Sour Corrosion

A large percentage of the wells in this country are producing hydrogen sulfide and many are corrosive. In the absence of protective measures, hydrogen sulfide corrosion in these corrosive sour wells costs hundreds of dollars per well per month for equipment failure. This figure varies, of course, depending upon individual well conditions. There are records of this type of corrosion costing in the thousand dollar range per well per month. From these figures it can be readily seen that the cost of replacing equipment alone could be well into the millions of dollars per year for the industry.

Sulfide corrosion generally starts slowly and the rate increases with time. Chemical inhibition, coatings, and, in some cases, special alloys have been used to successfully combat this attack. The favorable economics of corrosion mitigation have been proven by most operators, and corrosion-control methods are standard practice in field operations.

DESCRIPTION OF DAMAGE Chemistry of Reaction

Although hydrogen sulfide is noncorrosive in the absence of moisture, if moisture is present the gas becomes corrosive. It becomes very severely corrosive where even a trace level of oxygen (02) is present, and also may be influenced by a significant presence of carbon dioxide (C02). The general mechanism of this type of corrosion can be simply though not completely stated chemically as follows:

Hydrogen Iron Water Iron Hydrogen sulfide sulfide

Though iron is used in this example, other metals react in essentially the same manner to produce metallic sulfides. The iron sulfide produced by this reaction generally adheres to the steel surfaces as a black powder or scale. The scale tends to cause a local acceleration of corrosion because the iron sulfide is cathodic to the steel. This reaction results in deep pitting noted on equipment as shown in Fig. 47.

Another reaction occurs with hydrogen sulfide corrosion. The hydrogen released in the foregoing reaction enters into the steel where it is absorbed into the steel and embrittles it. It may also form molecular hydrogen which leads to blisters and cracks (Fig. 48 and 49).

As seen in the foregoing equation for the corrosion reaction, neither oxygen nor carbon dioxide is required to produce sulfide corrosion. Their


24 Corrosion of Oil- and Gas-well Equipment

24 Corrosion of Oil- and Gas-well Equipment

H2s Corrosion Pits
Fig. 49 — Cracks Due to H2S Originate in Tiny Pits pig. 48 — Blistering Due to H2S

presence, however, greatly accelerates the severity of sour corrosion. In fact, one of these is always present where hydrogen sulfide corrosion is a severe problem.

It has been shown by various investigators that micro-organisms can greatly affect corrosion rates. In order for micro-organisms to accelerate corrosion, the environment must be suitable for their growth and multiplication. Moisture, essential minerals, organic matter, an energy source, and a suitable pH must be provided. In many cases, when steel structures are in contact with the earth or water, all the necessary requirements are met. It is, therefore, not surprising that microbiological corrosion is quite common.

Micro-organisms such as the Desulfovibrio (sulfate reducers) can cause sulfide corrosion in the absence of atmospheric oxygen (anaerobic conditions). These organisms utilize hydrogen formed by electrochemical corrosion during their growth and reduce sulfate (S04) to H2S. Both hydrogen utilization and H2S formation cause increased corrosion rates.

Oil-well Tubing

In oil-well tubing water droplets break out of the oil and wet the surface of the tubing. The hydrogen sulfide dissolves in these droplets and causes the development of pits. On surfaces such as the inside of tubing and rods, where the flow of fluid gives erosion effects, the pits are generally smooth and appear as depressions (Fig. 50). Another major cause of tubing corrosion is corrosion-erosion or what is commonly called "box wear" or "rod wear" (Fig. 51).

Annular-space Corrosion

On the exterior of tubing or the interior of casing above the annular-fluid level where no erosion effects are in operation, the pits may have sharp edges and be cavernous (Fig. 52).


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  1. Sour Corrosion
  2. 51 (right) — Corrosion Wear of Tubing in a Sour Pumping Well
  3. 50 (left) — Sour Oil-well Tubing Corrosion
  4. 51 (right) — Corrosion Wear of Tubing in a Sour Pumping Well
  5. 52 (above) — Cavernous-type Pitting in Annular Space — Exterior Tubing
  6. 52 (above) — Cavernous-type Pitting in Annular Space — Exterior Tubing
  7. 50 (left) — Sour Oil-well Tubing Corrosion


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  • tesfalem
    What causes pitting on gas well tubing?
    6 years ago

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