EXPERIENCE REVEALS WAYS TO MINIMIZE FAILURES IN ROD-PUMPED WELLS

John C. Patterson, S. M. Bucaram
ARCO Exploration & Production Technology
Plano, Tex.

J. V. Curfew
ARCO Oil & Gas Co.
Midland, Tex.

From the experience gained over the past 25 years, ARCO Oil & Gas Co. has developed recommendations to reduce equipment failure in sucker-rod pumping installations.

These recommendations include equipment selection and design, operating procedures, and chemical treatment.

Equipment failure and its attendant costs are extremely important in today's petroleum industry. Because rod pumping is the predominant means of artificial lift, minimizing equipment failure in rod pumped wells can have a significant impact on profitability.

This compilation of recommendations comes from field locations throughout the U.S. and other countries. The goal is to address and solve problems on a well-by-well basis.

PREMATURE FAILURES

Failure control in its simplest form is failure analysis with the goal of achieving corrective action. In rod-pumped installations, premature equipment failures are usually a result of one or more of the following

Design deficiencies
Improper selection of material (material deficiencies)
Manufacturing deficiencies
Errors in assembly
Service conditions not considered in design.

TRACKING SYSTEM

A tracking system is required to minimize equipment failures. The system should identify the failures by type (rod, tubing, pump, etc.), location (pin, body, barrel, plunger, etc.), and cause (abrasion, stuck, corrosion, split, plugged, etc.).

From this data base, analysis of the failure trend can indicate the overall performance with time. The trend helps compare producing areas, and the analysis will point out problems.

Problems can be with the chemical treatment program or with a specific equipment component such as balls and seats, rod failures in the body or end (pin or coupling), or tubing leaks because of corrosion caused hole or a rod-wear caused split.

Periodic meetings to discuss "problem wells" (those wells with premature failures) help guide operators to reduce the number of failures.

ARCO collects data on the form shown in Fig. 1. 1

A "problem well" is defined as follows:

Pump failure in less than 12 months
Tubing failure in less than 12 months
Two rod failures (pin, coupling, body) in the last 12 months
Combination of any three failures in the last 12 months, for example: pump failure, polished-rod failure, and rod break in the last 12 months.

CHEMICAL TREATMENTS

Chemical treatments for corrosion control should be reviewed and revised every 3-6 months.

A treatment's need, design, and schedule should be based on factors such as failure performance, daily production, well depth, and fluid levels.

A treating program's key points are:

Standardize on one corrosion inhibitor for the entire lease.
A typical corrosion inhibitor batch treatment consists of 1 gal/week/100 b/d of fluid. This is equal to about 30 ppm on a continuous basis. If the batch treatment inhibitor exceeds 5 gal/treatment, then the volume should be divided into two treatments/week. These concentrations are a starting point and should be optimized based on performance.
Continuous treatments should be considered when the fluid production exceeds 1,000 b/d. Continuous chemical injection is equipment intensive and, therefore, should be the last alternative considered.
Flush is extremely important. A corrosion inhibition treatment typically consists of prewetting the casing (typically 1 bbl), pumping the corrosion inhibitor then flushing with volume of 0.5 bbl/1,000 ft (2 bbl minimum). Oil always is the best flush.
Producing wells in CO2 miscible injection projects should be flushed with oil when the CO2 content of the gas exceeds 20%.
For wells with high fluid levels (top two-thirds oil, and bottom one-third oil and water), circulation after batch treating is always a good idea. This is especially needed on high fluid level wells, and always on the first treatment after pulling the well.

OXYGEN

Oxygen must be kept out of the system. To keep oxygen from entering the annulus, keep it closed during normal operations and batch treating.

The flush water for corrosion inhibition treatments should have a minimal amount of oxygen. Otherwise, the oxygen will reduce the effectiveness of the inhibition treatment.

Water should be obtained from gas-blanketed tanks, or should be treated with an oxygen scavenger when the water is obtained.

PRETREATING PODS

High fluid velocity in the tubing during pumping operations may make it difficult to establish a corrosion inhibitor film. Evidence of this problem includes pitting on rod boxes and on top of rod guides.

Also, whenever a well is pulled, the corrosion inhibitor should be reapplied to restore the destroyed film. Therefore, 5 gal of inhibitor should be placed into the tubing prior to running the pump and rods. One tubing volume should be circulated before returning the well to production.

For wells difficult to inhibit, the normal batch treatment should be supplemented, prior to seating the pump, by displacing the tubing with lease oil and 10 gal of corrosion inhibitor. This treatment assures establishing an oil/inhibitor film. A similar treatment should be performed on wells that pump from below a packer that prevents batch treatments.

ROD/TUBING WEAR

To minimize rod/tubing wear, the following is recommended:

Always anchor the tubing except in cases where not anchoring can be justified. Anchor as close to the pump as practical. If the anchor is more than 400 ft from the pump, buckling can be a problem below the anchor; however, breathing of the tubing is eliminated above the anchor.
Install rod guides where repeated tubing splits and/or excessive rod coupling wear occurs. Often wear is concentrated on the bottom of the rod string where rods go into compression or in other areas where the tubing string may be deviated.
Install four plant-applied rod guides on each of the first few rods on top of the pump (minimum of two guided rods). Because of rod and tubing buckling, rod wear is often observed on the bottom few hundred feet of the rods. Rod guides in this interval will reduce wear. Guides also centralize the pull rod, thus minimizing cocking of the plunger.
To change the wear pattern, move two joints of tubing from the bottom to the top whenever the tubing is pulled. Always install replacement tubing (new or inspected) on the bottom.
Include several pony rods, of various lengths, at the top of the rod string. The pony rod overall length should be three times the stroke length. Every time the well is serviced, move a stroke length of pony rods from the string's top to the bottom but above the guided rods.
After moving all the pony rods to the bottom, reverse the procedure by moving the pony rods back to the top of the string. The wear pattern on the tubing can be changed by moving the pony rods in conjunction with moving the tubing joints.
Install rod rotators to distribute coupling wear around the circumference of the boxes and rod guides.
Pump as slow as practical. Wear increases as speed increases.

PUMP SPECIFICATION

Because of close tolerances and high fluid velocities experienced by sucker-rod pumps, selecting the proper material is often the most economical solution to corrosion and erosion failures. Deviations from basic pump specifications should be based on experience, design considerations, and pump performance.

The basic installation configuration is an insert pump with a top holddown and metal plunger. Based on the advantages illustrated in Table 1, a top holddown pump should be the first pump type considered.

The basic pump metallurgy has a barrel with a surface hardness greater than that of a plunger. The desire is to have wear on the plunger rather than the barrel. The recommended metallurgy is a chrome-plated carbon steel barrel, sprayed metal carbon steel plunger, cobalt-alloy balls, and tungsten carbide seats.

The initial (out of the pump shop) clearance between the barrel and the plunger should be specified by the operator. Typically, use a 0.002 to 0.003-in. downhole clearance for light-oil operations and a 0.005-in. clearance for heavy-oil operations. Remember that because of pressure and temperature affects, the downhole clearance will be different from the out-of-shop clearance.

Clearance should always be measured rather than using the fit designated by the manufacturer. Fit does not take into account tolerances. API manufacturing tolerances are -0 in. and +0.002 in. for the barrel ID, and -0.0005 in. and +0 for the plunger OD. Unless clearances are measured when selecting the plunger and the barrel, the pump could have an out-of-shop clearance that is 0.0025 in. greater than specified.

A pump should have the smallest possible clearance that provides the least leakage without excessive wear, while taking into account the presence of solids.

ROD CARE

For complete information concerning sucker rod handling consult API RP11BR. 2

Note that pins need to be lubricated prior to make up. Do not use pipe dope. In corrosive service use a combination lubricant/oil soluble corrosion inhibitor (an 80% oil, 20% inhibitor mixture is recommended). Spray or dip the pins to provide a light coating. Do not pour lubricant into the boxes.

Because sucker-rod threads are rolled not cut, once the threads are damaged the threads cannot be reconditioned and the rod should be discarded.

Power tongs are recommended for all rod sizes except 5/8-in. rods. (Do you really want to use 5/8-in. rods?). Calibrate the power tongs on each well and each taper using the circumferential displacement method.

Replace the coupling if there is any evidence of hammering or wrench marks.

Rods should be laid down and picked up in singles.

DESIGN AND OPERATIONS

Typically, the longest stroke and slowest speed should be used for a given production.

Pounding and improper spacing severely shorten equipment life. Fluid pound results from the incomplete filling of the barrel. Tapping occurs on the downstroke or upstroke because of improper pump spacing.

Keeping a well pumped off and pounding does not necessarily mean more production. In a reservoir with a low productivity index and high reservoir pressure, as in most water floods, having 5-10 joints of cover above the pump will not appreciably change the production. Try it!

Rod strings should be designed for the loads and routinely monitored with dynamometers. The range of stress should be within the modified Goodman diagram including the appropriate service factor for the installation. 2

A predictive program's design should always be checked against an actual dynamometer card to ensure that the rods and unit are within acceptable parameters. Always check the design under actual working conditions. Reversing the order in which the rods operate within a taper (top rod to bottom of taper; bottom rod to top of taper) could be done once a year or at the 5 million reversals criteria.

Whenever possible, dynamometer the well following an operational change, such as a change in the pump size, speed, or stroke length.

CORROSION COUPONS

It is easy to fall into the trap of believing that surface coupons represent the corrosive environment downhole. There are at least four reasons why surface corrosion coupons will not indicate downhole corrosion rate.

A typical corrosion treatment consists of a weekly batch treatment. Soon after the corrosion inhibitor films, it starts being removed by the produced fluids. The bottom of the rod string can be void of an inhibitor film while the surface corrosion coupon is still being inhibited.
A corrosion coupon does not show corrosion that is accelerated by wear. Metal loss can be accelerated in even mildly corrosive environments by continuously removing the corrosion byproducts. 3. An intermittently pumped well will have oil and water separation in the well bore. The bottom of the rod string will be in water while the surface corrosion coupon sees oil.
The pressure at the surface and downhole are substantially different; therefore, the partial pressure of carbon dioxide and hydrogen sulfide will be much greater downhole.

Rather than using corrosion coupons, look at the rods when they come out of the well. Note any evidence of corrosion, i.e., pitting. Do the rods stay black (i.e., good inhibitor film) while hanging in the derrick or do they turn red and rust (i.e., no inhibitor film)?

The real indicator of the corrosive nature of a well is the type of failures and their frequency.

ROD REPLACEMENT

Do not replace the rod string one rod at a time. Although this appears to be reducing costs, it actually costs more money when pulling cost is considered.

When the pulling cost because of rod failures exceeds the cost of a new rod string within a short period of time, then the rods should be replaced.

Typically, when a well has had three rod failures within a 2-year period, the rod string should be replaced on the fourth failure.

If the rod failures are all within a taper, change out only that section of rods.

FAILURE ANALYSIS

Good records are critical to failure analysis. Failed equipment should not be automatically replaced in kind. Always analyze the failure to determine the cause.

Look at the rods, tubing, and pumps. Witness pump teardowns, and then take the appropriate corrective action based on the result of the failure analysis.

Keep good records; memories are short.

ARCO'S EXPERIENCE

By following these recommendations, ARCO has improved equipment performance in its U.S. operations in the Lower 48 states. A comparison of the mean time between failures for 1970 and 1988 is as follows:

Rods: 20 months in 1970 and 75 months in 1988
Pumps: 20 months in 1970 and 40 months in 1988
Tubing: 60 months in 1970 and 100 months in 1988.

ACKNOWLEDGMENTS

The authors wish to thank their management for allowing this article to be published.

REFERENCES

Bucaram, S.M., and Yearly, B.J., "A Data-Gathering System to Optimize Producing Operations: A 14 Year Review," JPT, April 1987, pp. 457-62.
API RP11BR, "Recommended Practice for Care and Handling of Sucker Rods."