B31.G Modified B31.G and RSTRENG Background

The initial procedure for evaluating remaining strength was developed after pressuring actual corroded pipe to failure. Several hundred, full-size, full-scale tests using actual field pipe specimens of all types of defects were completed. Basic metallurgical principles presumed at the start of the tests were that resistance to fracture is related to the size of the defect and metal property toughness. The larger the corroded area the lower the failure pressure. The tougher the steel the larger the defect that can be tolerated.

See Also:

• The Development of the Modified B31G Criterion, RSTRENG
  • B31G – Research Objective
  • B31G Limitations
  • B31.G & Modified (Max Depth & Length)
  • Factors for B31.G Evaluations
  • Multiple Pitting Clusters
  • Original B31G Criterion
  • Basis of B31G Criterion
  • RSTRENG Method

Barlow’s Formula

For U.S. gas and hazardous liquid pipelines, the formula for predicting the pressure that may cause an area of the pipe wall to yield is known as Barlow’s formula:

P = 2t(SMYS)/D

MAOP (Maximum Allowable Operating Pressure)

For safety reasons a maximum allowable operating pressure (MAOP) is set lower than the calculated yield pressure by a percent referred to as the Design Factor (F) known as:

• 72% (Basis for Corrosion Calculations with Hazardous Liquid Lines)

As allowable operating pressures are based on nominal wall thicknesses for full lengths of a pipeline segment a prime question asked is: What pressure can be calculated and recognized as safe for random areas of pipe wall found with reduced thickness caused by corrosion?

• A viable calculation providing the lowest estimated pressure that will cause the area to fail/burst
• A decision of what maximum pressure lower than the fail pressure would be safe for operations

See also:

• Determining Yield Pressure
• Setting Operating Pressure

B31.G Criterion & Modified B31.G

Application of B31.G limited to:

• Corrosion on weldable pipeline steels
• Corrosion with smooth contours (Blunt Defects)
• Corrosion in isolated areas

Excluded are:

• Corrosion in welds or grooves
• Mechanical damage (Stresses)

Objective to evaluate structural integrity:

• Internal Pressure (Barlow’s Formula)
• Not secondary stresses

Basic Equation for Hoop Failure Stress

S_f = S (1-A/A₀)/(1- (A/A₀)M^-1)

• S = Flow stress; the level of stress beyond yield before the pipe metal will fail
• A = Area of metal loss in a projected longitudinal profile of the defect
• A0 = Total affected area of the pipe wall in the profiled longitudinal plane
• M = Folias Factor, a factor, which accounts for stress amplification at the ends of a flaw resulting from radial deflections along the flaw.

See Also:

• Folias Factor
• Modifying the Flow Stress
• Understanding Basic Equation for Hoop Failure Stress
• Values of the Equation Factors were established by Committee Consensus

References in DOT 192.483c, 192.933, 195.585 & 195.587
192.485c Remedial Measures: Transmission Lines

Under paragraphs (a) and (b) of this section, the strength of pipe based on actual remaining wall thickness may be determined by the procedure in ASME/ANSI B31G or the procedure in AGA Pipeline Research Committee Project PR 3–805 (with RSTRENG disk). Both procedures apply to corroded regions that do not penetrate the pipe wall, subject to the limitations prescribed in the procedures.

192.933 What Actions Must Be Taken to Address Integrity Issues?

1) Temporary pressure reduction. If an operator is unable to respond within the time limits for certain conditions specified in this section, the operator must temporarily reduce the operating pressure of the pipeline or take other action that ensures the safety of the covered segment. An operator must determine any temporary reduction in operating pressure required by this section using ASME/ANSI B31G (incorporated by reference, see §192.7) or AGA Pipeline Research Committee Project PR–3–805 (“RSTRENG,” incorporated by reference, see §192.7) or reduce the operating pressure to a level not exceeding 80 percent of the level at the time the condition was discovered.

(i) A calculation of the remaining strength of the pipe shows a predicted failure pressure less than or equal to 1.1 times the maximum allowable operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include ASME/ANSI B31G; RSTRENG; or an alternative equivalent method of remaining strength calculation. These documents are incorporated by reference and available at the addresses listed in appendix A to part 192.

195.587 – What Methods are Available to Determine the Strength of Corroded Pipe?

Under §195.585, you may use the procedure in ASME B31G, “Manual for Determining the Remaining Strength of Corroded Pipelines,” or the procedure developed by AGA/Battelle, “A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe (with RSTRENG disk),” to determine the strength of corroded pipe based on actual remaining wall thickness. These procedures apply to corroded regions that do not penetrate the pipe wall, subject to the limitations set out in the respective procedures.

See Also:

• The Making of ANSI/ASME B31G
• Evolution of Standards & Regulations

Finding and Measuring the Corrosion

The technician must identify the reference typically the U/S girth weld and verify boxed or clustered features as outlined by the ILI vendor. See figure below.

ILI Boxing or Clustering

U/S Girth Weld

ILI Boxing or Clustering

Manual Gridding and Clustering

Manual pit gauge measurements require that corrosion pitting be clustered based on the operator’s interaction rules and laid out in a grid pattern (typically 1 inch) as shown in the figure below. In addition, once the depth readings are measured and recorded in each grid, then the technician must determine the river bottom of the deepest corrosion features. This task is tedious, methodically, and is error-prone in every step based on the number of readings. Depending on the size of pipe, length, width, and depths of corrosion, it can take over a full 10-hour day.

RSTRENG ECDA_MGC Image.png

River Bottom Profile

Below is an example of a river bottom profile of how corrosion might occur and how the parameters of metal loss are configured and measured for analysis: L is the measured axial length of corrosion along the longitudinal axis of the pipe.

River Bottom Profile

Assessing Corrosion

Level 1

Original B31G — Uses a two-term Folias factor, Flow Stress = 1.1 SMYS plus the parabolic metal loss representation of (2/3)Ld. – Most Conservative

Modified B31G — Uses the three-term Folias factor, Flow Stress = SMYS + 10,000, and the metal loss as a rectangular area = to .85Ld. – Less Conservative

Level 2 – Effective Area Method

RSTRENG — Uses the three-term Folias factor, Flow Stress = SMYS + 10,000, and multiple measurements of the corrosion for identifying the Effective Area of metal loss. – Most Accurate

Interaction Rules

Corrosion occurs where multiple metal loss areas are closely spaced axially and circumferentially. Where they are spaced closely to impact the strength of corroded pipe, the metal loss will interact resulting in lowering the pressure.

See Also:

• Corrosion Interaction Distances
• Definition of Interaction Rules
• Effects of Large Axial Stresses on Corroded Pipes
• Flaw Spacing
• Helical Patterns > 45 degrees
• Interaction of Adjacent Corroded Regions
• Interactions – Compound Defects
• Interactions – Patches of Metal Loss
• Interactions – Pits
• Interactions Rules (3t and 6t)
• Interactions – Spiral Oriented Machined Groves
• Interactions – Type I Defects
• Interactions – Type II & III
• Interactions – Long, Narrow Defects
• Limitations to All Corrosion Analysis
• Reasons For Evaluating Only Corrosion Defects

ASME B31.8

According to B31.8, flaws that interact spaced longitudinal and circumferentially within a distance of 3 times the wall thickness must be evaluated as a single flaw. If they are outside this minimum dimension they can be evaluated as separate flaws.

On the next page is how separate flaws are measure to determine if they are spaced within the minimum distances of 3 times the wall thickness

Interaction Separation

Limitations

“These procedures should not be used to evaluate the remaining strength of corroded girth or longitudinal welds or related heat-affected zones, defects caused by mechanical damage, such as gouges and grooves, and defects introduced during pipe or plate manufacture, such as seams, laps, rolled ends, scabs, or slivers.” Other limitations include pipe vibration, fittings, wrinkle/ripple bends, etc.

• Crack-like defects
• Combined corrosion and crack-like defects.Combined corrosion and mechanical damage
• Metal loss defects due to mechanical damage (e.g. gouges)
• Metal loss in indentations and buckles, or metal loss that is coincident with other damage
• Metal loss in fittings
• Pipelines that operate at temperatures outside their original design envelope or operating at temperatures in the creep range.

Calculations with RSTRENG Program

Updating Existing Project Files

After the user enters the Location of Pitting, the pipe OD, Wall Thickness, and SMYS and begins entering a Design Factor, a supporting screen appears with MAOP values for noted Design Factors. See screenshot on next page of a Site Input Screen.

Opening New Project Files

The corrosion data can now be entered either by pasting the data from an Excel spreadsheet, manually inputting the data or from the 3D Pipeline Analysis software. Below are RSTRENG Calculations for a 20” O.D. x 0.250” WT x 52,000 SYMS x Class 1 location.

RSTRENG ECDA_4.7.2 Image.png

Using 3D Structured Light with RSTRENG

Using 3D structured light digital data acquisition and analysis allows the operator to assess, make feature comparisons and correlations automatically. Analysis can be used quickly for Level 1 and 2 assessments using RSTRENG, ASME B31.G, and Modified B31.G for corrosion and ASME B31.8 for dents.

Accurate 3D Measurements

In order to achieve accurate 3D measurements of the extent and impact of damage on a pipeline, the parent metal or surface of the pipe needs to serve as a baseline for the 3D analysis. Using 3D measurements representing the current condition of the pipe, the data is automatically separated into both damaged and undamaged regions of the pipe. Once the undamaged points have been identified, these points can be used to form surfaces, which then become the reference against which damaged areas are measured to determine the extent of metal loss or metal deformation. The overall data acquisition process consists of the following as shown in the figure on the next page.

Portfolio of 2D scan in sandbox and 3D scan in workspace.

Pipeline Analysis in Figure

• Corrosion using selectable interaction rules and grid patterns
• Dents using ASME B31.8 and Modified ASME B31.8
• Above surface features such as welds
• Combinations of all defects

Pipeline Analysis of Each Corrosion Defect showing maximum depth, area, width, and length with color coding for each defect.

Once the scan data has been analyzed using the appropriate grid size, interaction rules, and then the remaining strength of corroded pipe (RSTRENG) can begin as shown in the figure on the next page.

• Maximum Safe Pressure
• Burst Pressure
• Safety Factor
• Graph and Report

RSTRENG (Effective Area), Modified B31.G and B31.G Calculations

All tools have errors. The table below is a summary of the major sources of 3D tool error associated with the use of 3D data to determine metal loss and metal deformations.

Mitigation/Repair

Defects discovered during initial inspections are found in the operator’s Operations and Maintenance (O&M) plan. The plan includes the methods and timing of all repairs. The required repair schedule interval begins at the time once the condition is discovered.

Repairs

Defect repairs can be divided into three groups and repair intervals. Performance-based repairs are determined by engineering critical assessments (ECAs).

• Immediate
• Scheduled
• Monitored

Mitigation

Anomalies requiring immediate repair are those that might be expected to cause immediate or near-term leaks or ruptures based on their known or perceived effects on the strength of the pipeline. For example, this may include any external corrosion with depths exceeding 80% of the pipe wall thickness or corroded areas that have a failure pressure level less than 1.1 times the MAOP as determined by an engineering critical assessment procedure such as B31G or RSTRENG.

• Reduce Pressure
• Repair
  • Type B pressurized sleeve
  • Type A reinforcing sleeve
  • Composite reinforcing sleeve
  • Direct weld metal deposition
  • Leak clamp
  • Grind or buff out
• Replace Cylinder of Pipe
• Recoat

Documentation (Complete)

Integrity Management quality assurance outlines the necessary documentation for the integrity management program. A “Complete” program should include the processes, inspections, mitigation activities, and prevention activities. Below are some of the processes required for a “Complete” program.

• Provide the sequence of inspection(s) and field interaction of these processes
• Ensure that the criteria and verification for these processes are effective
• Measure, analyze, and record these processes
• Implement mitigation actions to achieve results for continued improvement of these processes

Additional Training

An operator’s integrity management program should include applicable activities to prevent and minimize the consequences of unintended releases from time-dependent features such as corrosion. Technical Toolboxes offers training to help better understand these issues which include:

• RSTRENG
• Integrity Verification & Engineering Critical Assessment
• Defect Assessment
• Cathodic Protection

Related Links

External Corrosion Direct Assessment Procedure – RSTRENG

Pipeline HUB – User Resources