Formation Pressure Research Articles

Causes of Multi-Mechanism Abnormal Formation Pressure in Offshore Oil and Gas Wells

This study thoroughly investigates the complex origins of abnormal formation pressure in offshore oil and gas wells, taking the Rio del Rey Basin in Cameroon as a case study. Renowned for its abundant oil and gas resources, the area faces unique challenges in predicting overpressure due to its high-temperature and high-pressure reservoir characteristics. By quantitatively analyzing the main mechanisms such as undercompaction, high-temperature fluid expansion, and mud diapirism, the study addresses the complexities of overpressure prediction. This paper introduces an innovative analytical framework that combines hierarchical clustering algorithms with the LightGBM model. Further refined by the application of Bayesian optimization, the model intelligently adjusts hyperparameters to enhance predictive accuracy. Utilizing well logging data and applying machine learning techniques, the paper classifies and identifies different mechanisms causing abnormal pressures, achieving a model prediction accuracy of 0.942. The research findings highlight the predominant role of the undercompaction mechanism, accounting for approximately 70% of the abnormal high-pressure events in the study area. Fluid expansion and shale diapirism contribute smaller but significant proportions of 10% and 20%, respectively. These quantitative insights into the pressure mechanisms are vital for optimizing drilling operations and reducing risks in oil and gas exploration. The study’s hybrid approach, integrating geophysical analysis with advanced computational techniques, sets a precedent for future research. It provides new avenues for applying machine learning to understand complex geological phenomena in similar geological environments and makes a significant contribution to the strategic planning of hydrocarbon exploration and production activities.

Intelligent Pressure Monitoring Method of BP Neural Network Optimized by Genetic Algorithm: A Case Study of X Well Area in Yinggehai Basin

While drilling formation pressure monitoring is an important basis for ensuring drilling safety and oil and gas discovery, the calculation of existing pressure monitoring methods is complicated and the accuracy is difficult to improve. Taking the actual well data of well area X in Yinggehai Basin as the object, correlation analysis was first carried out to select and standardize the data features, and relevant effective parameters were extracted. Two kinds of neural networks, back-propagation network BP and back-propagation network GA-BP optimized by genetic algorithm, were used to establish artificial intelligence monitoring models of formation pressure based on 10 kinds of measuring and logging data, respectively. The application effect of the model was evaluated based on the results of monitoring the pressure while drilling. The results show that the monitoring accuracy of the BP neural network model is 91.25%, and that of the GA-BP neural network model is 92.89%. The latter has a better monitoring effect on formation pore pressure. In formation pressure monitoring in areas with a high degree of well control, the introduction of artificial intelligence technology has the advantages of simplicity, speed and high precision, and can provide a reference for other areas of pressure monitoring while drilling.

Effect of cement slurry filtrate on methane hydrate stability during deepwater cementing operations

Whether the hydrate layer is stabilized during deepwater cementing operations has a direct impact on the safety of the cementing process and the quality of the cementing. When the cement slurry enters the annular space and waits for solidification, it will be extruded to produce filtrate under the action of formation temperature and pressure. Moreover, the inorganic ions and organic matter contained in the filtrate may penetrate into the formation. However, whether these processes have an effect on the stability of the hydrate layer is not clear at present.In this paper, we initially developed a methane hydrate generation system, termed the water-quartz sand-methane system. This system efficiently produces methane hydrate within a short time and ensures a uniform distribution of the gas-solid phase, which is highly suitable for further research into methane hydrate stability. Subsequently, the primary constituents of the cement slurry filtrate and the principal functional groups of the cement additive were identified. Furthermore, enhancements were made to the existing formula for quantifying methane gas alteration. Additionally, a hydrate testing experimental system was employed to circulate a solution comprising the primary constituents of the cement slurry filtrate over the methane hydrate surface. Ultimately, utilizing the amount of change in the volume of methane gas in the cyclic process as a criterion to evaluate the impact of various components of the cement slurry filtrate on methane hydrate stability, an investigation into the effect of the cement slurry filtrate on methane hydrate stability was conducted. It was confirmed that Ca2+, Na+, Cl- ions within the cement slurry filtrate, along with the pH value, minimally influence methane hydrate stability. Conversely, the cement additive exhibits a discernible disruptive effect on methane hydrate stability, with the retarder demonstrating the most pronounced impact when mass fractions are equated.This study suggests that the adverse effects of amide and carboxyl groups on hydrate stability must be considered in the selection of additives for deepwater cementing slurries. The findings offer guidance for the research and development of additives for deepwater cementing slurries and establish a theoretical foundation for studying cementing slurry systems in hydrate formations.

Gas Production Prediction Model of Volcanic Reservoir Based on Data-Driven Method

Based on on-site construction experience, considering the time-varying characteristics of gas well quantity, production time, effective reservoir thickness, controlled reserves, reserve abundance, formation pressure, and the energy storage coefficient, a data-driven method was used to establish a natural gas production prediction model based on differential simulation theory. The calculation results showed that the average error between the actual production and predicted production was 12.49%, and the model determination coefficient was 0.99, indicating that the model can effectively predict natural gas production. Additionally, we observed that the influence of factors such as reserve abundance, the number of wells in operation, controlled reserves, the previous year’s gas production, formation pressure, the energy storage coefficient, effective matrix thickness, and annual production time on the annual gas production increases progressively as the F-values decrease. These insights are pivotal to a more profound understanding of gas production dynamics in volcanic reservoirs and are instrumental in optimizing stimulation treatments and enhancing resource recovery in such reservoirs and other unconventional hydrocarbon formations.

Experimental study on the dynamic threshold pressure gradient of high water-bearing tight sandstone gas reservoir

Tight sandstone water-bearing gas reservoirs typically exhibit low porosity and low permeability, with reservoir rocks characterized by complex pore structures, often featuring micron-scale or smaller pore throats. This intricate reservoir structure significantly restricts fluid flow within the reservoir, necessitating a certain threshold pressure gradient (TPG) to be overcome before flow can commence. This study focuses on the Ordos Basin and explores the influence of high water content tight sandstone gas reservoirs on TPG under different water saturation and formation pressure conditions through experiments. A mathematical model of TPG is established using multiple linear regression method. The results show that TPG is primarily affected by water saturation, followed by formation pressure. As the water saturation increases, the TPG of the core decreases, and the change becomes more pronounced when the water saturation exceeds 50%. As formation pressure increases, the weakening of the slippage effect in gas molecules leads to TPG stabilization, especially when local pressure exceeds 25.0 MPa. The research also shows that low-permeability cores exhibit greater TPG variation with pressure changes, while high-permeability cores remain more stable. A mathematical model was developed and validated to predict TPG based on permeability, water saturation, and formation pressure. These findings highlight the need to monitor formation water content during tight sandstone gas reservoir development to optimize production strategies, providing valuable insights for improving reservoir management and guiding future research.

აზოტის გამოყენება ნავთობისა და გაზის ოპერაციებში

The article discusses several options for nitrogen application in the oil and gas industry. Nitrogen gas is useful in maintaining formation pressure in oil fields, expelling gas from the gas cap, stimulating steeply inclined formations, cyclic exploitation of gas condensate deposits, Completion of wells, Cleaning of wells with Coiled Tubing, Circulatimg low pressure reservoir wells with foam.Described experience of local oil and gas companies in Georgia utilizing nitrogen pumping in welltesting and stimulation.

Analytical solution to the problem of injection or reduction of the formation pressure in the reservoir with a fracture

The problem of injection of Newtonian fluid at a constant flow rate through an injection well into an initially undisturbed infinite reservoir with an erosive vertical main fracture of constant width is considered. Using the Laplace transform method, analytical solutions are obtained for the pressure fields in the fracture and reservoir, the flow velocity in the fracture, as well as the equations for fluid trajectories in the reservoir and in the main fracture are derived. The solutions obtained are also applicable to the problem of fluid withdrawal into a production well intersected by a vertical main fracture. Nonstationary two-dimensional pressure fields in the reservoir, as well as the pressure and velocity fields in the fracture, are constructed.

Research on the Injection–Production Law and the Feasibility of Underground Natural Gas Storage in a Low-Permeability Acid-Containing Depleted Gas Reservoir

Depleted gas reservoirs are important places for the rebuilding of gas-storage reservoirs. In order to demonstrate the feasibility of constructing and operating such underground gas storage, a low-permeability gas-storage seepage model considering fracture development was developed and established. The model was solved using semi-analytical methods, and the pressure–response characteristics during natural gas injection were analyzed. The impact of gas injection volume on formation pressure has been clarified, and the calculation method for ultimate injection pressure has been determined. Additionally, through numerical simulation methods, the migration law of acidic gas during gas injection, the variation law of produced acidic gas concentration, and the main control factors affecting the concentration of the produced acidic gas were studied. Furthermore, measures to reduce the concentration of the acidic gas produced were proposed. Finally, injection and production plans were designed for typical depleted acidic gas reservoirs, simulating the operation of gas storage for 12 cycles. The results indicate that the quality of natural gas produced in the third cycle can meet the Class II standard for commercial natural gas. Through this study, the feasibility of constructing gas-storage facilities for acidic depleted gas reservoirs has been demonstrated, and injection and production strategies for this type of gas reservoir have been proposed.

Synthesis and Properties of N1, N3‐di (2,4‐dinitrophenyl) −2‐fluoro‐1,3‐diamino‐4,6‐ Dinitrobenzene and its Analogues

AbstractPolynitrobenzene compounds are a type of heat‐resistant explosives with excellent thermal stability. This study reported three novel energetic compounds, namely compounds N1, N3‐bis(2,4‐dinitrophenyl)‐2‐fluoro‐4,6‐dinitrobenzene‐1,3‐ diamine (3), 2‐fluoro‐4,6‐dinitro‐N1,N3‐bis(2,4,6‐trinitrophenyl)benzene‐1,3‐ diamine (4), and 2‐chloro‐4,6‐dinitro‐N1,N3‐bis(2,4,6‐trinitrophenyl)benzene‐1,3‐ diamine (6). The target compounds were prepared with commercially available 2,3,4‐trifluoronitrobenzene and 2,3,4‐trichloronitrobenzole. The crystalline structures of compounds 3, 4, and 6 were determined by single‐crystal X‐ray diffraction, and the crystal densities (ρ) were calculated to be 1.7585 g cm−3, 1.6651 g cm−3, and 1.7371 g cm−3, respectively. Based on the calculated standard molar enthalpy of formation and crystal densities, the Chapman–Jouguet detonation properties of 3, 4, and 6 were predicted. Their enthalpy of formation (ΔHf), detonation velocities (D), and detonation pressures (P) were in the ranges of 110.1 kJ mol−1 to 349.9 Kj mol−1, 7264 m s−1 to 7770 m s−1, and 21.8 GPa to 25.9 GPa, respectively. Notably, the density, thermal decomposition temperature, detonation velocity, detonation pressure, and impact sensitivity value of compound 3 were 1.76 g cm−3, 313°C, 7546 m s−1, 24.2 GPa, and 16 J, respectively, suggesting that compound 3 is a high‐performance heat‐resistant explosive.

The Experimental and Modeling Study on the Thermodynamic Equilibrium Hydrate Formation Pressure of Helium-Rich Natural Gas in the Presence of Tetrahydrofuran.

Hydrate-based gas separation (HBGS) has good potential in the separation of helium from helium-rich natural gas. HBGS should be carried out under a pressure higher than the thermodynamic equilibrium hydrate formation pressure (Peq) to ensure the formation of hydrate so that the accurate prediction of Peq is the basis of the determination of HBGS pressure. In this work, the Peq of the helium-rich natural gases with different helium contents (1 mol%, 10 mol%, and 50 mol%) in gas and different tetrahydrofuran (THF) contents (5 wt%, 10 wt%, and 19 wt%) in liquid at different temperatures were experimentally investigated through the isothermal pressure search method. A new thermodynamic model was proposed to predict the Peq of helium-rich natural gas. This model can quantitatively describe the effects of THF and helium on Peq, and it predicts the Peq of the helium-rich natural gases in this work accurately. The average relative deviation of the model is less than 3%. This model can guide the determination of the operating condition of the HBGS of helium-rich natural gas.

Role of capillary pressure on carbon dioxide sequestration: mathematical analysis

ABSTRACT Geological disposal of CO2 after capturing the gas from large emitting sources is one of the safest and most prominent methods to eliminate CO2 from the atmosphere and mitigate climate change. The heterogeneities in porosity, permeability and capillary pressure in various underground formations impact gas distribution, affecting their storage capacity. Therefore, a numerical model is developed to study the plume migration under various physical heterogeneities by upscaling the variation in capillary pressure. Accordingly, homogeneous, heterogeneous and layered formations have been considered. The influence of capillary pressure and field-scale heterogeneities, such as porosity and permeability, is incorporated using the Leverett J function. The impact of variations in capillary pressure on gas migration is calibrated in different formations for ten years of injection. The analysis project that plume evolution in different formations highly deviates and a plume length of 3410 m is obtained for layered formation. A sensitivity analysis was conducted to understand the influence of interfacial tension in formations with differing heterogeneity. The change in interfacial tension impacts the average saturation of CO2, ranging from 0.287 to 0.155 in heterogeneous aquifers. The plume migration decreases in layered and increases in homogenous and heterogeneous media with decreased interfacial tension.

Efficient sealing of cemented sheath: An oil-responsive self-healing latex with toughness enhancement for cement composites

The integrity of the cemented sheath is important to the safe exploration of oil and gas resources. Sealing failure of cement sheath will result in formation fluid channeling and pressure carryover in the annulus. The both toughening and oil-responsive self-healing latex (TOS) was prepared to achieve efficient sealing of cemented sheath, and prolong its service life. The structure and oil swelling behavior of TOS, its toughening and self-healing effects on hardened cement paste (HCP) were analyzed by comprehensive characterizations. Results demonstrated that TOS possessed excellent stability and an oil swelling rate of 1235 %. Cement specimens by curing 28d containing 8 % TOS exhibited a 27.8 % increase in flexural strength, a 48.7 % reduction in elasticity modulus and a 33.8 % reduction in brittleness coefficient. The addition of TOS can effectively improve the toughness of cement. The average pore size of specimens containing 8 % TOS admixture decreased to 9.17 nm. This indicates that TOS enhanced the structural density of cement materials. The crack about 103μm in the cracking specimens with 8 % TOS was almost healed, and the corresponding permeability was reduced 99.1 % after curing in oil. Adsorption and film formation of TOS can resist the cracking of cement sheath, and the oil swelling expansion of film in cement matrix can repair the cracked structure.

Intelligent Lost Circulation Monitoring Method Based on Data Augmentation and Temporal Models

Deep and offshore drilling operations face complex geological formations, uncertain formation pressures, and narrow safety density windows, making them susceptible to lost circulation risks. To address these challenges, this paper introduces an innovative, intelligent lost circulation monitoring model that incorporates geological lithology information. This model not only utilizes real-time drilling parameters, but also encodes geological information such as rock type as inputs to the model. By combining these key lithological features, the model can comprehensively assess wellbore stability and reduce the lost circulation risks. In this paper, the Conditional Tabular Generative adversarial network (CTGAN) model is used to enhance the data of small-sample risk data, which can effectively expand the data distribution space and improve the performance of the model. This paper conducts a comparative analysis of intelligent monitoring results using artificial neural networks (ANNs), long short-term memory (LSTM), and temporal convolutional networks (TCNs). The results show that the TCN achieves an identification accuracy of 93.7%. Furthermore, the analysis reveals that the inclusion of lithology information significantly enhances the model’s performance, resulting in a 7.1% increase in accuracy. The false alarm rate of the model can be reduced by 10.2%, considering the fluctuation of the logging curve caused by the on/off condition of the pump. This indicates that the introduction of lithology information and the condition of the pump on−off provide advantages in monitoring and identifying lost circulation risks, enabling a more precise assessment of wellbore stability and a reduction in lost circulation incidents. The method of lost circulation monitoring proposed in this paper provides an important safety guarantee for the oil drilling industry.

Modelling stellar irradiances I: the transition regions of FGKM stars

ABSTRACT We employed advanced ionization equilibrium models that we developed in Dufresne et al. (2024), which include charge transfer and density effects, to model UV stellar irradiances for a sample of stars. Our sample includes $\epsilon$ Eridani (K2 V), $\alpha$ Centauri A (G2 V), Procyon (F5 V), and Proxima Centauri (M5.5 Ve). We measured line fluxes from STIS data sets and used O iv and O v as density diagnostics to find the formation pressure of ions in the transition region (TR) and adopted a simple differential emission measure (DEM) modelling. Our findings indicate significant improvements in modelling spectral lines from anomalous ions such as Si iv, C iv, and N v of the Li- and Na-like sequences, which produce the strongest lines in the UV. For example, the Si iv lines were under-predicted by a factor of 5 and now are within 40 per cent the observed fluxes. The improved models allow us to obtain for the first time reliable estimates of some stellar chemical abundances in the TR. We compared our results with available photospheric abundances in the literature and found no evidence for the first ionization potential (FIP) effect in the TR of our stellar sample. Finally, we compared our results with the solar TR that can also be described by photospheric abundances.

Evaluation and Application of Wellbore Stability of Deep Oil Wells in the Southern Margin of Junggar Basin

The stability of the oil well wellbore is a prerequisite for selecting the optimal completion method. In this paper, based on experimental testing and theoretical models of rock mechanics parameters in deep oil reservoirs, the in situ stress parameters of deep oil wells are accurately predicted. On this basis, a full life cycle assessment model for wellbore and perforation casing stability was established, and the effects of pressure depletion and changes in the production pressure differential on wellbore stability and casing stability were analyzed. The research results indicate that as the formation pressure decreases, the critical collapse pressure difference around the wellbore significantly decreases. The greater the production pressure difference, the more likely the wellbore is to become unstable. Under the original formation pressure coefficient, if there is no casing, the critical failure pressure difference of the wellbore wall is 55 MPa. After cementing and perforation, when the casing is uniformly stressed and the formation pressure drops to a coefficient of 0.83, the casing will not be damaged even when the wellbore is completely emptied. At this time, there is still a certain safety production pressure difference in the perforated formation. This study can effectively guide the optimization of well completion and safe development in deep oil reservoirs.

Accumulation sequence and exploration domain of continental whole petroleum system in Sichuan Basin, SW China

Based on the oil and gas exploration in the Sichuan Basin, combined with data such as seismic, logging and geochemistry, the basic geological conditions, hydrocarbon types, hydrocarbon distribution characteristics, source- reservoir relationship and accumulation model of the Upper Triassic–Jurassic continental whole petroleum system in the basin are systematically analyzed. The continental whole petroleum system in the Sichuan Basin develops multiple sets of gas-bearing strata, forming a whole petroleum system centered on the Triassic Xujiahe Formation source rocks. The thick and high-quality source rocks in the Upper Triassic Xujiahe Formation provide sufficient gas source basis for the continental whole petroleum system in the basin. The development of conventional-unconventional reservoirs provides favorable space for hydrocarbon accumulation. The coupling of faults and sandbodies provides a high-quality transport system for gas migration. Source rocks and reservoirs are overlapped vertically, and there are obvious differences in sedimentary environment, reservoir lithology and physical properties, which lead to the orderly development of inner-source shale gas, near-source tight gas, and far-source tight–conventional gas in the Upper Triassic–Jurassic, from bottom to top. The orderly change of geological conditions such as burial depth, reservoir physical properties, formation pressure and hydrocarbon generation intensity in zones controlled the formation of the whole petroleum system consisting of structural gas reservoir in thrust zone, shale gas-tight gas reservoir in depression zone, tight gas reservoir in slope zone, and tight gas–conventional gas reservoir in uplift zone on the plane. Based on the theory and concept of the whole petroleum system, the continental shale gas and tight gas resources in the Sichuan Basin have great potential, especially in the central and western parts with abundant unconventional resources.

Wyznaczanie dynamicznego ciśnienia formacji w strefie odwiertu

The article shows that the pressure drop in the near-wellbore zone decreases with increasing time that the well is left uncased due to the filtration of the drilling fluid filtrate into the formation. Under certain conditions, this does not pose a risk of drill string sticking. From the perspective of establishing the nature of changes in dynamic reservoir pressure behind the mud cake, the experimental studies by Johnson and Klotz (Stepanov, 1999), which determine the amount of filtrate entering the reservoir under both static and dynamic conditions, are particularly interesting. It should be noted that establishing the amount of filtrate experimentally takes into account in advance the nonlinearity of fluid movement along the borehole wall and through formation rocks. Reservoir pressure will increase to the depth of penetration of the drilling fluid filtrate, so the value of Rk is taken equal to the radius of a certain contour with formation pressure. The article shows that the dynamic reservoir pressure behind the mud cake initially rises intensively over time, and then, after a certain point, remains almost constant; the filtrate from the drilling fluid entering the formation partially displaces the reservoir fluid and fills the resulting pore space. During dynamic filtration, an intensive increase in pressure behind the mud cake occurs within 20–30 hours and depends little on the absolute values of fluid loss from the washing liquid, the thickness of the mud cake, and the initial pressure drop. Experience in drilling deep wells shows that sticking of the lower part of the drill string primarily occurs when opening productive horizons with low permeability (0.06–2) · 10–15 m2. Consequently, the ratio of the permeability of the rock of deep-lying productive horizons to that of the mud cake is approximately more than 1,000. Therefore, when opening productive horizons, pressure equalization practically does not occur, and leaving the drill string against these rock formations without movement for 15–20 minutes leads to its sticking due to the pressure difference.

Characteristics of Effective Fractures in Deep Buried-Hill Basement Gas Reservoirs and Its Effects on Fluids: The Jianbei Slope, Qaidam Basin, China

Summary Buried hills are basement uplifts beneath sediment layers that possess significant exploration potential. Using the Jianbei Slope of the Qaidam Basin in China as a case study, we systematically investigated the types and origins of fractures in deep buried-hill gas reservoirs. In our study, we synthesized various data, including experimental results, production dynamics, and both conventional and special logging with the aim of clarifying the sequence and effectiveness of fracture formation in these gas reservoirs; analyzing the impact of effective fractures on fluid migration, accumulation, and preservation; and proposing a development plan to enhance stable production. Research reveals that since the Late Paleozoic, the region has been influenced by multiple phases of tectonic stress, deep fluid dissolution, and surface weathering leaching. This has resulted in a fracture system dominated by east-west trending deep major faults, with accompanying tectonic fractures, alongside dissolution, diagenetic, and weathering-collapse fractures. Smaller fractures oriented at an angle to the maximum principal stress and fractures with normal stress lower than the compressive strength are conducive to maintaining fracture effectiveness. Fracture widths range from 0.1 μm to 343.36 μm, with effective fractures comprising 63.49% of the total. Based on aperture and permeability, effective fractures are categorized into three levels: Level I fractures (>100 μm) serve as primary migration pathways; Level II fractures (10–100 μm) are well configured with dissolution pores, forming a foundation for favorable reservoir development; and Level III fractures (micron scale) enhance reservoir storage capacity by connecting fractures. The gas-water interface in the reservoir rises rapidly and unevenly. In the I + II + III fracture combination model, fluid exhibits high-conductivity channeling, leading to rapid declines in formation pressure, quick water breakthroughs in single wells, and severe water sealing. Conversely, in the II + III fracture combination model, fluid invasion is characterized by weak-to-strong finger-like intrusion, leading to prolonged stable production. Vertically, the 20-m to 60-m interval above the bedrock weathering crust has a favorable pore-fracture configuration, making it a high-quality reservoir zone in buried hills. In addition, local thick layers of Level II microfractures within the bedrock represent potential exploration targets. Considering the differential distribution of reservoir fractures, the optimal development plan is expected to achieve a recovery rate of 28.35% by 2030.

Hydrogen implantation in lanthanum thin films for ambient pressure hydride formation

Near room temperature superconductivity of metal superhydrides has been shown both theoretically and experimentally at high pressures (>100 GPa). Taking advantage of room temperature superconductivity for engineering applications requires decreasing the pressure of formation while retaining the superconducting hydride phase. We implanted lanthanum thin films with various doses of hydrogen ions at ambient pressure in order to form a lanthanum hydride phase. We found evidence for granular superconductivity below 5 K consistent with the phase coexistence of lanthanum hydride and lanthanum. As the H+ dose increased, TC decreased from 4.6 K to 3.2 K with broader superconducting transitions. Transmission electron microscopy showed increased substrate damage with increased ion dose and confirmed the granular structure of the films. Although a superhydride phase requires a higher H+ dose than what was attained in this work, we have demonstrated that ion implantation at ambient pressure is a feasible technique for superconducting lanthanum hydride formation.

CO2 high-pressure miscible flooding and storage technology and its application in Shengli Oilfield, China

There are various issues for CO2 flooding and storage in Shengli Oilfield, which are characterized by low light hydrocarbon content of oil and high miscible pressure, strong reservoir heterogeneity and low sweep efficiency, gas channeling and difficult whole-process control. Through laboratory experiments, technical research and field practice, the theory and technology of CO2 high pressure miscible flooding and storage are established. By increasing the formation pressure to 1.2 times the minimum miscible pressure, the miscibility of the medium-heavy components can be improved, the production percentage of oil in small pores can be increased, the displacing front developed evenly, and the swept volume expanded. Rapid high-pressure miscibility is realized through advanced pressure flooding and energy replenishment, and technologies of cascade water-alternating-gas (WAG), injection and production coupling and multistage chemical plugging are used for dynamic control of flow resistance, so as to obtain the optimum of oil recovery and CO2 storage factor. The research results have been applied to the Gao89-Fan142 in carbon capture, utilization and storage (CCUS) demonstration site, where the daily oil production of the block has increased from 254.6 t to 358.2 t, and the recovery degree is expected to increase by 11.6 percentage points in 15 years, providing theoretical and technical support for the large-scale development of CCUS.