Formation of corrosion inhibitor film to protect the steel pipe wall.

Corrosion inhibitors are chemicals that can significantly reduce the corrosion of metals when applied properly into the fluids. In oil gas industry, gas system typically requires vapor phase corrosion inhibitor while liquid containing system typically requires film forming corrosion inhibitors. This article mainly covers film forming corrosion inhibitors in oil gas industry. Corrosion inhibitors used in acid stimulation are covered separately.

What are the signs of corrosion in oil gas production?

Corrosion can occur wherever there is water, metal, and a difference in electrical potential to create a cathode and an anode[1]. How do you tell you have a corrosion problem?

Reduced production

Production rates may begin to decrease, which could mean that the integrity of the tubing has been breached and a portion of the production fluid is escaping before reaching the surface.

Decreased casing pressure

There could be a decrease in casing pressure, which could mean that the casing wall has been breached and is allowing pressure to escape.

High iron counts

A water analysis could show high iron counts, which would suggest that iron in the metal surface is being corroded away. In a sour system where iron can drop out of water as scale, other metal ion counts need to be considered for signs of corrosion, e.g. mangnese, chrome, etc.

Corrosion coupons and probes

Inspection of corrosion coupons and reading of corrosion probes installed in the system can show signs of corrosion.

High debris in water

Actual parts of the tubing or other metal equipment could show up in the water as solid iron debris.

Reddish water at separator

Reddish water at the separator could be an indication of corrosion somewhere upstream.

Pigging or caliper operations show that pipe is thinning

Physical inspections using pigs or caliper runs could show that the walls of tubing or flow lines is getting thinner.

The age of the system

And finally, the age of the system could be an indicator. ALL refined metal will corrode eventually.

How does film forming corrosion inhibitor work

Film forming corrosion inhibitors work by forming a chemical barrier film between the water and the metal surface. This barrier keeps the corrosive components from interacting with each other. This protective film consists of many corrosion inhibitor molecules. Each molecule resembles a tadpole, with a “head” and a “tail”. These molecules are electrically charge: the “head” has a positive charge and the “tail” a negative charge.

The electrical polarity creates an affinity in the molecule for solids, such as the metal surfaces of tubing. As a result, the inhibitor molecules seek out the metal surface of tubing and attach themselves to form the protective film. But because fluid environments can differ greatly from well to well and field to field, each condition requires testing of different corrosion inhibitor products in order to achieve optimal performance for each application.

Corrosion inhibitor chemistries and properties

Typically, most corrosion inhibitors used in oil gas industry consist of reactive organic materials such as amines and organic acids. The specific chemical structure of their molecules will determine the properties the inhibitor have (solubility, film persistency, etc.) and its ability to control corrosion. Most film forming corrosion inhibitors contain heteroatoms in one or more head groups, which bind via long electron pairs to iron atoms on the metal surface. The head groups typically contain nitrogen, phosphorus, sulfur, and oxygen. The most common chemistry categories of film forming corrosion inhibitors are [2]:

  • Phosphate esters
  • Various nitrogenous compounds
  • Sulfur compounds often with other heteroatoms such as nitrogen

Corrosion inhibitor formulation

In pure form, corrosion inhibitors usually have a thick heavy consistency that makes them difficult to work with. To make them more manageable, they are diluted with other fluids. Depending on the chemistry of the inhibitor molecules, these other fluids can be either water-based or oil-based (hydrocarbon) substances.

Corrosion inhibitor solubility and impact on performance

The chemistry of the inhibitor also determines if it is classified as water soluble or oil soluble. Whether a product is water or oil soluble is a major factor on its effectiveness in certain situations, and in how the inhibitor is applied.

Water soluble

Water soluble inhibitors will dissolve completely in the water phase of the fluid stream. They remain in solution until reaching the tubing wall. At that point, they attach themselves to the surface and form the protective barrier between the water and the metal.

Because these products are water soluble, they will not completely dissolve in oil and they are not as durable as their oil-based counterparts and are easily stripped off the tubing by moving fluids.

Oil soluble

Oil-soluble, non-water dispersible inhibitors dissolve in the oil phase of the production stream. When one of these products is mixed with water it will separate immediately.

Oil-soluble, water-dispersible inhibitors dissolve into oil but also will stay suspended in water temporarily. How long it will stay dispersed in water determines the product’s dispersibility.

Generally, it’s more difficult to disperse an oil soluble corrosion inhibitor in heavy brines than in fresh water.

Oil-soluble products tend to be more “sticky” than water-base products. This allows them to better adhere to the tubing wall.

How are corrosion inhibitors tested in the lab?

The objective of a corrosion test is to evaluate the effectiveness of a corrosion inhibitor by measuring weight loss and surface change over time or measuring current flow and interpreting that as a corrosion current. Pitting corrosion can be observed using optical microscope or scanning electron microscope. The list of methods for corrosion inhibitor testing include:

  • Bubble or kettle test
  • Rotating cylinder electrode (RCE) test
  • Rotating disc electrode (RDE) test
  • Rotating cage autoclave (RCA) test
  • Jet impingement test
  • Flow loop test
  • Wheel test
  • Static test

How are corrosion inhibitors applied?

How corrosion inhibitors are applied depends largely on the chemistry of the product. For example, heavy, oil-soluble “filmers” are typically applied as batch treatments because they are very tenacious and stick well to the pipe. Therefore, they can be applied to the system and will provide a protective barrier between the water and the metal for a long period of time.

Water-soluble inhibitors, on the other hand, are less tenacious and will not form long-lasting films. Therefore, they must be continuously applied (injected) in order to be effective.

Batch application techniques for corrosion inhibitors include:

  • Batch and fall
  • Tubing displacement
  • Between pigs (for pipelines and some flowlines)

Inhibitor can be “manually applied” as well with a tool called the Tubingsaver®, which acts as a “paintbrush” of sorts to physically apply the chemical to the pipe.

Continuous Injection techniques include:

  • Injection down the backside (in the annulus) through cap string
  • Injection down the tubing through cap string
  • Injection into flowlines

How can I tell if the corrosion inhibitor treatment is working?

There are number of corrosion monitoring tools available to help assess the technical performance of the program. They include:


Coupons are small rods or strips of the same metal used in the tubing. When placed in the flowline (usually topside), they allow you to monitor how well the corrosion inhibitor is working without actually pulling the tubing to inspect it.


Instrumentation, such as Electrical Resistance (ER) probes, measure corrosion rates by the increase in resistance to current flow (as a wire or strip loses cross-sectional area, the resistance to current flow increases.) This process does not involve actual destruction of metal as is the case with coupons.

Test Subs

Test subs are short joints of tubing (5-6 feet vs. 30 feet) made from the same material as the regular tubing used in the well. They can be retrieved when tubing is pulled and easily inspected, weighed for weight loss, etc. Test subs are a way to monitor actual corrosion effects on the tubing material in the same conditions that the tubing inhabits while in the well.

Iron/Manganese Counts

Iron and/or manganese counts are good for identifying trends. Iron counts can be deceptive if pitting corrosion is taking place because they do not account for whether the metal loss is spread across the entire length of tubing or if it’s concentrated in one specific point.

Caliper Surveys

Caliper are instruments inserted into the tubing to probe the inner walls and make a true measurement of metal loss downhole.


Inspections of the inner pipe surface conditions can be conducted by smart pigging runs or external inspection technologies, such as X-ray, ultrasound, etc.

Failure Rates

Although the damage is done when tubing has failed, actual failure rates due to corrosion remain the only true measure of the how the corrosion treatment program is working.

Lessons learned

  • Scale inhibitors can severely negatively impact the performance of corrosion inhibitors.
  • Produced water with high calcium can be difficult to treat with corrosion inhibitors.
  • Applying the correct inhibitor dosage is very important because under dosing can cause severe pitting.
  • Corrosion inhibitor can potentially cause topsides water treating problems.


  1. Byers, Harry G., Corrosion Control In Petroleum Production (Second Edition.), NACE International, Houston, Texas, 1999.
  2. Production Chemicals for the Oil and Gas Industry, Malcolm A. Kelland