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