Subsurface sucker-rod pumps(штанговые скважинные насосы)

Подождите немного. Документ загружается.

Chapter 8

Subsurface Sucker-Rod Pumps

James R. Hendrix, OILWELL Div. of U.S. Steel Corp.*

Introduction

The general principles of sucker-rod pumps as used in oil

wells are well known. Fundamentally, they consist of

the usual simple combination of a cylinder and piston or

plunger with a suitable intake valve and discharge valve

for displacing the well fluid into the tubing and to the

surface. However, the variety of problems encountered

in pumping oil wells has resulted in a great number of

modifications of this fundamentally simple unit to make

it more effective for the various conditions encountered.

In general, the pumping of oil wells often presents the

widest variety of advqse conditions possible in a single

installation of any pumping application. These may in-

clude high discharge pressures; low intake pressures;

severe abrasive conditions resulting from sand or other

solids in suspension:

severe corrosive conditions

resulting from corrosive gases or salt waters; deposits of

lime, salts, or other solids from the water pumped; paraf-

fin deposits from the oil pumped; and the requirement

that the pump handle liquids, permanent gases, and con-

densable vapors under the pressure and temperature con-

ditions existing at the pump. Strong magnetic forces that

may interfere with valve action when the valves are

made of magnetic material are encountered often. and

electrolytic corrosion is likely to occur as a result of us-

ing dissimilar materials.

The bores of reciprocating oilwell pumps can range

from 1 to 4% in. in diameter. The 4X-in. bore pump has

a displacement about 22% times that of the l-in. pump

for a given speed and stroke length. This wide range of

pump capacities is necessary to permit selection of the

most efficient and economical pumping equipment for

all conditions encountered. In many wells it is necessary

to pump large volumes of water along with the oil, so the

pump must have a capacity several times that indicated

by the net oil production.

Subsurface pump bores now standardized by the API

are l%, lV2, 1%,2,2%,2%,and2% in. Strokelengths

range from a few inches to more than 30 ft, and produc-

tion rates with this type of pump range from a fraction of

a barrel per day-with part-time operation-to approx-

imately 3,000 B/D.

There are two broad classifications of pumps operated

by sucker rods. The older type is now known as a “tub-

ing pump.” This term indicates that the pump barrel is

attached directly to the tubing of a pumping well and

lowered to the bottom of the well, or to any desired loca-

tion for pumping, as the tubing is run into the well. The

plunger, or traveling valve, of a tubing pump is run in on

the lower end of the sucker rods until it contacts the

lower-valve (or “standing-valve”) assembly. The rods

are then raised sufficiently to prevent bumping bottom at

the end of the downstroke and connected to a pumping

unit, or jack, at the surface.

A more recent development is the “insert” or “rod”

pump in which the entire assembly of barrel, traveling

valve, plunger, and standing valve is installed with the

sucker rods and seated in a special seating nipple, a tub-

ing pump barrel, or other device designed for the pur-

pose. The rod-type pump has the obvious advantage that

the entire pump may be removed from the well for repair

or replacement, with only a rod-pulling job, whereas

with a tubing pump it is necessary to pull both rods and

tubing to remove the pump barrel. The rod pump,

however, is necessarily of smaller maximum capacity for

a given tubing size.

Tubing-type pumps may have a standing valve seated

in a coupling or seating shoe at the lower end of the bar-

rel, or the standing valve may be seated in a coupling at

the lower end of an “extension nipple” that extends

below the lower end of the barrel. The ID of the exten-

sion nipple is somewhat larger than that of the barrel to

permit the pump plunger to stroke out both top and bot-

tom to produce uniform barrel wear and prevent ac-

cumulations of solids on the barrel wall.

8-2

PETROLEUM ENGINEERING HANDBOOK

TABLE 6.1 -API PUMP DESIGNATION

Soft-Packed Plunger

Metal Plunger Pumps

Pumps

Heavy-Wall Thin-Wall Heavy-Wall Thin-Wall

Type of Pump Barrel Barrel Barrel

Barrel

Rod

Stationary barrel, top anchor RHA

RWA

RSA

Stationary barrel, bottom anchor RHB

RWB -

RSB

Traveling barrel, bottom anchor RHT

RWT -

RST

Tubing

First letter:

R = Rod or inserted” type; run on the rods; lhrough ,“b,ng

T=Tublng type, nonlnserted, run on lublng

Second letter

H = Heavy-wall, for meta, plunger pumps

W =Thln-wall, for metal plunger pumps

S=T~I~-wall: for soft-packed plunger pumps

P= Heavy-wall, far soft-packed plunger pumps

Third letter

A = Top anchor

E = Eotlom anchor

T = Bottom anchor with traveling barrel

Rod-type pumps may also be equipped with extension

nipples above and below the barrel for similar reasons.

In addition, rod pumps may be “top-seating” (pump

suspended from top of barrel), “bottom-seating” (pump

seated at bottom of barrel),

“stationary-barrel” (travel-

ing plunger), or “traveling-barrel.”

Both tubing- and rod-type pumps are equipped with

one-piece “full barrels. ”

The API has adopted standard designations for the

combinations listed above. The classification system

given in Table 8.1 is from API Standard 11 AX. ’

The following definitions are provided to clarify some

of the more important terms used in connection with sub-

surface oilwell pumps since a majority of these terms are

peculiar to deep-well pumping terminology.

Barrel. The barrel of an oilwell pump is the cylinder

into which the well fluid is admitted and displaced by a

closely fitted piston or plunger.

Plunger. The pump plunger is a closely fitted tubular

piston fitted with a check valve for displacing well fluid

from the pump barrel. This may be all metal or equipped

with cups, rings. or other soft packing to form a seal with

the barrel.

Standing Valve. This is the intake valve of the pump

and generally consists of a ball-and-seat-type check

valve. The valve assembly remains stationary during the

pumping cycle.

Traveling Valve. This is the discharge valve and

moves with the plunger of a stationary-barrel pump and

with the barrel of a traveling-barrel pump. The entire

assembly of a cup-type plunger. or plunger equipped

with other type of soft packing. along with the check

valve, is often called a “traveling valve.”

Standing Valve Puller. This is a tool designed to at-

tach to the standing-valve cage of a tubing-type pump

when the sucker rods are lowered to the bottom. The

standing-valve assembly is then unseated by raising the

rod string and is removed along with the pump plunger

when the rods are pulled. This avoids having to pull tub-

ing to remove the standing valve of the tubing-type

pump.

Valve Rod. Valve rods are used in rod-type stationary-

barrel pumps to connect the lower end of the sucker-rod

string to the pump plunger. The valve rod runs through a

guide at the top of the pump. API valve-rod sizes range

from ix6 to 1 X6 in. in diameter. Modified line pipe

threads are standard for API valve rods (see Table 1 of

Ref. 1).

Pull Tube. Pull tubes are used in rod-type traveling

barrel pumps to connect the plunger with the seating

assembly or “holddown.” (See Ref. 1 for thread dimen-

sions for straight threads.) Tapered threads are used on

some sizes of pull tubes by some manufacturers.

Seating Assembly. A seating assembly is an anchoring

device for retaining a rod pump in its working position.

The seating assembly is sometimes more commonly

called a “holddown.” The seating assembly may be

located either at the top or bottom of a stationary-barrel

rod pump but can be located only at the bottom of a

traveling-barrel pump. A seating assembly may be

equipped with composition cups or rings that form a tight

tit in a seating nipple, or coupling, to hold the pump in

its working position by friction, or it may be provided

with spring clips that snap into position under a shoulder

and require a definite pull upward on the rods to unlatch

for removal. With the cup-type seating assembly, the

cups or rings also serve as a seal to prevent leakage of

fluid from the tubing back to the well after it has passed

through the pump. With the mechanical seating

assembly, an accurately ground seating ring fitted on a

tapered mandrel seats on a mating taper to form a

leakproof seal.

Pump Selection

The selection of a proper subsurface pump for the ap-

plication is sometimes a point of conjecture. The follow-

ing recommendations generally are accepted as suitable

for most applications. Fig. 8.1 shows cross sections of

SUBSURFACE SUCKER-ROD PUMPS

8-3

Fig. 8.1 -API subsurface pump classification.

API pump classifications. There are many variations of

the pumps shown, some within the specifications of API

and some that are non-API that will still perform the

desired function of pumping oil to the surface.

Fig. 8. la shows a stationary-barrel rod pump with top-

seating holddown. This is a pump that is run into the well

with the sucker rods. In this pump the plunger is attached

to, and moves up and down with, the sucker-rod string.

The barrel is held stationary at its top end by the seating

assembly. The barrel is on the left and the plunger

assembly is on the right. This is the preferred seating for

the rod pump when possible. The top seating holddown

provides a seal just below the cage, where the well fluid

is discharged into the tubing, so sand or other solid par-

ticles are prevented from settling between the barrel and

the tubing, and the pump is not apt to become stuck in

the tubing by packed sand. Since the body of the pump

pivots from this top-seating arrangement, it aligns itself

in crooked wells more readily than other types of pumps.

Also, there is no tendency for the barrel to wear by rub-

bing against the tubing. This type of pump can handle

low-gravity crude oil down to 400 cp quite well. In the

stripper wells and in wells with low fluid levels, the top-

seating design of the pump allows the standing valve to

be submerged deep into the well fluid. This makes it

possible to pump the oil level lower than can be done

with a bottom-seated pump. This is a particular advan-

tage when the fluid flow from the oil reservoir is weak.

Fig. 8.1 b shows a stationary-barrel rod pump with

bottom-seating holddown. In this pump, the plunger is

also attached to, and moves up and down with, the

sucker-rod string. The barrel, on the left, is held sta-

tionary by a bottom-seating holddown, either mechanical

lock or cup type, which is the type shown in the figure.

This pump is more suitable for use in the deeper wells

since the barrel does not elongate from the fluid column

weight of the fluid in the tubing. Since the body of the

pump pivots from its bottom-seating arrangement, it too

can be used in crooked wells. However, there is a

tendency for the valve rod to wear against the upper rod

guide in this case. This pump also can handle low-

gravity crude oil down to 400 cp quite well. Because of

its bottom-seating arrangement, the pump can be seated

easily in an old existing tubing pump barrel without pull-

ing the tubing, where a top-seated rod pump might be too

long to pass through an old tubing barrel.

The main disadvantage of this type of pump is that the

pump barrel extends upward into the tubing. This makes

it inadvisable to use a long pump, since it is not anchored

at the top, and the action of the sucker-rod string will

8-4 PETROLEUM ENGINEERING HANDBOOK

(b)

Fig. 8.2-Plain (a) and grooved (b) metal-to-metal plungers.

tend to weave it back and forth, which may cause

premature failure. Also, this pump is not recommended

for extremely sandy conditions, because there is no cir-

culation of the well fluid around the outside of the barrel.

For this reason, the pump may become stuck in the tub-

ing by packed sand.

Fig. 8.1~ shows a traveling-barrel rod pump. Many

operators prefer this type of pump because of its

simplicity and because its construction also relieves the

pump barrel of a tension load resulting from the weight

of the fluid column. A theoretical advantage of this type

of pump is that the pressure differential across the

plunger is such that the high pressure is on the bottom of

the plunger on the intake stroke and the direction of

leakage, or slippage, past the plunger is opposite to the

direction of the force of gravity, which tends to cause

sand to settle on the plunger. For this reason there is less

tendency for sand to be forced into the clearance space

between the plunger and barrel and accelerate wear.

Although the traveling-barrel rod pump is bottom seated,

it is not so likely to become sanded in the tubing as is a

bottom-seated stationary-barrel rod pump since there is a

continual surging of the well fluid in and out of the lower

end of the barrel while in operation. Also, the construc-

tion of this pump is such that sand cannot settle into the

barrel when the pump is shut down. A disadvantage of

the traveling-barrel rod pump is the long and somewhat

restricted inlet for oil to be admitted to the pump barrel.

This may result in a relatively high pressure drop through

the “pull tube” and plunger to liberate excessive quan-

tities of free gas or to cause the formation of condensable

vapors that will adversely affect the volumetric efficien-

cy of the pump.

Some suppliers offer a combination top-seal and

bottom-seating stationary-barrel rod pump. While this

pump is considered “nonstandard,” it combines the ad-

vantages of top-seating and bottom-seating pumps. It is

particularly advantageous when a long pump is required

in a deep well. This type of pump reduces the possibility

of a collapsed barrel caused by external pressure and

reduces sedimentation around the barrel tube. Because of

additional sealing arrangements, this pump is more cost-

ly than standard API pumps.

Fig. 8.ld shows the tubing pump, so named because

its barrel assembly, including barrel, extension nipples

(if any), and seating nipple, is screwed onto, and

becomes a part of, the tubing. Since the tubing and barrel

assembly are lowered into the well together, it is easy to

position a tubing pump at any desired depth for pump-

ing. After the barrel assembly is in position, the

standing-valve assembly is placed in the tubing, and it

falls until it is stopped and held by the seating shoe. The

plunger can be lowered into the well by attaching it to the

sucker-rod string or by lowering it with the barrel

assembly. In the latter case, an “off-and-on” attachment

is used to connect the sucker rods to the plunger.

Another device, called a “standing-valve-puller’ ’ (see

Fig. 8. Id insert), can be attached to the plunger to hold

the standing-valve assembly, so both can be lowered

together. The standing-valve assembly is released from

the standing-valve puller by turning the sucker-rod

string; so the standing valve assembly remains in place,

held by the seating nipple. If this action is reversed, the

standing-valve assembly can be attached to the plunger

and pulled out of the well with the sucker-rod string.

This eliminates the necessity of pulling the complete tub-

ing string to replace the standing-valve assembly.

Another advantage of using a standing-valve puller is

that the standing-valve assembly is not in danger of be-

ing damaged or becoming stuck, as is possible if it is

dropped through the tubing.

Tubing pumps have larger bores and correspondingly

greater displacements for a given stroke length than rod

pumps that can be used with the same size tubing.

Therefore, tubing pumps commonly are used where it is

necessary to lift large volumes of fluid and a pump of

high displacement is required. A tubing pump has fewer

working parts and is often lower in cost than a rod pump

of corresponding size. However, the greater volume and

resulting heavier fluid load may cause a loss in this ad-

vantage by excessive sucker rod and tubing stretch.

Also, the entire tubing string must be pulled to service

the barrel of a tubing pump.

Plungers

Fig. 8.2 illustrates the two most common types of

“metal-to-metal” plungers used for displacing well fluid

in oilwell pumps. The left side shows a plain plunger

with “box-end” threads. This type of plunger generally

is finished somewhat undersize at each end opposite the

threads. This provides for the slight expansion of the

plunger when tightened, without causing binding of the

plunger in the pump barrel. The right side shows a

grooved “pin-end” plunger.

Most subsurface-pump manufacturers provide both

plain and grooved plungers in various materials. It has

never been demonstrated conclusively that either type of

SUBSURFACE SUCKER-ROD PUMPS

8-5

TABLE 8.2-LOSSES RESULTING FROM SLIPPAGE

OF 3-cp OIL PAST 2%~in. PUMP PLUNGER’

Slippage Loss in Pump

Slippage Past Plunger

at 15 strokedmin

Diametral Slippage Rate

Percent Pump

Clearance (cu in./min)

cu in.lmin BID Displacement

0.003 11.43 5.72 0.85

0.2

0.006 91.5 45.8 6.8

1.6

0.010 424.0 212.0 31.5

7.4

0.020 3,390.o 1,695.O 251.8

59.2

‘48 in. long with 2,000 ps dlfferentml pressure and vmous plunger fits. Also shppage in

percent pump displacement wth fifteen 48-m slrokes per mmufe.

construction has any particular advantage over the other.

Many operators feel that grooves facilitate lubrication of

closely fitted plungers by providing spaces for the well

fluid to accumulate in considerable quantities. However,

there is considerable slippage past any plunger operating

under usual conditions where the differential pressure

across the plunger is several hundred or even thousands

of pounds per square inch. This slippage will provide

adequate lubrication with either type of plunger if the

fluid has any lubricating value. One possible advantage

of a grooved plunger is that any solid particle, such as a

sand grain or a steel chip that gets between the plunger

and the barrel, may become lodged in a groove and

minimize scoring of the barrel and plunger. With a plain

plunger, particles cannot escape from the finished sur-

faces until they have traveled the full length of the

plunger. On the other hand, a grooved plunger stroking

out of a barrel increases the probability of picking up and

carrying solid material into the barrel.

The high differential pressures encountered in pump-

ing deep wells require an effective sealing or packing

means on the plunger. For wells of extreme depth, a

closely fitted metallic plunger is almost always used to

form a satisfactory seal with the barrel. Such plungers

are commonly supplied with nominal clearances of

0.001, 0.002, 0.003, or 0.005 in. in the barrel. Such

plunger fits are commonly referred to as - 1, -2, -3,

or -5 fits. For metal-to-metal pumps the API tolerance

for barrels is +0.002 in., -0.000 in., and the tolerance

for plungers is +O.OOOO in., -0.0005 in., making it

possible for the fit of a - 1 plunger, for example, to vary

from 0.0010 to 0.0035 in. diametral clearance.

Slippage Past Plungers

In slippage past a closely fitted plunger, the flow be-

tween the plunger and the barrel is in the viscous range,

so leakage or slippage is inversely proportional to the ab-

solute viscosity and to the plunger length. It is directly

proportional to the plunger diameter, the differential

pressure between the two ends of the plunger, and the

cube of the diametral clearance.

The absolute viscosity of well fluids commonly

pumped will range from approximately 1 to 100 cp at

temperatures existing at the pump setting. In some cases

the viscosity may be as high as 1,000 cp. As a result of

viscosity variations, the slippage past the plunger of a

particular plunger-pump assembly with a given plunger

fit, length, and diameter may vary by as much as 100 to

1 under fairly common conditions. and as much as 1,000

to 1 under extreme conditions with the same differential

pressure across the plunger. Thus it is seen that a plunger

pump may operate with acceptable efficiency in a well

producing a highly viscous oil, whereas the same pump

operated at the same speed and stroke may fail to deliver

any oil to the surface when installed at the same depth in

a well producing oil of low viscosity.

The following equation can be used to determine slip-

page losses past a pump plunger with sufficient accuracy

for most purposes.

adApAd C 3

pLx2.32x 1o-7 ) . .

where

4 = slippage loss, cu in./min (or 0.2371 cm’/s),

d = plunger diameter, in.,

Ap = differential pressure across plunger, psi,

Ad,. = diametral clearance, in.,

L = length of plunger, in., and

CL = absolute viscosity, cp.

A specific application of this equation will illustrate

the importance of plunger fits for a pump of a particular

bore and stroke, operating with various plunger fits in

fluids of various viscosities.

If we assume a 2%-in.-bore pump having a 0.003-in.

diametral clearance and operating with a pressure dif-

ferential of 2,000 psi between the two ends of a 48-in.

plunger at a rate of fifteen 48-in. strokes per minute in oil

having a viscosity of 3 cp, then Eq. 1 becomes

ax2.25x2,000x2.7x10-s

3x48x2.32x lo-’

= 11.43 cu in./min.

If we assume that the volume of the barrel below the

plunger is completely filled during the upstroke, this rate

of leakage can occur only during the upstroke, or ap-

proximately one-half of the total time. The net slippage

past the plunger is 5.72 cu in./min, or 0.85 B/D. The

displacement of a 21/4-in. pump operating at fifteen

48-in. strokes per minute is 426 BID, and the slippage in

this case is only about 0.2%, which is insignificant. The

results of this and other plunger clearances with 3-cp oil

are shown in Table 8.2.

In the case of 0.020-in. plunger clearance, the slippage

loss when water or oil with a viscosity of 1 cp is pumped

would be 755 B/D, which is more than the pump

displacement, and it would be impossible to pump water

8-6

PETROLEUM ENGINEERING HANDBOOK

to the surface. or to a level requiring 2,OOC-psi pressure

differential across the plunger. When pumping oil with a

viscosity of 100 cp, however, the slippage would be only

about 7.5 B/D, or less than 1.8% of the pump displace-

ment, and a clearance of 0.020 in. is reasonably satisfac-

tory for these conditions.

Slippage losses result directly in power losses, since

the same power is required to lift the plunger, with 90%

of the fluid slipping past the plunger during the upstroke

as is required with 1% or less slippage. The energy

dissipated in slippage losses results in an increase in

temperature of the oil within the pump and a decrease in

viscosity that further increases slippage losses. Also,

when water is produced with oil, excessive slippage

losses increase the chances of forming emulsions.

Close plunger clearances are relatively more important

with small-bore pumps than with larger bores, inasmuch

as the displacement for a given stroke length and speed

varies as the square of the diameter, whereas slippage

varies as the first power of the diameter. Close plunger

clearances are especially important in small pumps

BUSHING

WEAR RING

El-

END RING

Ikft-

MANDREL

CUP RING

KY-

WEAR RING

- LOCKNUT

- BUSHING

operated at extremely low speeds. as used in stripper

wells in some areas. The method outlined here should be

satisfactory for evaluating maximum slippage in most

cases.

Soft-Packed Plungers

Fig. 8.3 shows the cup- and ring-type plungers. The left

side shows composition-formed cups used to seal the

plunger against the barrel. The right side shows com-

position rings (generally square or rectangular in shape)

used for sealing. Some operators prefer a combination of

both cups and rings on a single plunger. The applications

of such soft-packing arrangements generally are limited

to shallow wells and to those where abrasive conditions

are not excessively severe. Where this type of plunger is

satisfactory, it has the advantage of being easily and less

expensively reconditioned with new cups or rings, and

the flexible packing will compensate for considerable

wear of the barrel as long as the barrel surface remains

smooth.

BUSHING

WEAR RING

PACKING RING

SPACER RING

MANDREL

WEAR RING

LOCKNUT

BUSHING

Fig. 8.3~Soft-packed plungers: (a) cup type; (b) ring type.

SUBSURFACE SUCKER-ROD PUMPS

8-7

Balls and Seats

Fig. 8.4 illustrates the type of ball-and-seat combination

commonly used for check valves in subsurface pumps.

Balls and seats are made in a variety of materials to resist

extremely abrasive and corrosive conditions. API Stan-

dard 11 AX ’ lists the important dimensions of standard

sizes along with the pump sizes with which they are

commonly used

Double Valves

Fig. 8.5 shows common arrangements of two valves in

series used both as traveling valves and as standing

valves. Experience has shown that two valves in series

will give much longer service than a single valve if the

valve life is determined by wear or fluid cutting, rather

than by corrosive action. This result appears entirely

logical where sand or other solid material is lifted with

the oil. In such cases failure is likely to occur as a result

of fluid cutting when a solid particle is caught between

the ball and seat and prevents perfect seating. A pressure

differential of 2,000 psi will produce a jet of fluid having

a velocity of over 500 ft/sec, which can easily damage

PUMP BARREL

1 STANDINGVALVES

BALL & SEA-I

VALVES

SEATING SHOE

c BODY

SEATING CUPS

TAPER-CUP NUT

Double Standing Valve

PLUGER

CLOSED CAGE

BALL & SEAT

VALVE

CLOSED CAGE

BALL & SEAT

VALVE

RETAINER

Double Valve on Bottom

of Plunger

Fig. 8.5-Double-valve arrangements.

Fig. 8.4-Pump valve ball and seat.

PULL ROD

OPEN CAGE

BALL & SEAT

VALVE

CLOSED CAGE

BALL & SEAT

VALVE

PLUNGER

Double Valve on Top

(a)

8-8

PETROLEUM ENGINEERING HANDBOOK

Fig. 8.6~-Bottom-discharge valve for use with bottom-

seating stationary-barrel rod pumps. This valve is

attached to the bottom of a pump and through it

part of the well fluid is diverted up the side of the

pump to help dislodge sand that may have settled

between the pump and the tubing.

the lapped valve-seating surface on balls and seats in a

short time. The rate of damage is accelerated if the fluid

jet carries solid material in suspension.

The life of a ball and seat will depend largely on the

number of times it is subjected to damage by fluid jets.

By use of double valves this can be greatly decreased,

since a jet cannot occur until both balls are held off their

seats during the same stroke. For example, if conditions

are such that a single ball and seat is prevented from

seating properly once out of each 100 strokes, the

chances of both valves in series failing to seat properly

will be reduced to 1 in 10,000 strokes. Furthermore, if

the two valves fail to seat, the pressure drop will be

distributed between the two valves and the cutting action

will be less severe than with a single valve.

Bottom-Discharge Valve

The bottom-discharge valve shown in Fig. 8.6 is used in

connection with bottom-seating stationary-barrel rod

pumps and is designed to cause part of the fluid dis-

charged from the pump to circulate up around the outside

GUIDE

TOP

SEAL

SEATING

NIPPLE

RING-TYPE

BOTTOM

ANCHOR

SEATING

NIPPLE

MANDREL

SEATING RING

SPACER RING

RING NUT

TOP ANCHOR

BUSHING

SEAL

Fig. 8.7-Top seal and bottom seating for stationary

rod pumps.

‘-barrel

of the pump barrel. This is done to prevent sand from

settling around the pump, which may make it impossible

to pull the pump on the sucker rods. The bottom-seating

arrangement for a rod-type pump is desirable in wells of

extreme depth since the pump barrel is relieved of the

fluid load, which places the barrel in tension. When top

seating is used, the barrel is subjected to a high pressure

which tends to expand the barrel.

Fig. 8.7 illustrates another means for utilizing the ad-

vantages of bottom seating with a stationary-barrel rod

pump and preventing sand from settling around the out-

side of the pump barrel. This assembly utilizes a

mechanical bottom-seating assembly, with seating cups

or rings that fit into a slightly restricted seating nipple,

properly spaced in the tubing to form a seal at the top of

the pump barrel.

Three-Tube Pump

This type of pump is illustrated in Fig. 8.8 and gets its

name from the three tubes used in its construction. The

complete pump assembly is lowered into the well on the

SUBSURFACE SUCKER-ROD PUMPS

sucker-rod string and is positioned in the well by contact-

ing either a cup-seating assembly or a mechanical lock

holddown. The middle tube of the pump is stationary, at-

tached to the holddown. The other two tubes attached to

the sucker-rod string move over the middle stationary

tube, one on the outside and one on the inside. The tubes

used in this pump are relatively long and have a relative-

ly large operating clearance in comparison with the usual

pump plunger. The resistance to flow between the tubes

is adequate to create the seal necessary to displace the

fluid past the standing valve and through the traveling

valve against the tubing pressure. This pump is designed

primarily to clean out wells after workover operations or

formation-fracturing operations, which may make the

well produce large quantities of sand for a considerable

time. It is also used in wells producing from loose-sand

formations that consistently produce quantities of fine

floating sand.

Gas Anchors

Where conditions are such that there is considerable free

gas in the well fluid at the pump intake, it is desirable to

prevent as much gas as possible from entering the pump

and permit the gas to rise to the surface through the cas-

ing annulus rather than through the tubing. Numerous

so-called gas anchors are in use that are designed to

separate the free gas and deflect it up the casing annulus.

Fig. 8.9 illustrates a common type of gas-anchor ar-

rangement in which the well fluid must enter the per-

forated nipple and circulate downward at a low velocity

before entering the gas-anchor tube, which is attached to

the pump intake. This gives the free gas an opportunity

to separate and rise to the uppermost ports in the per-

forated nipple where it may return to the casing. A large

portion of the gas will rise through the casing before

passing through the perforated nipple.

Special Pumps

There are many other special types of subsurface pumps

for use in special problem situations. Most of these are

considered “non-API” pumps, although they may use

some parts that meet API specifications in their construc-

tion. One special pump is the casing pump, which is

designed to be inserted directly into the casing without a

string of tubing. Such pumps are set in the casing on a

packer or casing anchor that grips the casing and holds

the pump in position. Such pumps are limited in size on-

ly by the casing size and can be made to have a very

large capacity in relatively shallow wells. However, with

this arrangement, all the gas produced with the well fluid

must pass through the pump, and this may seriously limit

the effective capacity in wells producing large quantities

of gas.

Another special type of pump that is used to some ex-

tent is an arrangement where two displacing plungers are

designed to act in series. This increases the displacement

of a pump that will run in a given size of tubing and at a

given stroke length. Another variation of this concept

uses two valves and seats in the lower plunger and none

in the upper plunger. This allows a fluid load on the

lower plunger at all times and assists the sucker rods in

falling on the downstroke. which is desirable for the

more viscous fluids.

8-9

rt-

TUBING

SUCKER ROD

TOP TRAVELING

VALVE

OUTSIDE

TRAVELING

TUBE

INSIDE

TRAVELING

TUBE

STATIONARY

TUBE

BOTTOM

TRAVELING

VALVE

STANDING VALVE

SEATING SHOE

SEATING CUPS OR

RINGS HOLDDOWN

GAS ANCHOR

-TUBING

-SEATING SHOE

_ PERFORATED

NIPPLE

-GAS ANCHOR

-TUBING

-COUPLING

-BULL PLUG

Fig. 8.8-Three-tube pump

Fig. 8.9-Gas-anchor arrangement.

Fluids with large amounts of gas can cause gas locking

or at least reduced flow because of expansion of gas in

the chamber between the plunger and the standing valve

on the upstroke. This situation can sometimes be re-

lieved by a special pump having two so-called compres-

sion chambers that serve to increase the compression

ratio in those chanbers above that normally obtainable in

a standard pump.

Corrosion

In some areas resistance to corrosion of the materials

used in subsurface pumps is of major importance. A

wide variety of alloy irons, steels, nonferrous alloys. and

elements have been used to combat corrosive conditions

E-10

PETROLEUM ENGINEERING HANDBOOK

in various locations. Some of the corrosive agents com-

monly found in various locations are hydrogen sulfide,

carbon dioxide, salt waters containing sodium chloride.

calcium chloride, magnesium chloride, and other salts.

Chemical corrosion inhibitors are now widely used by

many operators. Such inhibitors are fed either con-

tinuously or intermittently down the casing into the well.

Protective films arc formed on the tubing and rods, as

well as on pump parts. However, since protective films

cannot form on wearing surfaces, the closely fitted pump

parts in rubbing contact are not protected as well as the

rods and tubing by corrosion inhibitors. For this reason it

is more important to use corrosion-resistant materials in

the construction of subsurface pumps.

Effect of Gases and Vapors

In selecting pumping equipment for oil wells remember

that in a majority of cases some of the constituents of the

fluid being pumped are above or near their boiling points

at the pressure and temperature conditions existing

within the pump. These conditions may cause release of

large volumes of dissolved gases and vapors with a slight

drop in pressure of the well tluid, in addition to the free

gas initially in the fluid. For this reason it is very dif-

ficult to pump some wells down. Many wells apparently

will pump off with several hundred feet of fluid standing

in the hole because the condensable vapors and gases oc-

cupy the entire displacement volume of the pump. Under

these conditions.

without a relatively high intake

pressure,

which decreases compression ratio, the

pressure below the plunger cannot be raised to the tubing

pressure. (This is necessary before the traveling valve

can open and deliver oil to the tubing.) On the

downstroke the vapors may condense and occupy a very

small volume without an appreciable increase in

pressure, and only the permanent gases are effective in

increasing the pressure in accordance with the gas laws.

There are two precautions to take to minimize the

adverse effects of vapors and gases.

I. The compression ratio should be made as high as

possible. This is accomplished by using a closed-cage-

type valve below the plunger with a stationary-barrel

pump, or a valve above the plunger with a traveling-

barrel-type pump. It is also important to space the pump

so the traveling valve and standing valve come as near to

each other as possible at the lowest position of the rods

without making contact, and to use as long a stroke as

possible with the equipment available.

2. Flow velocities and turbulence at the pump inlet

should be kept at a minimum. This is accomplished by

using the largest standing valve possible and a suitable

gas anchor with the largest possible flow passages.

Conclusions

Most items covered in this section are discussed in Ref.

2, which was first issued in 1968 and is updated regular-

ly. It is recommended that this source be referred to for

state-of-the-art information about subsurface pumps.

It is well known that because of the dynamics involved

in the sucker-rod string, the fluid, and the tubing during

pumping cycles, the plunger stroke of the subsurface

pump is seldom equal to the stroke of the pumping unit

and its accompanying polished rod at the top of the well.

During pump operation the fluid load, which is altemate-

ly transferred from the tubing to the sucker rods, causes

the tubing to increase in length on the downstroke when

the tubing is supporting the fluid load. When the rods are

carrying the load on the upstroke, there is a shortening of

the tubing with an increase in the length of the sucker

rods. Both effects tend to shorten the plunger stroke in

the well in comparison with the polished-rod stroke at

the surface.

Because of the dynamic effects and the inertia and

elasticity of a string of sucker rods, there will be some

additional stretch in the rods during the pumping stroke.

This effect is known as overtravel and results in an in-

crease in the stroke length at the subsurface pump.

In years past, the calculation of sucker-rod and tubing

stretch, as well as overtravel, was accomplished with a

rather simple set of equations using tables and curves

developed for this purpose. Later it was recognized that

there are many factors in a pumping well that make the

calculations a complex problem. In 1954 a group of

users and manufacturers of sucker-rod pumping equip-

ment formed Sucker Rod Pumping Research Inc., a non-

profit organization, to study the problems of pumping

wells. They in turn retained Midwest Research Inst. of

Kansas City to achieve their objectives. Their study

covered several hundred pumping wells and resulted in

design calculation methods that more nearly match ac-

tual pumping conditions than previous methods. The

results of the study were turned over to the API Produc-

tion Dept. The API in turn adopted these methods.’

These design calculations are too involved and lengthy to

be included in this section. It is suggested that Ref. 3 be

used to determine the design values of a pumping

system.

References

1. “API Specification for Subsurface Pumps and Fittings.” API

Spec 1 IAX, seventh edition. Dallas (June 1979).

2. “API Recommended Practice for Care and Use of Subsurface

Pumps,”

API RP IIAR, second edition. Dallas (March 1983).

3. “API Recommended Practice for Design Calculations for Sucker

Rod Pumping Systems (Coventional Units).” API RP I IL. third

edition, Dallas (Feb. 1977)