The tie-back cement sheath is an important to isolate formation fluids in ultra-deep gas wells. To address the leakage caused by micro annulus and the quantitative evaluation methods, this study establishes a full-well characterization approach for microannulus by integrating mechanical analysis with finite element simulation. A quantitative evaluation method is developed for leakage severity based on equivalent permeability and the influence of prestress on microannulus is analyzed. Furthermore, a assessment method for cement sheath leakage is proposed by linking leakage pressure differentials with the total breakthrough pressure. The results indicate that the extreme values of wellbore pressure are the primary drivers of micro annulus initiation. Both microannulus size and equivalent permeability increase with depth and exhibit nonuniform distribution. In the case study well, the maximum equivalent permeability of the cement sheath reaches 26.93 mD, forming a channel for high-pressure fluid migration. Prestress cementing reduces the size of microannuli. The quantified relationship between total breakthrough pressure and leakage pressure differential challenges the conventional assumption that "microannulus formation directly implies leakage," providing a more reliable basis for leakage control. However, further work is required to resolve the key bottleneck of quantitatively characterizing breakthrough pressure gradient.

Thermal insulation is necessary for deepwater wells to achieve safe and effective production. Based on the comparison of different thermal insulation measures and the control requirements, this paper proposes two indicators to analyze thermal insulation performance. A model is established by considering the wellbore radial thermal resistance and wellbore-formation heat transfer process in order to calculate the two indicators. The analysis shows that there exists an overlapping effective range between vacuum-insulated tubing and insulation-coated tubing, and a similar overlap is observed between insulating liquid and insulated tubing. When comparable insulation performance can be achieved, insulating liquid should be prioritized, while vacuum-insulated tubing should be considered only as the final option. Under high production or a high geothermal gradient, annular temperature change is the primary control objective, whereas under low-production or low-temperature conditions, wellhead temperature becomes the dominant control target. The combination of insulated tubing and insulating liquid exhibits pronounced synergistic effects. In the case of a well under high-temperature and high-production conditions, the composite insulation reduces annular temperature change by 64.26%, and in low-temperature, low-production wells, it increases wellhead temperature by 100.43%. In practical applications, insulating fluids should be preferred, with insulated tubing employed as a supplementary measure.

Accurate productivity forecasting plays a vital role in ensuring the efficient and economical exploitation of gas hydrate reservoirs. This work proposes a modified inflow performance relationship (IPR) model tailored for the rapid prediction of Class I gas hydrate production behavior under vertical well and depressurization development strategies. The formulation of the revised IPR model is grounded in insights obtained from numerical simulations of production dynamics. Owing to its alignment with the typical IPR curve patterns and distinct production stages, the Fetkovich equation was selected as the core framework, with the late‐time slow decline stage omitted due to its marginal contribution to overall output. To enhance prediction accuracy, the conventional use of reservoir pressure was replaced by an effective average reservoir pressure, characterized through an energy coefficient denoted as B i . Sensitivity analyses revealed that this coefficient is primarily influenced by the initial formation pressure and temperature. By leveraging the phase equilibrium relationship between these two parameters, a fitted expression linking B i to temperature was derived based on orthogonal experimental results. Comparative evaluation against numerical simulation outputs indicates that the revised IPR model yields a mean relative error of 4.20%, significantly outperforming the original model’s 18.25% error. With its computational efficiency and practical applicability, the improved IPR formula provides a robust analytical alternative for productivity estimation in Class I gas hydrate systems developed via depressurization and vertical wells.

Trapped annular pressure is among the primary well integrity risks for deepwater wells, particularly under high-temperature and high-production-rate conditions. The application of thermally insulated fluid to mitigate trapped annular pressure offers the advantages of low cost and convenient operation, yet its applicability still requires systematic evaluation. To investigate the mitigation effect, this paper establishes a model by coupling radial heat transfer between the wellbore and surrounding formations based on annular volume compatibility. The model is mainly composed of two modules: temperature calculation and pressure calculation. A segmented iterative algorithm is adopted to solve the model, which enables quantitative analysis of the variation law under different conditions. Via the proposed model, this paper analyzes the influences of thermal conductivity, production rate, production time and geothermal gradient on trapped annular pressure. The results indicate that thermally insulated fluid can effectively reduce trapped annular pressure, and the mitigation effect becomes more significant as thermal conductivity decreases. Among different injection schemes, the optimal control performance is achieved when thermally insulated fluid is injected into the A annulus. Compared with conventional annular fluids, the B-annular pressure decreases from 50.71 MPa to 21.52 MPa when the thermal conductivity of thermally insulated fluid is reduced to 0.1 W/(m·°C). Thermally insulated fluid still maintains effectiveness under high-temperature and high-production-rate conditions, and its thermal conductivity should preferably be controlled below 0.15 W/(m·°C). Combined thermal insulation measures are recommended for long-term production under high production rate and high temperature. The maximum allowable annular pressure should be determined based on the strength of the C annulus, so as to provide a design criterion for the thermal insulation design.

ABSTRACT Class Ⅰ gas hydrate deposits are regarded as the most promising type for commercial development due to the underlying free gas layer, and they offer a relatively cheap and safe method for developing gas hydrates using a vertical well and depressurization. Therefore, this paper studies the production characteristics of Class Ⅰ gas hydrate deposits developed by vertical wells and depressurization, to provide a basis for productivity prediction and stimulation. On the basis of the gas production rate, a method is proposed to stage the gas production process. And then a new index is built to evaluate the gas hydrate contribution to gas production in different stages and analyze the influencing factors. The research shows that the gas production rate and decomposition gas decrease with time. The contribution of gas hydrate decomposition to gas production cannot be ignored. The gas and water saturations in the hydrate layer increase over time, while the hydrate saturation decreases. Deposit energy is rapidly consumed during the early production stage, which is one reason for the low gas production rate in the later stage. The production process can be divided into two stages according to the relationship between the gas production rate and the decomposition gas rate. The ratio of cumulative decomposition gas to cumulative gas production can be used to evaluate the contribution of the gas hydrate layer. The contribution ratio of gas hydrate is over 1 in Stage Two because the decomposition gas not only directly contributes to gas production but also sustains it by replenishing the deposit energy. High gas saturation reduces cumulative gas production due to the low effective permeability of the hydrate layer; therefore, heat or fracture stimulation can be used to enhance productivity. The gas production rate and cumulative gas production increase with the gas layer thickness. An increase in deposit energy can enhance productivity by accelerating hydrate decomposition in Stage One. Lower production pressure can promote gas production. To release productivity, production pressure can be kept as low as possible in Stage One, and methods for supplementing deposit energy can be considered in Stage Two.

Carbonate reservoirs are one important type of reservoirs in the Middle East, mainly composed of marine porous deposit. Rich gas flooding can further improve the injectivity and the recovery factor in carbonate reservoirs. Therefore, a numerical simulation model considering fluid distribution characteristics is established to clarify the reservoir fluid distribution characteristic after rich gas injection. Then the gas component at different production times and different areas are analyzed. The tracer method is used to mark the various components of injected gas, accurately reflecting the distribution characteristics of injected gas in the reservoir. Based on the coupling effect of reservoir fluid components and injected gas components, the Minimum mixing pressure (MMP) during rich gas flooding process is characterized. The simulation results show that the distribution characteristics of injected hydrocarbon gas in the reservoir are related to the proportion of components in the injected gas. A large number of injected rich gas mainly gather at the root of the horizontal injectors. This can increase the recovery factor of surrounding area and also bring high earlier gas breakthrough risk. After rich gas flooding, the overall composition of the reservoir liquid phase shows a trend of increasing intermediate hydrocarbon components. The reservoir fluid is enriched, and the change degree gradually decreases along the direction from injection wells to production wells. Due to the high output of light hydrocarbon components after rich gas injection, the proportion of heavy hydrocarbon components will increased also. The line analytical method results show the mixed fluid during rich gas flooding is mainly caused by vaporizing gas multiple-contact miscible process. The MMP pressure rises and exceeds the reservoir pressure, which cannot meet the miscibility requirements and presents a non miscibility state.

It is one of the most feasible ways for the development of gas hydrate by vertical well and depressurization. In order to compare and analyze the characteristics and performance of gas hydrate with different geological structures developed by vertical well and depressurization, a hydrate development geological model based on Tough + Hydrate is established. The laws of gas and water production in the long-term development are studied. The analysis shows that the initial gas production rate of Class I hydrate is high, and then decreases. The cumulative gas production is significantly higher than that of other types of hydrate. It has the characteristics of high cumulative gas production and low water production. Good economic benefits can be obtained by depressurization production in vertical wells. The gas production rate of Class II hydrate and Class III hydrate increases first and then decreases. The production capacity is lower than that of Class I hydrate. Class II hydrate has serious water production problem, and its production capacity is the lowest. Therefore, Class II gas hydrate needs to solve the problem of water production. Class III gas hydrate can release production capacity through well pattern optimization or increasing reservoir contact area.

Sustained annular pressure (SAP) is a primary indicator and hazard of wellbore integrity failure, commonly observed in deep oil and gas wells, gas storage injection/production wells, CCUS wells, and shale gas horizontal wells. The wellbores with SAP are faced with significant well control risks, primarily manifested as high-pressure fluid leakage, secondary risks during well interventions, and challenges in post-event remediation. To handle these risks, advancements have been made in barrier enhancement and pressure management technologies, annular pressure detection and identification techniques, and safety control strategies. These developments enable scientific prevention, real-time monitoring, quantitative detection, and effective control of SCP. However, gaps remain in the integration of simulation, evaluation, and control capabilities within industrial simulation software for SCP scenarios. Challenges also persist in sealing wellbore leaks, including high injection difficulty, low pressure-bearing capacity, and unsatisfactory remediation outcomes. It is recommended to develop industrial simulation software, innovate new materials, techniques, and equipment, and conduct scientific evaluations of SCP wellbore service safety. These efforts aim to overcome wellbore leakage management challenges under various engineering contexts.

Casing damage is one of the most challenging engineering issues in deep gas wells, leading to significant economic losses and severe incidents such as gas leaks or high annular pressure. According to field data analysis, in addition to traditional factors like stress, temperature, or corrosion, cement sheath quality also impacts casing damage. Hence, this paper establishes a three-dimensional finite element model for casing-cement sheath -formation considering cement sheath quality. It discusses the impact of different cement sheath defects (such as void and eccentricity) on casing stress distribution under the influence of in-situ stresses, high-pressure fluids, and annular pressure. The analysis reveals that under adverse conditions, poor cement sheath quality exacerbates stress on the casing, increasing the risk of casing failure, with the degree of impact being cement void angle > cement eccentricity > cement void thickness. Based on this, a nonlinear fitting of changes in casing equivalent stress is conducted to establish a model for calculating casing external loads under cement void or eccentricity conditions. Considering the dual uncertainty of casing external load and strength parameters, a casing reliability evaluation method is established based on the external load calculation model and stress-strength interference theory. The reliability of casing strength is assessed and analyzed using a practical well in an oil field as an example. The results indicate that compared to traditional safety factor methods, the reliability evaluation method established in this paper can more intuitively and accurately display variations in casing reliability, offering a scientific basis for optimized design solutions. Optimizing cement sheath performance (such as reduced cement elastic modulus and Poisson's ratio) and enhancing cementing quality (by preventing cement voids and eccentricity) effectively reduce the risk of casing failure.

Leakage is one of the most serious challenges for the safe production of high-pressure gas wells for its high risks, including abnormal annular pressure, natural gas accumulation, and environment pollution, but available methods can hardly accurately measure the leakage type and depth, which are the key parameters for the rigless leakage repair and risk assessment. Therefore, this paper proposes a method to measure the leakage based on the characteristics, which combines qualitative and quantitative measurement together. Qualitative measurement considers the annular pressure, tubing pressure, liquid level, cement quality, and workover history. Quantitative measurement is determined by noise logging, electromagnetic logging, pressure logging, and temperature logging. The logging should be optimized according to the qualitative measurement. The method was successfully applied in high-pressure gas well belonging to Tarim Oilfield. Two potential leakage types are provided based on the annular pressure, liquid level, cement quality, and workover history, including tubing leakage and linger hanger leakage. Based on the potential leakage types, the pressure difference, logging devices string, stopping length, and time are optimized to make the engineering logging reliable. Through measurement, two leakage points are found in tubing string. One is tubing body crack at the depth of 2724 m and the other is tubing thread leakage at the depth of 5211.7 m, which well matches the production data. Method to measure the wellbore leakage in high-pressure gas well.image

The existence of solid hydrate in porous media always greatly reduces the relative permeability, which limits the development of hydrate reservoirs. Therefore, to recover the gas, it is necessary to carry out reservoir reconstruction measures that induce fractures around the production wells to increase the gas production of hydrate reservoirs. At present, there is limited quantitative research on the promotion of gas production by induced fractures in hydrate reservoirs. In this paper, numerical models of Class Ⅲ hydrate reservoirs with induced fractures are established. By comparing the gas production with and without induced fractures, the effectiveness of induced fractures in promoting the depressurization production of natural gas hydrates is verified. An index of improved efficiency is established and calculated to measure the promotion effect of induced fractures during the fracture promotion stage. The multiple regression calculation formulas of improved efficiency with reservoir geological parameters are obtained by integrating nonlinear regression and linear regression. The calculation model is helpful to quickly and directly measure the rationality and economy of the induced fracture depressurization method to promote hydrate development.

Thermal-insulated liquid and nitrogen gas are two common methods to control the trapped annular pressure caused by the temperature–pressure effect, but few researches analyzed the control performance of these two measures applied in the deep gas well. Therefore, this paper builds a model to compare the control performance and a safety factor is proposed to evaluate the control performance when the tubing is totally blocked. The results indicate that the tubing-casing annulus temperature difference creates the conditions for the trapped annular pressure. Only when the production rate exceeds a certain value, can the thermal-insulated liquid reduce the trapped annular pressure. The nitrogen gas can achieve good control performance after the nitrogen gas volume exceeds 0.03 regardless of the production time and the production rate. To avoid the tubing collapse risk, the annular pressure should be controlled under the critical value. However, the thermal-insulated liquid is not able to reduce the annular pressure to the critical value. The nitrogen gas can prevent tubing collapse under different liquid densities by suitable volume. Therefore, the nitrogen gas is recommend.

The objectives are to demonstrate design, selection and maturation of new Dispersed Particle Gel (DPG) particles for water production management and EOR in giant carbonate reservoirs. DPG technologies have been applied in conventional mature reservoirs, but the challenges addressed here are high temperature, high salinity, deep, heterogeneous carbonate reservoirs. A systematic approach was developed and implemented taking the technology from screening, laboratory tests to field piloting. Existing technologies were reviewed. DPG technology was selected based on our successful applications in mature reservoirs in China. An extensive DPG design study was performed to best match DPG chemical make-up, size, performance parameters against expected carbonate reservoir heterogeneity and harsh conditions. Candidate DPGs were taken to extended laboratory tests to ensure compatibility. Two best performing candidates were studied by dedicated analytical models and detailed compositional sector models. Large scale deployment was assessed. Based on favourable deployment economics, field pilot candidates were ranked and selected, and high level design is completed. The Onshore Abu Dhabi carbonate reservoirs have relatively long production history, with water breakthrough seen in certain areas. For delaying/arresting water-cut increase and EOR targeting low permeability poorly flooded areas, linked polymer solution (LPS), colloidal dispersion gel (CDG) and pre-preparation particle gels (PPG) are not suitable due to high reservoir temperature and salinity. Polymer microspheres are difficult to control. DPG was selected, composed of functional polymer and different cross-linkers (PEI, FL103, HEX-RE, and PY accelerator). Extensive laboratory tests were performed with reservoir cores, covering DPG viscosity shear properties, thermal/pressure/salinity stability and injection performances. The final DPG candidates have wide distribution of sizes, low viscosity, shear resistance, excellent self-growth and coalescence ability, compatibility up to 150 oC and salinity 300,000 ppm. Significantly, technologies were tested successfully for DPG production, on-site preparation and injection. Based on dedicated analytical models and fine scale compositional model simulation, potential field pilots were studied using laboratory measurements as input. Uncertainty analysis were performed. Project economics for potential large scale deployment were generated based on a range of DPG performances, and are competitive. High level Pilot design is completed with multi pilot candidates. Although DPG technology has been applied in conventional mature reservoirs, this paper shares the work performed advancing the technology to the combined extremely high temperature (up to 150 oC) and high salinity (up to 300,000 ppm) heterogeneous carbonate reservoirs. It represents a world first for such applications. A comprehensive approach was adopted: from existing field applications to extensive theoretical analysis and accelerated laboratory tests, field operational considerations, etc. It is hoped that this work can provide discernment for operators with similar requirements.

Because of the problems, such as the lack of an electric power diagram atlas under different working conditions and the difficulty in intelligent diagnosis of variable torqued pumping unit wells, this paper proposes a diagnosis model of working conditions based on feature recognition. The mathematical relationship model between the polished rod load and motor output power is derived based on the analysis of geometric structure, motion law, and process of energy transformation and transfer of the variable torque pumping unit. It can calculate the electric power diagram based on a dynamometer card. On this basis, the electric power diagram atlas is created, and the feature analysis and eigenvalue extraction of the electric power diagrams under different working conditions are carried out to realize the direct diagnosis of the working conditions in the variable torque pumping unit wells. The application and analysis of examples show that the electric power diagram atlas created in this paper has good practicability, and the working condition diagnosis model accuracy is high. It can provide a theoretical basis and technical support for the intelligent diagnosis of oil production working conditions and improve the intellectual management level of the oilfield, which is conducive to reducing production management costs and improving the oilfield’s production efficiency and benefits.

In gas storage or high-pressure gas wells, annular pressure is an unavoidable threat to safe, long-term resource production. The more complex situation, however, is multiple annular pressure, which means annular pressure happens in not only one annulus but two or more. Such a situation brings serious challenges to the identification of well integrity. However, few researches analyze the phenomenon of multiple annular pressure. Therefore, this paper studies the mechanism of multi-annular pressure to provide a foundation for its prevention and diagnosis. Firstly, the multi-annular pressure is classified according to the mechanism and field data. Then the failure mechanism and function of the wellbore safety barriers in the process of passage formation are analyzed. Finally, some suggestions are put forward for identifying and controlling multi-annular pressure. The results show that gas storage wells and high-pressure gas wells have the conditions to generate pressure channels, which leads to the expansion of annular pressure from a single annulus to multiple annuli. The pressure channel is composed of the tubing string, casing string, and a cement mantle, and the failures among the three have causal and hierarchical relationships. According to the channel direction, it can be divided into two types: tubing-casing annulus to casing annulus and casing annulus to the tubing-casing annulus, of which the former is more harmful. Some measures can be considered to prevent pressure channeling, including improvement of cementing quality, revision of maximum allowable annular pressure, and suitable frequency of pressure relief.

Foam flooding is an efficient and promising technology of enhanced oil recovery that significantly improves sweep efficiency of immiscible displacement processes by providing favorable mobility control on displacing fluids. Although the advantages in flexibility and efficiency are apparent, accurate prediction and effective control of foam flooding in field applications are still difficult to achieve due to the complexity in multiphase interactions. Also, conventional field-scale or mesoscale foam models are inadequate to simulate recent experimental findings in feasibility of foam injection in tight reservoirs. Microscale modeling of foam behavior has been applied to further connect those pore-scale interactions and mesoscale multiphase properties such as foam texture and the relative permeability of foam banks. Modification on a microscale foam model based on a pore-filling event network method is proposed to simulate its propagation in grain-based pore networks with varying degrees of heterogeneity. The impacts of foam injection strategy and oil-weakening phenomena are successfully incorporated. Corresponding microfluidic experiments are performed to validate the simulation results in dynamic displacement pattern as well as interfacial configuration. The proposed modeling method of foam propagation in grain-based networks successfully captures the effects of lamellae configurations corresponding to various foaming processes. The results of the simulation suggest that the wettability of rock has an impact on the relevance between reservoir heterogeneity and the formation of immobile foam banks, which supports the core idea of the recently proposed foam injection strategy in tight oil reservoirs with severe heterogeneity, that of focusing more on the IFT adjustment ability of foam, instead of arbitrarily pursuing high-quality strong foam restricted by permeability constraints.

The temperature profile plays an important role in well integrity, flow assurance, and well test. Meanwhile, the impact of engineering conditions should not be ignored while calculating the well temperature profile. Therefore, in this study, we established a model to analyze the changing law of the temperature profile inside the production string of a high-pressure/high-temperature gas well (HPHT gas well). The proposed model considers the flow friction caused by a high production rate. Meanwhile, the variations in gas properties are taken into account to increase the model accuracy, including gas density, flow velocity, and viscosity. The analysis indicates that the temperature in the production string decreases more and more quickly from the reservoir to the wellhead. The wellhead temperature changes more and more slowly with time. When the reservoir temperature is too low to maintain production, it is useful to regulate the production rate or inject the thermal insulating fluid into the annulus to avoid the block caused by wax deposition or hydrate deposition. Considering the sensitivity, feasibility, and cost, it is recommended to change the well temperature profile by adjusting the production rate. If not applicable, the thermal conductivity can also be optimized to change the temperature profile.

水平井是实现Ⅲ类天然气水合物藏高效降压开采的重要手段之一.为明确Ⅲ类水合物藏水平井降压开采的生产动态及变化规律,建立了以Ⅲ类水合物藏为研究对象的、基于Tough+Hydrate水合物降压开采模型,从气体分解速度、累计产气量、产气峰值和产水等角度分析了水平井产气动态,研究了水合物饱和度、束缚气饱和度、生产压力和水平段长度对产气过程的影响.研究结果表明,产气曲线存在显著的峰值,可分为波动上升、快速下降和缓慢下降3个阶段,且在开采初期的产水量较大;产气速度峰值随着水合物饱和度和束缚气饱和度的增加而降低且出现时间延后;随着生产压力的降低和水平段长度的增加,产气速度峰值上升且整个生产进程加快.根据上述分析,在生产初期应合理配置产出水处理装置,保障安全生产.对于水合物饱和度和束缚气饱和度较高的储层,可采用压裂等辅助手段释放产能.除常规水平井外,还可采用多分支水平井来增加接触面积,进一步提升产能.

Productivity prediction is one of the important issues for the economic and effective development of gas hydrate deposit. Therefore, this paper proposes a method to establish productivity prediction for the Class III gas hydrate developed by depressurization and horizontal wells. The method are divided into four steps, including numerical simulation, production performance analysis, revision of formulas and quantitative calculation of key factors. The prediction method is based on inflow performance relationship (IPR) of gas hydrate. Considering the shape of IPR curves, Fetkovich's formula and Vogel's formula are selected as the basic formulas respectively for the increasing part and decreasing part of gas hydrate production. To revise Fetkovich's formula, the deposit pressure is replaced by comprehensive deposit pressure, which is determined by energy coefficient B0. Through the analysis and evaluation of influencing factors, B0 is described by a equation related to gas hydrate saturation. To revise the Vogel's formula, the lowest production pressure is set as the four phase point pressure, leading to the change of production pressure difference and maximum gas production rate. The key coefficient C is calculated by a equation related to gas hydrate saturation and well spacing. Compared with simulation results, the results of proposed formulas show good accuracy in the prediction of production rate of gas hydrate. The results of test point predicted by revised Fetkovich's formula almost coincide with simulation results. The average error between results of revised Vogel's formula and simulation results is 4.24%. So the proposed method can be applied to predict the productivity of gas hydrate for its good accuracy, fast speed and simple calculation.

The trapped annular pressure (TAP) caused by thermal expansion is one of the serious challenges for the safe production of a deep gas well. Therefore, this article proposes a model to calculate the temperature profile of the deep gas well based on the heat transfer process and the gas properties. With the help of the temperature model, the TAP in the tubing–casing annulus is analyzed according to the annular fluid distribution and the volume consistence law. The results indicate that the temperature inside the tubing string decreases faster under higher bottom hole pressure. When the tubing–casing annulus is totally filled with the annular protection liquid, the TAP continues increasing with the production rate. Considering the high production rate, the TAP is inevitable and high enough to damage the integrity of the deep gas well. The nitrogen gas mitigates the TAP by reducing the annular liquid volume and providing the extra space to accommodate the thermal-expanded annular liquid. A good mitigation performance can be achieved no matter how large the production rate is. The mitigation performance can be divided into the fast-decreasing stage, the efficient control stage, and the stable stage. These three stages occur as the nitrogen gas column length increases. The compression of the nitrogen gas volume plays a major role in the fast decrease stage while the reduction of the annular liquid plays a major role in the stable stage. For the best cost-effectiveness, the nitrogen gas column is recommended in the efficient control stage and should not exceed 15%.