2013 Inspection Summit – Session Descriptions
Tuesday, January 8, 2013
Upstream / Midstream
Challenging to Inspect Pipelines Track
Unique Offering for Inspection & Assessment of Challenging to Inspect Pipelines, Real
World Applications -Stefan Papenfuss, Quest Integrity Group
"Pipeline operators have always been aware of the need to manage and maintain the
integrity of their pipeline systems. Advanced ultrasonic in-line inspection tools are
capable of providing accurate, repeatable, 100% coverage data that can be used to
manage pipeline reliability from cradle to grave. Recent advances and proven
deployment of compact and highly accurate ultrasonic inspection tools for non-piggable
pipelines are now allowing operators to examine pipelines and piping systems that were
previously difficult, if not impossible, to completely inspect. Quest Integrity Group has
developed a unique ultrasonic in-line inspection solution (InvistaTM) and fitness-for-
service assessment of pipelines (LifeQuestTM) for pipelines that cannot be inspected
using ordinary in-line inspection technologies. This paper examines some real-world
case studies covering the application of this technology to inspect and assess
traditionally non-piggable pipelines both in Australia and internationally.
Ultrasonic Pig for Difficult to Pig Lines - Hans Gruitroij, A Hak
Inspection of Lined Pipelines - Dave Russel, Russell NDE
The inspection of pipelines that have internal liners or coatings of epoxy, cement
mortar, P.E. and HDPE has been a challenge for the incumbent MFL technology which is
employed in most in-line inspection tools. While MFL is an excellent technology for the
condition assessment of bare steel pipelines, it loses sensitivity as the distance of the
sensors to the steel pipe increases. Remote Field Technology (RFT) is relatively
insensitive to this “lift-off” of the sensors and can inspect through liners as thick as 1”.
The technology has now been in use in O&G pipelines for more than five years. The
technique is described and three case studies are presented, along with new variations
of the technology for detection of CUI from outside the pipe.
Innovative Pipeline Monitoring & Inspection Technology - Brian Morr, Subsea Integrity
Group
NDE Track:
Monitoring of Pipes Using Permanently Installed Guided Wave Sensors - Dr. Thomas
Vogt, Guided Ultrasonics
Guided Wave Testing is now an established method used in the petro-chemical and
related industries for screening pipe-work for defects. Each guided wave test requires
amplitude calibration, which is currently based on the observation of the reflection
amplitudes from girth welds as a reference. These amplitudes are assumed to be of a
certain size and constant with frequency, but depending on the actual dimensions of the
weld reinforcement this assumption can introduce large errors in the calibration. More
advanced techniques therefore require direct measurement of the dimensions of the
weld reinforcement, which allows for a more accurate estimation of the expected
reflection amplitude. Nevertheless, this approach also breaks down, for example, when
the weld reinforcement varies around the pipe circumference, there are no accessible
welds that can be measured or the weld is defective in a way that it influences its
reflection amplitude. All this has a direct impact on the reliability of the inspection since
all defect reflections are sized with respect to this reference. For example, an over-
estimation of the size of the weld reflection can lead to costly false calls. Until recently,
existing calibration techniques were largely satisfactory for standard screening
applications, but the demand for greater accuracy in the classification of defects makes
a new approach necessary. The novel calibration technique presented here is a
significant advancement in this direction and at the same time removes most of the
limitations of current calibration techniques.
Structured White Light for Surface Damage Assessment - John O'Brien, Chevron and
Matt Bellis
This paper will explore the development and application of a value for money, simple,
highly accurate structure white light field unit for the profiling of surface damage,
corrosion, mechanical damage. In the ditch validation of ILI indications and other
surface features has progressed over the years from simple mechanical pit gauge tools
to sophisticated laser scanners. These have had variable results and can be time
consuming. Seikowave in conjunction with Chevron has developed Seikowaves
structured light scanner into a filed portable device that can image surface damage in
seconds, process and deliver fitness for service answers within minutes. We will explore
images, comparisons with existing tools and outputs from the process.
Radiographic Surveys for Locating & Evaluating Corrosion - Joseph Galbraith, Phillips 66
Pipeline Company
Over the last twenty-five years, advances in digital image capture along with the
development of durable electronic computers, components and increasingly capable
means of creating x- and gamma ray energy have led to more cost-effective, more
capable applications of radiographic non-destructive testing in industry. Radiography
can provide the most cost-effective non-destructive testing (NDT) technique for locating
and evaluating anomalies that can adversely affect the integrity of an exposed,
operating, in-service pipeline. The restrictions associated with the use of radioactive
sources and the requirements for chemically developing the exposed film in a darkroom
environment have historically decreased its use as an NDT method; however, recent
advances in the sources and the image capturing devices have rendered the technique
much faster, more powerful and more cost-effective as a field technique. The systems
can be remotely deployed in areas difficult or dangerous to access, and can be used to
generate information on an operating pipeline without the extensive, expensive
preparation such as insulation and/or coating removal required when using other NDT
techniques such as ultrasonics. Not only can digital images of hidden pipe features that
can impact its ability to safely operate be directly created, processed, viewed and acted
on in real-time in the field, but also the image enhancement software commonly
available today can greatly assist the analyst in quickly determining the safe operating
pressures of damaged pipelines. Techniques for locating and evaluating both internal
and external corrosion on piping utilizing some of these advanced systems are discussed
in this paper.
Subsea RT - James McNab, Oceaneering
Reliability / Integrity Management Track:
In the Ditch NDE Technique Performance - Mark Piazza, PRCI and John O'Brien, Chevron
This paper will present selected results from an on-going multi-year project within PRCI
to evaluate and report the performance of NDE tools. Understanding the inherent
tolerance and variability of NDE tools and the impact on measurement data related to
procedures and personnel are critical components of assuring the quality of integrity
decisions in support of process safety. To support the development of industry guidance
on performance of NDE technologies, PRCI has established a state of the art repository
in Houston, TX housing real world flawed pipeline samples across a range of defect
types from Internal & External Corrosion through Stress Corrosion Cracking (SCC),
Fatigue Weld Cracking, Dents, Gouges and a range of interacting threats. These samples
are truly representative of real world flaws in sections up to 40’ in length. The repository
is used for knowledge learning, training, and technique and technology development, as
well as the core program of testing and determining NDE performance. We will
demonstrate results from testing to date sharing what has been learnt about the
performance of select NDE techniques for a range of flaws and features.
NDE and Validation of ILI - Sean Riccardelli, Riccardelli Consulting
Non-destructive examination (NDE), utilized as defect direct-assessment and validation
of in-line inspection (ILI) smart tool data, is a critical function of pipeline integrity
management. However, it is imperative that proper technology and techniques are
deployed for validating anomalies identified by ILI smart tools. These defects must be
properly characterized and the smart tool technology must be accurately graded by
validation. Advanced ultrasonics, such as phased array, can provide more accurate crack
sizing and corrosion mapping; or allow for more valuable defect characterization and
post-inspection analysis. Furthermore, accuracy of ILI tool validation can be enhanced
by the development of special calibration standards and ultrasonic probe holders,
automated and semi-automated data acquisition scanners, and proprietary zonal-
focusing transducers. Proper education and training is vital for the inspector technicians
that are called upon to perform these duties. Qualification on real flawed specimens
such as defect pipeline cutouts and mandatory practical exams can be a supremely
beneficial implementation to validate an inspector’s technical capability. Oil and gas
operators, ILI smart tool developers, inspection companies, and pipeline integrity
engineers are all encouraged to work together as a consortium to more effectively
understand, develop, and implement best practices for the non-intrusive identification
of pipeline defects, validation of anomalies identified by ILI smart pigs, and direct
assessment of defect anomalies.
Integrity Management of AST Through Estimation of Corrosion rate of Bottom Floor
Plate - Tariq, Al-Masoud, Kuwait Oil Company
Aboveground storage tanks are considered as vital assets in upstream sector of oil & gas
industry. The large inventory of flammable product stored in these tanks poses a
significant risk from HSE perspective. Over the years, Risk based inspection has been
developed as alternative approach to assess the mechanical integrity of the tank and its
components. Kuwait Oil Company (KOC) has large number of Aboveground storage
tanks in Gathering centres and Export Tank farms, storing crude oil in different stages of
production. Life assessment and integrity of these Aboveground storage tanks primarily
depends on the tank bottom plate corrosion. Operational requirements occasionally
constrain periodic intrusive inspection of these tanks. Longer operating cycle between
successive intrusive inspections necessitates estimation of realistic corrosion rate, in
order to adopt suitable integrity management program. In this paper, a study on the
estimation of theoretical corrosion rate of bottom plate for Aboveground storage tanks
in Gathering Centres in Kuwait Oil Company has been made, using API-581 Risk Based
Inspection recommended guidelines. Various extraneous factors like soil resistivity,
water drainage and protective measures like cathodic protection etc.,
Advantages of Automated Ultrasonic Inspection of Pipeline Girth Welds as Compared
to Radiography". - Andreanne Potvin, Olympus NDT
Panel: Buyer Beware - Validation of In Line Inspection Results – Panelists: Luc Huyse
Chevron, S Riccardelli, M Piazza PRCI, B Brown ROSEN
‘Caveat Emptor’, Buyer Beware do you really understand what you will get when you
buy ILI services or do you even understand what you need? This panel will discuss what
you can and cannot see with ILI tools and invite challenges and discussion around this
topic. Do buyers have unrealistic expectations? Do vendors deliver what they promise?
Is the question more complex that people really comprehend
Downstream:
Engineering/Analysis Track:
Morning Session:
Summit Kick-Off and John Bolton – Former US Ambassador to the UN – Keynote
Speaker “Threats to American Security: A Closer Look at the World’s Trouble Spots and
How They May Affect Our Energy Supply”
The Importance of MOC in Asset Integrity - Y. Al-Mowalad, Saudi Aramco
Not only can a well-managed asset integrity program help in identifying and reducing
safety risks before they escalate, but focusing on asset integrity can also play a major
role in both achieving operational excellence and extending the life of ageing assets. The
incident investigation reports published by the US Chemical Safety Board indicate
ineffective Management of Change (MOC) — a key process among the Asset Integrity
processes — is one of the major contributing factors in many catastrophic incidents.
MOC is a quality management process for managing the change that is not in-kind on
the asset. The International Organization for Standardization (ISO) has established
rigorous quality standards that include MOC concepts for companies that do business in
the international marketplace. Therefore; companies have to install protocols — in their
standards and procedures — for addressing the MOC scope and depth. These protocols
are required by external guidelines and regulations for managing asset integrity. This
paper exposes the MOC process part of the asset integrity program. It addresses the
main aspects of the MOC process; i.e., definition, types, common shortfalls in MOC
process and the MOC process key success factors. The paper also discusses the need for
enforcing the MOC through incorporating it as a requirement in the engineering
standards and procedures. In addition, the paper disseminates Saudi Aramco Yanbu’
NGL Fractionation Department’s efforts toward having the MOC as a procedural
prerequisite for any not in-kind change over the existing asset. MOC — the center of the
asset integrity program — could remain short-lived unless there are fundamental
changes in values, ways of thinking and approaches. This paper seeks to overcome
resistance to MOC, which is relatively a new concept in the process industry.
Afternoon Session:
Upgrading Mechanical Integrity Programs by Moving from Compliance to Reliability –
R. Davis, Mistras
All refining and chemical companies in the US must comply with OSHA 1910.119 Process
Safety Management of Highly Hazardous Chemicals. Paragraph (j) gives some specific
guidelines and requirements that must be met to meet the compliance requirement.
The result of compliance to the standard is a safer more reliable facility. This
presentation will discuss compliance to OSHA 1910.119(j) Mechanical Integrity. Findings
from OSHA National Emphasis Programs (NEP) will be discussed. This paper will look at
the multiple elements necessary to attain compliance to the standard. The paper will
further discuss the risk reduction and reliability benefits that result in complying with
the standard. The requirements for the different equipment types will be discussed
with an analysis on how the requirements contribute to safer more reliable equipment.
The emphasis of this paper is to identify that a safer more reliable facility is the result of
a proactive mechanical integrity program. By compliance to paragraph (j) of the PSM
standard facilities avoid fines. The resulting benefit of compliance is safer more reliable
plants. Target audience: Plant engineering and reliability management, OSHA PSM and
EPA Risk Management compliance managers on an intermediate level.
Getting the Most out of your Inspection Data Management System – E. Heard, Valero
Energy
Inspection Database Management systems (IDMs) have evolved greatly since the days
of TML point locations. We in these industries generate enormous amounts of data on
daily, weekly and monthly basis. What do we do with all this data? As an IDMs
admin/lead, our job is not just scheduling UT crews for next inspections. With the
addition of RBI, KPIs, ever-changing turnaround/squat schedules, the job we are tasked
with is managing this data to help give a correct and confident answer to what may be
asked. Some items to consider when managing a system are Correctness, Consistency,
Communication, Confidence, and then on the people side of the equation is Coaching.
Correctness of data is reviewing files (U1’s, construction drawings, etc…) each time a file
gets pulled. As these IDMs house a majority of the asset data (design data, P&IDs) that
gets used on a daily basis, we have become a main hub of information. So when
questions as simple as what P&ID does “X” RV reside on, to what Process Streams and
Equipment do we have that operate greater 400°F and have a hydrogen partial pressure
greater than 50 psia; we can answer them quickly and correctly. There are two parts to
consistency. When starting out as a new site or as a seasoned site with a new task to
track, “consistency” is a must. The original path taken may eventually be deemed
incorrect. Not a problem, because the data is structured the same, there will be only
one solution needed to put this back on track. The second part is users. An example is
four complex inspectors entering data four different ways. This will lead to having to
manage four reports to pull the same data for each complex. In the previous example
ask the complex inspectors why they are entering in reports or other data that particular
way. Communicate! Listen to all sides, one complex inspector may have items that are
under some Governmental jurisdiction and another does not know by using a certain
event they can then track the life of a RV or bundle life. By instilling the previous three
topics, it will then lead to “confidence” in the data. The proverbial question of “are you
sure?” shall greatly be decreased. It is not only that question being decreased, it’s
knowing that the product/process is operating within good metal and operating in a
safe manner. Coaching is the final topic. Show the folks on your Inspection team how to
run and build reports. Discuss what anomalies that get searched for when reviewing
data. Explain how UT data gets used in RBI data. There will be one individual that will
begin to ask what SQL is and the following Monday SQL for dummies is on their desk.
Now we get the “what if” and “can we” questions!
Full-scale Testing of Composite Repairs (Case Studies) – J. Bedoya, Stress Engineering
Services
The use of composite materials in high pressure pipeline and piping repairs are
becoming commonplace, and as such it is necessary to know the performance
limitations of these materials under different loading and environmental conditions.
This study discusses specific applications of composite materials in pipelines in
reinforcing defective girth welds, dents, corrosion and elbows and tees, subject to static
and fatigue loading and buried conditions. The viability of these repair methods is
discussed based on actual testing of these materials in relevant loading conditions. In
addition, the standards that govern the use of these materials is also discussed.
Methods to Improve Your Mechanical Integrity Program – W. Rivero, Meridium
(previously PDVSA)
The aim of this session is to create an awareness of the need for, and benefits of,
upgrading Mechanical integrity (MI) programs to a Risk Based Inspection program for
facilities in any industry, and in this case, specifically the Mining industry. A sound MI
program will consist of multiple aspects, meant to ensure failure prevention in the
operation of a facility when implemented and integrated correctly. Some key
components of this program include, documentation, degradation assessments,
inspection plans & drawings, inspection data management software, risk based
inspection and management of change. Pinnacle recently completed a MI program
assessment, and worked with Mosaic’s Potash and Phosphates business units to develop
a plan for implementation of an RBI program for stationary assets to improve
mechanical integrity. The intent of this initiative, when fully implemented, is to provide
Mosaic with a best-in-class Mechanical Integrity program. The Mosaic pilot RBI program
is currently being implemented for Potash at Esterhazy, Saskatchewan and for
Phosphates at New Wales, Florida. The next phase of the MI program implementation
is being completed for Potash at Carlsbad, New Mexico and Colonsay, Saskatchewan;
and for Phosphates at Four Corners, Bartow, Riverview and South Fort Meade in Florida
and Faustina in Louisiana. Pinnacle and Mosaic will present this paper on the
Mechanical Integrity Program development methodology.
Inspection/NDE Track:
Morning Session 1:
Summit Kick-Off and Keynote Speaker - John Bolton – Former US Ambassador to the
UN – “Threats to American Security: A Closer Look at the World’s Trouble Spots and
How They May Affect Our Energy Supply”
Infrared Inspection Program for Fired Heater Integrity Management - Tim Hill and
Rosalind Julian, Quest Integrity Group
Infrared (IR) thermometry has been used for forty years to monitor tube metal
temperatures in refining and chemical furnaces. The application of IR thermometry has
often been characterized as highly operator dependent and therefore developed a very
poor reputation in the industry from poorly applied and interpreted results. There is no
question that when absolute accuracy is unimportant, IR thermometry has proven to be
an excellent diagnostic tool for detecting tube hot spots from internal fouling and heat
distribution non-uniformity in fired heaters. However, to capture the full capability of IR
thermometry, a proven methodology is required to measure accurate temperatures in a
repeatable process. This presentation discusses the particular aspects involved in
establishing an infrared inspection program to monitor the integrity of the fired heater
tubes, as well as a wealth of diagnostic information that may be used to evaluate the
performance and reliability of major fired heater parts (e.g. tubes, tube supports,
burners, refractory and structural systems). It describes the key components of an
effective IR program by providing proven examples taken from real-world programs.
Attendees will take away best practices that may be used at their refinery.
How to Avoid Spills onto Navigable Waters with Rope Access Inspection of Wharf
Piping - Steven McGuire, Hawk Rope Access
Inaccessible piping over water is regulated by U.S. Coast Guard and State regulators.
Corrosion is a huge issue and inspections from boats, floating staging and walkways
provide only limited examination. The accessibility issue is being addressed by the use
of rope access with skilled technicians, certified in Visual and Ultrasonic Inspection.
Recently six out of 6 wharfs whose piping was inspected using rope access required
immediate remedial attention. The rope access specialists remove active rusting by
cleaning rust bloom areas to reveal significant metal wall loss. In addition, they lift the
piping at each support contact point for a thorough inspection of the entire line.
Detailed mapping of corroded areas are accomplished. It has been recorded, that as
high as 41% of the areas where corrosion was revealed required immediate attention.
This paper will explain the combination approach and detailed reporting as well as the
skill requirements for a satisfactory rope access survey. Illustrations will be provided to
provide documentary evidence of the hidden corrosion conditions.
Morning Session 2
Summit Kick-Off and Keynote Speaker - John Bolton – Former US Ambassador to the
UN – “Threats to American Security: A Closer Look at the World’s Trouble Spots and
How They May Affect Our Energy Supply”
Automated Weld Overlay Repairs of Large Damaged Equipment – Eric G. Williams with
CIMS Limited Partnership and Mahmod Samman, Houston Engineering Solutions
Weld repairs have been used for repairing damage in plant equipment for decades. The
difficulty of controlling the consistency of manual welding and its prohibitively time-
consuming process have limited its use to relatively small areas. Recent developments in
automated welding technologies have made possible the structural repairs of large
areas with high precision and efficiency. In addition, the use of temperbead weld
procedures has eliminated the need for the time-consuming and potentially damaging
post-weld heat treatment. The result is an effective weld deposition technique that can
be used to repair large areas of damage such as bulging, corrosion, and erosion. In this
presentation, the automated welding process is reviewed and the first set of results
from an ongoing comprehensive test program of weld overlay repairs is presented.
Mechanical, metallurgical, chemical, and fatigue test results of as-welded Inconel 625
are presented. The data which is mostly unavailable from public sources can be used to
design effective weld overlay repairs and provide regulatory agencies with the
information needed to approve such repairs.
What You Need to Know about ASME Section V – How It Relates to API In-Service
Inspection Standards and New Developments – Jon Batey, Dow Chemical
This presentation will discuss how ASME Codes and Standards in general and how
requirements are developed. A brief historical background on ASME Section V will be
provided. The relationship between ASME Section V and other Codes & Standards
including API will be discussed. Finally, new changes coming in the 2013 Edition as well
as developments that may appear in the 2015 Edition will be presented
Afternoon Session 1
A Near Fatal Incident Involving Small Bore Piping and the Corrective Action Inspection
Program- Anthony J. Rutkowski, Equity Engineering Group (retired COP)
This presentation will review how a rountine refinery practice caused a near fatal injury
and millions of dollars in repairs and lost production. On a 140,000 Crude Distillation
Unit a set of, kerosene to the field, heat exchanger was not performing affectively on
the shell side. The operators turned a fire monitor spray onto the shell. This is a routine
practice in most refineries. The set os exchanger next to the set being spray heated
what the operators called “wild naphtha” on its way to the debutanizer tower. It is
called that because of the high butane content. The naphtha coolers were insulated and
the back cover heads had reusable insulation blankets on them. The overspray from the
kerosene cooler’s external cooling effort was soaking the back covers head’s insulation.
A decision was made to pull and clean the naphtha preheaters on the run. As the
insulator was removing the stainless steel wires holding the blanket of the top
exchanger the blanket fell to the ground. A ¾” bleeder valve on the bottom of the bell
head broke off between the valve and the head dumping the butane rich naphtha onto
the exchanger below and flooding the area with product. The insulator ran to get an
operator but one was in the area and witnessed what transpired. The operator tried to
block in the exchangers but the liquid ignited before he could finish. The operator was
caught in flames but was able to escape and survive although severely burned. One item
to come out of the post incident investigation was “how many more like this are out
there”? That initiated a small bore inspection program involving every small bore branch
connection in a 340,000 barrel per day refinery. This presentation will describe how that
was accomplished and other efforts following the incident.
Heater Stack Integrity Assessment – Before the Next Big Windstorm- Michael Guillot,
Stress Engineering Services
Stacks exist in every plant but are often forgotten components until a hurricane enters
the Gulf of Mexico and then they become the focal point. Due to their height and
difficulty in inspecting them many times significant deterioration occurs before a
comprehensive inspection is made. This presentation provides an overview of the
problems typically found with stacks. It provides guidance on the locations where
problems are commonly found and discusses the corrosion mechanisms responsible for
many problems. Once the deterioration is documented its impact on the general failure
modes as described in ASME STS-1 is evaluated. An example of a free standing stack is
discussed to illustrate the concepts.
What is the ASNT Doing to Assist the Plant Inspection Efforts? – Danny Keck, ASNT
Level III, BP America
This presentation will include information on ASNT Publications Department topics such
as NDT Handbook development, the Programmed Instruction (PI) self-study Series and
our periodicals, the monthly Materials Evaluation magazine and the quarterly
newsletter, The NDT Technician, Mr. Keck will also discuss current certification issues
and upcoming conferences that will be of interest to the Petro-Chemical industry,
especially next June's 13th International Chemical and Petroleum Industry Inspection
Technology Conference (ICPIIT XIII).
Status, Recent Changes and Future Plans for the API Inspector Certification Program –
Tina Briskin, API ICP Manager
The past, present and future of ICP. This presentation will show how the program has
grown in the last decade, especially internationally. The API will show numerous charts
highlighting the growth of the program and existing trends. The presenter will describe
the new programs currently under development which will be available in 2013 such as
Source Inspectors. The presentation will also feature the transition of the exam
administrations from paper to computer based testing (CBT) that is likely to occur in the
near future. This will explain what is expected to be different with the change to CBT.
Afternoon Session 2
MI Inspection during Capital Projects Promotes PSM Compliance, Corrosion Rate
Accuracy, and Improved Budgeting - Travis Keener, SGS
Putting off the initial inspection (i.e. baseline) of piping and vessels in a new process unit
is both common and problematic. The tendency is to rely on the nominal thickness
because the actual original thickness was either not measured or not recorded.
Consequently, significant errors in calculated corrosion rates may result from variations
of thickness allowed by mill tolerance standards during fabrication. Not having the
original thickness can mask potentially hazardous conditions, or cause concern where
none is really warranted. Involvement of the inspection department in a capital project
can significantly improve quality, reduce cost, and ensure compliance. The objectives of
this paper are to provide: 1) justification for inspection during capital projects; 2)
effective roles for inspection departments in capital projects; 3) justification for
performing vendor surveillance in capital projects; and 4) the technical advantages from
performing pre-service baseline inspections.
Code Quality Inspection through Computerized Radiography – William Bobbitt,
PetroChem Inspection Services
Advancements in Radiography in the past decade have been great. Computerized
Radiography is no exception, although the mainstay seems to be geared more toward
profile and informational inspection. Computerized Radiography is capable of more, but
in order to do so certain steps should be taken. Several factors must be taken into
consideration when implementing Computerized Radiography for code quality weld
inspection and acceptance. Main consideration should be given to material type, size,
and thickness. Other considerations should be given to the type of energy and
phosphorus plate used. Protection against backscatter in almost all situations is key.
The use of lead screens, if needed. This paper will outline some methodologies used to
help establish technique development for code quality inspection thru Computerized
Radiography
Recent Developments in the Application of NDT for Improved Integrity Management -
Mark Stone, Sonomatic Ltd
Inspection using NDT methods is playing an increasingly important role in the integrity
management of safety and business critical equipment. There is a trend away from using
inspection simply as a means of providing assurance that the current condition is
acceptable towards making comprehensive use of the information obtained as a means
of longer term integrity management decision making. A key requirement is that the
inspection carried out provide reliable information on the true condition of equipment,
even when there may be only early stage degradation present. In order to maximise the
benefits of inspection in the integrity management process there is increased emphasis
on the reliability and accuracy of the inspection methods used. This paper considers
developments in a number of areas in which new approaches to inspection, and
subsequent analysis of the data collected, are leading to substantial improvements in
integrity management. The areas considered are Non-intrusive inspection of pressure
vessels and application of statistical analysis methods to the integrity management of
pipework. The paper covers the requirements for NDT feeding into these applications
and demonstrates the benefits of enhanced inspection and analysis approaches.
Improved Vendor Surveillance – Two Case Studies Based on Equipment Failures In-
Service - Mr. Mohammad Al- Shaiji, Kuwait Oil Company
Ensuring quality while manufacturing equipments for oil and gas facilities is of
paramount importance as the consequence of a failure of any equipment can jeopardize
the plant and facilities which may be catastrophic in nature. Static & Rotating
equipments like Pressure vessels, Heat exchangers, Valves, Piping, Pumps, Compressors
etc. are being procured through various projects based on the project Specifications,
Company and International Codes & Standards. This presentation comprised of the
experiences based on case studies of failures conducted for two equipments which are
operating in sour hydrocarbon service. First case study is pertaining to failure of valves
of Duplex Stainless Steel (DSS) castings which were procured through an EPC contractor.
Second case study refers to detection of cracks on a SS 321 cladded plate of a pressure
vessel which was inadvertently placed instead of specified SS 316L cladded plate. Gate
valves supplied by a particular vendor started leaking from the body and bonnet after
certain period of service. Investigations were carried out on failed DSS valves & found
that the failure occurred due to the formation of intermetallic phases during casting.
Hence, it is essential to maintain quality for any casting, especially exotic alloys during
manufacturing. To avoid material mix up of Corrosion Resistant Alloys,
vendor/manufacturer should ensure proper tagging of components & carry out 100%
Positive Material Identification during the manufacturing stage. The presentation deals
with the requirements of effective vendor surveillance to ensure that all the
requirements of the project specifications are met. Prior to manufacturing and assembly
of equipment, vendor shall define QA/QC activities in their Quality plan for the
procurement of critical components from their sub vendors. This shall be in addition to
vendor’s detailed Inspection & Test plans (ITP) of the complete assembly. It is necessary
for the Company to conduct Pre- Inspection Meetings (PIM) with the vendor to ensure
that the equipment procured shall meet the project specifications & monitor vendor
performance during all the stages of manufacturing & testing. This will enable to
procure quality products and achieve safe, reliable and un-interrupted production which
is vital for any Oil & Gas industry.
Materials/Corrosion Track:
Morning Session:
Summit Kick-Off and John Bolton – Former US Ambassador to the UN – Keynote
Speaker “Threats to American Security: A Closer Look at the World’s Trouble Spots and
How They May Affect Our Energy Supply”
PTA SCC Leaks on Incoloy 800 REAC Header Boxes – Art Jensen, Delaware City Refining
(PBF Energy) and Avoiding PTA SCC Leaks in Refining Equipment – Gerrit Buchheim,
Consultant, Marc McConnell, PinnacleAIS
During the restart of a high-pressure hydrocracker at the Delaware City Refinery there
was a small weep-type leak detected at a flange weld on an Incoloy-800 reactor effluent
air cooler (REAC) header box. X-ray examination indicated crack-like damage
characteristic of polythionic acid stress corrosion cracking (PTA SCC). The unit was shut
down and the flange and weld were cut out for examination, which verified the PTA SCC
damage mechanism. More than 30 other similar weld locations were examined on the
REAC system, but no additional cracking was detected. While hydrotesting the
equipment following the repairs another weep-like indication was noticed on one of the
REAC header boxes, which was also determined to be a crack-like defect consistent with
PTA SCC. Further investigation identified the source of this damage and established the
remaining useful life of the equipment. This example will emphasize the importance of
understanding equipment design, metallurgy, process environment and damage
mechanisms, and also the importance of knowing the full equipment history toward
understanding causes of current problems.
Welding Metallurgy for the Plant Inspector – Jeff Major, Western Refractory
It is well understood that the metallurgy of materials plays a key role in the success or
failure within all industrial sectors. Significant research has been conducted to
understand the influence of the environment(s) (e.g. temperature, media, flow rates,
etc.) on failure or prevention of failure. Through this research, a better understanding
into the key mechanisms and adversely the key elements/microstructures that prevent
or enhance failure is becoming better understood. Unfortunately, even with enhanced
materials they are only as “strong” as their weakest link. In many cases, the weakest
links are weld joints. This presentation will focus on the key fundamentals of welding
and welding metallurgy. Among inspectors, engineers, or quality control personnel it is
well understood that construction within all industrial sectors cannot be completed
without material joining. The most popular joining process is fusion welding. To help
ensure quality welds, the use of welding procedures that have undergone proof testing
is the leading recipe to success. But what exactly do welding procedures relay and how
are they developed to ensure sound welds. The first topic of discussion is welding
procedures and why they are important. The second topic focus is on welding process
fundamentals and their characteristics (e.g. flux decomposition and chemistry, shielding
gas and arc physics). The third topic of discussion will be general guidelines for filler
metal selection for both similar and dissimilar welding. Finally, a brief discussion on how
the previous topics influence the final metallurgy and properties of a weld joint.
Afternoon Session:
In-Situ Weld Repair Techniques and Technology - Darren Barborak, Aquilex Corporate
Technology Center
There are many material failure modes such as Fatigue, Fracture, Wear or Erosion, and
Corrosion which can be addressed economically in-situ with an Engineered Welded
Repair versus disassembling the component for shop repair or replacement. An
engineered approached will be discussed, which evaluates many aspects of the repair
such as the failure mechanism, repair scenarios, repair access, expected repair life,
service requirements, code requirements, welding & NDE requirements, and welder
safety. Welding techniques such as temper bead welding, and weld
buildup/inlay/onlay/overlay are discussed as well as advanced welding technologies
such as remote welding and low heat input modified short circuit gas metal arc welding.
Several examples of remote repair are provided including remote inspection, repair, and
NDE of buried pipe.
Dealing with Carbonate SCC in Modernized FCCU’s – Steve Bolinger, BP Texas City-
This presentation discusses an incident in which severe Carbonate cracking occurred in
an FCCU gas plant. The carbonate cracking stress corrosion cracking phenomenon
occurs in high pH sour waters in the presence of CO2. During this incident many cracks
were found and a large amount of piping and equipment was replaced. Additionally, all
new equipment required PWHT and higher than normal temperatures in order to
prevent cracking from occurring in the future.
Case Studies on the HIC Damage Mechanism – Jim McVay, Tersoro
Historically with many refiners Hydrogen Induces Cracking (HIC) was thought a relatively
benign damage mechanism affecting carbon steel in sour water services and very
simplistic and basic criteria was often used to assess to serviceability of HIC damaged
equipment. With the advent of modern analytical tools to assess detected HIC damage,
however, many of these same defects accepted historically may fail industry standard
Fitness for Service (FFS) assessments for continued operation at current mechanical
ratings. This presentation will: Discuss service and material conditions promoting the
occurrence of HIC damage, Discuss current common NDE methods and effective
application of those methods to detect and characterize HIC damage, Discuss possible
RBI-based inspection strategies to detect and monitor HIC damage. Discuss the use of
the analytical tools in API 579 to perform FFS assessments of HIC damage. Recent case
studies of equipment with HIC damage will be reviewed to support the discussion
outlined above.
The Need for PWHT and Out-Gassing After Welding Repairs on Equipment Operating
in Potential Environmental Cracking Services – Gerrit Buchheim, Consultant and Mike
Urzendowski, Valero
One of the most common issues that refiners face during a shutdown is whether PWHT
is needed subsequent to minor or major weld repairs on equipment and piping. There
are some API 510/NBIC Code issues, but in many cases it the service environment that
determines the need for PWHT. Another issue that often arises is whether equipment
in wet H2S service needs hydrogen outgassing before making repairs. The panelists will
prepare a few discussion points on PWHT and outgassing issues and the rest of the time
period will be spent fielding questions from the audience on their experiences and the
panelist will try to provide suggestions.
Wednesday, January 9, 2013
Upstream / Midstream
Challenges to Inspect Pipelines Track:
Challenges & Technology Solutions in Integrity Management of Pipelines & Subsea
Systems - Dave Wang, Shell
This presentation will provide an overview of major challenges and technology solutions
for integrity management of onshore and subsea systems. The discussion will focus on
three major challenges: 1) inspection of onshore and subsea pipelines that cannot be
examined by conventional inspection pigs, 2) monitoring of pipelines for corrosion wall
loss, third party intrusions, and geohazards, and 3) rapid response leak detection
systems. Examples will be given on technologies that can help overcome the challenges.
Such examples include free swimming pigs, electromagnetic acoustic transducer (EMAT)
Lamb wave scanning, digital radiography, large standoff magnetometry, riser weld
inspection pig, guided wave tomography, pressure wave and real-time transient
modelling (RTTM), and fiber optics. The objective of the presentation is to encourage
development and implementation of technologies that can close the major integrity
management gaps currently existing in our industry.
Alternatives for Challenging to Inspect Pipelines - Bob Burns, Applus
Depending on the pipeline design, its operational characteristics, the extent of any
damage (third party) to the line and economic factors that may or may not justify line
changes, a pipeline may be designated as unpiggable. Unpiggable means these lines are
not currently being inspected using In-Line-Inspection technologies. Unpiggable
pipelines are therefore a population of pipelines that have a broad range of
characteristics and operators will often apply criteria to prioritize these, for integrity
assessment. In this presentation we will provide an inventory of alternative inspection
approaches commonly used to secure data for integrity assessment purposes. In
addition, one novel approach that could be applied to short sections of pipe with limited
access will be described. Long Range Ultrasonic System (LORUS) was developed and has
been used primarily for the inspection of annular plates in a storage tanks for almost
two decades. Applus RTD has been working to adapt the technology for use in pipelines
by developing a unique comparative evaluation model.
Non-Intrusive Corrosion Monitoring - Geir Instanes, ClampOn AS
The paper discusses the latest technology development for Non-Intrusive Corrosion
Erosion Monitoring for subsea installations.
Subsea production templates, flow jumpers, manifolds and flow lines can today only be
inspected by pre-installation of corrosion/erosion sensors or by use of ROC-operated
sensors. Current pre-installed sensor systems for monitoring pipeline integrity have
proven to be of limited value to the operators and ROV-operated sensors only provide
indicative and unreliable readings. A major challenge is that “hot-spots”, i.e. areas
particularly susceptible to erosion/corrosion, are often detected after the template has
been in operation for a while. Accordingly, the ability to retrofit a corrosion-erosion
monitor (CEM) on identified hot spots subsea is crucial. Monitoring of pipe integrity is
increasingly important as installations grow older.
Robotics for Challenging to Inspect Pipelines- Robert Pechacek GE Energy Management
This presentation overviews a new line of buried pipe inspection systems (Surveyor)
recently introduced by the General Electric Company. These tools are targeted to
address the needs of the Oil & Gas and other Industries to perform comprehensive
inspections of their unpiggable buried piping systems to determine the integrity of the
piping. Most unpiggable piping is not accessible from the OD and requires a
comprehensive ID inspection solution. There have been few options for addressing
these critical needs in the past. These devices use tethered, self-propelled robots to
perform high resolution ultrasonic or electromagnetic inspections from the pipe ID to
detect and map both ID and OD corrosion of the pipe wall. The Surveyor systems are
capable of operating in liquid-filled, partially filled or empty piping systems. I will outline
the capabilities, strengths and limitations of the Surveyor systems and the range of pipe
diameters and conditions where it can be utilized. Additionally, I will overview recent
3rd party qualification testing of the technology and field deployment case study results.
This presentation is targeted for all unpiggable piping asset owners and managers and
will be delivered at a target intermediate level. Typical applications include storage
terminal pipe, transmission piping, road crossings, facility piping and all critical, low
access piping systems.
Challenging to Inspect Pipeline Pipelines Solutions - Rolf Spoerkel and Steven Trevino,
Oceaneering
In Line Inspection of Seam Welds – Adrian Belanger, TD Williamson
In the seam weld of a pipeline has long been susceptible to corrosion and anomalies due
to the welding process, and because of its axial orientation, failures can be catastrophic.
In the past it has been difficult to evaluate seam welds using traditional magnetic flux
leakage (MFL) techniques, but with the development of new technologies, long seam
assessment has become a staple of inline inspection. Each technology has its strengths
and weaknesses, and this presentation will examine the use of magnetic flux leakage,
ultrasonic inspection and electro-magnetic acoustic transmission (EMAT), describing
their pros and cons so that pipeline operators can make informed decisions in choosing
the best technology for their pipeline integrity programs. Line Inspection of Seam
Welds.
NDE Track:
Advanced subsea Inspection - Paul Cooper, Oceaneering
The rapidly growing number of subsea pipeline and riser systems has challenged the oil
and gas industry to develop new automated inspection solutions for sophisticated
materials and geometries. The new creative design solutions for deep water field
development, combined with a growing requirement for subsea field life extension
demands non-intrusive inspection techniques that provide detailed information for
engineering evaluation. Operators are facing the commercial challenges to justify
continued operation of existing subsea infrastructure where loss of hydro carbon
containment is an ongoing risk that needs to be mitigated. With these operational and
commercial challenges, comes an opportunity for innovation. Oceaneering is a market
leader in developing and applying advanced subsea inspection technologies, and is in a
unique position to combine in-house inspection technology, NDT expertise, and subsea
engineering to provide the industry with NDT and condition monitoring solutions to
meet the ever increasing subsea asset integrity requirements. Case studies will be
presented, with focus on project specific challenges, solutions and results.
Upstream Digital RT - Case Studies - John Iman, GE
Inspection of Pipelines Using High Resolution MWM - Todd Dunford, JENTEK Sensors
This presentation focuses on upstream and midstream applications of MWM-Array eddy
current sensors. MWM-Arrays offer a leap in capability for applications including pipe
wall thickness measurement through coatings, SCC mapping, and the characterization of
pitting. Solutions for in-line inspection (ILI), underwater inspections (shallow water and
deepsea) for pipe wall thickness, and permanently mounted sensors for continuous
monitoring are also being developed. This presentation provides a status review on
solutions for each of these applications. The specific advantages of the MWM-Array
technology are: (1) the use of simple drive windings and sensor array constructs that can
be accurately modeled using layered media models; (2) parallel architecture, high
integrity impedance instruments; (3) multi-variate inverse methods that use
Hyperlattices™ (pre-computed solution space databases) to convert wide bandwidth
sensor data into real material properties (such as pipe wall thickness); and (4)
GridStation decision support software that enables reliable inspections and data
visualization. The progress over the last few years has been funded by the U.S. DOT with
specific applications funded by PRCI and oil majors. Specific advancements include the
development of an impedance instrument that can provide accurate measurements at
very low frequencies (less than 5Hz) and high data rates at higher drive frequencies
(10,000 samples/second for frequencies above 10kHz). This instrumentation allows the
MWM-Arrays to perform inspections that are not typical for eddy current sensors, such
as pipe wall thickness measurement and internal corrosion using in-line inspection (ILI).
A series of case studies will be presented that demonstrate how eddy current sensors
such as MWM-Arrays and very low frequency MR-MWM-Arrays can be applied to
upstream and midstream applications. Permanently Installed Wireless Monitoring
Sensors - Gene Silverman, Berkeley Springs Instruments
Permanently Installed Wireless Monitoring Sensors - Gene Silverman, Berkeley Springs
Instruments
Acoustic Emission of Well Site Tanks - John Nyholt, BP America
Advanced Ultrasonic (cave man) Flaw sizing techniques - Mark Davis, Davis NDE
Reliability / Integrity Management Track:
Terminal Facility Piping Inspection Programs - Scott Lebsack, Mistras Group
In 2011, API Issued RP 2611 Terminal Piping Inspection—Inspection of In-Service
Terminal Piping Systems. This document addressed the need to assure operational
integrity without having to use API 570 as the basis for terminal integrity inspections.
While API 570 can be applied to any process piping system, it is not a good fit for the
different operating conditions found in a terminal versus those in a refinery. Terminal
operators have recognized the need for periodic monitoring to ensure, public safety,
operational integrity, and reduce environmental risk. Conditions in and around terminal
facilities dictate that a variety of assessment methods are needed to initiate an effective
piping integrity program in terminals. This presentation examines the inspection
challenges that are found in terminal operations as well as presenting the approach
used in carrying out assessment programs following API RP 2611. Requests for diverse
inspection programs to assess specific circumstances in terminals have increased over
the last three years. Terminal operators are addressing an ever increasing public
awareness of risks posed by these facilities along with an increasing regulatory and
environmental awareness from local and national agencies. Case histories are used to
illustrate how a comprehensive terminal inspection program is developed and how
unique situations are addressed using a variety of inspection techniques to get the data
needed to establish the condition of the pipe.
The Essential Elements of an Integrity Management System - Nick Marx, IRML
This is a presentation for an entire integrity management system not only an integrity
assessment. Elements are: Elements. System scope; clearly define what is included and
what is excluded. Organization & responsibility effective organizational structure:
senior management, line management (QA/QC), integrity assessment, maintenance,
operations, engineering, construction and purchasing. Concept, design, engineering
must be clearly defined (DBM along with numerous HAZOP’s) engineering contractor is
suitable. Fabrication, construction, erection ensure companies have the jurisdictional
approvals and sufficient competence Commissioning. Handover from projects to
operations; Operating parameters and procedures need for the revision of existing
procedures or the addition of new ones. Threats analysis, mitigation & monitoring;
Operations ensure the equipment is operated within the parameters notices of any
such excursion. Repairs & Alterations must include the steps necessary to effect both.
Competency - some form matrix of tasks to identify the required certification, skills and
knowledge. Inspection – integrity assessment Inspection at every stage of a program;
competence of each inspector what and how criteria are to be established to determine
inspections. Change management identify what items, processes and procedures need
to be controlled. Purchasing, material control, contracting & approved vendors.
Internal auditing. The IMS needs to be evergreen; must address changes to regulations,
procedures and industry best practices. Corrective & preventive measures identify what
types of issues root cause can be identified and eliminated or mitigated. A properly
developed IMS will result in fewer incidents, unexpected outages, This better
understanding of the resulting risk involved will also deliver a higher assurance of safety.
Real Time Application of Rarefaction Wave in Pipeline Leak Detection - Andy Hoffman,
Atmos International
Acoustic (negative pressure) pipeline leak detection technology has been around for
more than thirty years. However its application to operational pipelines has been
limited, largely due to the large number of false alarms generated. This presentation
addresses the development of a new rarefaction wave pipeline leak detection system,
based on high performance pressure sensors, modern communication systems and
advanced signal processing algorithms. Compared with the traditional acoustic systems,
this new leak detection system has the following advantages: It works on all pipe
materials: Lead, PVC, HDPE, MDPE, Cast Iron, Steel, Cement. It can cover any distance
between 100 metres and 250 kilometres between two consecutive pressure sensors. It
has a detection time of less than 3 minutes for leaks down to 1% of nominal flow. Leak
location typically within ± 100 metres. Leak detection under all operating conditions
including shut in and hydrostatic tests. A low false alarm rate once tuned to pipeline
operations.After a description of the system, its application to a few operational
pipelines will be discussed. The real life performance of the system will be presented
with over 100 leak test results and the implementation details. The main challenges
faced by the pipeline industry will be discussed together with realistic performance
expectations.
Enhancement of Pipeline Integrity Management Plans with Advanced Leak Detection
Technology - Maurino DeFebbo and Jeff Robbins, Asel-Tech
Commercial use of internal leak detection monitoring technology on transportation
pipelines has been common practice of pipeline operators for many years. The
overwhelming majority of existing internal leak detection monitoring technology
currently deployed is commonly referred to as “Mass Balance”. With ever increasing
pressure from the public, the media, government regulatory agencies and pipeline
operator management to mitigate pipeline failure risks and cost, there is a very keen
demand for alternative and improved technology to be utilized across the integrity
management board. The notion (and some techniques & vendors) of Acoustic leak
detection have been around since the late 1970’s. Acoustics never really caught on
because consistent performance was always an issue. Since that time, the quantum
advances made in sensor/transducer technology and signal processing techniques and
technologies (computers) has significantly enabled development of acoustic leak
detection monitoring technology that works substantially better than its predecessors,
and in most cases better than other CPM/Mass Balance type methods. Some advanced
systems even allow for integration of the acoustic technology with mass balance type
systems. The result being, a very versatile/broad spectrum system with built in
redundancy.
Leak Detection by Distributed Acoustic Fiber Sensing - Collin Stegeman, BT
A solution for a solid Fiber Acoustic Sensing leak detection capability will be discussed.
One of the most valuable applications is Leak Detection on pipelines, both for liquids
and gas. Provided that the Fiber optic cable is close to or attached to the pipeline, a leak
detection accuracy of 3 liters per minute is achievable in a low pressure liquid pipe. The
entire described Fiber Sense system consists of only two parts: a standard fiber optic
cable and a Helios interrogator on one end. The interrogator detects minute changes to
the reflected light in the fiber caused by small vibrations anywhere along its length. Any
noise or vibration disturbance to the fiber at any point can be detected at the end of the
fiber. This means that anything – machinery, refineries, pipelines, even boreholes – can
be closely monitored for changes that could signal trouble. The captured vibrations are
analyzed and categorized against known parameters to determine if they can be ignored
or passed on for further analysis. The solution can be fully integrated with existing CCTV,
GPS and GIS technologies to pinpoint events. Intelligent location detection and tracking
(LDAT) platforms manage alerts and minimize false positives.
Remote Sensing for Early Detection of Oil On water & Clean Up Support - Nina Soleng,
Kongsberg Satellite Services
Use of Synthetic Aperture Radar (SAR) sensor from satellites has proven to be an
excellent tool for detection of oil slicks, vessels and installations at sea. This advanced
sensor can detect oil slicks due to the change in behavior of the sea surface (the slick´s
dampening effect on the capillary waves). These radar satellites are able to observe
features and objects on the surface independent of day light and works in cloudy and
foggy conditions.
SAR has been used operationally for early detection of oil spills in Scandinavia since
early 1990’s for national authorities and the oil industry. This service concept was
developed in Norway, and has been improved and refined through years of participation
in national and multinational R&D projects. The analysis results from the experienced
operators are overlaid with maps /positions of rigs, drilling ships, pipelines and subsea
installations for detecting the most likely origin of the slick. Identification of vessels (AIS)
is also integrated with the analysis. The oil spill detection service today has a tailored
production chain for rapid alerts. So what started in Scandinavia 20 years ago today
comprises of 26 European coastal states through European Maritime Safety Agency
(EMSA) and is currently provided world-wide, assisting national authorities in detecting
oil discharges, and alerting oil companies of any early indications of oil leaks. In Norway
this monitoring by remote sensing is maintained by two entities; The National Coastal
Administration is responsible for monitoring of the shipping lanes, monitoring for
accidental and illegal discharges from vessels. NOFO (Norwegian Clean Seas Association
for Operating Companies) is the responsible entity handling satellite monitoring of the
offshore activity on behalf of their members (all operating oil companies on the
continental shelf). Oil spill detection using local radar (OSD) is being used in addition to
SAR from satellite, but at this time there is no operational use of this type of sensor -for
early detection purposes- in Norway. There are however ongoing projects initiated by
the industry and preliminary results from the Norwegian shelf can be presented.
Norway is one of the few countries that have the privilege to benefit from full scale off-
shore oil-on-water exercises NOFO organizes every year. The focus on integration of
sensors to a comprehensible operating picture is of current interest (satellite, ship radar,
AIS and infrared). Examples of use of remotely sensed data and integration of sensors
from the national Oil on Water exercise summer 2012 will be presented.
Industry Panel: New Solutions for Pipelines that are “Challenging to Inspect”.
Panelists: John O’Brien, Chevron, Rick McNealy, PRCI, David Wang, Shell Global
Downstream
Engineering/Analysis Track:
Morning Session:
Coke Drum Life Extension Issues and Solutions for Inlet Nozzle Problems – Richard Boswell, Stress Engineering Services Modern coke drum operations are used to process a heated mixture of hot liquid and vapor inside a vessel where the residuums produce more valuable liquids and gases while leaving large amounts of solid or semi-solid carbon. The batch process is a cycle of filling, cooling and removing the solid content. Coke drums suffer fatigue damage from several causes which can be accelerated if not managed properly and these can lead to premature and repetitive cracking. Traditional Analysis methods assume a uniform average flow of water upwards to remove heat from coke bed and shell at the same time, or flows up thru central primary flow channel. The coke bed formation determines path of least resistance for water flow. Temperature measurements suggest fast quench with flow near wall is common with the use of side inlet feed configured drums making shot coke. This creates greater stress in shell/cone-cladding bond and at skirt weld. Coke drums suffer fatigue damage from several causes which can be accelerated if not managed properly and these can lead to premature and repetitive cracking. Solutions focused on a single cause may overlook the other contributors today or in future operating conditions. Inspections that discover the extent of damage can be supplemented with active measurement of strain and temperature during the cycle to establish statistically relevant causes for low cycle fatigue failure. The drum geometry evolves from a cylindrical like object into a highly corrugated vessel which amplifies wall stress and accelerates local damage. Geometric degradation and crack growth are increasingly nonlinear in time and inspection programs must be designed to anticipate this to avoid unplanned outages for repairs. Drum bulge severity can be evaluated with finite element model analysis to determine the amplification potential, and to plan when and where areas should be inspected closely. Thermal distributions during quench show large differentials between sides and elevations when cooling water quenches the steel and not the coke. This is influenced by orientation of the inlet nozzle. Traditional bottom center feed creates the least trouble compared to single or dual side inlets, but is not trouble free because of the way shot coke forms and moves inside the drum. These configurations are discussed in comparison to new technology which restores vertically aligned flow streams when slide valve un-headers are used for safe removal of the coke solids. This technology can extend the economic life of old and new drums. Failure Modes and Inspection Needs of Coke Drums - M. Samman
Coke drums are large vertical refinery vessels that operate in cyclic batch process under
severe mechanical and thermal loads. Many drums start to experience failures within
three to five years of service. Typical failures include shell bulging and cracking, skirt
attachment cracks, anchor bolt failures, tilting, and vibration failures. Some of these
mechanisms can lead to unscheduled shutdowns, loss of containment and fires. This
presentation is an overview of these failure modes, their causes, consequences, and the
inspection methods that can be used to detect and characterize them. In addition, the
presentation will discuss the industry’s experience and lessons learned from these
failures and the advantages and disadvantages of various inspection techniques.
Case Study – Planning and Implementing a Successful RBI Program – M. Harmody,
Equity Engineering and R. Corn, Marathon Petroleum
As refiners continue to operate aging infrastructure, safe operation and equipment
availability continue to be key components of profitability. When considering optimizing
inspection projects, more and more refiners are making Risk-Based Inspection (RBI) an
integral part of their plan processes. When applied properly, RBI can refocus inspection
efforts using risk as a basis for prioritizing and managing an in-service inspection
program. A Joint Industry Project for Risk-Based Inspection (RBI JIP) was initiated and
managed by API within the refining and petrochemical industry in 1994. The work of this
JIP resulted in two publications, API 580 Risk-based Inspection and API 581 Risk-Based
Inspection Base Resource Document. The concept behind these publications was for API
580 to present the principles and general guidelines for RBI while API 581 provides the
quantitative RBI methodology. The key concept in RBI methodology is the systematic
determination of the probability and resulting consequence of an undesirable event.
Over the course of 3 years, the principles of API 580 and the technology of API 581 have
been successfully applied to majority of the process units at the Illinois Refining Division
of Marathon Petroleum Company. Through planning, training and plenty of hard work,
the RBI program at the Robinson Refinery has been very successful. This paper provides
an overview of the concepts in API 580 and API 581, a discussion on the steps taken to
lay the groundwork for the RBI program to be successful, examples of where the
program has been successful, and plans for the future.
Case Study – Handling Issues That Arise in a Plant Wide RBI Implementation – S.
Bolinger, BP Texas City
The BP Texas City refinery has performed an RBI analysis on all Tanks, Pressure
Equipment and Piping at the site. This paper will present the findings and risk ranking
for all the equipment in a risk matrix format. The risk ranking of piping is not common
in industry and some of the findings are discussed such as high risk circuits due to
cracking. The paper discusses further several issues that naturally arise when the
program is fully implemented. Such as how and when inspections should be performed
on piping, when does a site switch from rule based to RBI based intervals for pressure
equipment and how deferrals should be executed when the inspections required extend
past the RBI due dates. Additional discussion regarding extending tank intervals past
RBI and rule based due dates. Currently, there is little industry guidance on how these
types of decisions should be made in an RBI based inspection program.
Afternoon Session:
Case Study - PRV RBI Analysis Without Using Commercial Software – L. Ward, Siemens
The purpose of this presentation will be to demonstrate a method for using Risk Based
Inspection (RBI) in the analysis of a Pressure Relief Valve (PRV), including the theory of
API 581, based on an actual completed project (company to remain anonymous). The
presentation will focus on how the PRV RBI methodology evolved, was developed, and
then implemented.
The presentation will also include how equipment and piping RBI analyses were utilized
and the extra challenges to develop the risk matrix for that effort, and how it was
difference from the risk matrix that was used for the PRV RBI analysis, and also how
adjustments were necessary regarding the difference risk matrices.
Details of Consequence of Failure (COF) and Probability of Failure (POF) regarding PRV’s
will also be presented. Consequence of Failure was analyzed by looking at the types of
overpressure scenarios; the discharge location of the relief valves(s), and if there were
multiple relief valves in parallel. Probability of Failure was analyzed by looking at the
number of overpressure scenarios, fluid service severity, relief valve type, if a rupture
disk existed upstream of the relief valve, and inspection history. The resulting risk,
recommended inspection interval, and next inspection date will also be presented.
Five Key Factors to Consider Before Setting Up an RBI System – A. Hilmi, GL Noble
Denton
If used correctly, RBI can be an excellent tool in managing the integrity of assets.
Experience has shown that having the right risk based integrity management strategy
will significantly improve process safety. An RBI output will enable operators to
prioritise inspection and corrosion monitoring effort on higher risk assets. Conversely,
there have been instances where the operators have found out that their current RBI
system has not performed as planned. In this paper, five key factors that operators
should be aware of before setting up an RBI system will be presented. For operators
who are intending to introduce RBI to the organisation, this discussion will assist them
to make a more informed decision before investing in a particular RBI system. For
operators who already have a sound RBI in place, this paper may provide some ideas for
improvement.
Case Study – Effective Integration of RBI & FFS from Equipment Cradle to Grave – A.
Seijas, Phillips66
Managing the life-cycle of fixed equipment in petrochemical plants is a tough business.
Fortunately, Fitness-For-Service (FFS) and Risk-Based Inspection (RBI) are two widely
accepted stand alone methodologies that can work together perfectly facilitating the
management of asset during its lifespan. The API/ASME Standard on FFS provides
quantitative engineering evaluations to demonstrate if an in-service asset (asset or
component) containing a flaw or damage is safe and reliable to operate under specific
conditions during a defined period time; evaluation techniques also consider the
assessment of asset operating under conditions where there is risk of failure. API
published two recommended practices to quantify the risk of operation for process
equipment, providing owner-users to define inspection strategies and programs to
manage the risk of their assets. This paper will describe the most relevant advantages of
integrating RBI programs and FFS applications as part of the overall asset management
program, covering different stages of the life cycle, including construction and
commissioning, operation, inspection, engineering assessment, alteration/repairs, and
decommissioning. A comparison between the non-integrated /reactive and the full
integrated RBI-FFS/proactive approaches will be discussed. A case study is presented to
explain the benefits of implementing an integrated RBI-FFS approach. Finally the paper
will summarized the challenges to implement integrated RBI-FFS/proactive programs,
specifically those face by practitioners (inspectors/chief inspectors/engineers), reliability
teams, and management. This paper is intended for unit inspectors, chief inspectors,
and maintenance and reliability engineers.
Demonstrating Value from the RBI Process - Understanding and Managing Uncertainty
– Greg Alvarado, Equity Engineering Group
Consistency and adherence to inspection effectiveness confidence level rules are
important in the RBI process and for managing uncertainty. This presentation will cover
the impact of uncertainty in the Risk Management process and practices for creating
and interpreting inspection effectiveness tables that comply with API RP 580 and API RP
581. As Bayesian logic is used in the 581 RBI technology and process, a thorough
explanation of the sensitivities and importance of realistic and consistent application of
rating inspection effectiveness is critical to accomplish a credible, effective and
sustainable RBI program. All RBI practices in the process industries are based on relative
risk. As a result, if we lose consistency and credibility the risk rankings are of little
practical good. The focus of this presentation is demonstrating value in the RBI process
via effective management of uncertainties, how to achieve this credibly and consistently
and the role of inspection in understanding, measuring and managing the impact of
uncertainties.
Inspection/NDE Track:
Morning Session 1:
Pipe Hangers/Supports Inspection: What is Involved and What to Look For - Lange
Kimball and Britt Bettell, Stress Engineering Services
The API and ASME Piping Codes have long recognized the need to perform regular
monitoring of pipe supports and restraints at refineries and power plants. This is true
not only of existing plants but also of new plants. The condition of pipe supports and
restraints is an external barometer of hidden problems with the piping and attached
equipment. Recognizing pipe support and restraint distress can help prioritize pipe
inspections and equipment maintenance. The first part of such a surveillance program
is setting up the program. This should include: a.) defining the piping systems that will
be monitored, b.) collecting survey documents, c.) setting up a schedule to perform the
work, d.) training plant personnel who will be performing such a program and e.)
obtaining a commitment by the plant/owners to maintain the program through the life
of the plant. This paper discusses experiences and lessons learned setting up such
programs. Topics will include: 1.) what is a pipe support and restraint, 2.) types of pipe
supports and restraints, 3.) purpose of inspections, 4.) API 570/574 considerations, 5.)
what we look for and 6.) how results are reported.
A New Technique for Quantification of Corrosion at Structural Supports - Gary Kroner,
Carbon Steel Inspection, Inc.
Process, transfer lines or structural piping that requires physical supports usually creates
a potential corrosion site. These metal to metal or metal to insulation contact areas
could be considered as pads and sometimes require a significant amount of resources to
remove and inspect. A new technique developed by CSI called Guided Current Testing
(GCT) uses electrical current to push through the conductive material of interest. Based
on the material conductivity and thickness, current can be applied at varying
frequencies and with sensors placed at various distances to measure basic physical
material properties and test parameters. These properties and parameters are directly
related to the thickness of the test specimen. As wall loss or remaining wall thickness is
the critical variable in the test specimens’ integrity it is estimated via distance amplitude
curves. The amplitude can be any component of the material property or electrical test
parameter. The amplitude change in the material property is primarily caused by a
dimensional change in the test specimen; therefore a baseline reading is required to
determine the nominal reading. Once a benchmark reading is obtained then the
calibration or reference standards are helpful to improve accuracy for any given test but
are not necessary as the wall loss depth estimation curves can be extrapolated from
other distance amplitude curves or known values. The technique is extremely
repeatable and consistent enabling it to be used as a trending inspection for corrosion
rates and life assessments This new NDE inspection technique is targeted to the
Reliability Engineer and Inspection departments to provide a tool to obtain information
in areas that previously are difficult or unobtainable. The equipment and test
measurements are relatively inexpensive and fast as compared to other testing
equipment on the market. Additionally, technician training and implementation is
more conventional than advanced techniques such as Shear Wave, Phased Array and
Guided Wave. All techniques including GCT have advantages and disadvantages which
will be presented in the paper along with some of the variables effecting the
measurements.
Inspection of Raised Face HF Alky Flanges with Phased Array - John Sellers, PetroChem
Inspection Services
Corrosion at petrochemical and refining facilities will always be a major concern for
piping integrity. HF Alkylation units face an unusual type of corrosion that attacks the
raised gasket seating surface of the flanges. Safety conditions associated with the
product as well as access to the area of interest effect the ability to inspect these areas
reliably. Identifying appropriate inspection methods and tools is essential in
establishing a good inspection program of these flanges. Several factors must be taken
into consideration when implementing the inspection of the HF Alkylation units, first
and foremost is safety. Others are access, timeframe, tracking and cost. There are only
a few ways to inspect these flanges to determine if they are fit for continued service. A
commonly used method in the industry today is to visually check each flange set during
an outage by using a straight edge on the surface and measuring the damage to see if it
is in the gasket seating area. This puts the inspector at greater risk of exposure to the
product and forces the Owner of the equipment to wait until outage for cost of
replacement. Phased Array technology can be utilized to screen many of the flanges in
service, thus reducing exposure risks and providing estimated replacement projections
in time to budget for outages. This paper will outline some methodologies used to
inspect these flanges and what the benefits are for doing so. The employment of pre
assessment, indirect/direct inspections and post assessment can prove to be valuable
instruments in obtaining an effective inspection.
A Best in Class Approach to Fixed Equipment Turnaround Management - Nathaniel
Ince and Brad Wells, Pinnacle AIS
The goal of this presentation is to communicate best in class mechanical integrity in
regards to turnaround management. While mechanical integrity programs are now
being implemented and supported from an integrated perspective (integrating
operations, process, maintenance, lab information, IT, etc.), turnaround management
needs to be handled in the same way. Several mechanical integrity responsibilities must
be incorporated to successfully execute a turnaround, including inspection planning,
inspection staffing, inspection execution, corrosion specialist support, engineering
support, and inspection documentation. Traditionally these responsibilities have been
handled through a segmented effort, resulting in poor interfacing and slow decision
making. To ensure a turnaround is both streamlined and valuable, each of these
somewhat independent responsibilities must be viewed from a holistic perspective.
Usually, this process would be laborious, time intensive, and costly. Best in Class
Turnaround Management utilizes a process that provides for effective and quick
decision making, resulting in reduced risk, optimized asset life, and maximized uptime,
and increased personnel efficiency. In this presentation, we will discuss: The type of
team it requires to provide for best in class turnaround management; The type of
systems and interfaces required to ensure effective communication between the team
members; The timeline expectations for different activities, including inspection
planning, inspection reporting, fitness for service assessments, corrosion specialist
feedback, repair/replaced recommendations; The level of turnaround planning involved,
in addition to the training of the turnaround inspectors. Also, during the presentation,
an example will be provided to illustrate the point. In short, one piece of equipment will
be taken through the management process, and inspection plans, inspection feedback,
engineering decisions, and implementation actions will be demonstrated.
Morning Session 2:
Field Applications of Long Range Ultrasonic Testing: Benefits and Limitations - Scott
Taylor, ConocoPhillips
Long range ultrasonic testing (LRUT) is a guided wave screening technique for damage
to pipelines. As part of an integrity program, LRUT can provide inspection information
about hard to reach areas such as offshore deck penetrations or road crossings. The
Alaskan North Slope uses LRUT to screen drill pad, road, and caribou crossings as the
only other inspection recourse is to dig the crossing, cut open the casing, and examine
the pipe directly. Similarly, in offshore situations, LRUT can assess pipe integrity at deck
penetrations and pipe supports where a direct examination is expensive. However, LRUT
as with other NDT approaches has its limitations. This presentation will introduce the
LRUT and discuss data obtained under different scenarios: pipe supports (both welded
and fiber reinforced plastic), foamed-in-place anchors, road crossing, buried pipe,
offshore deck penetrations and pipes with different coatings. As these examples are
presented, the advantages and disadvantages of the technique will be discussed.
EMAT Solutions for In-Service Inspections - Borja Lopez, Innerspec Technologies
Electro Magnetic Acoustic Transducer (EMAT) is a non-contact, couplant-free ultrasonic
technique that generates sound in the part inspected. This method of ultrasonic
nondestructive testing has recently become very popular for corrosion detection on
pipelines and high-temperature measurements. In this paper we present a complete
overview of existing and new applications for EMAT including: Normal beam (0º)
inspections at very high (650ºC) and very low (-50ºC) temperatures; Corrosion
monitoring with permanent sensors; Austenitic weld inspection using Shear Horizontal
sensors; High-temperature weld inspection; Thin weld (<6mm) inspections using guided
waves; Detection of corrosion under supports and on air-to-soil interfaces; Surface wave
inspections; Measurement of material properties (stress, anisotropy, bolt-load); In-Line-
Inspections (ILI). This paper will present the techniques and equipment used on these
applications as well as future trends for EMAT technology and its applications in
Midstream and Downstream.
Practical Applications of Guided Wave Inspection: A Technician's Perspective - Mike
Sens, PetroChem Inspection Services
Guided Wave Pipe testing is a specialty Ultrasonic method that can inspect various
lengths of piping from a single location for a variety of damage types or situations.
Guided Wave testing can be applied in numerous applications; piping in pipe racks for
CUI, piping in pipe racks for corrosion damage at supports, sleeved piping such as road
way and rail crossings, dock piping for external damage from environment, elevated
inaccessible piping on structures or equipment, buried piping for general condition,
piping through tank dike walls, piping through concrete walls, piping with internal
erosion potential from product flow, etc…Although Guided Wave testing has gained
some notoriety as an inspection method it has also fell into disrepute with some for
inappropriate use or impractical expectations. This presentation will cover actual
capabilities and what to expect for results on the above listed types of applications
based on technician field experience with validated findings. False expectations such as
type of results to expect and exaggerated capabilities will be addressed. Actual benefits
and how to effectively utilize the technology will be addressed. Reported results and
general Guided Wave inspection reports will be analyzed. What level and type of
training / certification / experience should the technicians have and what end user
should look for in a quality guided wave inspector.
Non-Intrusive Inspection of Above Ground Storage Tanks – Sam Ternowchek, Mistras
Group
Internal inspections of above ground storage tanks is a very costly inspection. In order to
optimize inspection dollars there is a growing need to acquire as much data about the
internal condition of the tank as possible prior to opening the tank. There are also cases
where opening tanks may cause additional damage such as the introduction of oxygen
in a refrigerated ammonia storage tank or the removal of pacified surface coatings
during sand blasting. At the same time, accurate inspection data is extremely important
in today’s Equipment Integrity Programs. The demand for more complete and accurate
inspection data is driven by, among other things, the increase usage of Risk Analysis and
Fitness for Service methodologies. These techniques allow users to maintain their
equipment at a high level of integrity when the data used for the analysis is
representative of the equipment’s condition. Acquiring accurate, sufficient data is
paramount to successful implementation. An added benefit is to be able to acquire the
data while the equipment is on line and in service so as to eliminate down time. This
presentation describes the use of traditional as well as advance inspection techniques
that provide important information for Integrity Programs for storage tanks. Included
are Acoustic Emission for tank bottom assessment and automated ultrasonic corrosion
mapping. They can be used to detect, locate and size corrosion problems in the floors
and shells of AST’s . Acoustic emission allows for the detection and location of active
corrosion in storage tank floors. Large scale, automated ultrasonic thickness mapping
provides a complete map of corrosion and wall thinning problems in tanks shells,
especially at the liquid to air interface, and annular areas. As non-intrusive inspection
techniques, AE offers the ability to provide global screening of AST floors and annular
areas and AUT provides detailed size and orientation of corroded shell and annular
areas. This presentation will include example of these and how the end user can best
benefit from their use. Limitations of the techniques will also be described.
Afternoon Session 1:
Using Risk-Based Approaches to Define and Adjust CMLs, Inspection Techniques and
Inspection Intervals - Lynne Kaley, Trinity Bridge and Virginia Edley, SBK Consulting
Do you struggle with how to change your routine inspection program to better define
condition monitoring locations based on risk? Is your fixed interval inspection program
optimized to inspect more where needed and less where not needed? Today with
Inspectors having to do more with less, it is even more important to optimize where to
inspect and how to inspect. The presentation will propose a process for using risk-based
criteria to define methods, extent and frequency of inspection for equipment and
piping. This method can be used to optimize the condition monitoring locations,
coverage and maximum inspection intervals, considering the type of damage, the rate of
damage and the consequence of failure. The inspection prioritization method can be
applied without a risk-based inspection approach as well as to any risk- based
methodology. Case study examples will be presented.
The Impact of NDE on RBI Inspection Effectiveness - Anthony J. Rutkowski, Equity
Engineering Group
This presentation will cover a historical perspective of RBI, RBI initiatives, various factors
of the challenge, inspection strategy decisions, impact of inspection type and
inspector/NDE operators, effectiveness and why we inspect.
Robotic Crack Detection for Delayed Coke Drums using ACFM - Jacqueline Cameron,
CIA Inspection Inc
Since 1993, CIA Inspection (CIAI) has been operating a laser profiling service that locates
and measures distortion areas in coke drums. To date, CIAI has performed nearly 1000
inspections on operating coke drums throughout the world. During these inspections,
many crack type indications have been identified with the visual inspection system but
the existing technology was unable to validate or quantify the nature of these
indications. As part of its ongoing in-house research efforts, CIAI embarked on a
program to design, build and test a robotically deployed sensor which could identify,
validate and quantify crack type indications in live coke drums without shutting down
the process using a customized ACFM probe and crawler. This presentation will describe
the concept and provides an update on the current state of the program, focusing on
the results of recent field trials at several refineries in North America. They will discuss
ongoing efforts at their respective sites to further the development and implementation
of this unique tool.
High Temperature Hydrogen Attack Life Assessment Methods – Brian Olson, Stress
Engineering Services, Gerrit Buchheim, Consultant, Tim Munsterman, Lloyd’s Registry
Afternoon Session 2:
The Evolution of the API UT Examiner Qualification into Four Phases –
QUTE/QUSE/QUTB/QUPA- John Nyholt, BP
After a decade of API UT Examiner Qualification testing, the exams are being updated to
reflect performance trends against industry expectations as well as expanding
into additional ultrasonic test methods. This presentation will review past
exam performance measures, pass / fail rates and evolving UT technology and industry
needs. The API QUTE Exam has expanded from a fundamental UT weld flaw detection
and characterization test to UT crack sizing (QUSE), tank bottom thickness measurement
(QUTB) and UT phased array weld flaw detection and characterization (QUPA). This
presentation will discuss exam results to date including performance measures,
common reasons for exam failure, and recommendations on how to prepare for future
API UT examiner exams.
New-Generation Portable Phased Array Systems - Patrick Tremblay, Larry Mullins,
Laurent Enenkel, Zetec
Moore’s law states that computer power doubles every eighteen months. This
exponential improvement has dramatically enhanced the impact of digital electronics in
nearly every segment of the world economy. It also applies to the non-destructive
testing industry. The first generation of portable phased array UT systems has hit the
market in the early 2000’s. The massive adoption of these devices has been a game-
changer for ultrasonic inspections of critical components in oil & gas, aerospace, heavy
industry and power generation plants. Being given their relatively low computing power,
operators have learned to deal with the intrinsic limitations of the older portable PA
systems to a point where it has became normal to limit the number of focal laws, the
data quality and/or the data file size. This paper will show how enhanced computing
power of new-generation portable phased array UT systems allows breaking the barriers
to truly efficient data acquisition. In particular, we will explain through representative
user cases how more focal laws, more amplitude resolution and larger data file size
allows more efficient inspections.
Inspection Alternatives for Touch Point Corrosion at Pipe Supports- Mike Wechsler,
Mistras Group
Due to recent failures, and the aging infrastructure, piping circuits and supports are
becoming more of a focal point for inspections. However, most are unaware of
technologies currently being utilized to aide in these types of inspections. We will
discuss an ultrasonic technique to aide in determining if corrosion exists at the support
locations and approximately how deep the affected areas are.
Leveraging the Use of Permanently-Mounted High Temperature Wireless UT Sensors -
Hamed Bazaz, BP
Controlling corrosion is one the biggest challenges in the oil and gas industry, with vast
expanses of pipelines and metal exposed to harsh temperatures and processing
environments. Oil reserves being discovered today are heavier, more sour, and contain
different contaminants than the light sweet crudes of the past. New technologies
developed by BP and partners are leveraging a unique combination of science and
electronics to keep the threat of corrosion at bay. In collaboration with Imperial College
London, BP has developed a new ultrasonic spot sensor which can be permanently
attached to the plant (e.g. piping, vessels, tanks, etc.) at temperatures up to 600º
Celsius. This revolutionary device is wireless-enabled and has a resolution capable of
detecting small changes (±0.1mm) in wall thickness due to corrosion. Once installed,
repeated measurements can be taken without access, except to change the battery
every 5 years. The sensor is particularly well-suited for areas of the plant that are
difficult to access by inspection personnel. The technology has been commercialized
and available through Permasense, a spin-off of Imperial College. Today, the
Permasense sensors have been installed in all BP-operated oil refineries globally.
Continuous wall thickness monitors are helping to alert corrosion engineers on a real-
time basis, preventing leaks and changing the way BP approaches corrosion
management. The implemented technology is being leveraged to enhance safety,
monitor equipment health, optimize process control, inform maintenance schedules,
and quantify the performance of barrier systems.
Materials/Corrosion Track:
Morning Session:
Understanding and Inspecting for Naphthenic Acid Corrosion – Joyce Mancini, BP Texas
City
As stated in API-581, “While various papers have been presented on naphthenic acid
corrosion, no widely accepted correlations have yet been developed between corrosion
rate and the various factors influencing it.” As a result, there are a lot of misperceptions
for both prediction and prevention of this specific corrosion mechanism.
Increasing demand on the oil market has raided interest in oils with high naphthenic
acid concentration. These so called “opportunity crudes” are also referred to as “lower
quality” corrosive crudes due to their high naphthenic acid content. As a result, refinery
Inspectors have to adopt special strategy for monitoring the mitigating efforts of acidic
crude oil corrosivity and monitoring where the effects are going to cause corrosion. This
presentation will address the known facts for naphthenic acid. It will cover the effect of
naphthenic acid concentration, the combined effects with sulfur, temperature,
metallurgy and more.
How to handle the Corrosion Aspects of Opportunity Crudes– Hearl Mead, Shell Global
Solutions
Over the past few years increased feedstock flexibility has become an increasing reality for refineries to be a viable and profitable business. Gone are the days when as a corrosion engineer can set the operating limits to run sweet, non-corrosive crudes, and reject all other crudes. A profitable refinery requires processing of more difficult crudes, increased volumes of spot cargoes, and rapid response to crude acceptance requests. Reliability and process safety events have occurred from changes in crude supplies or varying crude blends and quality. These events can eliminate all profits gained from opportunity crudes. A robust end-to-end process is required to proactively manage these threats. This presentation will focus on the involvement of corrosion and inspection engineers in Crude Flexibility Reliability Management – management of change, inspection strategies, monitoring, CCDs, RBI, equipment integrity, corrosion models, downstream units…
Case Study of an Unusual Lower Temperature Naphthenic Acid Corrosion Failure –
Mike Urzendowski, Valero
It has been stated in many technical publications, that Naphthenic acid corrosion (NAC)
occurs at temperatures greater than 450°F (232°C). Because of these statements and
beliefs, many organizations do not inspect specifically for the localized corrosion that is
associated with NAC, nor do they inject Naphthenic acid inhibitors to prevent against
such attack. Recently, there has been mention of failures in streams having operating
temperatures less than 450°F that have been attributed to NAC, either in whole or in
part. Valero recently experienced one such failure, believed to be caused by NAC, at
their Port Arthur refinery, in a LVGO stream which operates with an average process
temperature of 400°F. This presentation describes this failure and what are believed to
be the contributing factors which helped to promote this attack at seemingly cool
temperatures, well below what is considered the “norm” for this mechanism
Solving Overhead Corrosion Problems – Successful Case Studies – George Duggan,
Baker Hughes Corp
Corrosion in refineries results in substantial costs, approaching $2/barrel of crude
processed. Managing refinery corrosion starts with an investigation into the underlying
causes. Mitigating corrosion is, in some cases, focused on metallurgy and corrosion
inhibitors. However, in the case of overhead system corrosion, a wide variety of options
exist to address the corrosion impact, including contaminant control, operating targets,
equipment re-design, chemical treatments and metallurgy. A successful mitigation
strategy should consist of those steps that provide the lowest cost of operation for the
refiner. This presentation describes the techniques used to diagnose overhead system
corrosion and select an appropriate mitigation strategy. Examples of successful
outcomes are included.
Afternoon Session:
Highlights of API 939C – Avoiding Sulfidation Failures - Gerrit Buchheim, Consultant –
Included in Sulfidation Panel Discussion
Sulfidation of Low Silicon Components - Case Study – Clay White, Phillips66 - Included
in Sulfidation Panel Discussion
Phillips 66 has recently encountered several cases of higher than expected corrosion rates and one significant failure of low silicon carbon steel (A-53 Grade B) piping. Although the potential for this problem was recognized, recent events prompting a revision to an internal required standard to ensure all potentially low silicon piping components operating in a high temperature sulfidation environment be identified and inspected. This presentation will highlight some of the general industry experience and details of several of Phillips 66 own cases with this corrosion problem.
Sulfidation Leak on Crude Unit Piping – A Significant Near Miss– Art Jensen, Delaware
City Refining (PBF Energy)- Included in Sulfidation Panel Discussion
Sulfidation Panelist – Jessica Stankiewicz, Chevron Richmond Refinery
Corrosion Control Documents- the Indispensable Guides to Inspecting for Plant
Damage Mechanisms-Hearl Mead, Shell Global Solutions
This presentation will show how valuable CCDs are (or can be) to the corrosion and inspection engineer to be pro-active in enhancing process safety and equipment reliability at their site. The presentation will cover a brief description of how reactive life as a corrosion engineer was without CCDs, the content of a strong CCD, who should be involved, and how it should be maintained. A CCD that is written by a team of experts and set on the shelf as “job completed” is pretty much useless, or not useful beyond the memory of the team that developed it. The CCD has to become a tool for the corrosion, inspection, and process engineers, as well as unit operators.
Thursday, January 10, 2013
Upstream / Midstream
Pipeline Inspection Track:
Remote Measurement of Stress in Carbon Steel Pipelines - Paul Jarram, Speir Hunter
Monitoring the integrity of buried ageing ferromagnetic pipelines is a significant
problem for infrastructure operators. Typically inspection relies on pig surveys, DCVG,
CIPS and contact NDT methods that often require pipes to be uncovered and often at
great expense. This presentation outlines recent developments in a novel remote
sensing technique to detect corrosion, metal defects and the effects of ground
movement by mapping variations in the earth’s magnetic field around pipelines.
Magnetostriction is the process by which internal domains inside the structure of
ferroelectric materials, such as carbon steel alloys, create magnetic fields when
subjected to mechanical stress. Corrosion, metallurgical defects and ground movements
result in areas of increased stress in pressurised pipelines. Measurement of the remote
magnetic field around a pipeline due to magnetostriction allows the measurement of
stress and determines the location of defects in the pipe wall. The presentation first
explores magnetostriction in ferromagnetic materials and then how measurements of
remote magnetic field can be applied to define the location of defects in operational
pipelines along with the benefits of using this technique which includes considerable
cost savings since no modification to the line is required, no input of energy and no
change to its operational parameters is needed. Examples of modeled predictions
correlating both with actual scanned data collected from the field and ILI defined
defects will be presented. This presentation will be of particular interest to all pipeline
integrity and inspection management and engineers and specifically offers a solution for
those involved with the inspection of unpiggable lines.
Magnetic Tomography Method a Remote NDE Technology for Buried & Subsea
Pipelines - I Kolesnikov, Transkor Group
Magnetic Tomography Method (MTM) Technology is a non-contact approach for
assessing safety and integrity of pressurized pipelines of any purpose made of
ferromagnetic materials. Quality of assessment is not influenced by transported product
(gas-, oil-, water- , or other). MTM is based on the inverse magnetostrictive effect
(Villary effect) - the change of the magnetic susceptibility of a ferrous material when
subjected to a mechanical stress. Method uses ""natural"" magnetization of the ferrous
pipes by magnetic field of the Earth. MTM equipment remotely registers magnetic field
from the pipe while moving along its axis. MTM does not measure the dimensions of
geometric defects alone but instead it measures the stress caused by these defects and
identifies their type, location and orientation in accordance with the location and
orientation of the area of stress. MTM determines the comparative degree of danger of
defects by a direct quantitative assessment of the stress-deformed state of the metal.
This technology ensures probability of detection (POD) of anomalies of stress-deformed
state greater than 80% at SMYS from 30% to 85%. POD is never less than 60% for any
SMYS value. MTM inspection covers 100% length of pipeline and has following features:
measurements could be performed remotely from within 15 diameters off the pipeline
axis for both buried and sub-sea pipelines , without interference with the pipeline mode
of operation Outcome of the application of MTM technology is the information on
potentially faulty sections causing elevated concentration of mechanical stress. The
latter includes: location (longitudinal, angular, GPS coordinates) evaluation of degree of
danger (absolute value of local stress in the pipe material is computed, safe operation
term is evaluated, maximum safe operating pressure of each pipeline anomaly section is
calculated)As a part of adapting technology for the inspection of offshore pipelines, a
series of tests was carried out during the last 2 years on the quantitative assessment of
factors of pipeline serviceability with defects, provided the changes of hoop stresses.
The outcome of comparing the results with the international codes ASME B31.G, API
RP579, DNV RP F101-A & B demonstrate the convergence rate of more than 92%.
Rapid EMAT Lamb Wave Scanning of Onshore & Subsea Pipelines - Mark Adams,
Spectrum
Inspecting pipelines using a couplant free ultrasonic guided wave system called EMATs
(electromagnetic acoustic transducers) are simply a coil of wire in a magnetic field. By
pulsing an electrical current through the coil, an eddy current is induced in the surface
of the nearby conductive material; the magnetic field interacts with this eddy current to
produce a mechanical force on the surface to excite ultrasonic vibrations. The same
configuration of coil and magnet also detects mechanical motion of the surface because
the motion of a conductor in a magnetic field produces currents that are detected and
measured by the near-by coil. One of the most useful properties of EMAT technology as
an inspection technique is its ability to generate the guided waves without having to
worry about coupling, due to the non-contact and couplant-free nature of EMAT
transducers. This ability enables EMAT technology to generate ultrasonic guided waves
and scan the transducers over the inspection area at the same time. Our company has
recently started to utilize our EMAT technology and developed a subsea pipeline
inspection system called Magna Subsea Inspection System™. This EMAT technology is
applied to the subsea pipelines for non-piggable pipelines, jumpers, risers and flow lines
on the ocean floor. We have inspected two of the world’s largest Pipelines using our
EMAT technology.
Gamma Transmission Detection for Deposition Studies - Jim Bramlet, Tracero
This paper will describe the use of on-line diagnostic technologies for pipeline inspection
that can be used to accurately measure the amount, location, and profile of any type of
deposits within pipelines using gamma transmission. This technique uses a small sealed
radioactive source and sensitive radiation detector positioned at adjacent sides of the
pipe. The measured signal intensity can be directly related to the amount of deposit in
the pipeline. Unsealed radioisotope tracing techniques are also used on a regular basis
to measure fluid velocity, flow rate, phase distribution, and deposit inventory. By
measuring the time interval between detector responses and knowledge of spacing the
mean linear velocity can be calculated. If full bore turbulent flow can be assumed then
the velocity can be converted to volumetric flow knowing the pipe internal diameter.
For this paper the focus will be on sealed source gamma transmission technology. The
application of gamma transmission for deposition studies can be summarized as follows:
Identify, locate and quantify pipeline materials such as waxes, scales, sand, sludge, and
hydrates, Assess total pipeline deposits as part of a cleaning program, Monitor pipeline
wax build-up over long time periods. This paper will illustrate how employing these
techniques in a remediation project will increase productivity, lower operational costs
and allow the optimization of downtime.
“Ultrasound Data Processing for Detection of Laminar Imperfections in Welded Pipes"
- Christophe Imbert, Olympus NDT
Oil & Gas well Drilling Tool Inspection - Mark Carte, Olympus NDT
This presentation includes the intricate details of inspection, dollar volume of this
inspection business, safety concerns and the cost associated with Drilling Tool failures.
The purpose of the presentation is to inform those who are concerned with the safety
and efficiency of Oil & Gas Well Drilling. Also it is intended for those who are interest in
expanding their inspection services in the Up Stream Petroleum Business Sector. It is the
presenters intention to provide valuable information for a full spectrum of attendees
including Owner Operators of Drilling Rigs, Oil & Gas Companies and Inspection Service
Providers. Included within the presentation is an all-encompassing information package
detailing the Drilling Tool Inspection Business.
Mechanical Integrity & Damage
Use of Facility RBI versus Direct Assessment- Justin Monroe, Chevron
Both risk-based inspection and direct assessment have been used throughout the oil
and gas industry for over a decade. Direct assessment was developed to identify areas
on a pipeline where there is greatest potential for either external (potential damage to
pipeline coating) or internal (probable areas where electrolyte can collect) corrosion by
the following 4-step process: Preassessment; Direct Assessment region identification;
Identification of locations for excavation and direct reexamination; Post assessment
evaluation and monitoring. Risk-based inspection (API documents RP 580 and RP 581) is
a process used predominately in upstream and downstream that evaluates both the
probability of failure along with the consequence of failure in order to identify the
following: Damage mechanisms; Inspection techniques; Corrosion monitoring location.
Both of these methods provide risk mitigation/minimization strategies based upon
decisions from non-destructive examination data at corrosion monitoring locations.
However, an issue has emerged over which methodology would be more appropriate to
identify areas to inspect at pipeline facilities. This presentation will identify similarities
and differences between these two processes in order to provide guidance for the
appropriate use of both processes for midstream operations.
MI Inspection During Capital Projects Promotes PSM Compliance, Corrosion rate
Accuracy & Improved Budgeting - Travis Keener
Putting off the initial inspection (i.e. baseline) of piping and vessels in a new process unit
is both common and problematic. The tendency is to rely on the nominal thickness
because the actual original thickness was either not measured or not recorded.
Consequently, significant errors in calculated corrosion rates may result from variations
of thickness allowed by mill tolerance standards during fabrication. Not having the
original thickness can mask potentially hazardous conditions, or cause concern where
none is really warranted. Involvement of the inspection department in a capital project
can significantly improve quality, reduce cost, and ensure compliance. The objectives of
this paper are to provide: 1) justification for inspection during capital projects; 2)
effective roles for inspection departments in capital projects; 3) justification for
performing vendor surveillance in capital projects; and 4) the technical advantages from
performing pre-service baseline inspections.
RBI for Decision Making & Infrastructure Assessment - Mike Manning, Kleinfelder
This abstract presents a risk based assessment program for infrastructure, and a
quantitative method of prioritizing resources required to inspect, document, analyze,
and plan asset repair. This topic is relevant because limited funds, workforce, and
management, demand sound quantitative methods of efficient and consistent data
collection, automated data analysis, automated risk prioritization, and automated RFP’s
to be used in forecasting, budgeting, and implementation. The objective of this abstract
and presentation is to illustrate a method of efficient information gathering and
automated decision making tools to: Assess Assets; Manage Risks; Reduce Costs, and
Schedules; Prioritize Resources; Reduce Contractors and Staff; Provide Consistent Data
Collection, Documented Quantifiable Decision Tools, Tools For Budgeting and Planning,
Easy To Use At-A-Glance Reports 56. Facilities are outliving their intended life. We all
face a difficult challenge of determining how to allocate funds and staff to manage risk.
Facilities are under heightened scrutiny to maintain integrity for safety, productivity,
and environment. Much of the infrastructure we rely on falls outside of mandatory
inspection and reporting but is critical to safe productivity. Electronic data capture via
tablets provides efficient and consistent data. Tablets programmed with well thought
out inspection inquiries leads to precise quantitative data collection no matter the
experience of the inspector. Predetermined risk parameters provide automated ranking
of priorities based on owner’s risk weighting. These automated rankings can be sorted
by risk, material, cost to repair, method of attachment, condition category, or
deficiency.(see attached samples for clarity) Easy to read rankings are highlighted in red,
orange, yellow, and green representing high risk to low risk. These user friendly reports
allow for quick and easy at-a-glance assessment and eliminate stalled forward progress.
The sample report is posted separately on sharepoint.
Asset Integrity Within Chevron - Phillip Delpero, Chevron
Over the past five years, Chevron Upstream has been working to develop the asset
integrity requirements and procedures that are part of the Surface Equipment Reliability
and Integrity Process (SERIP). The initial effort was on developing the overall Asset
Integrity Program and required management systems. Equipment specific requirements
were then developed covering the range of equipment types encountered in
Upstream. The last phase of the development effort is in progress and is focused on
development of some standardized methods to assure more consistent performance
across a diverse upstream workforce. Implementation of these requirements is now in
progress across upstream. Initial implementation is focused on establishing an overall
Asset Integrity Program and supporting management systems and implementation on
the primary layers of protection of fixed equipment and structures. This talk will discuss
the overall principles of the Chevron Upstream SERIP Asset Integrity requirements. The
talk will first focus on the programmatic aspects of the SERIP Asset Integrity
requirements, will expand to cover SERIP asset integrity requirements at the equipment
specific level, and then will wrap up some field learnings experience as Business Units
implement their asset integrity programs.
Speeding Up Your Inspections with Eddy Current Arrays - Dana Ives and Bobby
Kennedy, Mistras Group
Over the years, probe technology and data processing have advanced to the point
where Eddy Current Testing is recognized as being fast, simple, and accurate. The
technology is now widely used in the petrochemical, aerospace, automotive, and
power generation industries for the detection of surface or near-surface defects in
materials such as aluminum, stainless steel, copper, titanium, brass, Inconel®, and even
carbon steel (surface defects only). With the advancements in probe design and
multiplexing, Array Eddy Current drastically reduces inspection time and covers large
areas with a single pass. It also provides real-time cartography of the inspection area
which asset greatly in the data interpretation and improves reliability and probability of
detection (POD). A brief discussion will be presented regarding application array eddy
current for stress corrosion cracking (SCC), Hydrogen induced cracking (HIC), and
permeability variations in duplex piping.
Reliability / Integrity Management Track:
Synergy Damage Behavior in Pipeline Steels - Prof. C Huai –Xiang
Type L390 steel is widely used in buried natural gas pipelines. During the installation and
operation of natural gas pipeline, peeling, cracking, broken, pinholes and other damages
often appear in the coating. In the case of mechanical damages of pipe or coating
failure, it will suffer high stress and corrosion of soil, and should lead to accidents of
leakage or explosion. In this paper, corrosion experiments of L390 samples at various
stress levels in NS4 solution were conducted. Furthermore, the corrosion behavior and
law of L390 samples at various stress levels were studied by means of corrosion
morphologies, weight losses and electrochemical techniques. The results showed that,
synergy damage of stress and corrosion was not only a sum of stress injury and
corrosion damage, but also an accelerated corrosion, that the synergy of the total
damage was greater than the amount of two kinds of damage. Finally, it was pointed
out that the results were useful for the prediction of initiation life of stress corrosion
cracking (SCC) of pipelines.
Coiled Tubing Assessment Tools for Manufacturing & In Service Inspection - Roderic
Stanley, itRobotics
Advances in 3D Measurement In RVI - Edward Hubben, GE Measurement and Control
Facility Inspection beyond DOT Regulations - Justin Monroe, Chevron
Downstream
Engineering/Analysis Track:
Morning Session:
Optimizing the Minimum Pressurization Temperature for Hydroprocessing Reactors–
R. Brown, Equity Engineering
Heavy wall low-alloy hydroprocessing reactors are designed to operate at high
temperature and high hydrogen partial pressures. This operating environment results in
two main factors that affect the specification of minimum pressurization temperature
(MPT); long-term temper embrittlement and embrittlement caused by the hydrogen
charging within the reactor pressure boundary. During startup and shutdown
conditions is when the vessels are most vulnerable to potential brittle fracture and
hence the need for controlled pressurization/de-pressurization and heating/cooling
rates. Along with establishing the minimum safe operating limits, the optimization of
start-up and shut-down of heavy-walled reactors (MPT envelope definition) has the
potential to save significant time and related cost per unit shut-down cycle, while
maintaining acceptable risk tolerance. Many companies are seeking to optimize their
procedures by using faster heating/cooling rates, allowing pressurization at lower
temperatures, and/or cooling with hydrogen instead of liquid nitrogen. Provided in this
paper is an overview of the objectives of MPT optimization and the critical factors
related to structural integrity that affect startup and shutdown duration. A
methodology to establish the MPT envelope will be provided and reviewed in
comparison to the current draft API 934-F recommended procedure. Considerations for
both aged reactors and modern 2-1/4Cr-1Mo and vanadium enhanced materials will be
reviewed.
Highlights of Recent Revisions/New Articles of ASME Std PCC-2, Repair of Pressure
Equipment and Piping – S. Roberts, Shell Global Solutions
The third edition of ASME PCC-2, the 2011 edition, has been issued and contains 28
articles describing a wide variety of techniques used to repair pressure equipment and
piping. The intent of the document is to provide recognized and generally accepted
good engineering practice in repairs. While it is not a code, the intention is that it be
referenced by post construction inspection codes, such as those issued by API and NBIC.
It includes repairs using welding, those using mechanical devices such as clamps, repairs
using non-metals such as composite wraps, and guidance on examination and testing.
This presentation provides an overview of the current edition of ASME PCC-2, as well as
potential future repair articles that are under development.
Case Studies – Cost Effective Improvements for the Reliability & Integrity of Fired
Heaters – Tim Hill and James Widrig, Quest Integrity
Fired heater reliability has been a critical economic determinate to today’s refinery
integrity management programs. Unreliable operation due to radiant or convection
tube failures of these non-spared assets can quickly lead to millions of dollars in lost
profits. These tubes are only one part of a complex furnace system and the
performance of other associated components can result in integrity issues as well. This
presentation outlines approaches to operate and maintain all fired furnaces within a
refinery using best practices that minimize risk, minimize the amount of maintenance
and inspection shutdown work and maximize performance. It describes how to monitor
performance and reliability of a fired heater and use this data to evaluate operating risk,
fitness-for-service and remaining life of critical components. Case study examples will
illustrate the integrity management process for real world fired heaters. Attendees will
take away best practices that may be used to manage the integrity of all critical assets at
their refinery.
Challenges in Remaining Life Assessment of Furnace Tubes - Antonio Seijas, Phillips66
Afternoon Session:
How to Conduct the Right Inspections for Effective FFS Analysis – M. Jafari & Steve
Wickerson, Mistras Group
Since 2001, API 579-1/ASME FFS-1, “Fitness For Service” (FFS) document has been
utilized by many professionals in the chemical and petroleum industry to mitigate the
risk of operating process equipment with possible anomalies. A FFS assessment is an
engineering analysis of equipment to determine whether it is fit for continued service.
The equipment may contain flaws, may not meet current design standards, or may be
subject to more severe operating conditions than the design conditions. The product of
an FFS assessment is a decision to safely operate the equipment as is, or to alter, repair,
monitor, or replace the equipment. The data required for a for a FFS assessment depend
on the flaw type or damage mechanism being evaluated. Data requirements may
include: original equipment design data, information pertaining to maintenance and
operational history, expected future service, and data specific to the FFS assessment
such as flaw size, state of stress in the component at the location of the flaw, and
material properties. Data requirements specific to a damage mechanism or flaw type
are covered in the Part containing the corresponding assessment procedures. However,
in compiling these data often inspectors do not pay enough attention to the detail of
what is required. Often the FFS engineer have to ask for more information which may
lead to re-inspection of the same equipment and create delay and more cost for the
evaluation. This paper presents the requirements for inspection as outlined by the API
579-1/ASME FFS-1 for various damage mechanisms and educates inspectors on
gathering the appropriate data for engineering assessments. This will help the FFS
engineer to perform the evaluations on a timely manner which ultimately reduces the
costs for owner/user organizations.
Case Study - Using Laser Scan Technology to Speed Up & Improve Inspection
Effectiveness for FFS Analysis– S. Bouse, Stress Engineering Services.
Recent advances have enabled the performance of FFS assessments of bulges,
distortions, corroded regions, and crack-like flaws in a much shorter time frame than
could previously have been achieved. These advances now permit preliminary Level 3
assessments of distortions to be performed within 3-4 days of initial request, and within
4-6 days for crack-like flaws. These times compare favorably against historically longer
time required for complex distortion and crack-like flaw analysis with prior
methods. Much of the improved analysis speed has been derived through the use of
laser scan technology and close coordination with service contractors (CIA, Meridian,
etc.). Coordinating our efforts with a laser scan contractor allows us to focus more
quickly on the assessment, and spend less time in data manipulation. The system and
procedures we use were developed to work with a wide variety of input data formats,
mitigating dependence on any one survey contractor to deliver these rapid results. This
presentation will discuss the timeline and methods of a recent case study, from start to
finish, culminating with the results. In our demonstration case, the workflow outlined in
this presentation began on a Tuesday afternoon, with internal laser scanning performed
Wednesday mid-day and preliminary results available to the client by Thursday
afternoon. The accelerated results achieved through this process enabled the operator
to avoid unnecessary repairs (and the delays that accompany such work).
Evaluation of Laminations and Flaws in Equipment in H2S Service – Brian Mecejko and
Ryan Jones, Equity Engineering?
Part 13 of API 579-1/ASME FFS-1 Fitness-For-Service (API-579) details the inspection
requirements and evaluation techniques for Assessment of Laminations. It is very
common for carbon steel manufactured prior to the 1950’s, 1960’s, and 1970’s to have
laminations and inclusions. Without destructive testing or a baseline ultrasonic
examination (UT) inspection, it is nearly impossible to decipher whether laminar
indications in plate material have been present since original construction or whether
they have been caused by hydrogen diffusion during operation. API-579 therefore
requires that multiple levels of relatively closely spaced laminations in a hydrogen
charging environment must be treated as Hydrogen Induced Cracking (HIC) and
therefore evaluated using Part 7 Assessment of Hydrogen Blisters and Hydrogen
Damage Associated with HIC and SOHIC. The Part 7 procedures consider the potential
for failure due to loss of material strength as well as brittle fracture. Even if the damage
is concluded to be completely laminar without evidence of through-thickness directional
cracking or linkage between laminations, there is no guidance provided in the API-579
document to justify reduction of the conservative assumptions on material strength and
fracture toughness that are typically used to evaluate HIC (and SOHIC) damage.
Subsequently, many assets fail the Fitness-For-Service evaluation procedures. A recent
case history involving evaluation of laminated plate removed from a hydrogen charging
environment will be presented. The presentation will include results from field and
laboratory non-destructive examination (NDE) techniques as well as destructive material
testing.
New ASME Program for Training and Qualification of Bolted Flange Joint Assemblers –
C. Rodery, BP
A revised Appendix A of ASME PCC-1 has recently been approved and will be published
in the near future. This Appendix was developed in response to a need expressed by
some in the bolting services industry. It provides guidelines for establishing uniform
criteria for training and qualifying bolted joint assembly personnel. It also provides
guidelines for quality control of the program. This presentation will provide an overview
of the key highlights of the Appendix, including the various qualifications that are
available, the related experience requirements, the fundamental training areas
associated with each qualification, an examination overview, maintenance of
qualifications, and ongoing quality assurance of the program.
Inspection/NDE Track:
Morning Session 1:
In-Service Inspection of Stainless Steel Heat Exchanger Tube with Eddy Current Array
Probe- M. Grenier and J.R. Konerza, Eddify and J.R. Konerza, Sentinel Integrity
Eddy Current Testing (ECT) is a commonly used technique to inspect non ferromagnetic
heat exchanger and condenser tubing. The typical bobbin probe configuration has
proven to be efficient to detecting volumetric flaws such as pitting, fretting, erosion
and general corrosion. To some extent, it is even possible to perform sizing with this
probe / coil configuration as long as the calibration standard represents the damage
mechanism found in the tubes to be inspected. However, this probe design faces two
major limitations, the first limitation is when the defect mechanism is related to
cracking, especially along the circumferential axis of the tube, the second limitation is
the ability to determine circumferential extent for larger volume flaws. Motorized
Rotating Pancake Coil (MRPC) probes have been developed to overcome the limitation
of the circumferential cracking and to provide a high resolution mapping of the tube,
sensitive to all type of flaws in any orientation. However, this inspection technique
remains very slow and not appropriate to inspect the entire tube length. Eddy Current
Array (ECA) probes have been introduced with some success for Steam Generator
inspections, but these probes are very specialized and cost prohibitive outside the
scope of SG applications. Other specialized bobbin probes also labeled as array probes
integrate a dedicated coil assembly to detect the circumferential cracking are available,
but the sensitivity is generally not uniform around the circumference and the sizing
capability remains very limited. Another alternative to MRPC, SG Probes, and
specialized bobbin probe is to use Eddy Current Array (ECA) probes that utilizes channel
multiplexing. The ECA probe integrates several individual surface sensor coils into the
probe which are channel multiplexed to improve the resolution, the detection
capability and the sizing of defects while maintaining high speed inspection of the
entire length of the tube. This paper provides an overview of the operating principles
and the capabilities of a new configuration of ECA probe that combine a high resolution
array sensitive to circumferential defect and a regular bobbin probe. Laboratory and
field results are presented and compared to normal and specialized bobbin probe
response. The effect of the tube sheet and tube support plate on the signal quality and
defect detectability is also discussed.
Near Field Testing: New Developments and a Case Study - Tim Rush, Mistras Group
This paper addresses Near Field Testing (NFT), which was introduced in the Oil and Gas
industry approximately 10 years ago for the inspection of air cooler tubes (Fin Fans).
This technology has proven to be a cost saving alternative over other inspection
methods, such as IRIS and MFL (Magnetic Flux leakage). By illustrating examples of field
cases, data graphics, etc., the presentation will show the advancements of the
technology and how it has become a preferred tubing application for the detection of
internal corrosion, pitting, and inlet erosion.
Inspection of Insulated Components by Pulsed Eddy Current for CUI & High
Temperature Damage- Tom Burnett, Intertek/Apteck
Industry experience with the catastrophic failure of piping, feedwater heater shells,
high pressure feedwater lines, auxiliary steam systems and other miscellaneous piping
systems fortify the mandate to locate, inspect, and classify the degree of corrosion
under insulation, flow accelerated corrosion and other wall loss damage common to
these systems. Most inspections are typically a balance between intrusive offline and
non-intrusive, on-stream methodologies. Numerous current state-of-the-art inspection
methodologies are being applied in plants to measure wall thickness such as: ultrasonic
testing (UTTH), radiography (RT) and Pulsed Eddy Current (PEC) for this purpose. Non-
intrusive, on-stream inspection of equipment in high temperature service because of
the presence of insulation is particularly challenging. Significant improvements have
been made to the PEC technologies for this purpose, as well as for additional
applications in industry. This presentation is meant to provide information on the
improvements and application of current technology for high temperature wall loss as
well as common problems and restrictions associated with methodologies.
Eddy Current Arrays as a Replacement of Traditional NDT Methods for Detection of
Surface Breaking Cracks - Tommy Bourgelas, Olympus NDT
Multiple Eddy Current Sensors placed in close proximity to form an "Array" provides
large surface area inspection rapidly. This technology provides a "C Scan Image" of the
area inspected therefore recording and documenting the inspection. Eddy Current
Arrays rely on magnetic field coupling, which provides fast inspection through coatings
such as paint. Rapid coverage, high sensitivity and probability of detection excels over
traditional NDT methods such as Penetrant and Magnetic Particle. This presentation
will detail the fundamentals of Eddy Current Testing, the latest Technology in Eddy
Current Array and exemplify applications through illustrations and photographs
Morning Session 2:
Active Corrosion Monitoring with AET – Successful Case Studies - Miguel A. González
Núñez, Jean-Claude Lenain, Alain Proust, Valery Godinez, Mistras Group
Short periodic in-service monitoring with a specialized Acoustic Emission (AE) system
started with CORPAC™ and now Pocket CORPAC™ and proprietary software, provides
early detection of “ACTIVE” corrosion in such industrial structures as process
equipment, vessels, tanks and piping, all whether carbon or stainless steel. The general
CORPAC™ technology has been developed in Europe over the past fifteen plus years
with MISTRAS Group (Euro-Physical Acoustics, French subsidiary) Rodhia, Solvay and
INSA Lyon starting with a European Seed Grant. For the past 20 years MISTRAS Group
has reported the successful in-service corrosion monitoring of above ground tanks
utilizing its proprietary TankPAC™ acoustic emission expert system technology package.
More than 10,000 tanks have been tested repeatedly worldwide and especially in
Europe. In practice the AE detection used for above ground storage tank inspection are
rarely suitable for in-service monitoring of active corrosion and frequencies 5 times
higher need to be used in process environments in order to avoid strong background
noises created by the processes. In-turn, one consequence of the use of higher
frequencies for active corrosion monitoring is that the distance at which AE sources can
be detected is limited to typically one meter distance from the sensor. The ability to
identify when corrosion is active is very useful and in many ways. For example,
CORPAC™ technology can be used to help corrosion control inhibitors to be added
when corrosion is detected to be active. Specifically, for a recent application where de
AE activity rate of 100,000 emissions per hour was reduced to less than 200 emissions
per hour when the customer added to the vessel inhibitors. The CORPAC™ “expert”
system checks background noise, runs the test for one hour duration, and advices the
operator if localized active corrosion (pitting or stress corrosion cracking) is present or
not. Where it is desired to monitor a larger area or many areas at the same time, multi-
channel AE systems are used to acquire the data and then the CORPAC™ “expert”
system is applied for analysis. Detection of corrosion by acoustic emission is not a new
phenomenon, the first papers being published in the early 80’s. However, years of
experience and continuing development have helped to make the use of the method
practical and in some cases even quantitative. Recognizing and eliminating noise is still
the main challenge due to the small size of the signals in the presence of potential
process noise. Modern instrumentation, pattern recognition and neural networks have
helped to develop the new “Pocket CORPAC™” system with enhanced capabilities and
easy to use by non-expert operators. Our presentation will include 5 – 6 field case
studies where we will show the technology’s effectiveness while pointing out any
pitfalls. Additionally, we will present successful statistics of its use for the past 15 years
or so.
Utilizing AE Monitoring for Damage Mechanisms in FCC Fractionator Tower to
Provide for On-going FFS Confirmation – Steven Garcia and Claudio Allevato, Stress
Engineering
This presentation will be about an FCC Fractionator tower, which was found to contain
several cracks on the ID, about 9 years ago. Most of them were removed by gringing
and weld overlay applied. At the bottom of the tower, several cracks were left due to
different reasons such as access, coatings, time constraints, etc. Management decided
to use AET to “monitor” the bottom two cans of the tower using a series of in-service
pressurizations to 110% of the tower’s previous pressure within last 12 months. This is
according to ASME Sec V, Article 12.This series of AET monitorings revealed mild
progression of previously known flaws, and allowed them to bring the tower to the
present T/A
A Review of Acoustic Emission Testing for Leak Detection in Aboveground Storage
Tanks - Ronnie K. Miller, Mistras Group
Acoustic Emission (AE) is commonly used to assess the condition of aboveground
storage tank (AST) bottoms without removing the tanks from service. This is attractive
to owners and operators as they are not required to empty or decontaminate the tank
in order to perform the AE test. The results of the test are used to prioritize tanks for
internal inspection based on the amount of active corrosion detected. This
presentation will focus on those situations where the AE data from active corrosion
does not warrant internal inspection but the presence, or suspected presence, of a leak
does.
AET Surveillance of a Nozzle Flaw in a Process Column - Glenn A. Aucoin, Stress
Engineering
This presentation will explain the application of AE as a method which provided an
operator the feedback required to safely continue operation of a vessel with a through
wall flaw. AE when used as a surveillance method can provide equipment owners
valuable feedback to make decisions on continuing operation of damaged equipment.
A vessel operator witnessed product leaking through the weep hole of a nozzle repad.
This vessel was operating at 750F in a continuous process and the next shut down
opportunity was not scheduled for another two years. The proximity of the flaw and
the surface temperature of the vessel precluded the application of conventional NDE
methods for characterizing the flaw. The owner required a method to ensure that this
flaw was not detrimental to the integrity of the vessel in its current state, and that the
severity of the flaw did not become significant during daily operations over a 2 year
period. Continuous monitoring of the nozzle using AE and an internet interface allowed
for continuous and immediate feedback when activity alarm conditions were met. The
location algorithm of the AE software established the source locations as well as
screening of external signals. User defined ratios of the AE hit features allowed
characterization of the source signals and allowed for concluding that the majority of
the AE activity was generated from mechanical signals as opposed to crack-like signals.
The intended audience of this presentation includes owners/operators/inspectors of
equipment which could experience cracking as a damage mechanism and who may
desire to continue operation of any equipment in a damaged condition.
Afternoon Session 1:
What You Should Know Before You Replace or Upgrade Your Inspection Information
Management System – Mark Bell, Shell Global Solutions (retired)
The foundation of any quality equipment integrity management system is the
inspection information management tool. To be effective, these tools must be
comprehensive, user-friendly and provide transparency of information. Not only must
these tools provide the functionality to store data, they must also: Accommodate
multiple forms of information analysis, interface with associated management systems,
such a maintenance management systems and operation unit process data systems,
RBI systems, etc. and provide clear reporting to all stakeholders with an interest in
integrity Management. This discussion will outline the necessary and desirable
components of an effective inspection information management system. It will
emphasize the need to keep the functionality of such tools effective and
uncomplicated.
The Importance of Quality Data in a Modern Day Inspection Department – Mark
Vining, Intertek AIM
The presentation will speak to the changes that are often faced by an inspection
department when dealing with internal/external auditors and regulatory bodies. The
document will attempt to explain the transition these departments are experiencing as
a result of traditional inspection methods not always proving capable of providing asset
integrity related data in an accurate, timely and organized manner. In addition, the
presentation will speak to the value of using properly designed, implemented,
populated and managed Inspection Data Management Systems (IDMS) to become
more proactive specific to damage prediction and mitigation. The presentation will
address the speaker’s proposed roles and responsibilities of IDMS caretakers ranging
from data clerks to department managers in the hope that the listeners will remain
engaged no matter what their current levels of involvement. Previous talks and
presentations regarding this subject have demonstrated that the proposed topic has
generated strong opinions and discussions related to how varying organizations
manage said data and their IDMS implementation techniques.
Implementation of a Corporate-Wide Mechanical Integrity Inspection Data Program
at Flint Hills Resources – Scott White, FHR and Vinay Nihalani, Meridium
Flint Hills Resources (FHR) embarked on a project to implement an Enterprise System
for its corporate Mechanical Integrity (MI) Program several years ago. After evaluating
different options, FHR selected an Asset Performance Management (APM) system
based on the following major considerations.
• The new system must support multiple sites and existing MI work process and help ensure statutory compliance for many types of federal, state, and local regulations.
• The new system must support tracking and closure of many different types of data elements for Inspection Tasks and Field Events, Inspection Recommendation, etc.
• The new system must integrate with an: – Existing plant CMMS providing integration of Maintenance and Inspection
Work Processes. – Existing API RBI Calculator software providing a direct connection between
Inspection Planning and Risk Calculation.
• The new enterprise system must eliminate “islands of information” that existed
among the FHR sites. • The new system must provide ease of use for end-users while providing the
necessary complexities for querying, reporting, alerting, and auditing required for extensive data management.
This presentation outlines the strategic approach adopted by FHR for our MI project
which extended well beyond just positioning the project as an IT Implementation.
Throughout the project, FHR has focused on all three elements needed for ensuring
success – Process, People, and Technology.
Process: MI processes and procedures have been standardized and Metrics as well as
other monitoring tools have been put in place to ensure that these processes and
procedures are followed consistently across all FHR sites.
People: In addition to training for our workforce, FHR has developed the tools,
monitoring controls and stewardship programs to promote the right culture needed to
keep the program sustainable.
Technology: Last but not the least, software tools are being implemented at FHR’s
sites to enable the MI Processes and empower users with the right tools, so they can
make the right decisions at the right time.
Corrosion Measurement Data - Getting the Most out of Your CMLs - Dave McFarland,
Shell Oil Company
Dave McFarland will explore rules of thumb to apply for collecting corrosion
measurement data. He will also address how to manage the data especially
measurement “outliers” and “growths.” Managing this data more effectively leads to
better quality data and subsequently technical decisions for the assets you manage.
Afternoon Session 2:
Three Dimensional Laser Scanning of Aboveground Storage Tanks - Idamarie Carden,
Petrochem Inspection Services
The application of Three Dimensional Laser Scanning of Tanks provides
Owner/Operators a great deal more information regarding their Tanks. This
presentation will discuss the information that can be obtained by deploying this
technology. This technology can provide detailed assessment of the shell of the tank
with regard for deformations. The information collected can provide an “as is” detailed
digital representation of any deformations present. The same assessment of the shell
can be applied to the bottom allowing a thorough assessment of Tank Shell and Bottom
Settlement allowing for the worst area of deflection to be identified based on the vast
number of elevations collected from the bottom. With the inspection map created of
the bottom, the entire affected area can be identified for the area and the profile of
the bottom to allow for a more accurate Finite Element Analysis of the area. Tank
Calibration is another area where the technology can be utilized. Utilizing this
technology for Tank Calibrations can ensure that volumes are derived utilizing the full
surface of the Tank Shell and Bottom to include all deformations are included in the
computations.
Advanced On-stream Inspection Topics for Atmospheric Storage Tank Bottoms - Joe
Krynicki, Exxonmobil
This presentation will address various aspects of tank bottom reliability and inspection
including: corrosion concerns, Risk Based Inspection considerations, and, on-stream
inspection technologies and challenges. Much of this presentation will focus on tank
bottom and critical zone corrosion concerns and the status of relevant on-stream
inspection technologies.
Small Tank Inspections per STI SP001 5th Edition- Dana Schmidt, Steel Tank Institute
The standard SP001, first issued in 2001, addresses tanks and containers not covered
by other industry standards for inspection. The 5th Edition of this Standard was issued
in September 2011. The standard includes requirements for tanks and containers from
55 gallons to 265,000 gallons and inspection guidelines for portable containers, single
and double wall tanks, horizontal, vertical and rectangular tanks. The audience will gain
a better understanding of the risk-based inspection criteria of SP001. Included in the
presentation will be a comparison of the 5th Edition of the Standard to previous
editions. Although I spoke on this subject at the last API Inspector Summit, this revised
edition was issued after the Summit and thus contains new information. The
presentation is intended for tank owners, tank inspectors and tank regulators.
Numerous photos help to express the applicability of the standard to many varied tank
installations.
Risk Based Inspection of Storage Tanks- Jesus Esquivel, CUASMEX Services
The presentation will discuss the elements in probability, consequence of failure and
Risk, as well as real applications describing the inspection planning and benefits for
quantitative RBI Storage Tanks. Also, provide a guide to use code requirements,
methods of analysis and best practices. Topic relevant to the industry. There are over
700,000 aboveground storage tanks in the U.S. with capacities ranging from 500 barrels
to over 500,000 barrels. Many of these tanks leaks requiring repair. Risk based
Inspection is the most important methodology to established damage mechanisms,
probability and consequence of failure and control the actual and future risk.
Materials/Corrosion Track:
Morning Session:
Minimizing CUI with Thermal Sprayed Aluminum Coatings - Howard Mitschke, Coatings
Consultant (previously w/Shell Global Solutions).
Although thermal spray aluminum (TSA) technology has been around for decades, its
use began to expand in the last 15 years. One of its primary uses is as a corrosion
protective coating under thermal insulation (CUI). In this presentation, a brief history of
its use and application methods are reviewed. What are the reasons for owners
specifying it more and more? What are the advantages and limitations of TSA? What
are some of the difficulties experienced in the field with applications? Finally, what
does the coating inspector look for to ensure optimum applications?
Maximizing the Service Life of Refractory Linings with the Right QA/QC – Chris Fowler,
ExxonMobil
In November of 2008, The American Petroleum Institute adopted API Standard 936 –
Refractory Installation Quality Control – Inspection and Testing Monolithic Refractory
Linings and Materials. This standard represents an industry consensus of the minimum
requirements for Quality Control and Quality Assurance for the installation of monolithic
refractory products, and provides guidance to establish quality control elements to
achieve defined requirements. The role of the API-936 practitioner in insuring
compliance with this standard is discussed. Future plans for API 936 include:
Continued expansion of program and certification to include multiple languages.
Incorporate content from API 560 and any other new standards which include refractory technology.
Development of an on-line recertification test to keep practitioners current with changing technology.
Defining experience expectations for entry, mid-career and senior refractory inspectors.
The Key to Getting the Maximum Service Life from Your Plant Coatings - Monica
Chauviere, Monicorr, Inc.
The oil and gas industry has been plagued for some 30 years with corrosion damage
caused by Corrosion Under Insulation (CUI). Most corrosion professionals understand
the phenomena. Water ingress into insulation systems is held for long periods against
the warm or hot steel by the relatively thick, water-absorbent insulation, causing
corrosion of unprotected carbon steel, or upon steel that was never coated with a
proper immersion-grade coating. Over the years since Corrosion Under Insulation (CUI)
became an “industry-famous” acronym, there have been many studies, articles and
research efforts directed at the improvement of coatings technology to help combat
that chronic and very expensive issue. There has been substantial progress made with
industrial coatings technology in the past 2 decades. The industry has gleaned much
benefit from field experience and laboratory R&D. There is still, however, one factor
that must be recognized as applicable to the real world. . . .and that is that there is no
such thing as a perfect shop- or field-applied industrial coating. In spite of state of the
art technology, providing excellent performance in the protection of steel in hot, wet
conditions, it must be recognized that there is no such thing as a “silver bullet” which
provides complete protection of all surfaces on all equipment. Coating application
conditions are not perfect and people are not perfect; yet it is people who are employed
to select and install CUI coatings in real world conditions. Thus, there is need to
recognize other factors that impact the risk of CUI. This presentation addresses
parameters and characteristics related to industrial insulation which are influential on
both the risk of CUI and the thermal functionality of the insulation. Both of these
factors have significant bearing on the cost to own and operate a facility.
Reliable Corrosion Rate Measuring Techniques – Sam Lordo, Nalco Energy Services
Division
Corrosion monitoring takes many forms in Industry, varying from absolute
measurements to inferred measurements. In addition new methods are being
developed to try and move closer to real time corrosion monitoring. This presentation
will look at some of the more commonly used methods used in Refinery settings by
chemical suppliers. Also discussed will be some of the newer methods that have been
developed and that begin to move corrosion monitoring to near real time. Data
collected by chemical suppliers has traditionally been used and evaluated by the
Process/Operations groups. However, this corrosion data accumulated by chemical
suppliers can be a vital part to quantifying and monitoring equipment condition
Afternoon Session:
Improving Your Failure Analysis Process to Prevent Future Failures - Steve Burkle,
Lloyd’s Registry
Failure analysis is an essential tool for mitigating repetitive mechanical, metallurgical,
and corrosion-related failures in process equipment in all segments of the Oil & Gas and
Petrochemical Industry. When the results of a failure analysis are combined with
inspection methods such as nondestructive examination, damage already present in
equipment can be proactively pinpointed and detected before breech of containment
occurs. Failures in welds, wrought products, and castings can be eliminated by
understanding the cause of failure and by applying effective methods of repair or by
changing the material composition. A failure analysis can only be effective if adequate
and accurate failure data is available, and if the physical sample of the failure is
removed, labeled, sectioned and processed correctly. This paper describes the failure
analysis process, including the specific types of design, process, and inspection data
needed to assess a failure, various methods used for failure analysis, and proper
specimen selection and sampling. Actual case studies will be presented.
Leaks in Duplex SS Tubes from Aggressive MIC – Art Jensen, Delaware City Refining
(PBF Energy)
The Delaware City Refinery has experienced severe Microbiologically Induced Corrosion
(MIC) in brackish river water cooling exchangers. The problem has resulted in through-
wall tube leaks, severe crevice corrosion to the tube sheets (gasket surfaces and tube
roll areas), and corrosion in the floating head (gasket surface through-wall leaks). The
affected metallurgy has been Duplex 2205 and 2507, which the refinery has been using
for this service since approximately 2006. This presentation will discuss what has been
learned through the investigation which has taken many paths. Factors to be discussed
include: MIC-resistant metallurgy (including the importance of PREN calculations for
varying alloy content in Duplex); river-water chemistry and composition changes over
years and seasons; water biocide treatment options and limitations; inspection methods
being used to detect pitting on the ID of the tubes; and repair methods that have been
tried to mitigate the corrosion and extend bundle life.
NASA Insulation Technology for Improving CUI Resistance – Monica Chauviere,
Monicorr, Inc. (previously ExxonMobil)
The oil and gas industry has been plagued for some 30 years with corrosion damage
caused by Corrosion Under Insulation (CUI). Most corrosion professionals understand
the phenomena. Water ingress into insulation systems is held for long periods against
the warm or hot steel by the relatively thick, water-absorbent insulation, causing
corrosion of unprotected carbon steel, or upon steel that was never coated with a
proper immersion-grade coating. Over the years since Corrosion Under Insulation (CUI)
became an “industry-famous” acronym, there have been many studies, articles and
research efforts directed at the improvement of coatings technology to help combat
that chronic and very expensive issue. There has been substantial progress made with
industrial coatings technology in the past 2 decades. The industry has gleaned much
benefit from field experience and laboratory R&D. There is still, however, one factor
that must be recognized as applicable to the real world. . . .and that is that there is no
such thing as a perfect shop- or field-applied industrial coating. In spite of state of the
art technology, providing excellent performance in the protection of steel in hot, wet
conditions, it must be recognized that there is no such thing as a “silver bullet” which
provides complete protection of all surfaces on all equipment. Coating application
conditions are not perfect and people are not perfect; yet it is people who are employed
to select and install CUI coatings in real world conditions. Thus, there is need to
recognize other factors that impact the risk of CUI. This presentation addresses
parameters and characteristics related to industrial insulation which are influential on
both the risk of CUI and the thermal functionality of the insulation. Both of these
factors have significant bearing on the cost to own and operate a facility.
Inspection of Injection Point Internal Hardware: quills, spargers, spray nozzles, etc. –
Kimberly Comeaux, Coffyville Resources (CVR) and Sam Lordo, Nalco
Injection systems are designed to modify a process stream, or to control
chemical/physical interactions of specific process streams. Typically we rely on
corrosion related injections for quenching, scrubbing, neutralizing/corrosion inhibition.
Since the flow rate of the injected fluid is just a small fraction of the mixed stream, we
typically overlook the injection hardware itself, and focus on the adjacent
piping. However, the designed mixing system must be functioning at its optimum in
order for it to do its job and provide the intended corrosion related duties. Therefore,
inspection of the injection hardware is essential to the proper performance. Common
configurations include simple tees, quills, spray nozzles and spargers to disperse the
injecting stream.
This presentation will focus on the inspection requirements of the injection hardware
including corrosion, erosion and fouling effects.
Industry Panel: HTHA (High Temperature Hydrogen Attack) – Moderator: Tim
Munsterman, Lloyd’s Registry. Panelist: Gerritt Buchheim, Consultant, Mike
Urzendowski, Valero, Brian Jack, Phillips66, David Wang, Shell, Jorge Hall, Shell Global
Solutions.