Abstract Carbonated water (CW) imbibition is an effective method for enhanced oil recovery, by combining the advantages of CO2 and water. Nevertheless, there are few reports in existing studies on its performance in shale oil reservoirs. This research is specifically focused on these shale oil reservoirs, investigating the variation in countercurrent imbibition distance (CID) and the imbibition effects of using CW as a pre-fracturing fluid. In this study, CT online scanning experiments were conducted with shale cores to investigate the CID of formation water, CW, and fracturing fluids. Simultaneously, we determined and comparatively analyzed the countercurrent imbibition recovery (CIR) of these fluids. Furthermore, imbibition experiments were conducted using a high-temperature and high-pressure visual apparatus to assess the imbibition recovery of formation water, CW, and fracturing fluids. The findings suggest that CW significantly enhances shale oil recovery, with CID and CIR values reaching 1.75 cm and 6.95%, respectively. Compared to formation water and fracturing fluid, the CID of CW increased by 0.75 cm and 0.25 cm, while the CIR rose by 4.77% and 1.90%, respectively. CW achieved the highest imbibition recovery at 29.22%, exceeding that of fracturing fluids (25.18%) and formation water (10.25%). In this research, the application of CW as a pre-fracturing fluid to enhance shale oil recovery is introduced for the first time. Moreover, it quantifies the CID of CW and fracturing fluids in shale matrices, offering a pioneering strategy for the enhanced coordination of fracturing, shut-in, and production processes in shale oil exploitation.

Carbonated water (CW) injection refers to a development method that involves dissolving CO2 in water under specific temperatures and pressures, followed by its injection into reservoirs for oil recovery. This technique can simultaneously enhance oil recovery and facilitate CO2 storage, although its effectiveness requires further improvement. To address this, an advanced approach known as enhanced carbonated water (ECW) injection has been proposed. This approach involves the addition of other fluids to CW, including polymers, nanofluids, surfactants, and low salinity water, to serve as displacement media during oil recovery. It aims to leverage the advantages of various technologies to further enhance oil recovery and CO2 storage effectiveness. Although ECW injection exhibits significant application potential, a systematic summary of its research progress is still lacking. Therefore, this article aims to fill this gap by systematically summarizing the latest research on ECW injection, detailing the mechanisms and performance in enhancing oil recovery and achieving CO2 storage. The method effectively exploits the synergistic benefits of CW and various displacement agents. Its primary mechanisms include increasing the dissolution of CO2 and prolonging the duration of CO2 retention in the water, reducing interfacial tension, and altering wettability. Both laboratory experiments and numerical simulations have demonstrated that ECW injection can significantly boost recovery and offer promising results in CO2 storage, presenting it as a highly prospective method for reservoir development. In addition, this paper discusses the main challenges facing this technology and explores potential future research directions, aiming to provide robust guidance for the research and application of this technology.

Carbonated water (CW) is defined as water in which CO 2 has been dissolved. Utilizing CW as the imbibition fluid enables the simultaneous exploitation of capillary forces and CO 2 diffusion, resulting in enhanced oil recovery (EOR) and facilitating CO 2 sequestration. Nevertheless, the literature reveals a notable scarcity of research on the imbibition of CW in shale oil reservoirs. In this study, the imbibition experiments involving formation water, surfactant, CW, and active carbonated water (ACW) were conducted on shale cores, considering reservoirspecific temperatures and pressures. Furthermore, the countercurrent imbibition distance (CID) for these fluids was quantitatively characterized using online computed tomography scanning. The EOR performance, alongside the CID and countercurrent imbibition recovery (CIR), is further compared to highlight differences in effectiveness among the fluids. The experimental results demonstrate the imbibition recovery for formation water is 10.66 %. CW and ACW can significantly enhance the imbibition recovery, achieving 28.82 % and 34.65 %, respectively, both of which are higher than surfactant. The CID and CIR for formation water are 1.125 cm and 2.35 %, respectively. While surfactant can increase the imbibition spread area and the efficiency of imbibitiondriven oil recovery to some extent, CW and ACW exhibit even great efficacy, evidenced by their higher CIDs of 1.875 cm and 2.375 cm, and CIRs of 7.09 % and 9.30 %, respectively. This paper, for the first time, investigates the imbibition recovery, CID and CIR of CW and ACW in shale matrices, which uncovers the potential for CW/ ACW imbibition in enhancing shale oil recovery.

Countercurrent imbibition is an important mechanism for tight oil recovery, that is, water imbibes spontaneously from the fracture into the porous matrix while oil flows reversely into the fracture. Its significance over cocurrent imbibition and forced imbibition is highlighted when permeability reduces. We used the computed tomography (CT) scanning to measure the one-dimensional evolution of water saturation profile and countercurrent imbibition distance (CID) at different fluid pressures, initial water saturations, and permeability. Surprisingly, experiments show that CID evolution for tight reservoir cores dramatically deviates from the classical diffusive rule (i.e., evolutes proportional to square root of time, t0.5). At early stage, CID extends faster than t0.5 (super-diffusive); while at late stage, CID extends much slower than t0.5 (sub-diffusive). After tens of hours, the CID change becomes too slow to be practically efficient for tight oil recovery. This research demonstrates that this deviation from classic theory is a result of (1) a much longer characteristic capillary length than effective invasion depth, which eliminates full development of a classical displacement front; and (2) non-zero flow at low water saturation, which was always neglected for conventional reservoir and is amplified in sub-mili-Darcy rocks. To well depict the details of the imbibition front in this situation, we introduce non-zero wetting phase fluidity at low saturation into classical countercurrent imbibition model and conduct numerical simulations, which successfully rationalizes the non-diffusive behavior and fits experimental data. Our data and theory imply an optimum soaking time in tight oil recovery by countercurrent imbibition, beyond which increasing exposed fracture surface area becomes a more efficient enhanced oil recovery (EOR) strategy than soaking for longer time.

Global tight-oil reserves are abundant, but the depletion development of numerous tight-oil reservoirs remains unsatisfactory. CO2 injection development represents a significant method of reservoir production, potentially facilitating enhanced oil recovery (EOR) alongside CO2 storage. Currently, limited research exists on advanced CO2 injection and well pattern adjustment aimed at improving the oil recovery and CO2 storage within tight-oil reservoirs. This paper focuses on the examination of tight oil within the Ordos Basin. Through the employment of slim-tube experiments, long-core displacement experiments, and reservoir numerical simulations, the near-miscible pressure range and minimum miscible pressure (MMP) for the target block were ascertained. The viability of EOR and CO2 sequestration via advanced CO2 injection was elucidated, establishing well pattern adjustment methodologies to ameliorate CO2 storage and enhance oil recovery. Simultaneously, the impacts of the injection volume and bottom-hole pressure on the development of advanced CO2 injection were explored in further detail. The experimental results indicate that the near-miscible pressure range of the CO2–crude oil in the study area is from 15.33 to 18.47 MPa, with an MMP of 18.47 MPa, achievable under reservoir pressure conditions. Compared to continuous CO2 injection, advanced CO2 injection can more effectively facilitate EOR and achieve CO2 sequestration, with the recovery and CO2 sequestration rates increasing by 4.83% and 2.29%, respectively. Through numerical simulation, the optimal injection volume for advanced CO2 injection was determined to be 0.04 PV, and the most favorable bottom-hole flowing pressure was identified as 10 MPa. By transitioning from a square well pattern to either a five-point well pattern or a row well pattern, the CO2 storage ratio significantly improved, and the gas–oil ratio of the production wells also decreased. Well pattern adjustment effectively supplements the formation energy, extends the stable production lives of production wells, and increases both the sweep efficiency and oil recovery. This study provides theoretical support and serves as a reference for CO2 injection development in tight-oil reservoirs.

In the process of water-bearing gas reservoir development, water invasion has a serious influence on the recovery factor of the gas reservoirs. In order to accurately and intuitively evaluate the dynamic characteristics of water invasion in complex edge-water gas reservoirs and determine the size of edge water and the location of dominant water invasion channel, this paper regards the water and development gas well at the edge of a gas reservoir as the water invasion unit（including water unit and gas well unit） based on the geological data of the gas reservoir and the production data of the gas well, and establishes a new numerical simulation model of water invasion unit in the gas reservoir with complex water invasion flow of edge water. Then, the pressure of each unit is calculated by the material balance equation, and the gas saturation and water cut of each unit are calculated by the gas-water two-phase motion equation. Finally, combined with genetic algorithm, the production data is automatically fitted based on the characteristic parameters of modified water units and water invasion channels, and water distribution and dominant water invasion channel are reidentified. And the following research results are obtained. First, the new numerical simulation model based on water invasion unit can effectively improve the computational efficiency of numerical simulation and accurately reflect the inflow performance of water invasion. Second, the automatic history fitting of the new model combined with intelligent optimization algorithm realizes the inversion of water invasion performance, and can determine the characteristic parameters of water body and water invasion channels more quickly. Third, the development practice of a typical well group in a certain gas reservoir of the Sichuan Basin proves that the new numerical simulation model of water invasion unit can effectively recover the historical process of water invasion. This method can quickly and accurately evaluate the influence degree of water invasion, propose targeted optimization and adjustment scheme, and provide reference for the measures of drainage and gas recovery in the later period. In conclusion, the research results enrich the theoretical foundation for the numerical simulation of water invasion gas reservoir, and a new water invasion simulation method combining the surrogate model with intelligent optimization algorithm is innovatively proposed, which provides technical support and direction guidance for enhanced gas recovery of water-bearing gas reservoirs.

Tight oil energy occupies an increasingly important position for petroleum energy in the world.At present, most tight oil reservoirs have the problems of low formation pressure and difficult exploitation.Therefore, it is important to make reasonable management scenarios and forecasting for tight oil energy.Current research shows that natural gas flooding (NGF) can improve oil recovery for tight reservoirs, meanwhile, the oil field usually has abundant associated gas, which is suitable for natural gas flooding.This paper mainly investigates NGF development for tight oil reservoirs in Ordos Basin, aiming to recycle the associated natural gas that has little commercial value to enhance oil recovery, and formulates reasonable development plan and forecasting.The PVT experiment is conducted to provide support for numerical simulation, which includes three parts: Firstly, the numerical model of tight reservoir is established.Then, sensitivity production parameters are analyzed.Finally, oil recovery and gas storage are studied.The phase diagram of crude oil is obtained by PVT experiments, and the saturation-pressure line is obtained by composition model is well matched with the experimental data.Sensitivity analyses demonstrate that the recommended injection rate of single well is 4000-4500 m 3 /d and bottom hole pressure of production well is about 8 MPa.In the early stage of NGF, oil recovery is higher and gas storage effect is better, while oil recovery and gas storage effect are both poor in the later stage.This paper is a combination of energy recycling and enhanced oil recovery.In this research, development scenarios and forecasting are applied in practical oil fields and provides support for subsequent development, which provides a reference for developing similar oil reservoirs.Meanwhile, it is expected that this research can be extended to the collaborative gas storage construction and oilfield development.

In order to accurately and intuitively characterize the distribution of water and water invasion channel in complex edge water reservoir, a water invasion unit numerical simulation model (WINS) that can simulate complex edge water invasion dynamics is established, based on well geological data and production data. The model discretizes the edge water into water unit connected to the production well unit, and discretizes the locations with clear geological understanding into dense unit. The more dense units, the more accurate the water invasion dynamics. Based on the water unit, production well unit, dense unit, the material balance method is used to calculate the pressure of each unit, the water flooding front propulsion equation is used to calculate the saturation and water cut of each unit, and the genetic algorithm is combined to modify characteristic parameters of the water unit and the water invasion channel, fit automatically production data, realize the re-identification of water distribution and water invasion channel. Different edge water and high-permeability bands are constructed through numerical simulator, and the simulated production results are substituted into the model to automatically fit. The results show that the edge water distribution and water invasion dominant channel inversely performed by WINS are consistent with the results constructed by the numerical simulator. Compared with the process of constructing edge water at the reservoir by Eclipse numerical simulator, WINS saves the tedious steps of building a model, and its calculation efficiency is higher. Not only that, WINS can intelligently and automatically fit parameters, reducing errors caused by human interference.

The complexity of the pore structure, spatial development, fractures, and pore distribution of fractured-vuggy carbonate reservoirs influences the water invasion dynamics of gas reservoirs, which is crucial in the dynamic research of strongly heterogeneous reservoirs. In this study, the collocation relationship of pore-vuggy fractures is described by the quantitative characterization of their attribute parameters. The discrete fracture network model is used to match and construct the fractures in different modes. The distribution classification method is used to model three-dimensional geological reservoirs in terms of their geometric and attribute characteristics. Bottom-water and edge-water gas reservoirs are constructed separately using numerical simulation, and the dynamic characteristics of water invasion are described. The results show that the proposed method is suitable for the geological modeling of fractured-vuggy gas reservoirs with strong heterogeneity and complexity. The modeling accuracy is improved because the gas reservoir heterogeneity and water invasion's dynamic characteristics can be described accurately. Six stages of water invasion are identified from the numerical simulation of water invasion. This method provides theoretical guidance for the study of heterogeneous gas reservoirs with water.