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Effectively Managing the Complexities of a Natural Gas Pipeline Inspection: An End-To-End Process in Less Than 24 Hours* Ron Maurier, Quest Integrity Group, and Christian Castronova, South Jersey Gas Co. *Presented at Pipeline Pigging & Integrity Management (PPIM) Conference in Houston, Texas February 2014 About the Authors

Ron Maurier, Manager, Pipeline Integrity Management, joined Quest Integrity Group in 2011 with over 20 years of industry experience. In addition to global corporate management responsibilities, he has served as an on-site project manager, developing skills and processes for batching of UT ILI, pigging of unpiggable pipelines, completion of international projects, and integration of DA & ILI integrity evaluation methods. Prior to joining Quest Integrity, Ron spent over 10 years with Tuboscope Pipeline Services in business development and as the Vice President of Operations, and over 13 years with Corrpro Canada as a pipeline consultant and Vice President of Pipeline Services. Ron is also a member of several industry associations and knowledge sharing groups. Christian Castronova, Director, System Integrity, for South Jersey Gas Co. has 30 years of experience in pipeline operations and engineering, the majority of it in natural gas. He is responsible for SJGs integrity management programs and pipeline operations. His integrity management operation has primarily used ILI, and implemented extensive pipeline modifications to allow pig passage. He has also served as project manager for a number of pipeline construction projects. Executive Summary

A South Jersey Gas Co. (SJGC) 8-inch natural gas pipeline, installed in 1951, recently experienced two leaks failures in as many years. This critical asset that crosses an environmentally sensitive wetland and runs through a densely populated area required an integrity assessment to evaluate its future operational feasibility.

With little historic information on file, the low-pressure gas pipeline presented challenges to typical in-line inspection (ILI) applications. Other non-ILI integrity assessment methods were seen as “complicated’ or “near impossible” to complete, as a result of the limited access issues caused by a wetland region and paving over the line. Also, the line also delivered natural gas to a SJGC CNG vehicle refueling station that could not be removed from service for more than 24 consecutive hours, posing a daunting challenge. The previous history of leaks located at the girth welds raised the concern that there was an issue with field joint coating. Because this line is part of a system of pipelines constructed in the early 1950s, it was felt that information gained about this line would provide information that could be applied to the other lines of similar vintage.

During initial planning discussions, SJGC did not believe that inspection “pigging” was a viable option due to line operations. The undocumented bends and the lack of launcher and receiver barrels, as well as the line pressure, was too low to support typical MFL tool operations. Meanwhile, the possibility of a liquid-release failure and the lack of additional information gained made the hydrotesting option unattractive. SJGC required an integrity assessment solution that would enable comprehensive evaluation of the pipeline while minimizing all risks—both operational and environmental.

To meet the challenge, SJGC turned to Quest Integrity Group. SJGC chose Quest Integrity Group to perform the operation because the InVista™ tool is able to perform a comprehensive integrity assessment within the operational constraints of the system.


Quest Integrity developed a pipeline integrity management (PIM) solution that managed the main challenges, low pressure, wet land avoidance, and the 24-hour operation limitation. In a 12-hour period, the pipeline was depressurized and purged, and temporary pig traps were installed. The line was then cleaned, filled with water, inspected with an InVista ultrasonic ILI tool, dewatered, and dried back to a 40oC dew point. The timely operations did not exceed the 50 psi pressure on the pipeline system. The ILI tool traversed the entire length of the pipeline, and, in one pass, provided SJGC with a comprehensive data set featuring wall thickness and high-resolution geometry (deformation) results. The highly collapsible InVista tool was also able to pass an unknown protruding “line tap” that likely would have stopped more rigid ILI tools from traversing the entire line. Additionally, the InVista ultrasonic inspection tool can be reversed in a pipeline should an unpassable blockage be discovered, thereby eliminating the need to evacuate in an environmentally sensitive area.

The inspection provided the remaining strength factor (RSF) and the maximum allowable operating pressure (MAOP) for the entire length of the pipeline. The employment of this end-to-end PIM solution enabled SJGC to return its pipeline to service in record time, thus ensuring adherence to operational commitments with zero environmental impact to the wetlands.

Inspection Project Details

On July 2, 2013, Quest Integrity Group received a request from SJGC representative, Chris Castronova, to perform an InVista inspection and a LifeQuest™ Pipeline assessment at the SJGC Glassboro, NJ site in Egg Harbor Township, New Jersey, USA. The scope of work included the inspection of one pipeline, the 8-inch Glassboro lateral natural gas pipeline.

The Glassboro Lateral is approximately 6,200 feet long and was constructed in 1950 of 0.250-inch wall, Grade B, seamless steel pipe. This line is part of the original natural gas pipeline system built to serve the SJGC territory. Construction records were limited, and no known significant modifications were made to this line since its original construction.

On July 29, 2013, a field team from Quest Integrity Group traveled to the SJGC facility in Egg Harbor Township. The crew met with SJGC staff and made arrangements to begin the inspection. Quest Integrity provided a four-man crew that worked with SJGC personnel to perform the mechanical and operational tasks associated with the operation. Essential work tasks included:

Rigging up the temporary launcher and receivers

Operation of valves closure for pigging operations and loading, removal, venting and equalizing

Frac tanks and associated flow hose for water

Connection to a local firewater system for water supply for the operation

Supply and connection of a high-volume water pump

Injection of a water batch with a chemical cleaning agent

Supply and connection of a high-volume air compressor and air dryer unit

A mechanical line cleaning (four pig runs) propelled with air; the first cleaning run consisted of a disc-foam pig, followed by two cup-disc mandrel-body pigs, which was then followed by a mandrel multi-disc pig

The line was loaded with water during the final-cleaning pig run, ensuring complete removal of air from the line

On July 30, 2013, at 12:23 p.m. the 8-inch InVista inspection tool was introduced into the

temporary launcher at the Glassboro Block Valve location and entered the pipeline at 12:35 p.m. The


tool was propelled with water (~70°F) at a pressure of 10 lbs. to achieve a ~1.9 ft. /second scan rate. The total distance recorded was 6,208 ft.

The tool was received in the temporary receiver at the Glassboro Station at 1:45 p.m. One hour after the recovery of the inspection tool and the validation of data collection, line drying operations began. Quest Integrity Group ran 55 light-density foam pigs utilizing a HV air compressor and dryer unit. The pipeline was dried to the required and monitored -40oC dew point that same day.

Upon retrieval of the tool, the UT measurement data was downloaded and prepared for preliminary analysis. The analysis determined that the recorded data was mostly free of anomalies associated with scaling, gas pockets, or other foreign material present in the pipeline during inspection. The pipeline was then dried with additional cleaning pigs. Following the field inspection data verification, Quest Integrity Group personnel returned to the office to analyze, assess and report the fitness for service of the pipeline. With the written report and the provided LifeQuest™ Pipeline application package, Quest Integrity Group reported the results of the inspection and API 579-1 / ASME FFS-1 2007 fitness-for-service assessment. Table 1 lists the pipeline features. Table 2 lists the pipeline specifications.

Table 1. Pipeline Features

Feature Number

Girth welds 178

Flanges 6

Valves 2

Taps/Tees 6

Bends 20

Repair sleeves 0

Patches 0

External welds 5

Attachments 0

AGMs recorded / placed

6 / 6


Table 2. Pipeline Specifications

Pipeline Identification 8-Inch Glassboro lateral natural gas pipeline

Launch Location Glassboro Block Valve

Receive Location Glassboro Station

Pipe Material API 5L grade B carbon steel

Design Code ASME B31.4

Weld Quality Factor (E) 1.0

Specified Minimum Yield Strength

35,000 psi (241.3 MPa)

Design Safety Factor Applied

0.72

Maximum Allowable Operating Pressure (MAOP)

250 psig (1.7 MPa)

Maximum Operating Pressure (MOP)

250 psig (1.72 MPa)

Nominal Outer Diameter

8.625 inch (219.1mm)

Nominal Thickness

0.250 inch (6.35mm) 0.277 inch (7.04mm) 0.322 inch (8.18m) 0.500 inch (12.70mm)

Pipeline service Date 1951

Total Pipeline Length 6,202 ft. (1,891 m)

Corrosion Allowance None applied

The pipeline inspection data from the InVista inspection tool was analyzed for wall thinning and anomalies such as corrosion, denting and ovality. The qualified data from the analysis were assessed using the LifeQuest Pipeline software to determine the RSF and MAOP for the pipeline. This assessment was based on the longitudinal extent of thinning found in the pipeline and in accordance with a Level 2 Assessment described in Part 5 of the API 579 standard.


Table 3Table 3 is a summary of the analyzed data quality and the calculated RSFs, and compares computed MAOP values for the pipeline to the maximum operating pressure provided by Chris Castronova of SJGC.

Table 3. Analyzed Data Quality

Pipeline Segment

Sensor Data Captured, %

Valid Data (Inner

Profile), %

Valid Data (Thickness), %

Minimum Measured Wall

Thickness, inch

RSF, minimum

MAOPr [psig],

minimum

MAOP, psig

8-inch Glassboro

Lateral Natural Gas Pipeline

100 99.9 99.8 0.195 0.824 1,338 250

The pipeline MAOP was provided as 250 psig (1.72 MPa) and 60°F as the maximum operating

temperature. The pipeline was constructed of 6,202 ft. (1,891 m) of grade B API 5L carbon steel 8-inch pipes with nominal wall thicknesses of 0.250-inch, 0.277-inch, 0.322-inch and 0.500-inch. The inspection revealed the following:

Nine (9) external metal loss anomalies with a depth greater than 10% were individually identified in the inspection data. The minimum measured thickness due to metal loss was 0.196 inch (5.0 mm). Based on nominal wall thickness of 0.250 inch (6.3 mm), this metal loss corresponds to a 21.6% wall loss.

Three (3) internal metal loss anomalies with a depth greater than 10% were individually identified in the inspection data. The minimum measured thickness for the deepest internal metal loss feature was 0.195 inch (5.0 mm). Based on nominal wall thickness of 0.250 inch (6.3 mm), this metal loss corresponds to a 22.0% wall loss.

One hundred seventeen (117) dents in excess of 0.5% of the nominal outer diameter (OD) were identified in the inspection data. The maximum dent size was 7.6% of nominal OD, which was excavated based on the preliminary report and was found to have light gouging. It was subsequently repaired and reclassified as a dent with metal loss.

Three (3) dents with metal loss were individually identified in the inspection data. Two of the three dents with metal loss (including the 7.6% dent) were excavated following the preliminary report, were found to have light gouging, and were subsequently repaired and reclassified as dents with metal loss.

The minimum reduced MAOP calculated according to the Part 5 Level 2 assessment methodology in API 579 was 1,338 psi (9.2 MPa).

Based upon this inspection data, the pipeline satisfies the API 579 Part 5 Level 2 Fitness-for-Service

criterion for any maximum operating pressures equal to or below the listed design MAOP of 250 psig (1.7 MPa).

The assessment calculations were carried out without any future corrosion allowance. Future inspections to monitor corrosion rate, or additional assessment to analyze the damage mechanisms, or to more accurately quantify the stresses (e.g., Level 3 analysis) experienced by the thinned areas, could provide greater confidence for the continued safe operation of the pipeline.

Immediate Repair Conditions


The inspection identified one (1) dent on the pipeline in excess of 6% of the nominal OD. The inspection identified zero (0) metal loss in excess of 80% wall loss. The inspection identified three (3) dents with associated metal loss, as shown in Table 4.

Table 4. Dents With Metal Loss

Feature Number Max. Wall Loss, % Max Denting, %

Metal loss in excess of 80%

0 22.0 -

Dents over 6% 1

(repaired) - 7.6

Dents with metal loss 3

(2 of 3 repaired) - 7.6

Analysis of Inspection Data

A data analyst reviewed the raw UT measurements collected by the InVista tool to qualify the data and identify pipeline features. Qualified data are inspection readings which have been validated by the analyst. Data points not qualified by an analyst were not included in the assessment calculations. The quality of the data acquired directly corresponds to the cleanliness of the pipe, air bubbles in the line, and tool alignment passing through piping fittings such as bends, tees and valves. A quantitative measurement of data quality is obtained by taking the ratio of the qualified data points to the total number of data measurements, as shown in Table 5.

Table 5. Quality of Inspection Data

Pipeline Segment Sensor Data Captured, % Valid Data

(inner profile), % Valid Data

(thickness), %

8-Inch Glassboro lateral natural gas pipeline

100 99.9 99.8

In Table 5, valid data means an ultrasonic reading that was captured by the sensor with

sufficient signal strength and shape as judged by the data analyst. Due to the nature of the ultrasonic measurement, locations at which a valid inner profile reading was measured can be used as the primary indicator of whether a given sensor was unobstructed and successfully processing data at a given time.

Inner profile readings can be obstructed by debris in the pipeline. Reasons for a valid inner profile reading without a valid wall thickness reading can include cleanliness of the pipe, the inspection medium, geometry effects due to the profile of the pipe surface, geometry effects due to tool orientation, and grade of the pipe material.

Quest Integrity Group maintains a fully documented Qualification and Certification System as per the internal Written Practice WI040950, which complies with the Standards ASNT-SNT-TC-1A-2006 and ANSI/ASNT ILI-PQ-2005. All NDT tool operators are certified accordingly.

Detailed Inspection Results

The construction details for the pipeline were provided by SJGC and were compared to inspection data. Based on this information, the pipeline was constructed of 8-inch pipes with nominal wall thicknesses of 0.250-inch, 0.277-inch, 0.322-inch and 0.500-inch. The material throughout was


given as Grade B API 5L carbon steel seamless pipe. The inspection data started at Glassboro Block Valve (girth weld GW10) and ended at Glassboro Station (girth weld GW1810). Metal loss features with a wall loss greater than 10% were individually identified and reported in the inspection data. Interaction criteria of 3t by 3t were applied to combine metal loss features. A preliminary report providing the results of preliminary data analysis and assessment was provided on August 14, 2013.

Nine (9) external metal loss anomalies greater than 10% were individually identified in the inspection data. The minimum measured wall thickness (see Figure 1) due to external metal loss was located 34.92 ft. (10.6 m) downstream from girth weld GW1050 (GW position 3,591.18 ft. (1,094.6 m)) and the deepest point was located at 3:04 o’clock.

The minimum measured thickness for this metal loss feature was 0.196 inch (5.0 mm). Based on nominal wall thickness of 0.250 inch (6.3 mm), this metal loss corresponds to a 21.6% wall loss. The cause of the external wall loss appeared to be corrosion.


Figure 1. 2D and 3D views of external metal loss downstream of girth weld GW1050

External metal loss located

downstream of girth weld GW1050

with a depth of 21.6% of nominal wall

thickness.


Three (3) internal metal loss anomalies greater than 10% were individually identified in the inspection data. The minimum measured wall thickness (see Figure 2) due to internal metal loss was located at 21.95 ft. (6.7 m) downstream from girth weld 1360 (GW position 4,805.02 ft. (1,464.6 m)) and the deepest point was located at 3:04 o’clock (see Figure 2). The minimum measured thickness for this metal loss feature was 0.195 inch (5.0 mm).

Based on nominal wall thickness of 0.250 inch (6.3 mm), this metal loss corresponds to a 22.0% wall loss. The cause of the internal wall loss appeared to be corrosion.

Figure 2. 2D and 3D views of internal metal loss downstream of girth weld GW1360

A total of one hundred seventeen (117) dents with depth greater than or equal to 0.5% of the

Internal metal loss located

downstream of girth weld GW1360

with a depth of 22.0% of nominal wall

thickness.


nominal OD were individually identified in the inspection data. One (1) dent with a depth exceeding 6% of the nominal pipe outside diameter (OD) was identified.

The deepest dent was located downstream of girth weld GW650 at GW position 1,953.58 ft. (595.5 m) and had a depth of 7.6% of OD and an orientation of 10:33 o’clock (see Figure 3). This dent was excavated and repaired following the preliminary report and was found to have light gouging associated with it and the smaller surrounding dent. These dents have been reclassified as ‘Dent with Metal Loss’ in the final report.

No laminations longer than 12 inches (304.8 mm) and wider than 0.75 inch (19.05 mm) were individually identified.

Figure 3. Wall thickness, inner radius and cross-sectional views of dent downstream of girth weld GW650

Three (3) dents with metal loss were individually identified in the inspection data. The deepest

unrepaired dent with metal loss is located downstream of girth weld GW1120 at GW position 3,926.98 ft. (1,196.9 m) and has a deformation depth of 3.2% of OD and a metal loss with a minimum measured thickness of 0.215 inch (5.4 mm). This metal loss corresponds to a 14.2% wall loss and had an

Dent located downstream of

girth weld GW650 with a depth

of 7.6%

Wall Thickness

View

Inner Radius View


orientation of 11:26 o’clock (see Error! Reference source not found.Figure 4). The cause of the dent with metal loss appeared to be possible mechanical damage.

Figure 4. Wall thickness and inner radius views of dent with metal loss downstream of girth weld GW1120

Assessment of Inspection Data

Based on the assessment performed with LifeQuest™ Pipeline software and considering the operating conditions and material properties provided by SJGC, the lowest calculated RSF, with qualified data of 99.8% wall and 99.9% radius measurements, respectively, for the pipeline was 0.824. This minimum value is located between girth welds GW1560 and GW1570, with an MAOP of 1,338 psig (9.2 MPa), which is also the lowest MAOP for the pipeline. The corresponding minimum measured thickness for this area is 0.196 inch (5.0 mm) and represents a 21.6% wall loss from nominal. The minimum wall thickness for the pipeline is 0.195 inch (5.0 mm), located between girth welds GW1360 and GW1370 and in an area of internal metal loss. This minimum measured thickness represents a depth of 22.0%, based upon a nominal measured wall thickness of 0.250 inch (6.3 mm). The corresponding minimum RSF for this pipe joint is 0.896, with an MAOP of 1,454 psig (10.0 MPa).

Dent with a depth of 3.2% of

nominal OD

Inner Radius View

Wall Thickness View External metal loss with a depth of

14.2% of nominal wall thickness


According to SJGC, this pipeline has a MAOP of 250 psig (1.7 MPa). The minimum calculated MAOP (1,338 psi (9.2 MPa)) of the pipeline is greater than the given MAOP of 250 psig (1.7 MPa) on record for the line. An API 579 fitness-for-service assessment does not allow for operation at greater than the design MAOP, but the line satisfies the Part 5 Level 2 fitness-for-service criteria at the current design MAOP of 250 psig (1.7 MPa). Dent Assessments

Additionally, analysis of the inspection data identified 118 dents on the pipeline in excess of 0.5% of the nominal OD. One (1) dent with a depth exceeding 6% of the nominal pipe outside diameter (OD) was identified. Two (2) dents with associated metal loss were identified after reviewing the preliminary excavation results. Denting on DOT regulated pipelines is generally assessed using the prescriptive criteria of dent location, dent depth, location related to other pipe features, and indication of metal loss, cracking, or stress risers. In general, an API 579 Part 12 Level 1 Assessment of Dents, Gouges, and Dent-Gouge Combinations will be satisfied for simple dents of 7% or less. Additional engineering analysis beyond the scope of this current assessment can be performed for SJGC using the API 579 Level 1, 2, and 3, the B31.8 strain-based methodology, or another assessment type, to further analyze dents identified on this pipeline. Summary and Recommendations

Table 6 represents a summary of the anomalies found and the calculated RSFs, and MAOP values for the 8-inch Glassboro lateral natural gas pipeline.

Table 6. Summary of Anomalies

Feature Number Minimum Measured

Wall Thickness, inch

Maximum Wall Loss,

%

Maximum Depth of OD, %

RSF, minimum

Minimum MAOP [psig]

External Metal Loss 9 0.196 21.6 - 0.877 1,423

Internal Metal Loss 3 0.195 22.0 - 0.882 1,431

Dents 117 - - 7.6 - -

Dents with Metal Loss 3 - - 7.6 - -

Ovality 4 9.2

Laminations 0 - - - - -

The pipeline design conditions were provided as 250 psig (1.7 MPa) with an assumed maximum operating temperature of 60 °F. The maximum operating pressure was reported as 250 psig (1.72 MPa).


The pipeline satisfies the API 579 Part 5 Level 2 fitness-for-service criteria for any maximum operating pressures equal to or below the listed design MAOP of 250 psig (1.7 MPa). It should be noted that assessment calculations were carried out without any future corrosion allowance. The primary damage mechanism is believed to be external metal loss and denting.

Further inspections to monitor corrosion rate, or additional assessment to analyze the damage mechanisms or to more accurately quantify the stresses (e.g., Level 3 analysis) experienced by the thinned areas could provide greater confidence for the continued safe operation of the pipeline.

Conclusions

Based on the results, SJGC gained significant understanding of the condition of the piping system and was able to take appropriate steps to mitigate the risk associated with operating a 60 year-old pipeline system in a densely populated area. Initially, SJGC believed that the two leaks in question were caused by pipeline corrosion. Yet, Quest Integrity’s inspections proved that, in fact, many of the pipeline’s anomalies were actually dents caused by third-party damage or original construction. This fact is an important distinction needed to engineer proper remediation procedures and revise the IMP for this pipeline.

Quest Integrity’s unique technology, practical operations and pipeline-inspection experience were key to providing the inspection solution while meeting the multiple challenges. The success and results were a direct result of Quest Integrity Group’s provision of the InVista tool, which proved to be a viable and economical inspection solution to meet the multiple needs for low-pressure testing, environmentally safe operations, and quicker turnaround time that were not available via other inspection techniques and procedures.

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Effectively Managing the Complexities of a Natural Gas ... · Effectively Managing the Complexities of a Natural Gas Pipeline Inspection: An End-To-End Process in ... the recovery