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The reservoir type of the MH oil field in the Junggar Basin is a typical low-permeability conglomerate reservoir. The MH oilfield was developed by water injection in the early stage. Nowadays, the reservoir damage is serious, and water injection is difficult. There is an urgent need to carry out conversion injection flooding research to improve oil recovery. The use of CO2 oil-flooding technology can effectively supplement formation energy, reduce greenhouse gas emissions, and improve economic benefits. In order to clarify the feasibility of CO2 flooding to improve oil recovery in conglomerate reservoirs with low permeability, strong water sensitivity, and severe heterogeneity, this paper researched the impact of CO2 miscibility on production characteristics and mechanisms through multi-scale experiments. The aim was to determine the feasibility of using CO2 flooding to enhance oil recovery. This study initially elucidated the oil displacement characteristics of varying degrees of miscibility in different dimensions using slim tube experiments and long core experiments. Subsequently, mechanistic research was conducted, focusing on the produced oil components, changes in interfacial tension, and conditions for pore mobilization. The results indicate that the minimum miscibility pressure (MMP) of the block is 24 MPa. Under the slim tube scale, the increase in the degree of miscibility can effectively delay the gas breakthrough time; under the core scale, once the pressure reaches the near mixing phase, the drive state can transition from a non-mixed "closed-seal" to a "mixed-phase" state. Compared to the immiscible phase, the near-miscible and completely miscible phase can improve the final recovery efficiency by 9.27% and 18.72%. The component differences in the displacement products are mainly concentrated in the high-yield stage and gas breakthrough stage. During the high-yield stage, an increase in miscibility leads to a higher proportion of heavy components in the produced material. Conversely, in the gas breakthrough stage, extraction increases as the level of mixing increases, demonstrating the distinct extracting characteristics of different degrees of mixed phases. The core experiences significant variations in oil saturation mostly during the pre-gas stage. CO2 miscible flooding can effectively utilize crude oil in tiny and medium-sized pores during the middle stage of flooding, hence reducing the minimum threshold for pore utilization to 0.3 μm. [ABSTRACT FROM AUTHOR]

The Mahu conglomerate reservoir is characterized by strong heterogeneity and the uneven stimulation of the horizontal lateral during hydraulic fracturing. The optimization of the perforation number per cluster is of great value for horizontal well multi-stage fracturing (HWMF) because the suitable perforation number not only promotes the uniform propagation of multiple fractures but also prevents excessive perforation erosion. In this work, a typical well in the Mahu conglomerate reservoir was selected, and a field test of optimizing the perforation number was carried out. The perforation schemes of three, five, and eight perforations per cluster were designed in nine fracturing stages, respectively. The wellhead pressure under different perforation schemes was compared and analyzed with the step-down flow rate test, and the optimal perforation number per cluster in the Mahu conglomerate reservoir was selected as eight. The theoretical calculation results show that eight perforations per cluster can generate the perforation friction of 5 MPa, sufficient to overcome the mechanical property differences among multiple clusters within one stage. The downhole video technology shows that the perforation erosion area is the most uniform with the case of eight perforations per cluster. Moreover, the optical fiber monitoring results show that the perforation number of eight per cluster can realize the simultaneous initiation and uniform propagation of six fractures or five fractures within one stage. This work is of great significance for the efficient development of the Mahu conglomerate reservoir through HWMF. [ABSTRACT FROM AUTHOR]

Mahu conglomerate oilfield has strong heterogeneity. Currently, large-scale hydraulic fracturing is commonly used for reservoir reconstruction. The geometry of hydraulic fractures is influenced by gravel. By referring to the scanning and logging results of a conglomerate reservoir, and considering the characteristics of gravel development in the Mahu Oilfield reservoir, python programming is used to establish a finite element model containing a matrix, bonding interface, and gravel, which considers the random distribution of gravel position and size. The model uses cohesive element global embedding to study the geometry of a hydraulic fracture. The results show that the hydraulic fracture in the gravel reservoir mainly spreads around the gravel, and the propagation path of the hydraulic fracture is affected by the horizontal stress difference. When the interfacial bonding strength is greater than 2 MPa, the conglomerate is more likely to be penetrated by hydraulic fractures, or the hydraulic fractures stop expanding after entering the conglomerate. The strength of the conglomerate largely determines whether hydraulic fractures can pass through it. When the strength of gravel is greater than 7 MPa, hydraulic fractures will stop expanding after entering the gravel. During the hydraulic fracturing process of conglomerate reservoirs, using a large injection rate can result in longer hydraulic fractures and larger fracture volumes. [ABSTRACT FROM AUTHOR]