Muth Pump LLC - Creator of the Farr Plunger

SPE 68859
Extending Downhole Pump Life Using New Technology G.M. Muth, SPE, Muth Pump Company LLC, and T.M. Walker, SPE, Evans, Frey and Walker

© Copyright 2001, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the SPE Western Regional Meeting held in Bakersfield, California, 26-30 March 2001.
This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract
Sand, whether formation sand or frac sand, is produced along with hydrocarbons and water from many wells. This sand can accelerate wear of the plunger and pump barrel, and can also cause the plunger to stick in the barrel. These problems may result in frequent pulling jobs and expensive pump repair costs. The Farr plunger, a newly designed pump plunger and pull rod, has been tested during this past year in numerous oil fields in California. These tests indicate that the Farr plunger has the potential to reduce the pump wear and plunger sticking problems caused by sand production. This paper describes this new design, and the initial results of the field trials.

Introduction
A typical sucker rod pump configuration uses a plunger inside of a pump barrel to lift fluid from the wellbore to the surface. The pump contains a set of two valves; a standing valve and a traveling valve. The plunger is lifted by a prime mover, which is connected to the plunger via a string of sucker rods (Figure 1).

The traveling valve is forced closed and the standing valve is drawn open at the start of the upstroke of the plunger. Fluid is drawn from the wellbore into the pump barrel chamber during the upstroke. The standing valve will close and trap this fluid in the pump barrel chamber when the plunger reaches the top of the stroke.

The traveling valve opens during the down stroke of the plunger. The well fluids in the pump barrel chamber are compressed as the plunger continues down, forcing the fluids up through the travelling valve to a position above the plunger. The traveling valve closes when the plunger reaches the bottom of the stroke. This process is continuously repeated, eventually bringing the wellbore fluid up the production tubing and to the surface.

The plunger in a sucker rod pump application is typically 0.002 - 0.007" smaller in diameter than the inside of the pump barrel. This difference in diameter, which is known as "minus fit" or "tolerance", is important in that it allows formation fluid to slip back down and lubricate the plunger and pump barrel.

Unfortunately formation or frac sand produced with well fluids by a conventional sucker rod pump can accelerate wear of the plunger and pump barrel, and can also cause the plunger to stick in the barrel. Wear is generally caused when the sand grains are forced between the plunger and pump barrel with the lubricating wellbore fluids. Sand grains can have a higher Rockwell hardness than the components of the pump, and can therefore abrade the plunger and barrel during the reciprocating motion of the sucker rod pump. The frictional heat generated by this wear can cause the pump components to gall, or fuse together.

Various methods have been developed to minimize the impact of sand on wells produced with sucker rod pumps. These methods include:

minimizing the amount of sand entering the wellbore;
minimizing the amount of sand entering the sucker rod pump; and
minimizing the impact of sand on the sucker rod pump.

Minimizing sand entry into the wellbore must be done during initial well completion (i.e. gravel pack), or through implementation of a post completion sand consolidation treatment. Filters and centrifugal sand separators attached to the pump intake can reduce the amount of sand entering the sucker rod pump. Numerous modifications to the conventional sucker rod pump have been developed to minimize the impact of sand on these pumps, including the Farr plunger and the Muth dual string system.1

The unique aspect of the Farr plunger is the manner in which the sucker rod string is connected to the plunger. This connection was moved from the top of the plunger to the bottom of the plunger, and the angle at the top of the plunger has been reversed to force sand inwards as opposed to outwards (Figure 2). These two changes can greatly reduce the amount of sand forced between the plunger and pump barrel with the lubricating wellbore fluids.

Description of a conventional plunger
The connector used to join the sucker rod to the conventional plunger is tapered downward and outward from the sucker rod to the plunger. This connector is also about 60 thousandths (0.060") smaller in diameter than the conventional plunger. This 0.060" space between the connector and the pump barrel is located immediately above the 0.002" - 0.007" tolerance between the plunger and the pump barrel.

During the upstroke, the taper on the plunger connector displaces fluid above the plunger outward and downward. Any sand contained in this fluid is also displaced out and down. This sand will move into the 0.060" space between the connector and the pump barrel. The sand in this space will eventually work its way between the plunger and the pump barrel (Figure 3).

Numerous low volume wells are produced with pump off controllers (POC) or time clocks. When these wells are temporarily shut down, sand will settle down around the connector between the sucker rod and the conventional plunger. A small amount of sand can stick the pump by acting as a wedge between the connector and the pump barrel.

In summary, the clearance and tapered design of the conventional plunger acts to force sand between the plunger and the pump barrel, thus accelerating pump wear from sand. This design also increases the probability of sticking a pump in a POC application.

Description of the Farr Plunger
The connector, which creates these problems in the conventional plunger, has been moved from the top of the plunger to the bottom of the plunger in the Farr design. This simple change eliminates the 0.060" space between the connector and the pump barrel. The removal of this "sand storage" space helps to minimize the amount of sand able to migrate between the plunger and the pump barrel.

The angle at the top of plunger has been reversed, and tapers inward in the Farr plunger as opposed to the outward taper in the conventional plunger. During the upstroke, the taper on the Farr plunger displaces fluid above the plunger inward, away from the fit between the plunger and the pump barrel
(Figure 4).

These two changes also allow the Farr plunger to operate with POC's and time clocks. Sand settling out of solution in a Farr plunger equipped well will fall inside of the plunger instead of around the connector between the sucker rod and the conventional plunger. The first upstroke of a well with a Farr plunger will act like a scraper and move sand towards the inside of the plunger. The first downstroke of the unit, sand will be flushed out of the plunger and put back into solution.

Tthe design of the Farr plunger acts to direct sand away from area between the plunger & the pump barrel, thus minimizing pump wear due to sand. This design also decreases the probability of sticking a pump in a POC application.

Laboratory Test of the Farr Plunger
A simple test apparatus was developed to test the concept of the Farr plunger. A 2" Farr plunger was connected to a plastic pump barrel containing a traveling valve and a standing valve. The pump barrel was set on top of a perforated nipple, and this entire apparatus was placed inside of a six-inch clear plastic tube to simulate a wellbore. A sufficient amount of sand was placed inside of the simulated wellbore to cover the top of the perforated nipple, forcing the plunger to pump sand. Water was added to the "wellbore", an overflow tube was added to create a circulating system, and the plunger was connected to a prime mover to complete the test apparatus (Figure 5).

The Farr plunger in the test apparatus was operated for about 20 hours over a two-day period in October 1999. No scratching was seen in the plastic "pump barrel", indicating very minimal sand entry into the clearance between the plunger and the pump barrel. This test was repeated numerous times for shorter time periods with similar results. The pump was stopped and started during these later tests to simulate operation of a sucker rod pump in a POC or time clock operation. The Farr plunger was able to easily restart with several inches of sand settled on top of the plunger during this simulation.

The test apparatus was also used with a conventional plunger. The conventional plunger locked up in the pump barrel after only four strokes. Sand grains could be seen grooving the plastic pump barrel in this demonstration.

Farr Plunger Refinements

Initial Manufacturing Changes. A critical element of the Farr plunger is the sharp leading edge at the top of the plunger. An initial review of the first Farr plungers removed from service indicated a rounding of this leading edge. This erosion of the leading edge increased the clearance between the plunger and the pump barrel, negating some of the benefit of the Farr plunger.

Muth Pump Company investigated the process used to manufacture the plunger in an effort to understand the cause of these failures. Two separate companies were retained to construct the original Farr plungers. These two companies used two different techniques to apply the spray metal finish on the plungers. The first technique yielded a rough surface on the plunger, which led to a rough surface on the leading edge of the taper after the taper had been ground down. The second technique resulted in a smooth surface on the plunger, yielding a smooth surface on the leading edge of the taper.

This investigation revealed that the few Farr plungers pulled after failure had been manufactured with the rough leading edge. Muth Pump Company ceased manufacturing this style of plunger, and also removed the plungers with the rough leading edge from inventory. This failure analysis reinforced the need to construct the Farr plunger with a hard and sharp leading edge.

Further Product Refinements. The Farr plunger is currently manufactured in two basic types: a regular plunger with a spray metal finish having a Rockwell C hardness of 62, and a "Super 92" spray metal finish with a Rockwell C hardness of 92. Both of these plungers have the smooth surface and the smooth leading edge.

Research is currently ongoing into additional technology and options to further strengthen the leading edge of the plunger. Field trials should soon start on a plunger with a carbon steel leading edge. This plunger will have a 1-1/2" leading edge of carbon steel that is specially heat-treated. The tool steel tip is attached to the base metal with a silver solder process. The entire outer surface of the plunger is then finished with the "Super 92" spray metal finish.

Initial Field Trials of the Farr Plunger
The first Farr plungers were run in late 1999 and early 2000. Several of these plungers experienced severe wear and were removed from service. Inspection of these failures led to the elimination of the rough spray metal finish. Many of the original smooth surfaced plungers are still in operation today.

Run time comparisons between conventional and Farr plungers is complicated by the relatively short history of the Farr plunger. Table 1 is a summary of field experience with the Farr plunger in the Midway Sunset Field. This data, which summarizes the results of three different operators in the field, indicates that the run time for conventional pumps and plungers in these wells was 210 days.

The 33 Farr plungers installed in these 31 wells have run a total of 6,125 days as of January 23, 2001 for an average run time of 186 days. Most of these original Farr plungers are still in operation. This average run time will increase as these plungers continue to operate.

Sixteen of the thirty-three wells listed in Table 1 experienced an average run life of less than 145 days with a conventional plunger. This subset of problem wells, analyzed in Table 2, had an overall average run life of 76 days. The average run time for the Farr plunger in these wells was 187 days as of January 23, 2001. This is 2-1/2 times the average run time of the conventional plunger in these wells.

The Farr plunger has also been utilized in other California oil fields. The plunger is currently in service in the Coalinga, Belridge, and Kern Front fields in addition to the Midway Sunset field. Field trials are expected to start later this year in the Duri oil field of central Sumatra in Indonesia.

One operator reported a case in which the well could not be pumped with a conventional plunger. The well was equipped with a Farr plunger, and the well was placed on pump. This well sanded up after 13 days, and was then left idle. Although the plunger did not experience a long run time, the operator was able to lift fluids from the well. The experience with this well does point out a limitation of the Farr plunger.

Limitations of the Farr Plunger
The Farr plunger should greatly reduce the amount of sand entering the clearance between the plunger and the pump barrel, and should minimize pump-sticking problems in wells operated with time clocks or POC's. The Farr plunger will not, however, stop wells with high concentrations of sand from sanding up. The lifting velocity of the produced fluid has to exceed the settling velocity of the sand grains in the tubing to prevent the sand from accumulating in the tubing string and eventually sanding up the well.

Durability of the Farr Plunger
The leading edge of the plunger, which is a critical element in the design of the plunger, has shown the ability to survive the trip out of the wellbore. This edge should be expected to abrade against the tubing during a pull from the well. The first Farr plunger pulled due to a non-pump failure was successful re-run on November 21, 2000, and is still running as of the submission date of this paper. Also, one operator leaves the pump in place while cyclic steaming down the tubing / casing annulus. This operator steamed a well with a Farr plunger in place, and this well has run almost 3 months with the same plunger since that time. These early results indicate that the Farr plunger can withstand harsh oilfield environments.

Conclusions and Recommendations

The Farr plunger appears to have an application in the sand producing heavy oil fields in California.
Additional run time data will be required to fully evaluate the Farr plunger, and to accurately compare the plunger to conventional plungers.
The Farr plunger should be evaluated in additional heavy oil environments (such as the Duri Field).
The Farr plunger should be evaluated for use in clean up of recently frac'd wells to determine the applicability of the plunger in light oil applications.

Acknowledgements
The authors would like to acknowledge Young Kirkwood of Aera Energy, LLC; Harry McDermand of Berry Petroleum; and Christof Tisler of Chevron USA for their assistance in obtaining the data required in preparing this paper.