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Artificial Lift

Major Design Flaw

Found in the standard API down hole rod pumpsThe standard API down hole rod pump has been around for more than one hundred years. This research and the following studies will point out this design flaw that has plagued the oil industry for all those years.

This design flaw has cut drastically into the performance and longevity of these pump to stay in the ground. It has created numerous and unnecessary well pulling and pump repairs.

This is a plunger out of standard API pump that was pumping sand & other solids. Notice the severe grooving. This grooving will cause the pump to lose pump efficiency and eventually

FAIL

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Lets look at a diagram of a Rod Pump with a Conventional API Plunger

and see if we can find the problem.

Lets focus our attention to the upper portion of this pump

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60 Thousandths Connector

Plunger Walls

2 Thousandths

Pull Rod

Notice the connector at the top of the plunger in green. The connector is .060 thousandths smaller in out side diameter than the plunger which is .002 thousandths in out side diameter.

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When you have formation sand, frac sand or any other types of solids entrained in the produced fluid, then you have a potential problem.

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As the plunger starts it upward motion.

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Notice how the sand is forced downward and outward into the gap between the plunger connecter OD and the pump barrel wall ID.

gap

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Funnel

Notice the shape that is formed between the plunger connecter and the pump barrel wall. Doesn’t that remind you of a giant funnel? Well, that is exactly what is happening.

The sand is being funneled down into the gap

We call this the FUNNEL EFFECT

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Funnel

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Now, lets take a look at what happens when the well is shut down even for the shortest period of time. Sand will settle out of solution and fall on top of the plunger connecter and into the gap

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As the plunger tries to start back up, the sand is wedged in the gap between the plunger connecter and the pump barrel wall.

gap

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Wedge

Again, notice the shape that is formed between the plunger connector and the pump barrel wall. We call this the WEDGE EFFECT

The plunger is now stuck in the pump barrel. Even if the pumping unit had the power to pull the plunger loose, the plunger and the pump barrel will be severally grooved.

2013 Sucker Rod Pumping Workshop 14

Wedge

Now that we have discovered the two major problems with the standard API down hole rod pump is the

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Funnel Effect and Wedge Effect.

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The Funnel Effect and the Wedge Effect are created by the GAP between the plunger connector and the pump barrel wall. If we could remove the GAP, both of these conditions will go away.

What if we connected the valve rod to the bottom of the plunger rather than the top. Would that eliminated the GAP ?????

Lets see !

16Conventional “FARR”

On the left is the standard API pump with the top connector.On the right is the FARR pump with the connector on bottom.

Lets compare these two pumps.

17Conventional “FARR”

From

To

By moving the connector from the top to the bottom, we have moved the GAP to the bottom as well and now the GAP is irrelevant.

18Conventional “FARR”

.002

97 %Reduction

.060

The .060 thousandth GAP at the top has now been reduced 97% down to a .002 thousandth.

19Conventional “FARR”

.002

97 %Reduction

.060

By tapering the FARR plunger inward at the top, we are now forcing solid inward as opposed too outward like the API plunger does. Now 97% less solids get between the two metal surfaces.

20Conventional “FARR”

Funnel Effect

WedgeEffect

By FARRWe have now eliminated the Funnel Effect and the Wedge Effect.

Now, lets look at some case studies of the performance and longevity of the FARR pump over the last few years.

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Midway-Sunset field study in 2001 shows that FARR pumps out performed and out lasted all other sand type pumps in the field by 2.46 times longer. At the end of the study, 14 of the FARR pumps were still in the ground pumping.

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Venezuela study in 2005 shows FARR pumps out performed and out lasted all other sand type pumps by an even larger margin of 5.98 times longer.

Extending Downhole Pump Run Life using Ingenuity Innovation and New Technology Lead to Reduced OPEX and Increased Revenue in the Duri Steam Flood (DSF), Indonesia.

SPE-145249-PP

In DSF, > 700 Pump Stuck (PS) jobs are performed each year which primarily caused by sand production. Annual total cost of this routine service work is multimillion dollar. In addition, with average of 3 days downtime/PS job, there is over 2,100 days of lost production associated with downtime. With currently over 5,000 active producer wells, identifying artificial lift SRP alternatives that can improve run life and reduce number of PS jobs performed would result in lower OPEX (*Operating Expense) (less PS jobs), higher production (reduced downtime), and lower risk of HES (*Health, Environment, Safety) incidents (less rig work).

Three viable options were identified for a field trial after soliciting ideas and opinions from Service Suppliers, MSS (*Maintenance Supports & Services) Team, and Chevron Global Network to overcome these pump stuck issue:

0.015" fit Tubing PumpStroke-Thru Pump0.002" fit FARR Plunger

The 2008-2009 PMT (*Production Management Team) HOOU (*Heavy Oil Operation Unit) Artificial Lift Lean Sigma confirmed that these artificial lift options had a longer run life than the standard 0.010" fit pump. Average run life was increased by 93 days, and 70% of the time produced a longer run life. During 12 months trial period, there was an average reduction of 12 PS jobs/month compared to baseline data.

Since the 0.002" fit FARR Plunger had encouraging results in low wellhead temperature wells, there was initiative to evaluate it in higher temperature by modifying the pump fit to 0.005" considering thermal expansion. In 2010, 15 units of 0.005" fit FARR plungers were tested, replacing either a Stroke-Thru or 0.015" Fit Pump that had failed. The results were encouraging and indicated that the 0.005" FARR Plunger exceeded the run life of the previous pump 71% of the time with additional incremental run life of 44 days.

Author Aan Akhmad PrayogaPetroleum EngineerPT Chevron Pacific Indonesia

Abstract Submitted for APOGCE 2011

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Chevron in Indonesia (Duri steam flood) submitted this SPE paper in 2011.

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From: Kane RW (Rod) at mailto:RWKane@aeraenergy.coSent: Monday, March 17, 2014 1:43 PMTo: Dave MuthSubject: RE: FARR Plunger Horizontal Applications

I have been using the Farr plunger in horizontal wells for years. I first ran one when I had a well with a DLS of 8 degrees/100 ft and I could not keep a pump running in it.I shortened up the stroke and ran 3 ½” tubing with as short of an insert pump that I could run. Where my previous designs had only run for about 6 months, the Farr lasted over 3 years.One problem we have had with the Farr in horizontal wells, is that it is difficult to get on and off of the on/off tool if you run an oversized pump. But it is possible to get it, just difficult.

Rod Kane661-201-3484

Testimonial letter: March 2014Horizontal Well Applications.

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From: Cote, Ted J [mailto:ted.j.cote@esso.comSent: Tuesday, March 18, 2014 7:23 AMTo: Dave MuthCc: Cote, Ted JSubject: RE: FARR Plunger application in Deviated Horizontal Wells

Hi Dave, we are running the Farr Plunger pumps in deviated wells, virtually 100% of the time.  Every well that receive a Farr plunger has deviations ranging from 30 to 75° from vertical.   However, we do not call these wells “horizontal”.  Our horizontal wells are long reach, high rate wells which have big bore pumps (3-1/4” to 3-3/4”).  The pumps are landed at ranges from 75 to 85°.  We have not looked into ordering large Farr pumps because there is no demand at this time.  However, I would have no hesitations landing a Farr plunger pump at up to 85° vertical angle. I would have no problem discussing our general experience, such as deviation, with others.  However, I would be unable to get too specific, as you can understand.Thanks,

Ted CoteSubsurface EngineeringImperial Oil Resources – Cold Lake, AbBox 1020, Bonnyville, Ab, T9N 2J7Ph 780 639-5106; Cell 780 812-5594Email: ted.j.cote@esso.ca

Testimonial Letter - March 2014 Imperial Oil Resources – Cold Lake, Ab. Canada

In January 2013 a prominent Kern County Oil Company completed a 3 year Six Sigma Study of the FARR Plunger. The study found that the FARR Plunger increased run times 300% in their oil wells equipped with FARR Plungers.

All of these wells had high and low concentrations of sand and failure rates due to sand. This study compared the FARR Plunger to other “Sand Pump Plungers”: (Sand Pro), (3-Tube), (-10 Conventional), (Sand Flush) and etc.   27

Six Sigma Study - January 2013Bakersfield, CA.

  Plunger Count Failed % Still RunningFarr 188 94 50.00%

Non Farr* 205 182 11.22%

Significance:• 50% of all Farr plungers are still running.• Only 11.22% of all Non-Farr* plungers are still running.• The large percent of Farr plungers still running requires that

we rely on the projected median runtime in the survival plot analysis to explain the data.

Coalinga Calif. Study - May 2015Data Overview - Slide #1

*The study only looks at wells that have had a Farr plunger in them. Only two Non-Farr pump pulls prior to the Farr being installed and any Non-Farr pump pulls after the Farr was pulled were included in the study. The Non-Farr category includes a variety of plunger types. This applies to all slides pertaining to the 2015 Coalinga Study.

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Non-FarrFarrCombined

Non-FarrFarrCombined

--- Non-Farr

--- Farr

The projected median runtime for Farr is 470 days.

The projected median runtime for Non-Farr is 217 days.

The Farr has a 216% longer projected median runtime than the Non-Farr.

This is a 116% improvement.

Coalinga Calif. Study - May 2015Survival Plot - Slide #2

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Scenario:If 100 Non-Farr plungers are replaced with Farr

plungers in one year, then there would be a total yearly savings of $874,368.

Coalinga Calif. Study - May 2015Economic Analysis - Slide #3

Savings/well/year $8,744

  Cost/pull Projected median runtime Cost/well/day Cost/well/year

Farr $10,400 470 days $22 $8,077

Non-Farr $10,000 217 days $46 $16,820

BY MAKING ONE SMALL CHANGE TO YOUR STANDARD API DOWN HOLE ROD PUMPS, YOU WILL:

MAXIMIZE PRODUCTION AND EFFICIENCY

MINIMIZE HEALTH, SAFETY, & ENVIRONMENTAL RISKS

INCREASE PUMP RUN LIFE

Reduce well pulling

Reduce pump repairs

Save thousands of $dollars$ in the long run 31

Conclusion