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Fast-Acting And Persistent Post-Hydrotest Corrosion Inhibitors For Newly Constructed Oil Pipelines

Picture for Fast-Acting And Persistent Post-Hydrotest Corrosion Inhibitors For Newly Constructed Oil Pipelines
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Pressure testing is a standard practice used to validate the condition of new pipelines (prior to wet commissioning) and may also be used to revalidate the integrity of older pipelines. Since water is the primary medium for pressure testing, the process has been termed hydrostatic testing or hydrotesting. While the low cost, accessibility and environmental impact are primary drivers for use of water, the inherent corrosiveness of water poses an asset integrity challenge.

Product Number: 51321-16901-SG
Author: Hitesh Bagaria; Moshood Adewale; Rob Gutierrez; Jeanne O'Neal; Jennifer Sargent; Nimesh Patel; Trevor Place
Publication Date: 2021
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$20.00
$20.00

Newly constructed long-distance pipelines are often hydrotested with water from a natural reservoir without the use of chemical treatment. Chemicals are typically not used for various reasons: (i) the water is usually released back into the natural environment after use, (ii) the environmental impact of a chemically treated water release during hydrotesting is higher than an untreated water release, and (iii) the volume of water used to hydrotest long distance pipelines are too large for economical chemical treatment. It could take months before the hydrotested pipelines are put into service leading to potentially severe internal corrosion risk due to residual water and associated corrosion factors such as oxygen, salts, solids and microbes. Such risk can be reduced by conducting a batch chemical treatment with corrosion inhibitors and biocide. There are several key challenges for batch treatment of corrosion inhibitors: (i) low contact time during the batching process (e.g., 10 seconds) requiring fast acting and persistent inhibitors, (ii) vapor phase inhibition in situations when batched inhibitor does not wet the entire pipe surface, (iii) impact of brine chemistry, (iv) maintain inhibition at low concentrations for situations where batch pill is diluted as it picks up stagnant water in the pipe, (v) impact of inhibitors on refinery operations when residual inhibitor is carried with crude oil and (vi) HSE risks associated with the presence of residual inhibitor on the pipe wall and vapor spaces. This HSE risk is an especially difficult challenge to resolve. Here we report results of a laboratory study to investigate inhibitors to address these challenges. Corrosion in fluid, headspace and interface was measured by suspending coupons. Biocide compatibility was studied by ATP tests. Impact of inhibitor crude oil carryover on refinery processes was conducted with a battery of harms tests.

Newly constructed long-distance pipelines are often hydrotested with water from a natural reservoir without the use of chemical treatment. Chemicals are typically not used for various reasons: (i) the water is usually released back into the natural environment after use, (ii) the environmental impact of a chemically treated water release during hydrotesting is higher than an untreated water release, and (iii) the volume of water used to hydrotest long distance pipelines are too large for economical chemical treatment. It could take months before the hydrotested pipelines are put into service leading to potentially severe internal corrosion risk due to residual water and associated corrosion factors such as oxygen, salts, solids and microbes. Such risk can be reduced by conducting a batch chemical treatment with corrosion inhibitors and biocide. There are several key challenges for batch treatment of corrosion inhibitors: (i) low contact time during the batching process (e.g., 10 seconds) requiring fast acting and persistent inhibitors, (ii) vapor phase inhibition in situations when batched inhibitor does not wet the entire pipe surface, (iii) impact of brine chemistry, (iv) maintain inhibition at low concentrations for situations where batch pill is diluted as it picks up stagnant water in the pipe, (v) impact of inhibitors on refinery operations when residual inhibitor is carried with crude oil and (vi) HSE risks associated with the presence of residual inhibitor on the pipe wall and vapor spaces. This HSE risk is an especially difficult challenge to resolve. Here we report results of a laboratory study to investigate inhibitors to address these challenges. Corrosion in fluid, headspace and interface was measured by suspending coupons. Biocide compatibility was studied by ATP tests. Impact of inhibitor crude oil carryover on refinery processes was conducted with a battery of harms tests.

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