OIL FIELD CORROSION-2 FIELD MEASUREMENTS INVOLVE VARIOUS TECHNIQUES

Douglas P. Moore
Harry G. Byars
ARCO Oil & Gas
Plano, Tex.

A number of field techniques are available to determine the extent of corrosion on production equipment.

This second article in a three-part series on oil field corrosion explains the use of corrosion coupons, several types of probes, and various inspection techniques, and shows how to monitor iron content in the water.

CORROSION COUPONS

Monitoring corrosion with coupons is the most common technique used. A corrosion coupon is a small, specially prepared piece of metal which is placed in a system and allowed to corrode.

Coupons are carefully cleaned and weighed before and after exposure. Visual examination reveals characteristics of the corrosion attack. Pitting rates are measured, and general corrosion rates are calculated from weight-loss data.3

Besides environment, there are other factors that affect coupon results. They are:

Coupon material
Coupon preparation and cleaning procedure
Coupon location and orientation
Time of exposure.

The coupon material should have corroding characteristics similar to the material in the system. Surface preparation and cleaning procedures should be consistent and documented. Standard procedures are available in the literature.3 25 26

Short exposure times yield quick results, but can be misleading. In some cases initial rates may be high, but they decrease with time. On the other hand, pitting corrosion can take time to develop. Coupons should be exposed for at least one month unless high uncontrolled corrosion rates are expected.

Corrosion coupons are often positioned at several locations throughout a system. As pointed out earlier, corrosion is usually not uniform across a system because of changes in temperature, pressure, flow rates, etc. Coupons are an excellent way to assess these changes. Comparing coupon data can give magnitude and location of potential problems.

The orientation of the coupon with respect to flow must also be considered. Coupons should be positioned to contact the electrolyte as uniformly as possible. In cases of stratified flow, locate the coupon on the bottom side of the pipe, or in vertical runs, allow contact with the water phase.

When using flat coupons, orient them so flow impinges on the coupon edge. This will expose the coupon surface more uniformly by minimizing shielding. Examples of coupon fittings and orientation are shown in Fig. 1.

Handling of coupons during installation and retrieval will affect corrosion rates. A drop of sweat or sweaty hand prints can increase the rate of corrosion at the point of contact. A greasy thumb print can provide some protection to an area of the coupon. Disposable gloves are useful in avoiding contamination during handling.

Storing coupons in inhibited envelopes will prevent corrosion before installation and after exposure. Good handling practices are critical for consistent results.

After cleaning, coupons are weighed to determine loss due to exposure. This weight loss is used to calculate a general corrosion rate, commonly reported in mils/year (mpy). This rate assumes that corrosion occurs uniformly.

To put this in perspective, coupons should be examined to characterize the corrosion attack. Standard terms can be used to describe and qualify the attack .3 Defining the terms with photographs will give consistency.

When pitting corrosion is present, measure pit depths and report a pitting rate equivalent in mpy. This rate will be higher and usually more indicative of actual corrosion rates. This is particularly true in the oil field because pitting is the prominent attack form.

Analyzing and reporting coupon results can be greatly enhanced by establishing a computer system.4 This computer data base stores all pertinent data concerning the coupon exposure. Fig. 2 shows a plot of coupon data for a gas well. Here the rates show a decrease at the start of a chemical treating program.

Coupon results present a corrosion rate of the coupon itself. Whether this rate is equal to system parts depends on conditions. In any event, coupon data will provide relative information on changes in a system with respect to time and location. The quality of this relative data is dependent on the consistency of the four factors listed previously.

To compare data from exposure to exposure and location to location, coupons must be from the same supplier. The supplier must use consistent coupon materials, preparation techniques, and cleaning procedures.

Coupons do not give immediate data. The analysis can produce a time lag. However, coupons do provide information on the type of corrosion attack. They are easy to use, inexpensive, and applicable to any system.

IRON CONTENT

For steel materials, corrosion is simply iron dissolving into the water phase. Therefore, we can get a relative indication of corrosion activity by monitoring the iron content of the water (often referred to as iron count).

There are two critical issues in sampling water for iron count. First, the location must represent the system. If the concern is downhole corrosion, samples must be collected as close to the wellhead as possible to reflect activity downhole. This is shown in Fig. 3.

Second, the sample must be clean. Avoid corrosion products and other solids in the sample.

An example of a water-sampling device for a gas well is shown in Fig. 4a. The connection to the system is made on the bottom side of a flow stream. Water will collect and displace liquid hydrocarbons even at low water production rates.

The 1-in. ball valve allows easy removal of the sample cylinder. A small sampling valve is positioned horizontally at the top of the cylinder to allow pressure release. Its horizonal orientation will prevent solids plugging. An additional sampling valve is located at the cylinder base. Stainless steel components are used to avoid contamination.

An iron analysis of the sample can be performed onsite using a colorimetries test kit, as described in Part 1 of this series (OGJ, July 9, pp. 97). The test must be performed at once because the iron will oxidize and fall out of solution in a short time.

Preserving the sample with 1 ml 15% HCI/200 ml of water will hold the iron in solution for months. The preserved sample can be tested by colorimetries or sent to a laboratory for analysis.

For oil wells, iron in the oil also must be measured. This must be done in the laboratory.

The iron data generated must be related to fluid production to obtain consistent information. A constant iron content in declining fluid production correlates to an increasing corrosion rate, not a constant one. Iron content must be converted to iron production. The following equation can be used to obtain the pounds of iron lost per day:

(ppm iron) x (b/d of water) x (0.000335) = (lb/day iron)

An example plot of iron production data is shown in Fig. 5. In this case, iron production monitoring showed the benefit of one chemical treatment method over another. Iron readings moved downward and stabilized somewhat after low-volume batch inhibitor treatments began.

Iron counts are an inexpensive, easy way to monitor corrosion activity. It does not provide actual corrosion rates, but does provide relative information. There is no time lag in obtaining data; however, comparisons of recorded readings are needed to see results.

Iron counts may not yield meaningful results in sour systems. The reactivity of H2S and iron can produce sporadic data depending on the equilibrium of iron sulfide. Naturally occurring iron in the producing formation can also affect results, depending on amount and solubility.

Also, iron counts are difficult to correlate at high water rates. Large changes in the corrosion rate produce small changes in iron that make trends difficult to see.

PROBES

Four types of probes can be used to monitor corrosion.

ELECTRIC RESISTANCE

The electrical resistance (E/R) probe is an instrumented coupon designed to measure the change in electrical resistance as it corrodes. Because resistance increases with decreasing mass, the rate of change can be correlated to a corrosion rate .272829 A diagram of an E/R probe is shown in Fig. 4b. An example plot of E/R probe data is given in Fig. 6. Note that the slope determines the corrosion rate.

Because E/R probes are measured on-site, they can provide information faster than conventional coupons. Frequent measurements can pinpoint rapid changes. As with conventional coupons, probe handling and location are very important.

E/R probes can be applied to any system and lend themselves to automated monitoring.4 30 31 They can be installed to send data directly to a computer from a remote location.

The computer can read the probes as frequently as necessary and directly calculate a corrosion rate.

LINEAR POLARIZATION

Linear polarization rate (LPR) techniques measure the current necessary for slight polarization of a test probe. This current is correlated to an instantaneous corrosion rate of the probe.32 33 The probes are available in several different sizes and configurations.27 34 Fig. 4c shows a diagram of one type.

The strong advantage of the LPR probe is in providing real-time corrosion rates. The probe can detect changes in a system immediately and is particularly useful in comparing corrosion inhibitor effectiveness.

Because the probe uses potential measurements, the LPR must be in a continuous electrolyte to work. This makes it ideal in water or high water production, but not applicable to most three-phase systems.

The probe is relatively easy to use, but data must be interpreted by experienced personnel. The probe must be installed and allowed to equilibrate before readings are meaningful. Presence of conductive scales, such as some forms of iron sulfide, can mask response of the LPR probe.

Above all, remember the corrosion rate given is that of the probe, not of the pipe wall. Use the generated data in a relative sense. Even though readings are instantaneous, single readings are meaningless. Gathering data trends over time is necessary to get results.

POTENTIODYNAMIC POLARIZATION

The potentiodynamic polarization instrument is a device for varying the potential of an electrode continuously at a preset rate. A plot is made of potential vs. log of the current density required.

Information such as corrosion rate, pitting tendency, and passive behavior can be derived from these curves.33 35 An example of a polarization curve is shown in Fig. 7.

The use of potentiodynamic testing in the field has been limited to short-term evaluations. It is not a routine monitoring method. However, these probes are used extensively in the laboratory to test corrosion inhibitors.

The instrument also has been used to study the passive/active behavior of high alloy materials. The main use of potentiodynamic testing in the field has been limited to inhibitor evaluations.35 36

Potentiodynamic polarization probes, as with the LPR, provide a real-time corrosion rate. However, in this case, the full Tafel slope is developed resulting in a more accurate rate. In addition, reverse scans can be used to predict pitting tendencies.35 In field studies, it is not uncommon to use both methods since the electrode probe is the same.

Like the LPR, a continuous electrolyte is needed to conduct potentiodynamic scans. Readings are valid for the probe electrode, not the pipe wall. Relative data carry more importance. In addition, the procedure is more complicated than the LPR and the results require more interpretation. The operator must be experienced in these techniques to get useful data.

HYDROGEN

Hydrogen probes measure corrosion activity by capturing hydrogen generated from the corrosion reaction. There are two basic types of hydrogen probes used in the oil field: the pressure hydrogen probe (PHP) and the electro-chemical hydrogen probe (EHP).37

Nascent hydrogen (H0) forms at the cathode sites wherever corrosion is taking place. Because it is the smallest atom, HO has the ability to migrate through steel.38

The PHP provides a cavity to trap the migrating H0 as the atoms pass through the steel and into the cavity where H0 combines to form hydrogen gas (H2).

Because hydrogen gas is not mobile, the pressure of the cavity increases.

Changes in the cavity pressure are correlated to corrosion activity. The size of the cavity is restricted to improve response. Fig. 4d shows a diagram of a finger, or intrusive-type probe.

The EHP operates on the same principle except that the cavity is filled with an electrolyte. EHP uses an auxiliary electrode to oxidize the migrating hydrogen atoms. The electric current required to sustain the oxidation is proportional to the hydrogen entry rate and thus, corrosion activity.

The EHP is commonly a patch-type probe that is strapped on the outside of the pipe to detect hydrogen permeating through.

The EHP provides a more quantitative indication of hydrogen activity than the PHP, but is somewhat more expensive. The finger-type probes respond to corrosion occurring on the probe itself. The patch type responds to corrosion on the pipe wall. However, the seal to the pipe wall can be difficult to achieve and maintain.

Hydrogen probes can give quick information. Data from the PHP are not real-time. Trends must be reviewed. However, the EHP can provide real-time data. In the oil field, hydrogen probes work best in sour systems because the presence of H2S increases the amount of nascent hydrogen available by retarding the H0 to H2 reaction.

Hydrogen probes provide relative data on corrosion activity. These probes do not give actual corrosion rates, but will detect a change. Fig. 8 shows an example plot of data from a PHP. Note that the significance lies in the incremental pressure increase, not the cumulative reading.

Hydrogen probes are a specialty technique and not widely used in the oil field. However, they have produced some meaningful data in published cases.37

REFERENCES

"Preparing, Installing, and Interpreting Corrosion Coupons for Oil Production," NACE RP-07-75.
"Standard Recommended Practice for Preparing, Cleaning, and Evaluating Corrosion Test Specimens," ASTM G1-67.
Corrosion Monitoring Primer, 3rd edition, Rohrback Cosasco Systems, Santa Fe Springs, Calif.
Roller, D., and Scoff, W.R., "Detecting and Measuring Corrosion Using Electrical Resistance Techniques," Corrosion Technology, Vol. 8, No. 3, March 1961, pp. 71 -76.
Winegartner, E.C., "Recording Electrical Resistance Meters," Corrosion, Vol. 16, No. 6, June 1960.
Galbraith, J.M., Disbrow, L.A., and Van Buskirk, K.A., "Installation and Use of Automated Electric Resistance Probe Systems to Monitor Corrosion in the Eastern Operating Area of the Prudhoe Bay Oil Field," paper No. 239, Corrosion/84, New Orleans.
Houghton, C.J., Nice, P.I., and Rugtveit, A.G., "Use of Automated Corrosion Monitoring Aids Downhole Corrosion Control," paper No. 287, Corrosion/84, New Orleans.
Annand, R.R., "An Investigation of the Utility of Instantaneous Corrosion Rate Measurement for Inhibitor Studies," Corrosion, Vol. 22, No. 8, August 1966.
Martin, R.L., Application of Electrochemical Polarization to Corrosion Problems, Petrolite Corp., 1977, Houston.
French, E.C., "Flush-mounted probe measures pipe corrosion," OGJ, Nov. 17, 1975.
Martin, R.L., "Potentiodynamic Polarization Studies in the Field," Materials Performance, Vol. 18, No. 3, NACE, March 1979, pp. 41-50.
Martin, R.L., "Diagnosis and Inhibition of Corrosion Fatigue and Oxygen Influenced Corrosion in Oil Wells," Materials Performance, Vol. 22, No. 9, NACE, September 1983, pp. 33-36.
Thomason, W. H., "Corrosion Monitoring with Hydrogen Probes in the Oilfield," Materials Performance, Vol. 23, No. 5, NACE, 1984, p. 24.