scholarly journals Effect of Conformance Control Patterns and Size of the Slug of In Situ Supercritical CO2 Emulsion on Tertiary Oil Recovery by Supercritical CO2 Miscible Injection for Carbonate Reservoirs

ACS Omega ◽  
2020 ◽  
Vol 5 (51) ◽  
pp. 33395-33405
Author(s):  
Xianmin Zhou ◽  
Fawaz M AlOtaibi ◽  
Muhammad Shahzad Kamal ◽  
Sunil L Kokal
Keyword(s):  
Oil Recovery ◽  
Supercritical Co2 ◽  
Carbonate Reservoirs ◽  
Conformance Control ◽  
Tertiary Oil Recovery ◽  
Control Patterns

scholarly journals MICROEMULSION FLOODING MECHANISM FOR OPTIMUM OIL RECOVERY ON CHEMICAL INJECTION

2018 ◽  
Vol 40 (2) ◽  
pp. 85-90
Author(s):  
Yani Faozani Alli ◽  
Edward ML Tobing ◽  
Usman Usman
Keyword(s):  
Oil Recovery ◽  
Mobility Control ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Core Flooding ◽  
Oil Viscosity ◽  
Oil Saturation ◽  
Remaining Oil ◽  
Tertiary Oil Recovery

The formation of microemulsion in the injection of surfactant at chemical flooding is crucial for the effectiveness of injection. Microemulsion can be obtained either by mixing the surfactant and oil at the surface or injecting surfactant into the reservoir to form in situ microemulsion. Its translucent homogeneous mixtures of oil and water in the presence of surfactant is believed to displace the remaining oil in the reservoir. Previously, we showed the effect of microemulsion-based surfactant formulation to reduce the interfacial tension (IFT) of oil and water to the ultralow level that suffi cient enough to overcome the capillary pressure in the pore throat and mobilize the residual oil. However, the effectiveness of microemulsion flooding to enhance the oil recovery in the targeted representative core has not been investigated.In this article, the performance of microemulsion-based surfactant formulation to improve the oil recovery in the reservoir condition was investigated in the laboratory scale through the core flooding experiment. Microemulsion-based formulation consist of 2% surfactant A and 0.85% of alkaline sodium carbonate (Na2CO3) were prepared by mixing with synthetic soften brine (SSB) in the presence of various concentration of polymer for improving the mobility control. The viscosity of surfactant-polymer in the presence of alkaline (ASP) and polymer drive that used for chemical injection slug were measured. The tertiary oil recovery experiment was carried out using core flooding apparatus to study the ability of microemulsion-based formulation to recover the oil production. The results showed that polymer at 2200 ppm in the ASP mixtures can generate 12.16 cP solution which is twice higher than the oil viscosity to prevent the fi ngering occurrence. Whereas single polymer drive at 1300 ppm was able to produce 15.15 cP polymer solution due to the absence of alkaline. Core flooding experiment result with design injection of 0.15 PV ASP followed by 1.5 PV polymer showed that the additional oil recovery after waterflood can be obtained as high as 93.41% of remaining oil saturation after waterflood (Sor), or 57.71% of initial oil saturation (Soi). Those results conclude that the microemulsion-based surfactant flooding is the most effective mechanism to achieve the optimum oil recovery in the targeted reservoir.

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.

Crude Oil Recovery with Duomeen CTM-Stabilized Supercritical CO2 Foams for HPHT and Ultrahigh-Salinity Carbonate Reservoirs

2020 ◽  
Vol 34 (12) ◽  
pp. 15727-15735
Author(s):  
Leilei Zhang ◽  
Guoqing Jian ◽  
Maura Puerto ◽  
Xinglin Wang ◽  
Zeliang Chen ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Supercritical Co2 ◽  
Carbonate Reservoirs

scholarly journals Green Enhanced Oil Recovery for Carbonate Reservoirs

Polymers ◽  
2021 ◽  
Vol 13 (19) ◽  
pp. 3269
Author(s):  
Bashirul Haq
Keyword(s):  
Acrylic Acid ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Oil Production ◽  
Carbonate Reservoirs ◽  
Residual Oil ◽  
Acid Formulation ◽  
Tertiary Oil Recovery ◽  
Carbonate Cores ◽  
Modelling Studies

Green enhanced oil recovery (GEOR) is an eco-friendly EOR technique involving the injection of specific green fluids to improve macroscopic and microscopic sweep efficiencies, boosting residual oil production. The environmentally friendly surfactant-polymer (SP) flood is successfully tested in a sandstone reservoir. However, the applicability of the SP method does not extend to carbonate reservoirs yet and requires comprehensive investigation. This work aims to explore the oil recovery competency of a green SP formulation in carbonate through experimental and modelling studies. Numerous formulations of SP with ketone, alcohol, and organic acid are selected based on phase behavior and interfacial tension (IFT) reduction capabilities to examine their potential for enhancing residual oil production from carbonate cores. A blending of nonionic green surfactant alkyl polyglucoside (APG), xanthan gum (XG) biopolymer, and butanone recovered 22% tertiary oil from the carbonate core. This formulation recovered more than double residual crude than that of the APG, XG, and acetone. Similarly, a combination of APG, XG, acrylic acid, and butanol increased significantly more oil than the APG, XG, and acrylic acid formulation. The APG, XG, and butanone mixture is efficient with regards to boosting tertiary oil recovery from the carbonate core.

Oil Recovery Mechanisms During Sequential Injection of Chelating Agent Solutions Into Carbonate Rocks

2019 ◽  
Vol 142 (1) ◽  
Author(s):  
Amjed M. Hassan ◽  
Hasan S. Al-Hashim
Keyword(s):  
Oil Recovery ◽  
Chelating Agent ◽  
Carbonate Reservoirs ◽  
Analytical Models ◽  
Productivity Index ◽  
Wettability Alteration ◽  
Permeability Enhancement ◽  
Recovery Mechanisms ◽  
The Impact

Chelating agent solutions have been proposed as effective fluids for enhancing oil production. Different recovery mechanisms are reported for increasing the oil recovery during chelating agent flooding. The aims of this work are to identify the possible recovery mechanisms during chelating agent flooding in carbonate reservoirs and to investigate the in situ CO2 generation as a potential recovery mechanism during the injection of chelating agent solutions into carbonate reservoirs. The contribution of CO2 on enhancing the oil recovery was determined using experimental measurements and analytical calculations. Several measurements were conducted to study the contribution of each mechanism on enhancing the oil recovery. Coreflooding tests, zeta potential measurements, CO2 generation, and interfacial tension (IFT) experiments were carried out. Also, analytical models were utilized to determine the impact of the injected chemicals on reducing the capillary pressure and improving the flow conditions. In flooding tests, two chemicals (EDTA and GLDA) were injected in a sequential mode and the chemical concentration was increased gradually. In addition, a comparative study was performed to evaluate the effectiveness of EDTA and GLDA solutions to enhance oil recovery. Several parameters were investigated in this paper including incremental oil recovery, in situ CO2 generation, hydrocarbon swelling, IFT, wettability alteration, permeability enhancement, productivity index, and chemical cost. The obtained results show that GLDA chelating agent has better performance than EDTA solutions for enhancing the oil recovery when the same concentrations are used. Also, the in situ generation of CO2 shows a significant impact on improving the oil recovery from carbonate reservoirs during chelating agent flooding. In the literature, the reported recovery mechanisms of using chelating agents are the IFT reduction, wettability alteration, and rock dissolution. Based on this work, injecting chelating agent solutions at low pH can lead to involve additional recovery mechanisms due to the CO2 generation, the additional mechanisms are hydrocarbon swelling, viscosity and density reduction, and oil vaporization.

scholarly journals A comprehensive review of in situ polymer hydrogels for conformance control of oil reservoirs

2020 ◽  
Vol 75 ◽  
pp. 8 ◽  
Author(s):  
Kelly Lúcia Nazareth Pinho de Aguiar ◽  
Priscila Frias de Oliveira ◽  
Claudia Regina Elias Mansur
Keyword(s):  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Control Technique ◽  
Mechanical Resistance ◽  
Ideal Condition ◽  
Polymer Gel ◽  
Conformance Control ◽  
Polymer Hydrogels ◽  
Higher Temperature

In fractured reservoirs, fluids injected Enhanced Oil Recovery (EOR) are channeled through the fracture zones and travel through highly permeable regions, failing to displace part of the oil, and decreasing oil recovery efficiency. To solve these problems, the conformance control technique is now widely used, as it allows the reservoir to be swept totally, similar to the ideal condition. In this context, polyacrylamide-based polymer gel systems can be used to block the high-permeability regions of the rock matrix, forming in situ hydrogels that block the rock pores, avoiding the channeling of the fluids, and increasing the oil production. These polyacrylamide-based hydrogels can be crosslinked by inorganic (metal ions) or organic substances, and various systems are used for conformance control. Due to the greater stability of the bond formed between the polymer and the organic crosslinker, these systems are now used in higher temperature reservoirs. In order to produce hydrogels with higher resistance to severe salinity and temperature conditions, nanoparticles are applied to form systems with good mechanical resistance, and high thermal stability. These have presented promising results for conformance control.

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