Mobility of Hydrocarbon Liquids in Gas Condensate Reservoirs: Interpretation of Depletion Laboratory Experiments

Morel, Danielle; Lomer, J-F.; Morineau, Y.M.; Putz, A.

doi:10.2523/24939-ms

Cited by 11 publications

(6 citation statements)

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“…12 are less sensitive to viscous forces than the gas phase relative permeability. The model's results of relative permeabilities are also consistent with the experimental observation by Henderson et al 9 These authors found that the relative permeability of both phases increased with the increase of flow rate but that the liquid relative permeability increased less than the gas relative permeability.…”

Section: Features Of Gas Relativesupporting

confidence: 89%

“…These measurements were conducted in the presence of connate water. Morel et al 9 reported a critical condensate saturation of less than 1% for ϭ0.05 dyn/cm and connate water saturation of 20%. The critical condensate saturation was measured in a vertical dolomite core.…”

Section: Introductionmentioning

confidence: 98%

“…Various authors [4][5][6][7][8][9] have measured S cc and a wide range of observations has been reported. The measured values of S cc are generally in the range of 10 to 50%.…”

Section: Introductionmentioning

confidence: 99%

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Phenomenological Modeling of Critical Condensate Saturation and Relative Permeabilities in Gas/ Condensate Systems

Firoozabadi

2000

SPE Journal

122

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The effects of gravity, viscous forces, interfacial tension, and wettability on the critical condensate saturation and relative permeability of gas condensate systems are studied using a phenomenological simple network model. The results from the simple model show that wettability significantly affects both critical condensate saturation and relative permeability. Relative permeability at some saturations may increase significantly as the contact angle is altered from 0°͑strongly liquid-wet͒ to 85°͑intermediately gas-wet͒. The results suggest that gas well deliverability in condensate reservoirs can be enhanced by wettability alteration near the wellbore.

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Section: Features Of Gas Relativesupporting

confidence: 89%

Section: Introductionmentioning

confidence: 98%

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Phenomenological Modeling of Critical Condensate Saturation and Relative Permeabilities in Gas/ Condensate Systems

Firoozabadi

2000

SPE Journal

122

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“…Much has appeared recently, in the open literature, about relative permeability hysteresis [3][4][5][6][7] . The compositional simulator used in this study has an option to handle the impact of capillary number N c on relative permeability where:…”

Section: Relative Permeability Considerationsmentioning

confidence: 99%

Hydrocarbons Injection to Improve Recovery from Gas Condensate Reservoirs: A Simulation Approach

Harouaka¹,

Al-Hashim

2002

SPE Gas Technology Symposium

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractHydrocarbons injection has been reported, in the open literature, to improve both gas and condensate recovery from gas condensate reservoirs. The injection process is considered once a liquid ring builds up around the well bore thereby reducing drastically gas delivery. Actual reservoir and fluids data from a deep gas condensate well, completed in five distinct layers, were used as input to a compositional reservoir simulator to assess the following: 1) Evaluation of various (four) injection fluids; 2) impact of shut in and injection as well as shut in alone; 3) Impact of minimum flowing bottom hole pressure constraints; 4) evaluation of a single layer model equivalent to the original multi layer well; 5) impact of shut in and injection on the equivalent single layer model; 6) impact of shut in alone on the equivalent single layer model and 7) evaluation of a binary system (77% C 1 and 23% nC 4 ) at a relatively low pressure and temperature.From the four tested injection fluids the C 4 -C 5 mixture gave the best results for productivity restoration. The injected C 4 -C 5 mixture, at the high dew point considered in this work, creates, through miscibility, a single liquid phase around the w e l l b o r e .At the trailing edge of the liquid-phase around the well bore the capillary number increases sharply indicating a sharp drop in IFT. Hence the gas coming in towards the well bore is just like the liquids fully miscible with the liquid phase around the well bore.Simulation runs done on a binary system, at a low dew point pressure indicate the miscible process will also work but the single phase around the well bore will be a vapor phase.

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“…Several researchers [5][6][7][8][9][10][11][12][13][14] coincide in that the relative permeabilities behavior for gas and condensate flow could not be considered as unique or even constant, since these are function of the capillary number and vary with changes in the fluids properties, like viscosity and interfacial tension, and with rate (velocity) changes. Several researchers [5][6][7][8][9][10][11][12][13][14] coincide in that the relative permeabilities behavior for gas and condensate flow could not be considered as unique or even constant, since these are function of the capillary number and vary with changes in the fluids properties, like viscosity and interfacial tension, and with rate (velocity) changes.…”

Section: Spe 59049mentioning

confidence: 99%

Relative Permabilities of Gas-Condensate Fluids in Heterogeneous Porous Media

Moctezuma-Berthier¹,

V.²

2000

Proceedings of SPE International Petroleum Conference and Exhibition in Mexico

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractReservoir cores have complex porous structure and conventional approach to characterize two phase flows in the laboratory can be inadequate, especially in presence of fractured or vuggy porous media. An important problem is the determination of the relative permeabilities to the interpretation of two phase flow experiments. The relative permeability analysis for gas and condensate fluids presents special interest due to changes in fluids properties, like interfacial tension and viscosity due to compositional changes. In this way, relative permeability curves depend on the capillary number; thus the experimental conditions for the fluids and porous media must be carefully analyzed in order to get representative reservoir conditions. This work presents a methodology for the realization of laboratory representative studies of flow in heterogeneous cores flowing with gas and condensate equivalents fluids. The relative permeability curves are found fitting the oil production and pressure drop experimental data with a compositional simulator. This simulator was used to have a detailed behavior of the fluids during the experiment. Selection of the equivalent fluids was made plotting the derivative of the capillary number with respect to pressure vs. capillary number. We analyzed the curve for different mixtures and results compared with the reservoirs fluids curve. With this analysis, we got a pressure interval for the experiment and the required composition, the required to prepare a mixture which capillary number behavior was like reservoir fluids. In order to reproduce the detailed petrophysical model of the sample, the longitudinal porosity distribution was gotten from X-ray computerized tomography. In addition, the petrophysical porosity and effective permeability behavior of the sample for different confining pressures was done. This methodology was applied to fluids and samples from a carbonate fractured gas and condensate reservoir from Gulf of Mexico. It was possible to get the relative permeability curves using a binary mixture of C 1 -C 10 in a specific range of pressure, where the capillary number for both real and mixture was quite similar. The match between laboratory and simulation results was very good.

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Mobility of Hydrocarbon Liquids in Gas Condensate Reservoirs: Interpretation of Depletion Laboratory Experiments

Cited by 11 publications

References 0 publications

Phenomenological Modeling of Critical Condensate Saturation and Relative Permeabilities in Gas/ Condensate Systems

Phenomenological Modeling of Critical Condensate Saturation and Relative Permeabilities in Gas/ Condensate Systems

Hydrocarbons Injection to Improve Recovery from Gas Condensate Reservoirs: A Simulation Approach

Relative Permabilities of Gas-Condensate Fluids in Heterogeneous Porous Media

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