June 2017, Vol. 244, No. 6


Chemical Treatment of Offshore Pipeline Hydrotest Water Unnecessary

By Graham Collier and Edmond Jung, UniversalPegasus International, Houston

UniversalPegasus International (UPI) was contracted as an owner’s engineer by an operator in the U.S. Gulf of Mexico (GOM) to provide detailed engineering design, during installation and pre-commissioning.

The operator’s field, located in Mississippi Canyon, required a subsea pipeline from a well cluster at a depth of about 2,600 feet, tied back to a host platform in 650 feet of water depth. The operator required up to a three-month gap between pipeline flood/hydrotest and dewatering.

Design, construction and installation included a riser for the platform, about 22 miles in length, with an 8-inch outer diameter (OD) pipeline and installation of PLET and 8-inch OD rigid M-shape jumper.

UPI contracted Stress Engineering Services, Inc. (SES) to perform a series of immersion tests to determine the corrosion rate of API 5L X65 8-inch pipe from unaerated, untreated, unfiltered seawater in order to duplicate the conditions found during a wet parked period of 90 days following offshore pipeline hydrotesting.

There is a wide range of opinions among offshore pipeline engineers about the need for chemical treatment (biocides and corrosion inhibitors) in hydrotesting fluid for offshore pipelines. Currently, there is no analytical data, therefore offshore pipeline engineers are left with conjecture and promotions of chemical treatment product vendors. The objective of this test is to provide analytical data based on a set of project-specific parameters that may be appropriate in other circumstances.


The test’s purpose was to provide evidence that corrosion inhibitors or chemical additives are not necessary for the duration of wet-park conditions of less than 90 days.

The immersion study simulated the in-service conditions and maintained a closed environment temperature (70⁰F) for 90 days. There were no chemical additives to the unfiltered seawater and no sunlight exposure from transporting the seawater samples to the lab. The seawater was collected by Go-Flo bottles (Figure 1) with help of an ROV deployed at the water depth at whack each respective pipeline ends. It was brought to surface and transferred into five-gallon, high-density polyethylene (HDPE) canisters in a closed room, avoiding sun exposure.

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Figure 1: Ro-flo water sampling units.

The two test spools (Figures 2 and 3) were manufactured from provided API 5L Spec. X65 pipe, fitted with welded A36 material end caps and loaded with seawater that was collected from depths near the shallow and wellhead ends of the proposed pipeline.

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Figure 2: Test spool fabrication design drawing.


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Figure 3: Test spools setup for seawater samples. 

Additional seawater samples were sent to the lab for microbial tests and geochemical analysis before and after the testing period for comparison. At the end of 90 days of static conditions, each test spool was drained, fluid was collected for analysis and microbial assay. 

Upon first removal, the test water was blackened, but no scent of hydrogen sulfide or sign of microbial fouling was found. However, the blackened water turned to a bright rust red within 24 hours of being exposed to the atmosphere, suggesting the presence of soluble iron in solution.


After the test spools were emptied, each spool was sawed in half (Figure 4) to examine the internal pipe surface and then slit horizontally by a cold cut. Overall, the condition of each spool was good, rust staining was apparent predominantly where the test water had drained out of the test spools, but no pitting corrosion could be found (Figure 5).

No significant difference in welded sections between upper or lower half sections was found, and all weld surfaces were corrosion-free. Although there was misfit alignment in the welds, it showed no localized corrosion of any sort.

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Figure 4: Test spools cut in half.

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Figure 5: Test spools prior to sand blast.

Therefore, all girth welds and the re-entrant surface of the drain hole were free of localized corrosion. The total wall loss, based upon the increased iron count, was 0.4 mils (0.01 mm) over the exposure period (90 days), or an annualized corrosion loss of 1.6mpy (0.041 mm/yr). (It could be reasonably argued the relatively minute wall loss of 0.4 mils (0.01mm) could have resulted from cleaning the rust staining.)

In regards to the microbial bacteria count, the results were mild, starting at 10-100 viable bacteria per mL of solution with a MICkit 3. At the end of 30 days, there were 1,000-10,000 viable bacteria per mL of solution with MICkit 3-C. Microbial test vials were stored in an incubator at a steady temperature of 70°F and examined visually after 2-, 5-, 15- and 30-day durations. The series dilution test is simply a measure of bacteria count; it is not a measure of propensity for corrosion tendency.

Results for all sample runs were mild. The as‐received water produced a maximum positive test of two bottles, or 10-100 viable bacterial per mL of solution. The post-exposure bottles produced a maximum positive test of three bottles after 30 days or 1,000-10,000 viable bacteria per mL of solution.

The seawater tested as bacterially active and showed a slight-to-moderate increase in bacteria species after the 30-day tests under simulated wet park conditions. Levels of bacteria normally associated with heavy contamination or corrosion of carbon steel pipe were not seen.

During the offshore execution phase, the wet-parked pipeline was dewatered without the need of corrosion inhibitors, saving the operator time and cost to complete the pipeline commissioning and startup.


A typical subsea carbon steel pipeline may be left for up to 90 days with untreated seawater without being adversely affected by corrosion.

The hypothesis that it would be viable to leave a subsea pipeline flooded with untreated seawater for up to 90 days was undoubtedly proven. Further, we are confident the length of time could be extended beyond 90 days.

Authors: Edmund Jung has six years of project engineering, design, and procurement experience in the subsea industry. He has a bachelor’s degree in mechanical engineering from University of Texas at Arlington.

Graham Collier has 40 years of experience in the oil and gas industry mostly in the offshore sector. He has spent the last 29 years working as a project engineer/manager on several major construction projects. He earned a bachelor’s degree in maritime technology from the University of Wales in Cardiff.


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