20 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 InflowPerformance

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 InflowPerformance

NOT FLOWING

FINAL PRODUCTION PERFORMANCE



6500

6000

5500

5000

4500

4000

0 3000 6000 9000 12000 15000

Outflow


Pw

f, p

si

Reservoir InflowPerformance

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 holepressure 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 (pistón 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./Lift12,000

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 PistonPumps

Beam Pump ESP Hydraulic JetPump

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 CasingSurface Casing

Gas Injection

Flowline

PressurePwh

Pwf Pr

Staticgradient

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 CasingSurface Casing

Gas Injection

Flowline

SIDE POCKET MANDREL WITH GAS LIFT VALVE


Tubing Pressure Operated Valve Casing 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

PdPoPtPd=

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


GAS INJECTION PRESSURE

WELLHEAD PRESSURE

AVERAGE. RESERVOIR PRESSURE

PRESSURE

DE

PT

H

BALANCE POINT

INJECTION POINT

BOTTOMHOLE FLOWING PRESSURE

100 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 gasvolume

Eonomic 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

GLR

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

ctio

n D

epth

Maximum Injection Depth

EFFECT OF THE POINT OF GAS INJECTION DEPTH


Pwh pkoPsep

pvc1

pvc2

pcv3

pressured

epth

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

Flo

w R

ate

MM

SCF/

D


Gas Lift Performance Curve

x

x

x

x

x

xx

x

xx

LIFT-GAS INJECTION RATEOR PRODUCTION COSTS

NE

T O

IL P

RO

DU

CT

ION

OR

RE

VE

NU

E

2

1

3

4

SLOPE = 1.0Economic Limit

Technical Optimum

1Kick-OffLift-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 liftperformance curve

WELL 1

WELL 2

WELL n

QgitQgi

Qo

ΔQgi

ΔQo1

ΔQo2

ΔQon

n∑ ΔQoii=1

n∑ ΔQgii=1

Nodalanalysis


SCENARIOS

1. CONTNUOUS GAS INJECTION AND LIQUIDPRODUCTION.

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

Pw

f

Pr

QL

QA QB QC

PrInj.Pressure .

Val. 1

Val. 2

Val. 3

AB

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

STANDINGVALVE

FLUID

PLUNGER MOVING DOWN PLUNGER MOVING UP

TRAVELINGVALVE

FLUID WORKINGBARREL

CounterBalance

Pitman

Casing

Tubing

Sucker Rods

Plunger

Traveling Valve

Standing Valve

Horse Head

ElevatorPolish RodStuffing BoxFlowlineGas line

Prime Mover

Gear Box

Walking Beam

ROD PUMPING SYSTEM

ANIM

crank


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. Métodos de Levantamiento Artificial

2. Situación Actual de los Métodos de Levantamiento Artificial en Venezuela

3. Descripción 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.


“F”Breathing

Traveling valve closed;portion of fluid load trans-ferred to rods. Tubing relievedof load contracts. Tension in tubing at minimum for cycle. Buckling occurs from pumpto neutral point

UpstrokeDownstroke

Standing valve closed; fullfluid load stretched tubingdown to most elongated position. Tension in tubingat maximum for cycle. Nobuckling

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 Ap together 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.


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– Doesn’t 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)

Polis

hed

Rod

Load


Sonolog Fluid Level Survey

Sound reflection

Tubing collars

Fluid level

Sonolog

Charge ignited

Fluid level


BEAM PUMPING WELL OPTIMIZATION

REAL TIMEDATA

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 pumpingwell are maximum production with a dynamic fluid level at 100 feet above the pump or sufficientsubmergence of the pump to produce a full pumpcard .

For low productivity wells the full pump card Condition is difficult to maintain and a pump offcondition is generated. When pump off condition is detected, the pumping unit is shut down by a pump off controller for a predetermined periodof time to allow fluid build up in the casing-tubingannulus. The shut down time may be determined from a build up test.


PUMP ROD PERFORMANCE FROM CONVENTIONAL DYNAGRAPH CARD

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 CONVENTIONAL DYNAGRAPH CARD

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.


Pwh

ESP

Pwh

Pwf Pr

Pdn

Pup

ΔP

gas

Pwf

PdnPup

Pressure

Dep

th

ESP PRESSURE GRADIENT PROFILE


FLOW RATE, QL

FL

OW

ING

PR

ES

SU

RE

00

ΔP ΔP

Discharge Pressure, Pdn

IntakePressure,

Pup

NODAL ANALYSIS FOR A PUMPING SYSTEM

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

1) TOTAL DYNAMIC HEAD = ΔP / 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 PumpProgressive Cavity Pump


PROGRESSIVE CAVITY PUMP SYSTEM

RotorStator

CasingTubingRod 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



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


• 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.


Progressive Cavity PumpAdvantages

• 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 ºF.

Progressive Cavity PumpLimitations


APPLICATIONS:

• Horizontal wells

• Deep wells

• Deviated wells with severe dogleg

PROGRESSIVE CAVITY PUMP WITH BOTTOM DRIVE MOTOR

ProgressingCavity Pump

Tubing

Intake

Gear Box &Flex Drive

Protector

Motor Motor

Protector

Gearbox

Intake

StatorRotorCabl

e


Applications

• Heavy oil and bitumen.• Production of solids-laden

fluids.• Medium to sweet crude.• Agricultural areas.• Urban areas.


Progressing Cavity Pump BasicsCharacteristics

• 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


Progressing Cavity Pump BasicsDisplacement


• Non Pulsating

• Pump Generates Pressure Required To Move Constant Volume

• Flow is a function of RPM

Progressing Cavity Pump BasicsFlow Characteristics


Progressing Cavity Pump BasicsPulsationless Flow

QFLOW RATE = ACAVITY AREAVFLUID CAVITY VELOCITY


CONVENTIONAL 1:2 MULTILOBE 2:3

Progressing Cavity Pump BasicsPC Pump Types


Progressing Cavity Pump BasicsRotation

• 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

Progressing Cavity Pump BasicsPCP Description


Progressing Cavity Pump BasicsPCP Description

E 4E

D

P

D

P = Stator Pitch length(one full turn = two cavities)

D = Minor Diameter of StatorMajor 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.

Progressing Cavity Pump BasicsPumping 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

Progressing Cavity Pump BasicsPumping 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 PUMPHYDRAULIC JET PUMP

FLUIDOS

BOQUILLA

DIFUSORREVESTIDOR

FORMACION

FLUIDO DEPOTENCIA

FLUIDS

NOZZLE

THROAT

DIFUSSER

FORMATION

CASING

POWER FLUID

PRODUCTIONINLET

CHAMBER

COMBINEDFLUID

RETURN

DIFUSSER

NOZZLE

THROAT

video


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 PUMPHYDRAULIC JET PUMP

20 artificial lift

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