FINAL The Owens Lake Turnout Facility End Cap Study
Major Design Flaw
1. 1
Artificial Lift
Major Design Flaw
Found in the standard API down hole rod pumps
The 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.
2. 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
2
3. 3
Lets look at a diagram of a Rod Pump with a
Conventional API Plunger
and see if we can find the problem.
4. Lets focus our attention to the upper portion of this pump
4
5. 5
60 Thousandths
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.
6. 6
When you have formation sand, frac sand or any other types of
solids entrained in the produced fluid, then you have a potential
problem.
8. 8
Notice how the sand is forced downward and outward into the
gap between the plunger connecter OD and the pump barrel
wall ID.
gap
9. 9
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.
10. The sand is being funneled down into the gap
We call this the FUNNEL EFFECT
10
Funnel
11. 11
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
12. 12
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
13. 13
Wedge
Again, notice the shape that is formed between the plunger
connector and the pump barrel wall. We call this the
WEDGE EFFECT
14. 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
15. Now that we have discovered the two major problems with the
standard API down hole rod pump is the.
Funnel Effect and Wedge Effect.
15
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 !
16. 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.
17. 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.
19. 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.
21. Now, lets look at some case studies of the performance and
longevity of the FARR pump over the last few years.
21
22. 22
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.
23. 23
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.
24. 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 Pump
Stroke-Thru Pump
0.002" 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 Prayoga
Petroleum Engineer
PT Chevron Pacific Indonesia
Abstract Submitted for APOGCE 2011
24
Chevron in Indonesia
(Duri steam flood) submitted this SPE paper in 2011.
25. 25
From: Kane RW (Rod) at mailto:RWKane@aeraenergy.co
Sent: Monday, March 17, 2014 1:43 PM
To: Dave Muth
Subject: 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 Kane
661-201-3484
Testimonial letter: March 2014
Horizontal Well Applications.
26. 26
From: Cote, Ted J [mailto:ted.j.cote@esso.com
Sent: Tuesday, March 18, 2014 7:23 AM
To: Dave Muth
Cc: Cote, Ted J
Subject: 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 Cote
Subsurface Engineering
Imperial Oil Resources – Cold Lake, Ab
Box 1020, Bonnyville, Ab, T9N 2J7
Ph 780 639-5106; Cell 780 812-5594
Email: ted.j.cote@esso.ca
Testimonial Letter - March 2014
Imperial Oil Resources – Cold Lake, Ab. Canada
27. 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 2013
Bakersfield, CA.
28. Plunger Count Failed % Still Running
Farr 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 2015
Data 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.
28
29. Non-Farr
Farr
Combined
Non-Farr
Farr
Combined
--- 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 2015
Survival Plot - Slide #2
29
30. 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 2015
Economic 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
30
31. 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
