OIL FIELD CORROSION-CONCLUSION ECONOMICS IMPORTANT IN SELECTING MONITORING TECHNIQUES

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

Failure/risk costs need to be considered when deciding on the type of corrosion monitoring and inspection. Locations with high-pressure, high-velocity streams need closer monitoring.

This concluding article of a three-part series discusses the risks associated with different types of fluid streams and the various inspection techniques that can range from a low-cost visual examination to mechanical calipers and electromagnetic, radiographic, and ultrasonic tools.

INSPECTION

Because inspection is a procedure to determine the condition of equipment or piping, it is often overlooked as a corrosion-monitoring technique.

However, inspection methods can be used to detect corrosion damage and evaluate the need for corrosion control.

Most important, inspections provide the necessary proof for rating the success of a corrosion-control program. Following are several inspection techniques used in field operations.

VISUAL

Visual examination is the most common inspection technique. It is inexpensive, simple, and often forgotten. Careful examination of vessels, piping, and equipment can give helpful information on corrosion damage, surface flaws, and contamination. It can also help assess the need for further inspection and determine the best method.

Ideally, periodic visual inspections should be scheduled, but also conducted anytime the opportunity arises, such as whenever vessels are opened, pipe is cut, or tubing is pulled.

A record should be made of the visual exam with observations and findings.

It should include the following:

• Extent of metal loss

• Appearance of attack

• Location of attack

• Orientation of attack

• Record of deposits present and sample deposits

• Condition of coating, if present, and sample, if disbonded

• Condition of surface (oil or water wet)

• Gauge-measured pit depths

• Photographs.

Laboratory analysis of deposits will identify any corrosion products present. Knowing this will aid in troubleshooting the problem. Failed coating samples should be sent to a coatings lab for analysis. If the coating failed, the reason must be determined.

There are some tools that can be used to enhance a visual inspection, such as optical borescopes. Borescopes can literally be an extension of the human eye. Rigid borescopes are quite effective in straight tubes and looking into a hole. Although more expensive, flexible borescopes provide greater versatility in hard-to-reach locations.39

MECHANICAL CALIPERS

Mechanical calipers use spring-loaded feelers to inspect the presence and depth of corrosion in pipe.40 41 These typically consist of multiple feelers to cover an adequate sampling of the surface. Response from the feelers is sent electrically to a strip chart, or mechanically scribed on a cylinder. Calipers are most commonly used to inspect downhole tubing and casing.

The calipers with an electric response must be run on electric wire line. The mechanical scribing calipers are less expensive because they can be run on slick line. In either version, the presence of scale can mask results. Scale and corrosion products can fill pits and hide them from the feelers. Take steps to remove the scale before inspection, or results could be too optimistic.

Calipers only provide a sampling of the corrosion damage, but the data are real. The sampling is made statistically better by increasing the number of feelers. Getting data from each feeler is extremely helpful because it provides a cross sectional assessment of the pipe condition, as shown in Fig. 1.

A history of caliper data will give actual penetration rates of the tubing. Keep in mind, the data are in the past tense. It does not provide the current corrosion rate, but only what has occurred in the past.

The best frequency for inspections will depend on corrosion rates. In general, the caliper is a long-term evaluation tool. Ideal frequencies are often 6 months to 1 year or more.

Most of the focus here is on downhole inspection. Other uses of calipers include heat exchanger tubes and horizonal pipelines.

ELECTROMAGNETIC INSPECTION

Direct current electromagnetic inspection methods induce a magnetic field to detect corrosion pits. The magnetic field is monitored for disruptions, i.e., flux leakage, created by corrosion pits.

The measured flux leakage is calibrated, amplified, filtered, and converted into a strip chart recording showing pitting severity. This is a common method for inspecting tubing, casing, and pipe .42 An example of a downhole inspection tool is shown in Fig. 16.

There are two basic configurations of dc electromagnetic tools. One inspects tubular goods on the surface after they are removed from service. In this type, the inspection equipment is on the outside of the pipe. The other type inspects from the inside of piping, casing, or tubing while it is in place, i.e., in situ (Fig. 2).

In either case, dc electromagnetic tools often have difficulty detecting large areas of gradual wall loss in pipe. For this reason, a secondary device is often used to more accurately detect broad uniform wall loss.

An alternating current ac electromagnetic device is typically used to measure wall thickness in conjunction with the in situ dc inspection tools. This device passes a low-frequency electromagnetic signal through a test section. A phase shift between the transmitted and received signal is measured. This phase shift is proportional to the average wall thickness between the transmitter and receiver coils.

Because the measurement is an average, it can be relatively insensitive to small isolated pits. However, it will find large areas of uniform wall loss.

The surface inspection units typically use a gamma ray radiation device for more accurate wall thickness measurement. Here, a gamma ray radiation source is aimed at the pipe wall. A wall thickness is correlated based on either the unabsorbed or the back-scattered radiation collected. Both methods give a relatively accurate thickness measurement.

In situ electromagnetic tools provide better coverage of the pipe wall compared to mechanical calipers. Most can inspect 100% of the pipe area. The disadvantage of electromagnetic tools stems from the amplifying and filtering of the data. This massaging of the signal can affect inspection results. Some equipment may be more accurate than others in certain cases.

Surface inspection of downhole tubing can yield more accurate results than in situ tools by allowing time to verify the readings. The inspector can use other means, such as ultrasonics and visual, to evaluate indications from the electromagnetic unit. Because results are inspector dependent, a higher quality inspection can be obtained when the inspector has more time.

If plans are to pull the tubing regardless, a surface inspection is the best answer. When using surface inspection units, the tubing joints should be numbered to correlate attack location within the string.

Another approach uses a surface inspection unit attached to the wellhead to inspect tubing as it is pulled through. This reportedly saves cost by reducing workover rig time. However, the operator is forced to make quick decisions based on strip chart readings, negating the benefits of a surface inspection.

Inspecting the tubing after it is laid down requires more time, but it allows the operator to investigate more thoroughly.

Horizonal pipelines are inspected in situ using an electromagnetic inspection tool, or pig.43 44 The inspection pig is motorized or pumped through the pipeline and records data as it travels. Other equipment, such as video cameras, can be added to the tool to enhance inspection.

Presence of solids could affect inspection results and pig travel. Use cleaning pigs before an inspection to remove solids.

RADIOGRAPHIC INSPECTION

Radiographic inspection (X ray) is a technique using differential absorption of a radiation source to measure corrosion. A source emits radiation through a test area. Variations in thickness will cause different amounts of the radiation to be absorbed. The unabsorbed radiation is collected and correlated to a wall thickness. The two basic types of radiographic inspection are manual and real-time radiography.38

Manual radiography collects the unabsorbed radiation on sensitive film. In real-time radiography, the image is sent directly to a viewing screen or television monitor and can be taped for future review.

Both methods can be used on virtually any accessible area of pipe. Real-time radiography allows coverage of a large area in a short time. However, the resolution can vary. Testing parameters can be optimized using manual radiography. Corrosion damage can then be more accurately measured through densitometry.

The economics of choosing a method, or combination, depends largely on the amount and size of the pipe inspected."

Many people are familiar with radiography for weld inspection in the oil field. Its benefits as a corrosion detection and monitoring technique are now being realized. Radiography allows inspection of selected key areas in a system without shutdown.

In a flow line, for example, selected areas might include elbows, restrictions, or other places where higher corrosion rates are expected. It is usually not economical to inspect 100% of a system with radiography. So, selection of the test site is critical. Also, it requires experienced personnel to conduct the inspection and analyze results.

ULTRASONIC INSPECTION

Ultrasonic inspection induces high-frequency sound waves in the test piece to detect position and depth of flaws. in corrosion monitoring, ultrasonics is used to assess corrosion damage by measuring wall thickness of a vessel, tubing, casing, or pipeline. The high-frequency sound beam travels through the metal test piece and is reflected at the opposite side. The reflected beam is analyzed to determine the location and extent of corrosion damage.

There are various types of ultrasonic inspection equipment. The simplest form is the ultrasonic thickness (UT) meter. The UT meter merely analyzes the data from the first reflection and displays it as the thickness. The UT meter is very easy to use. However, the information can be misleading because it uses only one reflection at a time.

Systems that analyze multiple reflections can provide additional data leading to more accurate results. In these systems, the inspector scans the surface of the pipe or vessel wall with the ultrasonic transducer. The reflections produced from the scan are displayed on an oscilloscope and/or logged into a computer for analysis. There are three types of scanning techniques:39

• A-scan-A single point reading.

• B-scan-A series of measurements along a line. For example, a line around a pipe circumference, or a line up the side of a vessel across the fluid level (Fig. 3).

• C-scan-Multiple readings in a close-spaced grid pattern over an area of interest.

Automated crawling equipment can reduce the time-consuming job of scanning. In C-scans, a computer can analyze the information and enhance it to produce a three-dimensional map of the corroded surface.46 Although this method is expensive, it can be economical for high-risk situations.

Ultrasonics is a highly sensitive inspection technique that yields good accuracy. It has strong penetrating power allowing inspection of thick sections. It can inspect large piping or vessels where radiography is impractical.

As with other inspection methods, ultrasonics requires no shut-in time providing the test area is accessible. Also, the equipment can be quite portable if computers or automated scanning are not needed.

Ultrasonics is very good for detecting areas of gross metal loss, such as large pits and grooves. But it can often miss isolated pitting.

Ultrasonics testing requires an experienced technician. Although some meters are simple to use, readings can be misleading without some expertise in ultrasonics. Also, rough or irregular shapes can be difficult to inspect, and scanning large areas can be time-consuming.

It is often helpful to use ultrasonics along with radiography. Radiography can be used to spot problem areas, and the ultrasonics can make precise measurements of the damage. Coupling of these two methods results in a more economical inspection procedure.

MONITORING METHODS

Always consider corrosion monitoring needs during project design. Installation of monitoring fittings, etc., is easier and less expensive during the initial stages of a project. An important consideration in planning a corrosion monitoring program is economics. One must assess the failure risk/cost and project life before designing a program.

Any comprehensive monitoring program should include monitoring:

• The producing conditions

• The corrosion control program

• The equipment performance.

In addition, employ economic inspection methods as practical. Perform visual inspection whenever vessels are opened or a pipe is cut. Record observations and keep them on file. Schedule an inspection program for vessels and surface piping, using radiography and ultrasonics.

Frequencies will vary. Government requirements are involved in many areas. Review these requirements and include them as part of the comprehensive monitoring plan.

The following provides examples of applying corrosion monitoring methods to various specific oil field systems.

GAS PRODUCTION

A gas production system typically consists of gas wells, gathering lines, and gas-treating facilities. In gas systems, the most common monitoring method is with coupons. Coupons provide overall corrosion and pitting rates as well as information on the type of attack.

Electrical resistance (E/R) probes are used to supplement coupons where there is a need for more immediate data. Inspection methods are also used more in gas systems, due to higher operating pressures and failure risks.

Important locations to monitor a gas system include each wellhead, downstream end of the gathering lines, and between each vessel or separator. That is, monitor at each temperature level, pressure level, and wherever liquids are removed.

Make provisions to be sure that the coupons, or E/R probes, contact the produced water in each case. This may mean installing them in vertical flow sections or on the bottom side of a horizonal line (Fig. 4).

In monitoring downhole corrosion, iron counts and mechanical calipers are used in addition to coupons. Results from wellhead coupons, or E/R probes, will give relative information but may not equal downhole corrosion rates.

Iron counts provide immediate information correlating to corrosion activity downhole. An inspection program using mechanical calipers will add definitive data on tubing condition.

Coupons can be installed and retrieved downhole in special mandrels using wire line.

However, if you have to run wire line, it may be more economical to run an inspection tool instead and evaluate the tubing itself.

The extent and frequency of wellhead monitoring will depend on the failure risk and the data needed. Typically, coupons are applied widely throughout a field. Exposure times may range from 1 to 3 months. Iron counts and E/R probes are sometimes used on selected wells and moved to other wells as interest changes.

The frequency of these techniques is about 2-3 readings per week.

Frequency of caliper inspections is a function of corrosion rate and caliper resolution. Caliper results showing no change become uneconomical after awhile and the frequency should be extended. When monitoring several wells, develop a schedule to inspect a few each year. For example, select a group of six wells to monitor and split these into two groups of three. Run three caliper inspections per year, but alternate between the two groups. This gives a larger sampling and yearly data while maintaining the cost at three calipers per year. In gathering lines, locate coupons (or E/R probes) where you expect the highest corrosion rates. One example is a location farthest from an inhibitor-injection point.

Coupon fittings allowing access under pressure are helpful. An inspection program using radiography and ultrasonics should also be planned to assess actual conditions. Inspection frequency will depend on operating pressure and failure-cost exposure.

Coupons are also the most common corrosion-monitoring method in gas-treating facilities, such as glycol dehydration and amine sweetening. Monitoring locations include rich (glycol or amine) lines, lean (glycol or amine) lines, gas inlet, and gas outlet. Here, pressure-access coupon fittings are used to avoid system shut down.

High-pressure, high-velocity locations are selected for periodic inspection. Again, radiographic/ultrasonic inspection frequency will depend on conditions. However, visual inspections of any location should be conducted anytime the facility is down.

Periodic laboratory analysis should be conducted on lean and rich samples of the glycol, or amine to check quality.

Chemical degradation or absence of inhibitor can affect corrosion rates throughout the facility. Some on-site measurements, such as glycol pH, can be helpful when performed properly. However, there is no substitute for a routine lab check.

WATER-INJECTION SYSTEMS

Water-injection systems can consist of water-supply wells, supply gathering lines, handling facilities, distribution (injection) lines, and injection wells. The basic corrosion-monitoring philosophy for waterflood injection also holds true for water disposal. However, water-disposal systems are usually small. The economics point towards corrosion-control methods, such as fiber glass piping, where routine monitoring is not needed.

In general, coupons are used throughout a water-handling system to detect changes in operating conditions.

Coupons should be changed concurrently to allow data comparison from one location to another (Fig. 5).

In the water-source system, locate coupons at each supply well and in each leg of the gathering system. This will allow early detection of a problem and locate its source. Coupons should also be installed in the water-handling facility at the inlet and outlet of each tank, vessel, or pump (Fig. 6).

Results may help pinpoint oxygen entry through a pump suction leak, failure of a gas-blanket system, or bacteria contamination of a tank. Finding the location of a problem is more than half the battle of solving it.

Coupons in the injection system should be strategically located based on the system layout. Include all remote and high-risk wells. Also, include at least one well close to the handling facility and one far away. Try to cover each water leg, including the main trunk line. In any event, always locate a coupon at the farthest point downstream in the system.

Suspended-solids analysis from injectivity tests can detect a problem by showing presence of oxides or sulfides, for example. Moving farther upstream can pinpoint the origin of the problem. Keep records of these analyses.

Corrosion problems in water-injection systems are commonly caused by oxygen entry or bacteria activity. Once a problem is detected, determine the cause and source by using a specific monitoring technique.

For example, use an O2 meter (or test kit) to measure dissolved oxygen in both sides of a pump or tank, A differential reading will indicate air entry or problems with the gas-blanket system. A persistent problem could be continually monitored using a galvanic probe. This is extremely helpful in detecting cyclic oxygen entry.

Evaluate bacteria problems in a similar manner using culturing techniques described previously.

OIL PRODUCTION

Oil-production systems consist of oil wells, gathering lines, separation equipment, and storage tanks. With some exceptions, the main method for monitoring corrosion in oil systems is by failure records. In addition, visual inspections are also made throughout the system and recorded.

Electromagnetic inspection of production tubing is typically done after the tubing is pulled.

These inspection data can help quantify the failure damage and confirm cause. Production records are also used to detect changes in fluid rate or water cut. This can allow a change in a treating program before failures occur.

Other routine monitoring methods are usually not needed because of low failure costs.

Oil systems usually operate at low operating pressures that fail as leaks.

There are exceptions. Wells or systems that present a high failure risk will require additional routine monitoring. Examples include some offshore fields, and the Alaskan North Slope. In these cases, routine monitoring with coupons, E/R probes, and scheduled inspections may be justified.

Special short-term programs using coupons, E/R probes, or even linear polarization rate (LPR) probes have been used to assess conditions in a new field. A brief program could also be used to conduct a field inhibitor evaluation. However, the program has a limited scope and short duration in these cases.

The efficient use of failure data is exemplified in the case of rod-pumped wells. Because of the cyclic stress, sucker-rod failures will occur rapidly when well conditions get more severe. Rods will frequently show a change long before coupon data.

Sucker-rod failures are also indicative of tubing conditions because they see the same environment. The sucker rod is, in effect, a coupon providing excellent data.

Another aspect worth mentioning concerns gas-lifted oil wells. Corrosion can be affected by changes in the CO2 or H2S content of the lift gas. Changes in the lift-gas source should be noted, and samples should be submitted to the lab for analysis periodically.

Lift gas could also become contaminated with oxygen. Leaking flanges upstream of a compressor, for instance, could cause air contamination in the lift gas.

Personnel should be aware of signs implying oxygen corrosion, such as corrosion near an oxygen source or evidence of iron oxide. If suspected, measure dissolved oxygen in the produced water using a meter or field kit. Oxygen in the lift gas can be measured with a trace-oxygen analyzer. For either case, begin at the evidence and move upstream to pinpoint the source.

POINTS TO REMEMBER

Corrosion monitoring is the most important part of a corrosion-control program. It provides the necessary information to determine need, extent, and performance of corrosion-control measures.

In designing a corrosion-monitoring program, there are several important points to remember:

• Always consider corrosion-monitoring needs during the initial stages of any project.

• There are many different types of monitoring methods. Each has different advantages and disadvantages.

• Design an economical corrosion-monitoring program by first assessing failure risk and cost exposure associated with the system.

• When possible, use multiple monitoring methods. The different methods will complement each other and permit better interpretation of data.

• Maintaining accurate records in a usable form is essential to the life and benefit of a monitoring program.

• Periodically review the monitoring program and alter it to fit the changing system.

In essence, corrosion monitoring is score keeping. The data are critical. If you do not keep score, how do you know if you are winning?

REFERENCES

1. Bartz, M.H., and Rawlins, C.E., "Effects of Hydrogen Generated by Corrosion of Steel," Corrosion, Vol. 4, No. 5, May 1948.

2. Nondestructive Evaluation and Quality Control, Metals Handbook, 9th ad., Vol. 17, ASM International, 1989.

3. "The New Kinley Microscopic Caliper," from ASME presentation, Sept. 23, 1958. Available from the J.C. Kinley Co., Houston.

4. Casing Evaluation Services, Report 01/87, 2.5M, 9541, Chapter 4, Dresser Industries, 1985.

5. Haire, J.N., and Heflin, J.D., "Vertilog-A Down-Hole Casing Inspection Service," paper No. 6513, SPE 47th Annual California Regional Meeting, Bakersfield, Calif., Apr. 13-15, 1977.

6. Rogers, W.M., and Duckworth, H.N., "Electronic Survey Helps Assure Integrity of Offshore Pipelines," paper No. 1854, 5th Annual Offshore Technology Conference, Houston, Apr. 29-May 2, 1973.

7. Shannon, R.W.E., and Knott, R.N., "On-Line Inspection: Development and Operating Experience," paper No. 4923, 17th Annual Offshore Technology Conference, Houston, May 6-7, 1985.

8. Hill, D.E., and Galbraith, J.M., "Development of a Real-Time Radiographic System for Inspection of Corroded Crude Oil Flow Lines in the Eastern Operating Area of Prudhoe Bay, Alaska," paper No. 238, Corrosion/84, New Orleans.

9. Galbraith, J.M., "In-Service Corrosion Monitoring with Automated Ultrasonic Testing Systems," unpublished, available from CTI Inc., Anchorage, Alas.

Copyright 1990 Oil & Gas Journal. All Rights Reserved.