reservoir absolute permeability may be determined with two-phase steady-state pseudopressures (Raghavan et al. 1999; Xu and Lee 1999). In this paper, we show that well-test analysis can provide additional parameters, such as the gas relative permeabilities at both the endpoint and the near-wellbore saturations and the base capillary number. These in turn can be used to generate estimated relative permeability curves for gas.
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Nagy, Stanislaw, and Jakub Siemek. "Confined Phase Envelope of Gas-Condensate Systems in Shale Rocks." Archives of Mining Sciences 59, no. 4 (December 1, 2014): 1005–22. http://dx.doi.org/10.2478/amsc-2014-0069.
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Abstract Natural gas from shales (NGS) and from tight rocks are one of the most important fossil energy resource in this and next decade. Significant increase in gas consumption, in all world regions, will be marked in the energy sector. The exploration of unconventional natural gas & oil reservoirs has been discussed recently in many conferences. This paper describes the complex phenomena related to the impact of adsorption and capillary condensation of gas-condensate systems in nanopores. New two phase saturation model and new algorithm for search capillary condensation area is discussed. The algorithm is based on the Modified Tangent Plane Criterion for Capillary Condensation (MTPCCC) is presented. The examples of shift of phase envelopes are presented for selected composition of gas-condensate systems.
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Hassan, Amjed, Mohamed Mahmoud, Muhammad Shahzad Kamal, Syed Muhammad Shakil Hussain, and Shirish Patil. "Novel Treatment for Mitigating Condensate Bank Using a Newly Synthesized Gemini Surfactant." Molecules 25, no. 13 (July 2, 2020): 3030. http://dx.doi.org/10.3390/molecules25133030.
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Condensate accumulation in the vicinity of the gas well is known to curtail hydrocarbon production by up to 80%. Numerous approaches are being employed to mitigate condensate damage and improve gas productivity. Chemical treatment, gas recycling, and hydraulic fracturing are the most effective techniques for combatting the condensate bank. However, the gas injection technique showed temporary condensate recovery and limited improvement in gas productivity. Hydraulic fracturing is considered to be an expensive approach for treating condensate banking problems. In this study, a newly synthesized gemini surfactant (GS) was developed to prevent the formation of condensate blockage in the gas condensate reservoirs. Flushing the near-wellbore area with GS will change the rock wettability and thereby reduce the capillary forces holding the condensate due to the strong adsorption capacity of GS on the rock surface. In this study, several measurements were conducted to assess the performance of GS in mitigating the condensate bank including coreflood, relative permeability, phase behavior, and nuclear magnetic resonance (NMR) measurements. The results show that GS can reduce the capillary pressure by as much as 40%, increase the condensate mobility by more than 80%, and thereby mitigate the condensate bank by up to 84%. Phase behavior measurements indicate that adding GS to the oil–brine system could not induce any emulsions at different salinity levels. Moreover, NMR and permeability measurements reveal that the gemini surfactant has no effect on the pore system and no changes were observed in the T2 relaxation profiles with and without the GS injection. Ultimately, this work introduces a novel and effective treatment for mitigating the condensate bank. The new treatment showed an attractive performance in reducing liquid saturation and increasing the condensate relative permeability.
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Lysek, Mark, Marissa LaMadrid, Peter Day, and David Goodstein. "The melting of unsaturated capillary condensate." Langmuir 9, no. 4 (April 1993): 1040–45. http://dx.doi.org/10.1021/la00028a027.
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Cao, Lihu, Jinsheng Sun, Jianyi Liu, and Jiquan Liu. "Experiment and Application of Wax Deposition in Dabei Deep Condensate Gas Wells with High Pressure." Energies 15, no. 17 (August 26, 2022): 6200. http://dx.doi.org/10.3390/en15176200.
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The Dabei deep high-pressure condensate gas field occupies the paramount position in the Tarim Oilfield in China, the exploration and developments of which have been progressing. Since the initial development, the wax deposition and plugging in the wellbore and gathering pipeline have been the most bothering issues, resulting in the reduction or even shutdown of condensate gas well production. Therefore, the wax appearance temperature of Dabei condensate oil was studied using the capillary viscometer, differential scanning calorimetry (DSC), and polarizing microscope observation. The wax content was tested by using the DSC and crystallization separation test method. Finally, the wax appearance temperatures of degassed condensate oil and equilibrium condensate oil under different pressures were tested. Experimental results show that the wax appearance temperature measured by polarizing microscope observation was higher than that measured by the DSC and capillary viscometer, the lag of which can be recorded as the cloud point. The wax appearance temperature measured by polarizing microscope observation is of high accuracy. Secondly, the DSC method is not sufficient for measuring wax precipitation at low temperatures, showing a lower wax content than the crystallization separation test method. Thus, the wax content of Dabei condensate oil can be better measured by using the crystallization separation test method. Additionally, the wax precipitation law of equilibrium condensate oil is opposite to that of degassed condensate oil. The wax appearance temperature of equilibrium condensate oil increases as the pressure decreases. The results of wax appearance temperature of equilibrium condensate oil provide a useful and quick index to judge the potential risk of wax precipitation in the Tarim Oilfield, which can provide an efficient strategy for the development of waxy condensate gas reservoirs and the optimization of wax prevention and treatment technology.
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Hassan, Amjed, Mohamed Mahmoud, Abdulaziz Al-Majed, Ayman Al-Nakhli, Mohammed Bataweel, and Salaheldin Elkatatny. "Mitigation of Condensate Banking Using Thermochemical Treatment: Experimental and Analytical Study." Energies 12, no. 5 (February 28, 2019): 800. http://dx.doi.org/10.3390/en12050800.
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Condensate banking is a common problem in tight gas reservoirs because it diminishes the gas relative permeability and reduces the gas production rate significantly. CO2 injection is a common and very effective solution to mitigate the condensate damage around the borehole in tight gas reservoirs. The problem with CO2 injection is that it is a temporary solution and has to be repeated frequently in the field in addition to the supply limitations of CO2 in some areas. In addition, the infrastructure required at the surface to handle CO2 injection makes it expensive to apply CO2 injection for condensate removal. In this paper, a new permanent technique is introduced to remove the condensate by using a thermochemical technique. Two chemicals will be used to generate in situ CO2, nitrogen, steam, heat, and pressure. The reaction of the two chemicals downhole can be triggered either by the reservoir temperature or a chemical activator. Two chemicals will start reacting and produce all the mentioned reaction products after 24 h of mixing and injection. In addition, the reaction can be triggered by a chemical activator and this will shorten the time of reaction. Coreflooding experiments were carried out using actual condensate samples from one of the gas fields. Tight sandstone cores of 0.9 mD permeability were used. The results of this study showed that the thermochemical reaction products removed the condensate and reduced its viscosity due to the high temperature and the generated gases. The novelty in this paper is the creation of micro-fractures in the tight rock sample due to the in-situ generation of heat and pressure. These micro-fractures reduced the capillary forces that hold the condensate and enhanced the rock relative permeability. The creation of micro-fractures and in turn the reduction of the capillary forces can be considered as permanent condensate removal.
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Bozorgzadeh, Manijeh, and Alain C. Gringarten. "Condensate Bank Characterization from Well Test Data and Fluid PVT Properties." SPE Reservoir Evaluation & Engineering 9, no. 05 (October 1, 2006): 596–611. http://dx.doi.org/10.2118/89904-pa.
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Summary Published well-test analyses in gas/condensate reservoirs in which the pressure has dropped below the dewpoint are usually based on a two- or three-region radial composite well-test interpretation model to represent condensate dropout around the wellbore and initial gas in place away from the well. Gas/condensate-specific results from well-test analysis are the mobility and storativity ratios between the regions and the condensate-bank radius. For a given region, however, well-test analysis cannot uncouple the storativity ratio from the region radius, and the storativity ratio must be estimated independently to obtain the correct bank radius. In most cases, the storativity ratio is calculated incorrectly, which explains why condensate bank radii from well-test analysis often differ greatly from those obtained by numerical compositional simulation. In this study, a new method is introduced to estimate the storativity ratios between the different zones from buildup data when the saturation profile does not change during the buildup. Application of the method is illustrated with the analysis of a transient-pressure test in a gas/condensate field in the North Sea. The analysis uses single-phase pseudo pressures and two- and three-zone radial composite well-test interpretation models to yield the condensate-bank radius. The calculated condensate-bank radius is validated by verifying analytical well-test analyses with compositional simulations that include capillary number and inertia effects. Introduction and Background When the bottomhole flowing pressure falls below the dewpoint in a gas/condensate reservoir, retrograde condensation occurs, and a bank of condensate builds up around the producing well. This process creates concentric zones with different liquid saturations around the well (Fevang and Whitson 1996; Kniazeff and Nvaille 1965; Economides et al. 1987). The zone away from the well, where the reservoir pressure is still above the dewpoint, contains the original gas. The condensate bank around the wellbore contains two phases, reservoir gas and liquid condensate, and has a reduced gas mobility, except in the immediate vicinity of the well at high production rates, where the relative permeability to gas is greater than in the bank because of capillary number effects (Danesh et al. 1994; Boom et al. 1995; Henderson et al. 1998; Mott et al. 1999).
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Liu, Hua, Zhi Liang Shi, Xiang Fang Li, and Yun Cong Gao. "Mathematical Model for Condensate Gas Flow in Porous Media with Phase Change." Advanced Materials Research 616-618 (December 2012): 850–57. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.850.
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The retrograde condensation occurs in the condensate gas reservoir when the formation pressure is under dew point. The condensate appears in the formation with phase change in the process of condensate gas flowing in porous media, which change the temperature field and distribution of fluid pressure and affect flow rules of condensate gas in porous media accordingly. New momentum equations are set up, considering Non-Darcy flow effects, the phase change between condensate gas and condensate, phase velocity and fluid character, based on a simple model of three zones. Surface tension and capillary pressure were introduced into the new model. At the same time energy equations are deduced considering latent heat of vaporization and fluid-solid heat coupling. A mathematical model of multiphase flow in porous media with phase change is set up in this paper combining new momentum equations, new equations of energy with equations of mass conservation.
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Samnioti, Anna, Vassiliki Anastasiadou, and Vassilis Gaganis. "Application of Machine Learning to Accelerate Gas Condensate Reservoir Simulation." Clean Technologies 4, no. 1 (March 1, 2022): 153–73. http://dx.doi.org/10.3390/cleantechnol4010011.
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According to the roadmap toward clean energy, natural gas has been pronounced as the perfect transition fuel. Unlike usual dry gas reservoirs, gas condensates yield liquid which remains trapped in reservoir pores due to high capillarity, leading to the loss of an economically valuable product. To compensate, the gas produced on the surface is stripped from its heavy components and reinjected back to the reservoir as dry gas thus causing revaporization of the trapped condensate. To optimize this gas recycling process compositional reservoir simulation is utilized, which, however, takes very long to complete due to the complexity of the governing differential equations implicated. The calculations determining the prevailing k-values at every grid block and at each time step account for a great part of total CPU time. In this work machine learning (ML) is employed to accelerate thermodynamic calculations by providing the prevailing k-values in a tiny fraction of the time required by conventional methods. Regression tools such as artificial neural networks (ANNs) are trained against k-values that have been obtained beforehand by running sample simulations on small domains. Subsequently, the trained regression tools are embedded in the simulators acting thus as proxy models. The prediction error achieved is shown to be negligible for the needs of a real-world gas condensate reservoir simulation. The CPU time gain is at least one order of magnitude, thus rendering the proposed approach as yet another successful step toward the implementation of ML in the clean energy field.
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Greguš, Michal, Pavlo Ďurč, Julia Lačná, František Foreti, and Peter Kubáň. "Study of Various Parameters that Influence the Content of Exhaled Breath Condensate Used in the Diagnosis of Gastroesophageal Reflux Disease." Hungarian Journal of Industry and Chemistry 46, no. 1 (July 1, 2018): 29–34. http://dx.doi.org/10.1515/hjic-2018-0007.
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Abstract In this work, various parameters that influence the ionic content and pH of exhaled breath condensate in of the noninvasive diagnosis of gastroesophageal reflux disease were studied. Exhaled breath condensate samples were collected using a miniature and inexpensive sampling device. Capillary electrophoresis with contactless conductometric detection was used to monitor the ionic content of exhaled breath condensate. Background electrolyte composed of 20 mM of 2-(N-Morpholino)ethanesulfonic acid, 20 mM of L-Histidine, 2 mM of 18-Crown-6 and 30 M of cetyltrimethylammonium bromide facilitated the rapid separation of anions and cations, both in less than 2 minutes. The possibility of contamination of the exhaled breath condensate by saliva is discussed in detail. The day-to-day repeatability (n=5) of the ionic content and pH of the exhaled breath condensate was studied and was satisfactory, reflecting mainly the physiological variability
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Rezaveisi, Mohsen, Kamy Sepehrnoori, Gary A. Pope, and Russell T. Johns. "Thermodynamic Analysis of Phase Behavior at High Capillary Pressure." SPE Journal 23, no. 06 (August 23, 2018): 1977–90. http://dx.doi.org/10.2118/175135-pa.
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Summary High capillary pressure has a significant effect on the phase behavior of fluid mixtures. The capillary pressure is high in unconventional reservoirs because of the small pores in the rock, so understanding the effect of capillary pressure on phase behavior is necessary for reliable modeling of unconventional shale-gas and tight-oil reservoirs. As the main finding of this paper, first we show that the tangent-plane-distance method cannot be used to determine phase stability and present a rigorous thermodynamic analysis of the problem of phase stability with capillary pressure. Second, we demonstrate that there is a maximum capillary pressure (Pcmax) where calculation of capillary equilibrium using bulk-phase thermodynamics is possible and derive the necessary equations to obtain this maximum capillary pressure. We also briefly discuss the implementation of the capillary equilibrium in a general-purpose compositional reservoir simulator. Two simulation case studies for synthetic gas condensate reservoirs were performed to illustrate the influence of capillary pressure on production behavior for the fluids studied.
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Kazarinov, K., V. Malinin, V. Shchelkonogov, and A. Chekanov. "DEVELOPMENT OF TECHNOLOGY FOR STUDYING THE PULMONARY SURFACTANT SYSTEM USING ELECTRIC GENERATION OF CAPILLARY WAVES (EXPRESS METHOD)." Russian Journal of Biological Physics and Chemisrty 7, no. 2 (November 15, 2022): 293–96. http://dx.doi.org/10.29039/rusjbpc.2022.0517.
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Based on the use of a new design of a capillary wave generator, a method is proposed for studying the human surfactant system for diagnosing patients suffering from pulmonary diseases, including after infection with COVID-19. The study of the surfactant system of the lungs (SSL) in a healthy organism and in pathology is one of the important tasks of modern pulmonology. The proposed method for monitoring human exhaled air condensate consists in applying a condensate sample to the surface of an aqueous solution, on which capillary waves are created due to the phenomenon of electrostriction, the change in the amplitude and phase of which makes it possible to determine the surface tension of the liquid and the parameters of the surfactant layer. To this end, we have developed a design and received a patent for the invention of a liquid parameter meter containing a liquid cuvette, a generator associated with a system for creating capillary waves on the liquid surface and a system for recording the characteristics of liquid vibrations. Improving the technology of the CCL control process is aimed at solving the problems of reducing the time of measuring the CCL and reducing the cost of the method.
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Septiadi, Wayan Nata, and Nandy Putra. "Boiling Phenomenon of Tabulate Biomaterial Wick Heat Pipe." Applied Mechanics and Materials 776 (July 2015): 289–93. http://dx.doi.org/10.4028/www.scientific.net/amm.776.289.
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This research purposed to know the performance of heat pipe using wick made from biomaterial. Biomaterial (Coral) is the porous media which has the relative homogenous and small porous structures. The homogenous structures and the small biomaterial have the better capillarity and could be used as wick to circulate condensate in heat pipe. The heat pipe made from copper pipe with 50 mm in length and the inside and outer diameter was 25 mm and 24 mm in each, with the wick as thick as 1 mm made from Tabulate. Heat sink was adhered to the condenser part of heat pipe as wide as 637.5 cm2. The study was the observation of phenomena in porous media boiling between biomaterials with solid copper, in which the observations were made by using High Speed Video Camera (HSVC). Tabulate biomaterial has the porous structure which quite homogeny and the best capillary energy. The biomaterial as wick heat pipe could keep the condition of heat pipe from easily reachs the transition condition.
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Mahdaviara, Mehdi, and Abbas Helalizadeh. "A proposed capillary number dependent model for prediction of relative permeability in gas condensate reservoirs: a robust non-linear regression analysis." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 75 (2020): 24. http://dx.doi.org/10.2516/ogst/2020017.
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Well deliverability reduction as a result of liquid (condensate) build up in near well regions is an important deal in the development of gas condensate reservoirs. The relative permeability is an imperative factor for characterization of the aforementioned problem. The dependence of relative permeability on the coupled effects of Interfacial Tension (IFT) and flow velocity (capillary number) together with phase saturation is well established in the literature. In gas condensate reservoirs, however, the influence of IFT and velocity on this parameter becomes more evident. The current paper aims to establish a new model for predicting the relative permeability of gas condensate reservoirs by employing the direct interpolation technique. To this end, the regression analysis was carried out using seven sets of literature published experimental data. The validity analysis was executed by utilizing statistical parameters integrated with graphical descriptions. Furthermore, a comparison was carried out between the proposed model and some literature published empirical models. The results of the examination demonstrated that the new model outperformed other correlations from the standpoints of accuracy and reliability.
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Hassan, Amjed, Mohamed Abdalla, Mohamed Mahmoud, Guenther Glatz, Abdulaziz Al-Majed, and Ayman Al-Nakhli. "Condensate-Banking Removal and Gas-Production Enhancement Using Thermochemical Injection: A Field-Scale Simulation." Processes 8, no. 6 (June 23, 2020): 727. http://dx.doi.org/10.3390/pr8060727.
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Condensate-liquid accumulation in the vicinity of a well is known to curtail gas production up to 80%. Numerous approaches are employed to mitigate condensate banking and improve gas productivity. In this work, a field-scale simulation is presented for condensate damage removal in tight reservoirs using a thermochemical treatment strategy where heat and pressure are generated in situ. The impact of thermochemical injection on the gas recovery is also elucidated. A compositional simulator was utilized to assess the effectiveness of the suggested treatment on reducing the condensate damage and, thereby, improve the gas recovery. Compared to the base case, represented by an industry-standard gas injection strategy, simulation studies suggest a significantly improved hydrocarbon recovery performance upon thermochemical treatment of the near-wellbore zone. For the scenarios investigated, the application of thermochemicals allowed for an extension of the production plateau from 104 days, as determined for the reference gas injection case, to 683 days. This represents a 6.5-fold increase in production plateau time, boosting gas recovery from 25 to 89%. The improved recovery is attributed to the reduction of both capillary pressure and condensate viscosity. The presented work is crucial for designing and implementing thermochemical treatments in tight-gas reservoirs.
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Blom, Saskia M. P., and Jacques Hagoort. "The Combined Effect of Near-Critical Relative Permeability and Non-Darcy Flow on Well Impairment by Condensate Drop Out." SPE Reservoir Evaluation & Engineering 1, no. 05 (October 1, 1998): 421–29. http://dx.doi.org/10.2118/51367-pa.
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This paper (SPE 51367) was revised for publication from paper SPE 39976, first presented at the 1998 SPE Gas Technology Symposium, Calgary, 15-18 March. Original manuscript received for review 19 March 1998. Revised manuscript received 8 July 1998. Paper peer approved 13 July 1998. Summary We present a comprehensive numerical method to calculate well impairment based on steady-state radial flow. The method incorporate near-critical relative permeability and saturation-dependent inertial resistance. Example calculations show that near-critical relative permeability, which depends on the capillary number, and non-Darcy flow are strongly coupled. Inertial resistance gives rise to a higher capillary number. In its turn, the improved mobility of the gas phase caused by a higher capillary number enhances the importance of the inertial resistance. The effect of non-Darcy flow is much more pronounced in gas condensate reservoirs than in dry gas reservoirs. Well impairment may be grossly overestimated if the dependence of relative permeability on the capillary number is ignored. P. 421
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Jamiolahmady, Mahmoud, Ali Danesh, D. H. Tehrani, and Mehran Sohrabi. "Variations of Gas/Condensate Relative Permeability With Production Rate at Near-Wellbore Conditions: A General Correlation." SPE Reservoir Evaluation & Engineering 9, no. 06 (December 1, 2006): 688–97. http://dx.doi.org/10.2118/83960-pa.
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Summary It has been demonstrated, first by this laboratory and subsequently by other researchers, that the gas and condensate relative permeability can increase significantly by increasing rate, contrary to the common understanding. There are now a number of correlations in the literature and commercial reservoir simulators accounting for the positive effect of coupling and the negative effect of inertia at near-wellbore conditions. The available functional forms estimate the two effects separately and include a number of parameters, which should be determined with measurements at high-velocity conditions. Measurements of gas/condensate relative permeability at simulated near-wellbore conditions are very demanding and expensive. Recent experimental findings in this laboratory indicate that measured gas/condensate relative permeability values on cores with different characteristics become more similar if expressed in terms of fractional flow instead of the commonly used saturation. This would lower the number of rock curves required in reservoir studies. Hence, we have used a large data bank of gas/condensate relative permeability measurements to develop a general correlation accounting for the combined effect of coupling and inertia as a function of fractional flow. The parameters of the new correlation are either universal, applicable to all types of rocks, or can be determined from commonly measured petrophysical data. The developed correlation has been evaluated by comparing its prediction with the gas/condensate relative permeability values measured at near-wellbore conditions on reservoir rocks not used in its development. The results are quite satisfactory, confirming that the correlation can provide reliable information on variations of relative permeability at near-wellbore conditions with no requirement for expensive measurements. Introduction The process of condensation around the wellbore in a gas/condensate reservoir, when the pressure falls below the dewpoint, creates a region in which both gas and condensate phases flow. The flow behavior in this region is controlled by the viscous, capillary, and inertial forces. This, along with the presence of condensate in all the pores, dictates a flow mechanism that is different from that of gas/oil and gas/condensate in the bulk of the reservoir (Danesh et al. 1989). Accurate determination of gas/condensate relative permeability (kr) values, which is very important in well-deliverability estimates, is a major challenge and requires an approach different from that for conventional gas/oil systems. It has been widely accepted that relative permeability (kr) values at low values of interfacial tension (IFT) are strong functions of IFT as well as fluid saturation (Bardon and Longeron 1980; Asar and Handy 1988; Haniff and Ali 1990; Munkerud 1995). Danesh et al. (1994) were first to report the improvement of the relative permeability of condensing systems owing to an increase in velocity as well as that caused by a reduction in IFT. This flow behavior, referred to as the positive coupling effect, was subsequently confirmed experimentally by other investigators (Henderson et al. 1995, 1996; Ali et al. 1997; Blom et al. 1997). Jamiolahmady et al. (2000) were first to study the positive coupling effect mechanistically capturing the competition of viscous and capillary forces at the pore level, where there is simultaneous flow of the two phases with intermittent opening and closure of the gas passage by condensate. Jamiolahmady et al. (2003) developed a steady-dynamic network model capturing this flow behavior and predicted some kr values, which were quantitatively comparable with the experimentally measured values.
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Kubáň, Peter, Pavol Ďurč, Julia Lačná, Michal Greguš, František Foret, Jiří Dolina, Štefan Konečny, et al. "Capillary Electrophoretic Analysis of Exhaled Breath Condensate in the Diagnosis of Gastroesophageal Reflux Disease." Hungarian Journal of Industry and Chemistry 46, no. 1 (July 1, 2018): 23–27. http://dx.doi.org/10.1515/hjic-2018-0006.
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Abstract In this work, capillary electrophoresis with contactless conductometric detection (CCD) was used for the analysis of the ionic content of exhaled breath condensate (EBC) to differentiate between healthy individuals and patients with gastroesophageal reflux disease (GERD). The exhaled breath condensate was collected using a miniature sample collection device and the content analyzed using a separation electrolyte composed of 20 mM 2-(N-morpholino)ethanesulfonic acid, 20 mM L-histidine, 2 mM 18-Crown-6 and 30 M cetyltrimethylammonium bromide. The separation of anions took less than 2.5 minutes, while the cations were separated in less than 1.5 minutes. The most significantly elevated ions in the group of patients suffering from gastroesophageal reflux disease were chloride, nitrate, propionate and butyrate. Although the number of subjects was too small to draw definite conclusions with regard to the discriminatory power of these ions, the pilot data are promising for EBC as a useful non-invasive alternative for other methods used in the diagnosis of gastroesophageal reflux disease
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Hamidi, Samin, Maryam Khoubnasabjafari, Khalil Ansarin, Vahid Jouyban-Gharamaleki, and Abolghasem Jouyban. "Chiral separation of methadone in exhaled breath condensate using capillary electrophoresis." Analytical Methods 9, no. 15 (2017): 2342–50. http://dx.doi.org/10.1039/c7ay00110j.
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Raikovskyi, M. I., A. Yu Demianov, and O. Yu Dinariev. "On the accounting of capillary forces in the modeling of gas-condensate mixtures." Oil and Gas Studies, no. 2 (May 16, 2022): 37–52. http://dx.doi.org/10.31660/0445-0108-2022-2-37-52.
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This article is devoted to the study of the effect of the capillary pressure jump (CPJ) on the phase equilibrium between the liquid and gas phases, which are described by the Peng-Robinson equation of state. A numerical analysis the form of phase diagrams (PD) of a gascondensate mixture at various CPJ is carried out. Based on the specifics of the problem, the PD is constructed in the gas pressure - liquid pressure coordinates. The boundary of the two-phase region is defined as the region of existence of the two-phase state of the mixture, without additional studies on the stability of the single-phase state. The analysis is carried out without reference to any specific porous medium, and it is based on the conditions of phase equilibrium at different CPJ only. The obtained results demonstrate the importance of CPJ effects in computing the phase equilibrium of a gas-condensate mixture, when modeling the flow in a porous medium. The described computational and theoretical technique is applicable to two-phase multicomponent systems with an arbitrary number of components and is easily generalized to other equations of state, such as the Redlich-Kwong equation, equations of state of gas condensate systems.
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Neshat, Sajjad S., and Gary A. Pope. "Three-Phase Relative Permeability and Capillary Pressure Models With Hysteresis and Compositional Consistency." SPE Journal 23, no. 06 (September 10, 2018): 2394–408. http://dx.doi.org/10.2118/191384-pa.
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Summary New coupled three-phase hysteretic relative permeability and capillary pressure models have been developed and tested for use in compositional reservoir simulators. The new formulation incorporates hysteresis and compositional consistency for both capillary pressure and relative permeability. This approach is completely unaffected by phase flipping and misidentification, which commonly occur in compositional simulations. Instead of using phase labels (gas/oil/solvent/aqueous) to define hysteretic relative permeability and capillary pressure parameters, the parameters are continuously interpolated between reference values using the Gibbs free energy (GFE) of each phase at each timestep. Models that are independent of phase labels have many advantages in terms of both numerical stability and physical consistency. The models integrate and unify relevant physical parameters, including hysteresis and trapping number, into one rigorous algorithm with a minimum number of parameters for application in numerical reservoir simulators. The robustness of the new models is demonstrated with simulations of the miscible water-alternating-gas (WAG) process and solvent stimulation to remove condensate and/or water blocks in both conventional and unconventional formations.
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Kewen, Li, and Firoozabadi Abbas. "Experimental Study of Wettability Alteration to Preferential Gas-Wetting in Porous Media and Its Effects." SPE Reservoir Evaluation & Engineering 3, no. 02 (April 1, 2000): 139–49. http://dx.doi.org/10.2118/62515-pa.
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Summary In a recent theoretical study, Li and Firoozabadi [Li, K. and Firoozabadi, A.: "Phenomenological Modeling of Critical-Condensate Saturation and Relative Permeabilities in Gas-Condensate Systems," paper SPE 56014 available from SPE, Richardson, Texas (2000)] showed that if the wettability of porous media can be altered from preferential liquid-wetting to preferential gas-wetting, then gas-well deliverability in gas-condensate reservoirs can be increased. In this article, we present the results that the wettability of porous media may indeed be altered from preferential liquid-wetting to preferential gas-wetting. In the petroleum literature, it is often assumed that the contact angle through liquid-phase ? is equal to 0° for gas-liquid systems in rocks. As this work will show, while ? is always small, it may not always be zero. In laboratory experiments, we altered the wettability of porous media to preferential gas-wetting by using two chemicals, FC754 and FC722. Results show that in the glass capillary tube ? can be altered from about 50 to 90° and from 0 to 60° by FC754 for water-air and normal decane-air systems, respectively. While untreated Berea saturated with air has a 60% imbibition of water, its imbibition of water after chemical treatment is almost zero and its imbibition of normal decane is substantially reduced. FC722 has a more pronounced effect on the wettability alteration to preferential gas-wetting. In a glass capillary tube ? is altered from 50 to 120° and from 0 to 60° for water-air and normal decane-air systems, respectively. Similarly, because of wettability alteration with FC722, there is no imbibition of either oil or water in both Berea and chalk samples with or without initial brine saturation. Entry capillary pressure measurements in Berea and chalk give a clear demonstration that the wettability of porous media can be permanently altered to preferential gas-wetting. Introduction In a theoretical work,1 we have modeled gas and liquid relative permeabilities for gas-condensate systems in a simple network. The results imply that when one alters the wettability of porous media from strongly non-gas-wetting to preferential gas-wetting or intermediate gas-wetting, there may be a substantial increase in gas-well deliverability. The increase in gas-well deliverability of gas-condensate reservoirs is our main motivation for altering the wettability of porous media to preferential gas-wetting. Certain gas-condensate reservoirs experience a sharp drop in gas-well deliverability when the reservoir pressure drops below the dewpoint.2–4 Examples include many rich gas-condensate reservoirs that have a permeability of less than 100 md. In these reservoirs, it seems that the viscous forces alone cannot enhance gas-well deliverability. One may suggest removing liquid around the wellbore via phase-behavior effects through CO2 and propane injection. Both have been tried in the field with limited success; the effect of fluid injection around the wellbore for the removal of the condensate liquid is temporary. Wettability alteration can be a very important method for the enhancement of gas-well deliverability. If one can alter the wettability of the wellbore region to intermediate gas-wetting, gas may flow efficiently in porous media. As early as 1941, Buckley and Leverett5 recognized the importance of wettability on water flooding performance. Later, many authors studied the effect of wettability on capillary pressure, relative permeability, initial water saturation, residual oil saturation, oil recovery, electrical properties of reservoir rocks, reserves, and well stimulation.6–16 reported that it might be possible to improve oil displacement efficiency by wettability adjustment during water flooding. In 1967, Froning and Leach8 reported a field test in Clearfork and Gallup reservoirs for improving oil recovery by wettability alteration. Kamath9 then reviewed wettability detergent flooding. He noted that it was difficult to draw a definite conclusion regarding the success of detergent floods from the data available in the literature. Penny et al.12 presented a technique to improve well stimulation by changing the wettability for gas-water-rock systems. They added a surfactant in the fracturing fluid. This yielded impressive results; the production following cleanup after fracturing in gas wells generally was 2 to 3 times greater than field averages or offset wells treated with conventional techniques. Penny et al.12 believed that increased production was due to wettability alteration. However, they did not demonstrate that wettability had been altered. Recently, Wardlaw and McKellar17 reported that only 11% pore volume (PV) water imbibed into the Devonian dolomite samples with bitumen. The water imbibition test was conducted vertically in a dry core (saturated with air). Based on the imbibition experiments, they pointed out that many gas reservoirs in the western Alberta foothills of the Rocky Mountains were partially dehydrated and their wettability altered to a weakly water-wet or strongly oil-wet condition due to bitumen deposits on the pores. The water imbibition results of Wardlaw and McKellar17 demonstrated that the inappropriate hypothesis for wetting properties of gas reservoirs might lead to underestimation of hydrocarbon reserves.
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Wang, Yijun, Yili Kang, Dingfeng Wang, Lijun You, Mingjun Chen, and Xiaopeng Yan. "Liquid phase blockage in micro-nano capillary pores of tight condensate reservoirs." Capillarity 5, no. 1 (December 19, 2021): 12–22. http://dx.doi.org/10.46690/capi.2022.01.02.
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Hamidi, Samin, Maryam Khoubnasabjafari, Khalil Ansarin, Vahid Jouyban-Gharamaleki, and Abolghasem Jouyban. "Direct Analysis of Methadone in Exhaled Breath Condensate by Capillary Zone Electrophoresis." Current Pharmaceutical Analysis 12, no. 2 (March 6, 2016): 137–45. http://dx.doi.org/10.2174/1573412911666150911202647.
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Teng, H., P. Cheng, and T. S. Zhao. "Instability of condensate film and capillary blocking in small-diameter-thermosyphon condensers." International Journal of Heat and Mass Transfer 42, no. 16 (August 1999): 3071–83. http://dx.doi.org/10.1016/s0017-9310(98)90375-1.
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Kubáň, Petr, Eeva-Gerda Kobrin, and Mihkel Kaljurand. "Capillary electrophoresis – A new tool for ionic analysis of exhaled breath condensate." Journal of Chromatography A 1267 (December 2012): 239–45. http://dx.doi.org/10.1016/j.chroma.2012.06.085.
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Miyara, Akio. "Flow Dynamics and Heat Transfer of Wavy Condensate Film." Journal of Heat Transfer 123, no. 3 (August 14, 2000): 492–500. http://dx.doi.org/10.1115/1.1370522.
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Wave evolution and heat transfer behavior of a wavy condensate film down a vertical wall have been investigated by a finite difference method, in which the algorithm is based on the HSMAC method, and a staggered grid fixed on a physical space is employed. For the moving interface, newly proposed methods are used. A random perturbation of the film thickness is generated near the leading edge. The perturbation quickly diminishes once and small-amplitude long waves are propagated downstream. Then the amplitude of the wave increases rapidly at a certain position, and the wave shape changes from a sinusoidal wave to a pulse-like solitary wave which is composed of a large-amplitude wave and capillary waves. A circulation flow occurs in the large wave and it affects the temperature field. The heat transfer is enhanced by space-time film thickness variation and convection effects.
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Meisingset, K. K. "Uncertainties in Reservoir Fluid Description for Reservoir Modeling." SPE Reservoir Evaluation & Engineering 2, no. 05 (October 1, 1999): 431–35. http://dx.doi.org/10.2118/57886-pa.
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Summary The objective of the present paper is to communicate the basic knowledge needed for estimating the uncertainty in reservoir fluid parameters for prospects, discoveries, and producing oil and gas/condensate fields. Uncertainties associated with laboratory analysis, fluid sampling, process description, and variations over the reservoirs are discussed, based on experience from the North Sea. Introduction Reliable prediction of the oil and gas production is essential for the optimization of development plans for offshore oil and gas reservoirs. Because large investments have to be made early in the life of the fields, the uncertainty in the in-place volumes and production profiles may have a direct impact on important economical decisions. The uncertainties in the description of reservoir fluid composition and properties contribute to the total uncertainty in the reservoir description, and are of special importance for the optimization of the processing capacities of oil and gas, as well as for planning the transport and marketing of the products from the field. Rules of thumb for estimating the uncertainties in the reservoir fluid description, based on field experience, may therefore be of significant value for the petroleum industry. The discussion in the present paper is based on experience from the fields and discoveries where Statoil is an operator or partner, including almost all fields on the Norwegian Continental Shelf,1,2 and all types of reservoir oils and gas condensates except heavy oils with stock-tank oil densities above 940 kg/m3 (below 20° API). Fluid Parameters in the Reservoir Model The following parameters are used to describe the reservoir fluid in a "black oil" reservoir simulation model:densities at standard conditions of stabilized oil, condensate, gas, and water;viscosity (?O) oil formation volume factor (B O) and gas-oil ratio (RS) of reservoir oil;viscosity (?G) gas formation volume factor (B G) and condensate/gas ratio (RSG) of reservoir gas;viscosity (?W) formation volume factor (BW) and compressibility of formation water; andsaturation pressures: bubblepoint for reservoir oil, dew point for reservoir gas. The actual input is usually slightly more complex, with saturation pressure given as a function of depth, with RS and R SG defined as a function of saturation pressure, and with oil and gas viscosities and formation volume factors given as a function of reservoir pressure for a range of saturation pressure values. However, minor changes in saturation pressure versus depth are usually neglected, and the oil dissolved in the reservoir gas can also be neglected (RSG=0) when the solubility is small. Uncertainties in the modeling of other fluid parameters (interfacial tension may for instance be of importance, because of its effect on the capillary pressure), or compositional effects like revaporization of oil into injection gas, are not discussed here. Uncertainties in viscosity, formation volume factor and compressibility of formation water, and density of gas at standard conditions, are judged to be of minor importance for the total uncertainties in the reservoir model. The uncertainty in the salinity of the formation water is discussed here instead, because it is used for calculations of water resistivity for log interpretation, and therefore, affects the estimates of initial water saturation in the reservoir. In a compositional reservoir simulation model, the composition of reservoir oil and gas (with, typically, 4 to 10 pseudocomponents) is given as a function of depth, while phase equilibria and fluid properties are calculated by use of an equation of state. However, the uncertainties in the fluid description can be described in approximately the same way as for a "black oil" model. Quantified uncertainty ranges in the present paper are coarse estimates, aiming at covering 80% of the probability range for each parameter (estimated value plus/minus an uncertainty estimate defining the range between the 10% and 90% probability values3). Prospect Evaluation Assessments of the uncertainties in the reservoir description, as a basis for economic evaluation, are made in all phases of exploration and production. Of course, the complexity in the fluid description increases strongly from prospect evaluation through the exploration phase and further into the production phase, but the main fluid parameters in the reservoir model are the same. The prediction of fluid parameters in the prospect evaluation phase, before the first well has been drilled, is based on reservoir fluid data from discoveries near by, information about source rocks and migration, and empirical correlations. The uncertainties vary strongly from prospect to prospect. The probability as a function of volume for the presence of reservoir oil and gas is usually the most important fluid parameter. The probability for predicting the correct hydrocarbon phase varies from 50% (equal probability for reservoir oil and gas) to 90% (in regions where either oil or gas reservoirs are strongly dominating, or when the reservoir fluid can be expected to be the same as in another discovery near by). For formation volume factors, gas/liquid ratios, viscosities, and densities, an estimate for the most probable value as well as for a high and low possible value is commonly given. The range between the high and low value is often designed to include 80% of the probability range for the parameter, but accurate uncertainty estimates can seldom be made. The ratio of the high and low value is, typically, 1.5 to 50 for R SG 1.1 to 1.5 for B G 1.1 to 2.5 for ?G 1.2 to 3 for RS 1.1 to 2 for BO 1.5 to 5 for (?O and 1.03 to 1.1 for densities of stabilized oil and condensate. From Discovery to Production After a discovery has been made, the fluid description is based on laboratory analyses of reservoir fluid samples from drill-stem tests, production tests, and wireline sampling (RFT, FMT, MDT) in exploration and production wells. Pressure gradients in the reservoirs from measurements during wireline and drill-stem tests, analysis of residual hydrocarbons in core material from various depths, measurements of gas/oil ratio during drill-stem and production tests, and measurements of product streams from the field, give important supplementary information.
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Newton, J. M., Barry S. Rothman, and F. Ann Walker. "Separation and Determination of Diesel Contaminants in Various Fish Products by Capillary Gas Chromatography." Journal of AOAC INTERNATIONAL 74, no. 6 (November 1, 1991): 986–90. http://dx.doi.org/10.1093/jaoac/74.6.986.
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Abstract A semiquantitative capillary column gas chromatographic method Is described for the determination of diesel fuel contamination in various canned seafood products. The diesel contaminants are separated from the fish sample by steam distillation, with little carry-over of interfering intrinsic materials such as fish oils. The diesel fuel is extracted from the condensate with n-hexane, and the extract is analyzed on an SPB-1 fused silica capillary column. The efficiency of recovery of diesel fuel added to canned seafood at levels of 40-400 ppt ranged from 72 to 102%. With the additional step of concentrating the hexane extract, the sensitivity of this procedure may be increased at least 10-fold. This procedure can detect the differences among diesel fuel grades No. 1,2, and 5, and variations within diesel grade No. 2, and thus may be useful in determining the type of petroleum contaminants present in various canned fish products.
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Li, Yong, Yongle Hu, Baozhu Li, and Jing Xia. "Deliverability of wells in carbonate gas condensate reservoirs and the capillary number effect." Petroleum Science 6, no. 1 (February 4, 2009): 51–56. http://dx.doi.org/10.1007/s12182-009-0009-9.
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Astakhov, A. V., S. P. Khazov, and L. N. �konomova. "Effect of capillary condensate of methane on electrophysical and strength properties of coal." Journal of Mining Science 28, no. 3 (1992): 231–34. http://dx.doi.org/10.1007/bf00732769.
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Rudy, T. M., and R. L. Webb. "An Analytical Model to Predict Condensate Retention on Horizontal Integral-Fin Tubes." Journal of Heat Transfer 107, no. 2 (May 1, 1985): 361–68. http://dx.doi.org/10.1115/1.3247423.
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In this paper, the authors develop a general analytical model to predict the amount of surface that is flooded during condensation on a horizontal, integral-fin tube. The model is based on capillary equations that predict the amount of liquid rise on a vertical u-shaped channel. The space between adjacent integral fins forms such a channel. The authors compare the model to test data taken during condensation on three integral-fin tubes (748-to-1378 fpm) and a range of fluid properties. The analytical model predicts the amount of liquid retention on a horizontal, integral-fin tube within ± 10 percent over most of the data. The analysis is performed for the case of negligible vapor shear.
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Alfin amanda, Alfin Amanda, Nova R. Ismail, and M. Agus Sahbana. "ANALISA BENTUK PERMUKAAN PELAT PENYERAP SPONGE TERHADAP KINERJA SOLAR STILL DOUBLE SLOPE TIPE V." Jurnal Energi dan Teknologi Manufaktur (JETM) 3, no. 01 (June 30, 2020): 17–22. http://dx.doi.org/10.33795/jetm.v3i01.51.
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This study aims to determine the surface shape of the sponge absorbent plate to the performance of the solar still double slope type V. The surface shape of the sponge absorbent plate uses sponge models of triangles, fins, waves and flat with a thickness of 5 cm. experimental Tests methods use direct solar radiation and using sea water is used as raw material. The experiment produced 4,527 liters of condensate water with highest solar still efficiency of 50.14% using a sponge wave absorber plate with an area of 13,940.76 cm2. The Sea water disability to flow capillary to the surface of the absorbent plate affecting the performance of solar still.
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Khalilov, M. S. "About improving the efficiency of the development of gas condensate deposits with oil rims." SOCAR Proceedings, no. 4 (December 31, 2021): 61–66. http://dx.doi.org/10.5510/ogp20210400614.
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On the basis of a two-phase two-dimensional mathematical model, the process of developing gas condensate fields with oil springs was investigated during the implementation of the technological approach, according to which the gas extracted from the gas cap returns to the oil part after separation by injection wells drilled in oil-water contacts. It has been established that the injection of separated gas into water-oil contact reduces the value of residual oil saturation in the flushed zone with gas, since not only mobile oil evaporates, but also capillary bound, increasing the displacement ratio, and, ultimately, the efficiency of reservoir development is ensured.
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Wheatley, Courtney M., Wayne J. Morgan, Nicholas A. Cassuto, William T. Foxx-Lupo, Cori L. Daines, Mary A. Morgan, Hanna Phan, and Eric M. Snyder. "Exhaled Breath Condensate Detects Baseline Reductions in Chloride and Increases in Response to Albuterol in Cystic Fibrosis Patients." Clinical Medicine Insights: Circulatory, Respiratory and Pulmonary Medicine 7 (January 2013): CCRPM.S12882. http://dx.doi.org/10.4137/ccrpm.s12882.
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Impaired ion regulation and dehydration is the primary pathophysiology in cystic fibrosis (CF) lung disease. A potential application of exhaled breath condensate (EBC) collection is to assess airway surface liquid ionic composition at baseline and in response to pharmacological therapy in CF. Our aims were to determine if EBC could detect differences in ion regulation between CF and healthy and measure the effect of the albuterol on EBC ions in these populations. Baseline EBC Cl−, DLCO and SpO2 were lower in CF (n = 16) compared to healthy participants (n = 16). EBC Cl− increased in CF subjects, while there was no change in DLCO or membrane conductance, but a decrease in pulmonary-capillary blood volume in both groups following albuterol. This resulted in an improvement in diffusion at the alveolar-capillary unit, and removal of the baseline difference in SpO2 by 90-minutes in CF subjects. These results demonstrate that EBC detects differences in ion regulation between healthy and CF individuals, and that albuterol mediates increases in Cl− in CF, suggesting that the benefits of albuterol extend beyond simple bronchodilation.
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Kuczyński, Szymon. "Analysis of Vapour Liquid Equilibria in Unconventional Rich Liquid Gas Condensate Reservoirs." ACTA Universitatis Cibiniensis 65, no. 1 (December 1, 2014): 46–51. http://dx.doi.org/10.1515/aucts-2015-0008.
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Abstract At the beginning of 21st century, natural gas from conventional and unconventional reservoirs has become important fossil energy resource and its role as energy fuel has increased. The exploration of unconventional gas reservoirs has been discussed recently in many conferences and journals. The paper presents considerations which will be used to build the thermodynamic model that will describe the phenomenon of vapour - liquid equilibrium (VLE) in the retrograde condensation in rocks of ultra-low permeability and in the nanopores. The research will be limited to "tight gas" reservoirs (TGR) and "shale gas" reservoirs (SGR). Constructed models will take into account the phenomenon of capillary condensation and adsorption. These studies will be the base for modifications of existing compositional simulators
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Dinariev, O. Yu, and N. V. Evseev. "Role of Capillary Forces in Filtration of a Gas–Condensate Mixture near a Well." Journal of Engineering Physics and Thermophysics 77, no. 2 (March 2004): 266–74. http://dx.doi.org/10.1023/b:joep.0000028503.58759.9b.
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