To satisfy the requirements of cementing high-temperature sour gas wells,sodium triphosphate(STPP)was used to improve the performance of aluminate cement.In this study the effects of STPP's concentration on the performance of aluminate cement were evaluated,the influence of STPP on the corrosion resistance of aluminate cement was investigated,and the phase composition and micromorphology of the STPP set cement were analyzed.It was found that the incorporation of STPP in a cement slurry causes the it to have a longer thickening time and lower filter loss,but higher rheological readings.A modified aluminate cement treated with 10%STPP has its 7-day compressive strength that is 22.97%longer than that of a blank aluminate cement slurry sample.In a corrosion environment of 150℃and 21 MPa(partial pressure of CO2 is 80%)the cement slurry modified with 10%STPP has a 28-day compressive strength that is 67.73%higher than that of the blank cement slurry sample,and the permeability of the STPP cement slurry is reduced by 67.73%,indicating that STPP significantly improves the corrosion resistance of the aluminate cement at elevated temperatures.When STPP is incorporated into an aluminate cement,the PO43-ions it contains preferentially combine with Ca2+ions to form stable Ca10(PO4)6(OH)2,thereby inhibiting the corrosion process.The set cement formed by this cement slurry maintains tight pore structure after CO2 corrosion,indicating that the set cement has excellent corrosion resistance.The research results provide guidance for the design of well cementing materials for deep acidic environments.

Formulating oil-based drilling fluids (OBDFs) with an ultra-low oil-to-water ratio (OWR <= 60:40) presents a formidable stability challenge due to the maximized interfacial area and intensified stress on the interfacial film under high-temperature, high-density conditions. To address this, we engineered a synergistic stabilization system through molecular and colloidal design. A novel hyperbranched polyamide emulsifier (epoxidized soybean oil polyamide) (ESOP), synthesized from epoxidized soybean oil, exhibits superior thermal stability and interfacial activity due to its hyperbranched architecture. Combined with calcium petroleum sulfonate (CPS) and hydrophobic nanosilica (HNs), it enables a high-performance OBDF with an ultra-low OWR of 60:40. The results show that the optimized formula achieves an excellent demulsification voltage of 1290 V, an ultra-low HTHP fluid loss of 1.5 mL, a yield point of 12.9 Pa, and a superior sag factor (SF) of 0.504, outperforming both base and commercial systems. Mechanistic studies reveal a multiscale stabilization strategy involving a dense composite interfacial film, Pickering stabilization, a 3D network, and a unique thermally triggered self-reinforcement effect. This work not only provides a cost-effective OBDF formulation but, more importantly, establishes a molecular topology engineering paradigm for stabilizing complex industrial fluids under extreme conditions.

Conventional oil well cement fails to meet sealing demands in CO2 rich environments like carbon storage wells and sour gas reservoirs. While aluminate cement shows promise, its high-temperature curing performance is still insufficiently studied. This research comprehensively investigated phosphate-modified aluminate cement, analyzing mechanical properties, corrosion resistance, permeability, and microstructure before and after CO2 corrosion (CO2/N2 = 80%/20%,150 degrees C 21 MPa). Results showed the 10% SHMP-modified group exhibited a strong positive correlation between strength growth and curing time. After 28 days, its compressive strength increased by 97.2% versus unmodified cement. The modified cement activated a dual anti-corrosion mechanism, demonstrating 74.2%, 111.9%, and 89.1% higher corrosion resistance than controls at 7, 14, and 28 days, respectively. SHMP modification induced ion exchange reactions that transformed hydroxyapatite crystals into a lamellar, interwoven structure, maintaining permeability below 0.01 mD. The synergistic effect of physical filling and chemical bonding enhances the volume stability of cement, and provides a novel well cementing solution for environments containing carbon dioxide.

Magnesium oxychloride cement (MOC) is a promising acid soluble cementitious material for the downhole sealing of oil and gas well. However, its water resistance is poor under the temperature and pressure conditions of oil and gas well. In this paper, the evolution of compressive strength, permeability and microstructure was compared between air curing and simulated oil and gas well temperature and pressure conditions. The effect of different modified materials on improving the water resistance of MOC was evaluated. The results show that the decomposition of Phase 5 (5Mg(OH)2 center dot MgCl2 center dot 8 H2O) in MOC were significantly accelerated under the temperature and pressure curing conditions of oil and gas well compared with air curing, which leads to a significant decrease in compressive strength and an increase in permeability. All evaluated water-resistant modifiers can improve the water resistance of MOC to varying degrees. The most remarkable enhancement was achieved by potassium dihydrogen phosphate at the same dosage. The compressive strength retention ratio of the modified specimens at 28 days relative to that at 1 day was 91.59 %, and a 71.55 % relative increase was observed compared with the unmodified specimens. In addition, the permeability of the potassium dihydrogen phosphate modified specimens changed by only 6.68 % from 1 day to 28 days, and the 28 days permeability was reduced by 75.98 % compared with the unmodified specimens. This was attributed to the formation of an insoluble phosphate crystalline barrier on the surface of the Phase 5 crystals after the incorporation of potassium dihydrogen phosphate, by which the hydrolysis of Phase 5 was effectively inhibited and the deterioration of specimen performance was consequently retarded. These results provide a feasible method for improving the water resistance of MOC under the temperature and pressure conditions of oil and gas well.

Cellulose derivatives are widely used as key additives in water-based drilling fluids to regulate rheological properties and maintain system stability. In this study, CMC and PAC aqueous solutions with comparable initial rheological states were subjected to controlled CO2–thermal exposure at CO2 pressures of 0–1.0 MPa, temperatures of 80–120 ℃, and aging durations of 2–4 h. Post-aging rheological properties were evaluated at 25 °C using a rotational viscometer, and the effects of CO2 pressure, temperature, and aging time were quantified by response surface methodology. Dynamic light scattering, low-field nuclear magnetic resonance, microscopy, SEM–EDS, FTIR, and Congo-red-assisted UV–Vis spectroscopy were further employed to characterize the associated multiscale structural evolution. CO2 pressure showed the strongest influence on rheological retention, and increasing exposure severity resulted in decreases in apparent viscosity, yield point, and consistency coefficient, together with an increase in the flow behavior index. CMC exhibited pronounced broadening of the hydrodynamic size distribution and stronger changes in the water–polymer relaxation environment, whereas PAC retained a comparatively more stable dispersed structure. FTIR spectra showed no emergence or disappearance of major characteristic bands, suggesting that the rheological deterioration was dominated by changes in polymer conformation, aggregation, hydration, and intermolecular interactions rather than extensive chemical degradation of the cellulose backbone. These results reveal a multiscale association between structural evolution and post-aging rheological retention of cellulose derivatives under coupled CO2–thermal exposure.

A numerical heat transfer model for medium-deep U-shaped geothermal wells was developed, analyzing the effects of well configuration, build-up rate, boundary conditions, operatinal modes, and fluid types on thermal performance. The governing equations were discretized using the finite difference method, with validation against field data from Xr an. Results revealed that symmetrical U-shaped well achieve 5.5 % and 6.8 % higher heat extraction efficiency compared to left-deviated and right-deviated wells, attributable to the dual-section heat absorption mechanism. Maintaining the low build-up rate (1 degrees/30m) extended the contact duration with high-temperature rock formations, thereby elevating heat extraction rate to 2.11 MW. Comparative analysis demonstrated that heat transfer boundary conditions yield a 2.6 % power advantage over adiabatic boundary condition during 20-year operations. Compared to the continuous operation mode (Case 1), the intermittent operation mode (Case 2) reduced heat accumulation through cyclic heat recovery, resulting in a 3.55 degrees C increase in outlet temperature after 7 days of residential heating. During intermittent operation mode, wellbore wall and fluid temperatures exhibited periodic sawtooth fluctuations, where heat recovery strength correlated with building heating mode. The study elucidates multi-scenario simulation analysis for medium-deep U-shaped geothermal wells, providing theoretical foundations and design strategies for efficient medium-deep geothermal resource exploitation.

In the oil and gas wells with high-temperature and acidic gas environments, it prone to corrode oil well cement, causing deterioration performance and damaging the cement sheath. At the same time, the active bottomhole gas has higher requirement for the anti gas channeling. In order to develop a the oil well cement slurry resistant to corrosion and gas channeling for high-temperature oil and gas well, the key materials of cement slurry were studied, and a high-temperature oil well cement slurry resistant to corrosion and gas channeling was designed. The performances of the cement slurry were studied. The experimental results show that the designed high-temperature anti-corrosion agent and anti gas channeling agent can effectively improve the ability to resist corrosion and gas channeling at high temperatures, significantly reduce the corrosion depth, and shorten the development time of static gel strength. Multi-scale silicon powder as a high-temperature stabilizer can improve the mechanical performance stability of cement paste at high temperatures. The high-temperature anti-corrosion and anti channeling cement slurry system the additive materials studied has good rheological properties, high stability, no free liquid, less 50 mL water loss, adjustable thickening time, and meets the requirements of cementing operations. At the temperature of 180 ℃, the mechanical properties are stable and with strong anti-corrosion ability. The corrosion depth is less than 2 mm, and the development time of static gel strength is within 20 min. The microstructure analysis results indicate that the micro morphology of cement paste is dense and maintains good integrity even after corrosion. This research achievement can provide technical support for preventing gas channeling and cementing operations in deep oil and gas wells with acidic gas.

Pressure activated sealant (PAS) has been proven safety and efficiency for quick leak repairs in oil & gas production, due to the unique in-situ self-adaptive sealing property. However, its sealing mechanim of the liquid-tosolid transformation under leak pressures remains poorly understood to date. Elucidating the sealing mechanism of PAS is critical for designing and developing a new generation of wellbore sealing repair technology. In the present work, we conducted a pioneering investigtion that integrated experimental techniques with numerical simulations, to systematically explore the in-situ self-adaptive sealing performance of PAS in leaks. Firstly, latex deposition experiments were carried out to fabricate PAS from carboxylated acrylonitrile butadiene rubber latex (XNBRL), and then the physicochemical features of the XNBRL-based PAS, including chemical composition and microsctructure, were typically characterized using FTIR and SEM techniques. Subsequently, the micro-leak sealing capability of XNBRL-based PAS was evaluated under 20 MPa. The results showed that the fabriacted PAS is a type of multiphase fluid, wherein disperse phase are of regular spherical shape with an average size of 239.75 mu m. The disperse phase are essentially compound droplets with material interfaces, exhibiting unique interfacial mechnical and chemical properties in the surrounding flow. PAS demonstrated excellent pressureactivated sealing performance towards crack and screw leaks, and solid barriers can be rapidly formed to fill micro-leaks in 500s under 16 MPa. Considering the microstructural and dynamic features of compound droplets, a mechanical-chemical coupling model was proposed to explain the activation and agglomeration process of liquid sealant at leak. In the jet flow field caused by differential pressures, the self-adaptive sealing process of PAS consists of four stages: (1) the impact deformation of compound droplets in jet flow, (2) compound droplets activated by breakup of hydrated membrane, (3) adhesion and agglomeration of activated compound droplets, and (4) self-adaptive solidification of deformed drolpets to fill and block leakages. Finally, three-dimensional (3D) numerical simulations were empolyed to investigate dynamic deformation of compound droplet in the pressure differential flow, to rationalize liquid-to-solid transformation of PAS. The numerical results showed that dynamic motion of compound droplet in jet flow field includes deformation of compound droplet, breakup of outer hydrated membrane, and collision of inner polymer core with wall. The hydrated membrane completely breaks up into ligaments in 0.8 ms, facilitating exposure of activated inner core and enables further chemical agglomeration, which agrees generally well with the experimental and model analyses.

Summary 3D bulk polymer, as an alternative to linear polymer, has exhibited large potential in formulating high-performance water-based drilling fluids. Understanding the mechanism behind the enhanced rheological stability of drilling fluids by microspherical polymers is critical for designing and developing new high-performance drilling fluids. In this work, we conducted a pioneering investigation that integrated experimental techniques with computational modeling, to explore the enhancement mechanism involved in the targeted drilling fluids. Inverse emulsion polymerization experiments were first carried out to fabricate the microspherical polymer acrylic acid (AA), acrylamide (AM), and 2-acryloylamino-2-methyl-1-propanesulfonic acid [P(AA-AM-AMPS)], and then physicochemical properties of microspherical polymer were characterized. Subsequently, the performance of drilling fluids with microspherical polymer as an additive was systematically evaluated. Finally, molecular simulations were used to investigate the characteristics of chemical active sites, molecular conformation, and structural variation at various temperatures. The results showed that the final microspherical polymer has a core-shell structure, with an average size of 198.3 nm and a molecular weight of 6.2×106 g/mol. The 3D structure exhibits good thermal stability, and thermal decomposition occurs above 220°C. The drilling fluids formulated with the microspherical polymer showed better rheological stability in the medium-low (4–65°C) and medium-ultrahigh (40–240°C) temperature ranges, compared with the relevant drilling fluids with the parallel linear polymer. Analyses on electrostatic potentials (ESPs) and frontier molecular orbital (FMO) revealed that active groups within the confined sphere domain mainly include carbonyl C = O and amide -CO(NH2). Additionally, these active groups exhibit a hierarchical distribution in the outer molecular region. Analyses on the radius of gyration (Rg) and the radial distribution function g(r) further validated the core-shell structure of microspherical polymer and its temperature-resistant stability. Moreover, a new self-consistent structural compensation model was proposed to rationalize the structure-activity relationship of microspherical polymer in drilling fluids. The computational results align well with the experimental findings. This pioneering work will provide valuable information for both the synthesis of new functional additives and the formulation of tailored-performance drilling fluids.

This article aims to enhance the toughness performance of oil well cement with an optimized mixing ratio of three different lengths of carbon fibers optimized by response surface methodology. A response surface model was constructed with the impact strength as the response target based on the Box–Behnken design. The influence of carbon fiber mixtures on the impact strength of oil well cement was studied, and the ratio of mixed carbon fibers was optimized. The optimized cement slurry performance was tested, and the microstructure of the cement was analyzed. The results show that the impact strength of cement is significantly influenced by 3 mm carbon fiber and the interaction effect of 1 mm carbon fiber and 3 mm carbon fiber. The optimal mixing ratio of carbon fibers of different scales obtained through optimization is 0.322

Pore Pressure abrupt change (PPAC), encompassing pore pressure surge (PPS) and pore pressure reversal (PPR), are prevalent phenomena in ultra-deep formation of East China Sea Shelf Basin (ECSSB). To address this, the pore pressure distributions in the ECSSB are characterized in detail, utilizing measured pressures, mud weights, and logging responses. The genesis mechanism of PPS and PPR in ultra-deep formations is investigated. Finally, the significance of unveiling the genesis mechanisms behind PPACs to pore pressure prediction is discussed. The results indicate that the pore pressure in the ultra-deep formation is complex and variable, with the middle pressure rapidly rising to 1.8 and the lower formation reversing to 1.0, characterized by a reducing return trend. The primary cause of these PPACs is identified as the significant variation in overpressure mechanisms and lithological characteristics across different layer. Hydrocarbon generation serves as the primary mechanism for pressure formation leading to a surge, followed by pressure transfer. Furthermore, a multi-source and multi-mechanism pore pressure prediction model suitable for ultra-deep PPAC formation is established. It takes into account the influence of multiple factors such as composite overpressure mechanism, complex lithology, rock mechanical properties, rock conduction properties and rock volume properties. The results demonstrate that this novel model exhibits good applicability and reliability, with the prediction error margin controlled below 5.00

This study evaluated the effects of nano-silica and bentonite concentrations on drilling fluid rheology and filtration loss performance and studied the effect of nano-silica on shale’s swelling performance and dispersion performance to evaluate the enhancement effect of nano-silica on drilling fluid performance. The experimental results show that nano-silica has a negligible impact on rheology, which leads to a slight increase in plastic viscosity and a slight decrease in yield value. 0.8

In response to the challenge of carbon dioxide (CO2) corrosion of oil well cement in high-temperature environments, the effect of micron diabase powder on the resistance of oil well cement to corrosion was studied. By simulating the simultaneous presence of high-temperature and CO2, the effect of adding micron diabase powder on the corrosion resistance of oil well cement was evaluated, and the mechanism by which oil well cement was affected was analyzed. The results showed that the addition of micron diabase powder significantly improved the compressive strength of oil well cement while reducing the permeability and corrosion degree of the samples. After 21 days of corrosion under 120 degrees C and 30 MPa (CO2 partial pressure of 21 MPa), the compressive strength of cement containing 15 wt% diabase powder (Z3) increased by 53.93 %, and the permeability decreased by 58.84 % compared to the blank sample (Z0), while the corrosion degree of cement sample is 15.09 %. The addition of micron diabase powder promotes the formation of tobermorite after hydration of oil well cement at high temperatures, reducing the content of alpha-dicalcium silicate hydrate (alpha-C2SH). At the same time, the main components in micron diabase powder make the structure of oil well cement denser after hydration, thus exhibiting higher resistance to CO2 corrosion in high-temperature acidic gas environments. This study provides a new perspective for the development of cementing materials to improve the corrosion resistance of oil well cement.

Comprehensively considering the impact of properties of drilling fluid at high temperature and high pressure (HTHP), drill string eccentricity, rotation, and rock breaking of drill bit on the annular temperature profile, transient temperature variations were predicted by using a wellbore heat transfer model. The model was numerically solved using the finite difference method. Compared to DRILLBENCH simulations, the predicted model was more consistent with the field-measured data. The calculations revealed that comprehensively considering various heat source factors made the annular temperature closer to the actual wellbore value, with a temperature difference of up to 10.66 degrees C. When considering variations of properties of drilling fluid at HTHP, the lower section of the annulus showed a significant decrease in temperature with depth, with a bottom-hole temperature difference of 5.4 degrees C. The bottom-hole temperature decreased by about 2.6 degrees C from concentric to eccentric drill string, and the pressure difference was about 1 MPa. Compared to drill string eccentricity, rotation and rock breaking of drill bit had a greater impact on annular temperature, with bottom-hole temperature differences of 13 degrees C and 22 degrees C, respectively. Accurate temperature modeling can better understand and predict the variation patterns of wellbore temperature, providing important guidance for the development of deepwater drilling.

Magnesium oxysulfide cement (MOS) has excellent acid solubility properties and can be used for severe loss plugging in oil and gas wells. However, the solidification time of MOS cement is fast, making it difficult to be used in the geological environment of oil and gas wells. The MOS suitable for construction operation in oil and gas wells under a temperature of 60 degrees C was studied by optimizing the raw material ratio and modification. The influence of MgO/MgSO4 and H2O/MgSO4 mole ratios on the compressive strength of MOS was studied by a single-factor experiment. The response surface methodology (RSM) was used to optimize the raw material ratio. The sodium hexametaphosphate (SHMP) was applied to adjust the thickening time of MOS, and its effect on MOS was studied. The microstructure and phase composition of different MOS were analyzed. The results show that under hydrothermal conditions at 60 degrees C, the optimal mole ratio of MgO: MgSO4: H2O of MOS is 11.39:1:19.26, and the 24-hour compressive strength of MOS is 12.89 MPa. The thickening time of MOS was extended by 100 min, and the compressive strength increased by 25.26% in 72 h with 6 wt% SHMP at 60 degrees C. The SHMP-modified MOS has high compressive strength and a longer thickening time, and its strength develops steadily with time. The short rod-shaped 517 phase connected in MOS is beneficial for improving the strength. SHMP can regulate the stability of MOS, promote the formation of the 517 phase, and improve the strength of MOS. The research results support the application of magnesium oxysulfide cement in oil and gas wells.

To reduce drilling fluid damage, an oligomeric chelating agent DTPA-J was obtained by modifying DTPA with 1,3-dichloropropane to improve the solubility of barite, which was a non-toxic reagent and met environmental requirements. DTPA-J was chosen for the system of removal of chelating substances from the point of view of its corrosion, biotoxicity and dissolution of barite. The system consisted of a catalyst, a transforming agent and a glue breaker, which had a high efficiency of dissolving barite mud cake in a water-based drilling fluid, and the rate of weight loss of the mud cake exceeded 90%. In addition, the chelation removal system dissolved the additives pressed into the pores of the core, which can significantly improve the efficiency of restoring the permeability of the contaminated core. The application of the chelation removal system is of great importance for reservoir protection and subsequent oil and gas production, which can reduce requirements for the effectiveness of reservoir protection with water-based drilling fluids.

Oil well cement is a necessary sealing material for carbon dioxide storage wells and oil and gas wells containing carbon dioxide, but it is easily corroded by carbon dioxide fluids. Due to the lack of unified corrosion research methods in oil well cement, it is impossible to compare and analyze different technologies, which hinders the progress of anti-corrosion oil well cement slurry. This article focuses on the entire process of corrosion experiment of oil well cement and analyzes the research methods for oil well cement corroded by carbon dioxide from three aspects: experimental methods, evaluation methods, and mechanism analysis methods. For corrosion experimental methods, cylindrical cement specimens and longer curing time before corrosion are more conducive to conducting experiments. Carbon dioxide saturated solution is the environment where most oil well cement is corroded. Static corrosion experiments may have better stability than dynamic experiments. There is still room for improvement in the experimental equipment. For the corrosion evaluation methods, the corrosion depth (or corrosion area), compressive strength, porosity and permeability can all reflect the degree of corrosion of oil well cement. However, there is no complete correspondence between the corrosion depth and compressive strength, and there is no unified conclusion on the change of permeability with the impact of corrosion. For the mechanism analysis methods, it is necessary to combine two or more analysis methods from scanning electron microscope (SEM)/energy spectrum analysis (EDS), X-ray diffraction (XRD), thermogravimetric analysis (TGA) and solution composition analysis to analyze the corrosion process of cement paste more accurately. The conditions for curing before corrosion, the influencing factors of dynamic corrosion, more secure and intelligent experimental equipment, more reliable evaluation indicators, and more advanced mechanism analysis methods need to be further studied. The overview of research methods is conducive to accelerating the progress of anti-corrosion oil well cement technology.

As oil and gas exploration and development gradually shift towards the “double depth and double high” domain characterized by deep water, deep depth, high temperature, and high pressure, downhole electronic equipment faces the threat of high-temperature failure. Based on wellbore heat transfer model and non-dominated sorting genetic algorithm, the study investigates the extent to which drilling parameters affect downhole temperature and establishes a multi-objective parameter optimization model for downhole cooling. And the following research results are obtained. Firstly, adjustable drilling parameters for downhole temperature regulation include inlet temperature, pump rate, and rotation velocity. Secondly, the sensitivity analysis of downhole temperature parameters shows that cooling capacity is in a reverse relation with formation fracture pressure, which is the direct reason for the adoption of multi-objective optimization. Thirdly, through multi-objective optimization and decision integration, the optimal combination of operational parameters for downhole cooling was determined: inlet temperature of 16.87 ℃, pump rate of 14.84 L/s, and rotation velocity of 49.35 rpm, resulting in an optimized bottomhole temperature of 133.18 ℃. In conclusion, the concept of multi-objective optimization is feasible and applicable to downhole cooling. It provides a reference for the efficient development and utilization of deepwater drilling, aids in the design and construction optimization of high-temperature, high-pressure wells, and helps prevent downhole tool failures.

With the development of oil drilling technology and equipment, oil exploration is moving towards deep water high temperature and high pressure (HTHP) formations. However, deepwater drilling operations often encounter problems such as shallow gas, narrow formation pressure windows, and long non-productive time. As a new drilling method, managed pressure drilling (MPD) technology has been applied in deepwater drilling fields after upgrading conventional drilling equipment and construction technology. This study describes the technical characteristics of MPD operations, draws conclusions about several variants of MPD and their applications, and compares different states of equivalent circulating density (ECD) and bottom-hole pressure in conventional drilling and MPD. Early gas kick detection (EGKD) is at the core of the drilling safety issues. This paper summarizes the EGKD methods, which are classified into two categories: conventional gas kick detection and unconventional gas kick detection. The two major categories are systematically reviewed. The review of the existing literature shows that for conventional gas kick detection the sensitivity of mud pit gain ranges from 2.79 to 8.18 bbl, the accuracy of delta-flow measurements ranges between 25 and 50 gpm. Combining the MPD technology, we put forward a downhole condition identification model based on the physical mechanism neural network (PMNN) algorithm. In addition, it is difficult for drilling to accurately describe wellbore fluid flow by relying on forward modeling, and quantitative interpretation and analysis of downhole parameters need to be further realized. Moreover, conventional single-measurement point data cannot precisely reflect and explain the change of downhole parameters, thus combining the forward modeling, a multi-measurement point and multi-parameter inversion (MPMPI) method within the intelligent drill pipe technology is proposed. Finally, this paper summarizes the automatic control technology of MPD using nonlinear model predictive controllers (NMPC) algorithms for real-time intelligent optimization and decision-making.

A corrosion prediction model was established based on the genetic algorithm (GA) and back propagation (BP) neural network to predict the long-term corrosion changes of oil well cement, Considering that the cement sheath is susceptible to corrosion and its corrosion degree is not easy to observe in acid gas wells and geological storage wells containing carbon dioxide (CO2). The initial weights and thresholds of the neural network were optimized by GA. The number of hidden layer nodes was selected by error verification, and the network was trained with an improved algorithm. The sample data was regression processed based on the empirical formula and was used in the network training. The simulation results shows that: The improved GA-BP network model (3-5-6-1) has a higher prediction accuracy with faster convergence and better fitting effect compared with the traditional BP neural network and the regression model (REG) in long-term prediction of corrosion depth in oil well cement. The regression coefficient (R2) of the prediction model is 0.9913, and the mean square error (MSE) of test samples is 0.0026. The modeling idea proposed in this paper can be applied to improve the accuracy of prediction models in predicting the corrosion of oil well cement.