Table of Contents

Vol. 8, No.3
3rd Quarter 2002

Increasing gel strength (viscosity) is another approach for achieving a pressure response. This is typically used at the midpoint of a treatment when the Hall plot shows no increase in slope. Gel strength can be increased by accelerating the cross-linking, increasing the polymer loading of the gelant, or using a higher molecular weight polyacrylamide. 

The best candidates for gelled polymer treatments are shut-in wells or wells producing at or near their economic limit. These types of wells benefit most from a successful treatment and little is at risk if the treatment fails, other than the treatment cost. Other selection criteria include significant remaining mobile oil in place, high water-oil ratio, high producing fluid level, high initial productivity, wells associated with active natural water drive, and high permeability contrast between oil- and water-saturated rock (i.e., vuggy and/or fractured reservoir). Successful treatments have been conducted in both cased and open hole completions.

Only empirical methods exist at this time for sizing treatments. Experience in a particular formation is important. In many instances, larger volume treatments appear to decrease water production for longer periods of time and recover more oil. Some rules of thumb include two times the well's daily production rate as the minimum polymer volume, or using the daily production capacity of the well at maximum drawdown (i.e., what the well would be capable of producing if it were pumped off) as the treatment volume. In lower fluid level wells, the daily production rate is sometimes used as the minimum polymer volume.

Before pumping treatments, ensure the wellbore is clean, acidizing if necessary. Establish a maximum treating pressure, run a step rate test to determine parting pressure. Select an acceptable source of water. Having the service provider test water compatibility is important. Select a polymer-compatible biocide (typically 5-10 gallons per 500 barrels of mix water). Set tubing and packer above the zone to be treated. While pumping the treatment, use stages of increasing polymer concentration. Inject the treatment at a rate similar to the normal producing rate. Keep treatment pressure below the reservoir parting/fracture pressure. Changing conditions during the treatment may warrant design changes during the pumping. Over displace the treatment with water or oil.

Wellbore Management (Reducing Failures)

If produced water volumes are high and one has to live with them, operating and maintenance practices that control and reduce costs are critical. Tubing failures are usually internal from either corrosion or rod wear, or external from buckling. Internal corrosion has to be controlled with the corrosion inhibitor program or an internal coating mechanism. There are some very basic practices to minimize tubing and rod wear. Some published literature indicates that tubing should always be anchored. However, many operators have found that tubing anchors are not needed in wells less than 3,000 ft deep. If the tubing failures are collar failures (external) from the tubing buckling, or if there is evidence of rod coupling wear on the inside of the tubing, then a tubing anchor is justified even at very shallow depths. Tubing anchors should be as close to the pump as practical. If the anchor is more than 400 feet above the pump, buckling can still occur.

Tubing rotators that distribute tubing are an option for shallower wells without tubing anchors, but they are used infrequently. A new, lower cost mechanical rotator developed by Omega Technologies is being used in shallow wells (2,000 ft) with reported good results. Rod rotators can be used to distribute coupling wear. They are only used when rod guides are used. If a rod rotator is to be used, the operator should be sure that the correct rotator is used. 

Since increased fluid velocity around rod guides can remove inhibitor films, rod guides should only be used where repeated tubing splits and/or excessive rod coupling wear occur. Often, wear is concentrated on the bottom of the rod string where rods go into compression. An accepted practice is to install 3-4 guides per rod with the number varying with hole deviation. When tubing wear is found at the bottom in the sinker bar area, a short, 4 ft guided stabilizer is run between each sinker bar. Operators prefer "molded-on rod guides" over "snap-on rod guides," since snap-on rod guides require hammering them on, which can damage rods.

Polyethylene tubing liners are becoming increasingly popular. These liners are chemically inert and are a seamless tube tolerant to minor surface imperfections. Some operators are installing the liners one or two joints above the pump, while others are installing the liner in half of the tubing string. Polyethylene tubing liners can be installed in used "green and or blue band" tubing for a cost of about $1.50 per foot. There is some ID loss, but favorable friction characteristics partially offset ID losses.

Sucker Rod Handling

There are many, many variables that can lead to sucker rod pin and coupling failures. These are under torque, wrench marks, over torque, lubrication, contamination, thread wear and cross-thread. Be prudent when picking up rods. Thread protectors should be unscrewed, because knocking off the thread protectors leaves plastic remnants that can cause damage during makeup. When tailing rods to the floor, take care to prevent metal-to-metal contact when rods are drug, or contaminating the threads by dragging ends through dirt. Inspect and clean, as needed, all rod pins and boxes. Once the pins and boxes are clean, use only moderate lubrication.

All rod connections should be made "hand tight" using "only hands;" not hands holding wrenches! If a rod will not screw on by hand, thread damage has already occurred. Once hand tight, a mark can be placed across the connection to represent the first point of a distance of travel. This line represents zero displacement. Then, before tightening with tongs, the rod should be backed off by unscrewing approximately four rounds to allow the tongs time to reach full speed, ensuring the momentum force component of makeup is comparable to normal operating condition of the tongs.

Reducing Well (Rod/Tubing/Pump) Failures

Operating practices to reduce well failures vary from "none" (i.e., replace a single broken rod) to "very disciplined well failure analyses and corrective action processes." Field experience confirms that more thorough and disciplined programs reap results, as illustrated for one West Texas field. 

Well failure frequency averages for successful programs are generally under one failure per well per year, and some are as low as 0.15 failures per well per year. One might argue—that's great, but I'm a small company. The good news is that smaller companies can apply the same concepts by employing the services of their vendors and maintaining good communication.

Common elements of successful programs are:

• Visual inspection of rod and tubing failures
• Discussion of the problem and a review of the well history with team members-company, chemical, service company, equipment vendors, rod and tubing inspection personnel.
• Establishment and maintenance of a database of each well's failures. A tracking program can set up the database. The tracking program should also facilitate economic evaluation.

Over time, best operating practices in a given area should be developed. Successful programs usually employ the "pay me now, or pay me later" philosophy. Example; if a rod fails, successful programs call for either replacing the entire rod string with an inspected used rod string, or replacing the tapered section where the failure occurred. If one rod failed for mechanical or corrosive reasons, chances are that another failure will occur shortly. The pulled rod string is sent in for inspection. Typical inspection costs are: $7.95 per good rod, and $2.00 per rod rejected. A similar practice applies to tubing string failures. Used tubing strings of Yellow, Blue, and Green pipe body ratings are reused after inspection. Polyethylene liners work well in used tubing strings.

Lift Efficiency and Type of Lift System

With any lifting system, "system efficiency" is very important. Overall system efficiency is defined as the amount of theoretical work required to lift the liquid from the net liquid level depth to the surface divided by the amount of power supplied to the motor. There are programs that evaluate system efficiencies. One system offered by Echometer is computerized and takes about 45 minutes per well. System efficiency quickly translates into power cost savings.

For any lifting system, experience indicates that failure frequency is the most important variable. The other components of the system—equipment, servicing, power consumption cost—are much more stable, especially on beam-lifted wells. When considering typical failure frequencies, power consumption, service cost and equipment costs, general conclusions can be drawn. For producing depths of 4800 ft and wells with 5 ½-in casing considering "Total System Cost", beam pumps are most economical for volumes up to 320 BFPD. However, for this same depth and casing size, when considering only the "Operating and Maintenance Cost", the volumes where beam pumps are most economical increase to about 500 BFPD. For volumes above 500 BFPD, electrical submersible pumps (ESPs) are generally most applicable. ESPs are also preferred when holes are extremely crooked.

Kent Gantz, "Holistic Producing-Well Improvement Reduces Failures/Servicing Costs,"
Fig. 1, Petroleum Technology Digest section of World Oil, June 2002, p. 59-60. 

J.N. McCoy et.al, "Modern Total Well Management," Figure 1 fromSPE #62834
presented at 2000/SPE/AAPG Western Regional Meeting, Long Beach, CA, June 19-23, 2000