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System Description

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Steel Evaluation

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Features and Benefits

Appendix-I

Appendix-II

Appendix-III

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Socrates assists you in determining the viability of carbon steels versus CRAs through a rigorous evaluation of general corrosion susceptibility of steels with or without inhibition in the operating environment. The system determines a steel corrosion severity index, a measure of the overall corrosive severity of the environment.

In material selection it should be realized that conventional steels can be significantly more economical than CRAs in low severity environments or in greater severity environments when used with proper chemical inhibition. Therefore, before considering CRAs, it is important to first evaluate whether steels can be used in oilfield environments without being susceptible to sulfide stress cracking.

Socrates uses a large number of parameters to determine the steel corrosion severity index. The system uses the de Waard - Milliams' CO2-based corrosion prediction model to obtain an initial assessment of corrosion severity in carbon steels. The system generates a number that is directly proportional to corrosion rate of steel in mpy using the de Waard-Milliams model. This number is modified to account for the effects of other factors such as temperature, H2S, chlorides, velocity and inhibition. Relevant parameters in steel evaluation include,

Hydrogen Sulfide (H2S)

Corrosion generally increases with H2S partial pressure. H2S is an acid gas and the term acid refers to its ability to depress pH when it is dissolved in an aqueous solution. This increased aggressivity results from the decrease in the pH of the aqueous phase as the partial pressure of H2S increases. An added effect of H2S in CO2/brine systems is a reduction in corrosion rate of steel when compared to corrosion rates under conditions without H2S. This reduction in corrosion rate is primarily a low temperature effect and predominates system corrosivity at temperatures less than 175 F (80 C) due to the formation of a meta-stable iron sulfide film. At higher temperatures the combination of H2S and chlorides will usually produce higher corrosion rates than just CO2/brine systems, since stable iron carbonate films usually do not occur as readily in systems with H2S as they do in systems without H2S.

Carbon Dioxide

Corrosion severity generally increases with CO2 partial pressure. CO2 is an acid gas and the term acid refers to its ability to depress pH when it is dissolved in an aqueous solution. This increased aggressivity results from the decrease in the pH of the aqueous phase as the partial pressure of CO2 increases.

Chlorides

Under normal circumstances, the chloride content of the aqueous phase does not directly affect the hydrogen charging conditions in steel. However, it can have an effect on the effectiveness of chemical corrosion inhibitors. Therefore, in many cases, more careful selection of inhibitors and inhibition procedures must be performed where high levels of chlorides (>30,000 ppm) are present.

In naturally deaerated production environments, corrosion rate increases with increasing chloride ion content over the range 10,000 ppm to 100,000 ppm. The magnitude of this effect increases with increasing temperature over 150 F (60 C). This combined effect results from the fact that chloride ions in solution can be incorporated into and penetrate surface corrosion films which can lead to destabilization of the corrosion film and increased corrosion. This phenomenon of penetration of surface corrosion films increases in occurrence with both chloride ion concentration and temperature. Corrosion rates of steel in oil and gas production generally increase with increasing chloride content. The chloride species in the aqueous phase can work to penetrate and destabilize protective surface films. Typically, brines with low chloride content (i.e. <10,000 ppm) less aggressive than those having higher chloride contents provided that they are compared at the same pH. In some cases, the presence of salts can reduce the solubility of acid gases or buffer the water therefore affecting the solution pH.

Bicarbonates

The bicarbonate ion is a buffering agent used in aqueous solutions to increase the pH of the solution. Its presence is typically measured in milli-equivalents/liter (meq/l). One meq/l represents 0.061 grams of HCO3 in one liter of solution. The reduction in pH in turn decreases the corrosivity of the environment. Hence, presence of HCO3 is beneficial from the standpoint of corrosion. Typical quantities of HCO3 in production environments range from 1 meq/l to 100 meq/l.

Maximum Operating Temperature

Temperature affects the corrosion rate of steels in several ways which must be taken into account for estimation of corrosion severity:
Increasing aggressivity of chloride corrosion reactions with thermal activation.
Decreasing solubility of dissolved gases with increasing temperature which increases pH.
Formation of a protective carbonate scale in aqueous CO2 environments at elevated temperature.
Reduction in CO2 corrosion rate with addition of H2S.

Type of Flow

The flow conditions (i.e. static, stratified, turbulent, etc.) are dependent on the nature of the produced gases and fluids and if the flow is primarily horizontal (surface production) or vertical (subsurface production). Horizontal flow is usually more prone to static and stratified conditions which limits the amount of mixing of oil and water phases at low flow rates. Vertical flow typically exhibits these types of conditions only during period of shut-in of the well. See Superficial Gas Velocity for more information.

Method of Inhibition

For horizontal flow systems the following types of inhibition method are commonly used:

Continuous Inhibition - Inhibitor is continuously injected into the flow stream. This may be conducted in both downhole and surface production systems. It is preferred where the flow velocity is greater than 10 ft/sec (3 meter/sec) or where the amount of water is high.

Batch Inhibition - Inhibitor is added in the flow system periodically in batch treatments usually between two pigs. A strongly persistent filming inhibitor is usually used which can reduced corrosion rates effectively during the period between batch treatments. This technique is usually effective where the chloride concentration is high but the velocity is low. It is commonly used to supplement other inhibition techniques.

Pigging - Pigging is the use of flowline pigs to assist in (a) application of batch inhibitors and (b) removal of accumulated water, solids and other deposit in the flow system. In many applications, pigging is required to get proper distribution of inhibition chemicals through the flow system. In cases where flow velocity is low, pigging is used to remove water and deposits from the bottom of the pipe which can promote corrosion at this location.

For vertical flow systems the following types of inhibition method are commonly used:

Batch Inhibition - Inhibitor is added in the flow system periodically in batch treatments and usually added to the tubing bore in a process where the fluids in the well bore are displaced with the inhibitor and its carrier. A strongly persistent filming inhibitor is usually used which can reduce corrosion rates effectively during the period between batch treatments. This technique is usually effective where the chloride concentration is high but the velocity is low. However, conditions of high temperature (>250 F; 120 C) and high flow rate generally limit the use of this technique.

Squeeze Treatment - Squeeze treatments are a modification of batch inhibition used for controlling downhole corrosion. Instead of just displacing the tubing with inhibitor and its carrier fluid, the squeeze treatments also forces the fluid under pressure into the surrounding formation. This has the benefit of extending the duration between batch treatments in some wells. However, in other cases, squeeze treatments can also interfere with the well's production by plugging the formation.

Continuous Inhibition - Inhibitor is continuously injected into the tubing at bottom of the string or through a subsurface injection valve. The rate of injection is regulated to provide the inhibitor at a required concentration to mitigate corrosion. While more costly and requiring more equipment than batch inhibition, continuous inhibition has been shown to be more effective particularly in deeper high temperature wells and at more severely corrosive conditions. At high flow rates, continuous inhibitor injection may become costly and possibly ineffective.