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SP
SPE
1 337
Society
o
PetroIeu n
EngIneers
of
AI, E
Selection of rtificial Lift Method
Panel Discussion
Moderator: Buford Neely, Shell Oil Co
Sucker
Rod
Pumping
Submersible Pumping
Fred Gipson,
onoco
Bill Capps, Thums Long Beach Co
Gas Lift Hydraulic Pumping
Joe Clegg, Shell Oil
Co
Phil Wilson, Kobe Inc
©Copyrig ht 1981, Society of Petroleum Engineers of AIME
This paper was presented at the 56th Annual Fall Technical
Conference and Exhibition of the Society of Petroleum Engineers of
AIME, held in
San Antonio, Texas, October 5·7, 1981 The material
is subject to correction
by the author. Permission to copy
is
restricted to an
abstract
of
not more than 300 words. Write: 6200 N. Central Expressway,
Dallas, Texas 75206.
BSTR CT
This paper summarizes the opening remarks
of
the
panel
members on
a panel discussion of Select ion
of
Artificial
Lift Method . This
is
not a co-authored
paper in the
normal
sense.
It is
a paper with five
sections
each
section independently authored
by
a
pa
ne1 member,
RESERVOIR ND WELL
CONSIDER TIONS
In artificial l if t design the engineer
is
faced
with matching
artificial
l i f t
capabilities
and
the well
productivity so that an efficient l ift installation re
sults. With the increasing cost of energy, i t is be
coming more important that the best efficiency possible
be
obtained. In the typical artificial l i f t problem,
rate
Vs.
producing bottom-hole pressure
is plotted
one of
two
relationships will usually occur. Above
bubblepoint pressure, i t will be a straight line. Be-
low bubblepoint pressure, a curve as described by
Vog-
el will occur.
These two
types
of
productivity
rela
tionships are
shown
in Figure 1. Some types of arti- ;
ficial l i f t are able to reouce the producing pressure
to a lower level than other types.
The
reward for
achieving a lower producing pressure will depend on
the type of productivity
relationship. For
example,
a well in
a
reservoir with 2000 psi
reservoir
pressure
and
a producing pressure
of
500
psi will
be
producing
75 percent of the
maximum
rate if the well has a
straight line productivity relationship.
On
the other
hand, if it
is
following a Vogel curve relationship
i t will be producing gO percent of the maximum rate.
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Selection
of
Artificial Lift Method
SP ·1 337
short term but
spend
large amounts of capital
dollars
in changing equipment. The design engineer must con
sider both long term
and
short term aspects. Our
aim
is
to
maximize the over1ife efficiency of the opera
tion.
This mayor
may
not
anticipate
a
l i f t
system
change in the future.
SUCKER
ROD
PUMPING
Sucker rod pumping systems are the
oldest
and most
widely used type of artificial
l ift
for oil wells. In
fact, approximately
85
percent of artificially
lifted
wells are produced by beam pumping equipment.
About
79
percent of the oil wells make
less
than 10
barrels
of
oil
per
day and
are classified as
stripper
wells. A
vast majority of these
stripper
wells are
lifted
with
sucker rod pumps.
Of
the remaining
26
percent, about
20
percent are
lifted
with sucker rod pumping systems,
28 percent are flowing and the remaining 52 percent
are lifted by gas l i f t submersible electric pumps
and
subsurface hydraulic
pumps.
Sucker
rod pumping
systems should be considered
for
new,
low
volume
stripper
wells because operating
p ~ r s o n n e l are usually familiar with these
mechanically
slmple systems
and can
operate them more efficiently.
Inexperienced operating personnel operate this type of
equipment with greater
effectiveness
than other types
of artificial lift . Sucker rod pumping systems can
operate efficiently over a
wide
range of well produc
ing
characteristics.
Most of these systems have a
high salvage value.
Sucker rod systems should also be considered
for
lifting moderate volumes from shallow depths and small
volumes from intermediate depths. If the well fluids
do not contain hydrogen sulfide, or
if
specialty sucker
rods are used,
i t
is possible to
l if t
1,000
barrels
from
about 7,000
feet
and 200
barrels
from
approximate
ly 14,000 feet.
If
the well fluids contain hydrogen
sulfide, sucker rod
pumping
systems can
l i f t
1,000
barrels of
liquid
per
day from
4,000 feet
and 200
One
of the disadvantages of a beam
pumping
system
is
that the polished rod stuffing box can leak. How-
ever,
i f
proper design
and
operating criteria
are
con
sidered
and
followed, that disadvantage can be minimiz
ed.
G S LIFT
Gas l if t
dominates the Gulf Coast of the US as
a means
of artificial
l i f t and
is
used extensively
around the world. Most of these wells
are
on
constant
flow gas l ift . Thus, the questions: Why choose gas
lift? , Where
do
you use constant flow?
and
When
do
you
select
intennittent
lift?
Constant Flow Gas l i f t
Constant flow
gas l ift is recommended for
high
volume and high static bottom hole pressure wells
where major
pumping
problems
will
occur.
It
is an
excellent
application
for offshore clastic-type for
mations with water drive, or waterf100d reservoirs
with good PI's
and
high GOR's. When high pressure
gas
is
available without compression or where gas is
low in cost, gas
l i f t
is especially attractive.
Con-
stant
flow
gas l i f t
uses the produced gas with addi
tional injection allowing the producing gradient
to
be
lowered so tha t the well will flow
much
better.
It
should be obvious that a reliable, adequate
supply
of
good quality high-pressure
l i f t
gas is
mandatory. This supply is necessary throughout the
producing life,
if
gas
l i f t is
to be effectively main
tained.
In many
fields
the produces gas declines as
the well's water cut increases;
thus,
requiring some
outside source of gas. Also the wells will produce
erratically
or not
at
all when the l i f t supply stops
or pressure
fluctuates radically.
Furthermore, poor
quality
gas will impair or even stop production.
Thus
the basic requirement for gas must be met or other
artificial l i f t
means
should be installed.
Constant flow gas l if t imposes a relatively high
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SP 1 337
Selection
Of rtificial ift ethod
3
3. Gas l i f t permits the
use, of
wireline equip
ment and
such equipment
is easily
and economically
serviced.
This
feature allows
for
routine repairs
through the tubing.
4. The
normal
design leaves the tubing
full
open
ing. This permits
use
of BHP surveys,
sand
sounding
and
bailing, production logging, cutting paraffin, etc.
5. High formation GOR's are helpful rather than
being a hindrance. Thus in gas l i f t less
injection
gas
is
required; whereas. in all
pumping
methods,
pumped
gas reduces
efficiency drastically.
6. Gas
l i f t
is flexible. A wide range of vol
umes
and
lift
depths
can
be
achieved with
essentially
the same well equipment. In
some
cases, switching to
annular flow can also be easily accomplished to handle
exceedingly high volumes.
7. A central gas l if t system can
be easily
used
to service many wells or operate an entire field.
Centralization usually lowers
total capital
cost and
permits easier well control and
testing.
8. Gas 1
ft has
a
low
profile. The surface well
equipment
is
the same as
for
flowing wells except
for
injection
gas
metering.
The low profile is
usually
an advantage in urban environments.
9.
Well
subsurface equipment is
relatively
in
expensive
and
repair and maintenance of
this
subsurfacE
equipment is normally
low.
The equipment
is easily
pulled and repaired or replaced. Also major well
workovers occur infrequently.
10.
Installation
of gas l i f t is compatible with
subsurface safety valves and other surface equipment.
Use
of
the surface controlled subsurface safety valve
with the 1/4-inch control line allows easy shut-in of
the
well.
3. Adequate gas supply
is
needed throughout l ife
of
project. If the
field
runs out
of
gas or if gas
becomes
too expensive,
one
may have to switch to
another l i f t method. In
addition.
there must be
enough
gas
for easy
start-ups.
4. Operation and maintenance
of
compressors can
be expensive. Skilled operators and good compressor
mechanics are required for successful
and
reliable
operation.
5. There is increassd difficulty when
lifting
low
gravity
less than 15
API)
crude due to greater
friction. The cooling
effect
of gas expansion further
aggravates
this
problem. Also the cooling effect will
compound any
paraffin
problem.
6.
Low
fluid volumes in conjunction with high
water cuts less than 200 BPO in 2-3/8 00 tubing) be
come
less
efficient
to
l i f t and
frequently severe
heading is experienced.
7.
Good
data are required to make a good design.
Such
data
may
not be available
and you
limp along on
an
inefficient design that does not produce the well
near capacity.
The major factors to
be
considered
in
selecting
gas l i f t are listed in Table A. Also there are
some
potential problems
that
must be resolved.
1. Gas freezing and hydrate problems.
2. Corrosive
injection
gas.
3. Severe
paraffin
problems.
4. Fluctuating suction
and
discharge pressures.
5. Wireline problems.
6. Dual
artificial
l i f t frequently
results
in
poor
l if t efficiency.
7.
Changing
well conditions,
especially
decline
in BHP
and
PI.
8.
Deep
high volume l ift .
9.
Valve
interference - multipointing.
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4
election
of
rtificial li t ethod
SP 1 337
2. It
has
the ability to handle low volumes of
fluid with relatively low producing BHP s.
Limitations
1. Intermittent gas l i f t is limited to low vol
ume wells. For example
an
8,000 foot
we 11
with
2
nominal tubing can seldom be produced at
rates of
over
200
BPD with an average producing pressure
much
below
250 psig. Smaller sizes of tubing have even a lower
maximum
rate.
2. The average producing pressure
of
a conven
tional intermittent
l i f t
system is still relatively
high
when
compared to
rod
pumping.
However,
the pro
ducing BHP can
be
reduced by use of chambers. Cham-
bers are
particularly
suited to high PI,
low
BHP
wells
3. The output to input horsepower efficiency is
low. More gas is
used
per barrel of produced fluid
than constant flow. Also the slippage increases with
depth and water cut making the l if t system even more
inefficient. However, slippage
can
be reduced by use
of
plungers.
4. The fluctuation in rate and BHP can be detri
mental to wells with sand
control.
The
produced sand
may plug the tubing or standing valve. Also surface
fluctuations cause gas
and
fluid handling problems.
5.
Intermittent
gas l if t requires frequent ad
justments. The lease operator
must
alter the injec
tion rate and time period
routinely
to increase the
production
and
keep the used gas relatively low.
Conclusion
Gas
l if t
has
numerous
strengths
that
in
many
fields
make i t the best choice of artificial l i f t
However, there are
limitations
and
potential pro
blems to be
dealt
with. One has a choice
of
using
either constant flow for high volume wells or intet·
trols and associated producing facilities.
Method is quiet,
safe
and
sanitary for acceptable
operations in an offshore and environmentally
conscious area.
Generally considered a high
volume
pump
- pro
vides for increased volumes and water cuts
brought on
by
pressure maintenance and secondary
recovery operations.
Permits placing well on production immediately
after drilling and completion.
Permits continued well production even while
drilling
and
working over wells in immediate vic
inity.
Some
of the weaknesses of the submersible system
are
as follows:
Will tolerate only
minimal
percents of solids
(sand) production.
Costly pulling operations to
correct
downhole
failures
(DHF s).
While
on DHF there is a loss of production
during time well
is
covered by
drilling
opera
tions in immediate vicinity.
Not
particularly
adaptable to
low
volumes
-
less
than
150 ID
gross.
There have been a
number
of improvements to the sub
mersible system at Thums
that
have been implemented
over a sixteen year period
that
are responsible for
decreasing the failure rate from a high of
71
per
month in October 1969 (425 wells) to an average
of
29
per
month
in
1981 (564 wells).
These improvements
are
as
follows:
Feed
through mandrel
and
pigtail
system
Solid
state
controls.
Isolating transformers.
motor pothead and molded cable
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SP 1 337
Selection
of rtificial
ift ethod
5
power fluid (oil or water) is
d i ~ e c t e d
down the ~ a r g e
tubing
string
to operate the englne. The pump plston
or plunger
draws fluid
from the well.bore through
standing valve. Exhausted power fluld and productlon
are returned up the small
string
of tubing.
The
Jet Pump is shown
in Fig.
5. High
pressure
power fluid
is
directed down the tUbing to the nozzle
where the pressure energy is converted to velocity
head. The high velocity-low pressure power fluid en
trains the production in the
throat
of the pump. A
diffuser
then reduces the velocity and increases the
pressure
to
allow the
commingled
fluid to flow to
the surface.
The tubing arrangements in Fig. 4 and 5 are call-
ed
Open Power
Fluid systems. Fig. 4
is further
classi
fied as a Parallel installation with gas vented througt
the casing annulus to the surface. Fig. 5 is called
a Casing installation and requires the pump to handle
the gas. Both types are used with positive displace-
ment pumps and with Jet
Pumps.
In
fact,
most bottom
hole assemblies
can
accomodate interchangeability Jet
Pumps and
positive displacement pumps.
Fig. 6 shows a positive displacement pump a
Closed
Power
Fluid arrangement. Here, power fluld
is
returned to the surface seperately
from
the pro
duction. Because the Jet
Pump
must commingle the
power fluid and production, it cannot operate
as
a
Closed Power Fluid pump.
The most outstanding feature of hydraulic pumps
is the FREE
PUMP
as illustrated in Fig.
7. The
draw
ing on the left shows a standing valve
inserted
by
wireline) at the bottom of the tubing
and
the tubing
filled
with fluid. In the second drawing, a pump has
been inserted in the tubing
and is
being circulated to
the bottom. In the third drawing the pump is on bot-
tom
and pumping.
When
the
pump
is
in
need
of
repair,
i t
is
circulated to the surface
as
shown in the draw
ing on the right. Figs. 4, 5, and 6 are
all FREE
PUMPS
In some cases, two
pumps
have been inatalled in
one tubing string. Seal collars in the bottom hole
assembly connect the
pumps in parallel
hydraulically.
Thus, the maximum displacement values shown above
are
doubled.
A tabulation of capacity vs. l i t is not practi-
cal for Jet Pumps because of the variables
and their
complex
relationships.
To
keep
fluid
velocities below
50
Ft/Sec. in suction and discharge passages, the max
imum
production
rates
vs. tubing
size
for Jet FREE
PUMPS are approximately:
TUBING
2-3/8
2-7/8
3-1/2
PRODUCTION B/D
3000
6000
10000
Fixed type Jet Pumps (those too large to fi t
inside
the tubing)
have
been
made
with
capacities
to
17,000 B/D.
Even larger
pumps
can
be made. Maximum
lifting
depth for
Jet
Pumps is around 8000-9000 feet
i
surface
power
fluid pressure is limited to 3500
PSI.
The maximum capacities
listed
above
can
be
ob
tained only to about 5000-6000 feet. These J ~ t P u m p
figures
are only guidelines because well condltlons
and
fluid
properties can have significant influences
on
them.
It
should also
be
noted
that
the
maximum
capacities listed above are for high volume Jet
Pumps
that require bottom hole assemblies that
are
not
capable of also accomodating piston pumps.
Advantages
of
hydraulic pumps are:
1.
2.
FREE PUMP - Being able to
circulate
the pump in
and
out of the well is the most obvious
and
signi-
ficant feature of
hydraulic
pumps. It is
especi
ally attractive on offshore platforms, remote lo-
cations,
populated areas
and
in
agricultural
areas
Deep
Wells -
Positive
displacement pumps are
capable of pumping depths to 17,000 feet, and
deeper.
Working
fluid levels
for
Jet
Pumps
are
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TABLE
Jj
GAS
LIFT
WHAT
ARE
THE FACTORS
TO
CONSIDER?
I.
CAPITAL COST
:f
I.
OPERATING COST
III OPERATING
REVENUE
MAJOR ITEMS:
GAS AVAILABILITY
WELL PI
VOLUMES: BOD BWD MCFD
BHP
TYPE RESERVOIR DRIVE
SUPPLEMENTAL
RECOVERY PLANS
~ L U I
PROPERTIES
(PVT)
MAXIMUM
PVP(AT)
OVER
TOTAL
LIFE
WELL DATA
(DEPTH,
TUBULARS,
PROD. INTERVALS)
ANTICIPATED
PRODUCTION CHANGES
(BHP, PI,
GOR, CUT)
SAND,
SCALE,
CORROSION, WAX
ENERGY SOURCE AND COST
SURFACE GATHERING AND HANDLING
EQUIPMENT
SIZE OF FIELD
LOCATION
GOVERNMENTAL
RULES AND REGULATIONS
ENVIRONMENTAL AND
SAFETY
PRACTICES
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UJ
U J
u
o
o
2
3
PRESSURE 100
PSI
2 14 16 18
I I i
X BPD X ~
HHP
=
135,g00 X FG
SG X BPD X (FG X DP P
WH
- PIP
HHP
= .. . J...
135,800
X FG
EFFICIENCY - 100 HHP/INPUT
HP
vJhere:
SG
= Specific Gravity
BPD = Barrels Per Day
t: P = Pressure Increase across
Pump - Psi
FG
= Fluid Gradient -
Psi/ft
DP
=
Depth
of
Pump
-
f t
P
wh
= Wellhead Pressure - psia
.97
X qOO X
.Q2
X
6000+100-2 0)
135,800 X .42
=
100
X
16.5/50*
=
33
PIP = Pump Intake Pressure -
psia
PDP = Pump Discharge Pressure -
psia
*ASSUMES: 2 X PRHP
4 - TD
=
Total
Depth
- f t
P
wf
= Producing
BHP
-
psia
P
=
Average
Reservoir Pressure - psia
9
:r:
0
U J
£::)
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LW
u.J
u
o
o
2
3 -
~
c
I
I
Pc
I
I
I
I
I
I
I
PRESSURE, 100 PSI
12
14
16 18
I I i
SG X BPD x.6.P
HHP = e
135,800 X
FG
SG X BPD X (FG X DI +
P
WH
- )
HHP
=
~ ~ I
135,800 X FG
EFFICIENCY
=
100 X HHP/INPUT HP
EXAMPLE:
.97 X
400
X
(.42
X 6000 +
100
- 90 )
135,800 x
.42
.
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FLUID LEVEL
ENGINE
P
Fig. 4 Positive displacement pump
CH MBER
THRO T
DIFFUSER
COMBINED
FLUID
RETURN
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SHUT OFF
ND LEED
POWER
OIL
UN
FLOW
LINE
ST NDING
V LVE
CLOSED
PUMP IN
At
ST NDING
V LVE
CLOSED
OPER TE
ftL
I
ST NDING
V LVE
OPEN
Fig. 7 Free pump operation
PUMP OUT
ftL
ST NDING
V LVE
CLOSED
