Structural Reliability Analysis Method for Assessing the Fatigue Capacity of Subsea Wellhead Connectors

2020 ◽

Author(s):

G. Sigurdsson ◽

T. Hørte ◽

M. Macke ◽

A. Wormsen ◽

L. Reinås

Keyword(s):

Fatigue Failure ◽

Structural Reliability ◽

Failure Modes ◽

Load Level ◽

Life Extension ◽

Integrity Assessment ◽

Well Integrity ◽

Structural Capacity ◽

Drilling Operations ◽

Integrity Risk

Abstract Subsea Wellheads are the male part of an 18 3/4” bore connector used for connecting subsea components such as drilling BOP, XT or Workover systems equipped with a female counterpart — a wellhead connector. Subsea wellheads have an external locking profile for engaging a preloaded wellhead connector with matching internal profile. When the connector is locked subsea a metal-to-metal sealing is obtained and a structural conduit is formed. The details of the subsea wellhead profile are specified by the wellhead user and the standarisedH4 hub has a widespread use. In terms of well integrity, the wellhead connector is a barrier element during both well construction (drilling) activities and life of field (production). Due to the nature of subsea drilling operations a wellhead connector will be subjected to external loads. Fatigue and plastic collapse are therefore two potential failure modes. These two failure modes are due to the cyclic nature of the loads and the potential for accidental and extreme single loads respectively. Establishing the safe load level that the wellhead connector has structural capacity to handle without failure can be done by deterministic engineering methods. Similarly, a deterministic calculated safe fatigue life is the use limit preventing fatigue failure, assuming no inspections. Probabilistic engineering method; Structural Reliability Analysis (SRA), can be applied to a subsea wellhead connector to establish the probability of fatigue failure (PoF). Risk Based Inspection (RBI) is a probabilistic analysis procedure that requires quantified PoF and Consequence of Failure (CoF). The RBI outcome may be used to optimized inspection plans to ensure a safe PoF target level. The RBI methodology is widely accepted, and guidance can be found in several standards. Subsea wellheads are normally classified as un-inspectable. During drilling operations commencement, the uppermost section of the wellhead (high pressure housing including H4 hub profile) will be visible and accessible thus allowing for inspection. This uppermost section may also accessible for inspection when a wellhead connector is locked on. From an SRA basis a generic RBI procedure applicable to subsea wellheads are proposed and established for a generic case of a 27” mandrel with a H4 hub. This paper then proceeds to providing the maximum non detectable flaw size performance required for a wellhead inspection tool/method to be efficient. The importance of accidental load and cyclic load magnitude and uncertainty is shown to impact this conclusion. The potential inspectional value of performing BOP connector leak test at regular intervals during the drilling operation has also been investigated and shown to be conditionally limited. This paper proposes a procedure for application of RBI to the problem of achieving life extension of a wellhead external locking profile while connected to a wellhead connector. The objective is to propose minimum performance requirements for the inspection tool/method to be efficient. Finally, the potential impact of RBI results in a well integrity risk assessment is covered.

Download Full-text

Life Extension of a High Pressure Transmission Pipeline Using Structural Reliability Analysis

4th International Pipeline Conference, Parts A and B ◽

10.1115/ipc2002-27159 ◽

2002 ◽

Cited By ~ 1

Author(s):

Andrew Francis ◽

Mike Gardiner ◽

Marcus McCallum

Keyword(s):

High Pressure ◽

Reliability Analysis ◽

Structural Reliability ◽

Failure Modes ◽

Structural Integrity ◽

Life Extension ◽

Structural Reliability Analysis ◽

Natural Gas Pipeline ◽

Design Life ◽

Transmission Pipeline

Pipeline designers and operators recognize that the commercial viability of operating high-pressure gas pipelines decreases with time. This is because the structural integrity levels of the pipeline decrease, due to the action of deterioration processes such as corrosion and fatigue, until the level of mitigation required to ensure adequate safety levels becomes uneconomical. For this reason pipelines are assigned a nominal design life of typically 40 years. This paper describes the application of structural reliability analysis to a high-pressure natural gas pipeline having both onshore and offshore sections, in order to determine the extent to which the asset life could be increased beyond the design life without any significant reduction in reliability and hence safety levels. The approach adopted was to identify the credible failure modes that could affect each of the onshore and offshore sections and determine the probability of failure due to each failure mode taking account of the uncertainties in the parameters that affect each mode. Based on a detailed consideration of the results of the study it was concluded that the life of the asset considered here could be extended to 60 years without any significant reduction in safety levels. Moreover, it was concluded that if certain mitigating measures were to be implemented in the future then it would be possible to increase the asset life to significantly more than 60 years.

Download Full-text