Formation Pressure Research Articles

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.

Miscibility Evaluation for Reinjection of CO2 Flooding Associated Gas in Jilin Oilfield

Abstract In view of large amounts of associated gas produced in the late stage of CO2 flooding in Jilin Oilfield, the production characteristics of CO2 flooding associated gas are divided into three stages (i.e. before injected gas breakthrough, during injected gas breakthrough and after injected gas breakthrough). Taking the formation pressure as miscibility evaluation criteria, the miscibility effect of the produced CO2 flooding associated gas from different stages is evaluated. According to different gas production stages, the reinjection method of mixing the associated gas with pure CO2 under different proportions is proposed to elevate the utilization degree of the produced associated gas. The results indicate that at the very beginning of gas production process, produced gas is mainly composed of CH4 (58%) and C2~C3 (29%) with small amounts of N2 and C4~C6. During this stage, the associated gas can not reach miscibility with the oil by direct reinjection. It needs to be mixed with pure CO2, also the blending ratio of the associated gas should not exceed 6%. In the second stage, the compositions of the produced gas are mainly CH4 (34%) and CO2 (40%). During this stage, the blending ratio should not exceed 11%. At the final stage, the main composition of the produced gas is CO2 (94%). The associated gas can be directly reinjected into the reservoir during this stage.

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.

A New Productivity Prediction Model for Multi-fractured Horizontal Wells in Tight Oil Reservoirs

Abstract The productivity of Multi-fractured horizontal wells (MFHWs) in the tight oil reservoirs is the key index to evaluate the effect of volume fracturing. In this study, to find a solution for this problem, firstly, the big data affecting the productivity of MFHWs were collected, and then a multi-level evaluation system was built by using the analytic hierarchy process(AHP). Secondly, the gray theory was used to calculate the correlation coefficients between different parameters and production capacity to screen out the key parameters affecting the production capacity. Finally, a new horizontal well productivity prediction model by coupling key geological and engineering parameters was established, to calculate the similarity coefficient and realize quantitative prediction of single well productivity. The results show that the length of horizontal section, formation pressure, fracturing fluid volume, number of stages, net pay thickness and permeability are the key parameters affecting productivity of MFHWs. The new productivity prediction model has been successfully applied to 175 wells in China’s typical tight oil fields, with prediction errors less than 5%. It can be used in productivity prediction of horizontal wells after volume fracturing in similar unconventional tight oil reservoirs, has broad application prospects, and can guide the efficient development of and fracturing scheme selection for tight oil reservoirs effectively.

Borehole Stability of Natural Gas Hydrate Reservoirs

Abstract The decomposition of natural gas hydrate (NGH) due to long-term drilling may decrease the strength of reservoirs and increase the borehole failure risk. Meanwhile, the creep properties of NGH reservoirs also may give rise to engineering problems including borehole shrinkage and jamming of drilling tools in the late stage of drilling, which seriously impairs the drilling safety. A thermal-fluid-solid multi-field coupling model considering the decomposition kinetics of NGH and creep properties of reservoirs was established to explore the influence mechanism of NGH decomposition and creep properties of hydrate-bearing sediments on mechanical behaviors of boreholes. In addition, influences of drilling parameters and geomechanical properties of reservoirs on borehole stability in the drilling process of NGH reservoirs were analyzed. Research results show that creep properties of NGH deposits causes homogenization of stress distribution in different directions of NGH reservoirs around boreholes, transition of plastic zones around boreholes to a round shape, and possibly overall borehole collapse. As the horizontal geostress becomes more inhomogeneous, the borehole instability risk increases; the higher the initial pore pressure of formation is, the lower the effective geostress and the lower the borehole instability risk. The research results can provide theoretical support for safe drilling of NGH reservoirs in South China Sea and promote the early commercial exploitation of NGH resources in China.

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.

Caprock Safety Evaluation Method in CCUS Based on Latin Hypercube Sampling: A case study of a block reservoir

Abstract CO2 geological sequestration is one of the essential means to achieve carbon neutrality goals. However, substantial CO2 sequestration in formations can lead to leakage issues, primarily through the caprock, involving caprock rupture, leakage along caprock fractures/faults, and capillary leakage. Therefore, establishing a method to assess the safety of the caprock during CO2 storage processes is crucial. Firstly, a numerical simulation model is constructed based on parameters from the target block to study the influences of reservoir property, development parameters, and caprock parameters on CO2 flooding, gas injection, and CO2 storage. Latin hypercube sampling is employed for scheme design and subsequent result analysis, applying Spearman’s method to analyze the controlling factors in each CO2 storage. Secondly, using continuous gas flooding as an example, the migration pattern of CO2 in the formation is investigated, and the influence of the formation pressure distribution on caprock safety is analyzed. Finally, considering the comprehensive impact of different parameters on caprock safety, a fuzzy comprehensive evaluation of caprock safety in the target block is conducted. The study indicates that caprock permeability is the most critical factor affecting safety operation across all storage stages, with respective highest positive correlation coefficients of 0.413, 0.356, and 0.221 in different stages. The migration of CO2 in the formation is primarily influenced by the distribution of injection wells and gas migration channels. The established quantitative evaluation standard for caprock safety in the target block calculates a suitability degree of 3.43, suggesting a relatively secure caprock in the block suitable for achieving long-term stable CO2 storage. This research provides theoretical support for the safety analysis of caprock in different stages of CO2 flooding and storage, offering a scientific basis for the safety operation of CCUS schemes.

Application and Enlightenment of High Frequency Pressure Monitoring in Fracturing of Fengxi Block

Abstract Volumetric fracturing of large-scale horizontal Wells is one of the important techniques for unconventional oil and gas production. However, there are no effective quantitative methods to describe key parameters such as fracture size and formation flow parameters. The high frequency pressure monitoring technology is to install a high frequency pressure gauge at the wellhead, and obtain the fracture initiation position and the sealing property of the bridge plug through monitoring and analysis of the water hammer wave during the period of pump shutdown. At the same time, the fracturing scale, permeability and the original formation pressure are obtained by combining the analysis of seepage pressure. On the basis of quantitative monitoring results, the relationship between fracture parameters and geological and engineering factors is deeply analyzed, and the following conclusions are obtained. (1) The number of fractures opened is mainly affected by the physical properties of the reservoir, which in turn affects the amount of liquid intake and sand of the single cluster opened, and finally affects the length and height of fractures in the core area. (2) The fracture morphology is affected by the construction scale and reservoir mechanical properties of a single cluster, while the SRV of the core area and the overall SRV are more affected by the overall construction scale.

Formation pressure prediction method based on machine learning

Abstract Formation pore pressure is one of the key parameters in petroleum engineering. The high-temperature and high-pressure working conditions formed under the complex mechanism of Yingqiong Basin make downhole complex events such as overflow and well leakage occur frequently. To address the problem of the large prediction error of the traditional Eaton method under high temperature and high-pressure conditions, three machine learning methods, such as GA-BP(Genetic Algorithm-Back Propagation Neural Network), PSO-LSTM(Particle Swarm Optimization-Long Short-Term Memory Neural Network), SVR(Support Vector Regression), are introduced to find the nonlinear relationship between logging parameters and formation pore pressure. Seven logging parameters such as formation depth, mechanical drilling speed, drilling pressure, and rotational speed were used as input variables, and formation pore pressure was used as an output variable through correlation analysis for constructing the machine learning model. By analyzing the experimental results of the above three machine learning models with the Eaton method, the GA-BP model with lower error and more satisfying the needs of drilling engineering is preferred, and the various regression evaluation indexes of the model are also more excellent compared with other machine learning models, which are Mean Squared Error (MSE)=0.001, Mean Absolute Error (MAE)=0.003, and R-squared (R2)=0.991, respectively. It is concluded that the machine learning method is not only more advantageous in a class of nonlinear regression problems such as formation pore pressure prediction, but also can help engineers to predict formation pore pressure more accurately under the conditions of deep high-temperature, high-pressure, and complex formations, which contributes to guaranteeing the safety and high efficiency of drilling projects.

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.

Effect of Raw Material and Process Conditions During the Dry Forming of CTMP Fibers for Molded Pulp Products

ABSTRACT This article provides a concise insight into the thermoforming of airlaid CTMP pulp. First, the airlaid process was studied, showing that fiber fractionation and the retention of fines occurred in the forming head. Then, the effect of temperature and pressure during thermoforming was investigated. Harsher conditions, i.e. higher temperature and pressure, yielded greater densification of the substrate and higher tensile strength. The maximum strength was found at the highest settings tested, that is, 100 MPa and 200°C. The screening of thermoforming conditions was also compared to previously published results on wetforming. Next, the effect of softwood CTMP pulp was delineated, which on average showed the best mechanical properties at elevated freeness and high degrees of bleaching. At last, a comparison between dry forming and wetforming was made for one selected pulp quality. Here, the dryformed substrates were stiffer at low elongation, yet the wetformed substrates yielded a greater extensibility and higher tensile strength. In conclusion, dryformed pulp mostly relies on temperature and pressure for bond formation during thermoforming, which produces materials that are distinctly different from wetformed molded pulp.

Thermodynamic and Kinetic inhibition of Methane Hydrate with Organic Inhibitors

The present experimental work reports the impact of ethylene glycol, polyethylene glycol and glycerol on formation temperature, pressure and inhibition time of methane hydrate. The inhibition effects of hydroxyl functional group of inhibitors have been studied. It is evaluated in terms of temperature, pressure and induction time. Methane hydrate equilibrium temperature and pressure is also studied. Experimental results disclose that ethylene glycol is a strong candidate to hinder methane hydrate thermodynamically while glycerol is good competitor to discourage hydrate formation in both terms kinetic hindrance and thermodynamic hindrance.

Evaluating the efficacy of water alternating gas injection technique in the upper jurassic hydrocarbon reservoirs, considering saturation pressure

A tertiary method of enhanced oil recovery (EOR) based on the watergas alternating injection process (WG) is examined in this article based on the ratio between saturation pressure and reservoir pressure. A hydrodynamic simulation of the WAG process was carried out using TEMPEST MORE software (version 7,1). Many hydrocarbon fields worldwide are currently experiencing declining production rates. However, by utilizing advanced technologies like alternate injection of water and associated petroleum gas, the final oil recovery factor (RF) can be significantly increased. To ensure successful water injection experiments in real fields, it is crucial to consider the ratio of saturation and reservoir pressures during injection. Any negligence in this regard can lead to failure of the experiments aimed at enhancing oil recovery through WAG application. The research examines two variations of reservoir system models with certainty. In the initial model, the saturation pressure is lower than the reservoir pressure, signifying an under-saturated state of the reservoir system containing dissolved gas. Consequently, when accompanying petroleum gas is introduced, it mixes with oil at precise thermobaric conditions. According to the second model, the reservoir is saturated with gas at a saturation pressure equivalent to the formation pressure. A thorough assessment indicates that the success of water alternating gas injection (WAG) is heavily influenced by the initial state of the reservoir. In situations where the reservoir is already saturated with gas, implementing water-gas stimulation may be ineffective as gas breakthroughs may occur rapidly. However, implementing WAG in saturated reservoirs can lead to a 1 – 8% rise in overall oil production, observable within 3 – 4 years, depending on the timing after waterflooding. Simultaneously, in the case of reservoirs with a low saturation pressure, which exhibits an undersaturated reservoir system, the implementation of water alternating gas injection can be seen as a viable approach for enhancing oil recovery. WAG is a proven method that confidently increases oil recovery up to 10% in undersaturated reservoirs compared to conventional waterflooding.

The Effect of Hydrate Formation Conditions on the Mechanics of Laboratory Methane Hydrate‐Bearing Sediments

AbstractThe mechanics of methane hydrate‐bearing sediments (MHBS) have been broadly investigated over recent years in the context of methane‐gas production or climate‐change effects. Their mechanical investigation has mainly been carried out using models constructed from experimental data obtained for laboratory‐formed MHBS. Along with the dominant effects of hydrate saturation and morphology within the host soil pores, this study recognizes the effective pressure at which the hydrate is formed as a key factor in the MHBS mechanics. A state‐of‐the‐art experimental study has been conducted in order to isolate the effect of the hydrate formation pressure, for use as a model parameter. Two generalized mechanical prediction models that incorporate the effect of the hydrate formation pressure are developed in this work: (a) an analytical shear strength prediction, and (b) an empiric graphical model for predicting volumetric changes along a given stress path. The models are related to a novel data representation which enables the analysis of a few individual test outcomes as a whole, through a volume‐change mapping that describes the complex influence of the volumetric effect of hydrate in MHBS, under combined hydrostatic and deviatoric loading scenarios. In this study, we delve into a specific configuration of hydrate morphology, hydrate saturation, and host soil type, enabling a distinctive fundamental geotechnical investigation and the development of a conceptual modeling approach. The paper describes the approaches by which the MHBS properties can be extracted for other MHBS samples (than those examined in this work) having different host soils and hydrate pore‐space morphologies.

Prediction of hydrate formation boundaries in pure water and salt/alcohol containing systems based on prior knowledge and artificial intelligence

As an efficient and clean energy source, natural gas plays a crucial role in optimizing the global energy consumption structure. However, the formation and accumulation of hydrates in pipelines during the exploitation and transportation of natural gas greatly jeopardize the production safety. Accurately predicting hydrate formation boundaries remains challenging due to the complex interation among various influencing factors. Although mechanistic models provide insights, they often fall short in accuracy. Conversely, machine learning models, while promising, may face limitations related to small sample sizes and a lack of physical interpretability. To overcome these limitations, this study proposed a physically guided neural network (PGNN) based on the Chen-Guo model, which integrated thermodynamic mechanisms with a neural network framework. This proposed model utilized pressure calculated from the Chen-Guo model as an input variable and incorporates physical inconsistencies into its loss function. A comparative analysis using literature data that PGNN achieved superior prediction accuracy, with an R2 value of 0.9768 for gas hydrate formation pressure prediction. The integration of thermodynamic mechanisms enhanced the prediction accuracy, as evidenced by an increase in the R2 value by 0.036, and a reduction in the MSE value by 5.56. Furthermore, the PGNN maintained a high level of prediction accuracy, ranging from 0.96 to 0.98, even with limited sample sizes, thus confirming its applicability and stability. This study validated the feasibility of PGNN for predicting gas hydrate formation conditions and offered insights into hydrate-based applications and hydrate management strategies.

Effects of intracameral tissue plasminogen activator injection on posterior capsular opacification, fibrin formation, and intraocular pressure in dogs after phacoemulsification.

To evaluate whether intracameral tissue plasminogen activator (tPA) injection is effective in regulating posterior capsular opacification (PCO), fibrin formation and intraocular pressure (IOP) after cataract surgery. Prospective study involving 30 eyes of 21 dogs that underwent phacoemulsification. Thirty eyes were randomly divided into two groups of 15 eyes (control and tPA groups). Intracameral tPA (25 μg/0.1 mL) was injected into tPA group eyes before corneal incision closure but not into the eyes of the control group. The grades of anterior fibrin formation and PCO were compared based on slit lamp biomicroscope examination at 1 and 2 weeks, 1 month, and 2-3 months postoperatively. IOP was measured using applanation tonometry every 30 min for 4 h immediately after operation and on the following morning. The IOP of the two groups at each time was compared. The grade of anterior fibrin formation and that of PCO were not significantly different between the two groups at any time point (p > .05). However, the IOP of the tPA group was significantly lower than that of the control group at each point on the day of surgery (p < .05). No complications were observed with tPA injection, except for temporary hyphema (for 3 days) in one eye. Although the intracameral tPA injection did not affect anterior fibrin formation and PCO, it effectively maintained normal IOP immediately after phacoemulsification. Thus, our findings provide valuable insights into the potential benefits of intracameral tPA injection in achieving immediate IOP control after phacoemulsification.

CO2-EOR and storage in a low-permeability oil reservoir: Optimization of CO2 balanced displacement from lab experiment to numerical simulation

CO2 flooding can enhance oil recovery associated with CO2 storage, but its performance is often damaged by the gas channeling due to reservoir heterogeneity and the large CO2 mobility. Most current research focuses on chemical agents to prevent CO2 channeling, while there is less attention to reservoir engineering methods. In this study, a concept of balanced displacement was introduced to delay the gas channeling and achieve balanced development in a multi-layer and low-permeability block Y21. A series of lab experiments and numerical simulations were conducted to explore the best CO2 flooding scheme by considering three aspects of optimization. Layer grouping and well pattern and spacing adjustment were applied to seek for balanced utilization of geological reserves; gas channeling plugging and mobility control measures were taken to increase the CO2 swept volume; and the pressure control and injection-production optimization were carried out to improve the oil displacement efficiency. The results show that CO2 can reach miscible with crude oil in block Y21 under the original formation pressure, but gas breakthrough quickly occurs along the hydraulic fractures to the top of the structure. To obtain a balanced displacement, the layers of block Y21 should be divided into two groups for separate development. The current well pattern and spacing are suitable for CO2 flooding, which need not be adjusted. WAG injection with acid-resistant gel particles and foaming agents can be used to inhibit gas channeling. These measures can significantly improve the CO2 displacement profile in block Y21. The oil recovery factor can be increased by 10.01%, and 5.41 × 104 tons of CO2 can be stored. This study can provide valuable guidance for CO2-EOR and storage in low-permeability oil reservoirs.

On the role of the Bernoulli force in stuck pipe during oil and gas well drilling

Stuck pipe is one of the most prevalent and costly complications encountered during drilling operations in the oil and gas industry. It represents a significant challenge, contributing to delays and increased financial costs that cumulatively amount to billions of dollars annually. Understanding and addressing the root causes of pipe sticking are crucial for minimizing these adverse impacts. This paper provides a comprehensive analysis of the various factors contributing to stuck pipe incidents, highlighting both traditional and newly identified mechanisms. Key factors leading to pipe sticking include mechanical issues such as rock particles drilled out during the process, inadequate well cleanup, wellbore instability, and differential sticking forces, which are primarily due to the disparity between hydrostatic pressure and formation pressure. These issues are particularly prevalent in horizontal or inclined wells, where the dynamics of drilling differ significantly from vertical wells, exacerbating the risks of pipe sticking. The occurrence of stuck pipe not only increases the duration of drilling operations but also significantly escalates the associated costs, thereby impacting the overall economic viability of drilling projects. A novel factor contributing to stuck pipe is the Bernoulli force, a phenomenon that has been discussed in detail in this article. The Bernoulli force acts perpendicular to the flow axis from the edges towards the center of the flow. In the context of cylindrical flow within a wellbore, this force is magnified as the density difference between the drilled rock particles and the drilling fluid increases, along with the diameter of the mechanical cuttings. As a result, the Bernoulli force facilitates the migration of drilled rock particles towards the flow center, leading to an accumulation that increases local resistance due to friction. This intensified resistance can significantly contribute to the occurrence of a stuck pipe, presenting a new challenge for drilling operations that must be addressed. This paper discusses the comprehensive mechanisms of stuck pipe, including the differential and mechanical factors, and provides an in-depth analysis of these aspects. The study emphasizes the importance of understanding these factors to develop effective strategies for prevention and mitigation. By exploring the key features necessary to minimize the risks associated with differential and mechanical sticking, this article offers valuable insights into improving well drilling practices. The findings underscore the need for thorough well cleanup, effective management of wellbore instability, and a nuanced understanding of pressure dynamics to prevent stuck pipe incidents. The paper concludes with recommendations for industry practices and further research to mitigate the impact of stuck pipe on drilling operations.

APPROACH TO CREATION OF GEOLOGICAL AND RESERVOIR SIMULATION MODEL AND METHODS FOR HISTORY MATCHING OF RESERVOIR ENERGY STATE

Under conditions of complex geological structure and substantial share of hard-to-recover oil reserves, reservoir simulation is a key tool in reservoir management. Direct problems solved by reservoir simulation include forecasting of the production performance, control and management of reservoir development, and localization of residual oil reserves. Inverse problem solution is useful for updating the knowledge of geological structure, reservoir quality, and historical production data by means of history matching. The quality of history matching is fundamental to ensure reliable future forecasts and localization of residual oil zones. The main approaches to appropriate history matching rely on analysis and adjustment of well logging and geological parameters, as well as checking and correction of errors, inadequate historical data, application of physics-based and reasonable approaches and tools. The prerequisite for adequate history matching and predictive ability of the resultant reservoir simulation model is the compliance of simulated and actual energy state of the reservoir. In this paper, the initial stage of reservoir simulation is performed, the approach to history matching of reservoir energy state aimed at improving the quality of further predictions is described as exemplified by one of the production areas of Russian oil field. The main causes of poor history match of formation and bottomhole pressures are revealed. These causes are grouped as follows: — geological causes/reservoir quality, which include permeability field distribution, reservoir connectivity, and determination of rock and fluid compressibility;— technical causes (during reservoir simulation), that is model limitations in case of larger areas, the need to use sector models, consideration of buffer region;— technological causes, including inadequate historical data or lack of data, detection of behind-the-casing flows and production casing leaks in wellbore, etc. For each group of factors that have a substantial impact on reservoir pressure, recommendations and methods of energy state history matching on geological and reservoir simulation models are provided, examples are given.

Research on Optimization of Intermittent Production Process System

As gas wells enter later production stages, the formation pressure decreases and liquid accumulates at the bottom of the gas well. The formation pressure is insufficient to lift the accumulated liquid from the bottom of the well to the surface. At this time, a large number of gas wells need to undergo intermittent production to maintain their production capacity. This article focuses on the four stages of intermittent production in gas wells, considering the changes in slip gas holdup, pressure, and gas–liquid flow in and out of tubing and casing, and establishes a transient mathematical model for intermittent production in gas wells in stages. By using the dynamic tracking technology of moving liquid slugs to divide the wellbore grid and solve it in stages, the optimal shut-in time for intermittent production of gas wells was obtained. The transient mathematical model developed for intermittent gas well production achieved a high historical fit accuracy of over 90%. This indicates that the simulation results are in line with the actual situation of gas well intermittent production and can effectively guide intermittent production. The optimized intermittent production system of gas wells has a higher cumulative gas production compared to the original system, achieving the optimization of intermittent production system. This method is beneficial for guiding efficient production of gas wells in low-pressure formations.