An Experimental Study on Oil Recovery Performance Using in Situ Supercritical CO Emulsion for Carbonate Reservoirs

2020 ◽  
Author(s):  
Xianmin Zhou ◽  
Fawaz M. AlOtaibi ◽  
Muhammad S. Kamal ◽  
Sunil L. Kokal
Keyword(s):  
Experimental Study ◽  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Recovery Performance

An experimental study for carbonate reservoirs on the impact of CO2-EOR on petrophysics and oil recovery

Fuel ◽  
2019 ◽  
Vol 235 ◽  
pp. 1019-1038 ◽  
Author(s):  
Mohamed Khather ◽  
Ali Saeedi ◽  
Matthew B. Myers ◽  
Michael Verrall
Keyword(s):  
Experimental Study ◽  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Co2 Eor ◽  
The Impact

In Situ CO2 Enhanced Oil Recovery: Parameters Affecting Reaction Kinetics and Recovery Performance

2019 ◽  
Vol 33 (5) ◽  
pp. 3844-3854 ◽  
Author(s):  
Shuoshi Wang ◽  
Changlong Chen ◽  
Keren Li ◽  
Na Yuan ◽  
Benjamin Shiau ◽  
...  
Keyword(s):  
Reaction Kinetics ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Recovery Performance

scholarly journals Experimental study of the effects of acid microemulsion flooding to enhancement of oil recovery in carbonate reservoirs

2019 ◽  
Vol 10 (3) ◽  
pp. 1127-1135
Author(s):  
Tereza Neuma de Castro Dantas ◽  
Andrey Costa de Oliveira ◽  
Tamyris Thaise Costa de Souza ◽  
Cláudio Regis dos Santos Lucas ◽  
Edson de Andrade Araújo ◽  
...  
Keyword(s):  
Experimental Study ◽  
Oil Recovery ◽  
Carbonate Reservoirs

scholarly journals Experimental study on the enhanced oil recovery by in situ foam formulation

2020 ◽  
Vol 8 (4) ◽  
pp. 1092-1103 ◽  
Author(s):  
Hailong Chen ◽  
Zhaomin Li ◽  
Fei Wang ◽  
Aixin Li ◽  
Silagi Wanambwa ◽  
...  
Keyword(s):  
Experimental Study ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Foam Formulation

Multiple In-Situ Stress Measurements in Carbonate Reservoirs for CO2 Injection Capability Assessment and Far-Field Strain Calibrations

2022 ◽  
Author(s):  
Javier Alejandro Franquet ◽  
Viraj Nitin Telang ◽  
Hayat Abdi Ibrahim Jibar ◽  
Karem Alejandra Khan
Keyword(s):  
Oil Recovery ◽  
Fracture Initiation ◽  
In Situ Stress ◽  
Carbonate Reservoirs ◽  
Lateral Strain ◽  
Co2 Injection ◽  
Far Field ◽  
Pressure Derivative ◽  
Fracture Closure

Abstract The scope of this work is to measure downhole fracture-initiation pressures in multiple carbonate reservoirs located onshore about 50 km from Abu Dhabi city. The objective of characterizing formation breakdown across several reservoirs is to quantify the maximum gas and CO2 injection capacity on each reservoir layer for pressure maintenance and enhance oil recovery operations. This study also acquires pore pressure and fracture closure pressure measurements for calibrating the geomechanical in-situ stress model and far-field lateral strain boundary conditions. Several single-probe pressure drawdown and straddle packer microfrac injection tests provide accurate downhole measurements of reservoir pore pressure, fracture initiation, reopening and fracture closure pressures. These tests are achieved using a wireline or pipe-conveyed straddle packer logging tool capable to isolate 3 feet of openhole formation in a vertical pilot hole across five Lower Cretaceous carbonate reservoirs zones. The fracture closure pressures are obtained from three decline methods during the pressure fall-off after fracture propagation injection cycle. The three methods are: (1) square-root of the shut-in time, (2) G-Function pressure derivative, and (3) Log-Log pressure derivative. The far-field strain values are estimated by multi-variable regression from the microfrac test data and the core-calibrated static elastic properties of the formations where the stress tests are done. The reservoir pressure across these carbonate formations are between 0.48 to 0.5 psi/ft with a value repeatability of 0.05 psi among build-up tests and 0.05 psi/min of pressure stability. The formation breakdown pressures are obtained between 0.97 and 1.12 psi/ft over 5,500 psi above hydrostatic pressure. The in-situ fracture closure measurements provide the magnitude of the minimum horizontal stress 0.74 - 0.83 psi/ft which is used to back-calculate the lateral strain values (0.15 and 0.72 mStrain) as far-field boundary condition for subsequent geomechanical modeling. These measurements provide critical subsurface information to accurately predict wellbore stability, hydraulic fracture containment and CO2 injection capacity for effective enhance oil recovery within these reservoirs. This in-situ stress wellbore data represents the first of its kind in the field allowing petroleum and reservoir engineers to optimize the subsurface injection plans for efficient field developing.

scholarly journals Experimental study of in-situ W/O emulsification during the injection of MgSO4 and Na2CO3 solutions in a glass micromodel

2020 ◽  
Vol 75 ◽  
pp. 87
Author(s):  
Sepideh Palizdan ◽  
Hossein Doryani ◽  
Masoud Riazi ◽  
Mohammad Reza Malayeri
Keyword(s):  
Experimental Study ◽  
Flow Rate ◽  
Oil Recovery ◽  
Deionized Water ◽  
Water Flooding ◽  
Flow Rates ◽  
Glass Micromodel ◽  
The Impact ◽  
Emulsification Process

In-situ emulsification of injected brines of various types is gaining increased attention for the purpose of enhanced oil recovery. The present experimental study aims at evaluating the impact of injecting various solutions of Na2CO3 and MgSO4 at different flow rates resembling those in the reservoir and near wellbore using a glass micromodel with different permeability regions. Emulsification process was visualized through the injection of deionized water and different brines at different flow rates. The experimental results showed that the extent of emulsions produced in the vicinity of the micromodel exit was profoundly higher than those at the entrance of the micromodel. The injection of Na2CO3 brine after deionized water caused the impact of emulsification process more efficiently for attaining higher oil recovery than that for the MgSO4 brine. For instance, the injection of MgSO4 solution after water flooding increased oil recovery only up to 1%, while the equivalent figure for Na2CO3 was 28%. It was also found that lower flow rate of injection would cause the displacement front to be broadened since the injected fluid had more time to interact with the oil phase. Finally, lower injection flow rate reduced the viscous force of the displacing fluid which led to lesser occurrence of viscous fingering phenomenon.

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