Challenging Baseline Inspection Paradigms for Oil & Gas Upstream Equipment

Introduction

Conventional wisdom holds that baseline inspections must be done for all piping and other static mechanical pressure equipment [1-3]. An investigation was conducted to challenge this paradigm and the potential risk of changes to it. This article introduces a new approach to baselining practices that were developed for and implemented by one upstream operator. One substantial change was the elimination of baseline inspections for production and facility piping. Alterations were also made in baselining practices for pressure vessels with the objective of enhancing non-intrusive inspection (NII) programs.

Baseline Inspection Overview

Determining the purpose of performing baseline inspections is the principal consideration for a practitioner. Baselining is done for different purposes and can be classified in the three following categories:

1. Quality Control (QC)
2. Quality Assurance (QA)
3. Determination of future in-service corrosion rates by adding condition monitoring locations (CMLs)

(API 570 Piping Inspection Code definition designates areas on piping systems where periodic examinations are conducted. API 510 Pressure Vessel Inspection Code definition designates areas on pressure vessels where periodic external examinations are conducted in order to directly assess the condition of the vessel.)

What is necessary and fit for purpose for each of the objectives can vary significantly. Another factor to consider is when to perform baseline inspections and depending on the objective, the optimal time will vary. The scope of baseline inspection activities can include any of the following:

• Verification of materials of construction
• Visual testing (VT) or inspection to verify installations and evaluate general equipment condition (e.g., material quality, coatings, insulation, absence of mechanical or other forms of damage)
• Verification of installed wall thickness versus design requirements

Although the definitions of QC and QA are different, the activities are interrelated and often overlap. Given the context of this article, QC is the implementation of procedures used to ensure that facilities are constructed to meet the design specifications. QC typically works best when done early-on during the construction phase with the intent of correcting problems proactively and to ensure mistakes are not repeated. QA is a larger part of the overall quality management system that is applied throughout different project stages and sometimes on into the operational phase.

This article questions what baseline inspections are needed for determining in-service corrosion rates on upstream equipment. It also assesses when and how they should be done.

Background and Investigation

The operator’s general baselining practice was to perform wall thickness measurements on all static mechanical pressure equipment along with visual inspections prior to placing the equipment in service. The approach was to perform all these activities as part of an integrated program, (i.e., QC, QA, and wall thickness measurement for in-service corrosion rate determination) during the construction to pre-commissioning phases. Several issues arose from this practice which drove a reevaluation of the approach. One problem was that the requirements for adding CMLs were more arduous than needed for QC and QA wall thickness verifications. The result was a delay of construction activities. Additionally, the qualifications of personnel needed to implement the CML program exceeded what was necessary for the basic wall thickness verification work. Both factors were driving cost overruns and affecting optimal resource allocation.

The investigation pivoted to what was needed for determining in-service corrosion rates. The primary focus was on ultrasonic testing (UT) and wall thickness measurement. The objective was to optimize the approach and ensure a fit for purpose program. The investigation utilized information collected over many years from the following three data sources:

• Damage mechanism reviews (DMRs)
• Equipment degradation patterns
• Failure analyses