An Integrated Framework for Geothermal Energy Storage with CO2 Sequestration and Utilization

After hydraulic fracturing, shale reservoirs often undergo rapid production declines during depleted development, resulting in a low cumulative production. CO 2 huff and puff emerges as a promising method to enhance shale oil recovery postfracturing. This study conducted independent experiments to investigate multistage depressurization elastic depletion development and the CO 2 huff and puff method in shale oil. The effects of injection pressure, temperature, fractures, and other parameters on the CO 2 huff and puff recovery were analyzed using nuclear magnetic resonance (NMR). The impact of the CO 2 huff and puff on crude oil in different pores was elucidated. The results show that the fluid mobility of the shale reservoir is poor, with the recovery rate of elastic depletion development being less than 10%. Conversely, a CO 2 huff and puff can enhance the recovery rate by up to 20%. The recovery rate of shale oil through a CO 2 huff and puff correlates positively with injection pressure and temperature. The initial cycle of huff and puff contributes the most to crude oil recovery, reaching up to 50%. Under equivalent parameter conditions, the presence of fractures can increase the CO 2 huff and puff efficiency by 20% compared to the matrix core. Combined with NMR experiments, the lower limit of pores that oil can be produce in matrix and fracture cores in elastic depletion development is 200 and 150 nm, respectively. In the context of CO 2 huff and puff development, these values decrease to 30 nm for matrix cores and 15 nm for fractured cores.

Section: Introductionmentioning

confidence: 99%

Insights into Enhancing Shale Oil Recovery Postfracturing with CO₂ Huff and Puff and Elastic Depletion Development Strategies

Li,

Huang,

Duan

et al. 2024

“…Furthermore, corresponding measures must be taken to achieve negative CO 2 emissions, ensuring that the global average temperature increase is limited to 2 °C or even lower by 2050. Carbon capture, utilization, and storage (CCUS) technology has emerged as a key tool to address climate change. − …”

Section: Introductionmentioning

confidence: 99%

Data-Driven Quantitative Study of Synergistic Effects on CCUS-EOR─A Case Study of Ultralow-Permeability Sandstone Reservoirs

Hu,

Chen,

Rui

et al. 2024

Self Cite

CO 2 capture, utilization, and storage of CO 2 with enhanced oil recovery (CCUS-EOR) technology is an important method to achieve net-zero carbon goals. The two objectives of enhancing oil recovery and CO 2 storage exhibit both alignment and conflict, especially in the ultralow-permeability reservoir. However, current research often ignores the impact of reservoir heterogeneity, chemical reactions induced by CO 2, and the lack of quantitative characterization of synergies. This paper constructed a three-dimensional multiphase, multicomponent, thermal−hydraulic−chemical multifield coupled model for an actual well group. This paper thoroughly examines the mechanism of CO 2 storage in oil reservoirs and investigates the influence of geological and engineering parameters on CO 2 -enhanced oil recovery and storage by establishing a realistic CO 2 −water−oil−rock physicochemical reaction system. The gray correlation method was used to analyze the impact of various factors on the CO 2 oil displacement and storage, and the synergistic parameters were analyzed. The results show that reservoir pressure, WAG alternating cycles, and injection rate are synergistic parameters. In addition, the storage form of CO 2 is mainly structural storage, and mineralization storage can be ignored during the development of oil reservoirs. The amount of dissolved storage, however, gradually transforms into the amount of mineralized storage over time. During the 200 years of shut-in period, the amount of mineralized storage increased 13.6 times. It is also found that introducing hydrodynamic theory into the water−gas alternating injection process can effectively utilize the gravity of water and the buoyancy of CO 2 to increase the swept volume of CO 2 . When the depth of the gas and water injection points is small, the oil recovery and the CO 2 storage rate can be improved. The oil recovery of the final optimized plan is 40.5%, and the CO 2 storage rate is 64.5%. This study helps to better formulate development designs for ultralow-permeability reservoirs to achieve dual goals.

“…In the research of mathematical model of imbibition, in the 19th century, the spontaneous imbibition model was mainly developed based on the assumption of capillary bundles. Lucas et al investigated the correlation among the depth of the liquid column and imbibition time, proposed the capillary force imbibition model, and simplified the porous medium into capillary bundles. − Washburn concluded the Lucas–Washburn classical model through examining the relationship between liquid suction distance and imbibition time while disregarding the impact of gravitation . Handy and Firoozabadi established a model for the absorption of gas and water in rocks and examined the correlation among the amount of liquid absorbed and the duration of time .…”

Section: Introductionmentioning

confidence: 99%

Mechanisms of Imbibition Diffusion and Recovery Enhancing of Fracturing Fluids in Tight Reservoirs

Zhang,

Yu,

Tang

et al. 2024

Spontaneous imbibition is an essential method to enhance recovery during fracturing shut-in of tight reservoirs. However, most of the investigations are primarily focused on the mechanism of water imbibition to enhance recovery; the mechanism of fracturing fluid to enhance recovery and the lower limit of imbibition flow are remained insufficiently investigated. This paper identifies the pore structure characteristic of tight reservoirs, the fracturing fluid imbibition, and the lower limit of imbibition flow by combining nuclear magnetic resonance and high-pressure mercury intrusion methods, clarifying the mechanism of fracturing fluid recovery enhancement. The core-scale super diffusion model of fracturing fluid was established, and the sensitivity analysis of imbibition-influencing factors was conducted. The experimental results indicated that high interfacial tension increased the driving force and decreased the lower limit of imbibition flow, while low interfacial tension decreased the crude oil flow resistance and increased the lower limit of imbibition flow. The imbibition recovery improved with the increase of matrix permeability and decreased with the increase of crude oil viscosity. The degree of mobilization of micropores decreases and the degree of mobilization of mesopores with macropores increases with decreasing interfacial tension. The increase in matrix permeability elevated the degree of mobilization of each pore, while the increase of crude oil viscosity decreased the reduction of each pore. The simulation results fitted well with the experimental data, verifying the reasonableness of the model. The results indicated that the imbibition recovery was positively correlated with the characteristic parameters of the capillary force and negatively correlated with the core length and the viscosity of the fracturing fluid. The investigation in this paper provides a new theoretical basis for the improvement of recovery in tight reservoirs.