Light Oil Recovery From Cyclic CO2 Injection: Influence of Drive Gas, CO2 Injection Rate, and Reservoir Dip

1992 ◽  
Author(s):  
Fatma Karim ◽  
T.V. Berzins ◽  
P.A. Schenewerk ◽  
Z.A. Bassiouni ◽  
J.M. Wolcott
Keyword(s):  
Oil Recovery ◽  
Injection Rate ◽  
Co2 Injection ◽  
Light Oil

Novel Dual-Tubing Technique to Eliminate the Shut-in Period in CO2 Huff-n-Puff Injection for Heavy Oil Carbonate Reservoirs

2021 ◽  
Author(s):  
Zakaria Hamdi ◽  
Nirmal Mohanadas ◽  
Margarita Lilaysromant ◽  
Oluwole Talabi
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Injection Rate ◽  
Co2 Injection ◽  
Base Case ◽  
Production Time ◽  
Novel Approach ◽  
Dual Porosity Model ◽  
Carbon Dioxide Co2 ◽  
First Time

Abstract Some heavy oil production can be established using conventional methods; however, these methods are often somewhat ineffective with low recovery factors of less than 20%. Carbon dioxide (CO2) huff-n-puff or cyclic CO2 injection is one of the Enhanced oil recovery (EOR) methods that can be used in stimulating aging wells to recover some residual oil. The shut-in stage of this method results in a significant delay in the production time, and hence lower oil recovery. For the first time, in this paper, an attempt is made to overcome this issue by a novel approach, employing dual tubing completions. The aim of this is to increase the oil recovery with the production during soak time. Also, a majority of the remaining heavy oil reservoirs are carbonates, hence the research was focused on the same conditions. Numerical simulation is done using dual-tubing conditions in a dual-porosity model with conventional tubing as a base case. Optimization studies are done for injection rate, injection time, soaking time, production time, and huff-n-puff cycles. The results show that the recovery factor can increase significantly, with no discontinuity in production. Preliminary economic studies for the cases also showed a net increase in profit of 7% (1.3 million Dollars for the case chosen). This demonstrates the feasibility of the proposed method which can be implemented into conventional operations, for a more sustainable economy in the era of low oil prices.

Study of cyclic CO2 injection for low-pressure light oil recovery under reservoir conditions

Fuel ◽  
2016 ◽  
Vol 174 ◽  
pp. 296-306 ◽  
Author(s):  
Jinhua Ma ◽  
Xiangzeng Wang ◽  
Ruimin Gao ◽  
Fanhua Zeng ◽  
Chunxia Huang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Low Pressure ◽  
Co2 Injection ◽  
Reservoir Conditions ◽  
Light Oil

Light Oil Recovery From Cyclic CO2 Injection: Influence of Low Pressures Impure CO2, and Reservoir Gas

1991 ◽  
Vol 6 (01) ◽  
pp. 25-32 ◽  
Author(s):  
T.G. Monger ◽  
J.C. Ramos ◽  
Jacob Thomas
Keyword(s):  
Oil Recovery ◽  
Co2 Injection ◽  
Light Oil ◽  
Low Pressures

Feasibility of Cyclic CO2 Injection for Light-Oil Recovery

1991 ◽  
Vol 6 (02) ◽  
pp. 179-184 ◽  
Author(s):  
G.A. Thomas ◽  
T.G. Monger-McClure
Keyword(s):  
Oil Recovery ◽  
Co2 Injection ◽  
Light Oil

scholarly journals Enhancement of Heavy Oil Recovery with High CO2 Injection Rates in Silica Nanochannel

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 1) ◽  
Author(s):  
Shuo Zhang ◽  
Yanyu Zhang ◽  
Xiaofei Sun
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Co2 Adsorption ◽  
Injection Rate ◽  
Design Guidelines ◽  
Nonequilibrium Molecular Dynamics ◽  
Co2 Injection ◽  
Heavy Oil Recovery ◽  
Co2 Gas ◽  
Dynamics Simulations

Abstract CO2 injection enhanced oil recovery has become one of the most important approaches to develop heavy oil from reservoirs. However, the microscopic displacement behavior of heavy oil in the nanochannel is still not fully understood. In this paper, we use CO2 as the displacing agent to investigate the displacement of heavy oil molecules confined between the hydroxylated silica nanochannel by nonequilibrium molecular dynamics simulations. We find that for heavy oil molecules, it requires more much higher displacing speed to fully dissipate the residual oil which is found related to the decreased CO2 adsorption on the silica nanochannel. A faster CO2 gas injection rate will lower the CO2 adsorption inside the nanochannel, and more CO2 will participate in the displacement of the heavy oil. The results from this work will enhance our understanding of the CO2 gas displacing heavy oil recovery and design guidelines for heavy oil recovery applications.

Evaluating the Effects of CO2 Injection in Faulted Oil Reservoirs

2014 ◽  
Author(s):  
A.. Augustus ◽  
D.. Alexander
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Injection Rate ◽  
Oil Reservoirs ◽  
Co2 Injection ◽  
Geologic Sequestration ◽  
Sweep Efficiency ◽  
Fracture Pressure ◽  
Carbon Dioxide Co2 ◽  
Migration Pathways

Abstract The geologic sequestration of carbon dioxide (GCS) into depleted reservoirs has been contemplated and tested in several projects globally both for permanent storage of carbon dioxide (CO2) and enhancing oil recovery (EOR). Utilization of geologic sequestration as a mitigation strategy to reduce the effects of anthropogenic CO2 into the atmosphere may be costly without proper incentives. This cost can be lowered when incremental oil is recovered in mature fields because of rising oil prices and possibly earning carbon credits for sequestered CO2. The injection of CO2, for most of the infrastructure should be in place for mature fields. Therefore many EOR coupled with CO2 sequestration projects attempt to maximize the recovery of oil whilst storing as much CO2 as possible. Many oil reservoirs are reaching or have reached their maturity therefore secondary and tertiary methods for EOR have become increasingly important for sustainable volumes of oil to be produced. Reservoir simulators have become increasingly important in the pre-evaluation of these projects for proper reservoir management and evaluation. One of the most critical problems when considering the geologic storage of CO2 is the risk of leakage which can lead to seepage from the storage area. In Trinidad and Tobago (T&T) many reservoirs are highly faulted. Some faults form an integral part of the structural traps whilst others are leaky and provide migration pathways for the injected CO2 to return to surface. A simulation study was conducted using the commercial compositional simulator CMG-GEM. The model described in this paper seeks to optimize the injection of CO2 into an oil reservoir with some degree of compartmentalization due to faulting whilst maximizing the amount of incremental oil that can be produced. One of the main considerations will be to maximize the sweep efficiency below the fracture pressure and fault entry pressure. The model is intended for a type of formation likely to be used for storage in Trinidad. We conducted sensitivity analysis on the injection rate and fault transmissibity in an analogous field to those located offshore Trinidad. It was concluded that faults transmissibility affect the overall production of oil reservoirs. Sealing faults stored less CO2 and had less cumulative production than non sealing faults.

scholarly journals Geochemical Investigation of CO2 Injection in Oil and Gas Reservoirs of Middle East to Estimate the Formation Damage and Related Oil Recovery

Energies ◽  
2021 ◽  
Vol 14 (22) ◽  
pp. 7676
Author(s):  
Ilyas Khurshid ◽  
Imran Afgan
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Injection Rate ◽  
Rock Properties ◽  
Co2 Injection ◽  
Formation Damage ◽  
Gas Reservoirs ◽  
Oil And Gas Reservoirs ◽  
Carbon Dioxide Co2 ◽  
Injection Rates

The injection performance of carbon dioxide (CO2) for oil recovery depends upon its injection capability and the actual injection rate. The CO2–rock–water interaction could cause severe formation damage by plugging the reservoir pores and reducing the permeability of the reservoir. In this study, a simulator was developed to model the reactivity of injected CO2 at various reservoir depths, under different temperature and pressure conditions. Through the estimation of location and magnitude of the chemical reactions, the simulator is able to predict the effects of change in the reservoir porosity, permeability (due to the formation/dissolution) and transport/deposition of dissoluted particles. The paper also presents the effect of asphaltene on the shift of relative permeability curve and the related oil recovery. Finally, the effect of CO2 injection rate is analyzed to demonstrate the effect of CO2 miscibility on oil recovery from a reservoir. The developed model is validated against the experimental data. The predicted results show that the reservoir temperature, its depth, concentration of asphaltene and rock properties have a significant effect on formation/dissolution and precipitation during CO2 injection. Results showed that deep oil and gas reservoirs are good candidates for CO2 sequestration compared to shallow reservoirs, due to increased temperatures that reduce the dissolution rate and lower the solid precipitation. However, asphaltene deposition reduced the oil recovery by 10%. Moreover, the sensitivity analysis of CO2 injection rates was performed to identify the effect of CO2 injection rate on reduced permeability in deep and high-temperature formations. It was found that increased CO2 injection rates and pressures enable us to reach miscibility pressure. Once this pressure is reached, there are less benefits of injecting CO2 at a higher rate for better pressure maintenance and no further diminution of residual oil.

Determination of Optimum Parameters for Anaerobic Thermophilic Bacterium Injection using Commercial Simulator: Core Flooding Validation and Sensitivity

2020 ◽  
Author(s):  
A. Koto
Keyword(s):  
Oil Recovery ◽  
Simulation Experiment ◽  
Previous Experiment ◽  
Core Sample ◽  
Thermophilic Bacterium ◽  
Injection Rate ◽  
Core Flooding ◽  
Optimum Parameters ◽  
Result Show

The objective of this paper is to determine the optimum anaerobic-thermophilic bacterium injection (Microbial Enhanced Oil Recovery) parameters using commercial simulator from core flooding experiments. From the previous experiment in the laboratory, Petrotoga sp AR80 microbe and yeast extract has been injected into core sample. The result show that the experiment with the treated microbe flooding has produced more oil than the experiment that treated by brine flooding. Moreover, this microbe classified into anaerobic thermophilic bacterium due to its ability to live in 80 degC and without oxygen. So, to find the optimum parameter that affect this microbe, the simulation experiment has been conducted. The simulator that is used is CMG – STAR 2015.10. There are five scenarios that have been made to forecast the performance of microbial flooding. Each of this scenario focus on the injection rate and shut in periods. In terms of the result, the best scenario on this research can yield an oil recovery up to 55.7%.

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