The microscopic pore structure controls the fluid seepage characteristics, which in turn affect the final recovery of the reservoir. The pore structures of different reservoirs vary greatly; therefore, the scientific classification of microscopic pore structures is the prerequisite for enhancing the overall oil recovery. For the low permeability conglomerate reservoir in Mahu Sag, due to the differences in the sedimentary environment and late diagenesis, various reservoir types have developed in different regions, so it is very difficult to develop the reservoir using an integrated method. To effectively solve the problem of microscopic pore structure classification, the low permeability conglomerate of the Baikouquan Formation in Well Block Ma18, Well Block Ma131, and Well Block Aihu2 are selected as the research objects. The CTS, HPMI, CMI, NMR, and digital cores are used to systematically analyze the reservoir micro pore structure characteristics, identify the differences between different reservoir types, and optimize the corresponding micro pore structure characteristic parameters for reservoir classification. The results show that the pore types of the low permeability conglomerate reservoir in the Baikouquan Formation of the Mahu Sag are mainly intragranular dissolved pores and residual intergranular pores, accounting for 93.54%, microfractures and shrinkage pores that are locally developed, accounting for 5.63%, and other pore types that are less developed, accounting for only 0.83%. On the basis of clear pore types, the conglomerate reservoir of the Baikouquan Formation is divided into four types based on the physical properties and microscopic pore structure parameters. Different reservoir types have good matching relationships with lithologies. Sandy-grain-supported conglomerate, gravelly coarse sandstone, sandy-gravelly matrix-supported conglomerate, and argillaceous-supported conglomerate correspond to type I, II, III, and IV reservoirs, respectively. From type I to type IV, the corresponding microscopic pore structure parameters show regular change characteristics, among which, porosity and permeability gradually decrease, displacement pressure and median pressure increase, maximum pore throat radius, median radius, and average capillary radius decrease, and pore structure becomes worse overall. Apparently, determining the reservoir type, clarifying its fluid migration rule, and formulating a reasonable development plan can substantially enhance the oil recovery rate of low permeability conglomerate reservoirs.

Reservoir heterogeneity significantly affects reservoir flooding efficiency and the formation and distribution of residual oil. As an effective method for enhancing recovery, polymer–surfactant (SP) flooding has a complex mechanism of action in inhomogeneous reservoirs. In this study, the effect of reservoir heterogeneity on the SP drive was investigated by designing core parallel flooding experiments combined with NMR and CT scanning techniques, taking conglomerate reservoirs in a Xinjiang oilfield as the research object. The experimental results show that inter-layer heterogeneity significantly affects water flooding efficiency and SP driving in low-permeability cores—the larger the permeability difference is, the more obvious the effect is—while it has almost no effect on high-permeability cores. The limited recovery enhancement in low-permeability cores is mainly due to the small percentage of contributing pores. When the permeability difference undergoes an extreme increase, the polymer molecular weight is biased towards higher values; when the polymer molecular weight is fixed, the recovery enhancement of low-permeability cores may be comparable to that of high-permeability cores when the permeability difference is extremely small. However, the recovery enhancement of the former is smaller than that of the latter when the permeability difference is extremely large. Due to intra-layer heterogeneity, there is a serious fingering phenomenon in the flooding stage, while in the SP flooding stage, recovery enhancement is most significant in the 5–20 μm pore range. This study provides an important geological basis for the rational development of a chemical flooding programme.

In this paper, the conglomerate reservoir is selected as the object to investigate the micropore structure and the compatibility of polymer solutions. Firstly, the characteristics of complex mode pore structure are analyzed based on casting thin sections, scanning electron microscope, and capillary pressure curve. Then the conglomerate reservoir is divided into five types by use of the K-means clustering algorithm, and the differences in micropore structure among the different reservoir types are also clarified. Secondly, the dynamic light scattering technology is used to directly determine the hydrodynamic diameter of different polymer formulations. As the polymer molecular weight increases, the average hydrodynamic diameter becomes larger, and with the same polymer molecular weight, the average hydrodynamic diameter becomes gradually larger as the solution concentration increases. Based on the above research results, the matching relationship between five reservoir types and polymer solutions is determined through laboratory experiments. The experimental results show that when the polymer molecular weight is determined, the volume of pore volume that can be effectively swept by polymer hydration molecules gradually decreases as the concentration of the solution increases. When the polymer molecular weight and its concentration are both determined, the pore volume of effective displacement of polymer-hydrated molecules also gradually reduces with becoming worse reservoir pore structure. The scope of application of different polymer formulations becomes progressively smaller as the microscopic pore structure of type I to type V reservoirs becomes deteriorated. The compatibility between the micropore structure of different conglomerate reservoir types and polymer solution is determined to provide the geological basis for the reasonable formulation of the polymer flooding scheme.