Methods to Improve the Efficiency of Rod-Drawn Subsurface Pumps

8/18/2019 Methods to Improve the Efficiency of Rod-Drawn Subsurface Pumps

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2/16

2.

NETNODSTO INPROVSTNE EFFICIENCYOF ROD DRAWN SUE-SURFACE PUMPS

SPE 18828

=-

.

—.

—=

.

—

Very little gae is vented from the casing at

pressures approachingor abovs the bubble point.

Since at the higher pressure the gas bubbles are

small, and easily entrained, they are carried in

the same direction as the oil. Gae anchors are

effectiveat lower pump intakepressyresof bubble

point or less.

As shown by Clegg , the rising

velocitydependson the bubble size and ahape and

the physical

characteristics of

the liquid.

Also, when the pressure is decreased,bubble size

increases and gas separation begins to improve.

Relatively good pump efficiencies can often be

obtained in the lower pressure

range

with an

effective

type gas

anchor.

The efficiency will

decrease, however, with higher production rates.

But higher production rates are needed in many

wells due to higher water cut and the need

continuesfor a pump design that will operate in a

high volume

mode

with the presence of gaa

interference.A pump design has evolved from the

demand of

deeper setting depths, high volume

productionand with gas interference.The pump is

referred.o genericallyae a two-stagehollowvalve

rod pump.

SACRGRODND

The early history of the development of the

Two-Stage(2S-HVR)Hollow Valve Rod Pump begins in

West Texas,Gaines County,Adair Field,by a major

oil company.

The water flood project requiredlong strokes and

large pumps - 1-3/4” and 2“ bore inserte, and

2-1/4”bore tubingpumps. Valve rod failuresat the

threaded ends pointed to a need for improved

design. Collet-typefittings were used with some

euccees, but failures were still high, Tubing

failures in the first few jointe above the pump

from wells under water flood and C02 injection

system,

started using hollow valve rod pumps to

avoid buckling problems.They had experiencedpin

threadfailuresof plungersalong with tubingwear

and

other problems. These wells also had gas

interference from H2S,

and problems with iron

sulfide particles during shut down periods. Gas

Locking

had been a problem, and rather than

re-spacethe clamp on the polishedrod to bump down

m the pump, this company elected to cycle the

pumpingtime with occasionalstop or “rest” time to

allow the gae and pressure to “equalize” before

resumption of

pumping.

It was realized that

the top valve added as a sand check was also acting

ss a two-stagevalve,which helped open the bottom

plunger valve. These _ were not ~ lockin~.

.

5ome refinementswere made in the guide and lower

pull tube coupling to enhance the pumps’ ability

to handle the gas and particulate, and the pump

as calledthe TWO-STAGEHOLLOWVALVEROD PUNP.

I’ECRNICALDISCUSSION:

Refer to figure (1) for a sequence of operation

of the two-stagehollowvalve rod pump.

POSITION - Top of The Upstroke

The plunger valve has the hydrostatic

pressure load.

The

top valve, or

two-stagegas and sand check valve, is

in equilibrium and the weight.of

the

ball closeson the seat.

POSITION -

Start of The Downstroke

The plunger starts down, vacating the

chamber above the plunger and below the

close fitting guide.

This creates a

lower pressurein this chamberwhich has


3/16

SPE 18828

BOB COX ARD

BIWN?tWILLIAMS

3.

dischargewill be primarilyup the pull tube and

gassy welle in hundredsof installation, aee Case

throughthe top valve.But with a gaa-liquidmixture

Histories.Ball and seat and cage life expectancy

- that is, a compressiblefluid - the volume is is increaseddue to the smooth transitionof fluid

reducedat the higher pressureof hydrostatichead.

load.

In this case, the dischargedquantity may be much

lessdue to compression.

The two-stagehollow valve rod pump has been run

by

several

operatora

under a

In

the

packer,

and

schematic of

“Sequence of

Operation”

out-performed

many typea of

that

the top

valve is closed on the downstroke to

pumps were

previouslyin the well.

illustratethe theoreticalconditionwhen pumping a

compressible

fluid.

Gas break-out,

where

small.

Where sand and gas in combinationare encountered,

babbles expand, occurs with a pressure change or a this pump should be a primary consideration.The

temperaturechange.

Turbulence and agitation also

only disadvantageto the use of this pump design

influencegas solution fluid behavior, and all of

ia,

as a bottom hold-down stationarybarrel, sand

these factors take place

in rod drawn sub-surface

can pack between the barrel O.D.

and the tubing

pumps. I.D.

Where this is a possibility, the bottom

dischargevalve can be applied.

The fluid path ia through the holes in the ported

lower pull tube couplingand aroundthe pull tube to

CASE EISTORIES COMPARING TNS TWO-STAGE HOLLOW

guide clearance.This fluid flow helps keep sand or

VALVE ROD POMP TO CONVECTIONAL POW

other particulatematter in turbulenceand moving up

and out of the pump.

Case EW3tory 1

POSITION -

Start of The Upstroke Well information- ThunderCreek- Wyoming

Depth:7,700feet

The plungervalve seats and all pressure

FluidType:Muddy

load is on the plunger area. The standing

Gas Percent:18MCFPD

valve

opens due to a

pressure

Scale/Sand:2X sand

differential

created

by the

plunger

Productionhistory:15 BPD.

vacating

the chamber, allowing

well

Praviouspump: 2“ x 1-1/4”RHBC-16-4-6

fluids to enter.Pump intake pressure is

Surfaceoperation{7 5PM, 120” stroke

equal

to bottom hole pressure at

the

intakepoint,and is the force that fills

Pumping problems included pump “gas lock” and

the pump chamber.

abrasionof plungerand barrel surface.The well

POSITION-

pulling frequencywaa high, with an average run

UpstrokeCompletion of only

i ro

months. A packer was in place~

The

iorcingall fluid throughthe pump.

plunger displaces

fluid in

the

annulus between tha pull tube and barrel

After installationof the two-stagehollowvalve

through the pull tube and the top valve.

The perforatedpull tube couplingaccepts

rod pump, the well produced fifteen (15) BPD


4/16

4.

METEODS TO IKFROVS THE EFFICIENCY OF ROD DRAWN SDB-SURFACE PUMPS

SPE 18828

lulling

frequency of

the

previous

pump

by

Case History 6

me-third.

Well information-

CanyonField SouthCowden

:aseHistory 3

- Texas

Depth:8,000 feet

Well information

- RainbowRanchUnit - Wyoming

Fluid type:N/A

Depth:9,445 feet

Gas percent:NfA

Fluld type:Minnelusa

Scale/sand:none

Gas Percent:12 MCFPD

Productionhistory:30% oil, 70% water

Scale/sand:22 sand

Previouspump:NfA

Productionhistory:242 BPD, 10%water

Previouspump:2-l/2’”x1-3/4”RHBC-24-6-6 Pumping problems included

Surfaceoperation:8.3 SPM, 169”stroke

corrosion-erosion

of tubing opposite the fluid dischargeof the

RHBC pump. Three tubing failurea in eix months

Pt.mpingproblems included valve rod buckling

were attributed to the constant discharge of

wearing against the tubing, ias fluid pound

corrosive fluid at the stationary valve rod

and corrosiondamage to pump and tubing. Fluid

guide.

level recorded at 1,800 feet above the pump

and conventionalpump could not pump the level

‘l’hepump was converted to a two-stagehollow

down. Corrosion inhibitor wae ineffective.

valve rod pump so that dischargeof the fluid

was distributedover the stroke length.At last

The two-stagehollow valve rod pump eliminated

report the two-stagehollow valve rod pump had

the gas-fluidpound, the bucklingproblem,and

not been pulled in seven-and-a-halfmonths of

pumped the fluid level down to 800 feet above continuousoperation.

the pump.

Production stabilized at

242

BPD, whereaa the

conventional pump

would

Ca8e History 7

“gae-lock”and productionwould vary daily. The

conventional pump

averaged

only thfrty

Well information-

day run betweenpwnp repairs.

SterlingCongerField- Texaa

Depth:8,000 to 10,000feet

Fluid type:Ciaco and CanyonReef comingled

;aaeE3atory 4

Gas percent:600 MCFPD

Scale/sand:Moderatesand

Well information- ThunderCreek - Wyoming

Productionhistory:30Z crude,i’OZwater

Depth:

10,110feet

Fluid type:muddy

Previouspump: 2“ x 1-1/4”RHBC-12-4-6

Surfaceoperation:8 SPM, 84” stroke


Scale/sand:lightaand

Pumping problems included gas lock and ~aqd

Productionhistory:15 BPD

abrasion of plunger

Previouspump:2-1/2”x 1-1/4”RHBC-18-3-6

and barrel. Conventional

pump design, along with “Mother Hubbard” gas

Surfaceoperation:7 SPJ, 84” etroke

anchor

system,

was not effective to prevent

gas lock and would not pump the well down.


5/16

SPE 18828

BOB COX AND BENNYWILLIAMS

5.

only three

out of fourdays.

Case History 9

Well information- Red River - North Dakota

Depth:7,700feet

Fluidtype:N/A


Scale/sand:NfA

Productionhistory:With

conventional

pump,

well produced only fifty

days

out of

eighty-two

during

the observed test

period.

Productionaverage

per day was only44 BFPD.

After the two-stsge hollow valve rod pump was

installed,

the production averaged eighty-nine

BFPD with

no days of

zero production, in

thirty-eightdays of observation.

:ase tiistory 10

This case history involves a study of pump

failures on seventy-fivewells by a major oil

company

operating a

unitized

field

near

Levelland, Texas. Comparison is made on pump

faihreS with conventional pumps versus the

two-stagehollowvalve rod pumps over a two year

period.

The eummary statement concerninghe

comparison of the two pump designs

reads as

follows:

“Tagging”

and

pump failures

result in:

Brokenvalve rods

Brokenplungerpina

Bent pump barrels with seized plungers

Excessivepump repaircosts

Excessivedamage and handlingof sucker

rods

WBU~LINGtlOF VALVE RODSAND PULL ~ES

Valve rods “buckle”

or bend on the downstrokewhen

pushing a plungerwith a ball and seat valve. The

point of buckle can be calculatedvery accurately

using

the formula developed by Euler and tha

parabolicor J. B.

Johnson formula, discussed in

the text book Fundamentalsof Mechanical Design,

DeflectionAnalysissection.

Per Euler

~_ Nfi2EI

L2

...................,.

(1)

Per Johnson

[

1

P= (A) sy-(~j’~~.~:

......(2)

Application-

for slendernessratiogreaterthan:

t ‘(VY

use Euler

equation . . . . . . . . . . . .

(3)

Where:

P = criticalload (bucklepoint)

A = areaof column(squareinches)

Sy = yieldstrengthof material,psi

N = end constant

E

= modulusof elasticity(You~gs’),psi

I = area moment of inertia,In

L = length,in.

k = radiusof gyration,in.

The resistanceof the plunger imposedon the valve

rod ia due to the differentialarea above and below

the ball and seat.

The criteria for determining

columncriticalbucklingload is the length of the

column (valve rod or pull tube),

the diameter,

load, slenderness ratio and the end condttion.

In considering the end condition for valve rods

and pull

tubes, wa

use

the “fixed-free” for

determiningthe columncriticalbucklingload. As a


6/16

.

NETEODS TO INPROVS TEE EFFICI’XKY OF ROD DRAWN SDS-SURFACE PDHPS

SPE 18828

seat only;

we did not con$ider friction of t-he

system such as inertia,fluid velocityor abrasio~.

Buckle point of pull tubes

for traveling barr(:l

pumps are in parenthesis( ). The pull tube in RWl

and SST style pumps

support

the fluid load on

downstroke,and the free column length at the point

of buckling is rather short compared to stationary

barrel pumps equippedwith large valve rods or pull

tubss.

REVIEWOF CONVENTIONALAPI

SUE-SURFACE PDKP~ -

ADVANTAGES AND DISADVANTAGES OF APPLICATION

API SPEC 11AX4

designates two general types of

pumps: The tubing pump (T), and the rod or insert

pump (R).

Both tubingand rod type pumps consistof

metal barrel units with plungers having either

metallicor non-metallicsealingsurfacea.

API full barrels are all one piece tubes threaded

at both ends.

The sectional liner barrel and one

piece liner barrelwere discontinuedas part of API

SPEC llAXin 1979.

Metal plungers may be of one piece or aasembled

construction.One piece plungers generally have a

hard plating or coating, while assembled plungers

have a hard sleeve supportedby a plunger tube and

end fittings.

Refer to figure 2 for configurations of the

followingclassificationsof pumps:

TubingPumps

The tubing pump is rugged in constructionand

simple in design. The barrel of a tubing pump

is attached directly to

the

tubing string,

usuallyat the bottom.Below the pump barrelis a

the pressure of oil in the casing annulus then

opens

the

standing valve,

filling the void

creatad,by the upward movament of the plunger.

AS the plunger starts down, the standing valve

closes. The preseure below the plunger builds

up and opens the travelingvalve. Thus the fluid

that passed the standingvalve on the upstroke,

passes the travelingvalve and throughthe hollow

center of the plunger on the downstroke. This

fluid ia now above the plunger in the amulus

between the sucker rods and tubing. On the

subsequentupstroke,this fluid, along with the

rest of the fluid filling the rods and tubing

annulus,is lifted.It is importantto note that

the actual lifting of fluid is accomplishedon

the upstroke. On the downstroke, the plunger

drops through the oil which entered the pump

through

the standing valva on the upstroke.

The decision aa,to whether to pump a well with

a

tubing pump or a rod pump is important.

Rod Puqa

The rod pump is preferredover the tubing pump

in the great majorityof pumpedwells. The fact

thai the complete pump can be pulled with the

sucker rod stringwithout disturbingthe tubing

is the main reason. This reduces pUl15ng Unit

time at the well by more than fifty percentover

the tubingpump when both the barrel.and plunger

must be pulled. There are three types of rod

pumps, the travelingbarrel bottom anchor (API

RWT or RRT), the stationarybarrelbottom anchor

(APIRWB or RNB), and the stationarybarrel top

anchor(APIRWA or RNA).

When a rod pump has been selected, an API

seating nipple is run on or near the bottom


7/16

.

SPE 18828 BOB COX AND BENNT UILLIAHS

7.

quarter inch smaller than the nominal tubing

Both standing and traveling valvea on the

I.D. Where the maximum displacementis needed,

traveling barrel pump have open type cages.

the tubingpump is the logicalchoice.

These are more rugged,have more fluid passage

than blind cagesand are less prone to beat out

A tubing pump is the etrongeetpump made. The

from ball action.

heavy wall barrel is connecteddirectly to the

bottom of the tubing string with a collar,

eliminatingthe need for a eeating assemblyon

Due to equalized pressure on the outside of

the pump to hold the pump in position.Alao,

the barrel,

a bottom

anchored pump (either

the sucker rod string connectedirectly to the

traveling or stationary barrel)

has greater

plunger top cage, eliminatingthe need for the

resistance

to bursting

than a

top anchored

valve rod required in stationary barrel rod

pump.

In wells that pound fluid, or in wells

pumps.

where top anchoredpumps have experiencedburst

barrels, the traveling berrel pump is a good

Disadvantages

application.

The greatest disadvantageof the tubing pump

Disadvantages

la the fact that the tubing string must be

pulled in order to replace the pump barrel.

The travelingbarrelpump is at a disadvantage

This increases the pulling unit time at the

in wells that have a low static fluid level

well.

because of the greater.pressure drop between

the well bore and the pumping chamber. Since

The tubingpump is a poor installationin gassy

the standingvalve is located in the plunger

fluid. Because of the length of the standing

top cage on a travelingbarrel pump, it is

valve assembly and the puller on the plunger

smaller in diameter and therefore uses a

(and frequently the increased bore of an

smaller ball and seat than would be used in

extensionnipple)there ia a large unswept area

the standingvalve blind cage on a stationary

at the bottom of the stroke,

causing a poor

barrel pump.

compression

ratio.

This

reduces the

effectivenessof the pump valving, and cauaes

There is a relationshipbetween pump length,

low pump efficiencyin wells where gas entera

well depth

and

pump bore which must be

the pump suctionalongwith the producedfluid.

observed.

When the standing valve (in the

Plunger top cage) is closed, a column load is

The incre&3ed bore of a tubing pump causes

transmittedby the plunger through the pull

increasedload on the rod string and pumping

tube and seating assembly into

the seating

unit. It also increasesstroke loss due to rod

nipple. In a deep well, this load will be

and tubingstretch.As the pump is set deeper,

sufficientto put a bow in a long pull tube,

this strokeloss may actuallyresult in a lower

thus setting up a drag between the pull plu~

net displacementthan would be obtained with

and the pull tube.

the smaller plunger of a rod pump. API RP1lL

calculationsshould be made on both the tubing

Stationary Barrel Bottom Anchor Pumps


8/16

.

.

NETNODS TO IMPROVE TEE EFFICIENCY OF

ROD DRAWNSUB-SURFACEPUMPS

SPE 18828

gas anchor.

The short rise required for the

fluid to pass the standingvalve and enter the

pump minimizes the tendency to foam and thus

redqceefficiency.

Disadvantages

It is hazardous to run a

stationary barrel

bottom anchor pump in a sandy well since sand

can settle tightly in the annulus between the

pump and the tubingand stick it tightlyin the

jcint.

It alao has the disadvantageon intermittent

operation that sand or other foreign material

can settle past the barrel rod guide and on

top of the pump plungerwhen the well is shut

down, with the possibilityof stickingthe pump

when it is put back on production.

stationaryBarrel Top Anchor Punps

Advantages

The top anchor pump is recommendedin sandy

wells where a bottom anchor pump may become

sandedin and cause a strippingjob. The amount

of sand that can settle over the seating ring

or top cup is limited to a maximum of about

three inches, since the fluid discharge from

the guide cage keeps it washed free above this

point. In this respect, it is even superior

to the traveling barrel bottom anchor pump,

since if a travel barrel pump is spaced too

high, sand can settle around the pull tube

right up to the lowest point reached by the

pull plug on the downstroke.

The top anchor,pumpis specificallyrecommended

In low fluid level gassy or foamy wells where

it is particularlyadvantageous to have the

efficiency.Where gas interferenceis a problem

a properly designed gas separator should be

installedas a part of the sub-surfacepumping

assembly.Variousstylesare availablewith each

havingmerits for particularwell conditions.It

is importantto keep the back pressure on the

gas at the wellheadat a minimum.

Installations where fmmation aand can be a

problem.

“A pump will inherentlyhave problems if sand

is allowed to enter. Therefore,it is best to

utilize some method of sand control to prevent

entrance of sand Into

the well bore. Gravel

packs, screens,and chemicalbonding age..csare

frequentlyused for this purpose.

CONMON PDNP PROBLEMS AND SOLUTIONS

Corrosion.

Corrosion occurs in many wells with resulting

damage to

sub-surface equipment. Flany NACE

papersand documentshave been issueddescribing

inhibitorsand methods of treatment to reduce

damage to

down-hole

equipment.

However,

inhibitorsdo not protect the sub-surfacepump

efficiently. It is

recommended

that

pump

metallurgybe seriously consideredas a method

of corrosioncontrol.

Fluid Pound.

When a pump does not fill completelywith liquid

durf,ngthe upstrokea low pressuregas cap forms

in the top of the pump chamber between the

traveling

and

standing valve.

During

the


9/16

SPE 18828

BOB COX AND BENNY WILLIAMS

9.

When a fluid pound is allowed to exist extreme special attention given to the pump

damage can occur to the entire system and can intakepaasages.

be the primary cause of the followingequipment

failures:

Gaa Pound

1. SurfaceEquipment.

A. Fatigue failure of the pumping unit

A gaa pound is very similar to a fluid pound,

structure.

but is differentin the followingrespects:

B. Fatigue failure of gear teeth and

bearings.

1. A “pump off” conditiondoes not exist.

C. Fatigue failure of the pumping unit

2. A “restrictedintake” condition might or

base.

might not exist.

2. Sub-SurfaceEquipment

A. Fatigue failure within the rod string.

Gaa pound is causedby:

(Fluid Pounding is especiallydamaging

to the lower portion of the rod string

1. Free gaa going through the sub-surface

because of the compressive

force

gas separator and

entering

the pump

applied upward by

the

fluid pound

intake. This condition usually

causes

condition).

erraticgas poundingin various downstroke

B. Within the pump, a fluid pound causes

positions.

accelerated damage to the traveling

d. Gas

breaking out of

solution

during

valve and its cage.

Valve

rod

upstroke pump

fillage after

passing

breakage,barrel rupture,and standing

through the gaa separator.This.condition

valve failurecan occur.

usually cauaes consistentgas pounding in

C. Fluid pound action accelerate wear the same downstroke.

of the tubing threadscausing leakage.

3. If gas

entering

the

It is frequently the cause of the

pump ia at

sufficientlyhigh pressure due to a high

fatigue

parting of

the

tubing.

fluid level in the annulus the resulting

gaa pound will be cushioned and less

Minimizing Damaging

Effects of

Fluid Pound:

severe than a fluid pound. As the closed

travelingvalve moves downward toward the

A good approach to this probim is to design

liquidin the pump chamber,the compressed

a Pumping system and a pump diaplscementthat,

gas supplies a pneumatic

cushion which

when working at eightypercent efficiency,will

reducesthe severityof the inpacc.As the

achieve

the desired

production fro= the

pressurz of the gas entering the pump

reservoir.Fluid pound that occurs in the first

decreases,the severity of the gas pound

twentypercentof the downstrokeis leas severe increases.

than those occurringin the mid-portionof the

4. If gas pound is caused by free gas going

downstrokewhere pump plunger velocity ia the

through the separator, a

better

higheat.When pump capacitygreatly exceeds the

sub-surfacegaa separatoris needed. If it

well productivitythe stroke length, pumping

is cauaed by gas breaking out of solution


10/16

scale

deposits in aieas where agitation or 3. Use of top valve, a slide type check valve with

pressuredropa occur. Usually this problem is a close fit to the valve rod and housed in an

best resolved by use

of chemical treatment

open cage (see Figure 5). This

essory

item

which prevents,

reduces or dissolves the

deposit.

acts as a sand check valve to prevent sand from

recenteringthe pump chamber.

It also acts as

an upper standingvalve to check the hydrostatic

Casingperforationscan become pluggedby scale

pressure from acting on the traveling valve

which reduces well productivity and causes

during the downstroke on

conventional pumps.

prematurepump off. Gas separatoropenings can

become plugged

causing “starved pump”

The top valve also dampens the effect of fluid

condition.

pound on the

rods since it

assumes

the

hydrostaticpressure load at the start of the

All valves, openings,and parts within a pump downstroke.This accesaoryitem is often used in

can becomepluggedmaking the pump inoperative.

conjunction with the

rod-connected

mechanically-openedlunger valve (see Figure 3)

Scale can cause a stuck plunger condition.Use

in stationarybarrel rod pumps. It is applicable

of an RH or T.Htype pump with barrel length

to either RWA, RHA, KWB or RHB API conventional

and extension length designed to assure that

pumps.When adaptingto existingpumps, a longer

a Portion of the plunger will stroke out of

valve rod ie necessary,equal to the added length

each end of the heavy wall barrel on every

of the cagehousing.

stroke will

reduce stuck plunger problems

cauaedby scale.

The addition of the top valve to a stationary

barrel pump can be an economical meana of

kCCSSSORYITEMSFOR SUB-SURFACE

improving pump efficiency in gaseous wells. Ae

POMPEPPICIENCYINCREASE

the valve closesat the start of the downstroke,

the plunger traveling downward creates a low

SasInterference

pressure in the chamber above the plunger. The

low pressurehelpe the travelingvalve ball and

1.A mechanically

opened

rod

connected seat to open so that fluid in the barrel will

plunger-valve

syetem” (eee

Figure 3) that

travelthroughthe plunger to the upper ckamber.

replacesthe plunger,ball and seat and cage of

the conventional API pump.

The mechanically The top valve should be a prime consideration

openedplunger-valveopens at the start of the

for top anchoredinsertpumps when run to depthe

downstroke,allowingthe gas and fluid to pass

greaterthan 4,000feet (1,220metere).

through the inside of the plunger body to the

upper chamber of the barrel. On the upstroke

Scale/SnndProblems

the drop on the bottom of the connectingrod

seats to the mating surface lapped on the

1. BottomDischargeValve

plunger body and lifts the fluid into.the

tubingcolumn.

The partial bottom discharge valve (see Figure

6) ie designed to be used with a stationary


11/16

SPE 18828

BOB COX AND BESNY WILLIAMS

11.

=

—

.

in the compression chamber Is forced out

a stationarybarrel pump and a travelfnsbarrel

through the

side of

the bottom discharge

pump. It can be used in low fluid wells, and

valve into the annulus between the pump and

it is easier to fill because the fluid only

tubing.

has to pass through the large standing valve.

The traveling barrel creates fluid turbulence

On the downstroke, the hydrostatic pressure

around the hold-down which helps prevent sand

is equal

on the top

al,d bottom of the from settlingand preventingthe pump from being

discharge

ball and seat, The force moving pulled. In very sandy wells a bottom discharge

fluid through the ball and seat is due to valve can be installedon the standingbarrel.

fluid dynamic back pressure from the flow of Tha no-go ring is located on the standingvalve

fluid throughthe insi


12/16

.

12.

HETEODS TO IMPROVE TSE EFFICIESC2 OF ROD DRAW SDB-SDRFACE PUMPS

SPIZ18828

S1 L-LWC CONCESSION FAC’IWS

ft X 3.048* E-01 = m

fts

X

2.831 685 E-O% = ms

psi x 6.894 757

E+OO = lcp

SCF/bblX 1.801 175 E-01 = std mslms

in X 2.54* E+OO = cm

ft*

X 9.290 304*

E-02 = mz

bbl X 1.589 875

E 1 =

ma

gal

X 3.785 412

E-03 = ms

sq. in. x 6.451 6*

E-00 = cmz

cu. in. x 1.638 706

E+O1 = cm3

*Conversionfactoris exact.

TABLE 1

COLUMN CRITICAL BUCKLE LE&TB IN INCESS

Valve Rod

Fluid Lift Fluid Lift Fluid Lift

Fluid Lift

PlunSer - Pull Tube

2300’ (1000 PSI) 4600’ (2000 PSI) 7000’ (3000 PSI) 9200’ (4000 PSI)

1-1/4” 11/16”

120”

86” 70”

60,,

7/8”

192”

138”

108”

98,,

Sta. Bbl. Pull Tube

200”

140” 115” 100”

rrv. Bbl.

Pull Tube (95”) (60”)

(50”) (45”)

1-1/2” 11/16”

100”

741, 60,, 521:

7/8”

168”

115”

95

81’


13/16

s

TASLE 2

COLUHSSITICALUCSL2SGOAD,OUNDS

Size

?’SSSOLOHIlSRG2E.tWSSS

O.D.

I.D.

Inches

40

50

60

70 80 90 100

110 120 130 140 150 160

170 180 190 200 210

VALVSSODISq.lnclr

Area

11/16° .371

2,.$421,563

1,085 797 610

482

390

322

271 231 200

173

152 135 120 108

97 88

718” .601

6,389

4.089 2,839 2,086

1,597 1,262 1,022 844 709

604

521

454

399

3s3 3iZ

283

255 231

1-1/16” .836

13,890

8,890

6,173

4,535 3,472

2,743 2,220

1,836

1,5431,3151,133

987 868 769

685 615

555 503

PULLUSE / Sq . IrIcb

Area

553-c

.384

15/16”

X 5/81’ 6,774

4,335

3,012

2,210

1,689 1,334 1,080 893 750

640

550

480 422 374 333 300

270 245

533-E .552

1-118° X 314”

13.388 8,966 6,227

4,574 3,502

2,767 2,241

1,852 1,S56 1,326 1,143

996 875

775 690 620 560 508

232-K

.773

1-1/2” X 1-1/8”

24,592 21,028 16,671 12,317

9,430

7,451

6,035

4,987 4,190 3,570 3,080 2,680 2,357 2,088 1.862 1,670 1,508 1,368

232-N

.994

I-718° x 1-112”

34,798 32,000 28,588 24,522 19,884 15,711 12,726 10.517

8,837 7,530 6,492 5,656 4.971

4,4003.92’7,5253,1612,885

Used on 1 3/4” and 2“ borepumps.

**U~~d“& l/41t a d 2-1 12 1 b~re pumps.


14/16

“A

Fig.1

ssQusNcE

.

l,-*).

1

,

m

—

Fig. 2

AmericanPetrolsumI -

st@ts”s TypicslPumpAsssmblii nd Dm”gnstians

8

m

:;

m

N“

00

A

Q

OF OPENATION

lWO STAGS HOIJ X l VALVE BJ)D PUMP

~ FLUID LOAD [Hydrostatic Column)

A PUMP INTAKEPNESSUNS

~ SLIGSTLY ,...}

~ > FLulDWAD

A SLNETLY


15/16

= 18828

4

m

u

Q

ill

k

u


16/16

Fig. 6 Pa rt ia l Bot t om Discharge Valve

< ~-

/4

/5

4

,6

,7

,12

K -

/8

,9

,10

—

. 7 Three-Tube

ump

I

-9

2

3

—4

A

-lo

=

I-

1

—12

Fig. 8 Stroke Through pump

Modified

Methods to Improve the Efficiency of Rod-Drawn Subsurface Pumps

Documents

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