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In order to achieve the multiple purposes of the highest CO2 flooding recovery and the largest CO2 storage in high water cut reservoirs， an objective function of collaborative CO2 flooding and storage optimization for high water cut reservoirs based on economic net present value （NPV） was established by considering CO2 injection cost， CO2 flooding and storage benefits. Combined with the reservoir numerical simulation method， we used simultaneous perturbation stochastic approximation （SPSA） to solve the objective function iteratively. Taking a high water cut reservoir in Shengli Oilfield as an example， the different injection timings of water transferring to CO2 were set according to the different characteristics of water cut in the reservoir at different times. The optimization of water injection and CO2 injection schemes was carried out， respectively， and the differences in production behavoir and NPV under the two injection methods were compared. The influence of gas injection timing on cumulative oil production and CO2 storage was analyzed， and the optimal gas injection timing was determined. In addition， the effects of different gas injection prices and CO2 storage subsidy schemes on their economic benefits were analyzed. The results show that the water cut should be lower than 0.97 during waterf transferring CO2 injection to make the CO2 flooding project profitable in high water cut reservoirs. The high project profit can be guaranteed as CO2 is injected earlier when the CO2 injection price is 1.2 yuan/m3， and the carbon subsidy is 0.114 yuan/m3.

CO2 flooding technology is an effective technical means to enhance the recovery of low permeability reservoirs. After CO2 comes into contact with crude oil， the asphaltene in the system is deposited in a solid form， which causes a certain blockage to the reservoir， but the dissolution improves the flow capacity of the reservoir as a whole at the same time. The damage of CO2 flooding to low permeability reservoirs under different injection methods is different. The organic scale plugging mechanism， reservoir wettability， and CO2-water solution corrosion evaluation experiments were carried out after continuous CO2 injection and CO2-water alternating injection. The variation characteristics of relative permeability curve parameters were evaluated， and the damage of different injection methods of CO2 flooding to low permeability reservoirs was quantitatively characterized. The results show that the organic scale produced by CO2 flooding would block the pore throat of the rock， but on the whole， the dissolution caused by the reaction of CO2 and chlorite is stronger， which makes the recovery of the low permeability reservoirs effectively enhanced. Moreover， the organic scale blockage caused by CO2-water alternating injection is weaker than that caused by continuous CO2 injection， and the dissolution effect is better. The permeability loss rate is lower. It could achieve a better oil displacement effect in pores with a radius of more than 0.2 μm and increase the pore space and flow channel of the rock so that the recovery of low permeability reservoir could be effectively improved.

Accurate production prediction is crucial in the field of reservoir management and production optimization. Traditional models often struggle with the complexities of nonlinear relationships and high-dimensional data, which hinders their ability to capture the variability of the production process efficiently and results in time-consuming calculations. To overcome these limitations, this paper introduces an innovative proxy modeling technique employing a convolutional spatiotemporal neural network. This method utilizes convolutional neural networks to extract spatial features from high-dimensional data, while the Transformer is used to model and predict complex temporal dynamics in production. To validate the effectiveness of the proposed proxy model, two case studies involving four injection and nine production wells within two-dimensional (2D) and three-dimensional (3D) non-homogeneous reservoirs were conducted, with the R2 coefficient serving as the primary evaluation metric. As the number of training iterations and data volume increase, the proxy model demonstrates rapid convergence. In tests conducted on the 2D and 3D datasets, the average R2 value exceeded 0.96 and 0.94. These results confirm the accuracy and stability of the proxy model. It also shows that the proxy model can accurately describe the geological and fluid seepage characteristics of the reservoir, which in turn can achieve a highly accurate match with the real data. In addition, the computational time is reduced by two orders of magnitude compared to traditional models. Compared with the long short-term memory method, the accuracy of the prediction results is increased by 30%, which greatly enhances efficiency and accuracy. To some extent, the presented proxy model can provide some guidance for the efficient history match of production data. [ABSTRACT FROM AUTHOR]

In terms of the collaborative optimization of CO2 flooding for Enhanced Oil Recovery (EOR) and CO2 sequestration, previous studies have co-optimized both cumulative oil production and CO2 sequestration by various algorithms. However, these solutions fail to optimize the CO2 injection schemes for high-water cut oil reservoirs. This paper presents an optimization methodology for CO2 flooding and sequestration in high-water cut oil reservoirs. The production optimization was carried out by adjusting the injection and production rate. To solve the proposed objective functions, the simultaneous perturbation stochastic approximation (SPSA) algorithm is applied in this paper, and the CMG-GEM module is utilized to simulate the reservoir production performance. A typical high-water cut reservoir in the Shengli oilfield was used to verify the feasibility of the presented methodology. In this paper, the production performance and net present value (NPV) for continuous gas injection under different water cuts were analyzed. The optimal timing of transforming from water flooding to gas displacement for the high-water cut reservoir was optimized. In addition, the optimal water–gas ratios for Water-Alternating-Gas (WAG) flooding were determined. The sensitivity of NPV to gas injection price and carbon subsidy was analyzed. The results show that when the gas price is 0.178 $/m3 and the carbon subsidy is 0.0169 $/m3, the optimal timing of transforming from water flooding to gas injection should be earlier than the time when the water cut is 0.82. Through the combination of NPV, cumulative oil production rate, and CO2 sequestration volume for WAG flooding, the optimal WAG ratio should be 1:2. The presented method in this paper considers various economic indicators and can optimize CO2 flooding and sequestration in high-water cut oil reservoirs efficiently, which can provide some guidance for the design of CO2 flooding schemes in high-water cut oil reservoirs. [ABSTRACT FROM AUTHOR]

Owing to the prevalent viscosity in the subsurface medium, seismic waves experience amplitude attenuation effects during their propagation in visco-acoustic media. Therefore, it is crucial to develop a method that can compensate for wavelet amplitude attenuation and enhance imaging quality. In this paper, we derive an expression for corrected ray complex travel time by introducing the quality factor Q. Additionally, we modify the classical Gaussian beam propagation operator to an adaptive focus type propagation operator. Our research presents an adaptive focused beam migration imaging method specifically designed for viscous acoustic media, incorporating a combination of traditional Gaussian beam migration imaging methods. In comparison to traditional migration methods, the proposed approach achieves energy focusing along the phase axis and significantly improves imaging quality. The validity and effectiveness of our method are confirmed through the obtained imaging results. [ABSTRACT FROM AUTHOR]

Carbon dioxide flooding can accelerate the development of low-permeability reservoirs of the Kexia group in the K region of the T oil field, thus resolving the issue of inadequate water drive effects. This study was focused on the well group 80513 in the K region, and based on the reservoir and fluid parameters, a simulation model of water-sensitive post-CO 2 flooding was constructed to refine the gas injection strategy gradually. The injection rate of the continuous gas injection stage was preferred based on the degree of recovery. Multiindicator and multifactor injection and extraction schemes were established to optimize and analyze the key controlling factors, including the gas injection rate, gas injection period, gas-to-water ratio, and bottom-hole flow pressure, in the carbon dioxide gas-to-water alternation process. Recovery efficiency, oil exchange rate, formation pressure, and carbon dioxide storage rate were used as indicators. After 5 years of continuous CO 2 flooding, the results indicated that switching to CO 2 gas-water alternating flooding was more appropriate for the target block's environment. The best development plan was achieved when the gas injection rates were 1.0 and 1.25 × 10 4 m 3 ·d -1 for continuous gas injection and CO 2 gas-water alternating flooding, respectively, with a gas-water ratio of 1:1, a gas injection cycle of 90 days, and a bottom-hole flow pressure of 25 MPa in the production wells. A comparison between the results revealed that the formation pressure and oil recovery efficiency of this well group significantly increased upon CO 2 flooding, and the parameter optimization results were well suited for controlling the gas flurry, offering a versatile model for future development of the block., Competing Interests: The authors declare no competing financial interest., (© 2024 The Authors. Published by American Chemical Society.)