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Abstract Managed pressure cementing (MPC) is a new technology based on managed pressure drilling, which has a greater advantage in facing narrow density window formations. However, the existing pressure prediction models during MPC injection stage consider fewer factors and have lower accuracy. To this end, combined with the characteristics of the injection stage, a predictive model of the distribution of annular fluid type was first proposed. Then, based on the experimental results, fluid density and rheology as a function of temperature and pressure were fitted. The governing equation of temperature‐pressure field was established. Eventually the fluid performance parameters–temperature–pressure coupling prediction model was developed in this paper. By comparing the predicted pump pressure with the measured pump pressure, the maximum relative error is not more than 10%. Using this model, the fluid type distribution, temperature field distribution, and pressure field distribution were investigated. The results indicated that the distribution of fluid types in the wellbore presented a complex variation, with up to 10 fluids in the casing and up to five fluids in the annulus. The trend of temperature field is complex, with three turning points. The larger the formation temperature gradient, the higher the fluid temperature in the annulus. The influence law of fluid heat conduction coefficient is reversed at 6750 m. Decreasing drilling fluid density will trigger gas channeling, while increasing drilling fluid density will increase the risk of fracturing formation, and safe operation can be realized by MPC. The variation of the static pressure in the casing is more complicated than in the annulus and the annular circulation pressure in the eccentric casing is smaller than that of the concentric casing, which is due to the smaller annular friction pressure. This study can provide a theoretical basis for the prediction of hydrodynamic parameters during the MPC injection stage.

A multiphase flow model is an important foundation for well control simulation. In this paper, a multiphase variable mass flow model considering sudden density change was developed for variable gradient managed pressure drilling (MPD) and it was solved by finite difference method (FDM). Further, the model was used to simulate the whole process of well control based on constant bottom-hole pressure for variable gradient MPD. In this way, the advantages of the new gas kick detection method compared with the mud pit increment detection method and the variation laws of key parameters in the whole well control process were investigated. The results indicate that under the condition of small gas rate, the new gas kick detection method is better than the mud pit increment detection method because of its time savings. In the process of gas discharge, the wellbore pressure fluctuates due to the influence of gas expansion, sudden density changes at the separator position and annulus diameter changes at the casing shoe and mud line. The time when the back pressure reaches the maximum lags behind the time when the gas front reaches the wellhead. The mud pit increment increase rate when the gas front reaches the separator position is significantly higher than that in the early stage of gas kick detection.

Drilling into fractured formations can easily lead to mud loss, which significantly affects drilling efficiency and increases drilling costs. In high-temperature and high-pressure environments, changes in mud properties render mud loss more uncontrollable. On the basis of a mud performance test in a high-temperature and high-pressure environment, and considering the time-varying characteristics of wellbore temperature and pressure and the distribution law of fracture temperature and pressure, a coupling model of temperature and pressure in the wellbore and fracture was established in this study. The developed model was solved numerically using the finite difference approximation, and the characteristics of the mud loss were analyzed. The effects of geothermal gradient, fracture parameters (fracture width, fracture length, and deformation capacity), mud properties (viscosity, yield value, and specific heat capacity), and operating conditions on mud loss were investigated. The model was validated using field measurement-while-drilling tool data of the LD1 well in the South China Sea. The results show that the average errors between the calculated temperature and pressure results of the numerical model and the actual data are 2.45% and 0.57%, respectively, which proves that the model has high accuracy in the prediction of the bottom hole temperature and pressure. A comparison of the predicted data of mud loss with the actual measured data indicates that the average error of the mud leakage model is 4.23%. This also demonstrates that the model has a high accuracy in predicting mud loss. In addition, the results show that the mud performance changes significantly under high-temperature and high-pressure conditions, which has a significant influence on mud loss. The geothermal gradient affected the mud properties and thus significantly affected the mud loss characteristics. The larger the mud pumping rate, the larger the bottomhole pressure difference and the more serious the mud loss. Blindly increasing mud viscosity is not advisable because it may lead to more serious losses. With an increase in the mud yield value, the mud flow resistance in the fractures can be significantly increased to inhibit mud loss. The larger the mud-specific heat capacity, the less mud loss is affected by the temperature. With an increase in the fracture width, the degree of mud loss gradually decreased. The larger the fracture length and deformation capacity, the more serious the mud loss. The fracture length and width could be inverted using the developed model.

Aimed at the problem of gas flurries in carbon dioxide (CO2) geologic sequestration in the wellbore, this paper proposes a sealing method in which the downhole casing is processed with threaded grooves and then plugged with a low-melting-point alloy plug. Based on this method, a small-scale experimental setup was developed for alloy plug molding and gas sealing in this study. Molding and gas sealing experiments with Sn58Bi alloy plugs inside casings with different surface morphologies were carried out. The gas leakage pathway was determined. The microstructure of the interface between the alloy plug and casing was analyzed using an optical microscope. The influence of the inner surface roughness, threaded groove, length-to-diameter ratio, and ambient temperature on the gas sealing performance of the alloy plugs was analyzed. The experimental results show that, with an increase in ambient temperature, the gas sealing performance of the casing increases significantly; when the inner surface of the casing is processed through threaded grooves, the gas sealing performance is better than with smooth hole casing; the gas sealing performance of the alloy plug presents an obvious linear positive correlation with their length-to-diameter ratio. This research provides theoretical support for downhole CO2 plugging using Sn58Bi in the casing.

Abstract Horizontal wells with a slim hole (HW‐SH), characterized by high productivity, high environmental protection, and low cost are gradually being introduced into oil and gas extraction processes in high‐temperature and high‐pressure formations. However, the HW‐SH annulus is narrow, and the distributions of temperature and pressure in the wellbore are very different from those of conventional horizontal wells. Furthermore, the mud properties change under the influence of high temperature and pressure. In this study, a numerical model of the transient temperature‐pressure coupling field in an HW‐SH wellbore was developed based on high‐temperature and high‐pressure performance tests of mud, combined with the characteristics of a narrow annulus in HW‐SH. Subsequently, the effects of the ground temperature gradient, displacement, drill pipe speed, annulus size, and joint size on the temperature‐pressure coupling field were analyzed. Measured data from the HW‐SH drilled in the Mahu field in China were used to validate the developed model. The results showed that the ground temperature had a significant effect on the mud density and rheological properties. As the temperature increased, the mud density decreased, and its rheological properties improved. Although pressure also has a large effect on density, it has a negligible effect on the rheological properties of the mud. The coupled temperature‐pressure field model for HW‐SH considering the effects of the temperature and narrow annulus can predict the annulus temperature and pressure with an accuracy of up to 97%. The ground temperature gradient has the greatest influence on the HW‐SH annular temperature, larger than that of the displacement. In addition, the annular size, rotation speed of the drill pipe, and joint size have almost no influence on the annular temperature. Compared to those of conventional horizontal wells, the rotational speed, annulus size, and joint size of the HW‐SH have a greater impact on the annulus pressure.

Casing is inevitably damaged during perforation operation, and the perforation parameters will have a significant impact on the degree of casing damage, which will directly affect the stability of casing structure in the process of hydraulic fracturing. A three-dimensional numerical model, which was composed of perforating charge, casing–cement sheath, and formation and consistent with the engineering practice, was established, considering the dynamic characteristics of materials in the process of explosion impact. The numerical simulation results were verified by physical model tests and showed that the stress superposition between adjacent perforations increases the damage degree of casing. Perforation density and phase angle directly affect the range of stress superposition area, with the increase of perforation density or decrease of phase angle, the damage area and damage coefficient of casing are increasing. Based on the results of numerical simulation, an innovative perforation parameter optimization method considering casing yield strength was proposed, which could effectively reduce the stress superposition area between adjacent perforations and keep casing damage within a reasonable range. Finally, perforation parameter optimization based on real wells was carried out, and analysis results showed that the casing stress was lower than the yield strength after parameter optimization, which could ensure the stability of the casing. The research results can provide an important reference for the optimization of perforation design and field operation.

The special temperature-pressure environment and narrow safety density window of the deepwater formation pose a great challenge to wellbore pressure control during drilling. The downhole variable-gradient drilling method is an effective idea to solve this challenge. However, previous studies mainly focused on the theoretical adaptability analysis of this method, while the experimental feasibility verification has not yet been reported. In this paper, based on the segmental control principle of wellbore fluid density, we set up an indoor physical experiment system to investigate the feasibility of variable-gradient drilling method based on downhole cyclone separator. Using this experimental system, we investigated the effect of drilling fluid physical parameters, hollow glass microsphere (HGMS) performance parameters and engineering parameters on the separator separation efficiency, wellbore pressure gradient and HGMS slip rate. The experimental results revealed that the separator could separate the HGMSs into the annulus from the fluid mixture in the drill pipe. The separation efficiency increased with the increase in the HGMS diameter, HGMS concentration and flow rate, while decreased with the increase in the HGMS density and fluid viscosity. The HGMS density and HGMS concentration were the key factors affecting the annulus pressure gradient value, and the separator separation efficiency was the main factor determining the difference of the annulus pressure gradient. The HGMS slip rate was highly sensitive to its diameter and fluid viscosity, and a combination of optimal HGMS diameter and fluid viscosity could avoid the drilling risk caused by the HGMS slippage. Therefore, the variable-gradient drilling method based on downhole separator is feasible, which is able to create two or more pressure gradients in the annulus. This study could provide guidance for the optimization of key parameters and the development of equipment related to the variable-gradient drilling.

Abstract Sand deposition in the wellbore is one of the most common problems in oil–gas and hydrate exploitation work. A detailed understanding of the migration characteristics of the sand bed and accurate prediction of the starting velocity of the sand bed are key aspects of effective sand carrying. Therefore, this study conducted a large‐scale outdoor gas–water–sand three‐phase flow experiment. The effects of critical factors such as flow pattern, sand size, sand bed height, and pipe inclination angle on sand bed startup velocity and migration were studied experimentally. The experimental results indicated that during the startup process of the sand bed, sand particles exhibited three states: rolling, jumping, and suspension. During the experiment, the sand bed morphology included a static bed, rolling bed, jumping bed, and suspension bed. Compared to a stratified flow, intermittent flow and agitated flow were more beneficial for the startup velocity of sand beds. An increase in pipe inclination also reduced the starting velocity of the sand bed. With an increase in sand size, the startup velocity of the sand bed increased correspondingly. However, there was no significant influence on the migration morphology of the sand bed. Additionally, the greater the thickness of the sand bed, the lower the starting velocity of the sand bed. Based on the stress states of sand grains, in combination with experimental data, this study used least‐squares estimation to establish a prediction model for the startup velocity of sand beds. The model prediction results were in good agreement with the experimental data. This study will provide a basis for predicting the startup velocity of sand beds during the gas–liquid two‐phase sand‐carrying process.

Abstract Compound percussive drilling technology is a new method to improve the rock‐breaking efficiency in deep hard formation. In order to study the rock‐breaking mechanism of compound impact drilling, the thermal‐structure coupling simulation of the dynamic rock‐breaking process with a single PDC cutter was investigated by using ABAQUS software. The influence of impact parameters on the rock‐breaking performance and cutting temperature was analyzed. The results proved that the compound impact load changes the rock failure mode and improves the rock‐breaking efficiency. Compared with steady load cutting, the rock broken volume under compound impact increased by 7.5%, and the mechanical specific energy (MSE) decreased by 12.3%. As the axial impact load amplitude increases, the MSE increases gradually. With an increase in torsional impact load amplitude and impact frequency, the MSE decreases first and then increases, and the optimal torsional static load ratio is 0.3, and the optimal impact frequency is 30 Hz. In addition, the cutting temperature of the compound percussive drilling is higher than that of the steady load cutting, and it increases with the impact load amplitude and decreases with the frequency. For the three impact load waveforms—sine, triangle, and square in this paper, the rock‐breaking efficiency under the condition of sine waveform is the largest when the dynamic amplitude of the pulse force is fixed, and the cutting temperature under the condition of square waveform is the highest. Finally, based on the analysis of the rock‐breaking mechanism, a novel compound percussive drilling tool was designed and tested in the field.

Improving the rock-breaking efficiency of hard rock formation has always been of concern in drilling. Compound impact drilling technology is a new method to achieve efficient crushing of hard rock by exerting axial and torsional impacts on the drilling bit. In this study, to investigate the dynamic rock-breaking process and mechanism under compound impact, a numerical model was developed based on cohesive elements. Dynamic impact tests on sandstone were conducted to verify the effectiveness of the method. Then, the dynamic rock-breaking process under compound impact was simulated using the proposed model. Finally, the effects of impact parameters and cyclic loading on the rock-breaking performance were systematically studied. The results indicate that the stereoscopic crushing effect of rock can be achieved under compound impact. The amount of broken rock increases with the increase in the impact load amplitude and impact loading times, whereas both the impact angle and duration have an optimal range. When the impact angle is 30°, the impact duration is 2.5 ms, the amount of broken rock is maximum. A novel compound impact drilling tool was designed based on the analysis of the rock-breaking mechanism, the laboratory and field tests were carried out and the parameters were optimized.

Dual-gradient drilling technology is being increasingly used in formations with narrow pressure margins. For dual-gradient drilling based on downhole separation, hollow spheres are separated into the annulus at the separator position, resulting in variable mass flow in the wellbore. Thus, existing heat transfer models are no longer suitable for describing wellbore temperature profiles in dual-gradient drilling. This study focused on developing a wellbore heat transfer model that fully considers separated hollow spheres entering the annulus, complex casing programs, and heat sources, for dual-gradient drilling based on downhole separation. The model was solved using an iterative method. Then, the accuracy of the model was verified using temperature data measured from two wells. Finally, the difference in the annular temperature distributions between dual-gradient drilling and conventional single-gradient drilling were investigated, as were the wellbore heat transfer characteristics for dual-gradient drilling. The following major conclusions were drawn: (1) for dual-gradient drilling based on downhole separation, at the separator location, the annular fluid temperature does not decrease, but rather increase in the flow direction because of the inflow of hollow spheres; (2) a clear inflection point exists in the annular fluid temperature curve at the location where the separator would be; (3) the magnitude of the mutation of the temperature curve at the inflection point is considerably affected by the heat capacities of the hollow spheres and the pure drilling fluid; (4) under the same change in separation efficiency, distance between the bit and separator, flow rate, and thermal conductivity of formation, the variation range of the fluid temperature at the bottom hole is greater than that at the wellhead.

Abstract In deepwater drilling, accurate prediction of wellbore gas‐liquid two‐phase flow behavior is significant for gas kick detection and well‐control treatment. In this study, a new transient gas‐liquid two‐phase flow model was developed to simulate the wellbore gas‐liquid two‐phase flow during gas kick in deepwater dual‐gradient drilling based on downhole separation. This model accounts for the impact of a sudden change in density on gas‐liquid flow behavior. The transient model was solved using the finite‐difference method. The accuracy and stability of the model were verified using data measured from a full‐scale experimental well. Using this model, the differences in the apparent liquid velocity and the flow rate at the annular outlet during gas kick were compared between deepwater dual‐gradient drilling and conventional single‐gradient drilling. Additionally, the influences of numerous factors on variations in flow rate at the annular outlet were also studied. A new method of early gas kick detection was proposed for deepwater dual‐gradient drilling based on downhole separation.

An innovative perforation method of interlaced fixed perforation was put forward based on the analysis of the characteristics of fractures in various periods of perforation and conventional perforation modes. By conducting a large-scale perforation shooting experiments, we investigated the morphology, propagation mechanism and propagation law of the near-wellbore fractures generated during perforating processes under different fixed angle and interlaced angle combinations, and discussed the control method of near-wellbore fractures in different types of unconventional oil and gas reservoirs. The experimental results show that: (1) The interlaced fixed perforation strengthens the connectivity between the perforation tunnels not only in the same fixed plane but also in adjacent fixed planes, making it likely to form near-wellbore connected fractures which propagate in order. (2) Three kinds of micro-fractures will come up around the perforation tunnel during perforation, namely type I radial micro-fracture, type II oblique micro-fracture and type III divergent micro-fracture at the perforation tip, which are interconnected into complex near-wellbore fracture system. (3) Different types of perforation bullets under different combinations of fixed angles and interlaced angles result in different shapes of near-wellbore fractures propagating in different patterns. (4) By using the interlaced perforation on fixed planes, arranging fixed planes according to the spiral mode or the continuous “zigzag” shape, the desired near-wellbore fractures can be obtained, which is conducive to the manual control of main fractures in the fracturing of unconventional or complex conventional reservoirs. Key words: interlaced fixed perforation, near-wellbore fracture, physical simulation, propagation law, control method, shale, hydraulic fracturing

Abstract Casing shear deformation has become a prominent problem in the process of completion in shale gas wells. It was believed that the slide of strike‐slip fault induced by multistage fracturing was the main reason. This paper presented a new numerical investigation for evaluating the casing inner diameter after strike‐slip fault sliding based on the microseismic data. A 3D finite element model, considering the mechanical anisotropy of shale and heat‐fluid‐solid coupling effect during multistage fracturing, was developed to calculate the variation of casing inner diameter after fault sliding under different engineering and geological conditions. The calculation result was verified by comparison with the measurement result of the multi‐finger caliper survey. Sensitivity analysis was carried out and the results showed that decreasing the sliding distance, maintaining high pressure, increasing the casing thickness, and increasing the elasticity modulus and decreasing the Poisson ratio of cement sheath were beneficial to protect the casing integrity. Finally, the engineering verification demonstrated that the numerical method has an accuracy up to 85.9%. Numerical model in this study was expected to provide a better understanding of casing shear deformation and an evaluation method of casing inner diameter after fault sliding during multistage fracturing in shale gas wells.

To ensure safe drilling with narrow pressure margins in deepwater, a new deepwater dual-gradient drilling method based on downhole separation was designed. A laboratory experiment was conducted to verify the effectiveness of downhole separation and the feasibility of realizing dual-gradient in wellbore. The calculation of dynamic wellbore pressure during drilling was conducted. Then, an optimization model for drilling parameters was established for this drilling method, including separator position, separation efficiency, injection volume fraction, density of drilling fluid, wellhead back pressure and displacement. The optimization of drilling parameters under different control parameters and different narrow safe pressure margins is analyzed by case study. The optimization results indicate that the wellbore pressure profile can be optimized to adapt to the narrow pressure margins and achieve greater drilling depth. By using the optimization model, a smaller bottom-hole pressure difference can be obtained, which can increase the rate of penetration (ROP) and protect reservoirs. The dynamic wellbore pressure has been kept within safe pressure margins during optimization process, effectively avoiding the complicated underground situations caused by improper wellbore pressure. Key words: narrow pressure margins, deepwater dual-gradient drilling, drilling parameters, optimization model, maximum drilling depth

Organic rich dark shale of Q Formation can be found in many areas (e.g., in the North of S Basin). The shale target stratum is easy to hydrate and often undergoes spallation. Therefore, centering the casing in the horizontal section of the irregular borehole is relatively difficult. Similarly, achieving a good cement flushing efficiency under complex borehole conditions is a complex task. Through technologies such as centralizer, efficient preflushing, multi-stage flushing and ductile cement slurry, better performances can be achieved. In this study, it is shown that the cementing rate in the DY2H horizontal section is 97.8%, which is more than 34% higher than that of adjacent wells. This cementing matching technology for sidetracking horizontal wells can be used to improve the cementing quality of continental shale and provides a reference for future applications in this field. [ABSTRACT FROM AUTHOR]

An accurate analysis of casing stress distribution and its variation regularities present several challenges during hydraulic fracturing of shale gas wells. In this paper, a new analytical mechanical-thermal coupling method was provided to evaluate casing stress. For this new method, the casing, cement sheath, and formation (CCF) system was divided into three parts such as initial stress field, wellbore disturbance field, and thermal stress field to simulate the processes of drilling, casing, cementing, and fracturing. The analytical results reached a good agreement with a numerical approach and were in-line with the actual boundary condition of shale gas wells. Based on this new model, the parametric sensitivity analyses of casing stress such as mechanical and geometry properties, operation parameters, and geostress were conducted during multifracturing. Conclusions were drawn from the comparison between new and existing models. The results indicated that the existing model underestimated casing stress under the conditions of the geostress heterogeneity index at the range of 0.5–2.25, the fracturing pressure larger than 25 MPa, and a formation with large elastic modulus or small Poisson’s ratio. The casing stress increased dramatically with the increase of in situ stress nonuniformity degree. The stress decreased first and then increased with the increase of fracturing pressure. Thicker casing, higher fluid temperature, and cement sheath with small modulus, large Poisson’s ratio, and thinner wall were effective to decrease the casing stress. This new method was able to accurately predict casing stress, which can become an alternative approach of casing integrity evaluation for shale gas wells.

The purpose of this paper is to discuss the variation of wellbore temperature and bottom-hole pressure with key factors in the case of coupled temperature and pressure under multi-pressure system during deep-water drilling circulation. According to the law of energy conservation and momentum equation, the coupled temperature and pressure calculation model under multi-pressure system is developed by using the comprehensive convective heat transfer coefficient. The model is discretized and solved by finite difference method and Gauss Seidel iteration respectively. Then the calculation results of this paper are compared and verified with previous research models and field measured data. The results show that when the multi-pressure system is located in the middle formation, the temperature of the annulus corresponding to location of the system is the most affected, and the temperature of the other areas in annulus is hardly affected. However, when the multi-pressure system is located at the bottom hole, the annulus temperature is greatly affected from bottom hole to mudline. In addition, the thermo-physical parameters of the drilling fluid can be changed by overflow and leakage. When only overflow occurs, the annulus temperature increases the most, but the viscosity decreases the most. When only leakage occurs, the annulus temperature decreases the most and the viscosity increases the most. However, when the overflow rate is greater than the leakage rate, the mud density and bottom-hole pressure increase the most, and both increase the least when only leakage occurs. Meanwhile, bottom-hole pressure increases with the increase of pump rate but decreases with the increase of inlet temperature. The research results can provide theoretical guidance for safe drilling in complex formations such as multi-pressure systems.

Casing shear deformation has become a serious problem in the development of shale gas fields, which is believed to be related to fault slipping caused by multistage fracturing, and the evaluation of the reduction of a casing’s inner diameter is key. Although many fault slipping models have been published, most of them have not taken the fluid-solid-heat coupling effect into account, and none of the models could be used to calculate the reduction of a casing’s inner diameter. In this paper, a new 3D finite element model was developed to simulate the progress of fault slipping, taking the fluid-solid-heat coupling effect during fracturing into account. For the purpose of increasing calculation accuracy, the elastoplastic constitutive relations of materials were considered, and the solid-shell elements technique was used. The reduction of the casing’s inner diameter along the axis was calculated and the calculation results were compared with the measurement results of multi-finger caliper (MFC) surveys. A sensitivity analysis was conducted, and the influences of slip distance, casing internal pressure, thickness of production and intermediate casing, and the mechanical parameters of cement sheath on the reduction of a casing’s inner diameter in the deformed segment were analyzed. The numerical analysis results showed that decreasing the slip distance, maintaining high pressure, decreasing the Poisson ratio of cement sheath, and increasing casing thickness were beneficial to protect the integrity of the casing. The numerical simulation results were verified by comparison to the shape of MFC measurement results, and had an accuracy up to 90.17%. Results from this study are expected to provide a better understanding of casing shear deformation, and a prediction method of a casing’s inner diameter after fault slipping in multistage fracturing wells.

Accurate prediction of the hoop stress distribution of the cement sheath and its variation regularities during volume hydraulic fracturing in shale formations is of great significance for maintaining the wellbore integrity of shale gas horizontal wells. A finite element model of casing-cement sheath-formation system (CCFS) coupling between stresses and temperature was established through a staged finite element method based on the elastic anisotropy of shale. With this new model, the effects of operation parameters and formation mechanical property changes on the cement sheath hoop stress during the multi-stage hydraulic fracturing process were analyzed, and the results were compared with the conventional model. The results revealed that the increase of the temperature of the fracturing fluid could reduce the hoop stress of the cement sheath, which decreased gradually with the decreasing elastic modulus of the cement sheath, and eventually changed to compressive stress from tensile stress. The hoop tensile stress of the cement sheath increases first and then tends to decrease with the increasing internal casing pressure, the larger the local formation stress, the smaller the pore pressure and the smaller the hoop tensile stress of the cement sheath it preforms. The findings of this paper are of great guiding significance to the research of the cement sheath stress variations during volume fracturing in shale formations and to the optimization of fracturing design.