Reservoir sensitivity can lead to the physical or chemical reactions to block the pore throat. It is helpful for reducing the damage on tight sandstone reservoir to study the reservoir sensitivity and its controlling factors. This paper mainly focuses on the tight sandstone of the Chang 4+5 and Chang 6 reservoirs of the Yanchang Formation in the Nanniwan Oilfield, Ordos Basin. The reservoir sensitivity characteristics were evaluated through the core sensitivity experiment after the petrological and petrophysical analysis and pore structure study. The influencing factors on tight sandstone reservoir sensitivity were discussed from several aspects, such as clay mineral composition, porosity, permeability, and pore structure. The results show that the rock type of the Chang 4+5 and Chang 6 reservoirs in the N 212 well block of the Nanniwan Oilfield is mainly arkose, with the mean porosity of 11.2% and 8.45% and the mean permeability of μm² and μm², respectively. The clay mineral components mainly include chlorite and illite/smectite. Both the two reservoirs are characterized by moderate to weak velocity sensitivity, moderate to weak water sensitivity, moderate to strong salt sensitivity, weak acid sensitivity, and moderate to weak alkali sensitivity. In specific, the Chang 4+5 reservoir is stronger in velocity and salt sensitivities, while it is weaker in water, acid, and alkali sensitivities than those of the Chang 6. The major controlling factors on reservoir sensitivity are clay mineral component, petrophysical property, and pore structure. Among these, the velocity sensitivity displays the positive correlation with pore structure, porosity, and permeability. The water sensitivity will become strong with the increase of the volume content of illite/smectite, but weak with the getting better of pore structure. The acid sensitivity is positively correlated with the volume content of chlorite but is negatively correlated with pore structure. With the getting better of pore structure, the salt sensitivity and alkali sensitivity will become strong and weak, respectively. The research results can be as the guidance for the tight sandstone reservoir protection in the study area and the adjustment and optimization of the regional reservoir development scheme.

The tight carbonate reservoir was controlled by various geological factors, and such factors played different roles in buried depths and formations. Therefore, studies related to the factors controlling carbonate reservoir distribution are of great significance for the prediction and evaluation of high-quality dolostone reservoirs. In this paper, we focus on the controlling factor of the submember Ma5₅ dolostone reservoir in the western Ordos Basin. The main rock types, reservoir pores, physical properties, and pore structure characteristics of the reservoir were analyzed by thin section identification, physical property analysis, and mercury injection, respectively. Then, the main controlling factors of reservoir development were comprehensively analyzed from the perspectives of palaeostructure, lithofacies palaeogeography, diagenesis, and diagenetic facies. The results show that two kinds of dolostone reservoirs in the submember Ma5₅ developed in the western Ordos Basin, including intercrystalline pore-type and dissolution pore-type. The former reservoir is primarily characterized by powder-fine dolostone with residual structure, dolomite intercrystalline pore, and micropore with porosity ranging from 2 to 11. There are three types of pore structures developed in it, such as macropore-medium throat-single peak (MAMS), macropore-fine throat-single peak (MAFS), and medium pore-fine throat-single peak (MEFS). The latter reservoir is mainly featured by powdery crystalline dolostone with gypsum and halite dissolution, moldic pore, and dissolved pore between breccias with a porosity greater than 5. It consists of two types of pore structures, such as macropore-fine throat-single peak (MAFS) and medium pore-coarse throat-multipeak (MECM). The intercrystalline pore-type dolostone reservoir is mainly controlled by the lithofacies palaeogeographic environment and diagenesis. In specific, the shoal microfacies at the edge of the platform and the active reflux seepage dolomitization are the basic sedimentary environment conditions for reservoir formation and the key to reservoir formation, respectively. The dissolution pore-type dolostone reservoir is primarily influenced by both paleostructure and diagenesis. The relatively high part of the paleostructure provides favorable conditions for the formation of evaporate minerals, and early freshwater dissolution is the key to reservoir formation. This research will provide a theoretical basis for forecasting the favorable distribution areas of different types of dolostone reservoirs.

Recently, in addition to petrophysical properties, the present-day in situ stress (PDIS) is also considered as one of the controlling factors for the highly heterogeneous deep and ultradeep carbonate reservoirs. However, the specific relationship between PDIS and the distribution of carbonate reservoirs remains unclear. This situation restricts our understanding of the distribution law of deep carbonate reservoirs and the accurate prediction of favorable distribution areas. This paper focuses on unraveling the orientation, magnitude, and distribution law of PDIS and its influence on the distribution of deep carbonate reservoirs in the Upper Member of the Yingshan Formation within the S region of the Tahe Oilfield. By leveraging image logging, conventional logging, the combined spring model, and data dissection from a variety of geological experiments, drilling operations, and reservoir engineering undertakings, it is endeavored to shed light on these aspects. The results demonstrate that the maximum horizontal primary stress (Sh _max), minimum horizontal primary stress (Sh _min), and stress difference (D _s) are the key factors controlling the distribution of deep carbonate reservoirs in the Upper Member of the Yingshan Formation in the study area. Specifically, the reservoir thickness, showing a negative correlation with Sh _max and D _s, is generally high with a value more than 14 m in the areas where Sh _max and D _s are less than 157 and 61 MPa, respectively. Reservoir porosity displays a positive correlation with Sh _min but a negative correlation with Sh _max and D _s. It is commonly high with a value more than 5% in the areas where Sh _min is larger than 96 MPa and Sh _max and D _s are less than 157 and 61 MPa, respectively. The thickness of strata with fracture development exhibits a positive correlation with Sh _max and D _s and a relatively strong negative correlation with Sh _min. It is commonly high with a value more than 5 m in the areas where Sh _max and D _s are greater than 157 and 62 MPa, respectively, and Sh _min is less than 95 MPa. Regions where Sh _max is less than 157 MPa, D _s is less than 61 MPa, and Sh _min is greater than 96 MPa should be the primary choices for selecting favorable areas of deep carbonate reservoir distribution in the study area. The research results can not only benefit the exploration for the distribution law of deep and ultradeep marine carbonate reservoirs but also provide technical support for the prediction and optimization of favorable areas for deep oil and gas exploration.

Diagenetic fluids is one of the most important reservoir modifiers, their differences can result in various petrography, storage capacity, and geochemical characteristics, so clarifying the diagenetic fluids is vital for understanding dolostone origin. Dolomitization is an important genetic type of dolostone reservoir, the fluid properties differ in different dolomitization, which may lead to reservoir storage capacity changes. Therefore, the identification of dolomitization fluid properties is critical for deeply understanding of dolomitization process and predicting storage capacity. Two types of dolostone are developed in submember Ma5₅ of Majiagou Formation in northwestern Ordos Basin, with obviously different petrological characteristics and reservoir properties. On the basis of petrological studies such as core and casting thin section observation and cathodoluminescence analysis, the diagenetic fluid properties of these two dolostone are characterized by geochemical analytical methods such as major and trace element tests. The results show that Type-1 dolostone is mainly composed of micritic dolomite, showing micritic structure and algae-rich lamina structure, and accompanied by evaporite minerals and moldic pores. This type of dolostone has a various Mn content, weak to medium cathodoluminescence intensity, high contents of TiO₂, Al₂O₃, K₂O+Na₂O, Li, and U, and lower content of TFe₂O₃. The type-2 dolostone is composed of fine-grained dolomite with obvious residual texture of primary limestone, clear brim, and cloudy center structure, accompanied by the existence of intergranular pores. Most of this kind of dolostone have medium-strong cathodoluminescence, higher TFe₂O3 content and lower TiO₂, Al₂O₃, K₂O+Na₂O, Li, and U contents. Moreover, both the two types of dolostone have similar Fe/Ca and Mn/Ca ratios, and a low and concentrated CaO content, whose composition is similar to that of stoichiometric dolomite. The comprehensive analysis shows that the diagenetic fluid of Type-1 dolostone is mainly a high salinity fluid existed in plaster and calcareous sediments in a near surface environment with low temperature. The diagenetic fluid of Type-2 dolostone may be a high salinity brine formed by evaporation and concentration of seawater with normal salinity. The research results will provide a significant theoretical basis for the evaluation of dolostone reservoir quality and the prediction of favorable areas of reservoir distribution.