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.

The low-permeability conglomerate reservoir in the Mahu Sag has great resource potential, but its strong heterogeneity and complex microscopic pore structure lead to a high oil-gas decline ratio and low recovery ratio. Clarifying the migration rule of crude oil in microscopic pore throat of different scales is the premise of efficient reservoir development. The low-permeability conglomerate reservoir of the Baikouquan Formation in the Mahu Sag is selected as the research object, and two NMR experimental methods of centrifugal displacement and imbibition replacement are designed to reveal the differences in the migration rule of crude oil in different pore throats. According to the lithology and physical properties, the reservoirs in the study area can be divided into four categories: sandy grain-supported conglomerates, gravelly coarse sandstones, sandy-gravelly matrix-supported conglomerates and argillaceous-supported conglomerates. From type I to type IV, the shale content of the reservoir increases, and the physical property parameters worsen. Centrifugal displacement mainly produces crude oil in large pore throats, while imbibition replacement mainly produces crude oil in small pores. In the process of centrifugal displacement, for type I reservoirs, the crude oil in the pore throats with radii greater than 0.5 μm is mainly displaced, and for the other three types, it is greater than 0.1 μm. The crude oil in the pore throats with radii of 0.02–0.1 μm, which is the main storage space for the remaining oil, is difficult to effectively displace. The crude oil in the pore throats with radii less than 0.02 μm cannot be displaced. The two experimental methods of centrifugation and imbibition correspond to the two development methods of displacement and soaking in field development, respectively. The combination of displacement and soaking can effectively use crude oil in the full-scale pore throat space to greatly improve the recovery of low-permeability conglomerate reservoirs.

An accurate inversion of original reservoir resistivity is an important problem for waterflood development in oilfields in the middle-late development

The near-source, multistream, and rapidly changing sedimentary environments of conglomerate reservoirs lead to reservoir characteristics such as strong heterogeneity and complex modal pore structure, which create unique seepage pathways and strong permeability anisotropy, which in turn affect the displacement mode and oil recovery of crude oil in pores and throats. Thus, it is necessary to clarify the genetic mechanism and controlling factors of this permeability anisotropy, providing the basis and premise of sustainable and efficient development of conglomerate reservoirs. In this paper, a typical conglomerate reservoir from the Kexia Formation in the 7th Block of the Karamay oilfield (Xinjiang, China) was selected as the research object to solve the permeability anisotropy problem. According to the sealed coring data, eight conglomerate samples were cut preliminarily in the field and prepared finely in the laboratory to make standard cube samples with side lengths of 4.5 cm, and then these samples were investigated using casting thin section, computed tomography scanning, and constant velocity mercury injection experimental methods to determine the genetic mechanism of permeability anisotropy and its controlling factors at macro- and microscales. The results showed that sedimentation and hydrodynamic conditions controlled the distribution of permeability anisotropy, the separation, rounding, and arrangement of mineral particles, the development of sedimentary structural planes, and the different types of packing textures, which affected the seepage paths and resistance in different directions, resulting in great differences in permeability anisotropy. The permeability in the direction parallel to water flow was the largest, followed by the direction perpendicular to water flow, and the permeability in the vertical sedimentation direction was the lowest because of the combined influences of the tortuosity of seepage, the connectivity of pore throats, and the sedimentary structural planes. In addition, diagenesis in later stages can reduce the absolute value of permeability in different directions and the strength of permeability anisotropy by changing the micropore structure of the conglomerate reservoir, but it will not change the distribution of permeability anisotropy. Based on these observations, a generalized linear mixed model was used to analyze the micropore structure parameters and standard deviation of permeability in different directions from the eight conglomerate samples, and the results showed that the relative sorting coefficient had the greatest influence on the standard deviation of permeability, and the uniformity of pore-throat size distribution was the main microscale controlling factor on the strength of permeability anisotropy. When the pore-throat size distribution was less uniform, the difference in the amplitude of permeability anisotropy was more obvious. The average capillary radius, seepage tortuosity, and maximum pore-throat radius showed less importance than relative sorting coefficient, so they are considered secondary factors. The other micropore structure parameters showed some influence on the permeability anisotropy, but the degree of influence was limited.