Hilliard, Harold M., Petrolite Corp. Petrolite Corp. Copyright 1980, American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Petroleum Engineers, Inc. This paper was presented at the SPE Cotton Valley Symposium, held in Tyler, Texas, May 21, 1980. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, Texas 75206.


Corrosion in gas-condensate wells producing from the Cotton Valley Formation has been relatively low in spite of the presence of factors favoring a significant corrosion rate. Producers should be aware of the potential for severe corrosion if the fortuitous natural potential for severe corrosion if the fortuitous natural protection encountered should break down. protection encountered should break down


If corrosion control problems for a gas condensate well or field could be accurately predicted, adequate, but not excessive, provisions could be made starting from selection of tubular goods. This concept, in a limited form, is extremely necessary for sour gas wells where use of low hardness steels is mandatory and in very deep, hot gas wells where problems of corrosion inhibitor transport and possible need for a continuously applied inhibitor must be considered.

Early efforts to define the factors involved in corrosion of gas condensate wells provided guidelines based on the more shallow, lower pressure wells which were being produced in the 1940's and 1950's. Experience at that time showed corrosion to be likely "from a formation more than 5,000 feet in depth at a reservoir temperature above 160 deg. F, and above 1,500 psi". A more recent and still frequently quoted rule of psi". A more recent and still frequently quoted rule of thumb states that corrosion would not be severe if the partial pressure of CO2 were less than 48 kPa, would always be severe if it were greater than 210 kPa, and values between 48 and 210 kPa gave uncertain results. Unfortunately, research since that time has shown that these guidelines are oversimplified and the effects of gas composition and pressure, temperature, gas velocity and composition of produced water on corrosion in sweet wells cannot be stated as straight line relationships.

Similarly, as techniques to control corrosion have become more sophisticated, guidelines used in the past have become more suspect. Inorganic corrosion past have become more suspect. Inorganic corrosion inhibitors, such as chromates, used in the past for downhole corrosion control have been completely replaced by more effective organic inhibitors that give better corrosion control while minimizing problems resulting from inhibitor treatment. On the problems resulting from inhibitor treatment. On the other hand, improved understanding of the principles of inhibitor transport in the wells has not been universally recognized and low volume batch treatments are frequently used. That such treatments are often successful in routine gas wells is usually a result of good fortune and coincidence instead of successful recognition of the factors involved and limitations inherent in such treatments. While production from the Cotton Valley Formation does not present the extreme conditions encountered in some gas fields, it is still useful to consider the extend of our knowledge about corrosion anticipated in Cotton Valley production both now and as the field matures. production both now and as the field matures. Factors Affecting Corrosion in Sweet Gas Production:

Corrosion in sweet gas wells is usually less than would be anticipated from laboratory studies at 25 deg. C and pressures up to 250 kPa CO2 partial pressure. In addition, corrosion often is pressure. In addition, corrosion often is concentrated at the top of the tubing string although most reactions (including corrosion) should take place faster at the bottom of the well which is hotter and has a higher partial pressure of corrodent (CO2). This behavior has usually been attributed to the lack of liquid water at bottomhole. There appear to be other factors involved also.

The following paragraphs review our knowledge (or lack of it) about corrosion in sweet gas systems as a function of temperature, gas composition (mainly CO2 and H2S content), pressure, produced water volume and chemistry, velocity of produced gas and liquid (and sand, if any) and liquid hydrocarbon volume.


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