Wellhead System Research Articles

Sealing Characteristics Analysis of New Subsea Wellhead Sealing Device

Subsea wellhead systems are the crucial equipment for the development of oil and gas resources offshore, while the sealing device plays a vital role as the main component of the wellhead system. Once the seal fails, it is necessary to retrieve the original wellhead system and either repair the sealing device or reinstall a new one. This will result in a delay in normal production and an increase in development costs. Therefore, a novel subsea wellhead sealing device is designed. A finite element analysis model is developed to study the underwater wellhead sealing mechanism regarding the equivalent stress and contact stress. The research results show that as the driving block gradually increases from 4 mm to 12 mm, the stress of the 12 convex parts on the sealing body also increases. The maximum equivalent stress reaches 3.5 times the yield limit, indicating that it has entered the yield stage and can achieve a more effective seal. The analysis of the contact stress of the sealing body reveals that the contact stress of the driving block increases, leading to plastic deformation of the sealing body while driving it to achieve a complete seal. In general, the finite element simulation results are consistent with the engineering practice. By analyzing the sealing characteristics, it can serve as the foundation for designing and providing theoretical support for the optimization of the metal-sealing structure.

Bayesian-Based Approach in Soil Characterization for Tophole Design

Summary This paper addresses Bayesian-based data-driven site characterization (DDSC) methods for estimating soil parameters used in tophole casing design. Different models are applied to data sets of piezocone tests (CPTu) conducted in Brazilian fields, and their performance is compared to some characterization techniques currently used by the oil and gas industry. Regression models are crucial for soil characterization for tophole casing design. Data-driven methods consist of a powerful tool for this purpose, allowing handling uncertainties originating from soil variability. This paper addresses regression models devoted to sparse data, namely geotechnical lasso (Glasso) and Gaussian process regression (GPR) from a Bayesian perspective considering prior knowledge of site information. This approach provides statistical information on soil parameters like undrained shear strength, supporting structural analysis of wellhead systems, and conductor/surface casing strings. Data sets were collected from in-situ CPTu tests conducted in the Campos basins in eastern Brazil. The first case study addressed primary CPTu data, including cone tip resistance, friction sleeves, and total pore pressure, to characterize undrained shear resistance as a random variable. In this context, the parameter was modeled using Phoon’s modified Bartlett test to calculate sample sizes that ensure stationarity. This approach presented relevant results in assessing the probability of failure for conductor and surface casing design based on the operator’s internal design criteria. In these applications, more robust techniques were used to improve data characterization. Glasso and GPR models are used to model parameter tendencies and evaluate the random data. These methods differ in prior probability density functions adopted—Laplace and Gaussian, respectively—and they are compared with regression techniques widely used in design practice. All the models were trained to estimate undrained shear resistance. Preliminary results confirm that the technique improves the characterization of soil strata and undrained shear strength, with a beneficial effect on the analysis of offshore tophole structural design cases. Some metrics, such as mean absolute error (MAE) and root mean squared error (RMSE), indicate that GPR outperforms other methods. This is an innovative methodology applied in real-case scenarios with data ceded from the partner operator. The formulation evaluates uncertainties associated with the spatial heterogeneity of the material, continuously improving robustness with each new project data. This enables a better understanding of soil behavior in specific oil fields and can assist the decision-making process in well design, improving operational safety. Furthermore, the results of the statistical modeling support reliability-based analysis to deliver probability-based indicators for well integrity design.

Reliability analysis of subsea wellhead system subject to fatigue and degradation during service life

Reliability analysis of subsea wellhead system subject to fatigue and degradation during service life

Fatigue damage assessment methodology for a deepwater subsea wellhead based on monitoring data

ABSTRACT Deepwater subsea wellhead system is subjected to the various cyclic loads transmitted from the drilling riser due to ocean waves, currents and platform motion during drilling operation; therefore, the fatigue damage is accumulated. A fatigue damage assessment methodology and its detailed analysis procedure for subsea wellheads utilising transfer function theory based on monitoring acceleration data at the drilling riser are developed. Studies on an actual monitoring case for a subsea wellhead under drilling operation with 336 h of monitoring events are conducted and a verification method by comparison of the measured fatigue results and predicted fatigue results based on wave and current data are introduced. The results for wave and vortex-induced vibration (VIV) fatigue life based on measured acceleration data are calculated, and the fatigue bias with predicted results are summarised. The developed fatigue damage assessment method and monitoring case studies can be valuable references for deepwater drilling engineering.

Case Study: Conductor-Integrity Monitoring in Subsea Wells in Harsh Environments

_ A decade-long project to monitor drilling operations on subsea wells in harsh environments has delivered interesting results. Subsea production and exploration wells are subjected to loads from the drilling riser and subsea blowout preventors (BOP). The latter have grown in size and weight over time, resulting in larger wellhead loads. The main task of a subsea conductor is to transfer these loads into the seabed. The bending load applied on the wellhead is transferred into the conductor, which again transfers the loads through the cement and into the soil. In cases where the load exerted on the soil and cement exceeds the capacity, the soil around the conductor might fail. The cement filling the cavity between the conductor and the soil can also crack and consequently lose its intended function. This support degradation reduces the conductor’s ability to support the well. 4Subsea’s Subsea Wellhead Integrity Monitoring (SWIM) service for operations on subsea wells has now been in action for more than a decade. Sensors monitoring the motion and loads near the subsea wellhead have been mounted on more than 300 drilling campaigns (Fig. 1). In recent years, more than 70% of the drilling operations with semisubmersible drilling rigs on the Norwegian Continental Shelf (NCS) have been monitored using SWIM. As a part of the service, integrity parameters showing whether the conductor gives the intended amount of support are calculated. A major finding is that loss of conductor support during drilling operations has been observed in several of these campaigns, with different integrity issues detected. In at the Deep End Wells in the North Sea, the Norwegian Sea, and the Barents Sea are often developed as subsea fields. The typical setup while drilling these wells utilizes a mobile drilling unit (semisubmersible or drillship) with a marine riser and subsea BOP. The well foundation must be designed to withstand the imposed loads. In accordance with Norwegian Safety Authority facility regulations, wells and their foundations must follow strict regulations. These include that the conductor shall provide structural integrity of the well during its service life, and that it shall be evaluated with respect to structural loads and fatigue. Subsea wells can be divided into two categories based on the type of support of the respective conductor. - Supported conductors are the most-common configuration for subsea production wells in harsh environments, with a template structure supporting the conductor. - Unsupported conductors are used for exploration and production wells in less-harsh environments. During well foundation design, there are typically three different failure modes to consider. - Extreme load failure (ULS, ALS) of the wellhead system and supporting structures - Fatigue failure (FLS) of the wellhead system and supporting structure - Failure of the soil support and cement around the conductor SWIM covers both fatigue monitoring and detection of issues with the soil and cement support.

Analysis of different electricity generation scenarios in the “Macizo Volcánico del Ruiz” geothermal project

Based on preliminary estimates of the geothermal potential of the “Macizo Volcánico del Ruiz”, the performance of twelve hypothetical production wells was projected conceptually. Thirteen scenarios of geothermal electricity generation were simulated to the development of the “Macizo Volcánico del Ruiz” geothermal project, considering different technologies and development approaches (wellhead plant and/or central plant). As the results of these simulations and analysis, a technical overview for each scenario was obtained. This overview served as the input for an economic study, which starts from a common base and varies mainly due to the type of plant and the installed capacity of each turbogenerator. Taking all that into consideration it was possible to estimate the construction cost for the different scenarios as well as the operation & maintenance expenses. Finally, a financial projection was made, along with a sensitivity analysis of the construction time for each scenario, which ends when the total installed capacity comes into operation. The results showed the importance of including wellhead plants, when construction times are long, and the benefits of high enthalpy binary plants are highlighted. Under this perspective, the main contribution of the present work is an early analysis procedure of geothermal projects, which provides a general overview for the selection of the development approach, considering the technologies that are gaining relevance in the industry, such as wellhead systems, that no longer are considered a temporary fix but a long-term solution.

Mechanical model and characteristics of deep-water drilling riser-wellhead system under internal solitary waves

Internal solitary waves with a huge amount of energy easily trigger the large dynamic responses of riser-wellhead system and threaten its structural safety. However, previous studies have only focused on the dynamic response of the riser under internal solitary waves. The riser may experience excessive traction from the platform, especially from the mooring platform, in response to the arrival of internal solitary waves. The bottom of the riser connects to the wellhead system, which in turn exerts a reaction force on the riser. To address this problem, a coupled dynamic model of deep-water drilling mooring platform-riser-wellhead system under internal solitary waves is developed in this paper. A dynamic response analysis method based on the fourth-order Runge-Kutta method and finite element method is also proposed for the mooring platform-riser-wellhead system. A dynamical solver for the coupled system is then developed using MATLAB. The dynamic response characteristics of the riser-wellhead system under internal solitary waves are calculated. Results show that the displacement and bending moment of the system initially increases and then decreases along with the propagation of internal solitary waves, and finally reach equilibrium position. The displacement and bending moment reach their peak before the trough of internal solitary waves passes through the riser-wellhead system. The dynamic responses of the riser-wellhead system under the influence of internal solitary wave loads are much larger than those without the effect of internal solitary wave loads. The riser system experiences shearing loads at the interface of internal solitary waves, which trigger a step-like bending moment variation. The bending moment of the conductor under the mudline is greatly increased by the internal solitary waves.

TUBING HANGER INVESTIGATION OF LOADING

In this article, the failures of tube hangers made from UNS N07718 are discussed. An arrangement known as a tubing hanger may be found in wells that produce either oil or gas. It is positioned in the upper tubing head’s bowl after it has been installed. The tubing is held in place by this, and a main annulus seal is created between tubing also the production casing. This holds the tubing in place, and at the same time, it creates a primary annulus seal between tubing also production casing. When compared to odd component in wellhead system, tubing hangers are available in a broader range of styles and sizes than any other option. Tubing hangers made of UNS N07718 are often used in the installation process of sour service oil and gas wells that operate under high pressure and also high temperatures. Afterwards more than 10 years of service, it was only recently found that the tubing hanger made of UNS N07718 had failed in sour wells. Failures of the tubing hanger will inference in substantial production delays as well as high workover expenses. The purpose of this research is to demonstrate the failure mechanism of tubing hanger furthermore its ramifications on existing wells that were erected with material that is comparable to what was used here. In order to establish what caused the failure, each and every exposure that was brought on by well intervention efforts was evaluated. The manner of failure of stringer head suspension was researched, as was its influence on already existing wells that had been erected with materials that were comparable. Keywords: tubing head, tubing hanger, tubing thread, back pressure valve profile, landing shoulder, snap ring, running thread,

Hysteretic damping of soils for well conductor fatigue analysis

The fatigue assessment of a well conductor is a critical design task during offshore exploration and development of hydrocarbons. In recent years, major progress has been made towards the modelling of soil-conductor interaction. Upgraded soil-conductor interaction springs (i.e., p-y curves) and damping models are developed and are gaining acceptance by the industry. However, there is a general lack of simplified procedures to incorporate the soil damping into the time-domain structural analysis of a wellhead system. Thus, the motivation of this paper is to close this gap by proposing a simplified procedure for incorporating the soil damping in the well conductor time domain analysis. The procedure is generic and allows for convenient adoption of alterative p-y spring and damping models. Design charts for equivalent soil system damping ratio versus the lateral deflection of the conductor are developed through parametric analyses based on representative wellhead configurations with typical soil strength profiles in the Gulf of Mexico to facilitate practical design.

Probability Prediction Approach of Fatigue Failure for the Subsea Wellhead Using Bayesian Regularization Artificial Neural Network

The subsea wellhead (SW) system is a crucial connection between blowout preventors (BOPs) and subsea oil and gas wells. Excited by cyclical fatigue dynamic loadings, the SW is prone to fatigue failure, which would lead to the loss of well integrity and catastrophic accidents. Based on the Bayesian Regularization Artificial Neuron Network (BRANN), this paper proposes an efficient probability approach to predict the fatigue failure probability of SW during its entire life. In the proposed method, the BRANN fatigue damage (BRANN-FD) model reflecting the non-linear relationship between the input and output data was developed by the limited fatigue damage analysis data, which was utilized to generate thousands of non-numerical fatigue damage data of SW rapidly. Combining parametric and non-parametric estimation methods, the probability density function (PDF) of SW fatigue damage was determined to calculate the accumulation fatigue damage during service life. Using the logistic regression, the fatigue failure probability of SW was predicted. The application of the proposed approach was demonstrated by a case study. The results illustrated that the fatigue damage of SW would be viewed as obeying the Lognormal distribution, which could be used to obtain the accumulation fatigue damage in operation conveniently. Furthermore, the fatigue failure probability of SW nonlinearly increased with the increment in the accumulation fatigue damage of SW, which could be helpful to ensure the operation safety of SW in deepwater oil and gas development, especially for aged wellhead.

Fabrication of a high-fidelity prototype for subsea wellhead system equipment

Fabrication of a high-fidelity prototype for subsea wellhead system equipment

NUMERICAL INVESTIGATIONS ON THE EFFECTS OF SEABED SHALLOW SOILS ON A TYPICAL DEEPWATER SUBSEA WELLHEAD SYSTEM

Deepwater subsea wellheads may be significantly threatened under extreme sea conditions and operations, especially when the seabed is composed of very soft clay properties. A numerical model of a deepwater wellhead system is established using the classic ocean pipe element and nonlinear spring element of ANSYS to examine the behaviors of subsea wellheads in diverse seabed soil. Nonlinear spring elements coded in the APDL language are used to model three types of seabed soils: very soft soil, soft soil, and firm soil. The dynamic and quasi-static behaviors of the wellhead system in the typical coupled and decoupled models of the drilling riser system are particularly investigated in depth. The effects of the nonlinear seabed soil properties on the detailed wellhead are realistically simulated using time domain and extremum analysis. The results show that the softer the seabed soil, the greater the displacement, rotation angle, curvature, and bending moment of deepwater subsea wellheads. When the seabed soil reaches a particular depth, the mechanical characteristics of the wellheads under the three types of seabed soil conditions are almost simultaneously close to zero. Overall, several conclusions reached in this study may provide some useful references for design and stability analysis.

Dynamic stability evaluation of subsea wellhead based on fully coupled model

The subsea wellhead is a key equipment for offshore oil and gas development. Traditional research focuses on static stability of subsea wellhead system in which the dynamic effect is neglected. In this paper, a drilling platform/riser/wellhead/conductor fully coupled dynamic model is established to evaluate the dynamic stability of subsea wellhead system. An algorithm for solving the fully coupled dynamic model is proposed based on finite element method and Newmark integral method. A fully coupled analysis program is also developed in MATLAB to conduct the dynamic stability evaluation of subsea wellhead system based on the proposed fully coupled model and solving algorithm. Simulation results show that the maximum dynamic response of subsea wellhead system is obviously larger than static response. That is, the subsea wellhead system is likely to be unstable with dynamic loads. The depth of wellhead dynamic displacement and bending moment induced by dynamic loads reaches 32 m and 45 m under mudline, respectively. The dynamic response value appears an inflection point at a certain depth under the mud line. The subsea wellhead system vibrates in the opposite direction before and after the inflection point.

Understanding Material Selection Challenges in Geothermal Well and Systematic Qualification Approach

Geothermal wells are usually operated under High Temperature High Pressure (HTHP) conditions where corrosion is the major threat to the well integrity. As a result, high operation cost and production time loss due to a short life span of steel casing reported in less than two years. This paper describes a study of the casing problems and failures observed in geothermal wells and a possible approach to optimize material selection and qualification of geothermal wellhead system materials.

Integrated Approach Improves Completion Reliability Using Compact Horizontal Wellhead

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 20201, “Improving Completion Reliability by Integrating ESPs, Intelligent Completion, and Zonal Downhole Monitoring With a Compact Horizontal Wellhead,” by Suresh Jacob, SPE, Maithem Al-Nakhli, SPE, and Muhammad Munir, SPE, Saudi Aramco. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. The complete paper presents an oilwell completion integrating multilaterals, intelligent completions, permanent downhole monitoring systems, electric submersible pumps (ESPs), and a horizontal wellhead system. The paper discusses the completion drivers and design, individual equipment, preparation, field experience during installation, and performance of the system during production. The completion has been installed successfully and its lessons are being applied in the design of future installations. Background The well was drilled in a field comprising two main stacked reservoirs separated by a thick nonporous impermeable mudstone barrier. The two reservoirs are in an asymmetrical anticline structure sharing the same oil/water contact. The two reservoirs have a common pressure gradient and similar crude oil properties while having different petrophysical properties, with one reservoir having twice the productivity of the other. Both reservoirs were developed simultaneously using peripheral water injection with horizontal injector and producer wells. Dedicated producer and injector wells targeting individual reservoirs were drilled because of the differences in productivity and the areal extent between the reservoirs. ESPs were installed in all producers to increase rates and to transport fluid to surface facilities. Multilateral wells were drilled to increase production rate and to decrease pressure drawdown. These wells were drilled as TAML Level 2 wells, with openhole laterals drilled from a cemented liner. An intelligent completion allowed the production from each lateral to be controlled remotely from the surface. While both ESPs and intelligent completions are widely used in the industry, the integration of these technologies in the same well is rare because of the difference in operating cycles for the two systems. A well with both ESPs and intelligent completions should be designed to allow periodic ESP workovers while retaining the intelligent-completion equipment within the wellbore for the life of the well. The downhole-disconnection tool is a key enabler in the integration of ESPs and intelligent completions. However, the high level of operational planning and precision required to reconnect the control lines after ESP workover and the absence of downhole sensors in the intelligent completion prompted the design of an ESP/intelligent-completion integration without the downhole wet-connect tool.

The influence of wellhead stick-up on the analysis of critical stress points on conductor casing

During the subsea well construction and workover, a subsea well is connected to the drillship through the blowout preventer (BOP) and the drilling riser. Environmental loads acting on the drilling riser and the drillship are transferred to the wellhead, conductor, and casings, which can cause fatigue issues at critical points such as at the casing couplings. The main function of a subsea wellhead system is to perform the interface between the BOP and the well, ensuring its integrity throughout its operational life. Factors such as the increase in the weight and height of the BOP on 6th generation platforms contributed to the increased risk of failure due to fatigue. The system in this work is represented by a 3D finite element model including internal cement, conductor, and surface casings. Although simplifications were adopted in the modeling, the essence of the well physical behavior remains. The work addresses the influence of the wellhead stick-up on the maximum stress in the conductor below the seabed, comparing analyses of two wellhead stick-up and including horizontal displacement resulting from the integration of the platform/riser dynamics. These horizontal loads are transferred to the top of the wellhead system as a bending moment and shear force. A time series containing riser horizontal loadings is utilized to obtain the von Mises stress. This information is used to count cycles with the rainflow counting technique. The number of cycles resulting for the two wellhead stick-up is compared and demonstrates how wellhead stick-up can be influenced by an increase in dynamic loads acting on the wellhead top. An influence can be observed on the maximum stress point of the conductor located below the seabed. From these results, it was possible to conclude the wellhead stick-up can influence the depth of a critical point in the conductor below the seabed.

Wellhead Design Enables Offline Cementing and a Shift in Operational Efficiency

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202439, “Pushing Malaysia’s Drilling Industry Into a New Frontier: How a Distinctive Wellhead Design Enabled Implementation of a Fully Offline Well Cementing Resulting in a Significant Shift in Operational Efficiency,” by Fauzi Abbas and Azrynizam M. Nor, Vestigo, and Daryl Chang, Cameron, a Schlumberger Company, prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Traditionally, rigs are positioned over a well from the moment the surface casing is drilled until the installation of the wellhead tree. This results in the loss of precious time as the rig idles during online cementing. However, in mature Field A offshore Terengganu, Malaysia, a new approach eliminated such inefficiency dramatically. Operational Planning With oil production in Field A initiated in October 2015, historical data on well lithology, formation pressure, and potential issues during drilling were available and were studied to ensure that wells would not experience lost circulation. This preplanning is crucial to ensure that the offline cementing activity meets the operator’s barrier requirements. Petronas Procedures and Guidelines for Upstream Activities (PPGUA 4.0) was used for the development of five subject wells in Field A. In this standard, two well barriers are required during all well activities, including for suspended wells, to prevent uncontrolled outflow from the well to the external environment. For Field A, two barrier types, mechanical and fluid, allowed by PPGUA 4.0 were selected to complement the field’s geological conditions. As defined in PPGUA 4.0, the fluid barrier is the hydrostatic column pressure, which exceeds the flow zone pore pressure, while the mechanical barrier is an element that achieves sealing in the wellbore, such as plugs. The fluid barrier was used because the wells in Field A were not known to have circulation losses. For the development of Field A, the selected rig featured a light-duty crane to assist with equipment spotting on the platform. Once barriers and rig selection are finalized, planning out the drill sequence for rig skidding is imperative. Space required by drillers, cementers, and equipment are among the considerations that affect rig-skid sequence, as well as the necessity of increased manpower. Offline Cementing Equipment and Application In Field A, the casing program was 9⅝×7×3½ in. with a slimhole well design. The wellhead used was a monobore wellhead system with quick connectors. The standard 11-in. nominal wellhead design was used for the wells with no modifications required. All three sections of the casing program were offline cemented. They were the 9⅝-in. surface casing, 7-in. production casing, and 3½-in. tubing. The 9⅝-in. surface casing is threaded to the wellhead housing and was run and landed with the last casing joint. Subsequent wellhead 7-in. casing hangers and a 3½-in. tubing hanger then were run and landed into the compact housing.

Seal Qualification and Single-Trip Lockdown Sleeve Reduce Risk

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29943, “Seal Qualification and Single-Trip Lockdown Sleeve Reduce Risk Through Innovative and Advanced Technology,” by Scott Patrick Ellisor, Rodrigo Albani Queiroz, and Carlos Eduardo Martins Gaban, Dril-Quip, et al., prepared for the 2019 Offshore Technology Conference Brasil, Rio de Janeiro, 29-31 October. The paper has not been peer reviewed. Copyright 2019 Offshore Technology Conference. Reproduced by permission. Traditionally, a wellhead system requires a drilling lockdown sleeve (LDS) during drilling operations to ensure that the seal assembly is rigid and prevents dynamic movement. By eliminating the LDS, however, the operator will save multiple trips into the well. Because of a seal-assembly design outlined in the complete paper, development of a single-trip LDS was possible for wellhead systems requiring extremely high lockdown requirements, allowing the user to save trips required by legacy designs. New Subsea Challenges In high-pressure/high-temperature subsea wells, annular pressure buildup, caused by thermal expansion of fluid, endangers well integrity. This phenomenon is caused by the increase of pressure during the production phase, temperature differential during the drilling phase, and fluid parameters. This type of annuli pressure buildup causes uplift as high as 3,200,000 lbf. The number of times the system needs to be shut down could be as many as eight per year for a 25-year well life; the life of the field during the production phase, therefore, could see as many as 200 total cycles. Saving Rig Time by Implementing New Technologies The technologies presented in the complete paper are the single-trip LDS and the dynamic casing hanger seal assembly. The single-trip LDS is used if an extremely high lockdown capacity is required. When this LDS is used, the need to run a lead impression tool (LIT) before running the lockdown sleeve is eliminated. Thus, an extra tool on the rig floor is eliminated, as well as a trip into the well. By eliminating the LIT run, between 5 and 10 hours could be saved, depending on water depth. Similar to the way in which LDS saves operators both operating expense and capital expenditure, the dynamic casing hanger seal assembly does as well. The dynamic casing hanger seal assembly has a higher lockdown capacity than the industry-standard seal assembly, which allows this seal to be run downhole without installation of an LDS. Because of this design, running the casing hanger seal assembly could save between three and five trips into the well, reducing overall risk.

A local stress-strain approach for fatigue damage prediction of subsea wellhead system based on semi-decoupled model

Subjected to complicated and cyclical dynamic loads caused by waves, currents and vessel motions and transferred by drilling risers, the subsea wellhead (SW) is prone to fatigue failure, which could lead to the loss of well integrity and even catastrophic accidents. This paper presented a novel semi-decoupled model based local stress-strain approach to predict the fatigue damage of SW. Using the proposed method, a local fine finite element model of SW was built to analyze local load-strain curves of fatigue hot-spots and the equivalent model of the SW. Further, the equivalent model was put into the global model to extract load-time curve by dynamic analysis. After the strain-time curve was determined by the calculated load-strain and load-time curves, the strain range could be calculated by the stabilized hysteresis curve and rainflow counting. Subsequently, the fatigue damage was calculated by the modified strain-life curve and Palmgren-Miner's rule. The results of a case study indicated that the fatigue damage of high pressure wellhead (HW) weld was higher than that of low pressure wellhead (LW) weld, as the LW has the larger outside diameter and wall thickness causing the larger bending stiffness. Compared with the conventional S-N method of fatigue analysis, the calculation results of the proposed semi-decoupled model based local stress-strain approach would be more efficient and reasonable, and the related conclusions could provide reference for life extension of SW in deepwater oil and gas development.

Risk Assessment Method of Subsea Wellhead Instability in Consideration of Uncertain Factors in Deepwater Drilling

In deepwater drilling, the subsea wellhead is in a complicated stress state and carries the risk of instability. The mechanical stability of subsea wellhead has gradually become one of the key factors in the design and construction of deepwater drilling. In this paper, through the analysis of stress and deformation of subsea wellhead system in deepwater drilling, the characteristic parameters that characterize the mechanical stability of subsea wellhead were determined. On this basis, the influence of different factors on characteristic parameters was analyzed based on dimensionless processing and sensitivity analysis. Factors that were more sensitive and had greater impact on the wellhead mechanical stability of the instance well were screened. Aiming at the problem of greater uncertainty of resistance coefficient, the risk assessment method of subsea wellhead instability considering of uncertain factors was established. Using this method, the wellhead instability risks could be quantitatively evaluated in the drilling process, construction parameters and monitoring values of environmental loads which meet the wellhead safety requirements that could also be proposed. Example shows that: according to the selected parameters such as center value of drag coefficient $$\mu = 0.8$$ , fluctuation coefficient of drag coefficient $$\sigma = 0.05$$ , safety limit of subsea wellhead displacement $$S_{\mathrm{wm}} = 0.37\,\hbox {m}$$ , and safety limit of subsea wellhead deflection angle $$\theta _{\mathrm{wm}} = 3.1{^{\circ }}$$ , there was 24% probability of occurrence of wellhead instability for the target well. Meanwhile, the platform drift $$S_{\mathrm{w}}$$ should be < 43 m, and the maximum marine current velocity $$u_{\mathrm{w}}$$ should be < 1.188 m s $$^{-1}$$ .