Ali Ghalambor

An Introduction to Condition-Based Maintenance

Condition-based maintenance (CBM) usually consists of two steps: (1) asset health condition assessment and prediction and (2) maintenance decision optimization. As a general introduction, this chapter provides a discussion of the commonly used condition monitoring methods and signal processing techniques, asset health assessment, and prediction approaches, as well as maintenance decision optimization methods. Various condition monitoring methods such as vibration and acoustic technique, ultrasound and acoustic emission technique, oil, wear debris and ferrography analysis technique, and thermography technique are briefly introduced and discussed. The three major signal processing and analysis techniques, time domain analysis, frequency domain analysis, and time–frequency analysis, as well as the parameters used in these analysis techniques are summarized. Commonly employed condition-based asset health prediction models and methodologies including state space methods, covariate models, and artificial intelligent techniques in CBM are introduced. This is followed by a brief summary of CBM decision making.

Pipeline Vibration and Condition Based Maintenance

This chapter comprises two integrated parts. The first part of the chapter devotes to a detailed discussion of the mechanism leading to pipeline vibration and the effect of internal and external fluid flow on the pipeline vibration. It summarizes the formulations used for the design of optimal free span length of pipeline segments under different boundary conditions and pipeline operating conditions. Different measures used to mitigate pipeline vibration are also briefly discussed in the section. The procedures of pipeline condition based maintenance (CBM) are discussed in the second part of the chapter using vibration and other corrective maintenance (CM) parameters as asset health indicators. The typical models including P–F curve model, proportional hazard model, and proportional covariate model used to determine the optimal threshold and inspection intervals in CBM are introduced and discussed. The chapter also discusses the optimization of long-term maintenance activities using reliability based preventive maintenance decision-making approach.

Pipeline Installation Methods

This chapter provides a general introduction of pipeline installation design codes, various lay and tow methods commonly used by the industry.

Chapter 4 – Hydrodynamic Stability of Pipelines

This chapter addresses stability analysis of marine pipelines on the seabed under hydrodynamic loads (wave and current) and provides guidelines for pipeline stabilization using concrete coating. It does not address alternative methods such as pre- or post-trenching techniques, mattress covers, etc. Stability is checked for the installation case with the pipe empty using the 1-year return period condition and for lifetime (pipe with concrete) using the 100-year storm.

Installation Bending Stress Control

The dynamic stresses that occur during pipeline installation are normally less than 30% of the static stresses in shallow water. As the petroleum industry moves into deepwater environments, the dynamic stresses are more significant. Careful analysis of the dynamic stresses becomes essential for defining the limiting weather conditions that could cause overloading or fatigue failure of a pipeline. In this chapter, we describe how to control the magnitude of pipeline installation stresses that can occur under various installation conditions. These stresses include lay stresses, overbend stresses, sagbend stresses, and horizontal bending stresses.

Pipeline Riser Design

Riser is defined as the vertical or near-vertical segment of pipe connecting the facilities above water to the subsea pipeline. The riser design usually considers adjoining pipework segments, clamps, supports, guides, and expansion absorbing devices. The chapter addresses the engineering analysis and design of conventional steel risers and riser clamps. It is written on the basis of related codes and rules in riser design. It provides a guideline for pre-installed and post-installed conventional steel risers, but does not address J-tube or flexible pipe risers. Risers are assumed to be of API 5L line pipe and are operated at a temperature less than 250°F. Risers are subjected to various types of loads including functional loads, environmental loads, installation loads.

Chapter 13 – Pipeline On-Bottom Stability Control

Pipelines installed on the seabed are subjected to hydrodynamic forces. Waves and steady currents that are characteristics of all offshore areas subject the pipeline on the seabed to drag, lift, and inertia forces. For lateral stability, the pipeline resting on the seabed must resist these forces and at a minimum be at equilibrium. Drag and inertia forces act together laterally on the pipeline, tending to move the pipeline. The most common spectral models that are used to describe sea state are: Pierson-Moscowitz, Bretschneider, and JONSWAP (Joint North Sea Wave Project -JS). Clays are classified by their consistency and are measured by their shear strength. The most common and industry accepted methods for determining the on-bottom stability of submarine pipelines are: PRCI (AGA) Pipeline Stability Program and DnV RP E305.

Pipeline External Corrosion Protection

Offshore steel pipelines are normally designed for a life ranging from 10 years to 40 years. To enable the pipeline to last for the design life, the pipeline needs to be protected from corrosion both internally and externally. Internal corrosion is related to fluid that is carried by the pipeline, and this topic is not covered here. This chapter describes the method by which the external corrosion of offshore pipelines may be minimized.

Pipeline Testing and Precommissioning

From its fabrication to start-up, a pipeline system has to pass a series of tests. Some of these, such as the factory acceptance test (FAT), are done onshore at the fabrication yards with individual components. The FAT mainly consists of the inspection, testing, and reporting of the system according to the drawings, specifications, and requirements of the contract. Pipe sections must pass the FAT before they are accepted. Some of the tests, such as the pipeline hydrotest, are mainly done offshore with either a portion of the whole pipeline system or the whole pipeline system. The hydrotests are conducted to check the mechanical strength of the pipeline system and the integrity of the connections. The hydrotest is one of the pipeline precommissioning activities. Precommissioning is performed after the pipeline system is installed, and all the tie-ins are completed to assess the global integrity, qualify the system as ready for commissioning and start-up, confirm the safety to personnel and environment, and confirm the operational control of the pipeline system. This chapter covers the main activities associated with subsea pipeline testing and pre-commissioning.

Diameter and Wall Thickness

Design of pipeline involves the selection of pipeline diameter, its thickness, and the material to be used. Pipeline diameter should be selected on the basis of flow capacity required to transport production fluids at an expected rate provided by the oil or gas wells. This chapter covers wall thickness design for subsea steel pipelines and risers as governed by US Codes ASME/ANSI B32.8. Other codes such as Z187 (Canada), DnV (Norway), and IP6 (UK) have essentially the same requirements, but should be checked by the readers. Determination of pipeline wall thickness is based on the design internal pressure or the external hydrostatic pressure. The procedure for designing pipeline wall thickness is discussed in the chapter. The three pipeline codes typically used for design are ASME B31.4 (ASME, 1989), ASME B31.8 (ASME, 1990), and DnV 1981 (DnV, 1981). The mode of collapse is a function of D/t ratio, pipeline imperfections, and load conditions. For low D/t ratios (less than 20), the actual hoop stress in a pipeline tested from the surface is overestimated when using the thin wall equations.