Traditional stress sensitivity experiments are typically conducted under dry conditions, without considering the reservoir’s water content. In reality, the presence of water within pores significantly influences the extent of stress sensitivity damage in tight sandstone oil formations, subsequently affecting the determination of stress sensitivity coefficients during experimentation. By investigating sandstone samples from wells in the Mahu Block of China’s Xinjiang province, we observed that increasing water saturation reduces the stress sensitivity of tight sandstone. By conducting stress sensitivity experiments under varying water content conditions, we found that the stress sensitivity coefficient is not a constant value but decreases as water saturation increases. Based on experimental comparisons, an optimized power-law model for stress-sensitive damage assessment was refined. By conducting stress-sensitive damage assessment experiments under different water content conditions and integrating the concept of comprehensive compression coefficient, an improved stress-sensitive power-law model was established allowing for the influence of water content. The accuracy of this improved model was increased by 46.98% compared to the original power-law model through experimental validation. The research outcomes can enhance the accuracy of permeability and productivity evaluation, providing valuable guidance for unconventional oil and gas development.

In order to study the main control factors of volcanic reservoirs with complex oil–water relationships, the Carboniferous in the Chepaizi Uplift of the Junggar Basin was taken as an example and the lithofacies characteristics, main control factors, and hydrocarbon accumulation model of volcanic reservoirs were investigated by combining the petroleum geology with field testing (data of core analysis, well logging, formation testing, and production testing). The results show that the Carboniferous in the Chepaizi Uplift experienced three stages of volcanic activities and developed seven volcanic lithofacies bodies, distributed in a bead-string connected planar form along the Hongche fault. There is no unified oil–water interface across the whole study area and there are multiple oil–water systems within one fault block. The Carboniferous volcanic reservoir experienced two stages of hydrocarbon accumulation from two different source rocks. The distribution of faults penetrating hydrocarbon kitchens and source rocks controls the macro-scale distribution of reservoirs. The physical properties of reservoirs affect the pattern of oil and water differentiation in volcanic rock bodies, while the lithofacies body-controlled hydrocarbon accumulation mode highlighting “one rock body for one reservoir” determines the distribution of reservoirs. The matching between the paleo-structure and hydrocarbon accumulation stage controls the accumulation and adjustment of hydrocarbon distribution. The Permian source rocks in the Shawan Sag serve as the lateral hydrocarbon supply and hydrocarbons accumulate in the Carboniferous structural-lithologic traps, which are summarized as the two stages of hydrocarbon accumulation of newly generated hydrocarbons into older reservoir rocks. This study of the hydrocarbon accumulation pattern in volcanic rocks aims at guiding the development of Carboniferous reservoirs with complex oil and water relationships in this area.

The conglomerate matrix and fracture propagation are special in tight conglomerate reservoir with small well spacing. In this article, the fractal propagation characteristics of the fracture network in conglomerate reservoirs are described by experiment and a micro-mathematical model. According to the core slice, the conglomerate reservoir matrix presents the multi-modal pore structure, described as the “pseudo-dual-media” model. Given the above, the unsteady seepage mathematical model, comprehensively considering the fractal fracture network, stress sensitivity of main fractures, and threshold pressure gradient of the reservoir matrix, was developed and analytically solved. The Blasingame type curves for production decline analysis were plotted, and the sensitive parameters were analyzed. The field application was performed for validation. The research results show that the fractal dimension decides the complexity of the fracture network distribution. As it increases, the unsteady flow occurs earlier, and the boundary flow is delayed. The anomalous diffusion exponent represents the smoothness of crude oil migration and a higher value leads to higher resistance to oil migration and larger pressure drawdown for the same production rate. The growth of the threshold pressure gradient within a certain range can result in a localized downward shift of the type curves. The field application in a conglomerate oil reservoir showed that the presented model presents a fitting accuracy 10% higher than that of the conventional SRV model and has high reliability and precision for the production performance evaluation of the small-well-spacing development of tight conglomerate reservoirs.

In response to the problems of deteriorating quality of newly added reserves of deep and ultra-deep shale oil, significant differences in well efficiency among similar sweet spots, and difficulty in converting resources and production capacity, a deep and ultra-deep shale oil resource conversion evaluation method is proposed based on the entire process of shale oil development. Based on the production dynamics during the initial stage of production, we establish oil well classification standards for deep and ultra-deep shale oil and obtain two types of shale oil development unit classification standards. We construct well efficiency response indicators for development units, well efficiency index and well efficiency index, quantitatively characterizing the comprehensive well efficiency response within the development unit. We construct a production capacity evaluation system for the development of sweet spots that integrates resource utilization, technological economy, and business management. We use the fuzzy comprehensive evaluation method to obtain sweet spot evaluation scores and grades and quantitatively characterize the differences in production capacity construction for the development of sweet spots. On this basis, the “Resource–Productivity Matching Five Step Method” is proposed, which couples the sweet spot evaluation results with the well efficiency index to obtain the final score and evaluation results of resource conversion. The instance application of the M development unit shows that its overall resource conversion efficiency is not high, with only one type of area being a good match and the other areas being basic matches. The evaluation results are relative. This method achieves the integration of “sweet spot advantage (comprehensive score)—well efficiency response (well efficiency index)—conversion effect (final score)” and can identify false matches, improve the objectivity and reliability of evaluation results, and provide a scientific basis and technical support for shale oil block screening, well location deployment, construction planning and other research.

Thick conglomerate reservoirs possess substantial storage capacity and pronounced heterogeneity, yet their genesis remains debated. This study investigates the Permian Jiamuhe Formation thick conglomerate reservoir in the Zhongguai Uplift, Junggar Basin, utilizing full-diameter core analysis, cast thin-section petrography, X-ray diffraction, fluorescence microscopy, and heavy mineral assemblage analysis. The conglomerates exhibit low compositional and textural maturity, negligible clay matrix, and abundant magmatic lithic fragments. The pore system comprises predominantly detrital-grain dissolution pores (57.5%), followed by cement dissolution pores (25.1%) and microfractures (17.4%). Proximal Carboniferous volcanic rocks supplied plagioclase, pyroxene, and amphibole, providing labile constituents for subsequent acidic dissolution. Parent-rock weathering released Ca, Si, and Al, facilitating early zeolite and calcite cementation that reinforced grain-support frameworks and preserved primary porosity. Protracted leaching by acidic meteoric water during subaerial exposure was critical for reservoir enhancement. Steep paleotopography and the Jiamuhe–Wuerhe unconformity facilitated sustained fluid infiltration and extensive dissolution. In Well ZJ142, integrated petrophysical, mineralogical, and petrographic evidence indicates pronounced meteoric-water modification within the uppermost approximately 75 m beneath the weathering crust, with meteoric dissolution contributing up to a cumulative absolute porosity increment of 25.7 percentage points. Late faults and fractures provided pathways for deep acidic fluids interpreted to contain organic acids associated with source-rock maturation, promoting localized secondary dissolution during deep burial. The development of relatively favorable reservoir intervals was governed by a multistage process involving proximal supply of readily dissolvable volcanic fragments, early zeolite cementation, prolonged meteoric-water dissolution, and fault-assisted deep-fluid modification. Proximal soluble volcanic supply, early zeolite cementation, protracted meteoric dissolution, and fault-assisted deep fluid modification. These findings provide a robust theoretical basis for exploring deep thick conglomerate reservoirs in the Junggar Basin.