Search Results (6)

In order to clarify the pore evolution and coupling characteristics with hydrocarbon charging in the deep-buried ultra-tight sandstone reservoirs of the second member of Xujiahe Formation (hereinafter referred to as the Xu 2 Member) on the eastern slope of the Western Sichuan Depression, this study integrates burial history and thermal history with analytical methods including core observation, cast thin section analysis, scanning electron microscopy, carbon-oxygen isotope analysis, and fluid inclusion homogenization temperature measurements. The Xu 2 Member reservoirs are predominantly composed of lithic sandstones and quartz-rich sandstones, with authigenic quartz and carbonates as the main cementing materials. The reservoir spaces are dominated by intragranular dissolution pores. The timing of reservoir densification varies among different submembers. The upper submember underwent compaction during the Middle-Late Jurassic period due to the high ductility of mudstone clasts and other compaction-resistant components. The middle-lower submembers experienced densification in the Late Jurassic period. Late Cretaceous tectonic uplift induced fracture development, which enhanced dissolution in the middle-lower submembers, increasing reservoir porosity to approximately 5%. Two distinct phases of hydrocarbon charging are identified in the Xu 2 Member. The earlier densification of the upper submember created unfavorable conditions for hydrocarbon accumulation. In contrast, the middle-lower submembers received hydrocarbon charging prior to reservoir densification, providing favorable conditions for natural gas enrichment and reservoir formation. Three sweet-spot reservoir development patterns are recognized: paleo-structural trap + (internal source rock) + source-connected fracture assemblage type, paleo-structural trap + internal source rock + late-stage fracture assemblage type, and paleo-structural trap + (internal source rock) + source-connected fracture + late-stage fracture assemblage type. Full article

Compared with traditional gas reservoirs, ultra-deep and ultra-high-pressure tight sandstone gas reservoirs are characterized by well-developed faults and fractures, strong heterogeneity and stress sensitivity, and complex in situ stress distribution. Traditional three-dimensional geological models and numerical models ignore the variation characteristics of reservoir in situ stress during the production process, it affects the accuracy of the subsequent fracturing modification design and development plan formulation. Therefore, based on the integrated method of geological engineering, this article first carried out high-temperature and high-pressure stress sensitivity tests on reservoir rock samples and fitted the stress-sensitive mathematical model to clarify the influence of high temperature and high pressure on permeability. Then, aiming at the problem of four-dimensional in situ stress variation caused by the coupling of the seepage field and stress field during the exploitation of tight sandstone gas reservoirs, combined with the results of well logging interpretation, rock physical property analysis, and mechanical experiments, based on the three-dimensional geological model and geomechanical model of the gas reservoir and coupled with the stress-sensitive characteristics of the reservoir, a four-dimensional in situ stress model for the reservoir of tight sandstone gas reservoirs was established. The prediction of the variation law of four-dimensional in situ stress during the production process was carried out. Finally, the influence of considering stress sensitivity on reservoir production was simulated. The results show the following: ① The production process has a significant impact on the magnitude and distribution of four-dimensional in situ stress. With the decrease in pore pressure, both the maximum horizontal principal stress and the minimum horizontal principal stress decrease. ② In the area near the production well, the direction of in situ stress will significantly deflect over time. ③ In an ultra-deep and ultra-high-pressure environment, the gas reservoir is affected by the stress-sensitive effect. The stable production time of the gas well is reduced by two years, and the cumulative gas production decreases by 5.01 × 10⁸ m³. The research results provide the temporal stress field distribution results for the simulation and prediction of the secondary fracturing of old wells and the commissioning fracturing of new wells in the target well area. Full article

Under high-temperature and high-pressure conditions, understanding the competitive adsorption and mobilization mechanisms of gas and water in fractured tight sandstone gas reservoirs is crucial for optimizing the recovery factor. This study employs molecular dynamics simulation to investigate the adsorption behavior and mobilization characteristics of H₂O and CH₄ in 10 nm quartz nanopores under the conditions of the Keshen fractured tight sandstone gas reservoir. The results indicate that H₂O exhibits strong adsorption on the quartz surface, forming two high-density adsorption layers with a thickness of approximately 0.6 nm, whereas CH₄ forms three adsorption layers with a thickness of about 1.1 nm. Under gas–water coexistence conditions, the competitive adsorption effect of the water phase significantly influences the distribution of CH₄. Due to the hydrophilicity of the quartz wall, H₂O molecules preferentially adsorb onto the wall surface, forming a stable water film that significantly inhibits CH₄ adsorption. When the water saturation reaches 35%, water molecules form liquid bridges within the pores, segmenting the gas phase into different regions. As water saturation further increases, more stable liquid bridge structures develop, and microscopic water lock effects emerge, further restricting gas flow. During depletion development, H₂O remains difficult to mobilize due to strong wall adsorption, with a recovery factor of only 7%. In contrast, CH₄ exhibits high mobility, with a recovery factor of up to 75%. However, as water saturation increases from 30% to 70%, the recovery factor of CH₄ decreases significantly from 75% to 29%, indicating that the water phase not only occupies pore space, but also exerts a blocking effect that significantly inhibits CH₄ percolation and production. This study provides important theoretical support for the development strategies of ultra-deep fractured tight sandstone gas reservoirs and offers key insights for improving the ultimate recovery factor under gas–water coexistence conditions. Full article

Dynamic reserves evaluation is crucial for the development and assessment of gas reservoirs. However, ultra-deep fractured tight sandstone gas reservoirs pose unique challenges due to their abnormally high pressure, tight matrix, and complex fracture distribution. This paper proposes a simplified forward calculation method that incorporates the fracture length for the rapid estimation of dynamic reserves in fractured tight sandstone gas reservoirs. This method was based on the pressure change rate equation and considered the unique characteristics of fractured gas reservoirs. Numerical simulations were conducted to analyze the sensitivity of the proposed method. The proposed method was applied to estimate the dynamic reserves of a fractured gas reservoir, and the results closely approximate the well group method, indicating its accuracy. The main advantage of this method lies in its simplicity, allowing field engineers to perform rapid dynamic reserve evaluations. Full article

Located in the Kuqa foreland basin, Tarim Basin, the Xinkeshen gas field is a rare ultra-deep and ultra-high-pressure fractured tight sandstone gas reservoir. During the development process, the fluid in the well migrates from the bottom hole to the ground. Due to the huge temperature drop and pressure drop in the wellbore, salting-out and scale-out occur in the well to destroy the oil and gas flow channel, resulting in a decrease in gas production in the well and seriously affecting the normal production of the oil field. Aiming at the problem of wellbore scaling and blockage in the Keshen gas field, this paper takes the wellbore of the Keshen block as the research object. After analyzing the composition of produced water and scale in the wellbore, the solution of ‘fixing scale, clarifying mechanism, early prediction, and fine treatment’ is formulated, and the analysis and evaluation technology of the scale formation process and the prediction model of the gas well model are formed. The wellbore blockage in Keshen block is composed of iron oxide, calcium carbonate crystal, calcite crystal, and wellbore steel falling off due to electrochemical corrosion. It is indicated that the scale attached to the steel sheet causes electrochemical corrosion of the steel sheet, resulting in ‘hydrogen embrittlement’, resulting in the bubbling and falling off of the wellbore steel. Through simulation, it is found that the amount of fouling increases with the increase in wellbore depth, and the amount of fouling is 1.97 kg/d at 6800 m, which is in good agreement with the actual situation. Based on the temperature and pressure curves in the wellbore, the simulation results show that the corrosion rate reaches the highest value of 6.37 mm/yr at the depth of 3400 m. Because of the above problems, a polyaspartic acid scale inhibitor with a scale inhibition rate of 98.9% for wells in Keshen block was synthesized. It has important guidance and reference significance for the accurate treatment of scaling problems in the Keshen gas well. Full article

Sandstone oil–gas reservoirs in the Junggar Basin, China have great development potential. However, their ultra-deep formation depth leads to high crustal stress and high breakdown pressure. Therefore, in this research, we studied the cyclic hydraulic fracturing of tight sandstone with different combinations of “high-pressure duration + low-pressure duration” under high-stress conditions. Through laboratory experiments, the pump pressure curves, hydraulic fracture morphology, acoustic emission counts, and peak frequency of the samples were obtained. The results showed that: (1) Compared with conventional hydraulic fracturing, the breakdown pressure of cyclic hydraulic fracturing was reduced by more than 30%, the minimum threshold of cyclic pump pressure required for sample breakdown was between 60%P_b and 70%P_b, and cyclic hydraulic fracturing more easily formed complex and diverse hydraulic fractures. (2) In cyclic hydraulic fracturing, under the same upper limit of cyclic pump pressure, the shorter the high-pressure duration, the fewer the cycles required for sample breakdown. (3) Under the same “high-pressure duration + low-pressure duration” condition, the lower the upper limit of the cyclic pump pressure, and the greater the number of cycles required for sample breakdown. (4) The AE cumulative counts curves fluctuated greatly during cyclic hydraulic fracturing, rising in an obvious step-wise manner and the AE peak frequency was banded and mainly divided into three parts: low frequency, medium frequency, and high frequency. Full article