On the Economics of Improved Oil Recovery: The Optimal Recovery Factor from Oil and Gas Reservoirs

1988 ◽  
Vol 9 (4) ◽  
Author(s):  
Arild N. Nystad
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Optimal Recovery ◽  
Recovery Factor ◽  
Gas Reservoirs ◽  
Improved Oil Recovery ◽  
Oil And Gas Reservoirs

scholarly journals Experimental Study on Enhanced Condensate Recovery by Gas Injection in Yaha Condensate Gas Reservoir

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-15
Author(s):  
Yiming Wu ◽  
Kun Yao ◽  
Yan Liu ◽  
Xiangyun Li ◽  
Mimi Wu ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Recovery Rate ◽  
Oil And Gas ◽  
Gas Injection ◽  
Recovery Factor ◽  
Co2 Injection ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Injection Method ◽  
Production Ratio

A condensate gas reservoir is an important special oil and gas reservoir between oil reservoir and natural gas reservoir. Gas injection production is the most commonly used development method for this type of gas reservoir, but serious retrograde condensation usually occurs in the later stages of development. To improve the recovery efficiency of condensate oil in the middle and late stages of production of a condensate gas reservoir, a gas injection parameter optimization test study was carried out, taking the Yaha gas condensate reservoir in China as an example. On the premise that the physical experimental model and key parameters met the actual conditions of the formation, the injection method, injection medium, injection-production ratio, and other parameters of the condensate gas reservoir were studied. Research on the injection method showed that the top injection method had a lower gas-oil ratio and higher condensate oil recovery. The study of injection medium showed that the production effect of carbon dioxide (CO2) injection was the best injection medium, and the maximum recovery rate of condensate oil was 95.11%. The injection-production ratio study showed that the injection-production ratio was approximately inversely proportional to the recovery factor of condensate gas and approximately proportional to the recovery factor of condensate oil. When the injection-production ratio was 1 : 1, the maximum recovery rate of condensate oil was 83.31%. In summary, in the later stage of gas injection development of the Yaha condensate gas reservoir, it was recommended to choose the development plan of CO2 injection at the top position with an injection-production ratio of 1 : 1. This research can not only provide guidance for the later formulation of gas injection plans for Yaha condensate gas reservoirs but also lay a foundation for the research of gas injection migration characteristics of other condensate gas reservoirs.

scholarly journals Influence of CO2 retention mechanism storage in Alberta tight oil and gas reservoirs at Western Canadian Sedimentary Basin, Canada: hysteresis modeling and appraisal

2020 ◽  
Author(s):  
Perumal Rajkumar ◽  
Venkat Pranesh ◽  
Ramadoss Kesavakumar
Keyword(s):  
Oil Recovery ◽  
Fossil Fuels ◽  
Oil And Gas ◽  
Injection Pressure ◽  
Retention Mechanism ◽  
Gas Production ◽  
Tight Oil ◽  
Gas Reservoirs ◽  
Oil And Gas Reservoirs ◽  
Tight Oil And Gas

AbstractRapid combustion of fossil fuels in huge quantities resulted in the enormous release of CO2 in the atmosphere. Subsequently, leading to the greenhouse gas effect and climate change and contemporarily, quest and usage of fossil fuels has increased dramatically in recent times. The only solution to resolve the problem of CO2 emissions to the atmosphere is geological/subsurface storage of carbon dioxide or carbon capture and storage (CCS). Additionally, CO2 can be employed in the oil and gas fields for enhanced oil recovery operations and this cyclic form of the carbon dioxide injection into reservoirs for recovering oil and gas is known as CO2 Enhanced Oil and Gas Recovery (EOGR). Hence, this paper presents the CO2 retention dominance in tight oil and gas reservoirs in the Western Canadian Sedimentary Basin (WCSB) of the Alberta Province, Canada. Actually, hysteresis modeling was applied in the oil and gas reservoirs of WCSB for sequestering or trapping CO2 and EOR as well. Totally, four cases were taken for the investigation, such as WCSB Alberta tight oil and gas reservoirs with CO2 huff-n-puff and flooding processes. Actually, Canada has complex geology and therefore, implicate that it can serve as a promising candidate that is suitable and safer place for CO2 storage. Furthermore, injection pressure, time, rate (mass), number of cycles, soaking time, fracture half-length, conductivity, porosity, permeability, and initial reservoir pressure were taken as input parameters and cumulative oil production and oil recovery factor are the output parameters, this is mainly for tight oil reservoirs. In the tight gas reservoirs, only the output parameters differ from the oil reservoir, such as cumulative gas production and gas recovery factor. Reservoirs were modelled to operate for 30 years of oil and gas production and the factor year was designated as decision-making unit (DMU). CO2 retention was estimated in all four models and overall the gas retention in four cases showed a near sinusoidal behavior and the variations are sporadic. More than 80% CO2 retention in these tight formations were achieved and the major influencing factors that govern the CO2 storage in these tight reservoirs are injection pressure, time, mass, number of cycles, and soaking time. In general, the subsurface geology of the Canada is very complex consisting with many structural and stratigraphic layers and thus, it offers safe location for CO2 storage through retention mechanism and increasing the efficiency and reliability of oil and gas extraction from these complicated subsurface formations.

Modeling Study on Reviving Abandoned Oil Reservoirs by In Situ Combustion Without CO2 Production While Recovering Both Oil and Heat

2021 ◽  
Vol 143 (8) ◽  
Author(s):  
Yun Han ◽  
Kewen Li ◽  
Lin Jia
Keyword(s):  
Numerical Simulation ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Numerical Models ◽  
Oil Reservoirs ◽  
Co2 Production ◽  
Geothermal System ◽  
Residual Oil ◽  
Gas Reservoirs ◽  
Oil And Gas Reservoirs

Abstract A large number of oil wells have been or will be abandoned around the world. Yet, a very large amount of oil and energy is left behind inside the rocks in abandoned reservoirs because of technological and economic limitations. The residual oil saturation is usually more than 40%, and in shale reservoirs it can be more than 90%. There have been many enhanced oil recovery methods developed to tap the residual oil and improve the oil recovery. Interestingly, a concept has been proposed to transfer abandoned oil and gas reservoirs into exceptional enhanced geothermal reservoirs by oxidizing the residual oil with injected air (Li and Zhang, 2008, “Exceptional Enhanced Geothermal Systems From Oil and Gas Reservoirs,” 43rd Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, CA). This methodology was referred to as an exceptional enhanced geothermal system (EEGS). However, zero CO2 production has not been achieved during the process of EEGS. To this end, numerical models of EEGS in abandoned oil reservoirs configured with vertical wells were established in the present study. Numerical simulations in different well configurations were conducted. The effects of well distance, perforation position, and formation permeability on the CO2 production and the reservoir temperature have been investigated. The numerical simulation results showed that when the depth difference between the production and the injection well perforation positions reaches a specific value, the daily CO2 production rate could be kept at almost zero for over 50 years or even permanently while producing oil and thermal energy continuously. This implies that we realized the concept of EEGS with no CO2 successfully using numerical simulation.

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.

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