Correlating Wettability Alteration with Changes in Gas Relative Permeability in Gas Condensate/ Volatile Oil Reservoirs.

2011 ◽  
Author(s):  
Syed Furqan Hassan Gilani ◽  
Mukul Mani Sharma ◽  
David Enrique Torres ◽  
Mohabbat Ahmadi ◽  
Gary Arnold Pope ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Volatile Oil ◽  
Gas Condensate ◽  
Oil Reservoirs ◽  
Wettability Alteration

scholarly journals Production improvement in gas condensate reservoirs by wettability alteration, using superamphiphobic titanium oxide nanofluid

2018 ◽  
Vol 73 ◽  
pp. 46 ◽  
Author(s):  
Pouriya Esmaeilzadeh ◽  
Mohammad Taghi Sadeghi ◽  
Alireza Bahramian
Keyword(s):  
Liquid Phase ◽  
Relative Permeability ◽  
Core Sample ◽  
Carbonate Reservoir ◽  
Gas Condensate ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Energy Materials ◽  
Gas Condensate Reservoirs ◽  
Production Improvement

Many gas condensate reservoirs suffer a loss in productivity owing to accumulation of liquid in near-wellbore region. Wettability alteration of reservoir rock from liquid-wetting to gas-wetting appears to be a promising technique for elimination of the condensate blockage. In this paper, we report use of a superamphiphobic nanofluid containing TiO2 nanoparticles and low surface energy materials as polytetrafluoroethylene and trichloro(1H,1H,2H,2H-perfluorooctyl)silane to change the wettability of the carbonate reservoir rock to ultra gas-wetting. The utilization of nanofluid in the wettability alteration of carbonate rocks to gas-wetting in core scale has not been reported already and is still an ongoing issue. Contact angle measurements was conducted to investigate the wettability of carbonate core plugs in presence of nanofluid. It was found that the novel formulated nanofluid used in this work can remarkably change the wettability of the rock from both strongly water- and oil-wetting to highly gas-wetting condition. The adsorption of nanoparticles on the rock and formation of nano/submicron surface roughness was verified by Scanning Electron Microscope (SEM) and Stylus Profilometer (SP) analyses. Using free imbibition test, we showed that the nanofluid can imbibe interestingly into the core sample, resulting in notable ultimate gas-condensate liquid recovery. Moreover, we studied the effect of nanofluid on relative permeability and recovery performance of gas/water and gas/oil systems for a carbonate core. The result of coreflooding tests demonstrates that the relative permeability of both gas and liquid phase increased significantly as well as the liquid phase recovery enhanced greatly after the wettability alteration to gas-wetting.

scholarly journals Pore-Scale Analysis of Condensate Blockage Mitigation by Wettability Alteration

Energies ◽  
2020 ◽  
Vol 13 (18) ◽  
pp. 4673
Author(s):  
Paula K. P. Reis ◽  
Marcio S. Carvalho
Keyword(s):  
Relative Permeability ◽  
Contact Angles ◽  
Gas Condensate ◽  
Wettability Alteration ◽  
Impact Factors ◽  
Pore Network Model ◽  
Flow Enhancement ◽  
Condensate Blockage ◽  
Relative Permeability Curves ◽  
Liquid Trapping

Liquid banking in the near wellbore region can lessen significantly the production from gas reservoirs. As reservoir rocks commonly consist of liquid-wet porous media, they are prone to liquid trapping following well liquid invasion and/or condensate dropout in gas-condensate systems. For this reason, wettability alteration from liquid to gas-wet has been investigated in the past two decades as a permanent gas flow enhancement solution. Numerous experiments suggest flow improvement for immiscible gas-liquid flow in wettability altered cores. However, due to experimental limitations, few studies evaluate the method’s performance for condensing flows, typical of gas-condensate reservoirs. In this context, we present a compositional pore-network model for gas-condensate flow under variable wetting conditions. Different condensate modes and flow patterns based on experimental observations were implemented in the model so that the effects of wettability on condensing flow were represented. Flow analyses under several thermodynamic conditions and flow rates in a sandstone based network were conducted to determine the parameters affecting condensate blockage mitigation by wettability alteration. Relative permeability curves and impacts factors were calculated for gas flowing velocities between 7.5 and 150 m/day, contact angles between 45° and 135°, and condensate saturations up to 35%. Significantly different relative permeability curves were obtained for contrasting wettability media and impact factors below one were found at low flowing velocities in preferentially gas-wet cases. Results exhibited similar trends observed in coreflooding experiments and windows of optimal flow enhancement through wettability alteration were identified.

PVT characterisation and compositional modelling of gas condensate and volatile oil reservoirs

2011 ◽  
Vol 4 (1) ◽  
pp. 79 ◽  
Author(s):  
Baosheng Liang ◽  
Sriram Balasubramanian ◽  
Ben Wang ◽  
Clair Jensen ◽  
Anping Yang ◽  
...  
Keyword(s):  
Volatile Oil ◽  
Gas Condensate ◽  
Oil Reservoirs

scholarly journals Near Critical Gas Condensate Relative Permeability of Carbonates

2006 ◽  
Author(s):  
Huseyin Calisgan ◽  
Birol Demiral ◽  
Serhat Akin
Keyword(s):  
Relative Permeability ◽  
Gas Condensate

Determination of Bubble-Point and Dew-Point Pressure Without a Visual Cell

2014 ◽  
Author(s):  
R.. Hosein ◽  
R.. Mayrhoo ◽  
W. D. McCain
Keyword(s):  
Oil And Gas ◽  
Saturation Pressure ◽  
Volatile Oil ◽  
Phase Region ◽  
Gas Condensate ◽  
Dew Point ◽  
Bubble Point ◽  
Point Pressure ◽  
Dew Point Pressure

Abstract Bubble-point and dew-point pressures of oil and gas condensate reservoir fluids are used for planning the production profile of these reservoirs. Usually the best method for determination of these saturation pressures is by visual observation when a Constant Mass Expansion (CME) test is performed on a sample in a high pressure cell fitted with a glass window. In this test the cell pressure is reduced in steps and the pressure at which the first sign of gas bubbles is observed is recorded as bubble-point pressure for the oil samples and the first sign of liquid droplets is recorded as the dew-point pressure for the gas condensate samples. The experimental determination of saturation pressure especially for volatile oil and gas condensate require many small pressure reduction steps which make the observation method tedious, time consuming and expensive. In this study we have extended the Y-function which is often used to smooth out CME data for black oils below the bubble-point to determine saturation pressure of reservoir fluids. We started from the initial measured pressure and volume and by plotting log of the extended Y function which we call the YEXT function, with the corresponding pressure, two straight lines were obtained; one in the single phase region and the other in the two phase region. The point at which these two lines intersect is the saturation pressure. The differences between the saturation pressures determined by our proposed YEXT function method and the observation method was less than ± 4.0 % for the gas condensate, black oil and volatile oil samples studied. This extension of the Y function to determine dew-point and bubble-point pressures was not found elsewhere in the open literature. With this graphical method the determination of saturation pressures is less tedious and time consuming and expensive windowed cells are not required.

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