Wellbore Diameter Research Articles

Irregular Eccentric Wellbore Cementing: An Equivalent Circulation Density Calculation and Influencing Factors Analysis

In the field of cement, if the formation cannot be given sufficient pressure to maintain stability during construction, pressure control failure may occur, leading to the leakage of liquids and gasses from the formation to the wellbore. In addition, irregular wellbore diameter and casing eccentricity are important factors that are easily overlooked and affect the prediction of ECD (Equivalent Circulation Density) calculation. This results in major accidents and ecological disasters, further impacting the global environment. This study focuses on a well in the eastern oilfields of China, and based on a rheological experiment of high temperature and high pressure, an irregular eccentric wellbore model is established according to the measured wellbore diameter and eccentricity data to calculate the ECD of the whole cementing process. Then, a data set is constructed and analyzed using the random forest method to quantitatively evaluate influencing factors such as displacement, rheology, density, and eccentricity on the bottomhole and wellbore ECD. Results find that the density of cement slurry and drilling fluid has the most significant impact on the maximum ECD, with the impact reaching 0.3142 and 0.2902, respectively, and the main factors that affect the minimum ECD are the density and rheological changes in the drilling fluid, reaching 0.7014 and 0.2846. These research findings will contribute to the precise control of wellbore pressure during cementing operations, further ensuring the safety of cementing operations, and laying a technical foundation for the automation and intelligentization of subsequent cementing operations.

Application of Constant Pressure Explosive Floating Casing Technology in Large Displacement Horizontal Wells

Abstract Large displacement horizontal wells are commonly employed to enhance unconventional resource recovery. However, during the field process, challenges often arise, particularly in cases where the casing string cannot reach the designated position. This issue is particularly prominent in the development of shallow wells with long horizontal segments. Currently, widely adopted traditional floating casing methods fall into two main categories: mechanical and rupture disc types. Mechanical methods faces the challenge that after casing running, the mechanical separation structure remains in the wellbore, adding difficulties to subsequent operations. Rupture disc methods face the challenge of pressure misalignment due to factors such as excitement pressure in the liquid column, potentially leading to premature opening during descent. This paper presents a constant pressure explosive floating casing method, characterized by large reliability and the elimination of the need for additional drilling to remove the barrier structure after casing lowered. This paper focuses on two main aspects: firstly, the design of two-stage initiation mechanisms, corresponding to the initiation pressure of the exciting device and the crushing pressure of the rupture disc. This design ensures precise initiation at low pressure levels while maintaining pressure integrity. Secondly, for different well conditions, varying initiation pressures can be selected, allowing for targeted optimization of initiation and crushing pressures while keeping the pressure difference consistently within a safe range, preventing inadvertent opening and failure during the descent process. In field application, the constant pressure explosive floating casing technology has been successfully applied in over 100 wells, with the longest floating segment reaching 3270m. In all cases, the casing descended smoothly to the designated position, offering convenient, safe operations without the need for repeated plugging. This technology guarantees the attainment of the design-required opening pressure and ensures full wellbore diameter and sealing integrity. The technology effectively avoids the complexities associated with casing installation in long horizontal, large-displacement wells, reducing the difficulties in subsequent operations such as cementing and completion.

Research and Application of Drilling and Completion Technologies on Large-size Injection-production Well

Abstract The large-size injection-production well can increase the injection-production capacity to more than 3 times, compared with the conventional-size one. However, it had not been popularized and promoted for many years since it had the technical difficulties of long construction period, high engineering risk and large investment in a single well. The Liaohe double-6 gas storage planned to deploy 3 large-size horizontal wells, aiming at further improving injection-production capacity to satisfy peak shaving demand. To overcome the technical difficulties of large-size well, the drilling scheme was optimized according to geological characteristics of double-6 block in the paper. It included wellbore structure design, wellbore diameter control technology and hole cleaning technology. The optimized drilling scheme can not only improve the wellbore integrity, but also reduce the risk of engineering accidents and shorten the drilling period greatly. Besides, the cementing technology was optimized as well from the aspects of hierarchical cementing and cement slurry design, which can be used to solve the problems of high pressure at the bottom of well and large leaking risk of cement. On the basis, the above drilling and cementing technologies were applied to develop three large-size wells, and good practical results were achieved. The average completion period of the three well was 104 days, 36 days shorter than the planned period, which realized the applying effects that large-size wells can be designed, constructed, and produced in the same year. Moreover, the ultrasonic evaluation results showed that the average qualified rates of the three wells in technical casing was 92.8%, which was much higher than the industry standard. Besides, the test results showed that the injection and production volume of each large-size well in the paper can exceed 3 million cubic meters, solving the problem of insufficient injection-production capacity in the months with high peak shaving demand. Above all, the drilling and cementing technologies of large-size well had been optimized in the paper, which successfully reduced the well completion period, and improve the cementing quality and the safety of drilling construction. The researches can not only ensure the project quality of large-size well in Liaohe double-6 gas storage, but also provide technical support for promoting the drilling and completion engineering of large-size well in other domestic and foreign gas storages.

Artificial neural network prediction of wellbore stability in offshore shallow formations

Wellbore instability is one of the most critical challenges during drilling, which may result in complex problems such as stuck pipe, high torque and mud loss, impeding the drilling progress and increasing the cost of drilling operations. Offshore shallow formations are characterized by weak consolidation and low strength, causing serious wellbore collapse frequently. The traditional physics-based wellbore instability models attempt to predict the risk of failure of the wellbore for given drilling fluid densities and provide optimal fluid density for safe drilling. However, these models generally involve quite a few empirical coefficients, determination of which heavily rely on the field experiences of the engineers, and thus the results may vary greatly from person to person. In this study, an artificial neural network (ANN) model has been established for wellbore stability prediction, aiming to reduce the subjectivity while mapping the drilling performance of neighboring wells into the predicted results. Eleven factors that may affect wellbore stability have been identified from the prevailing physics-based model and used as the input of the ANN model, while the wellbore enlargement rate (WER) is used as the output to quantify the wellbore stability performance. The model has been trained using data from 5 wells drilled in the offshore shallow formations of the Bohai Bay Basin in east China and then used to predict the WER of another well in the same region. The results show that the mean absolute percentage error is 6.113%, and at most well depths the predicted wellbore diameter deviate from the measured values not more than 5%. Comparison of the ANN model and some other machine learning models, including random forest model, decision trees model, linear regression model, was conducted, which demonstrated the best performance of the ANN model in terms of the predicted wellbore diameter profile. Finally, the potential application of the ANN model in optimizing mud weight has been illustrated through the predicted wellbore diameter profiles for different mud weights. It is worth noting that the method presented in this paper is of physics and data-driven nature and provides a new research insight for wellbore stability analysis.

Study on the Gas Phase Liquid Carrying Velocity of Deep Coalbed Gas Well with Atomization Assisted Production

In order to clarify the gas-phase carrying capacity after the atomization of water from the bottom of deep coalbed wells, considering characteristics of atomization-assisted production and the dynamic equilibrium principle of gas–liquid two-phase flow in the wellbore, the gas-phase liquid-carrying drop model was established, and the solution method of the upstream and downstream driving force of liquid drop flow was studied. We also verified the theoretical model through physical simulation. Then, the law for the influence of droplet size, wellbore inclination, wellbore diameter, and wellhead back pressure of the critical liquid-carrying velocity in the gas phase is analyzed using the model. The results show the following: ① the larger the diameter of atomized droplets, the greater the gravity force applied to it, the worse the ability to be carried by the gas phase, a onefold increase in droplet diameter corresponds to the increase in the minimum critical velocity of the gas phase by 1.45 times; ② with the increase in wellbore inclination, the liquid-carrying capacity of the gas phase decreases, and the minimum critical liquid-carrying velocity of equal diameter droplets increases by 0.01438 m/s or 1.27 times for the increase in wellbore inclination by 10°; ③ with the increase in wellbore diameter, both the driving force of a droplet of equal diameter and the flow resistance through the gas phase in the wellbore decrease within the range of a driving pressure difference of 0.2 Mpa; the decrease in liquid-carrying velocity caused by the decrease in received flow resistance can reach the maximum value of 0.0473 m/s; ④ with the increase in wellhead back pressure, the driving force of equal-diameter droplets decreases, the resistance against passing through the high-concentration gas phase increases, and the gas-phase-carrying droplets start the game; ⑤ the atomization-assisted production has the function of drainage gas recovery, and the adoption of atomization-assisted production technology can increase the production time of a coalbed gas flowing well, enabling the wells to have a good transition time interval for the conversion of flowing wells to pumping ones, which provides a precise production dynamic basis for the efficient design and implements the overall strategy of drainage gas recovery by deep-well pumping. In short, this technology has the high-efficiency liquid-carrying function of “water atomization to help liquid-phase flow and increase gas production”, as well as obvious technical advantages, which can provide a new idea for the development of deep coalbed methane wells and other types of gas wells with water.

An interpretable ensemble machine-learning workflow for permeability predictions in tight sandstone reservoirs using logging data

Tight sandstone reservoirs exhibit strong vertical heterogeneity and complex pore structures, challenging conventional permeability evaluation methods based on well-logging data. Although rising machine-learning (ML) techniques have demonstrated excellent accuracy for industrial applications, the physics and rationality within such a powerful “black box” remain less clear. Hence, reliable permeability prediction would benefit from an interpretable ML-based workflow that could reveal the controlling factors. To compare the models and examine the underlying features, 16 different ML submodels are tested after data preprocessing, feature selection, and hyperparameter optimization. By comparing the fitting accuracy and tuning time, the light gradient boosting machine optimized by the whale optimization algorithm, referred to as LGB-WOA, is determined to be the optimal model with the best fitting accuracy and relatively short tuning time. A field data application demonstrates that even in highly heterogeneous reservoir sections, the LGB-WOA model outperformed conventional petrophysical models by being the most consistent with reservoir permeability directly measured from the core samples ([Formula: see text]). The Shapley additive explanation values are then used to interpret the predictions of our LGB-WOA model. As expected, the porosity curve exhibits the highest feature importance among all input features, significantly contributing to permeability predictions. Conversely, a wellbore diameter and compensated neutron log contribute the least and need not be used for subsequent model improvements. These experiments and workflow provide a powerful method for accurately assessing the permeability in complex reservoirs and contribute to a broader understanding of the application of ML in reservoir characterization, paving the way for establishing more interpretable and reliable prediction models.

Calculation of Lateral Logging Response and Environmental Impact Factor Analysis for Small Borehole Array

This paper refines an optimized array lateral logging tool designed for small boreholes, leveraging existing technologies. The tool features four investigation depth curves, and resistivity response curves are derived through finite element model simulations considering variables such as borehole size, mud characteristics, invasion zone features, resistive annuli, formation rock properties, and formation resistivity anisotropy. The findings included the following: (1) Increasing the wellbore diameter uniformly decreased resistivity across all four investigation depths, positively correlating with borehole size. When mud resistivity (Rm) exceeded formation resistivity (Rt), resistivity curves became distorted. (2) For high- and low-invasion models, the ratio of the deepest to the shallowest investigation depth curves ranged from 1 to 8 and 0.6 to 0.9, respectively, with maximum separation at an invasion depth of 0.5–0.8 m. (3) Under invasion conditions with annuli, an invasion zone depth and annulus width around 0.4 m yield well separated the resistivity curves for all depths. Low- and high-resistivity annuli of 2 m and 0.7 m, respectively, can cause curve intersections. (4) When the formation thickness exceeded 0.2 m, the tool accurately reflected formation resistivity variations and demonstrated effective layer identification in multi-layer conditions. (5) In anisotropic formations, resistivity was negatively correlated with the anisotropy coefficient (λ) as it changed from 2 to 4. The instrument can be fully utilized in the exploration of thin interlayers in oil and gas, significantly enhancing the accuracy of resource identification and extraction technologies.

Development of expandable pipe technology: double-acting expander

Drilling wells presents a number of problems such as loss of circulation, wellbore instability, stuck pipe due to differential pressure or mechanical problems, and increased formation damage. Traditionally, these problems have been addressed by installing additional casing, resulting in a reduction in wellbore diameter. However, the use of expandable tubing technology within the wellbore can effectively mitigate these problems, potentially eliminating the telescoping effect associated with traditional well designs. This technology allows wells to be completed without reducing the planned diameter of the production string, which is critical for deepwater and highly deviated wells. The effectiveness of expandable tubing technology continues to evolve both offshore and onshore, offering solutions to a variety of operational challenges encountered during well construction. Steel pipe expanding requires specialized tools. During workover operations, these tools are used to isolate corroded or worn sections of casing, seal unwanted perforations and reinforce casing to stimulate flow and treat the wellbore. They also allow problem areas to be isolated without connecting to the previous casing string. However, dual-action expanders are required to drill constant-diameter wells. These expanders create sockets at the bottom of the large-diameter pipe and then expand the casing string to the smaller diameter. The paper describes the design and operating principle of a new expanding device that has been developed to solve the problems associated with efficiently expanding round steel casing and achieving double expansion in mono-diameter well construction. In conclusion, the developed new round steel casing expanding tool achieves double expansion, facilitating the construction of monodiameter oil and gas wells. Keywords: Well drilling; Mono-diameter technology; Steel pipe expanding; Double expansion; Expander.

Predictions of locations of flash point and calcite scaling of geothermal fluids in wellbore by chemical and thermodynamic simulations

Geothermal energy, as a renewable energy source, has been intensively developed recently because its utilization can reduce CO2 emission, climate warming and sea level rising, and be beneficial to promote sustainable development. However, scaling in the wellbores often happens during the rising of geothermal fluids. At present, the methods to explore the scaling location principally focus on real measurement techniques and numerical simulation method. In comparison with the former, the latter is extremely time- and labor-saving to predict the scaling location based on the coupling model. In this study, the flash point and scaling locations of two geothermal wells in Hebei province are numerically simulated via ECO2N equation of state module in TOUGHREACT software, and the factors affecting the flash point and scaling locations of geothermal wells are explored. At the same time, the mechanism of geothermal fluid flash is analyzed. The prediction results show that the relative errors of scaling locations in geothermal well I and II are 5.43 % and 6.82 % compared to the field measured data; the pressure and temperature of geothermal fluids at well bottom can be calculated based on the related parameters of wellhead fluid; the locations of flash point and scaling can be determined according to the sudden increases of CO2 partial pressure and scaling amount, respectively. Furthermore, the liquid mass flow rate, CO2 mass flow rate and wellbore diameter have prominent influence on the locations of flash point and scaling, while wellbore diameter have significant effect on the amount of calcite scaling. The above conclusions provide useful guidelines for the next scaling removal and control in the production wellbore during the utilization of the geothermal energy.

Geophysical electrical potential inversion for grouting remote monitoring of coal mine double-layered wellbores

This work aims to remotely monitor the grouting process of double-layered wellbores in deep coal mining area by proposing a new geophysical electrical potential inversion imaging method. The proposed geophysical method is able to evaluate the grouting quality between the inner and outer walls of the wellbores by inverting the geologic electrical potential. Th challenge lies here in the potential inversion is that the thickness of the grouting space is extremely narrow when comparing with the wellbore diameter. To solve this problem, a constrained inversion model is developed to precisely generate the three-dimensional (3D) resistivity distributions of the double-layered wellbore based on the measured geologic electrical potential. A special designed test platform is constructed and experimental tests have been conducted to examine the performance of the proposed geophysical inversion imaging method. The geologic electrical potential of the grouting space is measured and remotely transmitted to the ground processing center; and the constrained inversion model is applied to the geologic signals to calculate the resistivity distributions at different grouting stages and produce the 3D geophysical images. The analysis results suggest that the present geophysical monitoring method can effectively visualize the grouting to evaluate the construction quality of the wellbore.

Enhancing drilling operations: prioritizing wellbore integrity, formation preservation, and effective mud waste control (case study)

This study examined the issues of wellbore instability encountered during the drilling of the vertical exploration Al-Rateena-1 well, Block 25D, Al-Rawat Field, Sudan. Measurements of the wellbore diameter revealed significant damage to the formation interval between 2775 and 2925 m. This damage released approximately 800 barrels of drill cuttings from the affected zone and overlying formations. A comprehensive wellbore stability assessment was conducted to identify the root causes of instability and develop strategies to mitigate future occurrences. The assessment involved a thorough analysis of the pore, vertical, effective vertical, and minimum and maximum horizontal pressures. All of these parameters play a crucial role in maintaining wellbore integrity. This study also evaluated the potential impact of these parameters on groundwater and soil quality, leading to the development of an efficient waste management system. The safe mud weight range for the well was determined to be between 13.5 and 15.5 pounds per gallon (PPG). However, the drilling fluid used during the operation had a significantly lower density of only 10 PPG. This ultimately leads to the collapse of the wellbore wall. Examination of drilling cuttings revealed elevated levels of various heavy metals. These heavy metals included Lead (94.12 ppm), Mercury (62.87 ppm), Nickel (1403 ppm), Copper (343 ppm), Calcium (23132.72 ppm), Magnesium (3700 ppm), and Barium (16000 ppm). These elements pose a significant threat to both surface water and groundwater quality. It is possible that they also contributed to the wellbore wall collapse. It was hypothesized that the interaction between these elements and the water-based drilling fluid or its additives could have triggered the collapse event. The findings of this study highlight the importance of conducting comprehensive wellbore stability assessments before drilling. Such assessments should incorporate detailed investigations, modelling, calculations, and simulations of various parameters that influence wellbore stability. In addition, careful consideration must be given to the potential environmental impacts of drilling fluids and cuttings, particularly in areas with sensitive ecosystems. The wellbore instability in the vertical exploration Al-Rateena-1 well was primarily caused by the use of an underweight drilling fluid. This underweight drilling fluid results in the collapse of the wellbore wall. Elevated levels of heavy metals in drill cuttings suggest a potential impact on groundwater quality. It is also possible that they contributed to the wellbore instability. Comprehensive wellbore stability assessments are essential to prevent similar incidents in the future. This study provides a detailed account of wellbore instability. This includes the identification of root causes and the development of preventive measures. This study also highlights the potential environmental impact of drilling fluids and cuttings. The findings of this study can help improve drilling practices and environmental protection in the oil and gas industry.

Design and optimization of the U-shaped well geothermal systems for heat production performance: A case study from Huangling, China

U-shaped well geothermal systems have obvious advantages in deep geothermal development due to the long heat exchange distance and no fluid leakage. Well layout is a primary optimization target to enhance the heat production performance. However, there is a lack of studies for well location selection and installation configuration considering regional groundwater flow. In this study, a coupled thermo-hydro model considering 1D U-shaped well and 3D reservoirs groundwater flow is proposed for the optimization of U-well geothermal systems. The proposed model is calibrated by the field test of U-shaped well in Huangling, China. First, the U-shaped well geothermal system with multiple injection wells is designed. The feasibility is comprehensively evaluated from the aspects of heat production performance and levelized cost of electricity. Subsequently, the influence of groundwater flow on heat production performance is analyzed in detail, including flow velocity, porosity, aquifer thickness and flow direction. Finally, sensitivity studies of thermal conductivity of cement, wellbore diameter, and injection flow rate are investigated to provide reference for production operations. The results show that the heat production performance of the U-shaped well geothermal system with multiple injection wells are significantly better than the single U-shaped well. And the levelized cost of energy can be reduced by 0.0288 $/kWh compared to the average industrial electricity price in China. The groundwater flow velocity remarkably affects the heat production performance. The large aquifer thickness and porosity contribute to the improvement of the heat production performance of the U-shaped well geothermal system. The U-shaped well with injection wells located in the lower reaches of groundwater flow field has better heat production performance. The research results can provide references for design and optimization of the U-shaped well geothermal systems.

Temperature prediction model in multiphase flow considering phase transition in the drilling operations

The study considers gas compression properties, gas slippage, back pressure (BP), phase transition (PT), well depth, and differences in gas-liquid physical properties. A new temperature model for multiphase flow is proposed by considering phase transition in the drilling process. The mathematical model of multiphase flow is solved using the finite difference method with annulus mesh division for grid nodes, and a module for multiphase flow calculation and analysis is developed. Numerical results indicate that the temperature varies along the annulus with the variation of gas influx at the bottom of the well. During the process of controlled pressure drilling, as gas slips along the annulus to the wellhead, its volume continuously expands, leading to an increase in the gas content within the annulus, and consequently, an increase in the pressure drop caused by gas slippage. The temperature increases with the increase in BP and decreases in gas influx rate and wellbore diameter. During gas influx, the thermal conductivity coefficient for the gas-drilling mud two phases is significantly weakened, resulting in a considerable change in temperature along the annulus. In the context of MPD, the method of slightly changing the temperature along the annulus by controlling the back pressure is feasible.

Research on the technology of casing inspection through tubing in the Saertu Development Zone of Daqing Oilfield

With the further development of Daqing Oilfield, the occurrence of widespread casing damage in the Saertu Development Area has been on the rise annually.In order to promptly prevent, detect and address casing damage, the management departments of the oil extraction plants must schedule regular casing inspection operations. This approach not only raises production costs but also prolongs the well shutdown period, further impacting crude oil output.This article focuses on the technical needs of oilfield development and has developed tubing and casing detection technology, the radial magnetic scanning system is integrated with the sixteen arm wellbore diameter, the synchronous tubing and casing inspection instrument represents the latest in concurrent inspection technology, developed specifically for the technical demands of oilfield development Without displacing the tubing column, it simultaneously captures data on tubing inner diameter, tubing continuity, the extent of casing damage via magnetic scanning, and continuous 3D imaging of the tubing at standard inspection speeds, the workload of checking and matching tasks were significantly reduced. Between 2022 and 2023, the through-tubing casing inspection technology was utilized in 525 wells, with 356 wells verified by mobilizing the tubing column, achieving a predictive accuracy of 87.6% and generating economic benefits of 69.6 million yuan.

Investigation of multi-field coupling mechanisms during well cement through gas hydrate layer in horizontal well

Exploitation of natural gas hydrates from horizontal wells can significantly improve the production rate and final recovery. However, the long interaction surfaces of horizontal wells may easily disturb the hydrate reservoir. Cement hydration in wellbore is an exothermic reaction, which may lead to the premature dissociation of hydrate, thereby threatening the wellbore integrity. In the present study, experimental and numerical investigations are carried out to analyze the cement hydration in a wide range of temperatures. Then, a coupled model is established considering the multi-field coupling mechanisms between horizontal wells and the hydrate reservoir during well cementing. In the proposed model, the cement hydration, phase change of hydrate, and the multiphase flow in porous hydrate layer are considered. The cement hydration process, transient temperature and pressure distributions, and the hydrate phase change are analyzed by numerical simulations. Results show that the temperature of wellbore and hydrate increases rapidly. The saturation of the hydrate layer within the region 3 times of wellbore diameter decreases significantly. The pressure at the wellbore-hydrate layer interface increases significantly, which may lead to gas penetration into the wellbore. Moreover, threats imposed by the premature dissociation of hydrate last even for a long period after well cementing.

Physically-Data Driven Approach for Predicting Formation Leakage Pressure: A Dual-Drive Method

Formation leak-off pressure, which sets the upper limit of the safe drilling fluid density window, is crucial for preventing wellbore accidents and ensuring safe and efficient drilling operations. The paper thoroughly examines models of drilling physics alongside artificial intelligence techniques. The study introduces a dual-driven method for predicting reservoir pore pressure by integrating long short-term memory (LSTM) and backpropagation (BP) neural networks, where the core component is the LSTM-BP neural network model. The input data for the LSTM-BP model include wellbore diameter, formation density, sonic time, natural gamma, mud content, and pore pressure. The study demonstrates the practical application of the method using two vertical wells in Block M, employing the M-1 well for training and the M-2 well for validation. Two distinct input layer configurations are devised for the LSTM-BP model to evaluate the influence of formation density on prediction accuracy. Notably, Scheme 2 omits formation density as a variable in contrast to Scheme 1. The study’s results indicate that, for input layer configurations corresponding to Scenario 1 and Scenario 2, the LSTM-BP model exhibits relative error ranges of (−2.467%, 2.510%) and (−6.141%, 5.201%) on the test set, respectively. In Scenario 1, the model achieves mean squared error (MSE), mean absolute error (MAE), and R-squared (R2) values of 0.000229935, 0.011198329, and 0.92178272, respectively, on the test set. Conversely, for Scenario 2, the model demonstrates a substantial escalation of 992.393% and 240.674% in MSE and MAE, respectively, compared to Scenario 1; however, R2 diminishes by 66.920%. Utilizing the trained LSTM-BP model, predictions for formation lost pressure in Well M-2 reveal linear correlation coefficients of 0.8173 and 0.6451 corresponding to Scenario 1 and Scenario 2, respectively. These findings imply that the predictions from the Scenario 1 model demonstrate stronger alignment with results derived from formulaic calculations. These observations remain consistent for both the BP neural network algorithm and the random forest algorithm. The aforementioned research results not only highlight the elevated predictive precision of the LSTM-BP model for intelligent prediction of formation lost pressure, a product of this study, thereby furnishing valuable data points to enhance the security of drilling operations in Block M, but also underscore the necessity of deliberating both physical relevance and data correlation during the selection of input layer variables.

Well Testing Analysis Method and Practice for Low Permeability Gas Reservoirs

With the gradual maturity of well testing interpretation theory, some scholars have conducted research on vertical well testing models, horizontal well testing models, and inclined well testing models for fractured and vuggy reservoirs, and plotted typical well testing curves. However, during the drilling process, the wellbore is usually connected to both the fractures and the reservoir matrix, resulting in a dual permeability situation where the fractures and matrix simultaneously supply fluid to the wellbore. Based on this, some scholars have established a horizontal well dual hole dual permeability testing model, a vertical well three hole dual permeability testing model, and a horizontal well three hole dual permeability testing model, making the results of well testing interpretation more reasonable and reliable. For the well testing analysis of inclined wells in fractured and vuggy reservoirs, the existing inclined well models only consider the three hole single permeability situation where the fractures are connected to the wellbore. There is little research on the three hole dual permeability well testing model where the inclined well matrix and fractures supply the wellbore simultaneously. Therefore, based on previous research, this article establishes and solves a well testing model for inclined wells with three pores and dual permeability, using the effective wellbore diameter and the principle of Duhame superposition, taking into account the bottom hole pressure effect, and draws sample curves for the analysis of inclined wells in fractured and vuggy reservoirs. This provides a reference for the analysis of inclined wells in fractured and vuggy reservoirs.

Study on the Influence Law of Temperature Profile of Water Injection Well

Due to the lack of knowledge on the influence law of the temperature profile of layered water injection wells, it is still highly challenging to quantitatively diagnose the water injection profile of layered water injection wells using distributed optical fiber temperature sensing (DTS). In this paper, a temperature profile prediction model for layered water injection wells has been developed by considering the micro-thermal effect and non-isothermal reservoir seepage. The influence of various single-factor changes on the temperature profile of layered water injection wells is simulated and analyzed. Orthogonal experiment analysis results demonstrate that the sensitivity of different factors on wellbore temperature from strong to weak is the injection temperature of the water, injection time, water injection rate, wellbore diameter, formation thermal conductivity, wellbore trajectory, and the permeability of injection formations (Tinj＞t＞Qinj＞D＞Kt＞θ＞k). The injection temperature of water, injection time, and water injection rate are the dominant factors affecting the temperature profile of water injection wells. The results of this paper provide a theoretical foundation for the accurate evaluation of the water injection profile and water injection scheme optimization for the layered water injection wells.

Numerical simulation inversion of creep laws of composite salt layers based on reaming while drilling

The composite salt layer of the Kuqa piedmont zone in the Tarim Basin is characterized by deep burial, complex tectonic stress, and interbedding between salt rocks and mudstone. Drilling such salt layers is associated with frequent salt rock creep and inter-salt rock lost circulation, which results in high challenges for safe drilling. Especially, the drilling and completion processes of the salt-gypsum layers of one typical group are found with frequent downhole accidents and complex issues, such as hole shrinkage, sticking, well kick, and lost circulation, which leads to high difficulties in delivering desirable cementing quality and severely hinders the subsequent safe rapid drilling. Reaming while drilling can effectively enlarge the wellbore diameter, provide extra tolerance for creep shrinkage of salt layers, and ultimately help to shorten drilling time, reduce accidents and complex issues, and improve the lifecycle of wells. In this research, a numerical simulation method was developed to invert the creep laws of composite salt layers, based on reaming while drilling. It is generally believed that the dislocation creep mechanism is dominant in coarse-grained salt rocks, while the pressure solution creep mechanism is dominant in fine-grained salt rocks. Here a well in the Dabei area was taken as an example and the numerical simulation of hole shrinkage at the wellbore scale was performed, based on the actual data before and after reaming and also the theoretical analysis of the two salt rock creep mechanisms and corresponding laws. Furthermore, the inversion results were validated using field data. This research discussed the selection of creep parameters and their variation, in cases of the dominance of the dislocation creep and pressure solution creep mechanisms. This presented method can accurately predict the creep behavior of salt layers and can be used as an effective supplement tool for other test methods like laboratory experiments.

Dynamic well killing method based on Y-tube principle when the drill bit is off-bottom

The design of dynamic well killing parameters lacks theoretical support because the U-tube principle is not applicable while drilling bit is not at the well bottom. We present the Y-tube principle and establish a gas and liquid two-phase flow model with the killing fluid backflow and zero net liquid flow theory in wellbore below the drill bit. A dynamic well killing theory is proposed, and the variations of the well killing parameters are revealed. The results were as follows. (1) The Y-tube was composed of an annular part above the bit, a drillstring part, and a wellbore part below the bit. Gas–liquid flow models in those three parts were established to accurately simulate the dynamic well killing process when the drill bit was off-bottom. (2) Based on these models, the dynamic inflow and outflow curves during the killing period were obtained. The variations of the dynamic well killing parameters were analyzed by comparing the two curves. (3) With the increase of pressure, the critical gas velocity of blowout decreases, while the temperature, density and viscosity of the killing fluid do the opposite. With the increase of temperature, density and viscosity, and the decrease of the wellbore diameter, the bottom hole pressure increases. And it decreases with the decrease of the distance between the bit and wellhead. (4) Considering the actual well killing conditions, it is recommended to increase the critical blowout velocity by increasing the killing fluid surface tension and density, and to change the killing fluid density and viscosity so that the dynamic outflow curve is always above the dynamic inflow curve or the dynamic outflow curve is always above the formation pressure. As a result, the dynamic well killing will be successful when the bit is not at the well bottom.