corrosion control at vmt...jan 17, 2013 · ecda—external corrosion direct assessment •external...
TRANSCRIPT
Corrosion Control at VMT
Dr. Rust, Inc. R. Heidersbach
K. Prakash
R. Guise
Corrosion Control at VMT
Dr. Rust, Inc.
R. Heidersbach
January 17, 2013
Emphasis of Project
• Objective not to second
guess
• Objective is an
assessment of what was
seen and obvious
reliability issues that
need to be addressed
• Goal for both Alyeska
and RCAC
– Prevent corrosion-related
environmental damage
Objectives
• Evaluate corrosion control at Valdez Marine Terminal
– Only for systems that can cause oil pollution
• Emphasis on procedures
• Review condition of
– Corrosion control efforts
– Tanks, piping, berths and related equipment
• Recommend changes, if any, that should be considered
Dr. Rust Inc
• Bob Heidersbach
– Direct contractor to PWSRCAC
– Pipes and corrosion inhibitors
• Kash Prakash
– Tanks
– Coatings
– Berth facilities
• Bob Guise
– Cathodic protection
9/20/2012 Board Meeting PWSRCAC
Thanks
Alyeska PSC
• Barry Roberts
• Steve Lacatena
• Clay Forsyth
• Doug Fleming
• Tawna Beer-Burns, Coffman
• Cecilia Sanchez, Baker Hughes
PWSRCAC
• Tom Kuckertz
• Linda Swiss
• Anna Carey
• Donna Schantz
• Mark Swanson
Priorities--crude oil marine
terminals Corrosive Environments
• Oil
– Largest volume of potential pollutants largest pollution risk
• Fire fighting equipment
– Safety
– Perhaps equal in operational priority, but less likely to produce pollution
• Vapor recovery
• Oily water
– Most corrosive liquid environment
Equipment
• Piping – Most likely to leak
– Pitting corrosion most likely corrosion-related leak initiator
• Berthing/dock facilities – At waters edge
• Pipelines – Buried
– Hard to inspect
– ECDA coming standard/requirement
• Tanks – Large volume of oil
– Easy to inspect
– Expensive internal inspections
Scheduling and Timeline
• Pre-visit Activities – Prior to July 31, 2012
– Requests for and analysis of documentation
• Anchorage Activities – July 31-August 3, 2012
– Documents review -- Alyeska’s Anchorage office
• Valdez Field Work – August 6 – 9, 2012
– Monday – Admin, safety, security, document requests, facilities access requests
– Tuesday – Look at Berth 4, tanks, CP, piping, fire foam systems
– Wednesday – Look at Berth 5 and other VMT locations,
– Thursday – Exit briefing
• Draft report – September 2012
• Final Report – Revise and review – October thru December 2012
• Final report – Proposed for acceptance -- January 2013
Changes in Oilfield Corrosion
Problems • As oilfields age, corrosivity increases
• Inspection and corrosion control efforts
need to be increased in ageing
fields/terminals
• Decreased production decreased
funding for maintenance and inspection at
the same time that needs for these efforts
increase
OK/Almost OK Areas
Internal corrosion of pipes
• Control is by corrosion inhibitor
– Injected batches on 2-week intervals
• Effectiveness of corrosion inhibitors and
biocides is monitored by coupons
– Inserted/removed twice per year
– Standard weight loss and pit depth report
• State of the art in the 1970s
• Still most common method of monitoring corrosivity
and effectiveness of corrosion inhibitors
Structural Integrity
• Covered by Alyeska MP-166.3.21, VMT
Facility Underwater Inspections
• Covered by Alyeska MP-166.3.21, VMT
Facility Underwater Inspections
Structural Integrity
AFFF—Fluoroprotein Foam
• Concern before this week’s efforts
• No longer a corrosion concern
• “Spiders” in tanks have experienced some
corrosion
– External in “deadleg” locations
– Now part of Alyeska T-500 tank inspection
protocol (2012 paragraph additions)
• Concern before August
efforts
• No longer a corrosion
concern
• “Spiders” in tanks have
experienced some
corrosion
– External in “deadleg”
locations
– Now part of Alyeska
T-500 tank inspection
protocol (2012
paragraph additions)
Fire-suppression
Foam
Tanks
• Tank inspection is OK
– Possible exceptions are
roof and vapor recovery
systems which were not
considered in this project’s
efforts
– Need to review summer
2012 inspection results
• Corroded foam spiders
now included in Alyeska
procedure
API 653 Scope • Includes foam fire suppression systems
• Alyeska T-500
– New section 3.4 on Fire Foam System added
early 2012
Cathodic Protection—Buried Piping
• Good
– Follow strictest industrial/regulatory practice
• NACE SP0169
• Coming
– ECDA
• NACE SP0502-2008, Pipeline External Corrosion
Direct Assessment Methodology
• Coming from US DOT
Cathodic protection
Industrial waste water line
• Ductile cast iron
• Bell and spigot connections
• No jumpers
– Questionable continuity • Jumpers
• Lead or jute packing poor or no electrical continuity at joints
– stray current
– Questionable cathodic protection beyond the first joint
ECDA—External corrosion direct
assessment
• External corrosion direct assessment
• NACE SP0502—Pipeline External Corrosion Direct Assessment Methodology
• Will be required by US DOT at some time in the future
• Requires digs and inspection in selected locations
• Controversial, – Evolving methodology
– RBI-related
Cathodic Protection—Berth
Platform Legs
• OK
Cathodic Protection
Berth Platform Legs--OK
Cathodic Protection--Tanks
• Tank bottoms
– Pay attention to readings
• Rectifiers turned off almost instant
depolarization based on measurements in
August 2012
• Stray current from nearby systems?
– Soil side only?
Corrosion Coupons in Piping • Used for monitoring changes in
the environment
• Cannot – Identify/measure worst corrosion
in the system • Only the corrosion of the
coupon—not the system
– Deadlegs
– Crevices
– MIC
– Identify when corrosion occurred • Comparison with previous
exposure data indication of effectiveness
• Misses upsets, etc.
• Needs comparisons with previous exposures to ID trends in corrosion rates
• Too much data to usefully interpret
Problem Areas
• Corrosion under insulation
• Inspectability
• Communications
– Contractor/Alyeska personnel
– Problemsresolution of problems
Corrosion Under Insulation (CUI)
—Berth 5 Crude Oil Line
• Good news—
corrosion
found/repaired with
no leaks into the
environment
• Concern
Previous Observations of Corrosion
on Unpainted Welded Joints
Corrosion near unpainted
welds on insulated piping. Photograph by T. Kuckertz, PWSRCAC staff
member, May 29, 2008 at the
VMT Ballast Water Treatment Facility
CUI Identified during Fieldwork in
Anchorage by Alyeska
Corrosion on Berth 4 riser piping caused 70% wall loss in places
Slide from Tom Kuckertz
presentation September 2012
Repairs in accordance with standard industrial practice
Summer 2012 CUI Corrosion
Inspections
Alyeska inspection
• 3rd year of program to
inspect selected
locations
• 2012 results
– Crude oil piping
– Maximum pitting 70%+
wall loss
– Sleeve repairs
Alyeska survey
• Project Z683 – VMT
Crude Header
External Condition
Survey (2012)
Summer 2012 CUI Corrosion
Inspections
Good news
• VMT found the
corrosion
– Before leaks
Concerns
• Over water location
Questions
• When did the
corrosion occur?
• Why not discovered
sooner?
– 3rd year of inspection
program
– Previous years did not
emphasize over-water
locations
Snow-removal damage 2012
Note sharp, angular features on openings
Openings prior to 2012 Piping Leading to Berth 5
Numerous patches at VMT This is good news—inspection/maintenance has occurred
Additional CUI-related
Observations
Corrosion coupon box— full of water on August 7 and again on August 8
Corrosion coupon box— full of water on August 7 and again on August 8
Wet pipe above coupon holder
Wet pipe above coupon holder
Water droplets
Unavoidable
“void” space
Note UT grid pattern
• Did anyone report the
water on the pipe?
• Contractors see these
locations several
times each year
• No requirement to
report moisture to
Alyeska decision
makers
• Did anyone report the
water on the pipe?
• Contractors see these
locations several
times each year
• No requirement to
report moisture to
Alyeska decision
makers
Question/problem?
• The previous slides show pipes wetted in
locations where a contractor pulling corrosion
coupons gains access to the pipe twice a year.
• Does Alyeska & their contractor have a method
of communicating the water accumulation at
these “dry” locations?
• Possibly install drain holes on bottom of jackets
– May lead to melt water intrusion due to high snow
loads in some locations at VMT
Corrosion Under Insulation
• NACE SP0198
• Not industry-recognized problem in 1970’s
Problem locations for insulated
above-ground pipelines
Slide from 2006 RCAC presentation
Illustrates problems associated with localized
corrosion inspections
Best practice—100% inspection
Key Recommendations • Install smart pigging, or other equivalent internal
inspection options ASAP (as soon as possible)
• Until this smart-pigging capability is installed, the
VMT should
– Emphasize inspection of above-water piping systems
– Repair damaged external jacketing (weather proofing)
• Improve communications and instructions to
corrosion contractors
• Improve reporting and information feedback
procedures
• Evaluate summer 2012 reports on Tanks 13 & 14
Smart Pigging
• Capital improvement – Time to schedule/fund/install
• Not possible in 1970s
• Allows simultaneous inspection for internal and external corrosion
• Will eventually allow • More frequent inspections
• Simultaneous internal and external corrosion inspections
• Complete inspections of entire VMT large-diameter piping lines
• Eliminate the need for – Digging
– Estimates as to where most corrosion has occurred.
Recommended Emphasis on
Over-Water Locations
• Smart pigging installations
• Inspections in absence of smart-pig
capability
Concluding remarks
• DRI was on-site for only 4 days
• Alyeska and VMT personnel are there
continuously
• Contractors do corrosion-related work on a
monthly and/or semi-annual basis
• Communications between contractors and
Alyeska decision makers need
improvement