Academic literature on the topic 'Capillary condensates'
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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.
Full textDissertations / Theses on the topic "Capillary condensates"
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Nowak, Dominika. "Supercooled capillary condensates." Thesis, University of Leeds, 2009. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.515376.
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Barber, Peter Andrew. "Surface effects on capillary condensates in a nanoscale pore." Thesis, University of Leeds, 2006. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.434217.
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Heath, David John. "Characterisation of waxy gas-condensates by high temperature capillary gas chromatography and oxidative degradation." Thesis, University of Plymouth, 1995. http://hdl.handle.net/10026.1/460.
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High molecular weight (HMW) hydrocarbons (defined herein as C35+ compounds) are difficult to characterise by conventional analytical methods. Very few studies have reported precise and reproducible quantification of such compounds in fossil fuels. Nonetheless, such components have important effects on the physical and biological fate of fossil fuels in the geosphere. For example, the phase behaviour of waxy gas condensates is significantly affected by the varying proportions of HMW compounds. Similarly HMW compounds are amongst the most resistant petroleum components to biodegradation. The current study reports the development of reproducible quantitative high temperature capillary gas chromatography (HTCGC) methods for studying both these aspects of the chemistry of HMW hydrocarbons. In addition those hydrocarbons which remain unresolved when analysed by gas chromatography (so called unresolved complex mixtures UCMs) are also studied. UCMs may account for a large portion of the hydrocarbons in many fossil fuels yet very little is known about their composition. Knowledge of these compounds may be important in enhancing the prediction of phase behaviour. Oxidative degradation and GC-MS is used to elucidate the types of structures present within the UCM. The concentrations of C3S4h. ydrocarbons in two unusually waxy gas condensates from high temperature wells in the North Sea were determined by HTCGC. The whole C, 5+ fraction comprised about 20% of the total hydrocarbons and consisted of compounds with carbon numbers extending up to and beyond Coo. By paying particular attention to sample dissolution and injection, good reproducibility and precision were obtained. For example, for authentic n-C, to n-C60 alkanes a relative standard deviation of under 5% for manual injection, linear response factors (1.01 Cm to 0.99 C6), and a linear calibration for 5 ng to 25 ng on-column were found. Limits of detection are reported for the first time for HMW n-alkanes. The limits were found to be as low as 0.8 ng for Cto to 1.87 ng for C60. Tristearin is proposed as a suitable HTCGC internal standard for quantification since the FID response factor (1.1) was close to that of the HMW n-alkanes and response was linear. Importantly, when co-injected with the two waxy North Sea condensates, tristearin was adequately separated from the closest eluting alkanes, n-C59 and n-C60 under normal operating conditions. Qualitative characterisation of the HMW compounds in the waxy gas condensates and in synthetic wax blends (polywax 1000) using HTCGC-EI MS and HTCGC-CI MS produced molecular ions or pseudo molecular ions for n-alkanes up to n- C6o. The spectra of some HMW compounds contained fragment ions characteristic of branched compounds but detailed characterisation was very limited. This study has also shown, for the first time, the significance of the unresolved complex mixture in gas condensatesU. CM hydrocarbonsa ccountedf or over 20% of the total hydrocarbons in a waxy North sea condensateT. he condensatew as first distilled and the distillate UCMs isolated. Thesew ere found to be between 64 to 97 % unresolved after molecular sieving (5A) and urea adduction. The UCMs were oxidised using CrO3/AcOHw hich produced5 -12% C02, and 55-83% dichloromethane-solublep roducts. Thus 65-94% of the original UCMs were accounted for as oxidation products. The remainder were thought to be water soluble acids which could not be determined in the presence of the AcOH reagent. Of the recovered oxidised products, 27- 81 % were resolved and these comprised mainly n-monocarboxylic acids (19-48 %). The average chain length was found to be C12 indicating the average length of alkyl groups. Branched acids, ketones, ketoacids, ndicarboxylic acids, branched dicarboxylic acids, lactones, isoprenoid acids, alkylcyclohexane carboxylic acids and toluic acids accounted for the majority of the remaining resolved products. The distillate UCMs all showed variations in amountso f productsb ut not in composition. Retro-structurala nalysis suggestedth at the UCM in the gasc ondensatew as mainly aliphatic and branched.T he numbero f isomerso f simple brancheda lkaneso ver the UCM molecular weight range (determined by cryoscopy) was calculated to be over 15000. Overall, oxidation provided structural information for about half of the UCM. HTCGC was also used to measure the biodegradability of HMW alkanes in a waxy Indonesian oil. Traditional alkane isolation techniques (TLC and CC) discriminated against HMW compounds above C40 whereas adsorption onto alumina in a warm cyclohexane slurry provided an aliphatic fraction still rich in HMW compounds and suitable as a biodegradation substrate. A waxy Indonesian oil was subjected to 136 day biodegradation by Pseudomonas fluorescens. Extraction efficiencies of over 90 % (RSD <5 %) were obtained for n-alkanes up to C6o using continuous liquid-liquid extraction. Over 80 % of the oil aliphatic fraction was degraded within 14 days. After 136 days only 14% of the original aliphatic fraction remained, yet surprisingly no decreases in the concentrations of compounds above C45 were observed. However, the use of a rapid screening biodegradation method proved conclusively that Pseudomonasfluorescens was capable of utilising n-alkanes up to C60 once the bacteria had acclimated to the HMW alkanes. This is the first report of bacterial utilisation of an n-alkane as large as C.
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Mohammadi, Shahrokh. "Stochastic modelling of capillary dominated gas condensate flow in porousmedia." Thesis, Heriot-Watt University, 1993. http://hdl.handle.net/10399/1451.
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Al, Ghamdi Bander Nasser Ayala H. Luis Felipe. "Analysis of capillary pressure and relative permeability effects on the productivity of naturally fractured gas-condensate reservoirs using compositional simulation." [University Park, Pa.] : Pennsylvania State University, 2009. http://etda.libraries.psu.edu/theses/approved/WorldWideIndex/ETD-4622/index.html.
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Calisgan, Huseyin. "Comprehensive Modelling Of Gas Condensate Relative Permeability And Its Influence On Field Performance." Phd thesis, METU, 2005. http://etd.lib.metu.edu.tr/upload/12606667/index.pdf.
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The productivity of most gas condensate wells is reduced significantly due to condensate banking when the bottom hole pressure falls below the dew point. The liquid drop-out in these very high rate gas wells may lead to low recovery problems. The most important parameter for determining condensate well productivity is the effective gas permeability in the near wellbore region, where very high velocities can occur. An understanding of the characteristics of the high-velocity gas-condensate flow and relative permeability data is necessary for accurate forecast of well productivity.
In order to tackle this goal, a series of two-phase drainage relative permeability measurements on a moderate permeability North Marmara &ndash1 gas well carbonate core plug sample, using a simple synthetic binary retrograde condensate fluid sample were conducted under reservoir conditions which corresponded to near miscible conditions. As a fluid system, the model of methanol/n-hexane system was used as a binary model that exhibits a critical point at ambient conditions. The interfacial tension by means of temperature and the flow rate were varied in the laboratory measurements. The laboratory experiments were repeated for the same conditions of interfacial tension and flow rate at immobile water saturation to observe the influence of brine saturation in gas condensate systems. The laboratory experiment results show a clear trend from the immiscible relative permeability to miscible relative permeability lines with decreasing interfacial tension and increasing velocity. So that, if the interfacial tension is high and the flow velocity is low, the relative permeability functions clearly curved, whereas the relative permeability curves straighten as a linear at lower values of the interfacial tension and higher values of the flow velocity. The presence of the immobile brine saturation in the porous medium shows the same shape of behavior for relative permeability curves with a small difference that is the initial wetting phase saturations in the relative permeability curve shifts to the left in the presence of immobile water saturation. A simple new mathematical model is developed to compute the gas and condensate relative permeabilities as a function of the three-parameter. It is called as condensate number
NK so that the new model is more sensitivity to temperature that represents implicitly the effect of interfacial tension. The new model generated the results were in good agreement with the literature data and the laboratory test results. Additionally, the end point relative permeability data and residual saturations satisfactorily correlate with literature data. The proposed model has fairly good fitness results for the condensate relative permeability curves compared to that of gas case. This model, with typical parameters for gas condensates, can be used to describe the relative permeability behavior and to run a compositional simulation study of a single well to better understand the productivity of the field.
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Maeda, Nobuo. "Phase Transitions of Long-Chain N-Alkanes at Interfaces." Phd thesis, 2001. http://hdl.handle.net/1885/47795.
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An experimental study of phase transitions of long-chain n-alkanes induced by the effect of interfaces is described. ¶ The phase behaviour of long-chain n-alkanes (carbon number 14, 16, 17, 18) adsorbed at isolated mica surfaces and confined between two mica surfaces has been studied in the vicinity of and down to several degrees below the bulk melting points, Tm. Using the Surface Force Apparatus we have measured the thickness of alkane films adsorbed from vapour (0.97 [equal to or greater-than] p/p[subscript o] [equal to or greater-than] 0.997), studied capillary condensation transition, subsequent growth of capillary condensates between two surfaces, and phase transitions in both the adsorbed films and the condensates. By measuring the growth rate of the capillary condensates we have identified a transition in the lateral mobility of molecules in the adsorbed films on isolated mica surfaces. This transition to greater mobility occurs slightly above Tm for n-hexadecane, n-heptadecane and n-octadecane but several degrees below Tm for n-tetradecane, and is accompanied by a change in wetting behaviour and a measurable decrease in adsorbed film thickness for n-heptadecane and n-octadecane. Capillary condensates that form below Tm remain liquid, but may freeze if the degree of confinement is reduced by separation of the mica surfaces. An increase in the area of the liquid-vapour interface relative to that of the liquid-mica interface facilitates freezing in the case of the long-chain alkanes, which show surface freezing at the liquid-vapour interface. ¶ Although thermodynamic properties of the surface freezing transition have been rather well documented, the kinetics involved in formation of such ordered monolayers has so far received very little attention. We studied the surface tension of n-octadecane as a function of temperature in the vicinity of Tm, using the static Wilhelmy plate and the dynamic maximum bubble pressure methods. The two methods give different results on cooling paths, where nucleation of the surface ordered phase is involved, but agree on heating paths, where both methods measure properties of the equilibrium surface phase. On cooling paths, the surface of bubbles may supercool below the equilibrium surface freezing temperature. The onset of surface freezing is marked by a sharp drop in the surface tension. The transition is accompanied by an increased stability of the films resulting in longer bubble lifetimes at the liquid surface, which suggests that the mechanical properties of the surfaces change from liquid-like to solid-like. Our results suggest occurrence of supercooling of the monolayer itself.
Book chapters on the topic "Capillary condensates"
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FCO CAMPASSI REIS, ÁLVARO. "PETROPHYSICAL PROPERTIES AND EVALUATION OF TIGHT GAS SANDS IN POTIGUAR BASIN ONSHORE." In Resumos do I Encontro Brasileiro de Petrofísica de Campos Maduros. Editora Realize, 2022. http://dx.doi.org/10.46943/i.ebpcm.2022.01.012.
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TIGHT GAS SANDS RESERVOIRS WERE ORIGINALLY DESCRIBED IN FORELAND BASINS GEOGRAPHICALLY LOCATED IN THE ROCKY MOUNTAINS IN NORTH AMERICA. THESE RESERVOIRS COMMONLY CONSTITUTE AN UNCONVENTIONAL PETROLEUM SYSTEM CALLED BCGS (BASIN CENTERED GAS SYSTEMS) WHOSE MAIN CHARACTERISTICS ARE: LOW PERMEABILITY, PRESENCE OF ABNORMALLY STATIC PRESSURE, ACCUMULATIONS NOT DEPENDENT ON GEOLOGICAL TRAPS, SEAL BY CAPILLARITY AND ABSENCE OF GAS/WATER CONTACT DOWNDIP, MASTER (1979) AND DAVIS (1984). DESPITE HAVING A DIFFERENT GEOLOGICAL CONTEXT, THE POTIGUAR BASIN ALSO PRESENTS IN ITS DEPOCENTERS, IN THE GRABENS OF APODI AND UMBUZEIRO, AN UNCONVENTIONAL GAS/CONDENSATE SYSTEM ANALOGOUS TO THAT ORIGINALLY DESCRIBED IN NORTH AMERICA. THIS PAPER DISCUSSES THE MAIN CHARACTERISTICS OF THIS SYSTEM FORMED BY CLASTIC RESERVOIRS OF VERY LOW PERMEABILITY AND POROSITY, FOUND IN THE PENDENCIA FORMATION OF THE POTIGUAR BASIN ONSHORE, BELOW 3 KM DEEP. THE PETROPHYSICAL INTERPRETATION WORKFLOW USED IN THE WELLS, SOME PROPERTIES OF THE RESERVOIRS AND THE RESULTS OBTAINED ARE DESCRIBED. AFTER THE EVALUATION OF THE WELLS IT WAS CONCLUDED THAT THE PROJECT REPRESENTED A GEOLOGICAL SUCCESS, ONCE IT CONFIRMED THE OCCURRENCE OF AN UNCONVENTIONAL SYSTEM IN THE AREA, HOWEVER, DUE TO SEVERAL ASPECTS AMONG THEM THE COSTS INVOLVED, A COMMERCIAL SUCCESS WAS NOT OBTAINED.
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FCO CAMPASSI REIS, ÁLVARO. "PETROPHYSICAL PROPERTIES AND EVALUATION OF TIGHT GAS SANDS IN POTIGUAR BASIN ONSHORE." In Resumos do I Encontro Brasileiro de Petrofísica de Campos Maduros. Editora Realize, 2022. http://dx.doi.org/10.46943/i.ebpcm.2022.01.012.
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TIGHT GAS SANDS RESERVOIRS WERE ORIGINALLY DESCRIBED IN FORELAND BASINS GEOGRAPHICALLY LOCATED IN THE ROCKY MOUNTAINS IN NORTH AMERICA. THESE RESERVOIRS COMMONLY CONSTITUTE AN UNCONVENTIONAL PETROLEUM SYSTEM CALLED BCGS (BASIN CENTERED GAS SYSTEMS) WHOSE MAIN CHARACTERISTICS ARE: LOW PERMEABILITY, PRESENCE OF ABNORMALLY STATIC PRESSURE, ACCUMULATIONS NOT DEPENDENT ON GEOLOGICAL TRAPS, SEAL BY CAPILLARITY AND ABSENCE OF GAS/WATER CONTACT DOWNDIP, MASTER (1979) AND DAVIS (1984). DESPITE HAVING A DIFFERENT GEOLOGICAL CONTEXT, THE POTIGUAR BASIN ALSO PRESENTS IN ITS DEPOCENTERS, IN THE GRABENS OF APODI AND UMBUZEIRO, AN UNCONVENTIONAL GAS/CONDENSATE SYSTEM ANALOGOUS TO THAT ORIGINALLY DESCRIBED IN NORTH AMERICA. THIS PAPER DISCUSSES THE MAIN CHARACTERISTICS OF THIS SYSTEM FORMED BY CLASTIC RESERVOIRS OF VERY LOW PERMEABILITY AND POROSITY, FOUND IN THE PENDENCIA FORMATION OF THE POTIGUAR BASIN ONSHORE, BELOW 3 KM DEEP. THE PETROPHYSICAL INTERPRETATION WORKFLOW USED IN THE WELLS, SOME PROPERTIES OF THE RESERVOIRS AND THE RESULTS OBTAINED ARE DESCRIBED. AFTER THE EVALUATION OF THE WELLS IT WAS CONCLUDED THAT THE PROJECT REPRESENTED A GEOLOGICAL SUCCESS, ONCE IT CONFIRMED THE OCCURRENCE OF AN UNCONVENTIONAL SYSTEM IN THE AREA, HOWEVER, DUE TO SEVERAL ASPECTS AMONG THEM THE COSTS INVOLVED, A COMMERCIAL SUCCESS WAS NOT OBTAINED.
Conference papers on the topic "Capillary condensates"
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Potsch, K. "Precipitation of Gas Condensates Under the Influence of Capillary Pressure in Porous Media." In ECMOR V - 5th European Conference on the Mathematics of Oil Recovery. European Association of Geoscientists & Engineers, 1996. http://dx.doi.org/10.3997/2214-4609.201406866.
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Pint, Cary L. "Capillary Force Guided Nanomanufacturing of Composite Materials for Advanced Battery Applications." In ASME 2017 International Mechanical Engineering Congress and Exposition. American Society of Mechanical Engineers, 2017. http://dx.doi.org/10.1115/imece2017-71738.
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This paper introduces the use of capillary thermodynamics as a powerful nanomanufacturing tool, and its specific application to infiltrate sulfur into 3-D nanostructured electrodes for advanced lithium-sulfur and/or sodium-sulfur battery development. The capillary effect specifically targets nucleation from the equilibrium vapor pressure of bulk sulfur (gas phase) onto nanoscale surfaces (liquid phase). This leads to condensates that nucleate and grow uniformly over the surface leading to self-limited and conformal composite materials moderated by the chemical potential driving force between the nanoscale nuclei and the bulk sulfur. Our studies show highly consistent and repeatable sulfur loading exceeding 80 wt.% sulfur, fast kinetics that can lead to full infiltration in ∼ 10 minutes, and synergy with pre-formed carbon materials including carbon nanotube arrays, carbon nanotube foams and sponges, and microporous carbons with pore sizes ∼ 0.5 nm. This overcomes challenges of scaling to high areal capacity in lithium-sulfur and sodium-sulfur batteries, and our results emphasize the highest reported areal capacities for solid-processed cathodes to date (> 19 mAh/cm2). This paves the route to batteries with energy density > 500 Wh/kg with reliable manufacturing processes that simultaneously sustain low cost and high throughput.
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Hassan, Amjed, Mohamed Mahmoud, Muhammad Shahzad Kamal, Abdulaziz Al-Majed, Ayman Al-Nakhli, Syed Muhammad Shakil Hussain, and Shirish Patil. "Mitigation of Gas Condensate Banking Using Thermochemical Fluids and Gemini Surfactant: A Comparison Study." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/206023-ms.
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Abstract Accumulation of condensate liquid around the production well can cause a significant reduction in gas production. Several methods are used to mitigate the condensate bank and maintain the gas production. The most effective approaches are altering the rock wettability or inducing multiple fractures around the wellbore. This paper presents a comparison study for two effective approaches in mitigating the condensate bank. The performance of thermochemical fluids (TCF) and gemini surfactant (GS) in removing the condensate liquid and improve the formation productivity is studied. In this work, several experiments were carried out including coreflooding, capillary pressure, and relative permeability measurements. The profiles of condensate saturations show that GS can mitigate the condensate bank by 84%, while TCF removed around 63% of the condensate liquid. Also, GS and TCF treatments can increase the relative permeability to condensate liquid by factors of 1.89 and 1.22 respectively, due to the wettability alteration mechanism. Capillary pressure calculations show that GS can reduce the capillary pressure by around 40% on average, while TCF leads to a 70% reduction in the capillary forces. Overall, injection of GS into the condensate region can lead to changing the wettability condition due to the chemical adsorption of GS on the pore surface, and thereby reduce the capillary forces and improve the condensate mobility. On the other hand, TCF injection can improve rock permeability and reduce capillary pressure. Both treatments (GS and TCF) showed very attractive performance in mitigating the condensate bank and improving the formation production for the long term. Finally, an integrated approach is presented that can mitigate the condensate damage by around 95%, utilizing the effective mechanisms of GS and TCF chemicals.
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Blom, S. M. P., and J. Hagoort. "How to Include the Capillary Number in Gas Condensate Relative Permeability Functions?" In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 1998. http://dx.doi.org/10.2118/49268-ms.
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Narayanaswamy, G., G. A. Pope, M. M. Sharma, M. K. Hwang, and R. N. Vaidya. "Predicting Gas Condensate Well Productivity Using Capillary Number and Non-Darcy Effects." In SPE Reservoir Simulation Symposium. Society of Petroleum Engineers, 1999. http://dx.doi.org/10.2118/51910-ms.
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Ehibor, Idahosa, Ikponmwosa Ohenhen, Bukolo Oloyede, Gbenga Adetoyi, Tochukwu Amaechi, Olanike Olajide, Ademola Kaka, and Anthony Woyengidiripre. "Gas Condensate Well Deliverability Model, a Field Case Study of a Niger Delta Gas Condensate Reservoir." In SPE Nigeria Annual International Conference and Exhibition. SPE, 2022. http://dx.doi.org/10.2118/212043-ms.
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Abstract Gas condensate banking accumulated near the wellbore occurs when the bottomhole pressure becomes less than the dew point pressure, allowing the liquid fraction to condense out of the gas phase. Once the accumulation near the wellbore is higher than critical condensate saturation, the liquid phase becomes mobile with the gas phase, affecting well deliverability and making it difficult to estimate gas and condensate flow rate from the reservoir due to two phase flow of fluid. This paper presents an analytical model that evaluates the well deliverability from the reservoir. The concept of two phases Pseudo-pressure is used in the interpretation and evaluation of well deliverability from the gas condensate reservoir. The model considers non-Darcy flow effects and capillary effects. The model is applied to a live field case study of a Niger Delta gas condensate reservoir to determine well deliverability. Gas and liquid production profile from the model showed 95% accuracy when compared with compositional simulation model. This model is encoded into a spreadsheet program using python to calculate well deliverability parameters.
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Solovev, Daniil Yurievich, Anton Sergeevich Epryntsev, Petr Ilich Eliseev, Andrey Gennadievich Yamov, Yamov Grigorievich Nerodenko, Elkin Bakirovich Guseynov, and Vladimir Alexandrovich Bobrov. "Adaptation of Capillary String for the Surfactants Delivery into a Gas Condensate Well and Optimization of its Operation Using Dynamic Multiphase Flow Simulator." In SPE Russian Petroleum Technology Conference. SPE, 2021. http://dx.doi.org/10.2118/206575-ms.
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Abstract The studied productive formation of gas condensate field is at the stage of declining production. The inflow of bottom water due to the rise of the GWC and the design features of horizontal wells (large tubing and liner diameters) create the prerequisites for the development of a liquid loading of wells. This necessitate the optimization of the existing method of liquid unloading by dosing surfactants into the annulus. In order to increase the efficiency of well treatment with a foaming agent, the use of a surfactant injection system through a capillary string suspended inside a tubing is considered. The use of this system allows to increase the speed and depth of surfactant delivery, use the potential of the well by simultaneous work in tubing and annulus during significant watering period (water flow rate: 50 and more m3 / day), reduce reagent losses associated with retention on the casing walls, and reduce the required consumption of surfactant. The capillary string for the pumping surfactant is applicated to ensuring the stable operation of gas condensate wells during liquid loading. But today there are not ready-made applied solutions for correctly accounting surfactant action in unsteady flows conditions in the well. The paper presents the substantiation and analysis of the capillary string introduction into the well for the pumping surfactant using specialized software. In the course of work, the main analysis tool is the dynamic modeling of multiphase flows in the conditions of steady and unsteady processes in wells. This approach use is aimed at determining the optimal depth and diameter of capillary, the required consumption and concentration of surfactant, the rate of its delivery to the bottomhole, and the liquid removal efficiency from the horizontal wellbore.
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Mabrouki, Bachir, Liz Sturman, Chantorn Butphet, and Anthony William Peacock. "Effect of High Reynolds and Capillary Numbers on Over-Pressured Rich Gas Condensate Reservoir Development." In International Petroleum Technology Conference. International Petroleum Technology Conference, 2014. http://dx.doi.org/10.2523/iptc-17840-ms.
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Chamarthy, Pramod, H. Peter J. de Bock, Boris Russ, Shakti Chauhan, Brian Rush, Stanton E. Weaver, Tao Deng, and Kripa Varanasi. "Novel Fluorescent Visualization Method to Characterize Transport Properties in Micro/Nano Heat Pipe Wick Structures." In ASME 2009 InterPACK Conference collocated with the ASME 2009 Summer Heat Transfer Conference and the ASME 2009 3rd International Conference on Energy Sustainability. ASMEDC, 2009. http://dx.doi.org/10.1115/interpack2009-89173.
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Heat pipes have been gaining a lot of popularity in electronics cooling applications due to their ease of operation, reliability, and high effective thermal conductivity. An important component of a heat pipe is the wick structure, which transports the condensate from condenser to evaporator. The design of wick structures is complicated by competing requirements to create high capillary driving forces and maintain high permeability. While generating large pore sizes will help achieve high permeability, it will significantly reduce the wick’s capillary performance. This study presents a novel experimental method to simultaneously measure capillary and permeability characteristics of the wick structures using fluorescent visualization. This technique will be used to study the effects of pore size and gravitational force on the flow-related properties of the wick structures. Initial results are presented on wick samples visually characterized from zero to nine g acceleration on a centrifuge. These results will provide a tool to understand the physics involved in transport through porous structures and help in the design of high performance heat pipes.
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Li, Baoyan, Ayaz Mehmani, Jinhong Chen, Daniel Taylan Georgi, and Guodong Jin. "The Condition of Capillary Condensation and Its Effects on Adsorption Isotherms of Unconventional Gas Condensate Reservoirs." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2013. http://dx.doi.org/10.2118/166162-ms.
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