- Author: Qu Wei, Zhang Chuanxi, Jin Lei, Wang Haifeng, Liu Liang
(1. China National Offshore Oil Corporation (CNOOC) Tianjin Branch; 2. CNOOC Tianjin Pipeline Engineering Technology Co., Ltd.)
Introduction
Subsea pipelines are crucial facilities for transporting oil, gas, and water in offshore oil and gas development, serving as the lifeline for offshore production. Due to the harsh marine environment, subsea pipelines typically employ coating and cathodic protection methods to prevent corrosion of the outer surface. However, the difficulty and complexity of accessing and inspecting subsea pipelines after installation make it extremely challenging to assess the effectiveness of protective coatings and cathodic protection. This makes it difficult to obtain data on the corrosion protection performance of in-service subsea pipelines, hindering efforts to manage the integrity of subsea pipelines and extend their service life.
A submarine natural gas pipeline, which has been in service for 5 years, had approximately 3.5 km of its pipeline segment removed and recycled due to realignment operations. In practical situations, recovered submarine pipelines (segments) are relatively rare. Studying these recovered submarine pipelines (segments) can provide more direct and accurate data on the corrosion condition of the entire pipeline, which will have significant guidance for corrosion control and operation management of the pipeline, as well as pipelines in the same region and type.
Currently, there are only a few reports on the internal corrosion detection of recovered seabed pipelines or segments. However, there are no reports on the detection of the external anti-corrosion layer of recovered seabed pipelines. Therefore, this study focuses on detecting the condition of the external anti-corrosion layer of in-service seabed natural gas pipelines using macroscopic inspection, spark testing, and coating performance testing. This study not only provides a method for evaluating the performance of anti-corrosion layers on in-service seabed pipelines but also accumulates performance data, which can provide reference and basis for extending the lifespan of seabed pipelines, assessing external corrosion, and designing new anti-corrosion layers for pipelines.
1. Relevant information for existing marine pipelines
The structural cross-section of the existing offshore natural gas pipeline is shown in Figure 1. From inside to outside, the layers are steel pipe, 3PE anti-corrosion layer, and concrete weighting layer. Detailed parameters are shown in Table 1. The 3PE anti-corrosion layer consists of an epoxy powder coating on the bottom layer, an adhesive layer in the middle layer, and a polyethylene layer on the outer layer, forming a comprehensive corrosion protection system for the pipeline. The offshore pipeline joints are treated with corrosion and waterproofing using "epoxy powder primer (FBE) + heat-shrink sleeve (HSS) + polyurethane foam layer (PUF) + steel plate". In addition, the outer wall of the offshore pipeline also uses sacrificial anode cathodic protection for corrosion protection.
Figure 1: Cross-sectional view of the in-service pipeline structure.
Table 1: Basic parameters of in-service gas pipelines
2. Macro-inspection of anti-corrosion layer on in-service offshore pipeline sections
2.1 Macro Inspection of the Counterweight Layer
Figure 2 shows the appearance of the in-service offshore pipeline segment after visual inspection. The concrete weight layer appears intact and shows no obvious damage.
Figure 2: Macroscopic appearance of the in-service marine pipeline segment
2.2 Macro-inspection of the anti-corrosion layer
Due to the inability to directly correlate the in-situ marine pipeline segment being removed with its original location on the seabed, a segment with a sacrificial anode was selected for removal of the concrete weight layer and sacrificial anode, followed by 3PE anti-corrosion layer inspection. After removing the weight layer and sacrificial anode from the pipe segment, the 3PE anti-corrosion layer was exposed (as shown in Figure 3). Visual inspection revealed no damage.
Figure 3: Macroscopic morphology of the 3PE anti-corrosion layer after removing the weighting layer and sacrificial anode in the in-service seawater pipeline segment.
(Top: Overall appearance; Bottom: Close-up view)
2.3 Detection of Leak Points in Corrosion Protection Layer
The 3PE anti-corrosion layer was inspected for leaks using a DP300 spark detection instrument. The detection voltage was 25 kV, and the inspection covered the entire pipe. Figure 4 shows a photograph of the 3PE anti-corrosion layer spark detection on-site. During the inspection, the instrument showed no alarms or sparks, indicating that the 3PE anti-corrosion layer of the recovered pipe section was intact.
Figure 4: Photo of the in-service offshore pipeline recovery segment 3PE anti-corrosion layer electrical spark leakage detection site.
2.4 Inspection of Expansion Joints
Due to the use of flame cutting for welding operations on the existing marine pipeline during retrieval, the heat generated caused damage to the heat shrink sleeves located near the weld joint. As shown in Figure 5, individual retrieved pipeline segments exhibit slight peeling near the weld joint, but the heat shrink sleeves cannot be further lifted with a steel ruler.
Figure 5: The heat shrink sleeve on the node weld of the in-service marine pipeline segment was damaged.
2.4.1 Inspection of the thermal shrink sleeve's connection to the steel pipe near the circumferential weld.
Select steel wire with a diameter of 1.2 mm at the joint weld seam end and the connection between the pipe body and the heat shrink sleeve, passing it axially through the pipe, as shown in Figure 6. If the wire cannot be inserted, it indicates that the remaining heat shrink sleeve and pipe body connection is tight. Randomly select 50 recovered pipe segments and repeat the inspection, and the results are consistent.
Figure 6 shows the close fit between the heat shrink sleeve for the pipe section and the pipe body, achieved through axial piercing inspection of the steel wire.
2.4.2 Inspection of the thermal expansion sleeve and 3PE anti-corrosion layer at the proximity of the counterweight layer.
Randomly select 20 recovered pipe segments, remove the polyurethane foam layers at the joints (as shown in Figure 7), exposing the heat shrink sleeve close to the weighting layer and the interface with the 3PE corrosion-resistant layer, in order to inspect the bonding between the heat shrink sleeve and the 3PE corrosion-resistant layer near the weighting layer.
Figure 7: After removing the polyurethane foam nodes in the recovery pipe segment, the exposed thermal insulation layer is located near the overlap with the counterweight layer.
The ends of both recovered pipe sections were inspected. In the randomly selected 20 pipe sections, only two had a slight detachment at the overlapping joint of the heat shrink sleeve itself. One section, identified as 2xxx, measured a detachment size of approximately 170mm x 45mm (see Figure 8), with both axial and circumferential steel wires intact. The other section, identified as 51xx, measured a detachment size of approximately 45mm x 45mm (see Figure 9), with clean edges at the end of the heat shrink sleeve, and both axial and circumferential steel wires intact.
Figure 8, item 2xxx, shows a slight separation and detachment at the overlapping joint of the recycled pipe segment.
Figure 9, section 5xxx, shows a slight separation and detachment at the overlapping joint of the salvaged pipe segment.
2.4.3 Detection of Heat Shrinkage Leak Points in Joints
The nodes of the heat shrink sleeves were inspected for defects using a DP300 spark test instrument. The test voltage was 25 kV, and the sleeves on both ends of the 20 segments of the recycled tubes (as specified in 2.4.2) were inspected. Figure 10 shows the on-site spark test photos of the node heat shrink sleeves of the recycled tube segment. The absence of alarms and sparks during the inspection indicates that the heat shrink sleeves of the recycled tube segment nodes are intact.
Figure 10: Hot spark leakage detection at a marine pipeline recovery segment node.
3 Key Performance Inspection of Anti-Corrosion Layer
Samples were taken from the existing offshore pipeline to perform performance testing according to relevant standards, and the results were compared with the specified requirements. The findings indicate that the protective layer of the offshore pipeline still meets the requirements of the relevant standards after 5 years of service.
Feedback
After 5 years of operation, the underwater natural gas pipeline section was found to have intact weight and corrosion protection layers, with no leakage detected during macro-inspection and spark testing of the corrosion protection layer. The expansion joint sleeves, when macro-inspected, exhibited good adhesion to the steel pipe body and the 3PE corrosion protection layer, and no leakage was detected during spark testing. Key performance tests of the sampled corrosion protection layer also met the requirements of relevant standards. Therefore, the corrosion protection system of the underwater pipeline is still in good condition and can continue to be used.
We recommend that this pipe continue conducting corrosion layer detection and evaluation work, accumulating detection data and performance data for corrosion layers of different service durations. This information can provide a reference and basis for evaluating the corrosion layer performance of similar pipe types, extending the service life of pipes, and designing new pipe corrosion layers.
References (omitted)
Original Title: Inspection and Evaluation of Anti-Corrosion Layer on Existing Marine Pipeline Segments
Please see the complete content in the October 2020 issue of "Coatings and Protection."