Artificial Lift

Copyright 2007, , All rights reserved

ARTIFICIAL LIFT


6500

6000

5500

5000

4500

4000

0 3000 6000 9000 12000 15000

Outflow

Flow Rate ( STB/day )

Pw

f, p

si

Reservoir Inflow

Performance

INITIAL PRODUCTION PERFORMANCE

NATURAL FLOW

ARTIFICIAL LIFT ASSISTED PRODUCTION


6500

6000

5500

5000

4500

4000

0 3000 6000 9000 12000 15000

Outflow


Pw

f, p

si

Reservoir Inflow

Performance

NOT FLOWING

FINAL PRODUCTION PERFORMANCE



6500

6000

5500

5000

4500

4000

0 3000 6000 9000 12000 15000

Outflow


Pw

f, p

si

Reservoir Inflow

Performance

BACK TO PRODUCTION BY

ARTIFICIAL LIFT



ARTIFICIAL LIFT As pressure in the reservoir declines, the producing capacityof the wells will decline. The decline is caused by a decrease

in the ability of the reservoir to supply fluid to the well bore.

Methods are available to reduce the flowing well bottom hole

pressure by artificial means.

POZOS EN FLUJO NATURAL

BOMBEO CAVIDADES PROGRESIVAS (BCP) BOMBEO ELECTROSUMERGIBLE (BES)

BOMBEO MECANICO (BALANCIN)

GAS LIFT CONTINUO

GAS LIFT INTERMITENTE

CHAMBER LIFT

ARTIFICIAL PLUNGER LIFT

BOMBEO HIDRAULICO (pistn o jet)

NATURAL FLOW WELL

PROGRESSIVE CAVITY PUMP (PCP) ELECTRICAL SUBMERSIBLE PUMP (ESP)

SUCKER ROD BEAM PUMP (BP)

CONTINUOUS

GAS LIFT (GL)

PLUNGER LIFT

INTERMITTENT GAS LIFT

CHAMBER LIFT

HYDRAULIC PUMP (piston or jet)

ARTIFICIAL PLUNGER LIFT

PLUNGER LIFT


Ft./Lift

12,000

11,000

10,000

9,000

8,000

7,000

6,000

5,000

4,000

3,000

2,000

1,000

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 20,000 30,000 40,000 50,000 BPD

Typical Artificial Lift Application Range

Rod

Pumps

PC Pumps Hydraulic Lift Submersible Pump Gas Lift

Comparison of Lift Methods


System Efficiency by Artificial Lift Method

0

10

20

30

40

50

60

70

80

90

100

PCP Hydraulic Piston

Pumps

Beam Pump ESP Hydraulic Jet

Pump

Gas Lift

(Continuous)

Gas Lift

(Intermittent)

Artificial Lift Type

Ov

era

ll S

ys

tem

Eff

icie

nc

y (

%)

Comparison of Lift Methods


SCHEMATIC OF A CONTINUOUS GAS LIFT WELL

Gaslift valves

De

pth

Operating Valve

Packer

Tubing

Production Casing

Surface Casing

Gas Injection

Flowline

PressurePwh

Pwf Pr

Static

gradient

Gas Lift involves the supply of high

pressure gas to the casing/tubing annulus and its

injection into the tubing deep in the well. The

increased gas content of the produced fluid

reduces the average flowing density of the fluids

in the tubing, hence increasing the formation

drawdown and the well inflow rate.


video

SCHEMATIC OF A CONTINUOUS GAS LIFT WELL

Gaslift valves

Operating ValvePacker

Tubing

Production Casing

Surface Casing

Gas Injection

Flowline

SIDE POCKET MANDREL WITH GAS LIFT VALVE

../animaciones/GASLIFT_15MB.MPG


Tubing Pressure Operated ValveCasing Pressure Operated Valve

Ppd

Piod

Ppd

Piod

Pressure chamber

Bellows

Stem

Ball

TYPES OF CONTINUOUS GAS LIFT VALVES


Ab

Pc

Pt

Ap

Required Pressure to open the valve

Valve Mechanic

Casing Pressure Operated Valve

PdPo

PtPd=

R

1 - R

-

where R = Ap / Ab

Pd Po +Pt(1 R) R=

Required Dome pressure to get the

opening pressure at P, T:


14

GAS LIFT MANDRELS

SIDE POCKET

MANDRELS

CONVENTIONAL

MANDREL


15

RK / BK LATCH


16

KICKOVER TOOL

THE KICKOVER TOOL IS RUN ON WIRELINE

AND USED TO PULL AND SET GAS LIFT

VALVES. THE ABILITY TO WIRELINE

CHANGE-OUT GAS LIFT VALVES GIVES

GREAT FLEXIBILITY IN THE GAS LIFT

DESIGN


17


18


UNLOADING PROCESS OF A GAS LIFT WELL

Valve 1

Valve 2

Valve 3

Valve 1

Valve 2

Valve 3

Valve 1

Valve 2

Valve 3

Valve 1

Valve 2

Valve 3

Valve 1

Valve 2

Valve 3

Valve 1

Valve 2

Valve 3

open

open

open

open

open

open

open

open

open

open

open

closed

open

open

closed

open

closed

closed

Video 2

../animaciones/GL_Unloading_Sequence_rev6.exe


GAS INJECTION

PRESSURE

WELLHEAD

PRESSURE

AVERAGE.

RESERVOIR

PRESSURE

PRESSURE

DE

PT

H

BALANCE POINT

INJECTION POINT

BOTTOMHOLE

FLOWING

PRESSURE100 PSI

AVAILABLE

PRESSURE

PRESSURES AND PRESSURE GRADIENTS

VERSUS DEPTH IN CONTINUOUS GAS LIFT


GAS LIFT WELL PERFORMANCE

LIQ

UID

PR

OD

UC

TIO

N

RA

TE

, Q

L

GAS INJECTION RATE, Qgi

Available gas

volumeEonomic Optimum

Maximum liquid production

LIQUID PRODUCTION RATE, QL

BO

TT

OM

HO

LE

FL

OW

ING

PR

ES

SU

RE

, P

wf

Inflow Performance

IPR

Pr Excessive GLR

(a) Gas lift well analysis (b) Effect of gas injection rate


GAS INJECTION RATE, Qgi

LIQ

UID

RA

TE

, Q

L

Available Gas Volume

Inje

cti

on

Dep

th

Maximum Injection Depth

EFFECT OF THE POINT OF GAS INJECTION DEPTH


Pwh pkoPsep

pvc1

pvc2

pcv3

pressured

ep

th

Opening pressure

Tubing flowing pressure

Available gas surface pressure

Closing pressure

GAS LIFT DESIGN FOR CASING PRESSURE OPERATED VALVES


Gas Injection Rate

PRESSURE (PSI)

SUB-CRITICAL

FLOW

PCASING

PTUBING = 55%

ORIFICE FLOW

GA

S I

NJE

CT

ION

RA

TE

(M

MS

CF

/D)


Different Injection Gas

Rates

Gas Passage through a RDO-5 Orifice Valve with a 1/2" Port

(163 deg F, Gas S.G. 0.83, Discharge Coefficient 0.84)

0

1

2

3

4

5

6

7

8

9

0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000

Pressure psi

Gas F

low

Rate

MM

SC

F/D


Gas Lift Performance Curve

x

x

x

x

x

xx

x

xx

LIFT-GAS INJECTION RATE

OR PRODUCTION COSTS

NE

T O

IL P

RO

DU

CT

ION

OR

RE

VE

NU

E

2

1

3

4

SLOPE = 1.0

Economic Limit

Technical

Optimum

1Kick-Off

Lift-Gas Requirement

2 Initial Oil Rate at Kick-off

3 Technical cut-off limit

4 Max. Oil Rate

x Incremental Lift-Gas Volume


OPTIMIZATION OF GAS LIFT GAS DISTRIBUTION

Qgi

Qo

Qgi

Qo

Qot

Optimum total field gas lift

performance curve

WELL 1

WELL 2

WELL n

QgitQgi

Qo

Qgi

Qo1

Qo2

Qon

n

Qoi

i=1

n

Qgi

i=1

Nodal

analysis


SCENARIOS

1. CONTNUOUS GAS INJECTION AND LIQUID

PRODUCTION.

2. CONTINUOUS GAS INJECTION AND NO LIQUID

PRODUCTION.

3. THE WELL DOES NOT RECEIVE GAS AND THERE

IS NOT LIQUID PRODUCTION

GAS LIFT WELL DIAGNOSIS


C

B

A

Pr

QL

QA QB QC

PrInj.Pressure .

Val. 1

Val. 2

Val. 3

A

B

C

Pwh.

Dep

th

GAS LIFT WELL DIAGNOSIS CONTINUOUS GAS INJECTION AND LIQUID PRODUCTION SCENARIO

DETERMINATION OF THE WORKING GAS LIFT VALVE

When there is not consistency in the data, then a hole in the tubing or multiple injection points

may exist, in which case a temperature log is necessary to arrive at a final conclusion.


GAS LIFT WELL DIAGNOSIS

CONTINUOUS GAS INJECTION AND NO LIQUID PRODUCTION SCENARIO

Under this scenario the well is circulating gas due to the following possible causes:

Hole in the tubing

No transference of the injection point to the next valve

Formation damage restricts the inflow capacity of the reservoir

Organic or inorganic deposits in the tubing or flowline

The causes of no transference of the injection point to the next deeper valve are:

High tubing pressure

Low gas injection pressure

Under this scenario the well is circulating gas due to the following possible causes:

Hole in the tubing

No transference of the injection point to the next valve

Formation damage restricts the inflow capacity of the reservoir

Organic or inorganic deposits in the tubing or flowline

The causes of no transference of the injection point to the next deeper valve are:

High tubing pressure

Low gas injection pressure


GAS LIFT WELL DIAGNOSIS NO GAS INJECTION AND NO LIQUID PRODUCTION SCENARIO

Possible causes:

Gas injection valve closed

Gas line broken

Gas line restriction due to hydrates formation (Freezing Problems)

High gas lift valve opening pressure

Possible causes:

Gas injection valve closed

Gas line broken

Gas line restriction due to hydrates formation (Freezing Problems)

High gas lift valve opening pressure


CONTINUOUS GAS LIFT

Range of application

Medium-light oil (15 - 40 API)

GOR 0 - 4000 SCF / STB

Depth limited to compression capacity

Low capacity to reduce the bottom hole flowing pressure

High initial investment (Gas compressors cost)

Installation cost low (slick line job)

Low operational and maintenance cost

Simplified well completions

Flexibility - can handle rates from 10 to 50,000 bpd

Can best handle sand / gas / well deviation

Intervention relatively less expensive


SUCKER RODS

PLUNGER

STANDING

VALVEFLUID

PLUNGER MOVING DOWN PLUNGER MOVING UP

TRAVELING

VALVE

FLUID WORKINGBARREL

CounterBalance

Pitman

Casing

Tubing

Sucker Rods

Plunger

Traveling Valve

Standing Valve

Horse Head

Elevator

Polish Rod

Stuffing Box

Flowline

Gas linePrime Mover

Gear Box

Walking Beam

ROD PUMPING SYSTEM

ANIM

crank

../animaciones/RODLIFT_20.MPG


ROD PUMPING SYSTEMSUBSURFACE PUMP COMPONENTS

BARREL

SUCKER ROD

PLUNGER

BALLS ANDSEATS

STANDINGVALVE


Extra heavy-light oil (8.5 - 40 API)

Oil Production: 20 - 2000 STB/day

GOR: 2.000 PCN / BN (can handle free gas, but pump

efficiency is decreased)

Maximum depth: 9000 feet for light oil and 5000 feet

for heavy-extra heavy oil

Subsurface equipment stands up to 500 F

Tolerant to solids production (5-10 % volume)

Tolerant to pumping off conditions

ROD PUMPING SYSTEM

RANGE OF APPLICATION


Mark II

Low

Profile Air Balanced

Beam Balanced

Drawings Courtesy of Lufkin Industries, Inc. Lufkin, Texas

Types of Pumping Units


1. Mtodos de Levantamiento Artificial

2. Situacin Actual de los Mtodos de Levantamiento

Artificial en Venezuela

3. Descripcin de los diferentes Sistemas de

Levantamiento Artificial

4. Estado del Arte del Levantamiento Artificial

BEAM PUMPING SYSTEM

(AIR BALANCED UNIT)


How can we change the flow rate ?

Change the pump stroke length

Typical range 54 306 inches

Change the number of strokes

Typical range 5 15 spm


Downhole Pumps

Insert Pump - fits inside the production tubing and is

seated in nipple in the tubing.

Tubing Pump - is an integral part of the production

tubing string.


Insert Pumps

Pump is run inside the tubing attached to sucker rods

Pump size is limited by tubing size

Lower flow rates than tubing pump

Easily removed for repair


Insert Pump

Ball & seat

Seating nipple

Standing valve

Barrel

Traveling valve

Plunger

Tubing

Cage


Tubing Pumps

Integral part of production tubing string

Cannot be removed without removing production

tubing

Permits larger pump sizes

Used where higher flow rates are needed


Tubing Pump

Ball & seat

Standingvalve

Barrel

Travelingvalve

Plunger

Tubing

Cage

Connectionw/tubing


Tubing Anchors

Often a device is used to prevent the

tubing string from moving with the rod

pump during actuation. A tubing anchor

prevents the tubing from moving, and

allows the tubing to be left in tension which

reduces rod wear.


FBreathing

Traveling valve closed;

portion of fluid load trans-

ferred to rods. Tubing relieved

of load contracts. Tension in

tubing at minimum for cycle.

Buckling occurs from pump

to neutral point

UpstrokeDownstroke

Standing valve closed; full

fluid load stretched tubing

down to most elongated

position. Tension in tubing

at maximum for cycle. No

buckling

No buckling

Neutral point

Buckling

Tubing Anchors


Pump Displacement

(Sizing)

PD = 0.1484 x Ap (in2) x Sp (in/stroke) x N

(strokes/min)PD = pump displacement (bbl/day)

Ap = cross sectional area of piston (in2)

Sp = plunger stroke (in)

N = pumping speed (strokes/min)

0.1484 = 1440 min/day / 9702 in3/bbl

Manufacturers put the constant and Aptogether as K for each plunger size, so

PD = K x Sp X N


Volumetric efficiency

Calculated pump displacement will differ from surface rate due to:

Slip/leakage of the plunger

Stroke length stretch

Viscosity of fluid

Gas breakout on chamber

Reservoir formation factor (Bo) defines higher downhole volume

Volumetric efficiency Ev = Q / PD

Typical values : 70 80%


Exercise

A)Determine the pump speed (SPM) needed

to produce 400 STB/d at the surface with a

rod pump having a 2-inch diameter

plunger, a 80-inch effective plunger stroke

length, and a plunger efficiency due to

slippage of 80%. The oil formation volume

factor is 1.2.

B)If my pump speed is not to exceed 10 SPM

what is an alternative plunger design ?

Sol.

Solutions to Exercises/EXERCISE 14 SOLUTION.ppt


Exercise (Equations)

A) SPM = (q x Bo / Ev) / (0.1484 x Ap x Sp)

B) Ap = (q x Bo / Ev) / (0.1484 x SPM x Sp)


Rod Design Considerations

Weight of rod string

Weight of fluid

Maximum stress in rod

Yield strength of rod material

Stretch

Buckling

Fatigue loading

Inertia of rod and fluid as goes through a stroke

Buoyancy

Friction

Well head pressure


Counterweight

Balances the load on the surface prime

mover

A pump with no counterweight would have

a cyclic load on the prime mover load

only on upstroke

Sized on an average load through the

cycle

Equivalent to buoyant weight of rods plus half

the weight of the fluid


Prime Mover HorsePower -

Estimations

Hydraulic Horsepower = power required to lift a given volume of fluid

vertically in a given period of time

= 7.36 x 10-6 x Q x G x L

where Q = rate b/d (efficiency corrected), G= SG of fluid, L = net lift

in feet

Frictional Horsepower

= 6.31 x 10-7 x W x S x N

Where W=weight of rods in lb, S=stroke length,N=SPM

Polished Rod Horsepower (PRHP)= sum (hydraulic, frictional)

Prime mover HP = PRHP x CLF / surface efficiency

where CLF = cyclic load factor dependent on model of motor typical

range 1.1 to 2.0


Gas Separators

A rod pump is

designed to pump or

lift liquids only. Any

entrained gas

(formation gas) must

be separated from the

produced liquids and

allowed to vent up the

annulus. If gas is

allowed to enter the

pump, damage will

often occur due to gas

lock or fluid pound.

WFP


Pump Problems

Downhole pump failures can result from:

Abrasion from solids

Corrosion (galvanic, H2S embrittlement, or acid)

Scale buildup

Normal wear seal and valves

Gas locking

Stress from fluid pounding

Rod breaks

Plunger jams


Rod Pumping

Advantages Possible to pump off

Best understood by field personnel

Some pumps can handle sand or trash

Usually the cheapest (where suitable)

Low intake pressure capabilities

Readily accommodates volume changes

Works in high temperatures

Reliable diagnostic and troubleshooting tools available

Disadvantages Maximum volume

decreases rapidly with

depth

Susceptible to free gas

Frequent repairs

Deviated wellbores are

difficult

Reduced tubing bore

Subsurface safety difficult

Doesnt utilize formation

gas

Can suffer from severe

corrosion


Identifying Problems with

Rod Pumping

Dynamometer

Measures the load applied to the top rod in a string

of sucker rods (the polished rod)

A dynamometer card is a recording of the loads on

the polished rod throughout one full pumping cycle

(upstroke and downstroke)

A dynamometer load cell can be permanently

installed on a well to continuously monitor rod loads

and dynamics. This device is called a Pump-off

Controller


CONVENTIONAL DYNAGRAPH CARD

Displacement

Lo

ad

Upstroke

Downstroke


Dynamometer Card

B

F

EC

D

A

Maximum load

End of downstroke

and beginningof upstroke

End of upstroke

and beginningof downstroke

Downstroke

Upstroke

Minimum load

Polished Rod Position (0 - stroke

length)

Po

lish

ed

Ro

d L

oa

d


Sonolog Fluid Level Survey

Sound reflection

Tubing collars

Fluid level

Sonolog

Charge ignited

Fluid level


BEAM PUMPING WELL OPTIMIZATION

REAL TIME

DATA

MONITORING

Variables

Dynagraph Card

Motor Current Demand

Liquid Production Rate

Production Gas Liquid Ratio

Water Cut

Tubing Head Pressure and Temperature

Casing Head Pressure and Temperature

Bottom Hole Flowing Pressure and Temperature

(fluid level in the annulus)

Pumping Velocity


Variables which could change once a year

Data required for calculations at a particular point

in time during the life of the reservoir :

Reservoir Average Pressure and Depth

Stroke Length

Pump Configuration

Tubing Configuration

Flowline Configuration

Production Casing Size

Oil PVT data

BEAM PUMPING WELL OPTIMIZATION


AUTOMATIC BEAM PUMPING WELL

TARGET OPTIMIZATION

Displacement

Lo

ad

Displacement

Lo

ad

(a) Full pump card

(b) Pump off card

The conditions of an optimized beam pumping

well are maximum production with a dynamic

fluid level at 100 feet above the pump or sufficient

submergence of the pump to produce a full pump

card .

For low productivity wells the full pump card

Condition is difficult to maintain and a pump off

condition is generated. When pump off condition

is detected, the pumping unit is shut down by a

pump off controller for a predetermined period

of time to allow fluid build up in the casing-tubing

annulus. The shut down time may be determined

from a build up test.


PUMP ROD PERFORMANCE FROM


Displacement

Lo

ad

(b) Restriction in the well

Displacement

Lo

ad

Displacement

Lo

ad

(d) Excessive friction in

the pumping system

(c) Sticking Plunger


PUMP ROD PERFORMANCE FROM


Displacement

Lo

ad

Displacement

Lo

ad

(e) Liquid pound (f) Gas pound

Displacement

Lo

ad

Displacement

Lo

ad

(g) Gas lock (h) Plunger undertravel


PUMP OFF CONTROLLER

Pump off Controller


Typical ESP Installation


The Basic ESP System

100 to 100,000 BPD

Installed to 15,000 ft

Equipment diameters from

3.38 to 11.25

Casing Sizes - 4 1/2 to 13

5/8

Variable Speed Available

Metallurgies to Suit

Applications


Extra heavy - light (8.5 - 40 API)

Gas Volume at bottom hole conditions:

less than 15 %

Maximum Temperature: 500 F

Very sensible to solids production and pump

off condition.

ELECTRICAL SUBMERSIBLE PUMP

Range of Application


Each "stage" consists

of an impeller and a

diffuser. The impeller

takes the fluid and

imparts kinetic energy

to it. The diffuser

converts this kinetic

energy into potential

energy (head).

The Basic ESP System


ELECTRICAL SUBMERSIBLE PUMP SCHEMATIC

video

Impeller

Diffuser

Shaft

Oil flows up, through

suction side of

impeller, and is

discharged with

higher pressure, out

through the diffuser.

../animaciones/ESP_15MB.MPG


Pwh

ESP

Pwh

Pwf Pr

Pdn

Pup

P

gas

Pwf

PdnPup

Pressure

Dep

th

ESP PRESSURE GRADIENT PROFILE


FLOW RATE, QL

FL

OW

ING

PR

ES

SU

RE

00

P P

Discharge Pressure, Pdn

Intake

Pressure,

Pup

NODAL ANALYSIS FOR A PUMPING SYSTEM

HP = 1.72x10-5P (QoBo + QwBw)

Copyright 2007, , All rights reserved FLOW RATE, QL

00

HE

AD

, ft

/ s

tag

e

HEAD CAPACITY

PUMP EFFICIENCY

OPTIMUM

RANGE

HORSE POWER

SP. GR: =1.0

HP

MO

TO

R L

OA

D

PU

MP

EF

FIC

IEN

CY,%

0

100

ELECTRICAL SUBMERSIBLE PUMP PERFORMANCE CURVE


ESP SELECTION

4) HORSE POWER REQ.(HP) = 1.72x10-5P (QoBo + QwBw)

1) TOTAL DYNAMIC HEAD = P / fluid density

2) FROM TYPICAL PUMP PERFORMANCE CURVE

DETERMINE HEAD (FT) PER STAGE AND EFFICIENCY

3) NUMBER OF STAGES =

TOTAL DYNAMIC HEAD

FEET/STAGE


Progressive Cavity Pump


PROGRESSIVE CAVITY PUMP SYSTEM

Rotor

Stator

Casing

Tubing

Rod String

Flowline Wellhead

Drive head

Gear Box

Electric motor

Stop

pin

ROTOR

STATOR

When the rotor and stator are in place,

defined sealed cavities are formed. As the

rotor turns within the stator, the cavities

progress in an upward direction. When fluid

enters a cavity, it is actually driven to the

surface in a smooth steady flow.video

../../../CURSOS METODOS DE PRODUCCION/introduccin al negocio petrolero/introduccin al a las operaciones petroleras/PCP_15MB.MPG



When the rotor and stator are in place,

defined sealed cavities are formed. As the

rotor turns within the stator, the cavities

progress in an upward direction. When fluid

enters a cavity, it is actually driven to the

surface in a smooth steady flow.

video

../../../CURSOS METODOS DE PRODUCCION/introduccin al negocio petrolero/introduccin al a las operaciones petroleras/PCP_15MB.MPG


Extra heavy Light oil (8.5 - 40 API)

Production Capacity: 20-3500 STB/day

GOR: 0 -5000 SCF/ STB

Maximum Depth:

- 3000 feet: 500 - 3000 STB/day heavy-extra heavy oil

- 7000 feet : < 500 STB/day heavy-extra heavy oil

Maximum Temperature for subsurface pump: 250 F

Low profile surface components (very low environmental impact)

Does not create emulsions

Does not gas lock.


Range of Application and Capabilities



Range of Application and Capabilities (cont.)

Able to produce:

High concentrations of sand.

High viscosity fluid.

High percentages of free gas.



Advantages

Simple two piece design

Capable of handling

solids & high viscosity

fluids

Will not emulsify fluid

High volumetric

efficiencies


Production rates 3500 bbls/day

Lift capacity 7000 ft.

Elastomer incompatible with certain

fluids/gases

Aromatics (12%)

H2S (max. 6%), CO2(max. 30%)

Other chemical additives

Max. Temperature up to 250 F.


Limitations


APPLICATIONS:

Horizontal wells

Deep wells

Deviated wells with severe dogleg

PROGRESSIVE CAVITY PUMP

WITH BOTTOM DRIVE MOTOR

Progressing

Cavity Pump

Tubing

Intake

Gear Box &

Flex Drive

Protector

Motor Motor

Protect

or

Gearbo

x

Intake

Stator

RotorCable


Applications

Heavy oil and bitumen.

Production of solids-laden

fluids.

Medium to sweet crude.

Agricultural areas.

Urban areas.


Progressing Cavity Pump Basics

Characteristics

Interference fit between the rotor and

stator creates a series of isolated

cavities

Rotation of the rotor causes the cavities

to move or progress from one end of

the pump to the other



Displacement


Non Pulsating

Pump Generates Pressure Required To

Move Constant Volume

Flow is a function of RPM


Flow Characteristics



Pulsationless Flow

QFLOW RATE = ACAVITY AREAVFLUID CAVITY VELOCITY


CONVENTIONAL 1:2 MULTILOBE 2:3


PC Pump Types



Rotation

The Rotor turns eccentrically

within the Stator.

Movement is actually a

combination of two movements:

Rotation about its own axis

Rotation in the opposite

direction of its own axis about

the axis of the Stator.


Eccentricity

Stator Pitch

(one full turn)

RotorStator


PCP Description



PCP Description

E4E

D

P

D

P = Stator Pitch length

(one full turn = two cavities)

D = Minor Diameter of Stator

Major Diameter of Stator


The geometry of the helical gear formed by the rotor and

the stator is fully defined by the following parameters:

the diameter of the Rotor = D (in.)

eccentricity = E (in.)

pitch length of the Stator = P (in.)

The minimum length required for the pump to create

effective pumping action is the pitch length. This is the

length of one seal line.


Pumping Principle


Each full turn of the Rotor produces two cavities of fluid.

Pump displacement = Volume produced for each turn of

the rotor

V = C *D*E*P

C = Constant (SI: 5.76x10-6, Imperial: 5.94x10-4)

At zero head, the flow rate is directionally proportional to

the rotational speed N:

Q = V*N


Pumping Principle


Given:

Pump eccentricity (e) = 0.25 in

Pump rotor diameter (D) = 1.5 in

Pump stator pitch (p) = 6.0 in

Pump speed (N) = 200 RPM

Find:

Pump displacement

Theoretical fluid rate

Example


HYDRAULIC JET PUMP

FLUIDOS

BOQUILLA

DIFUSORREVESTIDOR

FORMACION

FLUIDO DEPOTENCIA

FLUIDS

NOZZLE

THROAT

DIFUSSER

FORMATION

CASING

POWER FLUID

PRODUCTION

INLET

CHAMBER

COMBINED

FLUID

RETURN

DIFUSSER

NOZZLE

THROAT

video

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OPPORTUNITIES FOR APLICATION:

Can be installed in small tubing

diameter (down to 2-3/8) and with

coiled tubing (1-1/4).

Highly deviated/horizontal wells with

small hole diameter.

Can be hydraulically recovered without

using wireline.

Low equipment costs

No moving parts

High solids content

High GOR

No depth limitations

Extra heavy-light oil (8.5 - 40 API)

Production: 100 -20000 STB/day

HYDRAULIC JET PUMP

Documents

Artificial Lift