conference programme9[1]

8/6/2019 Conference Programme9[1]

http://slidepdf.com/reader/full/conference-programme91 1/17

AbstractThe use of jet pumps has proven to be extremely

advantageous and cost effective for operators in the

following cases:

a) For dewatering gas wells

b) For frac fluid recovery operations

c) For when the well has stopped flowing

d) To boost production from wells

e) For when an existing gas lift well is proving cost

prohibitive

or the gas is depleting

f) To clean sandy wells prior to running EPS’s

g) Performing DST’s prior to installing production pumps

h) In hybrid systems as a backup to gas lift or ESP

In addition to the above, a coiled tubing jet pump (Figures 1

and 2) can be used so that the existing tubing typically does

not need to be pulled, or when the casing is no longer a

viable fluid flow conduit. When the size of the existing

tubing in the well is 2-3/8” or larger, the pump standing

valve and seal areas are attached to the coiled tubing (either

1-1/4” or 1-1/2”). They are run in as a unit and seated on a

tubing packer. The pump can then be circulated in and out

hydraulically, or it can be installed/retrieved via standard

wireline.

Production rates of as much as 2000-3000 bpd can be

achieved for the full size jet pumps (Figure 3) and 600-800

bpd for the coiled tubing jets inside of either 2-3/8” or larger

tubing. As with all jet pump production rates, the aboverates are highly dependent on well conditions especially the

pump-intake-pressure (or flowing bottomhole pressure at

pump depth).

This paper will center on the first two items in the above list

along with actual installation results for both (see Figures 4

and 5).

DiscussionThe 1-1/4” and 2-3/8” sizes of jet pumps have become the

hydraulic pumps of choice for these applications. Both

pumps were developed so that they can be used either as

free style pumps inside of their respective tubing string orattached to it (known as fixed style). Both the 1-1/4” and 2-

3/8” tubing sizes can be used as either coil tubing or as stick

pipe and run inside a larger string of tubing. The power fluid

goes to the pump through the inner tubing string and the

produced fluid combined with the spent power fluid returns

to the surface through the tubing-tubing annulus. The gas is

free to flow to the surface through the casing-tubing annulus

(Figure 2).

The jet pump is well suited to this application because it is

highly tolerant of particles in the produced fluid, and can

easily be used in applications where the GLR through the

pump is typically no more than the 1000-1500 scfpb range.

While they can be easily used at higher GLR’s (and have

been), the required horsepower for the power fluid pump

located on the surface might be more than an operator caresto install.

It should be noted that while the different sizes of jet pumps

are more than capable of the production rates mentioned

above, they are not capable of the low rates necessary to

pump-off a well. Before the flowing bottomhole pressure

declines to or even approaches the level for a pumped off condition, the pump will enter a condition known as “power

fluid cavitation” (Figure 6). This condition is not as well

known as production cavitation but it is something that

should be avoided. An appendix is included that has

information on the theory, advantages and disadvantages of

jet pumps along with a section on trouble shooting.

The essential differences between the typical gas well

dewatering installation and a frac fluid recovery installation

are their respective production volumes and the portions of

their respective IPR curves that are used. The reason for

dewatering a gas well is to remove the back pressure on the

formation so the gas can easily flow to the surface, and

uncovering no more than half of the perforations will

usually accomplish this. The liquid producing rates in gas

wells tend to be relatively small (no more than a few 100

bpd or less) so the jet pump will be designed to cover the

lower end of the PI/IPR curve while staying out of the

power fluid cavitation area. Once the gas is flowing freely to

the surface, the jet pump can be removed or left in place asdesired. For a frac fluid recovery installation, the goal is to

remove the frac fluid from the formation as quickly as

possible. This leads to producing rates that tend to be verylarge (1000’s of bpd with higher FBHP’s) so the jet pump

will be sized to cover the upper end of the PI/IPR curve.

Usually, only about 50% of the injected frac fluid is

recovered before the gas is flowing freely. At that time, the

jet pump is normally removed from the well to allow more

flow area for the gas.

Jet pumps are also used in dewatering coal bed methane

wells where the primary difference between those wells and

the previously discussed wells are the fines. While the finesin a CBM well are coal fines, they are typically no worse

than the frac sands in a frac fluid recovery well or formation

sands in a gas well. While some CBM wells have fines that

are sharp and angular, the same is also true of fines in other

types of formations such as the Bromide formation in

Oklahoma. Also, it should be noted that the high strength

frac sands do not create any unusual problems for a jet

pump. In those wells which have damaging fines, the area in

the jet pump that is typically the most damaged is around

the entrance to the throat. It has been found that using a

throat made of silicon carbide, instead of the standard

tungsten carbide, greatly improves the life of the pump in

ADVANTAGES OF USING JET PUMPS TO DEWATER GAS WELLS AND FOR

FRAC FLUID RECOVERYToby Pugh, Weathreford International



2 [Paper Nu

such wells. It has also been reported that the fines in CBM

wells tend to clump together inside of the downhole jet

pumps. However, an investigation of this claim disclosed

that clumps have been found on the surface but no evidence

was found of any clumps in the jet pumps.

Sizing Considerations

A jet pump must have a capacity that is sufficient to obtainthe rate of production that the well is capable of delivering.

At the same time, the required surface horsepower must be

kept at a reasonable level. The first part of the process

involves matching the jet pump performance curves with the

PI/IPR of the well. The balance of the process involves

staying within the operating limitations for a particular

installation. The most common limitations are power fluid

injection pressure and/or rate, and space limitations (such as

for offshore installations). In addition, the backpressure (or

discharge pressure) imposed on a jet pump always needs to

be as low as possible.

A computer is almost always required for the analysis, as

the solution is an iterative process if gas is present and it has

been known to require almost 50 iterations to obtain a

convergence. An analysis can be done with a hand-help

calculator if the GLR is 10 or less as a flowing gradient

correlation would not be needed.

TYPES OF SUBSURFACE PUMP INSTALLATIONSThere are three basic subsurface pump systems: the free-type,

the fixed-type, and the wireline-type. The first two are most

commonly used for gas well dewatering and frac fluid

recovery (see Figure 7).

FREE-TYPE INSTALLATIONS

The free-type system does not require a pulling unit to runor retrieve the pump. The pump is placed inside the power

fluid tubing string and is "free" to move with the power

fluid to the bottom of the well and back out again when the

power fluid direction is reversed (Figure 8). This may be the

primary advantage of hydraulic pumping systems.

FIXED-INSERT INSTALLATIONSIn a fixed-insert installation a large tubing string is run to

bottom. The pump is then run on a smaller tubing string

inside the main tubing string and seated in a seating shoe. In

this design, the smaller string carries the pressurized power

fluid to the pump. The exhausted power fluid plus the

produced fluids are carried to the surface through the tubing-tubing annulus. This allows gas to be vented up the casing

annulus to the surface.

A variation of this design would involve a packer set below a

bottomhole assembly. This isolates the producing zone below

the packer from the rest of the well but will cause all of the

produced gas to go through the jet pump. This design would

also be advantageous whenever bad casing up the hole is a

problem or whenever it is necessary to isolate the zone being

producing from another zone above the packer but it would

not be considered to be a good choice for dewatering a gas

well.

SURFACE POWER FLUID CONDITIONINGSYSTEMSThe purpose of a surface power fluid conditioning system is

to provide a constant and adequate supply of suitable power

fluid to operate the subsurface pumps. The success and

economical operation of any hydraulic pumping fluid

installation is, to a large extent, dependent on theeffectiveness of the surface conditioning system in

supplying clean power fluid for the surface power pump and

down-hole pump.

The presence of gas, solids, or abrasive materials in the

power fluid will seriously affect the operation and wear life

of the surface power fluid pump well before any damage is

done to the downhole pump. Therefore, the primary

objective in conditioning crude oil or water for use as power

fluid is to make it as free of gas and solids as is practical. In

addition to removing gas and solid material, adding a

chemical treatment to the power fluid at the surface could

increase the wear life of the pumping equipment.

POWER FLUID CHOICESThe liquids that are predominately used for the power fluid

are those produced by the well — typically water or oil.

Arguments can be made for and against the use of either of

them as a power fluid so the final choice must be made by

the operator.

LIMITATIONS OF OTHER FORMS OF LIFTIt has always been recognized that the weak link and

limiting factor in sucker rod-pumping systems is the sucker

rod itself. The thousands of feet of rods needed to transmit

the reciprocating motion from the surface to the bottom-hole

pump cannot be made strong enough to lift large loads fromgreat depths. Even with the high strength Class "D" rods

and tapered string designs, it would not be possible to have

more than approximately 40,000 lb. peak load without over

stressing the top rods and causing failures. The top rod

must lift not only the well fluid on every stroke but also the

weight of the submerged rods, which can be as much as 15

tons. The combined effects of the weight of the rods and the

dynamics of cyclic loading along with rod/tubing wear in

less-than-straight wells impose serious limitations on

pumping depths and associated production volumes.

The use of high volume electric submersible pumping is

increasingly limited as producing horizons become deeper.Problems include the loss of power in the cable, the pressure

limitations of the pump discharge housing, the large number

of stages and the horsepower of the motor.

The use of gas lift is also restricted due to producing

bottom-hole pressure requirements. As a rule, it is not

possible to obtain as much drawdown of the reservoir with

gas lift as with pumps, provided gas interference is not a

problem with the pumps. In addition, deep wells may

require high injection pressures, which can adversely affect

the casing. Gas lift, however, can still be advantageous in

gassy or sandy wells, or wells that are very expensive to



[Paper Number]

service due to pulling the tubing if the gas lift valves that are

used are installed/retrieved with wireline.

CONCLUSIONSUsing jet pumps has shown to be both effective and easy to

use for dewatering gas wells and for frac fluid recvery. In

addition to the versatility it offers to match the wells

production rate by simply changing the nozzle and/or throat,it also offers the operator an opportunity for a significant

cost savings as compared to other forms of lift.

ACKNOWLEDGEMENTThe author would like to thank the management of

Weatherford International for its support in writing this

paper.

ReferencesRef 1: SPE 20024, Artificial Lift with Coiled Tubing for

Flow Testing the Monterey Formation, Offshore

California

Ref 2: SPE 35586, Coiled Tubing Conveyed Jet Pump

Application

Ref 3: Weatherford Internal Document, “Overview of

Hydraulic Pumping” by Toby Pugh

List of IllustrationsFig. 1 1-1/4” Colied Tubing Jet Pump

Fig. 2 1-1/4” Coiled Tubing Jet Pump Installation

Fig. 3 Typical Full Size Jet Pump

Fig. 4 Gas Well Installation Results

Fig. 5 Frac Well Installation Results

Fig. 6 Schematic of Cavitation Bubbles and Damage Due

to “Power Fluid Cavitation”

Fig. 7 Free and Fixed Pump Installations

Fig. 8 Installing/Removing a Free Style PumpFig. 9 Schematic of Flow Velocity and Static Pressure in

a Jet Pump

Fig. 10 Flow Rates/Pressures Entering and Leaving a Jet

Pump

Fig. 11 Volume/Pressure Relationships for Different Area

Ratios

APPENDIXTHEORY OF JET PUMPS

The key components of a jet pump are the nozzle and throat.

The ratio of the areas of these two parts is referred to as the

area ratio of the pump and it determines the performance

characteristics of the pump. Pumps with the same area ratio

have the same performance and efficiency curves. Note: The

power fluid and production flow rates must be within the

design parameters of the physical nozzles and throats being

used in order for them to function correctly. It is not

uncommon for someone to focus on the ratios used in jet

pumps, such as the area ratio, and forget about the actual

sizes of the parts being analyzed. This can lead to

misapplications and failure to perform as desired.

Power fluid is pumped at a given rate (QS) to the down-hole jet pump where it reaches a nozzle with a total pressure,

designated as PN (see Figure 9). This high-pressure liquid is

then directed through the nozzle, which converts the fluid

from a low velocity, high static pressure flow to a high

velocity, low static pressure flow (PS). The low static

pressure (PS) allows well fluids to flow from the reservoir at

the desired production rate (QS) into the well bore and

pump. The volume of power fluid used will be primarily

proportional to the size of the nozzle.

Whenever a high velocity jet of liquid is introduced into a

stagnant or slowly moving liquid, a dragging action occurs

at the boundary between the two liquids due to the

interaction of the high velocity particles with the low ve-

locity particles. The mixing of the two liquids is initialed by

this dragging action and the transfer of momenta accelerates

the slow liquid in the direction of flow. The mixing of the

two streams at this point is minimal at most as the slow

moving liquid at the boundary is able to move away from

the high velocity jet. The slow liquid then enters a region of

decreasing area, which is the annulus between the mixture

stream and the inner walls of the throat. At the throat

entrance, that annular area is the difference between nozzle

exit area and throat area. As the two flows progress, a

through mixing of the two streams takes place because the

slow moving liquid at the boundary is not able to move

away due to the walls of the throat. The area of the mixturestream progressively spreads while the area of the core of

the high velocity jet progressively decreases until it

disappears (see Figure 10). At or before the throat exit the

mixture stream has spread until it touches the walls of the

throat. At that point, all of the slow liquid has been mixed

with the primary jet. The flow then exits the pump through a

diffuser section, which converts it to a high static pressure,

low velocity state. This high discharge pressure (Pd) must

be sufficient to lift the combined flow rate (Qt) to the

surface.

The area of the throat must be able to pass the power fluid

as well as the liquids and gas being produced. The area inthe pump that must accommodate just the produced fluids

(liquid and gas) is the annular area between the nozzle and

the throat and it is this area that determines the cavitation

characteristics of the pump.

For high flow installations the size of the nozzle is chosen

such that the annulus area in the throat is maximized. The

resultant area ratio is excellent for high flow/low lift

requirements. The reverse is true for low production rate

installations where the annular area annulus is minimized.

The resultant area ratio for this case is excellent for high



4 [Paper Nu

lift/low flow installations. However, high lift ratios are more

susceptible to cavitation than are the low lift ratios (see

Figure 11).

Advantages/Disadvantages of Hydraulic PumpsThere are numerous advantages of a hydraulic pumping

system as compared to sucker-rod, ESP or gas-lift systems.

One major advantage is that it will operate over a widerange of well conditions such as setting depths of as much

as 18,000 feet and production rates of as much as 35,000

bpd. Virtually all of the following advantages apply to

dewatering gas wells as well as typical production

installations.

• Typically, no rig is required to retrieve free

pumps. In many cases, this may be the primary

advantage of hydraulic pumping systems as

compared to the other systems.

• Jet pumps are highly flexible in adjusting to

changing production rates.

Jet pumps can operate more reliably in deviated

wells. Chemicals can be added to the power fluid to

control corrosion, paraffin, scaling, etc. plus

fresh water can be used to desolve salt deposits.

Jet pumps have no moving parts.

Jet pumps can typically perform better in higher

GLR wells than positive displacement pumps,

such as progressive cavity pumps, rod pumps,

hydraulic piston pumps and ESP’s.

Jet pumps have long run lives.

Standard jet pujps can operate successfully in

temperatures as high as 400oF by simply using

high temperatuere elastomers for their o-rings

and sseal rings. Jet pumps have low maintenance costs.

Jet pumps are field repairable.

Jet pumps can be installed in sliding sleeves,

wireline nipples and across gas lift mandrels as

well as their own bottomhole assemblies.

Jet pumps have a high tolerance for solids in the

production fluids.

Jet pumps have a high tolerance to corrosive

fluids through the use of CRA materials and/or

inhibitors entrained in the power fluid.

The power fluid serves as a diluent when

producing viscous crudes.

The power fluid can be heated (usually water) toproduce heavy crudes or crudes with high pour

points.

The disadvantages connected with a hydraulic pumping

system include:

It is often misapplied (this is a common problem

for all forms of artificial lift).

It requires knowledge by operating personnel

(this is a common problem for all forms of

artificial lift).

Surface pressures of as much as 5000 psi might

be a safety hazard.

Conditioning of the power fluid is required in

order to have a supply of clean power fluid. Sand

or other particles in the power fluid must be

removed as they can damage the power fluid

pump on the surface, the nozzle in a jet pump

and the throat in a jet pump. A jet pump cannot “pump-off” a well. It requires

a minimum flowing bottomhole pressure in order

to avoid “power fluid cavitation”. That minimum

pressure can be as much as 10%-30% of the

hydrostatic based on the TVD of the pump and

the makeup of the fluids being produced.

However, it has been reported that some jet

pumps were able to be operated with just 3% of

the hydrostatic pressure without cavitating

issues.

The use of hydraulic pumps offshore has

typically been limited to those platforms where a

water injection system is already in place, as thedeck space requirements for the surface

equipment normally exceed what is available.

Casing pressure capability can be a limitation for

reverse flow installations.

Jet pumps have low operating efficiencies which

result in a higher installed horsepower than what

is needed by other forms of lift.

The power fluid injection rate for jet pumps will

vary from 1 - 4 times the production rate, which

depends primarily on the PI/IPR of the

formation.

The back pressure imposed on a jet pump has a

strong influence on the power fluid injectionpressure and can increase the injection pressure

by 1-1/2 to 4 psi for each psi of back pressure.

The rate of increase for a particular jet pump is

determined by the area ratio of that pump (the

area of the nozzle divided by the area of the

throat).



[Paper Number]

TROUBLE SHOOTING — CAUSES AND SOLUTIONS

INDICATION CAUSE REMEDY

Sudden increase in operating

pressure – power fluid rate

constant or reduced.

(a) Paraffin build-up or obstruction in power o il line, flow line, or

valve.

(b) Partial plug in nozzle.

(a) Run soluble plug or hot oil, or remove obstruction. Unseat

and reseat pump.

(b) Retrieve pump and clear nozzle.

Slow increase in operating

pressure with constant power fluid

rate, or slow decrease in power

fluid rate with constant operating

pressure.

(a) Slow build-up of paraffin.

(b) Worn throat or diffuser

(a) Run soluble plug or hot oil.

(b) Retrieve pump and repair.

Sudden increase in operating

pressure and power fluid rateessentially stopped.

(a) Fully plugged nozzle. (a) Retrieve pump and clear nozzle.

Sudden decrease in operating

pressure with power fluid rate

constant, or sudden increase in

power fluid rate with operating

pressure constant.

(a) Failure in power fluid tubing string.

(b) Blown pump seal or broken nozzle.

(a) Check tubing for leaks and pull and repair if leaking.

(b) Retrieve pump and repair.

Drop in production while all

surface measurements conditions

remain normal.

(a) Worn throat or diffuser.

(b) Plugged standing valve or pump.

(c) Leak or plug in gas vent.

(d) Changing well conditions.

(a) Increase operating pressure. Replace throat and diffuser.

(b) Retrieve pump and check. Retrieve/check standing valve.

(c) Check gas vent system.

(d) Run pressure recorder and resize pump.

No production increase when

operating pressure is increased.

(a) Cavitation damage in pump or high gas production.

(b) Plugging of standing valve or pump.

(a) Lower operating pressure or install larger throat.

(b) Retrieve pump and check. Retrieve/check standing valve.

Throat worn as noted by one or

more dark, pitted zones.

(a) Cavitation damage. (a) Check pump and standing valve for plugging. Install larger

throat or reduce operating pressure to reduce velocity.

Throat worn – its cylindrical shape

changed to barrel shape, smooth

finish.

(a) Erosion. (a) Replace throat, preferably with a premium material throat.

Install a larger nozzle and throat to reduce velocity.

New installation does not meet

prediction of production.

(a) Incorrect well data.

(b) Plugging of standing valve or pump.

(c) Tubular leak.

(d) Side string in parallel installations not landed.

(a) Run pressure recorder and resize pump.

(b) Check pump and standing valve.

(c) Check tubing. Pull and repair if leaking.

(d) Check tubing and re-stab if necessary.



6 [Paper Number

Examples of Throat Damage

Example “A” Erosion from sand

normally occurs in along enlarged areafrom the entrance endof the throat and intothe diffuser section of the throat.

Solution: Use a sandconsolidationtechnique in thereservoir, use siliconcarbide for throatmaterial.

Example “C” Cavitation at theentrance of the throat isdue to an excess of produced fluids.Solution: Go to larger size throat.

Cavitation farther intothe throat indicatespower fluid cavitation,

which is usually theresult of insufficientpump-intake-pressure.Solution: Decreaseoperatingpressure/injection rate,resize nozzle/throatcombination.

Example “B” Entrance end of throat

enlarged, usually caused fromtrying to produce more than the

annular area will accommodate

Also, choking from large

volume of gas.

Solution: Go to larger throat

size.

Example “D” Cavitation in thelower end of thethroat and into thediffuser indicatespower fluidcavitation, which isusually the result of insufficient pump-intake-pressure.Solution: Decreaseoperating

pressure/injectionrate, resizenozzle/throatcombination.



Figure 1 1-1/4” Coiled Tubing Jet Pump



Seal Area

Figure 2 1-1/4” Coiled Tubing Jet Pump Installation

COILED ORCONVENTIONAL

TUBING

PUMPCAVITY

1-1/4" JET "FREE" PUMP

WELL CASING (OPEN FOR

VENTING GAS)

STANDING VALVE

TUBING PACKER

POWER FLUID

WELL FLUID

PRODUCED

FLUID

GAS



Figure 3 Typical Full Size Jet Pump


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Real Result RR 1175.00

Weatherford International Ltd.

515 Post Oak Blvd., Suite 600Houston, Texas 77027 USA

Tel: 713-693-4000

www.weatherford.com

REAL RESULTS

Weatherford products and services are subject to theCompany’s standard terms and conditions, available onrequest or at www.weatherford.com. For more informationcontact an authorized Weatherford representative. Unlessnoted otherwise, trademarks and service marks herein arethe property of Weatherford. Specifications are subject to

change without notice.

• Gas is flowing freely to the surface because the pumps areproducing the necessary volumes of water.

• Freestyle jet pumps have low operating costs, with quickinstallation and retrieval for maintenance, using power fluid

instead of a pulling unit. Low-cost repair parts are amongother money-saving advantages.

• Performance of the jet pumps is being optimized on an

ongoing basis.

• Dewater wells producing up to 200 bbl/d of water.

• Progressing cavity pumps (PCPs) had been usedpreviously, but numerous problems were experienced

including rod/tubing wear, broken rotors resulting fromtorque problems, surging, and corrosion. The high volume

of gas precluded use of rod pumps. Electric submersiblepumps (ESPs) were ruled out because of the difficulty inproducing at rates lower than 300 bbl/d, the high-angle

deviation of the wells, and lack of electricity at the site.

• The freestyle jet pumps are producing at rates up to 800bbl/d and at less than 50 bbl/d by changing only the nozzle

and/or throat. This task was quickly accomplished, as

freestyle operation capability meant that the pump could becirculated in and out hydraulically.

• The jet pumps had no trouble dealing with the high deviation

angles or other problems encountered by PCPs. The jetpumps have proven highly reliable in removing the required

volumes of water to enable gas flow.

Weatherford

Toby Pugh, Regional Product Line Manager972-243-1114 or 713-693-4895

Mobile: 972-768-4174

Reliable, Cost-Saving Jet Pumps,Installed Freestyle, Remove Water forFree Flow of Gas to Surface

Well type:

Gas; four directional, one vertical

Casing/tubing:

5 in., 17 lb/ft; 2-7/8 in.; 1-1/4 in.

Depth in:8,000 ft

Flow rate:200 bbl/d

BHA details:Coiled tubing

Objec t ives

Resul ts

Value t o Cl ient


http://slidepdf.com/reader/full/conference-programme91 11/17 © 2007 Weatherford. All rights reserved.Real Result RR 2843.00

Weatherford International Ltd.515 Post Oak Blvd., Suite 600Houston, Texas 77027 USATel: 713-693-4000

www.weatherford.com

REAL RESULTS

Weatherford products and services are subject to the Company’s standardterms and conditions, available on request or at www.weatherford.com. For more information contact an authorized Weatherford representative. Unlessnoted otherwise, trademarks and service marks herein are the property of Weatherford. Specifications are subject to change without notice. Weatherfordsells its products and services in accordance with the terms andconditions set

forth in the applicable contract between Weatherford and the client.

• Accelerate frac fluid recovery to reduce associated costs andput wells on production faster. The operator’s standardprocedure in the past was to let wells flow naturally and thenfracture-stimulate them when flow rates were no longer

acceptable. Frac fluid recovery would be completed byswabbing or, on rare occasions, by using nitrogen foam. Inthe case of these four wells, the operator sought a solutionfor faster recovery of the frac fluids to maximize the benefitsof fracturing and reduce fluid recovery costs.

WeatherfordDarrell Richardson

Hydraulic Lift Products

[email protected]

Freestyle Jet Pumps RecoverFrac Fluid Five Times Faster,Saving up to $200,000 per Well

LocationOklahoma, USA

Well Type

Oil and gas

Hole AngleVertical/deviated

Casing and Tubing• 5 1/2-in., 17-lb/ft casing• 2 7/8-in. tubing

FormationsViola, Bromide, Woodford Shale, Hunton

Bottomhole Assembly

Freestyle pump

Products/Services• Hydraulic-lift services• Freestyle jet pump• Portable surface power unit

Objec t ives

Resul ts

• Weatherford’s freestyle jet pumps were used on all four wells.The pump and portable surface power unit were quicklyrelocated, from well to well, to repeat the recovery process.

• Frac fluids were recovered in one to three days for small-volume fracs (less than 15,000 bpd) and in one to threeweeks for large-volume fracs (more than 15,000 bpd).

• During the frac fluid recovery process, well data wereobtained that would allow the operator to accurately size theartificial-lift equipment needed for producing each well.

• Recovering the frac fluids and putting the wells on productionwas five times faster than possible with swabbing. Nitrogenfoam, which is cost prohibitive at US$50,000 to $200,000 per

day, was used only on rare occasions. Sales beganimmediately when Weatherford’s jet pump was used.

• Once each well was producing, the pump was easilyremoved to provide an optimal oil and gas flow path to thesurface with the full tubing ID, in addition to the tubing-casingannulus.

• Success with Weatherford’s jet pump gave the client a viableoption for more cost-effective frac fluid recovery.

Weatherford’s freestyle jet pump provides acost-efficient means for speeding fluidrecovery. The jet pump is easily moved fromwell to well and can pump at rates of lessthan 50 bpd to up to 2,000 bpd with a simplechange of nozzle and/or throat.

Reversing the

power fluid flowdirection allows

removal of the jetpump to provide anoptimal oil and gasflow to the surface.

Value t o Cl ient



Figure 6 Schematic of Cavitation Bubbles and Damage Due to “Power Fluid Cavitation”



Outer Tubing

Inner Tubing

Inside the

Tubing Packer

Jet Pump

Outer Tubing

Inner Tubing

Jet Pump

Free Style Pump Fixed Style Pump

Color Key

Power Fluid

Produced Fluid

Return Fluid (Production and Spent Power Fluid)

Figure 7 Free and Fixed Pump Installations



Figure 8 Installing/Removing a Free Style Pump



N o z z le T h ro a t D iffu s e r

P o w e r

F lu id

P r e s s u r e

P o w e r

F lu id

V e l o c i t y

H o w T h e J e t P u m p W o rk s

PN

P s P a

P d

Figure 9 Schematic of Flow Velocity and Static Pressure in a Jet Pump



PN

QN

PS

QS

P d

Qt

PS

QS

S e c o n d a r y F l o w

H i g h V e l o c i t y C o r e

M i x e d F l o w

N o z z l e T h r o a t D i f f u s e r

Figure 10 Flow Rates/Pressures Entering and Leaving a Jet Pump



N o z z le /T h ro at R a t io s

V o lum e /P ressu re R e l a t io n sh ips

A R a t io

C R a t io

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Figure 11 Volume/Pressure Relationships for Different Area Ratios

conference programme9[1]

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