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The Lucaogou Formation, a typical fine-grained mixed formation in the Jimusaer Sag of the Junggar Basin, exhibits considerable potential for hydrocarbon exploration. Accurate brittle prediction is a crucial factor in determining hydraulic fracturing effectiveness. However, the area features complex lithological characteristics, including carbonate rocks, clastic rocks, volcanic rocks, and gypsum interbeds, along with thin layering and sporadic sweet spots. Traditional prediction methods offer limited resolution and there is an urgent need for a seismic brittle prediction method tailored to this complex geological environment. This paper presents a multi-mineral composition equivalent model for complex lithologies that enables the accurate calculation of Vp and Vs These ratios serve as the foundation for pre-stack elastic parameter predictions, which include Poisson’s ratio and Young’s modulus. By comparing the predicted parameters with well-logging measurements, the prediction accuracy is improved to 82%, with particularly high conformity in intervals characterized by high organic matter and clay content. Additionally, a three-dimensional brittle modeling approach reveals that the brittleness of the reservoir exceeds that of the surrounding rock, showing a gradual improvement in brittleness with increasing burial depth from southeast to northwest. The central area exhibits relatively good brittleness, with a stable, blocky distribution pattern.

The current oil recovery of the Lucaogou shale oil reservoir is predicted to be about 7.2%. It is crucial to explore improved oil recovery (IOR) technologies, and further experimental and field research needs to be conducted to study the complex mechanism. In this study, laboratory experiments were carried out to investigate the performance of one-step and multi-step depletion, CO2 huff-n-puff, and surfactant imbibition based on nuclear magnetic resonance (NMR). The sweep efficiencies were assessed via NMR imaging. In addition, hybrid methods of combining surfactant with CO2 huff-n-puff and the performance of injection sequence on oil recovery were investigated. The experimental results indicate that oil recoveries of depletion development at different initial pressures range from 4% to 11%. CO2 huff-n-puff has the highest oil recovery (30.45% and 40.70%), followed by surfactant imbibition (24.24% and 20.89%). Pore size distribution is an important factor. After three more cycles of surfactant imbibition and CO2 huff-n-puff, the oil recovery can be increased by 11.27% and 26.27%, respectively. Surfactant imbibition after CO2 huff-n-puff shows a viable method. Our study can provide guidance and theoretical support for shale oil development in the Lucaogou shale oil reservoir. [ABSTRACT FROM AUTHOR]

To address the problems of low recovery rate and poor water injection huff-n-puff effect in the depleted development of Jimsar shale oil. A study on the applicability of CO2 huff-n-puff technology in shale oil reservoirs was carried out by means of hydrocarbon phase experiments and numerical simulation methods for reservoirs to guide the implementation of CO2 huff-n-puff technology in the field. The results show that Compared with CH4, CO2 interacts better with Jimsar shale oil. Under the conditions of formation pressure and formation temperature, the solution gas-oil ratio of CO2 in crude oil is 497. 83 m³ / m³, the crude oil viscosity is reduced by 70. 65%, and the crude oil volume is expanded by 2. 05 times; for typical shale oil wells, multi-cycle CO2 huff-n-puff can improve the recovery rate by 9. 43 percentage points and crude oil production by 31 472. 40 t. With the shortening of frac- ture spacing and the increase of reservoir porosity, the effect of CO2 huff-n-puff on oil enhancement gradually becomes better, and the influence of permeability and oil saturation on the effect of CO2 huff-n-puff is relatively small. The results of the field test show that CO2 huff-n-puff can effectively enhance the recovery rate of shale oil, and the oil enhancement effect is better under the condition of no fracture disturbance. The research results have some implications for the efficient development of shale oil. [ABSTRACT FROM AUTHOR]

In response to the problems of low recoverable reserves and poor commercial benefits of single well with vertical well fracturing in low-permeabilitv conglomerate reservoir in Well Block Ma18, Aihu Oilfield, the parameter design and productivity prediction of multi-stage fractured horizontal wells were investigated bv numerical reservoir simulation, reservoir engineering method, economic limit method and mine field test method. The results indicated that the " sweet spot" depth in Well Block Ma18 was 3 876 to 3 881 m, the horizontal well strike should be in north-south direction, the recommended length of horizontal interval in horizontal well was 1 200 to 1 400 m, the well spacing was 500 m, the fracture half-length was 150 m, and the fracture spacing was 50 m. Six multistage fractured horizontal wells were designed with optimized parameters, achieving an average daily oil production of 29. 0 t/d in the first year, which was consistent with the predicted production of 25. 0 to 33. 0 t/d. This study developed an oil saturation prediction method for conglomerate reservoir, and developed a method of parameter design and productivity prediction for multi - stage fractured horizontal wells in conglomerate reservoir, providing a reference for similar reservoirs. [ABSTRACT FROM AUTHOR]