Guidelines & Recommended Practices

tobascothwackUrban and Civil

Nov 15, 2013 (3 years and 8 months ago)

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2.3
a

Sucker Rod Pumping


This
section
discusses the practical limits of
sucker rod pumping

in terms of
liquid production rate, gas production rate, depth, pressure, temperature, etc.

It presents

rough guidelines on the relative costs
sucker rod pumpi
ng
. Obv
i-
ously precise costs can not be given as they depend on many factors.
It

presents rough guidelines on the relative life expectancy of
sucker rod pum
p-
ing
. Clearly, precise expectations can not be given as they depend on many
fa
c
tors.




Practical Li
mits



-

Depth limits

-

Size limits

-

Pressure limits

-

Temperature limits

-

Rate limits

-

Limits with sand, corrosion, erosion, H
2
S, CO
2
, etc.

-

Power requirements

-

Operating requirements

-

Maintenance requirements




Cost Guidelines


-

CAPEX

-

OPEX

-

R&M




Life Expectancy Guideli
nes


-

Infant mortality (early time failure)

-

Normal operating life





Practical Limits for Sucker Rod Pumping





Cost Guidelines for Sucker Rod Pumping





Life Expectancy Guidelines for Sucker Rod Pumping



Guidelines & Recommended Practices

Selection of Artificial Lift Systems

f
or Deliquifying Gas Wells

Selection of Artificial Lift Systems for Deliquifying Gas Wells

Page
2



Much of below is from:

Beam Pumping Systems: By J F L
ea, PLTech LLC & Lynn Rowlan, Echometer Co.

Published in Rogtec Magazine


Introduction:

Sucker rod pumping systems are the oldest and most widely used type of artificial for
oil wells. Figure 10
-
3 shows a schematic of a rod pumping system.




There are
about 2 million oil wells in operation in the world. Over 1 million wells ut
i-
lize some type of artificial lift. Over 750,000 of the lifted wells use sucker rod pumps. In
the U.S. sucker rod pumps lift about 350,000 wells. About 80 percent of all U.S. oil w
ells
are stripper wells, making less than 10 bpd with some water cut. A vast majority of
stripper wells are lifted with sucker rod pumps.

























Figure 1: Simplistic Beam Pump System




Beam Pump System Considerations and Advantages/Di
sadvantages:




Sucker rod pumping systems should be considered for new, lower volume stripper
wells because they have proved to be cost effective over time. In addition operating
personnel are usually familiar with these mechanically simple systems and ca
n ope
r-



Selection of Artificial Lift Systems for Deliquifying Gas Wells

Page
3



ate them more efficiently. Less experienced personnel also can often operate rod
pumps more effectively than other types of AL. Sucker rod pumping systems can o
p-
erate efficiently over a wide range of production rates and depths. Sucker rod systems
have a high salvage value.




Sucker rod systems should be considered for lifting moderate volumes from shallow
depths and small volumes from intermediate depths. It is possible to lift up to 1,000
BPD from about 7,000 feet and 200 barrels from approximatel
y 14,000 feet (special
rods may be required and lower rates result depending on conditions present). More
commonly less might be lifted from 7,000 feet and few wells lifted by Beam below
10,000 ft.




Most of the parts of the sucker rod pumping system are m
anufactured to meet existing
standards, which have been established by the American Petroleum Institute (API).
Numerous manufacturers can supply each part, and all interconnecting parts are co
m-
patible. Also there are many components that are manufactured

and used that are not
API certified, such as larger (and smaller) diameter downhole pumps extending b
e-
yond API sizes.





The sucker rod string is the length of the rods from the surface to the down hole pump
and it is continuously subjected to cyclic load
fatigue typical of sucker rod pump sy
s-
tems. The system must be protected against corrosion and from damage from ru
n-
ning/pulling more than any other AL system, since corrosion introduces stress co
n-
centrations that can lead to early failures. Special high s
trength and fiberglass rods are
available.




Sucker rod pumping systems are often very incompatible with deviated (doglegged)
wells, even with the use of rod protectors, and rod and/or tubing rotators. However
deviated wells with smooth profiles and low do
gleg severity may allow satisfactory
sucker rod pumping, even if the angle at the bottom of the well is large (~30
-
40


and
some up to 80

). Some high angle hole systems employ advanced methods of pr
o-
tecting the tubing and rod string with rod protectors an
d “roller
-
rod protectors” while
other installations with high oil cuts, smooth profiles, and lower angles of deviation
use only a few of these devices. Plastic lined tubing has been shown effective in r
e-
ducing rod/tubing wear.




The ability of sucker rod p
umping systems to produce sand laden fluids is limited,
although there are several special filters and sand exclusion devices available. Some
pumps are designed to either exclude the sand or continue to operate as the sand tra
v-
els through the barrel
-
plung
er clearance. Special pump metallurgies are employed for
fine sand wear.




Paraffin and scale can interfere with the efficient operation of sucker rod pumping
systems. Special wiper systems on the rods and hot water/oil treatments are used to
combat paraf
fin. Hard scales can cause early failures.


Selection of Artificial Lift Systems for Deliquifying Gas Wells

Page
4





Free gas entering the down hole pump reduces hydrocarbon production and causes
other problems. See
WWW.Echometer.com

and select papers related to gas separation for
info
rmation on this subject.




One of the disadvantages of a beam pumping system is that the polished rod stuffing
box (which is where a polished rod with the rods hung below enter the well at the su
r-
face through a rubber packing element) can leak. This can b
e minimized using sp
e-
cial pollution free stuffing boxes that collect any leakage. Good operations with
sta
n
dard boxes, such as “don’t over tighten”, and “insure unit alignment”, are also
impo
r
tant.




Continuous production with the system attempting to prod
uce more that the reservoir
will produce leads to incomplete pump filling of the pump, “fluid pound”, mechanical
damage and low energy efficiency. Many systems are designed to produce 120
-
150%
more than the reservoir will produce but when the well is pumpe
d
-
down, a POC
(pump
-
off controller) will stop pumping temporarily to allow fluid entry into the ca
s-
ing
-
tubing annulus over the pump before automatically restarting.


In general, sucker
-
rod pumping is the premier method of AL that should be used if the
sys
tem can be designed without overloading the prime mover, gearbox, unit structure,
and the calculated fatigue loading limits of the rods. Many feel you should justify why
not to use Beam systems if possible.


Surveillance and Automation:



Typically beam p
ump surveillance consist of a pump off controller (POC) monitoring one
or more parameters of the sucker rod pumping system and shutting down the pumping
unit when one of the parameters exceeds a limit set by the operator. Common parameters
monitored to de
tect pump off can include polished rod load and position, electrical cu
r-
rent, pumping unit change in RPM and flow line pressures. Loads are used to evaluate
loads on the unit, gearbox, motor, and rods. SPM and stroke length (with pump diameter)
relate to
production capacity. One common use of pump off controllers is to detect i
n-
complete pump fill and then turn the pumping system off for a set downtime. The pump
off controller usually starts the pumping system after a predetermined downtime. This
off and

on cycle is repeated throughout the day and generally reduces both operating time
and operating expense without the loss of oil production. POC is used so that if fluids are
pumped down in the casing/tubing annulus to the pump intake, the unit can be shu
t down
for a time to allow fluids to build in the annulus and the system to pump with a pump that
is mostly filled with liquids.


The collected information is analyzed and the unit is controlled using the controller (A) in
the below figure and the results

can be transmitted. The load at the top of the top rod is
measured by a load cell (B) between the carrier bar and the PR clamp. The Position in the
stroke is measured by some sort of position indicator shown as (D) below. Position can
also be checked by a

one point pickup as the cranks pass a sensor during the pumping
Selection of Artificial Lift Systems for Deliquifying Gas Wells

Page
5



cycle. Shown below is (E) which is older style strain gage used to monitor loads as done
more exactly by (B).










A
-

Rod Pump Controller

B
-

Polished Rod Lo
ad Cell

C
-

Position Sensor Switch, for Pump
-
Off Control

D
-

Optional Continuous Position Transducer for
Downhole Analysis

E
-

Optional Beam
-
Mounted Strain Gauge


Figure 2: Instrumented Beam Pump System (Courtesy Weatherford, EP Systems)





One technique

is to monitor the load/position plot (surface dynamometer) as shown b
e-
low and as the downhole pump becomes less filled (pumped off) a set point can be input
and when passed, the controller can shut the unit down to allow fluid to once again build
in the w
ell before pumping begins again.



A

B

C

D

E

Selection of Artificial Lift Systems for Deliquifying Gas Wells

Page
6







It is noted that some controllers calculate a so
-
called downhole dynamometer card (using
calculated loads and positions in the rod just above the pump and use the downhole d
y-
namometer card

to determine when pump
-
off or incomplete fillage is occurring.


The below figure shows (3) sequences of top and bottom hole dynamometer cards as the
pump is completely full, about 20% incomplete fillage is occurring in the pump at 30
seconds and finally
about 50% incomplete fillage is occurring in the pump at one minute,
as the pump lowers the fluid level to the pump intake and gas enters the pump with li
q-
uids. A POC system might perhaps stop the unit from pumping, at about 25% incomplete
fillage and allo
w the unit to wait until fluids build downhole before starting again.















Selection of Artificial Lift Systems for Deliquifying Gas Wells

Page
7











Figure 3: Surface and Bottom Hole Dynamometer Cards progressing from Full, to about
80% pump fillage to about 50% pump fillage. A POC would have shut the well in w
hen
pump about 85% full or 15% filled with gas.


The production of sand, extremely cold temperature or lack of electric power usually
means the sucker rod pumping system must operate 100% of the time without POC.






Pumping Speed and Stroke Length Cons
iderations:


To produce a specific volume of liquid to the surface the Sucker Rod Pumping system is
very flexible. For a particular production rate and set of well conditions there are many
possible combinations of stroke lengths, strokes per minute, plun
ger diameter, pump se
t-
Selection of Artificial Lift Systems for Deliquifying Gas Wells

Page
8



ting depth and rod string taper designs. Without overloading the surface equipment or
the rod string the designer can select different combinations of these parameters that r
e-
sult in the exact same downhole pump displacement. The e
xpected liquid inflow flow
rate from the formation at low producing bottom hole pressure is used to determine the
pump displacement. Common practice is to size equipment to produce anywhere within
a range of 90% to 150% of the maximum flow rate possible f
rom the well. With all of
these combinations possible the sucker rod system designer often defines a particular
combination of parameters as the best design practice for his field. His design results in
the lowest operating cost or highest operating prof
it for this particular set of field cond
i-
tions. But in other locations this best design practice for one field will result in too high
of failure rates, too high initial cost, and too high operating cost.


Different locations through out the world desi
gn very different sucker rod configurations
for the exact same downhole pump displacement. High pumping efficiency is maintained
when the pump is filled with fluid on each pump stroke. Effective use of a POC requires
that pump displacement exceed inflow
from the well and that the well not operate 100%
of the time for each day. In the initial design larger plunger diameters are frequently used
to increase pump displacement in order to pump the well off and utilize the POC’s fe
a-
tures. But if personal pref
erence or well conditions prevent the on and off pumping c
y-
cle, then designing for 150% of the maximum well inflow from the well using a large d
i-
ameter pump would be a bad practice. Pumping with a pump filled with fluid is still i
m-
portant when the decisi
on is made to operate 100% of the time and slow pumping speeds,
longer stroke lengths and smaller plunger diameters are specified to efficiently produce
the well.


The best practice for the selection of pumping speeds, stroke lengths, and plunger sizes
should result in a run life of the rods, pump and tubing downhole system in a well to e
x-
ceed 3 years between failures. When rod on tubing wear and rod parts are a problem,
then a longer and slower stroke per minute with a smaller plunger size may reduce r
od
overloading and rod buckling problems and increase run life. When surface equipment
overloading is a problem, then shorter stroke lengths and larger plunger sizes with i
n-
creased pumping speed will reduce gearbox failures due to torque overloads. Frequ
ently
sucker rod failures are caused by factors other than the selection of pumping speeds,
stroke lengths, and plunger sizes and these factors must be corrected before making
changes to the operational design parameters. When the pump is not filled with
fluid due
to gas interference then actions are required to prevent gas from entering the pump, just
higher compression ratio due to increasing the stroke length is not enough to prevent fai
l-
ures. Downhole equipment failures due to corrosion or foreign mat
erial sticking the
pump requires proper chemical treatment to prevent these type of failures, just changing
the operational design parameters will do little to reduce these type of failures.


Rod Buckling Considerations:


Rod buckling can be aggravated b
y dynamic effects in the rod string, friction between the
plunger and the barrel on the down stroke, flow through the traveling valve on the dow
n-
stroke, perhaps by tight spots in the tubing, and apparently by fluid pound in some cases.
Selection of Artificial Lift Systems for Deliquifying Gas Wells

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9



Rod buckling is not
influenced by the increasing hydrostatic pressures versus depth or not
by buoyancy force of being submerged in fluid, but only influenced by forces applied to
the rods by the pump or external forces acting on the rods.


The force required to buckle rods o
f various sizes is shown in the following table:































Figure 4: Local forces needed to buckle sucker rods of various sizes.


Note for most commonly used rod sizes, the force to buckle rods is less than 100 lbfs so
the force neede
d to move the rods to contact the tubing on the downstroke is not large
and once buckling more wear can occur between the rods and tubing. Obviously a force
well in excess of the buckling force may accelerate rod/tubing wear.


Common practice is to put pe
rhaps 200
-
300 ft of larger diameter sinker bars above the
pump where plunger/barrel resistance and perhaps fluid pound can occur causing
rod/tubing wear. Flow less severe wear experienced, rod guides may be used in place of
sinker bars by some operators.


Selection of Artificial Lift Systems for Deliquifying Gas Wells

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10





Design: Motor, Pumping Unit, and Rod String

Sucker Rod System design programs are useful when setting up new installations; they
are used to select a pumping unit, design the rod string taper, and a size the pump for new
wells. The designer can easily
evaluate which pumping speed and stroke will yield the
desired production without overloading the rods, beam, and gearbox. Another use of
predictive design programs is to check an existing pumping system, to verify that the
measured loads match with the p
redicted loads. The calculated fluid load, Fo, applied to
the rods by the pump and the weight of the rods in fluid, Wrf, should match very closely
(within 1
-
3%) to the values measured at the well. If Fo and Wrf measured and calculated
do not match closel
y, then any of the other predicted parameters are likely to be in error.
Once these two values match, then other effects such as of motor slip, fluid inertia, and
partial fillage can be important in getting a good match between the predicted and mea
s-
ured
conditions. Production rate and pump intake are related by the inflow relation ship
of the well and accurate modeling of rod loading depend on the fluid load which depend
on the pump intake pressure determined from the desired production rate based. Mat
c
h-
ing measured data with predicted calculations depend on modeling all parameters well.
Motor performance curves with slip effects may needed to be used to determine the a
c
t
u-
al speed of the system if the motor is heavily loaded and large speed variations
occur du
r-
ing a stroke. The motor/pumping unit slows down as the torque increase and speeds up
when the net gear box torque decreases, thereby affecting rod load and positioning of the
peak loading. Peak load, pump and polished rod horsepower and pump str
oke should be
predicted with
-
in 2% of measured data. Predicted minimum rod load is usually higher
than actual measured. Peak gear box torque is usually higher than actual in
-
balance
gearbox loading and sizing of the pumping unit is usually large enough f
or the actual
loading that is experienced. Most predictive programs are well suited for designing a
sucker rod pumping system. QRod is a very widely used, program for the design and
prediction of the performance of Sucker Rod Beam Pumping Installations.

The QRod
software can be downloaded for installation and use on any numbers of PCs free of
charge from the web at
http://www.echometer.com/software/qrod/index.html

. It has
been found to
compare well with the basic design parameters measured in the field.


Analysis: Dynamometer Cards

Acquiring surface load and position data on sucker rod lifted wells using a dynamometer
transducer has been performed in the oil field for more than 50
years. Measured surface
dynamometer cards often do not allow the operator to make complete diagnostics of the
sucker rod lift system. Experience in a particular field can be used to associate certain
surface dynamometer card shapes to certain downhole pr
oblems. Current dynamometer
and computer technology result in very accurate measurement of load and position at the
surface and prediction of loads along the rod string and down to the pump. During the
1960s the rod string was mathematically modeled using

a wave equation, thereby using
the measured surface loads and position to "wave down" predicting a downhole dyn
a-
mometer pump card.


Selection of Artificial Lift Systems for Deliquifying Gas Wells

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11



The measured surface dynamometer card is the plot of measured polished rod load at p
o-
sitions throughout a stroke. Surfac
e dynamometer cards are valuable for diagnosing rod
loading, structural loading of the pumping unit beam, and torque loads on the gearbox
and prime mover. In shallow wells, the shape of the surface dynamometer card is usually
effective in diagnosing pump
performance. In most other wells, the complex dynamics
of the sucker rod pumping system reduces the effectiveness of diagnosing downhole
problems from only the surface dynamometer card. The pump dynamometer card is a
plot of the predicted load at positio
ns of pump stroke and represents the load the traveling
valve/pump plunger assembly applies to the bottom of the rod string. Identifying how the
pump is performing and analyzing downhole problems are the primary uses of the calc
u-
lated downhole pump card d
ynamometer plot.




















Figure 5: A calculated downhole pump card


The above pump card shape is for normal pumping with the pump filled with liquid with
very little gas present in the pump. The pump is functioning properly and the tubing a
p-
pears to be anchored. The maximum plunger travel, MPT, is the horizontal distance from
A
-
C. MPT is the maximum length of the plunger movement with respect to the pump
barrel during one complete stroke. The fluid load is the height of the vertical line la
beled
Fo and represents a force caused by the difference in tubing pressure minus intake pre
s-
sure acting across the pump plunger seal at the traveling valve. The fluid load acts across
the traveling valve on the upstroke and the tubing discharge pressure
is transferred to the
standing valve on the down stroke. The magnitude of the fluid load is equal to the pump
discharge pressure minus the pump intake pressure multiplied by the plunger area. From
points B to C the rods carry the fluid load, when the tra
veling valve is closed. From
points D to A the tubing carries the fluid load, when the standing valve is closed. The
distance from A
-
D is the effective plunger travel, EPT, and EPT is the length of the
plunger travel when the full fluid load is acting on

the standing valve.

Selection of Artificial Lift Systems for Deliquifying Gas Wells

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12




The successive steps in the pump operation are:

At the start of the upstroke (point A), the traveling valve and standing valve are both
closed. From point A to point B, the fluid load is fully carried by the tubing prior to point
A a
nd is gradually picked up by the stretched rods at point B. The load transfers as the
rods elastically stretch to pick up the fluid load. With the tubing anchored, the plunger
does not move relative to the tubing. The pressure in the pump decreases and
any free
gas in the clearance space between valves expands from the

tubing discharge pressure to
slightly less than the pump intake pressure. The standing valve begins to open at A, a
l-
lowing fluid to enter the pump when the pressure in the pump drops belo
w the intake
pressure. From point B to C, the fluid load is carried by the rods as well fluids flow into
the pump. At C, the standing valve closes as the plunger starts down, and the traveling
valve remains closed until the pressure inside the pump is sl
ightly greater than the pump
discharge pressure. From C to D, gas in the pump (if present) is compressed as the
plunger moves down to increase pressure on the fluid from the intake pressure to the di
s-
charge pressure in the tubing;
but the plunger does not

move if the pump barrel is full of
incompressible fluid.

As the fluid in the pump barrel is compressed, the fluid load is
gradually transferred from the rods to the tubing. At D, the compressed pressure inside
the pump barrel is greater than pump discha
rge pressure and the traveling valve opens.
From D to A, the fluid in the pump is displaced through the traveling valve into the tu
b-
ing on the down stroke and the closed standing valve holds the fluid in the tubing.


Many types of downhole problems may be

diagnosed through use of the pump card.
These problems vary from incomplete pump fillage due to over pumping the well or i
n-
complete pump fillage caused by gas being swept into the pump due to poor gas separ
a-
tion at the pump intake. Both the loss in load

caused by a leaking travel or the gain in
load caused by a leaking standing valve are easily identified by the curved shape of the
pump card when the valve should be closed carrying the load. These diagnostic pump
card shapes and many other shapes can be

seen on the web at
http://www.echometer.com/support/technotes/pumpcards.html





Some Simple Best Practices:


Design Rate in order to use POC:


Design Rate =
Desired Rate x 24 hr
/day (Using POC)


.80 VE x 20 hr/day

Example: Well can make 300 bfpd so what do you rate do you design the well
for?


Design Rate =
300 bfpd x 24 hr/day

= 450 bfpd


.80 VE x 20 hr/day

Selection of Artificial Lift Systems for Deliquifying Gas Wells

Page
13



Or in other words,

if you design for POC, design for about 1.5 times what the well
makes. If no POC, design for what well will make or slightly less if gassy. As
stated above these recommendations for POC design may be altered by the oper
a-
tor or under some conditions POC ma
y not be used.



Guidelines for Design Using Predictive Program:


1. Design with no additional load on pump

2. Use default dampening factors

3. A low pumped off level of about 50’ should be used. This will give maximum
load on pump.

4. 100 % pump load sh
ould be input. This also gives max loads on unit, and rods.

5. Use motor option for speed variation and use defaults for inertial values, etc.


Rod String Guidelines:


1. Use Grade D rods with T couplings or Spray Metal couplings if wear and ec
o-
nomics dic
tate. Grade “C” rods can be used in sinker bars larger than 1” in d
i
a
m-
eter.

2. High strength rods should only be used when absolutely necessary. EL high
strength rods do not have high strength pins. Use high strength couplings with
high strength rods. B
e cautious of slim hole couplings with high strength rods. Be
cautious of high strength rods when H2S is present.

3. All rods should be designed with loadings using your field established service
factor. Do not change from D rod to high strength rods unti
l rod loading on D
rods exceed 100% when using a 1.0 service factor.

4. Molded rod guides should be placed on any rods below the anchor or run
weight bars. NOT DO NOT RUN ROD GUIDES ON WEIGHT BARS!!

5. Use steel as opposed to fiberglass unless it can be
shown to be economical to
do otherwise.

6. Use lighter % loading with Fiberglass (~ 80%) using lowest temperature rating
. This usually shown in predictive program input/output. Fiberglass is used for
deep wells when rod loading is a problem. It is used w
ith some FG rods for pe
r-
haps 50
-
70% of the top of the string and steel rods for the bottom of the string to
keep the glass out of compression.

7. With Fiberglass, shear tools should be run on all wells that have shown any
tendency to sticking pumps.


Best

Practice for Pumps:


1. Use of larger pumps without overloading the unit and rods will result in a more
energy efficient installation.

2. Use a simple design. More complicated pumps fail more and cost more.

3. Use heavy wall pumps. Thin wall pumps have
less corrosion and pressure r
e-
si
s
tance.

Selection of Artificial Lift Systems for Deliquifying Gas Wells

Page
14



4. All pumps should be designed and built where the traveling valve is within 1”
of the standing valve when pump bottoms out on the clutch at the top.

5. Pump leakage should be in the range of 2
-
5% of production. H
igh water cut
wells should have more pump leakage. Deep wells can have pumps with smaller
clearances. Use new leakage equation with calculated downhole clearances.


Beam Pump Unit Best Practices:


1. The gearbox and the unit structure should not be loaded
more than 100%.

2. Use a predictive program to help size the motor. If program says a 32 HP motor
is needed and the next bigger available size in stock is 50 HP, then use the 50HP.
In general you loose significant energy only when the motor size exceeds a
bout
2X the correct size. Use only NEMA D motors.

3. Polish Rods: Spray metal polish rods without liners should be used in all CO2
flood beam lifted wells and corrosive wells. Water flood and primary wells can
use either a liner on the polish rod or a spr
ay metal polish rod.



Tubing Best Practice (with beam pumping):


1. Use J55 tubing on producing wells with depths no greater than 8500’. For
deeper wells, calculations must be made. Use couplings of same grade as the tu
b-
ing

2. Run the seating nipple as
deep as possible.

3. Minimize the distance between the tubing anchor and the seating nipple. In
open hole , the tubing anchor should be as close to the casing shoe as possible. In
cased hole, the tubing anchor should be out of the perforated zones.


4. Jus
tify why not to use a tubing anchor. Corroded casing, small diameter pumps,
and shallow wells are reasons not to use tubing anchor.

5. Use API modified no lead thread sealant spread over complete thread area.

6. Tubing below the anchor should be inspecte
d for excessive wear on each pull
and replaced if worn.

7. Use thread protectors until tubing in derrick.

8. No wrench marks are acceptable on tubing anchors. Use only ISO 9000 r
e-
placement parts.

9. A non API seating nipple should be used only on 2 7/8’s
tubing strings. The
API nipple can cause the pump to stick.





Gas Separation Best Practice:


Selection of Artificial Lift Systems for Deliquifying Gas Wells

Page
15



1. The pump intake should be below the gas entry point to the well. If this is not
possible, consider the new Echometer collar size gas separator instead of th
e poor
boy separator.

2. A typical poor boy separator can only be used for low rates (~75
-
150 bpd). For
2 7/8’s tubing, a 1 1/4” stinger and velocity between the gas and mud anchor of
1/2 ft/sec, the max fluid rate is 177 bfpd. If 30% is gas, the max flui
d rate is only
124 bfpd.

3. An improperly sized gas separator is worse than no separator as it breaks out
more gas and also becomes gas locked. Again see the Ecometer.com for add
i
tio
n-
al information.


Beam Pumping Unit:


1. The unit should have the concret
e base set on 5/8’s river stock. Sand can wash
out.

2. The unit must be aligned correctly so the polish rod pulls out straight each time

3. Each week the unit should be inspected for abnormal sounds, grease or oil
leaks, or rust stains at metal joints.

4.
On a six month interval, grease all bushings, inspect unit and gearbox oil for
contamination, check tightness of all bolts, follow check list and keep records.

5. Check stuffing boxes daily. Don’t over tighten which can cause wear on polish
rod and load mo
tor unnecessarily.


Fluid Level Detection:


1. Shooting fluid levels regularly is recommended, especially on wells that aren’t
on POC. Echometer’s AWP program can be used to correct foamy fluid levels.
Dynamometer cards can indicate if a well is pumped o
ff and pounding fluid.

2. Shoot fluid levels when the well is being tested.

3. Based on well analysis and fluid level, consider lift revision to increase the
pumping unit capacity if indicated.


Casing Pressure:


1. Lower is better

2. Check casing side che
ck valves to be sure it is operating properly.








Best Practices (Beam Pump) Directed at Producing Liquids
off Gas Wells:

Selection of Artificial Lift Systems for Deliquifying Gas Wells

Page
16




Recommendations below mostly from Bill Elmer 2006 Gas Well Workshop




Pumping Units are the best choice for high PI, low bottomh
ole pressure, multiple BCF
wells



Goal is to reduce the FBHP to minimum values by flowing up large annular area,
where friction is minimal



Normal wellheads may only have one casing valve, with small diameter threads
for setting a plug



Original flowlines des
igned for high pressures, normally 2” Sch 80



Choke bodies, line heaters, small pipe contribute to pressure drop



Antidotes:



Connect both sides of tubing head to new larger flowline



Use old flowline to handle fluids pumped from tubing



Replace tubing head wit
h model with 3” outlets



Remove all chokes and line heaters, as no longer needed





Problem: Typical 4
-
1/2” and 5
-
1/2” casing has a diameter too small for effective dow
n-
hole separation of gas and liquids, wells with liners even more of a problem



What is hap
pening?



Fluid is prevented by turbulence around perforations from falling



Velocity not high enough to lift fluids, but will drag gas



How to Identify



Look for wells pumping at 15% or less



Prior to start of pumping cycle, manually shut
-
in casing for 10 minut
es. Open
casing when well pumped off. Lufkin SAM can do this



Note if normal pumping time changes appreciably



Install automated valve to perform this process



Pneumatic or electric powered of sufficient diameter



Give consideration for POC makers to add this

ability to product



Pump Tolerance



Improvement in machining equipment has allowed tolerances between pump
plunger and barrel diameter to be reduced to one thousandth.



Historic Rule of Thumb of 1 foot of plunger per thousand foot of pump depth no
longer ap
plicable with these pumps.



Lack of pump slippage can aggravate gas locking



“Sloppy” pumps with short plungers better for gas wells



.6 foot of plunger per thousand foot of pump depth



Use five thousandth clearance pumps



Slippage of 10 BPD not critical when t
rying to pump 5 BPD with 40 BPD of
pump capacity in hole



Slippage can break gas lock if it happens given time



Pump Valves: Double valves extend pump life (but may reduce compression ratio)



Alloy/Carbide for upper valve



Alloy/ Alloy for lower valve



Often ut
ilize bottom discharge valve



Pump Metallurgy: Spray metal plunger and chrome barrel



Pump plunger design:

Selection of Artificial Lift Systems for Deliquifying Gas Wells

Page
17





Use .005 clearance between plunger and barrel



We use 4 foot plunger length at 6000 to 7000 foot depth



Pump Size: Make sure your shop stocks 1.06” pump
s



Hold
-
down: Nylon cups will reseat


Use a pump shop with demonstrated experience pumping gas wells with other operators. Don’t
train them at your experience. Experienced pump hands are worth your money.

Field Foremen: Know the man that repairs your pump
s.



Per “Design Considerations When Pumping Gas Wells”



Utilize 5/8” rods when pumping above 8000 feet



Use Grade “C” rods when possible due to corrosion resistance



Utilize rod guides on top and bottom ten rods



During shut
-
in period, fluid level can drop, r
emoving lubrication



Bottom rods in compression can aggravate tubing wear



Use field experience to modify design




Corrosion Chemical


Essential



Rod Failures should be extremely rare!



Improper makeup of rod joint



Poor rod handling practices



Well service cre
ws who normally work gas wells may not be up to speed with
rod handling and makeup practices. TRAINING!!!



Make sure crews do not overstretch the small rods trying to unseat the pumps.
Follow appropriate guidelines.



Compression with Beam Pumping System:


A beam pumping
unit produces

the gas up the annulus. To keep low pressures on the
formation, the unit should be designed to pump with a low

height

of fluid over the pump

in the annulus
. For gas separation the pump is best placed below the perforations. H
o
w-
ever it does not matter if you set the pump below the perforations

(or above)

and have a
low fluid level if the
producing
CHP pressure is high.
If the CHP is high, no matter if the
producing fluid level in the annulus is low
, the pressure on the producin
g gas formation is
still high.
Therefore for best operations when

beam pumping to dewater gas wells,
it is
best to operate with a
low CHP pressure. If it is not low, the
n

compression

(field wide or
single well)

must be added to the casing to achieve low CH
P’s or the installation will
“NOT” produce the well to low pressures.
This recommendation applies to all pumping
methods. Compression on the producing conduit also assists plunger lift, velocity string
installations, gas lifting of gas wells and wells that

are producing with surfactants.









Corrosion:


Selection of Artificial Lift Systems for Deliquifying Gas Wells

Page
18



1. For corrosive wells producing, for instance, H2S, target might be treating with
25 ppm of oil soluble filming amine. The total chemical treatment volume is
based on wells total production with the mi
nimum treating volume of 1 gallon.
Treating schedules are 1/week for the most part. For normal water flood wells,
flush a volume of 3 bbls water with the treatment. For wells with a gas rate of
100
-
200 mscfd, use 5 bbls and for greater than 200 mscfd, use
8 bbls of water
with the treatment. These recommendations for W. Texas area where H2S prev
a-
lent but may provide a starting point for other areas.

2. Check your chemical program or check with your chemical supplier.

3. Before running pump and rods, it rec
ommended that 15 gallons of oil soluble
filming amine and 15 bbls of lease crude be pumped into the tubing after a
wor
k
over. This should be done on wells that have been killed with heavy brine or
on wells that have exhibited severe pitting on tubulars or
rods. It is optional on
less severe situations.