The specific crude oil produced from a field has a major effect on the corrosion of steel in the crude oil/brine environment. The addition of crude oil to a brine lowers the measured corrosion rate of steel exposed to the mixture, but different crude oils have significantly different effects on steel corrosion, with identical brine compositions. The primary effect of the crude oil on steel corrosion in crude oil brine mixtures is apparently on the protectiveness of the corrosion product layer formed on the steel. Consequently, corrosion tests conducted on steel in brine without the crude oil present do not give a true picture of the behavior of steel in the production environment. This leads to gross errors when using the test results to estimate the potential corrosion problems, and effects of corrosion inhibitor treatments, in a crude oil production system. (1, 2)

Efird Corrosion International employs a defined procedure to accurately predict the produced water level in crude oil production where accelerated corrosion of steel occurs (defined as the Corrosion Rate Break produced water level). The methodology is also used to evaluate the requirement for corrosion inhibitor treatment. The primary focus is preventive corrosion engineering in material selection and chemical treatment initiation to minimize the cost of corrosion control while maximizing its effectiveness. The technique is particularly useful in making recommendations for new crude oil discoveries where no explicit corrosion data exist. The major ramifications are:

• Different crude oils have significantly different effects on corrosion.



• Corrosion tests simulating crude oil production systems must include the specific produced crude oil to yield valid results.



• The produced water level where accelerated corrosion of steel corrosion occurs (Corrosion Rate Break) is identifiable to a high degree of accuracy.



• Capital expense is minimized by knowing the degree and timing of corrosion in the system. Operating expense is minimized by delaying the start of chemical treatment until it is actually necessary.



• Downhole equipment and tubular failure and replacement expense is minimized by preventing corrosion damage before it occurs.

The Crude Oil Effect
Water related factors identified as controlling the corrosion of steel in production environments include pH, temperature, velocity, chloride, bicarbonate, organic acids, and acid gas partial pressure. These factors do not account for the effect of the crude oil on the corrosion process. The varying effects of specific crude oils on the corrosion rate of steel in crude oil/brine mixtures, with identical brine composition, is shown in Figure 1 for brine contents of 0% to 40%. The effect of each of the crude oils on corrosion rate at a constant brine content of 5% is shown in Figure 2.

Figure 1. The 24 hour corrosion rate of API N-80 steel in crude oil/brine mixtures for different crude oils with brine contents from 0% to 40% at 5.2 MPa CO2 pressure and 85oC (Brine = 4% NaCl solution in distilled water).
Figure 2. The 24 hour corrosion rate of API N-80 steel in crude oil/5% brine mixtures for different crude oils at 5.2 MPa CO2 pressure and 85oC (Brine = 4% NaCl solution in distilled water).

It is evident from the data that crude oil has a significant effect of the corrosion of steel in crude oil/brine mixtures, and these effects are different for different crude oils. The corrosion rate differences vary over several orders of magnitude. The differences are real and they are significant in making materials and treatment decisions.

Corrosion Rate Break Determination
This test protocol is used to evaluate the corrosion of steel in crude oil production environments under field conditions, and to determine the produced water level at which accelerated corrosion begins (Corrosion Rate Break). A range of produced water levels in crude oil are tested to define the produced water level where corrosion rapidly accelerates, defined as the Corrosion Rate Break produced water level. These tests are also employed to evaluate the effectiveness of corrosion inhibitors above the Corrosion Rate Break produced water level.

The test environment consists of the produced crude oil, simulated produced water, and a gas phase. The test environment data should include the specific crude oil(s), the produced water composition, the downhole and wellhead temperatures and pressures, and the acid gas partial pressures or mole fraction for carbon dioxide and hydrogen sulfide.

All crude oil used for the test program is carefully handled to prevent the possibility of oxygen contamination. These precautions are necessary to prevent weathering of the crude oil (oxidation of some crude oil components), which can significantly altar its corrosive effects. The crude oil samples are collected in a manner to prevent contact with air, and shipped under an inert gas blanket in containers constructed of corrosion resistant material, or in containers lined with an inert material. The general test cell arrangement used and its internal equipment are shown in Figure 3.

Figure 3. A diagram of the apparatus typically used to conduct the crude oil corrosion experiments.

A sequence of corrosion tests are run starting at 0% produced water, with produced water increased in specified increments until the measured corrosion rate plotted with respect to water level shows a substantial increase. This is the Corrosion Rate Break produced water level.

A following test sequence is conducted to more closely define the Corrosion Rate Break produced water level. A test is run at the incremental produced water level immediately before the corrosion rate increase to confirm the previously measured corrosion rate. Corrosion tests are then conducted at produced water levels in specified increments between the two larger increments.

The corrosion rate/produced water content curves for different crude oils commonly fall into one of three general types as shown in Figure 4.

Figure 4. The change in corrosion rate of steel in crude oil/produced water mixtures with increasing produced water content showing the three general types of behavior observed.

The Type 1 crude oil (C03) exhibits a rapid increase in corrosion rate over a very narrow range of produced water levels, usually occurring at a produced water level below 20%. This is the most dangerous type of behavior from the corrosion standpoint, because the increase in corrosion rate is very rapid and the precise produced water level where this rapid increase occurs is highly crude oil dependent.

The Type 2 crude oil (CL1) shows a gradual increase in corrosion rate followed by an accelerating rate of increase at relatively high produced water levels. This type is the most difficult for application of the technique because it lacks a single well defined break in the curve to excessively high corrosion rates.

The Type 3 crude oil (SJC) shows only a moderate gradual increase in corrosion rate for the entire range of produced water levels tested. This behavior is typically observed for heavy, asphaltinic or waxy crude oils, and high corrosion rates are only observed at very high produced water contents.

Corrosion Rate Break Examples
Crude Oil C48 Corrosion Rate Break
Electrochemical linear polarization corrosion tests were conducted for 0.2% (in "as received" crude oil) to 90% produced water in crude oil. A plot of the measured corrosion rate variation with the produced water content is given in Figure 5. The Corrosion Rate Break occurs at approximately 7% produced water. Corrosion inhibitors were evaluated at a 15% produced water level.

The recommendation was made to field operations to begin corrosion inhibitor injection when the produced water level reached 5%. To date the produced water level for this well has not exceeded 3% and no excessive corrosion has been encountered.

Figure 5. The change in corrosion rate of steel in crude oil C48/produced water mixtures with increasing produced water content showing a Corrosion Rate Break at approximately 7% produced water.

Crude Oil PD3 Corrosion Rate Break
Weight loss corrosion tests were conducted for 0.1% (in "as received" crude oil) to 10% produced water in crude oil. A plot of the measured corrosion rate variation with the produced water content is given in Figure 6. The Corrosion Rate Break occurs at a very low 2% produced water content. The production from this well is extremely corrosive. Corrosion inhibitors were evaluated at a 10% produced water level.

The recommendation was made to field operations to begin corrosion inhibitor injection when the produced water level reached 1%. The occurrence of accelerated corrosion at this very low produced water level was subsequently confirmed, but corrosion inhibitor treatment had been initiated before any corrosion damage could occur.

Figure 6. The change in corrosion rate of steel in crude oil PD3/produced water mixtures with increasing produced water content showing a Corrosion Rate Break at approximately 2% produced water.

Crude Oil CL1 Corrosion Rate Break
Electrochemical linear polarization corrosion tests were conducted for 5% to 90% produced water in crude oil. The plot of the measured corrosion rate variation with the produced water content is given in Figure 7. The Corrosion Rate Break produced water level is 30 to 40% produced water for this crude oil. The interpretation of this curve for the Corrosion Rate Break is much more subjective than for the previous examples.

The determination was made that the corrosion monitoring would provide adequate warning of accelerated steel corrosion for this crude oil so no refinement in the Corrosion Rate Break produced water level was attempted. A significant increase in the corrosion rate was detected by the on-stream corrosion monitoring when the produced water level exceeded 30%. Corrosion inhibitor injection was started and the corrosion is under control.

Figure 7. The change in corrosion rate of steel in crude oil CL1/produced water mixtures with increasing produced water content showing a Corrosion Rate Break at 20% to 30% produced water.

Summary

1. Crude oil has a significant effect of the corrosion of steel in crude oil/brine mixtures, and these effects are significantly different for different crude oils.



2. The differences in the observed steel corrosion behavior for different crude oils are in the degree of corrosion product protectiveness, and not in the rate of formation of the corrosion product.



3. Corrosion tests conducted on steel in brine environments without the crude oil present do not give a true picture of the behavior of steel in the crude oil/brine production environment. This can lead to gross errors when using the test results to estimate the potential corrosion problems, and effects of corrosion inhibitor treatments, in a crude oil production system.



4. The produced water level where accelerated corrosion of steel corrosion in crude oil production will occur can be identified with a high degree of accuracy and confidence. This can minimize operating expense by delaying the start of chemical treatment until it is actually necessary.



5. The expense of failure and replacement of downhole equipment and tubulars is minimized by identifying the produced water level where accelerated corrosion of steel will begin before it actually occurs in the operating system.

References

1. K. D. Efird and R. J. Jasinski, "The Effect of the Crude Oil on the Corrosion of Steel in Crude Oil/Brine Production," Corrosion, Vol. 45, No. 2, February 1989.



2. K. D. Efird, "Predicting the Corrosion of Steel in Crude Oil Production for Preventive Corrosion Engineering," Materials Performance, Vol. 30, No. 3, March 1991, pp. 63-66.



3. K. D. Efird, "Preventive Corrosion Engineering in Crude Oil Production," 23rd Annual Offshore Technology Conference, Houston, Texas, May 6-9, 1991, Paper OTC 6599.



4. K. D. Efird, Chapter 36 "Petroleum," Corrosion Tests and Standards: Application and Interpretation, Robert Baboian Editor, ASTM Manual Series: MLN 20, ASM, Philadelphia, PA, 1995.

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