Annular Fluid Research Articles

Thermo-fluid characteristics and exergy analysis of a twisted tube helical coil.

In the present investigation, the exergy of an innovative technique involving the integration of curved helical tubes with twisted passages was experimentally presented. This technique aims to improve the thermofluid characteristics by involving the swirl intensity of fluid flow in a twisted tube helical coil (TTHC). Six identical geometries with different pitch ratios Υ of 36mm, 54mm, and ∞ (smooth/no twisted) were experimentally explored at two different inner tube profiles of triangular and square cross-sections in counter flow arrangements. The experimental runs were carried out at 10,300 ≤ Rei ≤ 37,800 and 2400 ≤ Reo ≤17,600 for both the inner and annulus fluids, respectively. The results showed that the Nusselt number, Nu, increased by 39.6% and 41.5% for triangular and square inner twisted cross-section profiles, respectively, at a [Formula: see text] of 36mm at the expense of increasing f by 37.6% and 60.7%, respectively. The results also showed that the thermal performance factor reached 1.3 and 1.25 for a [Formula: see text] of 36mm for the triangular and square inner twisted tube profiles, respectively. A comprehensive study is performed to analyze the TTHC from thermal, frictional, and exergetic viewpoints. New correlations for expecting the annulus Nuo and fo are presented.

Simulation Analysis of the Annular Liquid Disturbance Induced by Gas Leakage from String Seals During Annular Pressure Relief

Due to the failure of string seals, gas can leak and result in the abnormal annulus pressure in gas wells, so it is necessary to relieve the pressure in gas wells. In the process of pressure relief, the leaked gas enters the annulus, causes a the great disturbance to the annulus flow field, and thus reduces the protection performance of the annular protection fluid in the string. In order to investigate the influence of gas leakage on the annular flow field, a VOF finite element model of the gas-liquid two-phase flow disturbed by gas leakage in a casing was established to simulate the transient flow field in the annular flow disturbed by gas leakage, and the influences of leakage pressure differences, leakage direction, and leakage time on annular flow field disturbance and wall shear force were analyzed. The analysis results showed that the larger leakage pressure difference corresponded to the faster diffusion rate of the leaked gas in the annulus, the faster the flushing rate of the leaked gas against the casing wall, and a larger shear force on the tubing wall was detrimental to the formation of the corrosion inhibitor film on the tubing wall and casing wall. Under the same conditions, the shear action on the outer wall of tubing in the leakage direction of 90° was stronger than that in the leakage directions of 135° and 45° and the diffusion range was also larger. With the increase in leakage time, leaked gas further moved upward in the annulus and the shear effect on the outer wall of tubing was gradually strengthened. The leaked acid gas flushed the outer wall of casing, thus increasing the peeling-off risk of the corrosion inhibitor film. The study results show that the disturbance law of gas leakage to annular protection fluid is clear, and it was suggested to reduce unnecessary pressure relief time in the annulus to ensure the safety and integrity of gas wells.

Predicting pressure loss of turbulent non-Newtonian fluids in annuli under temperature and pipe rotation effects using optimization algorithms

Accurate estimation of frictional pressure loss in an annulus is crucial for selecting appropriate pump systems, determining horsepower requirements, and controlling hole cleaning. Generally, when calculating the friction factor, the temperature of the fluid and the rotation of the inner pipe are not considered, which can lead to errors in estimating the pressure difference in the annulus. In this study, to ensure accurate pressure drop calculations, the effects of temperature and inner pipe rotation, along with other parameters, were included. An extensive experimental study was conducted at Izmir Katip Celebi University’s Flow Loop using two Carboxymethyl cellulose (CMC) solutions, across various fluid velocities, fluid temperatures, diameter ratios, and inner pipe rotation speeds. A dimensional analysis was performed to identify the parameters that affect friction factors in the annulus. Finally, friction factor equations were developed based on the experimental data using optimization algorithms such as interior point (fmincon), genetic, minimax, and simulated annealing. The findings showed that the predictions from all the algorithms tested in the study closely matched the experimental results; however, the interior point algorithm (fmincon) provided the best performance, with an average absolute percentage error of 9.4%.

Peristaltic Flow of Jeffrey Fluid in an Inclined Porous Tube with Multi-Thrombosis

The fact that multiple thrombosis opposes blood flow and flow is rare in blood vessels is refined to a normal condition with catheter application. The inner surface of the circular blood arteries may not be smooth in the majority of diseased instances. Additionally, the small blood vessel peristalsis mechanism is formed. In this paper, we discuss a mathematical model for the flow of biological fluid (blood) in a circular tube with multi-thrombosis considered under peristaltic wave propagation. The blood flow in this tube is restricted due to the many thromboses present, and the flow is redesigned with the aid of a catheter. We model this non-Newtonian blood flow issue for Jeffrey fluid. In most pathological cases, the inner surface of the circular blood vessels may not be smooth. Further, the mechanism of the peristalsis is established for small blood vessels. Because of this biological phenomenon, the peristaltic movement of Jeffrey fluid in a porous annulus with slip is examined. Equations that govern energy and momentum are solved exactly, and graphical interpretation is made using mathematical software. Streamline graphs show the many thromboses that increase in height. The wall shear stress graphs show a sinusoidally advancing wave with peaks and dips of different amplitudes. This tube's unique crest and trough amplitude are caused by the presence of multiple thromboses. We obtained the impact of the pressure gradient on the permeability parameter (β). The pressure gradient falls as the permeability parameter rises.

Numerical study on hydrogen desorption performance of a new MgH2 solid-state hydrogen storage device

To explore the factors affecting the hydrogen evolution performance of a new MgH2 solid-state hydrogen storage heat exchanger, this paper designs the MgH2 solid-state hydrogen storage device. The study numerically investigates the influence of operating parameters and structural parameters on the hydrogen release reaction. The results demonstrate that the hydrogen desorption rate increases as the pressure decreases from 0.3 MPa to 0.1 MPa. Moreover, the hydrogen evolution reaction rate significantly rises with an increase in the inlet temperature of the heat transfer fluid (HTF) from 600 K to 700 K. Similarly, the rate of hydrogen evolution reaction increases with an increase in the flow rate of the HTF from 0.5 m/s to 1.25 m/s. The hydrogen evolution reaction time can be notably reduced by increasing the thickness of the annular HTF layer. Compared to no annular fluid layer, the completion time of the hydrogen desorption reaction is shortened by 558 s with a 5 mm thickness. The arrangement of heat exchanger pipes plays a crucial role in the hydrogen evolution reaction, and thus a comprehensive index M is defined to evaluate its influence. A higher M value indicates slower hydrogen release efficiency of the device. By optimizing the operating conditions, the hydrogen desorption time can be shortened by 93.4 %.

Coupling analysis of multi-annular temperature and pressure gradients in oil and gas wells considering fluid thermodynamic properties

A coupled prediction model for temperature and pressure is developed for the annulus of multiple casings to prevent damaging the integrity of oil and gas wells due to annular pressures. The complex structure of the oil and gas well requires dividing the calculation of the annular pressure into three stages based on the annulus level. The annular temperature and pressure gradients of the wellbore are then studied. The hydrostatic pressure changes of the annular fluid at different temperatures, pressures, and well depths are analyzed considering the influence of the isobaric expansion coefficient and isothermal compression coefficient in annular fluids. The pressure gradients of annular fluids A, B, and C with production time and well depth are discussed along with the deformation of production casings. Results show that the annular fluid density and hydrostatic pressure decrease with the increase of temperature, while they will increase with the increase of annular pressure. The annular pressure increases first and then decreases from the bottom of the well to the wellhead. The annular pressure increases the fastest in the early production stages.

Multi-Objective Optimization Study of Annular Fluid Flow Structure in Cordless Core Drilling Tools

Multi-Objective Optimization Study of Annular Fluid Flow Structure in Cordless Core Drilling Tools

Study on transient prediction method of dynamic underbalanced pressure after perforation detonation in ultra-deep wells

Dynamic underbalanced pressure creates a significant transient pressure difference between the upper and lower ends of the packer and the inner and outer walls of the string below the packer, which can lead to the failure of the packer, the tubing, and the casing and is one of the main reasons for the low success rate of the perforation-acidizing-testing combined technology in ultra-deep wells. A danger caused by the dynamic underbalanced pressure is increased rapidly with an increase in the well depth. Despite the fact that researchers have a well enough understanding of the applications and benefits of the dynamic underbalanced pressure, the mechanism of the wellbore failure caused by the dynamic underbalanced pressure is inadequate. Therefore, a pressure drop model of tubing-casing annulus fluid is established, and a seepage model of reservoir rock is given. A transient prediction method of the dynamic underbalanced pressure is developed by coupling the pressure drop model and the seepage model. Then, the determining factors, key nodes of the maximum value, and derivation and propagation laws of the dynamic underbalanced pressure are revealed. An influence study focusing on an ultra-deep well is conducted. The obtained results indicated that the dynamic underbalanced pressure describes a fast drop in the annulus fluid pressure caused by the fluid flow among the annulus, the perforating guns, and the perforation tunnels since the pressures in the perforating guns and the perforation tunnels are lower than the annulus pressure after the perforation detonation. The annulus fluid pressure can slowly recover and increase due to the fluid flow between the screens and the annulus and the fluid flow between the reservoir rock and the wellbore. The main form of the wellbore failure caused by the dynamic underbalanced pressure is the casing collapse deformation. Therefore, changing perforating conditions, wellbore conditions, and reservoir rock conditions can increase the maximum for the dynamic underbalanced pressure to improve the success rate of the combined technology. The research presented in this paper can provide a new understanding and prediction method of the dynamic underbalanced pressure.

Study of Retention of Drilling Fluid Layer on Annulus Wall during Cementing

To guarantee that the cement sheath has a sealing effect, it is best to replace the drilling fluid entirely and fill the annulus with cement slurry throughout the cementing process. A significant driving power and high stability at the interface between the cement slurry and drilling fluid are often necessary for achieving a high displacement efficiency. It is important that a comprehensive theoretical characterization is established on the thickness and location of drilling fluid retention and the conditions to prevent the formation of drilling fluid retention. In this study, firstly, the characteristics of annulus fluid shear stress distribution are analyzed by establishing the differential equation of shear stress distribution. Subsequently, the calculation model of the drilling fluid retention layer’s thickness is constructed. Subsequently, the impact of cement slurry and drilling fluid properties, eccentricity of the casing, and additional variables on the annular wall’s drilling fluid retention thickness are scrutinized. The quantitative conditions for preventing drilling fluid retention are also analyzed (i.e., Equation (23)). Based on the newly developed model, a case study is conducted to show the significance of the new model. This offers a theoretical foundation for enhancing cement injection displacement efficiency and cementing performance optimization.

CFD Investigation of a Co-Flow Nozzle for Cold Spray Additive Manufacturing Applications

This current work evaluates the efficacy of a co-flow nozzle for cold spray applications with the aim of mitigating nozzle clogging issues, which can occur during long-duration operations, by replacing the solid wall of a divergent nozzle section with an annular co-flow fluid boundary. Simulations were conducted on high-pressure nitrogen flowing through convergent–divergent (C–D) axisymmetric nozzles, with a stagnation pressure of 6 MPa and a stagnation temperature of 1273 K. In these simulations, Inconel 718 particles of varying sizes (15 µm to 35 µm) were modeled using a 2-way Lagrangian technique, and the model’s accuracy was confirmed through validation against experimental results. An annular co-flow nozzle with a circular cross section and straight passage covering the primary C–D nozzle has been designed and modeled for cold spray application. Co-flow was introduced to the reduced nozzle length to compensate for particle velocity loss at higher operating conditions. It was found that co-flow facilitates momentum preservation for primary flow by providing an annular gas boundary, resulting in increased particle speed for a longer axial distance beyond the nozzle exit of the reduced divergent length nozzle. The particle acceleration performance of the reduced divergent section nozzle, when combined with co-flow, is comparable to the original length nozzle.

Case Study: Innovative Sand-Screen Technology Resolves Offshore Nigeria Water-Injection Issues

_ During continuous injection, reservoir solids usually remain within the reservoir. However, prolonged or abrupt well shut ins can trigger intense transient flow phenomena like water hammer, backflow, and crossflow, causing fines and matrix sands to migrate and accumulate in the wellbore (SPE 187103). As a result, the accumulation of debris can markedly reduce structural integrity and the overall long-term viability of enhanced oil recovery (EOR) from the injection wells. This issue had become particularly evident in an offshore field situated in the southern region of the Niger Delta. Over time, buildup in the well led to a substantial decrease in injection rates, which had significantly shortened the operational lifespan of the wells to just a few years at the anticipated injection rates. Various remediation technologies were attempted, such as tubing-installed valve and backflow-restrictor technology but both proved ineffective in resolving annular-flow and crossflow issues. To prevent potentially expensive and complex interventions, sidetracking, or wellbore abandonment, further analyses by the operator, SNEPCo, concluded that an effective solution necessitated deployment as close to the sandface within the injector wells as possible. The Cascade system, a check-valve system developed by TAQA Well Completions (formerly Tendeka), was then successfully deployed in three wells to maintain the required injection volumes for efficient pressure maintenance and reservoir sweep. Non-Return Valve Screen Technology Establishing a reliable flow-control system for the lower completion requires engineering the check-valve components to seamlessly integrate within the sand-control screens for deployment across multiple zones of the injection tubing. The non-return valve (NRV) employs a three-component design comprising a valve body, valve insert, and ball. Ball check valves are installed on the screen base pipe under a shroud that allows the injection of fluid into the reservoir and prevents any backflow from the reservoir during shut ins. The system features a flow-control check valve integrated within traditional sand screens that do not alter completion geometry (Fig. 1). With a metal-to-metal seal, it essentially isolates fluid in the completion annulus and locks injection water into the formation. The NRV has been designed to handle a variety of well conditions including erosion, plugging, temperature, and repeated checking cycles. All flow-control device components are manufactured with high-alloy stainless steel and tungsten carbide components to resist tortuous downhole conditions for up to 15 years. Developed in 2018, more than 2,000 of the valves have already been successfully installed in several wells globally. As this new sand-control technology can autonomously and immediately isolate the reservoir from the wellbore during shut ins, the technology offers additional benefits. - Nonintrusive nature for intervention tools - Unhindered access to the lower completion sandface during injection and intervention - Durability throughout the well’s operational life - Compatibility with openhole standalone screens, gravel- pack completions, direct wrap or metal mesh screens - Cost-effectiveness compared to other options

Numerical investigation of turbulent flow of Herschel–Bulkley fluids in a concentric annulus with inner cylinder rotation

In the present work, under-resolved direct numerical simulation (UDNS) is used to study the turbulent flow of Herschel–Bulkley fluids in a concentric annular region with the rotation effect of the inner cylinder. The current numerical method is verified against the first- and second-order statistics of the velocity field with the large-eddy simulation (LES) data available in the literature for the Reynolds number of 8,900. The influence of the flow behavior index (n= 0.65, 0.70, and 0.75), the Bingham number (Bn= 0.10, 0.25, and 0.40), and the Rotation number (N= 0, 0.15 and 0.30) on the flow characteristics are explored. The instantaneous flow quantities, including contours of the axial velocity and viscosity and vortical structures, and mean flow features, such as the first- and second-order turbulence statistics, mean viscosity profiles, pressure gradient, and skin friction coefficients, are investigated. The results show that weaker Reynolds stress tensor components are generated as the n value is reduced and the Bingham number increases. Moreover, raising the rotation rate increases the magnitudes of turbulent statistics and makes the velocity fluctuations more asymmetrical.

A Comparative Study of the Corrosion Behavior of P110 Casing Steel in Simulated Concrete Liquid Containing Chloride and Annulus Fluid from an Oil Well

The corrosion behavior of P110 casing steel in simulated concrete liquid and simulated annulus fluid was investigated to reveal the corrosion pattern and protective properties of corrosion products in the two environments. Potentiodynamic polarization curves, electrochemical impedance spectroscopy (EIS), Mott–Schottky tests, and electrochemical noise (EN) tests were used to study the corrosion behavior of P110 casing steel in simulated concrete liquid and simulated annulus fluid saturated with CO2. Scanning electron microscopy (SEM) combined with Energy-Dispersive Spectrometer (EDS) mapping was used to characterize the corrosion morphology and elemental distribution of P110 casing steel. The results show that the corrosion resistance of P110 casing steel deteriorates with the increasing immersion days in the simulated annulus fluid, the impedance decreases gradually, and the corrosion-product film shows a loose and porous structure. In the simulated concrete liquid, under the condition of containing a low concentration of Cl−, the protection of the corrosion products gradually increases with the extension of immersion days. With the increasing concentration of Cl− and the extension of immersion days, the electrochemical noise resistance and charge transfer resistance of P110 steel decrease gradually, and the protective property of the corrosion-product film decreases, which is capable of forming steady pitting corrosion.

Semi-analytical solutions of Newtonian fluid-FENE-P fluid core annular flow

Water-lubricated transportation of viscous oil is an important application of core annular flow (CAF), which significantly reduces friction pressure drop and saves pump power. However, the core oil floats up due to the density difference of oil and water, causing instability and even destruction of CAF, which restricts the application and development of the drag reduction technology. The viscoelastic fluid in the annular can inhibit the tendency of the core oil to float up and enhance the stability of the CAF. Nevertheless, theoretical studies related to the viscoelastic fluid CAF are currently missing. To make up for the lack of theoretical research, the solutions of laminar concentric viscous oil-viscoelastic fluid CAF in horizontal and inclined pipes are obtained in this work, and the annular fluid is regarded as viscoelastic fluid conforming to the FENE-P model. Based on the Navier–Stokes equation and FENE-P model, a non-dimensional CAF model is established, and the Newton–Raphson method is used to solve the model. The rheological behavior of annular fluid and the effects of viscoelastic fluid rheology and viscosity ratio on various CAF flow characteristics, including holdup, pressure gradient, slip ratio, and Ledinegg instability, are investigated. The results indicate that the shear-thinning effect of viscoelastic fluid has a significant effect on water holdup and expands the multi-solution region. Different from Newtonian fluid, when the annulus fluid is viscoelastic, the slip ratio can be less than 2. The most significant property is that the shear-thinning effect can transform the hydraulic characteristic curve in the multi-valued region into a single-valued curve, which helps to eliminate Ledinegg instability.

Research on the Retention Model of Drilling Fluid in Eccentric Annulus

Research on the Retention Model of Drilling Fluid in Eccentric Annulus

Computational Fluid Dynamics Modeling and Analysis of Axial and Radial Temperature of Wellbore during Injection and Production Process

Summary To solve problems such as additional tubing/casing load, casing deformation, and packer failure caused by changes in annular temperature during oil and gas reservoir fracturing and production, based on the well structure of oil and gas reservoirs and transition transient heat transfer mechanism, a four-field coupling simulation model of the temperature field in the main fluid domain of the tubing, the temperature field in the solid domain of the tubing, the temperature field in the annular fluid domain, and the temperature field in the solid domain of the casing is proposed. Considering the coupling of fluid temperature, pressure, and physical parameters, boundary conditions are established based on reservoir characteristics, wellbore heat transfer characteristics, and fracturing and production conditions, and are compiled into Fluent software for simulation through the user-defined function (UDF) method. The effects of the temperature and flow rate of injected fracturing fluid and produced oil and gas on the distribution of the wellbore temperature field and temperature gradient are studied. The research results show that by applying D14-1 and D5-5 gas wells to the model, the simulated temperature is in good agreement with the measured wellbore temperature, and the maximum errors of the simulated values of the two different wells are 6.4% and 4.3%, respectively. As the injection and production operation time increase, the heat transfer between the wellbore and the formation gradually stabilizes. At this time, the injection and production flow rate have little impact on the wellbore temperature field, while the injection and production temperature have a greater impact on the wellbore temperature field. The injection and production temperature will cause changes in annular temperature and temperature gradient, leading to an increase or decrease in pressure within a limited annular volume, resulting in local stress on the tubing and casing. The research results can provide a theoretical basis for the analysis of the temperature field and pressure field of the wellbore during fracturing and oil and gas production, ensuring the safety and stability of fracturing and production.

Fingering stabilization and adhesion force in the lifting flow with a fluid annulus.

The lifting Hele-Shaw cell flow commonly involves the stretching of a viscous oil droplet surrounded by air, in the confined space between two parallel plates. As the upper plate is lifted, viscous fingering instabilities emerge at the air-oil interface. Such an interfacial instability phenomenon is widely observed in numerous technological and industrial applications, being quite difficult to control. Motivated by the recent interest in controlling and stabilizing the Saffman-Taylor instability in lifting Hele-Shaw flows, we propose an alternative way to restrain the development of interfacial disturbances in this gap-variable system. Our method modifies the traditional plate-lifting flow arrangement by introducing a finite fluid annulus layer encircling the central oil droplet, and separating it from the air. A second-order, perturbative mode-coupling approach is employed to analyze morphological and stability behaviors in this three-fluid, two-interface, doubly connected system. Our findings indicate that the intermediate fluid ring can significantly stabilize the interface of the central oil droplet. We show that the effectiveness of this stabilization protocol relies on the appropriate choice of the ring's viscosity and thickness. Furthermore, we calculate the adhesion force required to detach the plates, and find that it does not change significantly with the addition of the fluid envelope as long as it is sufficiently thin. Finally, we detect no distinction in the adhesion force computed for stable or unstable annular interfaces, indicating that the presence of fingering at the ring's boundaries has a negligible effect on the adhesion force.

Performance of vacuum-insulated central pipes for deep borehole heat exchangers in geothermal systems

Abstract Geothermal energy is considered a promising future energy prospect, with the geothermal well outlet temperature being one of the important parameters affecting possible utilization options. For ground source heat pump applications or direct district heating, using lower temperatures can be acceptable. However, efficient electricity production requires a higher enthalpy gradient, which cannot be achieved without high temperature at the wellhead. The selection of the dry co-axial close-loop deep borehole systems (DBHE) may be, in some cases, very beneficial. The operating performance of co-axial DBHE can be optimized if the undesired heat transfer between the central pipe and annular fluid zones is minimized. Therefore, the operational performance of such a system depends strongly on the high thermal resistance of the central pipe. The most common option would be a low thermal conductivity material, such as high-density polyethylene (HDPE). In addition, vacuum-insulated tubing (VIT) used as the central pipe could be considered. The article presents results from the study aimed at the comparison of the homogeneous central pipe made of HDPE material and the gap-insulated central pipe. In the study, various air pressure levels as well as variations of surface emissivity were examined to reveal the effect on the heat transfer between the fluid channels. The simulation has been performed using a new purposely developed WellTH simulation software. A coaxial heat exchanger system using a VIT outperforms significantly the heat exchanger with an HDPE for deep geothermal wells. However, this advantage diminishes for shallow wells and therefore this tendency should be considered in the design stage.

Methodology and performance of annular fluid enhanced self-excited oscillation in pulsed submerged waterjet for coal mine engineering

Submerged waterjets often yield low coal-breaking efficiency and have limited permeability. This study introduced a novel approach to enhance submerged waterjets by harnessing the annular fluid hydraulic energy of a borehole. A new waterjet modulator was developed using large eddy simulation (LES) combined with the response surface method (RSM). The reliability of the method was verified by submerged waterjet high-frequency pulsation pressure test experiments. The results indicated that the pulsation amplitude of the annular fluid enhanced self-excited oscillation pulsed waterjet (AFESOPW) was 330.05%, 45.17%, and 32.56% higher than those of the continuous waterjet, self-excited oscillation pulsed waterjet (SOPW), and pre-optimized waterjet, respectively. Additionally, the pulsating pressure peak increased by 42.84%, 19.60%, and 25.81%, respectively. Under the submerged condition, the outlet pulsating pressure peak of the AFESOPW was 1.32–1.58 times the inlet pressure. The self-priming annular fluid weakened the hinderance of the submerged environmental pressure and enhanced the waterjet pulsation effect.

A wellbore fluid performance parameters–temperature–pressure coupling prediction model during the managed pressure cementing injection stage

AbstractManaged 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.