In Situ Pipeline Coating Process Passes Saudi Desert Test

The in situ coating process has proven in many parts of the world to be a viable alternative for rehabilitating corroded pipe interiors with a wide range of diameters and lenths. Compared to replacement with newpipeline, this one-run field process is cost-effective. The coating effectively controls internal pipeline corrosionthrough the application of multiple coats of a high-build liquid epoxy that coves the entire internal surface of the pipeline including girth welds, corrosion pits, channels, corrosion lakes or general corrosion and other internal pipeline imperfections, thus delaying leaks and extending the remaining pipeline service life.

Surface, buried, and subea pipelines have been coated in various geographies ranging from the North Sea, North America, Continental Europe, and Africa to Hong Kong and Indonesia. This article details the in situcoating process and then reports on an assessment of the process in rehabilitating piplines suffering from internal corrosion at an oil desert field complex in Saudi Arabia. A trial was required to quality the technology within a Saudi Arabia pipelines network system.

History of the In Situ Coating Process

The in situ coating process was developed to apply an epoxy barrier coating to the internal surfaces of piplines to prevent future corrosion and extend pipline useful life. The process has been successfully undertaken for more than 30 years in many parts of the world. More than 150 new and existing piplines have been coated successfully, with diameters ranging from 15 to 75 cm (6 to 30 inches) and in lengths up to 25 km (16 miles). The coating process is designed to provide full internal coverage, including the coating of girth welds, bends, pits, general corrosion and erosion, and other surface discontinuities.

While the bulk of the applications have been in the oil and gas industry, coatings have been applied to otherpipelines including water, chemical, food, and fuel logistics. Exposure environments for all applications have varied widely. The coated pipelines have a long history of post-coating service, with certain lines coated as far back as 1978 that are still in service. To the author's knowledge, no pipelines have been withdrawn from service due to a compromise of the coating applied using this process, except for demolished or mothballed pipe.

Outside of extending pipeline life (negating the need for pipeline replacement), other benefits of the process include effectively reducing internal pipe friction (high pipeline volumes and reduced energy costs), reducing future scraping requirements and maintenance costs, producing a cleaner product, reducing the use of inhibitors, and reducing fouling. The process is also, potentially, one of the solutions for mitigating the generation of black powder in pipes if the source of the black powder is the uncoated internal pipelinesurfaces. 'Black powder' is a broad term for byproducts, mainly iron oxides, in addition to mill scale, dust, and other irons, that formed during pipeline operations. The size of these substances varies between 1 and 100 microns.

How the Process Works

The in situ internal coating process is primarily based on the use of scrapers propelled by either compressed air or nitrogen. The coating is required to deliver

• consistent coverage
• a moisture barrier
• resistance to the product transported across the scoped operating temperatures
• high levels of adhesion when applied and over its useful life
• no adverse reaction to the pipeline
• sufficient physical strength to resist erosion
• a non-toxic and environmentally benign coating, an
• attractive costs relative to other viable solutions.

Generally completed within 30 days, depending on the pipe length, diameter, and internal condition, the in situ internal pipeline cleaning and coating process comprises of the following steps, which were followed in most of projects,

1. Field Inspection & Planning: This phase of the operation involves gathering the necessary technical information, including pipe diameter; suitability of line for the passage of scrapers; elevation profile; mapping of junctions, joints, restrictions, and other features, such as access at the launcher and receiver sites; planning; and logistics.

2. Site Preparation: This phase calls for procedures such as installing specialized launchers and receivers; mobilizing compressors and dryers; installing (drop-out) spools and shoes; setting up effluent handling facilities; establishing the fuel and water supply; training for operator induction; and situating mobile workshops, compressors, and storage facilities for consumables. It is important for the compressor string to deliver dry and particu-late-free air into the pipeline.

3. De-oiling/Dewatering: Depending on the hand-over condition of the pipeline, this phase has the objective of delivering a hydrocarbon-free pipeline that will allow the surface preparation phase to begin in earnest. All effluent will be disposed of in a manner acceptable to the client or facility owner.

4. Mechanical Cleaning: This phase requires removing all loose material (such as rust, mill scale, and dust) on the internal surfaces of the pipeline and is achieved through multiple-run passes of mechanical and brush scrapers through the pipeline in conjunction with water flushes, if necessary (Figs. 1 and 2).

5. Chemical Cleaning (Fig. 3): This phase targets the removal of all iron oxide and mill scale and leaves the internal pipe surface cleanliness comparable to a Near-White Metal finish (SSPC-SP 10/NACE No. 2). This degree of cleanliness is required to guarantee the adhesion of the coating to the interna! surface of the pipeline. This is achieved by running a dilute HCI solution containing a corrosion inhibitor between two acid-resistant scrapers. (The solution is inhibited to mitigate the risk of a negative impact on the clean internal surface of the carbon steel pipe.) The solution is titrated before and after its passage through the pipeline to determine the degree of depletion of the concentration of the solution. The effluent is also tested for solids. Batching of HCI solutions will continue until both the depletion and solids tests are within acceptable parameters. HCI is then purged from the line with a water rinse; the rinse water will also be tested for pH, chlorides, and solids. Water rinses continue until these parameters are again within acceptable limits. Where possible, the line at drop-out spools and other access points, such as pipe ends, should be inspected visually to confirm the cleanliness of the pipeline.

6. Passivation: This phase serves to remove any oxidation (rust blooming/flash rusting) that results from the previous water rinses and to stabilize the metal surface to prevent any further oxidation. Passivation is completed by running a pH-balanced phosphoric acid wash through the pipeline.

7. Inhibited Water Rinse: To buffer the low pH of the phosphoric acid in the pipeline and further passivate thepipeline, a dilute inhibited water batch is run through the pipeline.

8. Drying: To ensure that the pipeline is dry before applying the coating two procedures are undertaken: solvent drying and dry air purging:

• Solvent drying involves running suitable solvent batches through the line to remove moisture from thepipeline.
• Dry air purging is done slowly using dehydrated air that is tested until dew point measurements are within acceptable limits.

9. Coating Application: The coating is a specially formulated polyamide or aminecured epoxy to ensure a longer pot life and hanging-properties needed for the coating to bond to the internal pipe wall at the 12 o'clock position during and after the coating application (Fig. 4). The coating is applied between two modified urethane coating scrapers and, depending on the pipe length and size, the coating is applied over a number of multiple runs, with appropriate coating drying periods, to deliver the specified dry film thickness (DFT).

10. Testing and Quality Control (QC): Throughout the process and after coating, numerous tests, including DFT and adhesion tests, and other quality control measures, are undertaken to ensure the quality and long life of the final coating.

Field Application

A 40-centimeter (16-inch) crude oil trunk line was selected to test the in situ internal coating method described above and offered by one ot the oil field service specialist pipe coating companies in Saudi Arabia. The trunk line used in the trial is 10 kilometers (6 miles) long and links two gas and oil separation plants' lateral lines, which connect several oil wells in the Empty Quarter desert. The corrosion identified was a combination of general internal corrosion and pitting, concentrated in the 4 to 8 o'clock position in the internal surface of the pipe. The corrosion had resulted in a number of leaks recently after the pipeline was commissioned.

The process involved the application of an internal epoxy coating with a DFT of approximately 8 mils (200 microns) on the internal surface of the pipeline, providing a barrier to control further corrosion on the internal surfaces. Because the cleaning and coating processes are based on scraper operations, access to the pipes was essen-tial only at either end of the pipeline being repaired, which are identified as the launcher and the receiver. The work involved the intensive process of preparing the pipe internal surface by de-oiling and de-watering, mechanical cleaning, chemical cleaning, passivation, drying and internal coating, including inspection.

For the project to begin, the pipeline had to be taken out of service and drained of oil within a specified timeframe and strict schedule. The pipeline was then given to a coating applicator for site commissioning, final de-oiling and hydrocarbon removal, mechanical cleaning, chemical cleaning, passivation, drying, and coating.

The pipeline has a maximum elevation differential of 300 m (985 ft), and the launcher end is at 100 m (328 ft] above the receiver end. Figures 5 and 6 illustrate both the in situ internal cleaning and coating overall process and the core cleaning and coating tools of the pipeline respectively.

After the pipeline section was handed over to the applicator, the next step was to establish the site, which took one week. Figures 7 and 8 show the launcher and receiver sites respectively.

The pipeline had not been purged of hydrocarbons, so after site establishment, the removal of hydrocarbons began and was completed within 14 days.

The corroded pipeline (Fig. 9) was successfully cleaned, coated (Figs. 10 and 11) and handed back to facility owner within 21 days of the first scraper being run through the pipeline.

The test run at the Arabian desert's oil field confirms the usefulness of the internal pipeline "in situ coatingprocess" in providing a cost-effective solution for the rehabilitation of corroded and pitted pipelines, delivering effective life extension to the pipelines services. The process can be completed with limited downtime for thepipeline, requiring access to the pipeline for approximately 30 days depending on the pipeline length and diameter. In the trial described above, the coating was proven to effectively cover pits, channel corrosion and erosion, girth welds, bends and other disconformities on the internal surface of the pipeline in the desert. Consequently, the in situ coating is a viable and reliable alternative for pipeline rehabilitations, and due to the success of the trial, has resulted in further internal coating applications in the area.

Sumber : Hammad, Baker S. "In Situ Pipeline Coating Process Passes Saudi Desert Test". 28 Januari 2014. http://search.proquest.com/docview/1345204090?accountid=31562