IN LINE INSPECTION PROMPTS FORTIES' LINE REPLACEMENT

An in-line inspection carried out at British Gas' On Line Inspection Centre, a unit of British Gas plc, enabled BP Exploration to evaluate the condition of its Forties pipeline in the North Sea.

Results of the inspection led to a decision to replace the line.

The inspection and the results are described in a report written by Tom Sowerby of the center.

Although the line remained in fully acceptable operating condition, the center reports it was clear that the Forties and other fields that used the system would go on producing well beyond the economic life of the original line.

As a result of the inspections, BP last year replaced the 169-km (104-mile), 32-in. Forties pipeline by laying alongside it a new 36-in. system (OGJ, May 6, p. 49). The replacement increased to 900,000 b/d the pipeline's capacity to take liquid products from a range of adjacent fields.

The staff at the center states that it is almost 20 years since it formulated a policy for the structural revalidation of its own pipeline network by using on-line inspection techniques rather than expensive and disruptive hydrostatic pressure testing.

A research and development program culminated in the production of a range of advanced on-line inspection devices based on the magnetic flux-leakage technique.

At regular intervals, these devices are now run through British Gas' 17,000 km (10,557 miles) of high-pressure transmission pipelines to monitor structural integrity.

An agreement with BP was reached in 1987 to produce an inspection system suitable for the 32-in. Forties main oil pipeline. Such a system required some adaptation of the basic inspection sensing systems in order accurately to locate, size, and subsequently monitor a particular type of corrosion likely to be found in the pipeline.

PIPELINE DETAILS

The Forties pipeline is part of the 380 km of offshore and onshore pipelines which make up the Forties pipeline system (map, OGJ, May 6, p. 50).

The line was installed in 1973-74 to carry production from BP's Forties field to Cruden Bay, Scotland. At that time, it represented the largest offshore pipeline diameter (32 in.) that could be used and was constructed of 5L X65 grade, 19 mm W.T. Design pressure was 2,084 psig (142 bar).

Forties field reserves have been increased four times since discovery, from an initial 1.8 billion bbl of oil to a current 2.470 billion bbl.

Also, production from the Buchan, South Brae, North Brae, Montrose, and Balmoral fields, and from Heimdal in the Norwegian sector, now flows through the pipeline. Early next year, BP's Miller field will produce into the line, according to the company.

Routine conventional monitoring of the pipeline system by BP had already identified the existence of some corrosion, the center says. It was therefore deemed necessary for the inspection system to locate and quantify such corrosion accurately in order for the line's maximum operating throughput to be maintained.

This routine monitoring led to the replacement in 1986-87 of part of the main pipeline riser. It contained the internal metal loss characteristic of individual corrosion pitting, general corrosion containing pitting, selective corrosion attacks of girth welds, and areas of relatively uniform metal loss, which resembles general wall thinning but with a rough internal surface texture.

INSPECTION PROGRAM

The center reports that it performed three inspection operations in the Forties line in June 1988, March 1989, and October 1989. The standard inspection center's performance specification (Table 1) dictated the performance specification of the inspection system.

Adaptations carried out to the sensing systems, however, expanded the specification to include pipe wall-thickness assessment and sizing of specific girth-weld corrosion.

These adaptations meant that all the types of corrosion damage evident on the replaced riser could be unambiguously identified and accurately sized, says the center.

In each of the inspection operations, the center supplied all the launching and receiving equipment necessary to handle the vehicles and hence perform the operations efficiently.

The center ran three types of vehicles in the pipeline: a cleaning vehicle, profile vehicle, and inspection vehicle; the latter is shown in Fig. 1.

These vehicles were all fully commissioned at the center, located in Cramlington, before the operation commenced and transported offshore in special trays and containers to ensure that a minimum amount of preparation and time were required on the platform.

The center reports that during operational planning, a site survey of both launch and receipt facilities had been carried out by the team engineer to ensure that all equipment and facilities to be provided by BP were available at the required time.

INSPECTION RESULTS

When each inspection vehicle was run through the pipeline, the center initially assessed the recorded data to determine both the quality of the data and distance of pipeline inspected.

Full data processing occurred at the inspection center involving transferal of data from inspection tape to computer tape. All data were then fully evaluated by the computing facility at the center.

The data produced showed that corrosion was evident in the pipeline characteristic of individual corrosion pitting, general corrosion containing pitting, large areas of pipe wall thinning, and selective attack of girth welds.

The corrosion was detected from the start of the pipeline for approximately 29 km, gradually reducing with distance from the launch.

The center reports that within this area were found some pipe spools that had resisted corrosion attack even when adjacent pipe spools had shown corrosion.

From the outset, it was necessary to produce the inspection results in formats that allowed BP to:

• Determine the general condition of the pipeline

• Use fracture mechanics specialists to evaluate the effect of the condition of the line on its operating integrity

• Determine a derating curve for the pipeline validated by subsequent inspections.

As a first step, a computer listing was produced (Fig. 2) giving weld numbers down the line, relative distance between each weld, and their absolute distances from launch.

Values of pipe wall thickness for each spool were added to this list. But because of the very large number of readings involved in the inspection process, the center states the values were given in the following manner:

• Mean value-Average value for each spool

• Maximum value-The maximum value obtained in the spool; this also shows the presence of buckle arrestors

• Minimum value-The value of the thinnest area of pipe in the spool

• Standard deviation-A figure which gives an indication of the variability of the wall thickness over the entire spool and hence overall condition of that spool.

In addition to these pipewall thickness statistics, a general assessment of girthweld condition was given in the form of a simple grading system, which identified ucorroded welds, corrosion less than 10% depth, and corrosion greater than 10% depth.

Along with this overall view of the pipeline condition, separate standard feature reports were prepared for the deepest individual corrosion pits found in the line. For each pit the depth, width, and length were given, together with location details.

DEFECTS' SIGNIFICANCE

From the very first inspection operation, the center reports that discussions with BP attempted fully to evaluate the vast quantity of information produced and its relevance to the operation of the pipeline.

At this time, BP entered into a separate contract with the British Gas engineering research station to provide a consultancy service on the fracture mechanics assessment of the data to determine the significance of the defects.

When the inspection vehicle was run in Operation 2 (March 1989), the center notes that it was important to assess the exact nature and extent of the girth-weld corrosion found in Operation 1 and also to determine any "corrosion growth rate,"

This assessment of corrosion growth rate would allow BP to take steps to change the operating conditions of the pipeline, assess the longterm viability of the pipeline with respect to future perceptions of throughput, and satisfy the appropriate regulatory authorities that all actions were being taken to operate the pipeline in a safe manner.

The results obtained in Operation 2 were therefore given as before, i.e., listings of pipe wall thickness and girthweld corrosion severity.

As an additional aid to viewing and understanding, the results were produced graphically. Fig. 3 shows the maximum wall thickness figures plotted for the first 50 km of pipeline.

A further graph was then produced (Fig. 4) to compare 1988 and 1989 pipe wall-thickness data. For clarity, this graph was produced with pipe wall-thickness values averaged over 25 pipe spools. The results showed that corrosion growth had occurred.

The center states that a similar procedure was then adopted for girth-weld corrosion by producing graphs showing depth and circumferential extent. The results from Operation 2 were compared with the 1988 operation results, and the graphs produced to show the increase in maximum depth of girth-weld corrosion and increase in circumferential extent.

These graphs are shown in Figs. 5 and 6, respectively.

As a final step, a report was produced to compare the reported sizes of individual pits from the 1988 and 1989 operations.

Following presentation of this second set of reports, the center reports that BP identified particular pipe spools along the line for which it required further information.

These plans were requested to enable BP directly to compare data produced by the inspection system against automated ultrasonic wall-thickness mapping data retrieved by divers at specific subsea locations along the pipeline.

As a result, the center conducted additional analyses to produce plans of individual pipe spools giving wall-thickness values along and around each selected spool.

Fig. 7 shows such a pipespool plan, with wall thicknesses given at approximately 70 positions along the spool length and at 12 positions around the circumference.

Using this type of spoolplan listing allowed BP, through British Gas' engineering research station, to quantify fully the significance of the wall-thinning corrosion on the operating condition of the pipeline, according to the center.

From the data obtained during Operation 3 (October 1989), the center states that reports on pipe wall thickness and girth-weld corrosion were again produced in both graphical and listing formats.

Pipe wall-thickness graphs compared these data with those obtained from Operations 1 and 2, similar to that produced in Fig. 3.

Graphs were also produced showing girth-weld depth and circumferential increase similar to those shown in Figs. 4 and 5.

As a final report, the deepest pitting corrosion found in the pipeline was given and then compared with those identified from the previous runs.

Copyright 1991 Oil & Gas Journal. All Rights Reserved.