Canadian Province Issues Minimum Requirements for RBI
New API/ASME Standard on In-Service Inspection
The New SPCC Rule Incorporates Industry Standards and Best Practices
API RP 580 Risk-Based Inspection Is Now Available
Effective Planning For Utilization of Contractor API Inspectors For Turnarounds
"RBI 2002" Deriving Maximum Value from the Process - An Owner User Perspective
Aboveground Storage Tanks and the Responsible Use and Application of RBI
Alberta Boilers Safety Association (ABSA) Issues Directive
Similar Service Methodology for Establishing Aboveground Storage Tank Corrosion Rates
2002 Inspectioneering Journal Article Index
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May/June 2002 Inspectioneering JournalBy Mike Badeen at Phillips 66 Co., Mark Geisenhoff at Flint Hills Resources, and Lynne Kaley at Trinity Bridge LLC / Trinity Bridge Digital
Risk-Based Inspection (RBI) is an emerging technology available to plant engineers and managers as they apply risk directed activities to prioritize work and available resources for equipment management. This paper describes the learning of highly experienced RBI users, sharing results of implementation in their plants. The advantages of making and documenting reasonable assumptions will be explored. Additional benefits of the program will be shared, such as streamlined process reliability studies where RBI information can significantly impact time required for completion. Results of using the API RBI methodology for storage tank analyses will also be presented. The presenters have a combined refinery experience of over 40 years and RBI experience of over 10 years with responsibility for over 20,000 pressure vessels and overall responsibility for equipment integrity in two large refineries.
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July/August 2002 Inspectioneering JournalBy Mike Badeen at Phillips 66 Co., Mark Geisenhoff at Flint Hills Resources, and Lynne Kaley at Trinity Bridge LLC / Trinity Bridge Digital
Risk-Based Inspection (RBI) is an emerging technology available to plant engineers and managers as theyapply risk directed activities to prioritize work and available resources for equipment management. This paper describes the learning of highly experienced RBI users, sharing results of implementation in their plants. The advantages of making and documenting reasonable assumptions will be explored.
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July/August 2002 Inspectioneering JournalBy Mark Geisenhoff at Flint Hills Resources
Risk Based Inspection (RBI) analysis is a powerful tool that all of us can use to help with the complex issues of risk. The opportunities for application are exciting and open the door for new ways of conducting business and focusing resources. Along with these new and exciting opportunities comes the responsibility for all of us to apply RBI in a responsible manner.
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July/August 2002 Inspectioneering Journal
ABSA is the regulatory body governing practices related to pressure vessel and piping integrity for the Canadian province of Alberta.
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March/April 2002 Inspectioneering Journal
The American Petroleum Institute Recommended Practice for Risk Based Inspection, RP 580, is expected to be available for purchase in early May 2002.
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September/October 2002 Inspectioneering JournalBy John Reynolds at Intertek
In May 2002, after 6 years of preparation, the API published the first edition of API 580 Risk-based Inspection. The document is now an ANSI/API Standard, which was balloted and approved using the ANSI consensus process for creating American National Standards. As such it becomes a "recognized and generally accepted good engineering practice", for use by all companies in the oil and chemical industry.
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November/December 2002 Inspectioneering JournalBy Greg Alvarado at Inspectioneering Journal
The Alberta Boilers Safety Association (ABSA) issued the requirements document, Risk Based Inspection Programs for Pressure Equipment, in March 2001. This document defines the minimum requirements for the development and use of risk based inspection (RBI) to manage the safety of pressure equipment operating in Alberta.
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January/February 2002 Inspectioneering JournalBy Kelley Jones at Pro-Inspect Inc.
The second part of this article will continue to provide data regarding tasks to successfully plan for the use of API Inspectors prior to the start of the Turnaround. This article will provide information on what needs to be done to successfully utilize the API Contractor Inspector effectively. The first part was the start of the Planning Phase involving Pre-Turnaround activities. We covered items 1 and 2 in Article 1. Now let's continue the Planning Phase with the third item...
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March/April 2002 Inspectioneering JournalBy Kelley Jones at Pro-Inspect Inc.
We all agree that safety is the most important item on any Turnaround. It is also one of the most difficult items to sort out prior to the Turnaround. The fact that API Turnaround Inspectors travel all over the country increases the need to be aware of varying safety requirements and their nuances as they go through the training processes at safety councils throughout the US. Not all safety councils are reciprocal and inspection companies and inspectors need to be aware of which are and which are not. It is very important that the site safety requirements are understood and are prepared for and complied with before the Turnaround starts.
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September/October 2002 Inspectioneering JournalBy Kelley Jones at Pro-Inspect Inc.
If you enter a petrochemical facility to work everyday, you realize the security issues. It is very important to have this issue resolved before the inspectors begin to arrive. The first morning of the Turnaround there are usually several thousand contractors trying to get in the same gate. Inspectors are a small fraction of the Turnaround workforce. However, they can get caught up in the overall delays.
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September/October 2002 Inspectioneering JournalBy Greg Alvarado at Inspectioneering Journal
John has primary responsibility for NDE consulting and troubleshooting for BP around the world in the refining, chemical and gas processing industries. We at the IJ thought it might be valuable to spend some time chatting about his background, challenges he has faced recently and what he feels are some of the biggest challenges ahead for the Inspectioneering community.
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May/June 2002 Inspectioneering JournalBy Greg Alvarado at Inspectioneering Journal, and C.P. Hsiao
We have discussed various factors that can affect the reliability of NDE techniques (i.e., probability of detection - POD and sizing accuracy) in Part 1. In general, it is difficult to quantify these uncertainties. In fact, it is impossible to fully quantify the uncertainties in NDE results. However, one can achieve a higher level of reliability by reducing or minimizing the uncertainties. We will discuss some of the steps one can take to minimize the uncertainties in NDE results. By minimizing or reducing the uncertainties in NDE results, FFS assessments can be less conservative, and thus provide more margin to the serviceability of the equipment.
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January/February 2002 Inspectioneering JournalBy Greg Alvarado at Inspectioneering Journal, and C.P. Hsiao
Safety, environmental and economic pressures are motivating process industry (e.g. refineries & petrochemical plants) operators to consistently improve equipment reliability performance, optimize expenses and more accurately target resources where they will provide the greatest benefit. These improvements yield improved return on net assets (e.g. pressure vessels, piping and tanks). Companies that can better assure that decisions about repairs or replacement of equipment are more accurately arrived at are heading in the right direction. In order to equip operators with tools for better decision making, the American Petroleum Institute, within the last few years, has introduced Recommended Practice (RP) 579 Fitness for Service (FFS), which had been in development for several preceding years. The latest versions of the widely used inspection codes; API 510 (pressure vessels), API 570 (piping) and API 653 (above ground storage tanks) now reference this RP as a tool for determining the fitness for service of these types of equipment when corrosion, cracking, or other forms of deterioration are found and in the case of re-rating equipment.
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Partner ContentFFS assessment techniques are applicable to a wide range of damage types: LTA's, cracks, creep damage, dents, and more. These are very powerful analytical tools that often allow operators to not only keep the plant running, but to keep it running safely.
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November/December 2002 Inspectioneering JournalBy John Reynolds at Intertek
An effort is currently underway to create a new code for in-service inspection and maintenance of pressure equipment in the hydrocarbon process industry. The API Committee on Refinery Equipment (CRE) and the ASME Board on Pressure Technology Codes & Standards (BPTCS) have agreed to explore the idea by putting together a joint task group that would report to both organizations. That group will be meeting soon to put together a set of committee operating procedures and the scope/objective of the document for approval by the API CRE & ASME BPTCS. Once the charter/scope and operating procedures are approved by both societies, a committee will be assembled to accomplish the task.
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Proposed Changes to Outer Continental Shelf Mechanical Integrity Rule Incorporate API 510 - US Department of the InteriorJanuary/February 2002 Inspectioneering Journal
The office of Minerals Management Services (MMS) is proposing to add a reference into their regulations governing oil and gas and sulphur operations in the Outer Continental Shelf (OCS). This revision will ensure that lessees use the best available and safest technologies while operating in the OCS. The new document is API 510, titled "Pressure Vessel Inspection Code: Maintenance Inspection, Rating, Repair, and Alteration."
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July/August 2002 Inspectioneering JournalBy Philip Myers at Chevron Texaco
One of the most important steps involved with regard to tank inspection, using API Standard 653, is establishing the internal inspection interval. API 653 says, "Section 6.4.1.1 Internal inspection is primarily required to: a. Ensure that the bottom is not severely corroded and leaking. b. Gather the data necessary for the minimum bottom and shell thickness 1 assessments detailed in Section 6. As applicable, these data shall also take into account external ultrasonic measurements made during in-service inspections (see 6.3.3).........."
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November/December 2002 Inspectioneering JournalBy Philip Myers at Chevron Texaco
The purpose of the new SPCC rule is two-fold; i.e. to prevent oil spills from occurring and to respond to them if they do occur. We believe that few will argue that prevention is far better and less costly than response in general. The focus of this paper is to highlight how the new SPCC invokes existing industry standards as a requirement for implementation at all covered facilities in an effort to prevent spills. In particular, we focus on the most important industry standards that are required to prevent spills from occurring in existing facilities. Since the SPCC rule does not specifically identify any required standards the task of figuring out which standards are applicable and must be implemented is a challenging one. There are at least a hundred industry standards related to tanks and terminal facilities.
