Proposed NACE Standard Recommended Practice

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Proposed NACE Standard Recommended Practice

• Internal Corrosion Direct Assessment Methodology
  for Pipelines Carrying Normally Dry Natural Gas
  (DG-ICDA)
• Brian Powell
• Project Engineer, Columbia Gas of Ohio
• Ohio Gas Association Technical Seminar
• March 31, 2005

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Why care about internal corrosion?

• Public Safety
• Liability
• Protecting Assets
• Increased Scrutiny
• Compliance

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Pipeline Integrity Management Compliance

• Operators must evaluate transmission lines in
  High Consequence Areas for the threat of internal
  corrosion.
• If considered a threat, assessments must be
  performed.

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Pipeline Integrity Management Compliance

• Lack of documented internal corrosion may not be
  sufficient to exclude IC as a threat.
• Record-keeping practices must be such that, if
  upsets have occurred, they would likely have been
  documented. (FAQ 105)

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Pipeline Integrity Management Compliance

• Acceptable assessment methods, per Subpart O
• Inline Inspection
• Pressure Testing
• Direct Assessment
• External Corrosion Direct Assessment
• Internal Corrosion Direct Assessment
• Stress Corrosion Cracking Direct Assessment

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Pipeline Integrity Management Compliance

• Subpart O contains requirements for ICDA. It
  also requires operators to follow
• ASME B31.8S - Managing System Integrity of Gas
  Pipelines
• Section 6.4
• Appendix B2
• GRI 02-0057 ICDA of Gas Transmission Pipelines
  Methodology

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NACE ICDA Task Groups

• Normally dry gas
• Task Group 293
• Unresolved negative
• Reballot technical changes
• Wet gas
• Task Group 305
• Liquid petroleum
• Task Group 315

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NACE Standards - Wording

• Shall and must mandatory requirements
• Should recommended but not mandatory
• May optional
• Shall and must statements are considered
  mandatory by OPS. Should statements are
  expected to be followed. If not followed,
  justification must be documented.

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Dry Gas ICDA Guiding Principle

• For normally dry gas, corrosion most likely where
  water first accumulates
• If no corrosion at most likely water accumulation
  points, other locations (less likely to have
  water) are unlikely to have corroded.

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Dry Gas ICDA Method

• Predict locations of water accumulation by
  multiphase flow modeling
• Evaluate those limited locations for corrosion
• Excavate and inspect (e.g., ultrasonic)
• Conventional monitoring/prediction methods
• Corrosion found? No Downstream pipe corrosion
  unlikely Yes Problem successfully identified

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Scope of ICDA

• Characteristics of typical natural gas
  transmission pipelines
• Stratified flow
• Constant Temperature
• Normally above dew point
• Short upsets of water that vaporize
• Corrosion typically not expected

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NACE DG-ICDA

• Section 1 General
• Section 2 Definitions
• Section 3 Pre-Assessment
• Section 4 Indirect Inspection
• Section 5 Detailed Examinations
• Section 6 Post Assessment
• Section 7 DG-ICDA Records

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General

• The ICDA methodology assesses the likelihood of
  internal corrosion
• Applies to normally dry natural gas piping
  systems but may suffer from infrequent,
  short-term upsets of liquid water
• ICDA has limitations and not all pipelines can be
  successfully assessed with ICDA

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Definitions

• Inclination An angle resulting from a change in
  elevation between two points on a pipeline, in
  degrees.
• Critical Inclination Angle Angle determined by
  DG-ICDA flow modeling the lowest angle at which
  liquid carryover is not expected to occur under
  stratified flow conditions.

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Definitions

• DG-ICDA Region A continuous length of pipe
  (including weld joints) uninterrupted by any
  significant change in water or flow
  characteristics that includes similar physical
  characteristics or operating history.
• Dry Gas A gas above its dew point and without
  condensed liquids.

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4-Step Process

• Pre-assessment
• Is ICDA appropriate?
• Select local examination points
• Liquid accumulation (Flow modeling results)
• Upstream most susceptible
• Perform detailed examination
• Usually local inspection
• Post-assessment
• Process review and reassessment interval

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Step 1 Pre-assessment

• Objectives
• Determine whether DG-ICDA is feasible for the
  pipeline being evaluated
• Identify DG-ICDA regions

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Step 1 Pre-assessment

• Step includes
• Data Collection
• Assessment of ICDA feasibility
• Identification of ICDA regions

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Step 1. Pre-assessment Data Collection

• Operating history
• Defined length
• Elevation
• Features with inclination
• Diameter
• Pressure
• Flow rates (or maximum design)
• Temperature
• Water dew point

• Type and locations of inputs/outputs
• Use of any corrosion inhibitors
• Upsets
• Type of Dehydration
• Hydrostatic test frequency
• Repair/ Maintenance Data
• Leaks and Failures

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Step 1. Pre-assessment Feasibility
Assessment

• Normally no liquids
• Converted from different service
• No internal corrosion coating
• No top of the pipeline corrosion
• Frequent maintenance pigging
• Uninhibited
• Constant temperature over the pipe length
• Solids and Sludge
• Uniform material properties

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Step 1 Pre-assessment Region Identification

• Identification of ICDA regions
• Operators should define criteria for identifying
  ICDA regions
• ICDA region portion of a pipeline with a
  defined length
• Temperature and pressure must be considered
• Similar flow conditions and physical
  characteristics
• ICDA regions shall be identified for each flow
  direction
• Historical flow conditions must be considered

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Step 2 Indirect Inspection

• Objective is to use flow modeling results to
  predict the locations most likely to have
  experienced internal corrosion within each ICDA
  region

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Step 2. Indirect Inspection

• IC most likely where water 1st accumulates
• Given presence of liquid water, where will it
  accumulate
• Upstream locations most likely

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Step 2 Indirect Inspection

• The DG-ICDA indirect inspection step shall
  include each of the following activities, for
  each DG-ICDA region
• Performing multiphase flow calculations using
  collected data to determine the critical
  inclination angle of liquid holdup
• Producing a pipeline inclination profile and
•  
• Identifying sites where internal corrosion may be
  present by integrating the flow calculation
  results with the pipeline inclination profile.

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Step 2. Indirect Inspection Flow Modeling
Principles

• The operator shall predict critical parameters
  for water accumulation using flow modeling
  calculations for each identified DG-ICDA region.

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Step 2. Indirect Inspection Flow Modeling
Principles

• Premise
• Liquid phase flows down bottom of pipe
• Water droplets evaporate in dry gas phase
• Two forces
• Gravity drives liquid downhill
• Gas pushes water stream forward by shear

gas
liquid
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Step 2. Indirect Inspection Flow Modeling
Principles
Shear and Gravity drive liquid downstream No
holdup at any gas velocity
gas
Shear drives liquid downstream Gravity
neutral Holdup only with no gas flow
stagnant gas
liquid
Shear drives liquid downstream Gravity drives
liquid upstream Holdup depends on slope and gas
velocity
gas
liquid
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Step 2. Indirect Inspection Flow Modeling
Principles
Utilizing a fluid flow model results, the
critical angle for water accumulation is
determined as a function of gas velocity.
The actual angle of inclination of pipe with
respect to gas flow direction is determined
through digital elevation maps and pipe burial
depths
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Step 2. Indirect Inspection Flow Modeling
Principles

• Equation for determining critical inclination
  angle
• Where
• ?l liquid density
• ?g gas density (determined by total pressure
  and temperature)
• g acceleration due to gravity
• did internal diameter
• Vg superficial gas velocity and

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Step 2. Indirect Inspection Elevation Mapping

• The operator shall calculate the inclination
  profile, or change in elevation over the defined
  length.
• Method must have sufficient accuracy to resolve
  angles.

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Step 2. Indirect Inspection Other Facility
Components

• Consideration given to fittings or other low
  points where electrolyte could collect
• Valves
• Sags
• Dead-legs
• Drips
• Traps

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Step 3. Detailed Examinations

• The objectives of the DG-ICDA detailed
  examination are
• 1) to determine if internal corrosion exists at
  locations selected in the previous step, and
• 2) to use the findings to assess the overall
  condition of the DG-ICDA region.

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Step 3. Detailed Examinations

• Perform sequence of excavations to characterize
  damage
• Nondestructive inspection techniques used to
  assess internal wall loss
• Depending on results of examinations
• No corrosion - IC integrity verified
• Isolated corrosion Repair/mitigate
• Much corrosion Threat identified but not
  characterized by ICDA

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Step 3. Detailed Examinations

• Minimum of 3 digs for entire process
• Inspect 1st critical angle
• If no corrosion, inspect 2nd critical
• Presence of corrosion restarts dig sequence
• One Validation dig
• Subregions
• Upstream of 1st critical
• Between corroded locations
• Minimum of 2 inspections given presence of angle

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Step 4 Post Assessment

• Determine ICDA effectiveness
• Effectiveness of the DG-ICDA process is
  determined by the correlation between detected
  corrosion and the DG-ICDA predicted locations.
• Are results consistent with method?

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Step 4 Post Assessment

• Reassessment interval
• Treat remaining scheduled indications as if they
  equal the worst
• Or use statistically based analysis of excavated
  features
• Consider root cause
• e.g., Pitting, uniform/general, MIC, stray
  current
• Corrosion growth rate
• Linear, literature, coupon, sampling/testing

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ICDA Records

• DG-ICDA records must documentin a clear,
  concise, and workable mannerdata that are
  pertinent to pre-assessment, indirect inspection,
  detailed examination, and post assessment.
• All decisions and supporting assessments must be
  documented.

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ICDA Records

• Sample Documentation

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NACE ICDA vs. Subpart O

• Different formula used in GRI 02-0057
• Minimum dig number greater using NACE ICDA
• Location of digs different
• Subpart O considers HCAs
• Subpart O requires provisions that more
  restrictive criteria be used when performing ICDA
  for the first time.

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Integrity Management Principles Applicable to ICDA

• Use qualified employees to conduct the assessment
  and make decisions
• Continuous process improvements
• Develop procedures
• When problems found, consider other similar
  segments
• Must address other threats or defects that are
  discovered during the course of excavations

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Proposed NACE Standard Recommended Practice

• Internal Corrosion Direct Assessment Methodology
  for Pipelines Carrying Normally Dry Natural Gas
  (DG-ICDA)
• Brian Powell
• Project Engineer, Columbia Gas of Ohio
• Ohio Gas Association Technical Seminar
• March 31, 2005