Pressure tests prove strength. What happens next decides corrosion: inhibitor chemistry in the water and how quickly operators drain and dry the line.
Hydrostatic testing, the standard integrity check that fills a new line with water at about 1.25× its operating pressure, is routine — and risky if mishandled (www.scribd.com). “Hydrotest” water left behind can set off corrosion in carbon steel within weeks. One test spool left with untreated seawater for 90 days lost roughly 0.01 mm (0.4 mils) of wall thickness, a uniform rate of about 1.6 mpy (mils per year), with no pitting reported (pgjonline.com).
That’s why operators dose hydrotest water with a package of oxygen scavenger, biocide, and film‑forming corrosion inhibitor during wet lay‑up (the period a system is held full of water) (www.scribd.com) (www.scribd.com). The oxygen scavenger is typically sodium or ammonium bisulfite; film inhibitors may be alkaline silicates, nitrates, or organic species. Many teams also hold the test water above about pH 9 (via soda ash), which can essentially preclude carbon‑steel attack; one operator used fresh water at pH>9 and saw no corrosion (www.scribd.com).
These are the same chemistries sold as oxygen scavengers for oil and gas service. Film‑forming options are available as corrosion inhibitor packages commonly used for temporary preservation. For accurate feed control at the ppm (parts per million) level, operators rely on dosing pumps.
Chemical inhibitor packages and target dosages
Guidelines peg a bisulfite oxygen scavenger dose around 125 ppm — roughly five times the stoichiometric amount to consume about 10 ppm dissolved oxygen — with biocide and filming inhibitor each at 100–500 ppm depending on how long the water will be held (www.scribd.com) (www.scribd.com). In practice, that chemistry drives corrosion toward near‑zero during the hold. Maintaining the test‑water pH above about 9 is cited as a simple and effective approach (www.scribd.com).
Microbiologically‑induced corrosion (MIC) is a second driver. Bacteria counts can rise from less than 100 CFU/mL (colony‑forming units per milliliter) to about 10,000 CFU/mL in 30 days of static water, a moderate increase that still accelerates attack (pgjonline.com). Omitting biocide once led an operator to abandon a pipeline due to bacterial fouling during hydrotest (www.scribd.com). It’s why owners dose an oxygen scavenger and biocide “from Day 1” (www.scribd.com). Biocidal control is available as biocide programs tailored for stagnant systems.
Vapor‑phase inhibitors can be added to purge gas as a precaution, though their benefit in liquid‑filled lines is debated (www.scribd.com). For operators looking to source complete treatment bundles, vendors supply a full range of oilfield chemicals for test, preservation, and commissioning.
Data‑backed dosages (ppm by weight)
- Oxygen scavenger (bisulfite): ~125 ppm (≈4× dissolved O₂ hold rate) (www.scribd.com).
- Biocide: 100–200 ppm for short‑term (<1 month) hold; 200–500 ppm for longer hold (www.scribd.com).
- Film inhibitor: 100 ppm (short hold) up to about 500 ppm (long hold) (www.scribd.com).
- (Optional dye) 10–50 ppm fluorescent dye for offshore leak detection (www.scribd.com).
Measured outcomes and discharge constraints
Chemical treatment materially reduces risk: wall loss under treated conditions is essentially negligible, with near‑zero corrosion rates during the hold. In one Canadian project, inhibited flush‑water was pigged (mechanical swabbing with “pigs”) out in multiple wash cycles: an initial 15 m³ rinse contained 230 ppm inhibitor, a second 15 m³ cut it to 60 ppm, and a third (~38 m³) dropped it below 10 ppm (www.researchgate.net). After dilution in the full 15,000 m³ system, residual inhibitor was about 0.05 ppm (www.researchgate.net).
Regulators often cap discharges at around 30 ppm, which can force multiple rinses as above (www.researchgate.net). One Gulf of Mexico subsea line remained flooded with untreated seawater for 90 days with only superficial rust and no pitting in that specific case — suggesting that in benign conditions inhibitors might be forgone, although operators treat that as an exception (pgjonline.com) (pgjonline.com). The industry consensus (NACE/Shell guidance) remains that “hydrotest water should always contain at least biocide and O₂ scavenger” to insure against corrosion during any extended delay (www.scribd.com) (pgjonline.com).
Hydrotest water specifications and standards
Codes also focus on water quality. NORSOK L‑004 (an offshore piping standard) calls for fresh hydrotest water with chloride below 50 ppm and pH 6.5–7.5 (pdfcoffee.com). The same standard requires the line to “be properly drained as soon as possible” after testing (pdfcoffee.com).
Dewatering, purging, and dryness targets
Once depressurized, all low‑point drains and vents should be opened and the line thoroughly drained to remove any residual or trapped liquids (pdfcoffee.com). Operators then purge with inert gas (often dry nitrogen) or hot, dry air to drive out moisture. The practical goal is zero free water.
A common field criterion is to continue purging until the outlet dew point — the temperature at which water vapor condenses — is significantly lower (for example, more than 10 °F lower) than the inlet, a conservative sign of dryness (nigen.com). In multi‑kilometer systems, this typically involves pig trains and/or vacuum or vapor‑extraction equipment (nigen.com) (nigen.com).
Why dewatering speed matters
Removing residual water strips out the electrolyte needed for corrosion to proceed. Pipeline drying specialists note that water trapped after a hydrotest leads to “rapid corrosion,” and even small puddles in low spots will severely attack exposed metal (nigen.com). Drying also prevents operational issues such as liquid slugs, freezing, and microbial growth; eliminating hydrotest water “reduces the chance of rapid corrosive damage” and avoids freeze or blockage in cold climates (nigen.com).
Integrated preservation strategy and outcomes
Best practice couples both controls: treat the water in situ and then expel it quickly. One industry handbook frames simple drying without inhibitors as “risky” for oil‑service lines (www.scribd.com). Conversely, even heavily inhibited systems must be drained and dried.
Following standards for immediate flushing and venting (pdfcoffee.com) (pdfcoffee.com) and verifying low outlet dew points (nigen.com) leaves the pipeline interior essentially dry and oxygen‑free. When the line enters service, the steel starts with a pristine surface (often with corrosion inhibitor or inert gas “packing” maintained) rather than a soaked one. Quantitatively, dry, well‑preserved lines exhibit corrosion rates close to zero, whereas any retained water can produce measurable metal loss on the order of about 1 mph or more within a year (pgjonline.com) (nigen.com).
In short, the chemical package allows “parking” a wet pipeline for weeks or months with effectively no active corrosion, lowering the risk of costly rework (pgjonline.com). Then fast, thorough dewatering and drying lock in that benefit.
