Comparing The Application Of Plunger Lift
Technologies in A Given North American Mature
Field To Understand Which System Results in
Higher Production Rates Relative to Cost and Well
ConditionsGORDON GATES
RETIRED FROM BP NOW CONSULTING
Will Plungers work in my field and why should I use
them in lieu of other Artificial Lift Methods
Disclaimer!!!
When I say always what I really mean in usually.
When I hear “plungers will not work in my field because my wells are different or we are on the other side of the mountain” I………
There can/will be exceptions to success. (there are so many variables that we are not aware of like sand, casing leaks, hole in tubing, EOT location, etc.)
It has been my experience that you need to listen to the local operator to understand what they have seen and try to understand how you can make your plunger work there. Application varies from field to field. (GLR, perm, etc.)
These are my opinions based on my experience and I am human with my own biases
How do I evaluate wells to see if plungers
will be successful?
Typically a well by well with engineer, operator, and artificial lift
specialist
Decline curve analysis:
Determine gas to liquid ratio
Line pressure
Tubing size
End of tubing
Does it have a packer, tapered string?
Well history like sand, paraffin, scale, corrosion
Decline Curve
Decline CurveLoading Detection
Another decline curve. Do you have
these examples?
Does the Gas to Liquid Ratio meet the minimum requirements?
Minimum GLR = 400 scf per bbl per 1000' of lift depth
Example
Well Data
200 MCF/Day
10 Barrels/Day
7000’ Depth
Well GLR = 200,000 SCF/10 BBLS/7
= 2857 SCF/bbl
Well GLR is above 400 SCF/BBL/1000’
Should be adequate for running plunger
How do plungers stack up against
other Artificial Lift Methods? Of course a flowing well above critical is best
Velocity Strings (right size tubing) still a flowing well
Intermittent – never as efficient as plunger IF you can get consistent arrivals
Soap has a daily cost, will not achieve bottom hole pressure compared to a plunger, Soap is easy to apply and vendors will keep them pumping
Beam Lift – Much more capital needed. Down time due to rod repair and gas locking an issue. I sometimes go from Beam Lift to plungers and really lower cost. Much More (a lot of Beam Lift, Why)
Gas Lift - usually best choice when LGR is >150 bbls/MMCF, much more capital needed. Much More
ESPs – Gas separation an issue. GLR should be less than 800 SCF/bbl.
PCP – Ok in shallow wells less than 4000’ ?? Still need power and capitol.
When should I install plungers on
my well?
Better late than never if you can make it work? This is the bulk of
installations so far.
When the well reaches about 120% of critical you should start testing
if the continuous run plunger will help.
Critical rate is the point where you start to have more liquid falling
back than is being removed from the tubing.
In some fields with 250 PSI line pressure continuous run plungers are
dropped at 1.6 MMCFD
Turner et al
Unloading Rates for
Various Tubing Sizes
0
100
200
300
400
500
600
700
800
900
1000
0 100 200 300 400 500 600 700 800
Surface Pressure, PSIA
Min
Un
load
ing
Ra
te
, m
cfd
2.375
2.063
1.90
1.66
What type of plunger systems will
be most effective?
So when a wells is drilled and it starts to reach around 120 % of
critical you drop a continuous run plunger.
As you optimize that plunger and your off time increases from a few
seconds to 30 minutes or enough time for a conventional plunger to
reach bottom you should move to what some describe as a
conventional plunger which means it will not fall against flow and
the well must be shut in for the plunger to reach bottom.
As the well depletes and more offtime is needed to build energy
make sure you have a more efficient plunger which will fall slower
due to the efficiency of the plunger
Life cycle of a well (High GLR)
There are many different
types of plungers.
What type of plunger should I
choose?
If you have sand issues try to manage them, do not give up. Use
brushes, bars, and some on the bars with holes that allow the gas to
move through the plunger to clean the sand.
If you have paraffin clean out, bars, or sometimes even pads if you
run often and never let them miss arrivals.
Scale, salt, tight spots, etc. – clean outs or bars
Strong wells – continuous run plungers (two piece)
Weak wells – highly efficient
Low GLR or weak wells - Staged plungers but not many are used
due to maintenance or understanding
Combining plungers with other
methods of Artificial Lift
Most used – Plungers and Soap. I have seen questionable results.
Gas assisted plunger lift – not that common but it is a tool in the right
application. It certainly reduces injection gas volume.
Chamber lift – Works in theory but limited application.
Venting – used quite often but becomes a crutch for poor wells or
optimization.
What portion of my wells will be
successful if plunger lift is installed?
The most important factor is GLR. (Not really it is second to operator
application and skills)
My goal is to get plungers on all of the wells that will work as soon as
possible to get flatter declines and less deferred gas.
One reason we often see a well that plungers do not work on is the
engineer opened up a water zone trying to get a little more gas.
Typically shutting off that water is usually not successful.
So if I had to pull a number out of the sky on a field that most wells
run plungers I would say 75%.
My goal is as close to 100% as possible
How do I optimize my wells?
Monitor cycle logs looking for arrivals every time within the window
of arrival targets
Use the Min on/Min off concept to tune in the well. Which means
optimize the after flow to get the optimum liquid slug size with shut in
time as short as possible.
Assess operators and provide training when needed with coaching.
Monitor short and long term daily gas rates using decline analysis to
catch wells that are falling fast or had a sudden change caused by
something like sand or hole in tubing.
Min On/Min OffBill Hern came up with this illustration
Min Off
Strong Well
Min On
Depleted Well or low GLR
This is one of the reasons optimization is
important
What type of automation control
should I use to monitor and
optimize my plunger wells? Ten years ago there were not many options for control, but many
today that are quite reasonable.
Some of the controllers that are now available that I prefer is one
that optimizes slug size based on arrival time automatically (very
common choice)
All types of options like high line hold, back up time, missed arrival
adjustments
One that provides historical logs and communication (group text
work well)
What type of maintenance is
needed?
Keep a history of plunger installation date, type, problems, wear
when checked, problems, etc.
Start out with no history of three months on conventional plungers
and adjust as you get some history. (Some inspect plungers at 1
month and some as long as never) Typical inspection time maybe 8
months
Also inspect lubricator especially if you are having fast runs.
What type of operator skills are
needed?
Understand and apply decline analysis
Understand and apply Min on/Min Off
Understand wellbore
Basic Automation skills
Understand how wells load and deliquification training.
Understand Critical Rate
Communication skills
How long will plungers be
effective?
If you can make them work they will work a lot longer than most
people think. You just keep adding more shut time to build energy
as the well depletes.
I have run plungers into 1000 PSI as well as near zero PSI systems. I
have run plungers with as low as 40 psi casing pressure.
One method in lieu of pumps is to continue to add compression.
We still do not have that magic pump yet that works in a gas
system that is low cost.
What does plunger success look
like?
A plunger arrives every time
Arrival times are consistent
You have a flat decline
You achieve the lowest casing pressure possible
Increased production is dependent on IPR and liquid.
This is the challenge of the near future, but it
can be managed with plungers
Arkoma West- Well Profile Representation(15% Of Total Horizontals)
6500
7000
7500
8000
8500
9000
9500
10000
10500
11000
7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000
Measured Depth (Ft.)
TVD
(Ft.)
Surdahl 1-11H
Schmitt 1-1H
Sundown 2-20H
Sundown Ranch 2-17H
Louise 1-1H
Loftis 1-2H
Linda 1-32H
Walkup 3-27H
Waccaw 1-15H
Burleson 2-1H
LLN 1-26H
Powell 2-5H
Steinsick 2-14H
Gleese 1-28H
Horizontal Wells – Are they mature
yet? The drilling Machine
The present day inventory of loaded and shut in horizontal wells that
are much more difficult to operate than vertical wells. ( You have
that horizontal lateral that contains many, many barrels of fluid that
when you go vertical the well is dead before the liquid reaches surface)
Tubing completions complicate the issues
Questions now and later?
I like to talk about Plungers
I am biased to plungers if I can make them work
I believe plungers are the most effective and economical tool for
deliquification
Thank You
Gordon Gates - Consultant
409 504 2584
