A mathematical model of CO2 miscible front migration in tight reservoirs with injection-production coupling technology

Sun, Lianting; Cui, Chuanzhi; Wu, Zhongwei; Yang, Yue-Tzu; Zhang, Chuanbao; Wang, Jian; Trivedi, Japan; Guevara, Jose

doi:10.1016/j.geoen.2022.211376

Cited by 11 publications

(4 citation statements)

References 32 publications

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“…The parameters refer to the actual reservoir conditions. The formation crude oil density is 0.875 g/cm 3 , the formation crude oil viscosity is 88mPa•s, the saturation pressure is 4.15MPa, the gas-oil ratio is 12.3m 3 /t, and the volume coefficient is 1.055 m 3 /m 3 . The reservoir porosity, permeability and oil saturation models are shown in Figure 1.…”

Section: Build the Modelmentioning

confidence: 99%

“…Due to its complexity and particularity in reservoir development and residual oil distribution, fault block reservoirs are highly difficult to develop in the field [1][2]. In addition, due to the serious heterogeneity of the reservoir, with the continuous development of the reservoir, injected water preferentially enters the high permeability interval, while the crude oil in the low permeability interval cannot be effectively used, the water cut of the reservoir increases rapidly, and the formation energy cannot be effectively supplemented [3]. Therefore, it is easy to form residual oil enrichment in areas with poor porosity and permeability development and general reservoir physical properties.…”

Section: Introductionmentioning

confidence: 99%

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Numerical Simulation Study on Optimization of Injection-Production Coupling Parameters in Complex Fault Block Reservoirs

Gan,

Zhang,

Jia

et al. 2023

AJST

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Taking complex fault-block reservoir in Biyang Depression as the research object, the influence of different factors on the coupling development mode of injection-production was studied. The numerical simulation method was used to evaluate the influence of intervention timing, injection intensity, periodic injection volume and production strength on the coupling implementation effect of the fault-block reservoir, and the coupling development parameters were optimized.The main knowledge obtained is that the timing and intensity of intervention are the main controlling factors of injection-production coupling in fault block reservoirs. The earlier the intervention time, that is, the lower the water cut, the better the injection and production coupling development effect. There is an optimal injection intensity, and the coupling injection and production effect is the best when the injection and production ratio is kept at 1:1. When the pressure is restored to 100%-120%, the coupling injection and production development effect is the best, and the periodic water injection volume is 2400-3200m3. The higher the strength of liquid production, the faster the oil recovery rate.

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Section: Build the Modelmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Numerical Simulation Study on Optimization of Injection-Production Coupling Parameters in Complex Fault Block Reservoirs

Gan,

Zhang,

Jia

et al. 2023

AJST

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“…Currently, research on injection and recovery coupling for residual oil recovery focuses primarily on mechanism, physical experiments, and oilfield applications. L Sun (2023) conducted sand-filled tube experiments for CO2 mixed-phase oil drive in tight reservoirs, proposed the correlation between TPG and CO2 concentration, and further fitted a mathematical model for mixed-phase leading edge transport, and concluded that the most important parameter affecting CO2 breakthrough is the injection rate [3]. X Chen (2023) addressed the issue of how to reduce energy consumption in the development of high water-bearing oil fields, established a comprehensive energy consumption calculation model for the three stages of water injection-reservoir-extraction, and implemented the proposed scheme through a particle swarm optimization algorithm [4].…”

Section: Introductionmentioning

confidence: 99%

Reservoir recovery study with stability analysis model constructed by flat sand filling experiment-Example of well area X in Tankou oilfield

Yang

2024

Preprint

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Injecting and recovering fluids in mature oil fields is a challenging task that can have significant impact on overall recovery rates. Conventionally, the approach taken has been a combination of laboratory experiments and numerical simulations, which lack field-scale verification and prediction accuracy. To address this limitation, we propose a new methodological approach—from experimentation to data simulation to developing a solution proposal to mathematically proving the validity of the approach. The novelty of this approach lies in its ability to fast-track verification of the solution and to predict, within limitations, the expected performance under real-field conditions. In the case study detailed in this paper, we establish the relationship between permeability, crude oil viscosity, and fluid recovery rate—all key parameters—on recovery performance, assuming a fixed wellbore network configuration. The results are validated through numerical simulations. Based on these findings, we recommend a development adjustment scheme, which is then rapidly validated using a reliability analysis model for a period of one year. The scheme implementation results in exponential distribution percentiles of 0.258375 and 0.276978, indicating its effectiveness. Additionally, the DGM (1,1) model projects recovery rates of 8.93 and 12.08 for the next two time points. Based on these projections, engineering guidelines are developed recommending crude oil viscosity adjustment through blending and dosing, and adoption of a 5 mL/min water injection rate for optimal recovery performance.

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“…Global climate change has attracted widespread attention from the international community, and reducing greenhouse gas CO 2 emissions to address the challenges of climate change has gradually become a consensus in the international community. − Coal, oil, and natural gas account for 70% of the total primary energy consumption, but they produce 2/3 of CO 2 , the main source of greenhouse gases. From 1750 to 2020, the volume fraction of CO 2 in the global atmosphere increased from 277 to 416 ppm, an increase of 1.5 times. − The Paris Climate Agreement determined that by 2050, the global average temperature increase needs to be controlled within 2 °C before industrialization and strive to be within 1.5 °C .…”

Section: Introductionmentioning

confidence: 99%

Experimental and Numerical Simulation Analysis of Factors Affecting CO₂ Geological Storage and Enhanced Oil Recovery in Extra-Low Permeability

Liu,

Shen,

Yue

et al. 2023

Energy Fuels

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Carbon neutrality has become the long-term development strategy of many countries worldwide, and the widespread implementation of CCUS (carbon capture, utilization, and storage) is critical for achieving this goal. Ultralow permeability reservoirs have good storage and shielding properties, making them ideal for CO2 geological storage. CO2 into these reservoirs has the dual purpose of improving crude oil recovery and protecting the environment. However, the physical properties of ultralow permeability reservoirs are poor. Furthermore, the distribution of fractures is often complex. The mechanism and influencing factors of the CO2 storage are still unclear. Here, the CO2 storage in ultralow permeability reservoirs is analyzed through core displacement experiments and numerical simulation. The main influencing factors of cumulative oil production and CO2 storage capacity were calculated through gray correlation theory, including CO2 injection rate, permeability, porosity, the solubility of CO2 in water, and the bottom hole flow pressure of production wells. The research results show that the geological storage of CO2 in ultralow permeability reservoirs mainly consists of structural trapping and dissolution into the residual fluids; in the short term, mineralization is relatively small and can be ignored. Within the 15 years predicted by numerical simulation, the injected CO2 into the Y28–102 well group in the Huang3 district was structurally trapped, with a total capacity of 6.59 × 104t. The burial ratio was 63.4%, of which structural burial accounted for 82%, oil dissolution accounted for 9%, water dissolution accounted for 8%, and mineral burial accounted for approximately 1%. The research results reference CO2 flooding and geological storage in ultralow permeability reservoirs.

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A mathematical model of CO2 miscible front migration in tight reservoirs with injection-production coupling technology

Cited by 11 publications

References 32 publications

Numerical Simulation Study on Optimization of Injection-Production Coupling Parameters in Complex Fault Block Reservoirs

Numerical Simulation Study on Optimization of Injection-Production Coupling Parameters in Complex Fault Block Reservoirs

Reservoir recovery study with stability analysis model constructed by flat sand filling experiment-Example of well area X in Tankou oilfield

Experimental and Numerical Simulation Analysis of Factors Affecting CO₂ Geological Storage and Enhanced Oil Recovery in Extra-Low Permeability

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A mathematical model of CO2 miscible front migration in tight reservoirs with injection-production coupling technology

Cited by 11 publications

References 32 publications

Numerical Simulation Study on Optimization of Injection-Production Coupling Parameters in Complex Fault Block Reservoirs

Numerical Simulation Study on Optimization of Injection-Production Coupling Parameters in Complex Fault Block Reservoirs

Reservoir recovery study with stability analysis model constructed by flat sand filling experiment-Example of well area X in Tankou oilfield

Experimental and Numerical Simulation Analysis of Factors Affecting CO2 Geological Storage and Enhanced Oil Recovery in Extra-Low Permeability

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Product

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Experimental and Numerical Simulation Analysis of Factors Affecting CO₂ Geological Storage and Enhanced Oil Recovery in Extra-Low Permeability