PL Fit for Service Theory

Fitness for Service (FFS) is a quantitative engineering methodology designed to assess in-service industrial assets' structural integrity and operational safety. In IMS PLSS, FFS assessments are conducted exclusively for Carbon Steel Pipelines, Flowlines, and Pipeline Jumpers, adhering to two primary standards: DNV RP-F101 and ASME B31G. These standards provide structured approaches for evaluating the condition of assets with material loss or other damage mechanisms.

The primary goal of IMS PLSS is to determine the Next Inspection Date (NID) by calculating the Pipeline's Remaining Life (RL). This process begins with the FFS module analyzing Defects identified during in-line Inspections. It then calculates the Corrosion Tolerance values for each Defect and identifies the most critical one. This information helps us determine whether a pipeline is fit for service, how long it will remain so, and how much corrosion can occur without compromising integrity. By combining FFS results with Risk-Based Assessment, IMS-PLSS helps you determine the NID.

Defect Assessment

The objective of FFS is to determine if the Pipline with Defect(s) is Fit for Service (at the time of Inspection) i.e. to confirm that its Safe Working Pressure (PSW) is higher than its Maximum Allowable Operating Pressure (MAOP). The PSW reflects the maximum pressure a Pipeline can endure safely under normal conditions, while the MAOP defines the highest operational pressure permitted without compromising structural integrity.

Hoop Stress Due to Internal Pressure

Hoop stress is the circumferential stress in a Pipeline wall resulting from internal pressure. It is a key factor in determining a Pipeline's ability to withstand operational pressures.

Barlow's Equation is used to calculate Hoop stress:

Where:

σ_h = Hoop stress

P = Internal pressure

D = Pipe diameter

t = Wall thickness

Design Pressure

Design pressure emerges from this analysis, representing the Maximum Safe Operating Pressure. It incorporates material properties, safety factors, and potential operational variations. The Design pressure is calculated:

Where:

f= Pipeline design factor

σ_{y =} Material Yield Strength (SMYS)

Failure Pressure of an Undamaged Pipe

As internal stress increases within the pipeline, it approaches the material’s Yield Strength, leading to deformation, as illustrated on the image below as we can see in the image below, where the red line reprssents the Hoop stress burst test for undemaged Pipeline.

Yield Strength (σy​) represents the maximum stress a material can withstand while maintaining its original shape, with Ultimate Tensile Strength (σUTS​) indicating the stress threshold before failure, and the region between these points marking the transition from elastic to plastic deformation where permanent material changes occur.

Failure occurs when the Hoops Stres (σ_h) becmes equal to the Flow Stress (σ_flow) indiating that the pipeline can no longer maintain it’s structural integrity.

From here we derive the formula for Failure Pressure for undamaged pipe:

Failure Pressure of a Corroded Pipe

A pipe with a Defect, such as corrosion, must be evaluated to determine its impact on structural integrity. If the defect is characterized by a specific length (L) and depth (d), its area (A₀) can be calculated using the following formula:

Where:

A₀: Area of the defect

t: Wall thickness of the pipe

To calculate the Failure Pressure of a corroded pipe, we begin with the failure pressure of an undamaged pipe and apply a factor known as the Remaining Strength Factor (RSF). This factor accounts for the impact of corrosion:

Where:

A = Area affected by corrosion

M = Bulging factor, which accounts for the effects of internal pressure on the structural integrity of a pipe with defects.

The Failure Pressure (P_failure) of a corroded Pipeline can then be expressed as the Failure Pressure of an undamaged Pipe multiplied by the Remaining Strength Factor (RSF) due to corrosion:

Or alternatively,

This equation serves as a universal method for calculating Safe Working Pressures across various pipeline and Fitness for Service (FFS) assessment codes.

Where:

• σ_flow​ = Flow stress (the stress at which failure occurs)

• D = Diameter of the pipe

After evaluating the extent of corrosion and its impact on pressure tolerance, next we need to determine how much pressure a corroded pipe can safely handle to ensuring accurate evaluations even under less-than-ideal conditions.

Safe Working Pressure

The Safe Working Pressure (P_SW) is calculated:

or,

Where:

• f = Design factor or safety factor, which accounts for uncertainties in material properties and operating conditions.

The Repair Factor (ERF)

Once we have established the Safe Working Pressure, we calculate the Estimated Repair Factor (ERF) based on inspection findings. The ERF is defined as:

For each Anomaly an ERF is often given in the Inspection report, following an ILI Run.

This factor helps determine whether corrective actions are necessary:

• If ERF < 1, it indicates that MAOP is below Safe Working Pressure, allowing operations to continue safely.

• Conversely, if ERF>1, it signals that immediate action is required, such as Repairs or Derating.

For instance, if an inspection reveals an ERF of 0.8 at one point in time but later assessments show an increase beyond 1, this highlights the need for prompt intervention to ensure safety.

Defect Assessment Methods

In IMS PLSS there are different Defect Assessment methods that allow us to calculate the Corrosion Tolerance:

ASME B31G defines flow stress as 1.1 times the Specified Minimum Yield Strength (SMYS) in its original form, while a modified version adds 69 MPa (approximately 10 KSI) for improved accuracy.

Introduced in 2010, DNV RP-F101 focuses on Ultimate Tensile Strength (UTS) and predicts failure at 0.9 times UTS. This standard simplifies Defect shapes to rectangles, whereas ASME B31G originally used parabolic approximations before allowing arbitrary shapes.

The Bulging Factor assesses how Defects deform under pressure; smaller defects have less impact, while larger ones significantly affect structural integrity.

Both standards utilize the Failure Assessment Diagram (FAD) to visualize safe working pressures. This diagram plots defect length against depth, with points below the curve indicating safe conditions and those above signaling potential failure risks.

The maximum allowable depths for Defects are: 80% of Wall Thickness (WT) for ASME and 85% for DNV. Exceeding these thresholds renders Defects unsafe.

The defect assessment curve varies depending of the material grade and Assessment method.

Assessment Levels

There are different FFS Assessment Levels:

• Level 1 (in PLSS): Includes Original B31G, Modified B31G, and DNV RP-F101 (Part B). These methods provide simple calculations for pipeline integrity, focusing on individual defects and safe working pressure.

• Level 2 (not in PLSS): The Effective Area Method (or River Bottom Profile) refines assessments by considering the effective area of interacting defects.

• Level 3 (not in PLSS): Involves detailed techniques like Finite Element Analysis (FEA) for complex stress modeling and precise evaluations of pipeline behavior under various conditions.

Defect Interaction

In Pipeline Assessments, Defects often cluster, leading to complex vulnerabilities. ASME B31G evaluates defects individually but recognizes that closely spaced defects (within three times the nominal wall thickness, or 3t can behave as a single larger defect, compromising structural integrity. DNV RP-F101 also assesses Defects individually but accounts for interactions among adjacent Defects based on their axial distance relative to the Pipe Diameter and Wall Thickness. This approach helps identify potential influences between Defects.

ASME B31G Defect Interaction

When Defects are close enough, they may interact, effectively acting as a single, larger defect. This interaction reduces the pipeline's strength at that location more than any individual defect would.

• The ASME B31G methodology handles interacting defects by constructing them into a "cluster." Each corrosion defect is assessed once, either as an individual defect or, if interacting, as part of a corrosioncluster.

• Defects are considered interacting if the axial and radial distance between them is less than three times the Nominal Wall Thickness).

• A cluster's total length includes all interacting defects, and its depth is calculated as the average depth of those defects.

Take note

If you select the ASME B31G (original or modified) methodology in IMS PLSS, the software does not automatically check for defect interaction. You must:

1. Identify interacting defects and define clusters manually.

2. Import the "clustered" defect list into PLSS for assessment.

Typically, inline inspection (ILI) vendors provide both "unclustered" and "clustered" defect lists, ensuring you have the data needed for proper analysis.

Clustering method: when the distance between corrosion sites is less than three times the nominal wall thickness, these defects may be grouped together as a single entity.

DNV RP F101 Defect Interaction

When defects are sufficiently close, they may interact, resulting in a combined strength that is lower than that of any individual defect.

The DNV RP-F101 methodology assesses each defect individually while also evaluating adjacent combinations of interacting defects. A corrosion defect can be assessed multiple times if it interacts with others, and the worst safe working pressure is selected. Corrosion defects are considered interacting if the axial distance is less than 2 and the radial distance is less than π .

Take note

If you choose the DNV RP-F101 methodology, IMS PLSS automatically applies the interaction rules. You need to import the "unclustered" defect list into PLSS. Typically, your inline inspection (ILI) vendor can provide both "unclustered" and "clustered" defect lists for your assessment needs.

The DNV RP-F101 method uses a three-step process consiting of:

• Step 1. Sectioning the Pipeline:

  The pipeline is divided into sections using , where D is the Diameter and t is the Wall Thickness, to organize defect analysis.

• Step 2. Projecting Defects:

  Defects are mapped onto projection lines from neighboring sections. Overlapping internal and external Defects interact, with combined depth calculated as di=d1+d2​ in the 2010 version.

• Step 3. Calculating the Safe Working Pressure: P_sw is calculated for each adjacent combination (n to m) with effective length l_nm and effective depth d_nm. The lowest determines the Safe Working Pressure for the corroded pipe. defects can nly interact for .

The three-step process is repeated per each of the projection lines.

In DNV RP-F101 2010, overlapping defects were treated as a single defect with combined length and maximum depth.

The 2015 update considers overlapping defects individually for pressure calculations.

Corrosion Tolerance and Limit State

IMS PLSS helps you determine for how long after the inspection date, the Pipeline will be still fit for service. This involves determining when the pipeline will reach its Limit State, defined as the condition at which it is no longer fit for service. To estimate this timeframe, it is neccessary assesses Corrosion Tolerance and divide it by the predicted Corrosion Rate. Under both ASME and DNV guidelines, the condition where safe working pressure equals maximum allowable operating pressure signifies reaching the limit state.

Corrosion Tolerance without Defects

In scenarios where no defects are identified during inspection (or no inspection has been conducted), potential corrosion types must be anticipated—be it general corrosion, grooving, or pitting. Corrosion morphology is modeled based on these corrosion types using specific length-to-depth ratios:

• Pitting: Length (L) = 20 times diameter (d)

• Grooving: Length (L) = 80 times diameter (d)

• General Corrosion: Length (L) = 1000 times diameter (d)

A line is plotted on the Assessment diagram from the origin (0,0) to the limit state based on this length-to-depth ratio. The intersation of tis line with the Assessment Curve reveals the CT and Minimal Allowable Thicknes (MAT).

Corrosion Tolerance with Defects

When defects are present, a line is drawn from the origin (0,0) through the defect to represent historical corrosion growth. From the defect point onward to where it intersects with the assessment curve represents future corrosion growth, assuming that the length-to-depth ratio remains constant. The distance between where these lines intersect with the safety curve and where the defect meets the x-axis indicates the Corrosion Tolerances (CT) at the time of the In-Line Inspection (ILI) run.

In PLSS Corrosion Tolerance is calculated fro every Defect. With ASME, this is a single calculation because every defect is only assessed once. With DNV, this is an iterative calculation because defects may be assessed multiple times (if interacting) – hence more computationally intensive (noticeable if >50.000 defects)

In the RBA module, for pipe sections with Defects, the Defect with the smallest Corrosion Tolerance (CT) is used to calculate the Remaining Life based on Corrosion Rates. The selected morphology is ignored if there are defects, also if this would lead to a smaller CT. For defect-free sections, the selected morphology is used to determine CT.

Corrosion Tolerance in PLSS - DNV

In PLSS the following method is used to determine the CT of a Defect:

1. Grow Defects: Each individual defect is grown by a factor where N starts at 0 and increases incrementally, maintaining the length-to-depth ratio (L/D).

2. Reassess Interaction and Recalculate Safe Working Pressure:

• If the recalculated Safe Working Pressure is less than the Maximum Allowable Operating Pressure (MAOP), increment  N by 1 and repeat step 1.

• If the safe working pressure exceeds MAOP, set Corrosion Tolerance as and stop.