Annular Pressure Research Articles

Study on Casing Safety Evaluation in High-Temperature Wells with Annular Pressure Buildup

In high-temperature wells, annular pressure buildup (APB) caused by temperature increase is a widespread phenomenon in production, especially in offshore thermal recovery wells. It increases the load on the tubing and casing and consequently threatens the wellbore integrity. Hence, research on casing safety evaluation and APB management has great significance for field production. In this paper, the tubing and casing safety evaluation and APB limit determination methods are presented considering the effect of thermal stress and APB. Based on the case study of an offshore thermal recovery well, an APB-management chart and the recommended optimal range of APB are provided. Finally, an analysis of three commonly used mitigation methods is presented. The effect and the recommended parameters of these mitigation methods are further discussed. The research results show that the thermal stress and APB phenomena affect the stress distribution of the casing and may bring great danger to the wellbore integrity. Maintaining the APB in the safety range is necessary for field production. It is recommended that the annular pressure be kept below the critical value given in this paper. Injecting nitrogen in annulus A and installing rupture disks are both effective methods to improve casing safety. In the case study, the APB decrease percentage is more than 75% when nitrogen is injected in annulus A. However, the nitrogen pressure, the rupture pressure and the installation depth of the rupture disk need to be determined via casing safety evaluation. The effect of optimizing the steel grade and thickness of the tubing and casing is not significant. They can be used as assistance methods when other mitigation methods are adopted.

Study on the mechanism and controlling method for annulus pressure buildup problems in shale gas wells

The Annulus Pressure Buildup (APB) problems in shale gas wells is mainly caused by the crack at casing-cement interface. The stresses on casing-cement interface and cement-formation interface are calculated by the established model which the constrain of formation rock is considered. The elastic modulus of cement sheath has great effect on the stress on casing-cement and cement formation interface. The radial stress on interfaces changed linearly with fluid pressure. The cement rock is treated as a porous elastic material and the residual strain in cement sheath is mainly caused deformation or collapse of pore structure in the cement rock due to the large radial stress on interfaces. Ultimately, micro-annulus will be generated on the casing-cement interface due to the residual strain of cement sheath. High flexibility cement rock is proposed to decrease the radial stress on the interfaces which can reduce the residual strain of cement sheath. On the other hand, PABP is proposed to offset the decreased radial stress due to residual strain. A model for calculating the stress on interface by considering residual strain of cement sheath and PABP is established. The radial stress on the interfaces caused by PABP is quantitative calculated. The mechanism on how the method for solving APB problems in shale gas wells is clearly explained. The field application certificated the validity of method for solving the APB problems and it also proved the correctness of the calculation method.

Fault Diagnosis in Gas Lift System Using PDF Data

Fault detection and isolation in the gas lift system were implemented assuming the gas lift variables are stochastic. Injection valve coefficient (Civ), production choke coefficient (Cpc), annulus pressure (Pa), and wellhead pressure (Pwh) were observed to show variations with faults presence. By simulating these gas lift variables as stochastic, the probability density function (PDF) data were used to generate decision functions for both the detection and isolation of the gas lift valve faults. The scheme accurately detected and isolated faults in the injection valve coefficient (Civ) and production choke coefficient (Cpc). The result of this diagnosis will aid the proper implementation of fault tolerant control in the gas lift system which will lead to its optimal operation.

A new real-time hole cleaning monitoring method based on downhole multi-point pressure measurement and data driven approach

During the construction of long horizontal wells and extended reach wells, inadequate hole cleaning can lead to a series of drilling problems. Traditional hole cleaning analysis is simply based on theoretical models or surface vibrating screen data, and cannot accurately assess downhole cuttings distribution and existing problems. This paper introduces a novel research idea that combines the traditional drilling hydraulic model with the artificial intelligence method. A downhole true cuttings distribution technology based on measurement data, the inversion of flow characteristics from pressure in the hole cleaning field, and a new method for quantitatively evaluating the dynamic distribution of downhole cuttings using along-string measurement (ASM) data were proposed. The results depict that, the relationship between hole cleanliness and annular pressure loss in different hole sections under different working conditions is proportional. Second, under given flow conditions, a pressure-driven hole-cleaning model exerted a reverse pressure drop by inferring the effect of cuttings on the borehole. Third, downhole multipoint measurement indicated an accurate evaluation of the hole cleaning condition and provide detailed downhole information that avoided and solve inadequate hole cleaning of long horizontal wells and extended reach wells. In conclusion, the combination of these methods can overcome the defects of traditional hole cleaning analysis. The integrated approach is helpful in improving the practical technique in hole cleaning and promotes the large-scale application in the oil and gas industry.

Multistage Acid Stimulation Uses Straddle Packer, Real-Time Telemetry

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 204830, “Multistage Acid Stimulation for ICD Screens Completion Using Straddle Packer and Real-Time Telemetry Coiled Tubing,” by Qadir Looni, SPE, Malik M. Humood, SPE, and Ahmed A. Mousa, Saudi Aramco, et al. The paper has not been peer reviewed. _ The authors describe in the complete paper how the combination of a straddle-packer system and a downhole real-time telemetry system was used to acid-stimulate up to 38 stages successfully and monitor the behavior of the straddle packer continuously during diversion of multistage acid treatment of screens while maintaining packer-seal integrity and downhole pressure. In addition, the study also provides lessons learned from implementation of multistage packers with real-time telemetry for successful diversion of acid treatment uniformly across screens in a horizontal well. Introduction Use of inflow control devices (ICDs) is a preferred completion technique in producing multilayer reservoirs from a single well while allowing the optimal production profile along the completed intervals by managing the drawdown from the reservoir to the wellbore. This study focuses on controlled acid treatment of a high number of ICDs in a single well. Two options existed for achieving optimal acid placement in the subject well with 38 ICDs during treatment, chemical and mechanical diversion. Mechanical diversion is the preferred option because it ensures the most-accurate fluid diversion during stimulation. Once the methodology was confirmed, the next step was to identify the optimal bottomhole assembly (BHA) with a packer element that could be set and unset 38 times in a single coiled tubing (CT) run. The final step in the feasibility study was to obtain real-time bottomhole data to ensure adherence to operational parameters during the interventions. More specifically, a casing collar locator (CCL) reading for depth accuracy, CT downhole pressure for ensuring the packer-set value, and downhole annular pressure to check pressure differences along the packer elements were needed. This required fiber-optic (FO)-enabled CT to acquire real-time communication with downhole tools. Methodology The challenges associated with treatment of ICD screens using a straddle-packer system to divert the treatment mechanically include successfully locating the ICD and placing it across the straddle-packer system, monitoring the pressures inside and outside the CT to confirm the treatment affecting the targeted ICD, and not involving an already-treated ICD. In addition, when treating more than 38 ICDs in a well, maintaining the integrity of the straddle-packer elements is necessary to reduce treatment time per stage and maximize the number of stages that can be treated in a run. Another challenging aspect of mechanically treating the ICD screen is the CT reach. A common practice to extend CT pipe reach is selection of a larger-diameter pipe, but, considering the weight capabilities of the rig crane, increasing the pipe size proved problematic.

Rheological effects of air drilling fluids on cuttings transportation in underbalanced drilling

This research investigates factors influencing cuttings transport efficiency in air drilling operations, aiming to understand the underlying mechanisms, identify critical factors, and optimize drilling parameters for enhanced performance. The methodology includes a literature review, computational fluid dynamics (CFD) simulations, and sensitivity analysis of air velocity, drilling fluid properties, cuttings size, and outlet pressure. CFD simulations were employed to model the multi-phase flow in the annulus during air drilling, examining the effects of varying air velocities, cuttings sizes, and outlet pressures on cuttings transport and hole cleaning efficiency. Results show that increased air velocity improves cuttings transport and hole cleaning but may cause higher pressure drops and borehole erosion. Air drilling fluids' unique rheological properties significantly impact cuttings transportation, requiring careful consideration of factors like air velocity, aerodynamic lift, hole cleaning efficiency, annular pressure losses, and potential cuttings accumulation. The study reveals that cuttings size is crucial for transport efficiency, with larger cuttings necessitating higher air velocities for effective transport and being more prone to settling and accumulation. Moreover, the research demonstrates that increasing outlet pressure typically enhances cuttings transport efficiency in horizontal wells. In conclusion, this study offers valuable insights into factors affecting cuttings transport efficiency in air drilling operations, providing recommendations for optimizing drilling parameters to balance efficient cuttings removal, hole cleaning, and minimal pressure drop. The findings hold practical implications for air drilling operations' design and execution, with the potential to improve drilling performance and reduce operational risks.

Transient Open‐Closed Loop Experimental Validation of a Nonlinear Two‐Phase Flow Distributed System

AbstractThe oil well drilling process is a nonlinear system with transient nature. Conventional drilling is unable to assure safe and cost‐effective operation for fractured, cavernous, and highly permeable carbonate reservoirs, which contain the largest oil reserves worldwide. Concerning drilling technologies, Pressurized Mud Cap Drilling (PMCD) is suitable for the challenging scenario previously mentioned. According to PMCD technique, a sacrificial fluid is injected through the drill string and a light annular mud is pumped in countercurrent through the annulus region (bullheading), without surface return, forcing gas and drilled cuttings back to formation. A two‐phase flow distributed model (Drift Flux Model – DFM) is developed to properly describe the complex nature of the system. Also, an experimental facility, presenting field similarity, is employed to validate the open – closed loop schemes. The main objective of the controller (control reconfiguration with gain scheduling) is to regulate annulus pressure, handling gas kick, drilling fluid losses and inverse response dynamics. Besides, gas injection, migration and bullheading are studied. The simulations, validated through experimental data, highlight the methodology usefulness for field applications.

Monitoring system for the sensing of variables in a well safety work over team

This work proposes the design of a monitoring system for the sensing of variables in a well control system (accumulator), for which reengineering is applied to measure pressure and system level, with activation of sound and visual alarms. An accumulator is a unit used to operate hydraulically BOP (Blowout Preventer) components. The monitoring system in the proposed accumulator is based on the sensing of three variables: system pressure, manifold pressure, and annular pressure. In this project, to develop the design, an in-depth study, and analysis of the BOP system is carried out to avoid errors that affect the accumulator's physical integrity. API (American Petroleum Institute) standards are also considered. As a result, the proposed design serves as the basis for the company to take an interest in deploying electronics to the other workover equipment to make them safer and more reliable.

Flow Field and Pressure Loss Characteristics at Rotary Drillstring Joints

A thorough understanding and accurate calculation of the annulus pressure losses are paramount to drilling design and construction. However, due to the influence of the drillstring rotation and the abrupt dimensional variation at the joint, it is difficult to calculate the pressure loss by theoretical analysis in the annulus at the drillstring joints. Considering the geometric nonlinearity of drillstring joints and the unsteady flow of annular fluid caused by pipe rotation, based on the turbulence model k − ε , the flow field characteristics demonstrate the annulus pressure losses at the drillstring joint are studied by numerical simulation. Simulation results indicate that drillstring rotation speed, annular gap, and eccentricity greatly influence flow field and pressure losses at drillstring joints. The annular pressure loss would increase with the decrease of the annular gap and eccentricity but decrease with the increase of the drillstring rotation rate. The investigation method and results would help guide the design of drilling hydraulic parameters.

Maximum Allowable Annular Surface Pressure (MAASP) Standards Calculations Study; a Field Case Study

Well integrity failures may arise during the production phase of a well in a field. Those failures could create a Sustained Casing Pressure (SCP), a pressure that is measurable at the wellhead that can not be bled-off. SCP has to be addressed carefully to avoid any uncontrolled fluid flow to other formation or to surface. To maintain SCP value from degrading the other barrier integrity, the pressure threshold should be known and maintained for each annulus in a well. The maximum pressure threshold known as Maximum Allowable Annular Surface Pressure (MAASP).
 This case study will calculate MAASP from three wells in X field using three known method as outlined in API RP90-2 and ISO 16530-1. API RP 90-2 define two methods in calculation MAASP (known as MAASP – Maximum Allowavle Wellhead Operating Pressure), Simple Derating Method (SDM) and Explicit Derating Method (EDM).
 The result then compared and evaluted to know the differences, trend of MAASP for each methods, and create a generalization of MAASP/depth for field rule of thumb. For A annulus, the MAASP obtained using API RP90-2 SDM and EDM method is always greater than that obtained using the ISO 16530-1 method. However, for B annulus, the MAASP obtained using the API RP 90-2 SDM method varies, occasionally being greater or less than the ISO 16530-1 method. While in C annulus, the MAASP obtained using the API RP 90-2 SDM and EDM methods is always less than the ISO 16530-1 method. The MAASP/depth generalization will be presented for MAASP ISO 16530-1.

Importance of drilling-related processes on the origin of borehole breakouts — Insights from LWD observations

Logging while drilling (LWD) images are widely used for the analysis of borehole stability. In this context, borehole breakouts are a crucial indication of rock failure developing when the circumferential stress around the borehole exceeds the yield value of the rock. This study investigates the impact of drilling-related processes (DRPs) on the origin of borehole breakouts. DRPs, for instance, include connections or tripping operations. For this purpose, we analyze data from 12 boreholes in different geological settings throughout the Norwegian and Danish North Sea, containing a total of 208 borehole breakouts. The extensive data acquisition of LWD offers the unique possibility to link the imaging to real-time drilling operations and to monitor anomalies of e.g., bottom hole pressure. These records allow us to connect any thermal, hydraulic, or mechanical interaction next to the borehole wall to perturbations of the stress field. This analysis resulted in an apparent strong coincidence of borehole breakouts, representing major stress perturbations, with DRPs. The causal relationship is highlighted by one order of magnitude higher occurrence of DRPs in depth sections containing breakouts. Major pressure reductions in the annulus of the borehole seem to be the most significant cause of drilling-related wellbore failures. This applies in particular to shutting off the pumps during connections, where pressure reductions of up to 16 % of the annulus pressure led to higher circumferential stresses. This process will increase the likelihood of compressive and shear failure, therefore causing borehole breakouts. These observations further open the perspective of counteracting wellbore instabilities by pressure modification. In addition to the initiation of breakouts, their temporal evolution – as seen in relogs – can also be ascribed to DRPs. This study indicates that not only plasticity but also mechanical interaction from DRPs is a key driver of the temporal growth of borehole breakouts.

Comparison of Nitrogen Gas and Thermal-Insulation Liquid to Control the Temperature–Pressure Effect in Deep Gas Well

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

Application of soft computing approaches for modeling annular pressure loss of slim-hole wells in one of Iranian central oil fields

Application of soft computing approaches for modeling annular pressure loss of slim-hole wells in one of Iranian central oil fields

Hybrid Gas-Lifting Method Optimizes High-GOR Production

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209721, “Hybrid Artificial Lift-SRP/Gas Lift for Oil Production in High-GOR Environments,” by Kuldeep Chanchlani, SPE, Ranjit Gogoi, and Sukumar Awasthi, SPE, ONGC, et al. The paper has not been peer reviewed. _ The casing gas-pressure-operated rod-lift (CGPORL) system described in the complete paper consists of a sucker rod, pump, gas-lift valves, downhole gas anchor, and tubing string. The completion was invented to save workover rig cost, reduce production deferments, and increase production efficiency in high-gas/oil-ratio (GOR) environments in marginal fields. CGPORL System Description The hybrid-lift system includes gas-lift and rod-lift modes, allowing operators to switch between two modes of artificial lift without costly workovers (Fig. 1). The key factor is the ability to isolate or communicate between the tubing and the annulus without pulling the tubing string out of the hole. Gas lift requires that the annulus should isolate tubing in order to inject gas through valves installed inside pocket mandrels, whereas rod pumps need communication between the tubing and annulus for passage of liberated free gas. Mechanism The gas-lift valve opens once annulus pressure develops over the valve-closing pressure. Once free gas is released into the tubing and the injection valve is closed, the annulus becomes a closed system. The free gas released from the downhole gas anchor gradually pressurizes the annulus until the valve opens for the next cycle. This mechanism indicates an intermittent gas-lift process in a cycle. When the well ceases to flow because of rod-lift failure, the well When the well ceases to flow because of rod-lift failure, the well will continue to flow through the annulus by keeping open the annulus valve connected to the nonreturn valve. Because of the nondevelopment of annulus pressure in case of rod-lift the CGPORL system. failure, a mobile air compressor can be used for valve unloading until the rod pump can be serviced. As the solution gas is recombined with liquid above the pump-setting depth, the hydrostatic head is relatively decreased. If the gas-lift valve is placed at a shallower depth, the drilled well length contributing to the reduction of fluid density is short. If the pump is placed at a deeper depth, annulus pressure can be high, so the gas-lift valve can be placed in a low position. Optimization for the point-of-pump setting and gas-lift-valve setting depth is required. These effects are related directly to the frequency of injection and rate, which must be examined along with economic and safety factors.

Risk Assessment of Annular Pressure Caused by Tubing Leakage in Offshore Gas Wells with High CO2

CO2 sequestration is a kind of technology that can effectively mitigate the greenhouse effect, and the wellbore integrity of the storage system is the key issue to ensure successful CCUS. Failure to timely diagnose tubing leakage in offshore gas wells with high CO2 will lead to annular pressure risk and wellbore corrosion problems. The annular pressure caused by tubing leakage is characterized by high pressure and rapid rise rate, resulting in wellhead jacking, gas leakage, and wellbore structure corrosion, which has become the main cause of wellbore integrity failure in offshore gas wells. Therefore, a model of heat and mass transfer and distribution in offshore gas wells was established firstly, and the physical process of gas leakage and accumulation was described based on the pinhole model and the principle of gas PVT characteristics and volume compatibility. The results show that the depth and equivalent size of the leakage point are two important factors affecting the pressure rise process and leakage rate. Taking case well parameters as an example, after inversion calculation, the annulus pressure in case well was 23.0 MPa, the leakage point equivalent diameter was 2.3 mm, the maximum leakage rate was 0.30 m3/min, and the wellbore safety risk is relatively high. Mechanical repair and chemical plugging agent are recommended to seal the tubing leakage. These risk assessment technologies provide reference for wellbore integrity design and management to reduce CO2 leakage risk caused by wellbore integrity failure.

Sealing failure mechanism and control method for cement sheath in HPHT gas wells

The sustained casing pressure (SCP) caused by the sealing failure of cement sheaths has become one of the main threats to the safe and efficient production of high-temperature and high-pressure (HTHP) gas wells. An actual HTHP gas well was used as an example, and the temperature calculation models were established. Then, the temperature–pressure coupling finite element coupling models of casing-cement sheath-formation assembly for the whole well were established, and the factors affecting the integrity were examined. Finally, the maximum production and wellhead annular pressure based on the constraints of cement sheath integrity was analyzed. The results indicate that the natural gas would transfer energy to the wellbore assembly during production; the greater the production, the greater the temperature fluctuation of the cement sheath, which was unbeneficial to the integrity, the radial and tangential stresses of the cement sheath increase and decrease, respectively, with depth. The cement sheath near the ground was at risk of tensile failure, which could result in tangential tensile cracks. The cement sheath near the packer was susceptible to compression failure, resulting in radial compression cracks, reducing production and wellhead annular pressure were beneficial to relieve the stress state. Compared to the production, the wellhead pressure has a greater impact, it is necessary to control the wellhead pressure in a reasonable range to ensure integrity.

Research on Wellbore Integrity Assurance Technology for Deepwater High-Pressure Oil and Gas Wells

Annulus pressure control is critical to well safety in deepwater oil and gas wells, and it is crucial for deepwater high-pressure oil and gas wells, which are related to production safety. At present, the deepwater annular pressure analysis model is mainly based on the trapped annulus principle. For the high annular pressure of deepwater high-pressure oil and gas wells, it brings great management and control challenges. This paper proposes a deepwater high-pressure oil and gas well annular pressure analysis method considering formation connectivity. According to the existing measures of annular pressure management and control, the differences between various types of annular pressure management and control technology are systematically analyzed and expounded, and the annular pressure management and control technology of deepwater high-pressure oil and gas wells is proposed accordingly. At the same time, combined with the actual case of a deepwater high-pressure well in the South China Sea, the annular pressure considering different influencing factors is analyzed, and the appropriate management and control methods of annular pressure are recommended. This paper systematically summarizes and studies the analysis and control technology of annular pressure in deepwater high-pressure oil and gas wells, which provides a technical basis for China’s deep water to move from conventional deepwater to deepwater high-pressure, and can provide a reference for the management and control of annular pressure in oil and gas wells in subsequent deepwater projects.

Numerical study of temperature and pressure effects of a yield-power law fluid flow on frictional pressure losses for laminar and turbulent regimes

The effective determination of pressure losses depends on accurate knowledge of the drilling fluid rheology. As the fluid circulates deeper around the wellbore, its rheological behavior undergoes significant alterations due to the variations in downhole conditions encountered. The present study investigates the effects of the rheological properties of Yield-power law fluid at various pressures and temperatures on annular pressure losses and velocity profiles. Simulations were performed using Computational Fluid Dynamics to examine the fluid flow in turbulent and laminar regimes. Comparison between numerical, experimental and slot approximation model results showed a good agreement. Results indicated that pressure losses have reduced in both regimes with increasing temperature, at a constant pressure. However the pressure has the opposite effect at a constant temperature. For a drilling fluid flow velocity of 1 m/s, the elevation of temperature from 25 °C to 90 °C, decreases the pressure drop gradient by (31% to 48%) at low and high- pressure conditions respectively. Whereas, the influence of increasing pressure on pressure losses is more apparent at 25 °C. Earlier transition from laminar to turbulent is observed with temperature rise. Therefore, the temperature effect on pressure losses in the turbulent region; is shown for different Generalized Reynolds numbers.

Study on water-based epoxy resin cementing fluid system

Cement-based cementing materials have some disadvantages, such as high brittleness and poor mechanical properties. In the long-term production process of oil and gas wells, it is easy to damage, resulting in annulus pressure and interlayer channeling. However, curable resin-based cementing materials have the advantages of good toughness, high strength, and low elastic modulus, and have the potential as cementing materials. A water-based epoxy resin cementing fluid system suitable for cementing was obtained in this article, which has good toughness and high strength, and can directly replace cement slurry for cementing. When the temperature was 50 °C and 70 °C, the fluidity of water-based epoxy resin cementing fluid system was greater than 18 cm, and the thickening time was 74 minute and 128 minute, respectively. The 28 day compressive strength of the resin cured at 70 °C increased by 276.3% and the tensile strength increased by 117.9% compared with the blank cement paste. Scanning electron microscope test indicated that the matrix of water-based epoxy resin is denser than that of blank cement paste. Fourier transform infrared spectrometer and X-ray diffraction analyses demonstrate that the cured epoxy resin products are not affected by curing age. According to the thermogravimetric results, epoxy resin can be used in high temperature deep well. On the whole, replacing cement with water-based epoxy resin cementing fluid can improve the cementing quality, which has broad application value.

Analysis of wellhead growth mechanism and influencing factors of offshore gas wells based on gas-liquid two-phase

Due to the short time for production fluid in high temperature and high pressure (HPHT) well to reach the wellhead, severe temperature and pressure disturbance happen to the whole wellbore and the resulting wellhead growth will threaten wellbore safety. Considering the difference in wellbore heat transfer characteristics between seawater section and formation section and the influence of reservoir fluid on the wellbore heat transfer capacity, a new wellhead growth mathematical model for offshore gas well is established combined with the calculation method of multiple annulus temperature and pressure conduction. Compared with the measured data, the errors of wellhead growth, annulus pressure and wellhead temperature data calculated by this new model are all less than 6 %. Based on this model, the wellhead growth mechanism and its influencing factors of offshore gas wells are studied. The results show that the liquid phase in mixed fluid exists as annular flow and changes the radial heat transfer characteristics of the wellbore, resulting in a variation trend of wellhead growth decreases first and then increases with the increase of liquid content. Strong convective heat transfer effect between the wellbore and seawater raises the outer annulus temperature, exacerbating wellhead growth. Higher gas production increases the heat carried by production fluid per unit time and exacerbates wellhead growth. But there is a critical production affecting the wellhead growth rate (case well is 50 ×104m3/d.). Optimizing the production plan, regulating the liquid phase production, and optimizing the annulus filler with rational thermal conductivity can effectively mitigate the growth rate and total height of the wellhead, and improve wellbore safety in the production life cycle.