SIPES Houston: 2015 CES

1. Michael R Berry, PE
Dwiggins Consulting, LLC
mike.berry@dwigginsconsulting.com
+1-405-694-9950
9/25/2015SIPES Continuing Education Seminar

2. Layman’s Guide to
Artificial Lift
• Gas Lift
o Put a bunch of holes in the tubing then pump gas down the
annulus and hope something comes out the tubing
• Velocity Strings
o Just keep making the tubing smaller
o In the right well, you can just stop using scale inhibitor
• Plunger Lift
o Just drop a plug down the tubing and it will float up on a gas
bubble – kind of like perpetual motion
• Rod Pump
o Visualize on old western hand pump with a really long rod…
• Progressing Cavity Pump
o Pulling those rods up and down is too much work, just rotate ‘em
9/25/2015SIPES Continuing Education Seminar 2

3. Layman’s Guide to
Artificial Lift
• Hydraulic Piston Pump
o Rotating rods is ridiculous and only a Canadian would consider it
o The problem is we are pulling the plunger from the top, let’s push
from the bottom instead!
• Jet Pump
o Just knock a hole in the bottom of your tubing and then squirt
water past it to the surface – no, really! It will work!
• Electric Submersible Pump
o Simply put a 4000 volt motor on an 8000’ extension cord in a well
full of pressurized salt water. What could possibly go wrong?
9/25/2015SIPES Continuing Education Seminar 3

4. High Rate vs. Depth Capacity
9/25/2015SIPES Continuing Education Seminar 4

5. Low Rate vs. Depth Capacity
9/25/2015SIPES Continuing Education Seminar 5

6. Lift Methods by Cost
• Free
o Natural flow
• Practically Free
o Plunger lift
• Cheap
o Gas lift w/ HP gas source
o Progressing cavity pump on elec. motor
o Rod pump w/ inventory pump jack
• Not so cheap
o Progressing cavity pump on hydraulic drive
o Rod pump w/ new pump jack
9/25/2015SIPES Continuing Education Seminar 6

7. Lift Methods by Cost
• Not cheap at all
o ESP on utility grid
o Jet or hydraulic pump on utility grid
• You are going to make your vendors very happy
o ESP via generator
o Gas lift via compressor
o Jet or hydraulic pump using engine power or generator
9/25/2015SIPES Continuing Education Seminar 7

8. Natural Flow
Advantages Disadvantages
• Defers cash
expenditures
• Puts less stress on the
completion
• Flowing period can be
extended by reducing
flow conduit cross-
sectional area
• Minimal wellhead foot-
print w/ no moving
parts
• May not provide
optimum rate
• May be difficult to re-
start flow if well dies
9/25/2015SIPES Continuing Education Seminar 8

9. Gas Lift
9/25/2015SIPES Continuing Education Seminar 9

10. Gas Lift
Advantages Disadvantages
• High rate
• Very tolerant of high GLR,
sand, corrosion & doglegs
• Relatively easy on
completions
• Easy, forgiving operation
• Small wellhead footprint
w/ no moving parts
• Valves can be wireline
retrievable
• Full bore tubing access
• Compressors can be
noisy, expensive and
hard to operate
• More economic on large
scale projects (multi-well}
• Low drawdown (~0.1
psi/ft)
• Needs larger tubing /
casing for high rates
• Doesn’t like high back-
pressure or fluid viscosity
(<15°API)
• Can be hard to optimize
9/25/2015SIPES Continuing Education Seminar 10

11. Plunger Lift
9/25/2015SIPES Continuing Education Seminar 11

12. Plunger Lift
Advantages Disadvantages
• Doesn’t require external
energy
• Inexpensive installation &
maintenance (rig
generally not required)
• Tolerates high GLR &
doglegs
• High drawdown
• Keeps well cleaned of
paraffin deposits
• Small wellhead footprint
w/ no moving parts
• Low rate (<200 bpd)
o Need to maximize tbg/csg
• Has minimum GLR &
static BHP requirements
• Doesn’t like solids or
scale
• Requires surveillance to
optimize
• Deviation limited to
~60°
9/25/2015SIPES Continuing Education Seminar 12

13. Reciprocating Rod Pump
9/25/2015SIPES Continuing Education Seminar 13

14. Reciprocating Rod Pump
Advantages Disadvantages
• Well understood lift
method
• Widespread
infrastructure
• High drawdown
• Low OPEX
• High system efficiency
• Surface units can be
moved between wells
• Rate easily adjusted
through stroke length
and speed
• Rate capacity decreases
with depth & tubing size
• Doesn’t like gas, sand or
doglegs
• High initial CAPEX
• Requires either utility grid
or maintenance of IC
engine
• Large wellhead footprint
w/ large moving parts
• Potential for stuffing box
leaks
• IC engine can be noisy
9/25/2015SIPES Continuing Education Seminar 14

15. Progressing Cavity Pump
9/25/2015SIPES Continuing Education Seminar 15

16. Progressing Cavity Pump
Advantages Disadvantages
• Tolerates high viscosity
• Can pump high sand
fractions (>30%)
• High drawdown
• Low operating &
capital cost
• Can be very efficient
• Low power
consumption
o Solar powered possible
• Moderate wellhead
footprint
• Elastomers limited to ~250°F
• Elastomers intolerant of high
API crudes (35-40°)
• Doesn’t like high GLR or
doglegs
• Rate capacity drops with
depth & tubing size
• Realistic TDH around 6000’
• Intolerant of being pumped off
• Requires either utility grid or
maintenance of IC engine
• Has moving parts at wellhead
and potential for stuffing box
leaks
• IC engine can be noisy
9/25/2015SIPES Continuing Education Seminar 16

17. Hydraulic Piston Pump
9/25/2015SIPES Continuing Education Seminar 17

18. Hydraulic Piston Pump
Advantages Disadvantages
• High drawdown
• Good depth capability
(15,000’ or more)
• Easy to pull/run pumps
• Unaffected by doglegs
or deviation
• Can produce multiple
wells from a single
surface installation
• Small wellhead
footprint w/ no moving
parts
• Doesn’t like solids or gas
• Requires maintenance of
downhole PD hyd. pump
• Requires maintenance of
surface hyd. pump
• High pressure hyd. lines at
surface
• Needs two flow conduits
• Needs larger diameter
tubing/casing for high rates
• Requires either utility grid or
maintenance of IC engine
• Surf. hyd. pumps are noisy
• IC engine can be noisy
9/25/2015SIPES Continuing Education Seminar 18

19. Hydraulic Jet Pump
9/25/2015SIPES Continuing Education Seminar 19

20. Hydraulic Jet Pump
Advantages Disadvantages
• High rate
• Tolerates solids
• No moving parts
• Easy to replace/resize
nozzles
• Unaffected by doglegs or
deviation
• Can produce multiple
wells from a single surface
installation
• Small wellhead footprint
w/ no moving parts
• Low drawdown
• Doesn’t like gas
• Low power efficiency
• Needs two flow conduits
minimum, three to vent gas
• Needs larger diameter
tubing/casing for high rates
• Requires maintenance of
surface hyd. pump
• Requires either robust utility
grid or maintenance of IC
engine
• High-pressure hydraulic lines
at surface
• Surface hyd. pumps are
noisy
9/25/2015SIPES Continuing Education Seminar 20

21. Electric Submersible Pumps
9/25/2015SIPES Continuing Education Seminar 21

22. Electric Submersible Pump
Advantages Disadvantages
• High rate, high
drawdown
• Suitable for moderately
deviated wells
• Useful for well testing
• Small, wellhead footprint
w/ no moving parts
• Can tolerate some gas
o <10-20% by volume at intake
• Can tolerate some solids
o <6% by weight
• Can resist corrosion w/
proper trim selection
• High CAPEX & OPEX
• Unforgiving operation
• Doesn’t particularly like
free gas, abrasives, scale
or high viscosity
• Rate capacity decreases
with depth & casing size
• Requires robust utility grid
or maintenance of
generator
• Generators can be noisy
• High voltage at wellhead
9/25/2015SIPES Continuing Education Seminar 22

23. Artificial Lift Methods Limits
9/25/2015SIPES Continuing Education Seminar 23

24. Why does lift method matter?
• As production engineers our job is to maximize the
value of the properties we are responsible for
o Yes, yes. Safely, legally, and in an environmentally friendly way
• This is NOT the same thing as maximizing the
production rate or minimizing the lifting cost
• This means maximizing NPV, IRR, or whatever financial
criteria we select
• When we select an artificial lift method we want to
select the method that gives us the greatest financial
return for the property
9/25/2015SIPES Continuing Education Seminar 24

25. Don’t blindly maximize rate!
• Is maximizing rate by drawing a well down to
the point you are damaging a formation or
tearing up pumps, are you really making
more money?
o The answer could be yes
o But, you must compare alternative economics
9/25/2015SIPES Continuing Education Seminar 25

26. Don’t justify a lift installation
on days to payout!
• Maybe you have a great well & you are
destroying an ESP every 3 weeks but you can
pay for a new one in a week.
• You are making money, but are you maximizing
economics?
• A pump a week for that kind of well is maybe
$250K/week. Four pumps is $1MM.
• Maybe you could have used that money for
something else?
9/25/2015SIPES Continuing Education Seminar 26

27. The most best time to
consider a lift method?
• BEFORE YOU DRILL THE WELL!!!!
• If you put a 12° dogleg in a well at 1000’, you
are had as far as any rod lift method goes
• You may or may not be able to get an ESP
below doglegs greater that 10°
• You need a “tangent” section with a dogleg
< 6° to land an ESP
9/25/2015SIPES Continuing Education Seminar 27

28. Check your drillers’
heart health
• Tell them your high rate gassy wells need 7”
production casing!
o Smaller diameter casing/tubing restricts the
rate/depth capacity of all lift methods
o ESP’s need room for the gas to bypass the
equipment. Otherwise the gas must be ingested.
o Jet and hydraulic pumps require at least two flow
conduits. If you want to vent gas so the pumps don’t
have to ingest the gas, you need an extra flow path.
i.e. bigger casing!
9/25/2015SIPES Continuing Education Seminar 28

29. Don’t take no for an answer, at
least not without an argument!
• Run the economics
• Educate your drillers
• These days wells are drilled in 3 weeks or less
• Production has to deal with them for 30 years
or more
• If someone tells you time value economics
means nothing matters after X years, tell them,
“Well then, I guess we’ll just cut the reserves
off at X years too!”
9/25/2015SIPES Continuing Education Seminar 29

30. So how do we rationally
select an AL method?
• Understand well performance
• Eliminate methods that are not feasible
• Project production & expenses for each of the
remaining methods
• Run the economics
• Evaluate alternate scenarios
o Maximize rate with ESPs / gas lift / jet pumps vs. flowing until rates
drop into the rod pump range for example
• Don’t be afraid to think big, consider central
compression / hyd. power / elec. power
9/25/2015SIPES Continuing Education Seminar 30

31. Reasons not to use a technically
feasible lift method
• Government restrictions (BLM, EPA)
• Civic restrictions (residences, crop circles)
• Support infrastructure (nearest shop)
• Your personnel (will you need body armor?)
• Their personnel (are they competent?)
• Future lift methods
• Utility restrictions (power limits)
• Ambient conditions limitations (extreme
heat, cold)
9/25/2015SIPES Continuing Education Seminar 31

32. What about your
commitment?
• The most critical requirement for the success
of a new lift method is to get you field
personnel on board
o Make your case to the field and get their buy in
o Start with easier wells
• A new lift method is more work, it will mean
more long days, it will mean more
aggravation
• Will you take the time, do you have the time
to help your field personnel to become
proficient (past the first couple of installs?
9/25/2015SIPES Continuing Education Seminar 32

33. Conclusion
• Your best choice for artificial lift might not be the
method that gives you the highest production rate
• Design process:
o Pick the methods that are capable of producing your well
o Compare the economics of each viable method
o Pick the method with the highest return, adjusted for your
local circumstances
• If this is a new lift method:
o Sell it to field operations
o Don’t start with your most difficult well
• Provide continuous support/training for both old &
new lift methods
9/25/2015SIPES Continuing Education Seminar 33

34. Questions?
9/25/2015SIPES Continuing Education Seminar 34