POWER April 2014 - 22

3D Visualization's Value at a Refinery
The National Cooperative Refinery Association (NCRA) in McPherson,
Kan., streamlined its risk-based inspection programs for its
85,000-barrel/day processing facility in 2008. The deployment began
with a pilot project involving 19 pumps, 14 heat exchangers,
a fractionator tower, and associated piping and structural components
at a crude processing unit. Today more than 50% of the facility
has been converted to 3D virtualized models, with conversion
of all major processing units expected by about 2015.
In the recent past, process and instrument diagrams (P&IDs)
were developed as the most accurate representation of the facility's
process equipment. Inspection engineers had to develop indices
to match legacy documents to the newly developed P&ID line
numbers. Legacy drawings for equipment were often inadequate for
current inspection practices, so a draftsperson would then sketch
the line in the as-built condition, refine it in the AutoCad System,
and then produce an isometric for the inspectors.
Today, the 3D models are used to generate drawings of piping
" circuits " for inspection teams. The team receives a booklet with
essentially everything they need to do the job, including the location,
piping, test routines, thickness monitoring locations, corrosion-monitoring
locations, and testing procedures.
isometrics (in some cases hand-drawn), or scanned versions of
old diagrams.
■ Lack of proper management of change procedures.
■ Reliance on recall of plant personnel in determining what has
changed since the last inspections.
■ Virtually no " system " context for higher understanding of corrosion
phenomena.
■ Excel spreadsheets of inspection data that are not linked to
drawings.
■ Time-, or location-based inspection intervals, rather than inspections
based on actual condition.
■ Silos of information and knowledge among different stakeholders
involved in the inspection routines.
2. Color coding. Piping can be color-coded to reflect areas of
high, medium, or low flow accelerated corrosion susceptibility, allowing
personnel to easily understand the system as a whole while
process data can be included as text. In this example, reflected-light
temperature colors are mostly subdued and a red glow is emitted by
areas of potentially high damage rates. Courtesy: INOVx
Thickness data are collected in a data logger, downloaded into
the plant condition-monitoring system, and automatically associated
with the 3D representation of the circuit. NCRA is now integrating
the 3D visualization system with the computerized maintenance
management system, the distributed control system, and the turnaround
(outage) planning processes and procedures. In the near
future, inspectors will be able to view the circuits on an iPad or
equivalent mobile device which, when integrated with the data loggers,
achieves full electronic transfer of information.
NCRA's program resulted in the following benefits, with obvious
cost paybacks:
■ Reduced the number of inspection points by 50% and inspection
hours by 20% to 30% while increasing reliability and safety.
■ Helped the plant comply with myriad American Petroleum Institute
and Occupational Safety and Health Administration
standards.
■ Improved accuracy and consistency in documenting placement
of thickness measurement and condition monitoring locations.
■ Broke down information silos around the plant.
■ Independently verified payback of 13.4 months.
Unfortunately, the situation promises to get worse. The threat
of FAC increases with age. Most U.S. nuclear plants and large,
flagship coal-fired plants have been operating for several decades.
Power uprates, common at most nuclear units, also raise
the threat of FAC incidences. As the frequency of inspection grows
with aging (but more productive) plants, power plant owners and
operators must consider new ways to hold down costs. Petrochemical
facilities implementing this technology have enjoyed
paybacks of four months to just over a year.
Applying 3D visualization at nuclear plants can reduce the
amount of time workers are exposed to radiation, an important
key performance indicator, and helps meet several criteria set forth
by the Electric Power Research Institute (EPRI) in its 2008 FAC
Program Recommendations Document:
■ Makes it easier to train back-up personnel and maintain continuity
of trained staff.
■ Formalizes the sharing of data and information on FAC and a
consistent picture of reality.
■ Ensures a high level of quality assurance in documenting procedures
and preparing tasks.
EPRI and others have documented that FAC has occurred in
about 60% of all conventional fossil plants. Increased and deeper
load cycling, common at fossil thermal and combined cycle
plants, also aggravate FAC. In gas-fired combined cycle and cogeneration
plants, FAC is reportedly the leading cause of damage
and failure in heat recovery steam generators (see, for example,
" Ten Years of Experience with FAC in HRSGs " in the September
2010 issue, online at powermag.com).
According to a paper presented at the Fossil FAC International
Conference 2010, one Midwestern owner/operator noted that a
formal FAC inspection program started in 2006 has been very successful
in identifying thinned components and for justifying their
removal from service prior to failure. However, some of their lessons
learned are opportunities to improve, using 3D visualization.
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POWER April 2014

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