Artificial Lift

ARTIFICIAL LIFT

Copyright 2007,

, All rights reserved

ARTIFICIAL LIFT ASSISTED PRODUCTION

INITIAL PRODUCTION PERFORMANCE

6500

Outflow 6000

NATURAL FLOW

Pwf, psi

5500

Reservoir Inflow Performance 5000

4500

4000 0

3000

6000

9000

Flow Rate ( STB/day ) Copyright 2007,


12000

15000


FINAL PRODUCTION PERFORMANCE

6500

Outflow 6000

NOT FLOWING

Pwf, psi

5500

5000

Reservoir Inflow Performance

4500

4000 0

3000

6000

9000



12000

15000


6500

BACK TO PRODUCTION BY ARTIFICIAL LIFT

6000

Outflow

Pwf, psi

5500

5000

Reservoir Inflow Performance

4500

4000 0

3000

6000

9000



12000

15000

ARTIFICIAL LIFT

As pressure in the reservoir declines, the producing capacity of 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.

BOMBEO CAVIDADES PROGRESSIVE CAVITYPROGRESIVAS PUMP (PCP) (BCP)

BOMBEO ELECTRICAL ELECTROSUMERGIBLE SUBMERSIBLE PUMP (BES) (ESP)

SUCKER ROD BEAM PUMP (BP) BOMBEO MECANICO (BALANCIN) BOMBEO HYDRAULIC HIDRAULICO PUMP (piston (pistón or jet) o jet)

POZOS EN FLUJO NATURAL FLOWNATURAL WELL

“GAS CONTINUOUS LIFT” CONTINUO GAS LIFT

PLUNGER LIFT PLUNGER LIFT

(GL) CHAMBER CHAMBER LIFT LIFT

INTERMITTENT GAS LIFT “GAS LIFT” INTERMITENTE ARTIFICIALPLUNGER PLUNGERLIFT LIFT ARTIFICIAL Copyright 2007,


Comparison of Lift Methods Typical Artificial Lift Application Range 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

Rod Pumps

Copyright 2007,

2,000

3,000

PC Pumps


4,000

5,000

6,000

7,000

Hydraulic Lift

8,000

9,000

10,000 20,000 30,000 40,000 50,000 BPD

Submersible Pump

Gas Lift

Comparison of Lift Methods System Efficiency by Artificial Lift Method 100

Overall System Efficiency (%)

90 80 70 60 50 40 30 20 10 0 PCP

Hydraulic Piston Pumps

Beam Pump

ESP

Artificial Lift Type

Copyright 2007,


Hydraulic Jet Pump

Gas Lift (Continuous)

Gas Lift (Intermittent)

SCHEMATIC OF A CONTINUOUS GAS LIFT WELL

Flowline

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.

Gas Injection Pwh

Pressure

Tubing Operating Valve

Depth

Surface Casing Production Casing Static gradient

Gaslift valves Packer Pwf

Copyright 2007,


Pr

SCHEMATIC OF A CONTINUOUS GAS LIFT WELL SIDE POCKET MANDREL WITH GAS LIFT VALVE

Flowline

Gas Injection

Surface Casing Production Casing Tubing

Gaslift valves Packer

Operating Valve

video Copyright 2007,


TYPES OF CONTINUOUS GAS LIFT VALVES

Casing Pressure Operated Valve

Tubing Pressure Operated Valve

Pressure chamber Bellows

Stem

Piod Ball

Ppd Copyright 2007,


Piod

Ppd

Valve Mechanic

Casing Pressure Operated Valve Required Pressure to open the valve

Po = Pd - Pt R 1-R

Pd Ab

where R = Ap / Ab Required Dome pressure to get the opening pressure at P, T:

Pc

Ap

Pd = Po (1 – R) +Pt R Pt

Copyright 2007,


GAS LIFT MANDRELS

SIDE POCKET MANDRELS

CONVENTIONAL MANDREL

14 Copyright 2007,


RK / BK LATCH

15 Copyright 2007,


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

16 Copyright 2007,


17 Copyright 2007,


18 Copyright 2007,


UNLOADING PROCESS OF A GAS LIFT WELL

Copyright 2007,

Valve 1

open

Valve 1

open

Valve 1

open

Valve 2

open

Valve 2

open

Valve 2

open

Valve 3

open

Valve 3

open

Valve 3

open

Valve 1

closed

Valve 1

closed

Valve 1

closed

Valve 2

open

Valve 2

open

Valve 2

closed

Valve 3

open

Valve 3

open

Valve 3

open


Video 2

PRESSURES AND PRESSURE GRADIENTS VERSUS DEPTH IN CONTINUOUS GAS LIFT WELLHEAD PRESSURE

GAS INJECTION PRESSURE

PRESSURE AVAILABLE PRESSURE

DEPTH

INJECTION POINT

BALANCE POINT

BOTTOMHOLE FLOWING PRESSURE

100 PSI AVERAGE. RESERVOIR PRESSURE Copyright 2007,


Pr

Excessive GLR

Inflow Performance IPR

LIQUID PRODUCTION RATE, QL

(a) Gas lift well analysis

Copyright 2007,


LIQUID PRODUCTION RATE, QL

BOTTOM HOLE FLOWING PRESSURE, Pwf

GAS LIFT WELL PERFORMANCE

Maximum liquid production

Available gas volume

Eonomic Optimum

GAS INJECTION RATE, Qgi

(b) Effect of gas injection rate

EFFECT OF THE POINT OF GAS INJECTION DEPTH

LIQUID RATE, QL

Injection Depth

Maximum Injection Depth

Available Gas Volume

GAS INJECTION RATE, Qgi

Copyright 2007,


GAS LIFT DESIGN FOR CASING PRESSURE OPERATED VALVES

Available gas surface pressure

Psep Pwh

pko

pressure

Closing pressure

pvc1

depth

pvc2

pcv3

Tubing flowing pressure

Copyright 2007,


Opening pressure

GAS INJECTION RATE (MMSCF/D)

Gas Injection Rate

SUB-CRITICAL FLOW

ORIFICE FLOW

PTUBING = 55%

PRESSURE (PSI) Copyright 2007,


PCASING

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) 9

Gas Flow Rate MMSCF/D

8 7 6 5 4 3 2 1 0 0

100

200

300

400

500

600

700

800

900

1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000

Pressure psi

Copyright 2007,


Gas Lift Performance Curve Technical Optimum

SLOPE = 1.0 Economic Limit 4 x Kick-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

x x

NET OIL PRODUCTION OR REVENUE

1

x

x

x x

x x

2 x

3 1 Copyright 2007,


LIFT-GAS INJECTION RATE OR PRODUCTION COSTS

OPTIMIZATION OF GAS LIFT GAS DISTRIBUTION

Qo Optimum total field gas lift performance curve

ΔQo1

WELL 1

Qgi Qo ΔQo2

WELL 2

Qot

Nodal analysis

Qgi

Qo WELL n

n ∑ ΔQgi i=1

ΔQon

Qgi ΔQgi

Copyright 2007,


n ∑ ΔQoi i=1

Qgit

GAS LIFT WELL DIAGNOSIS

SCENARIOS 1.

CONTNUOUS GAS INJECTION AND LIQUID PRODUCTION.

2. CONTINUOUS GAS INJECTION AND NO LIQUID PRODUCTION. 3.

Copyright 2007,


THE WELL DOES NOT RECEIVE GAS AND THERE IS NOT LIQUID PRODUCTION

GAS LIFT WELL DIAGNOSIS CONTINUOUS GAS INJECTION AND LIQUID PRODUCTION SCENARIO

DETERMINATION OF THE WORKING GAS LIFT VALVE

Pwh .

Pr

Inj.Pressure .

Pr A Val. 1

B

Depth

C

Val. 2

Val. 3

A B C

QA

QB

QC

QL

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. Copyright 2007,


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: Under this scenario the well is circulating gas due to the following possible causes: •Hole in the tubing •Hole in the tubing •No transference of the injection point to the next valve •No transference of the injection point to the next valve •Formation damage restricts the inflow capacity of the reservoir •Formation damage restricts the inflow capacity of the reservoir •Organic or inorganic deposits in the tubing or flowline •Organic or inorganic deposits in the tubing or flowline The causes of no transference of the injection point to the next deeper valve are: The causes of no transference of the injection point to the next deeper valve are:

•High tubing pressure •High tubing pressure •Low gas injection pressure •Low gas injection pressure

Copyright 2007,


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

Possible causes: Possible causes: •Gas injection valve closed •Gas injection valve closed •Gas line broken •Gas line broken •Gas line restriction due to hydrates formation (Freezing Problems) •Gas line restriction due to hydrates formation (Freezing Problems) •High gas lift valve opening pressure •High gas lift valve opening pressure

Copyright 2007,


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

Copyright 2007,


ROD PUMPING SYSTEM Walking Beam CounterBalance Pitman

Horse Head

Gear Box

Elevator Polish Rod Stuffing Box Flowline Gas line

Prime Mover

SUCKER RODS PLUNGER

TRAVELING VALVE

Casing

crank

Tubing Sucker Rods

FLUID

WORKING BARREL STANDING VALVE

FLUID

Plunger

PLUNGER MOVING UP

PLUNGER MOVING DOWN

Traveling Valve

Standing Valve

ANIM Copyright 2007,


ROD PUMPING SYSTEM SUBSURFACE PUMP COMPONENTS

SUCKER ROD PLUNGER BARREL

STANDING VALVE

Copyright 2007,


BALLS AND SEATS

ROD PUMPING SYSTEM RANGE OF APPLICATION

• 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 Copyright 2007,


Types of Pumping Units

Mark II

Beam Balanced

Low Profile Copyright 2007,


Air Balanced Drawings Courtesy of Lufkin Industries, Inc. Lufkin, Texas

BEAM PUMPING SYSTEM (AIR BALANCED UNIT)

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

Copyright 2007,


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

Copyright 2007,


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.

Copyright 2007,


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

Copyright 2007,


Insert Pump

Tubing

Plunger

Traveling valve Barrel Standing valve Seating nipple Ball & seat Copyright 2007,


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

Copyright 2007,


Tubing Pump Tubing Connection w/tubing

Plunger

Traveling valve Barrel Cage Standing valve Ball & seat Copyright 2007,


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.

Copyright 2007,


Tubing Anchors No buckling Neutral point

Buckling

Downstroke Standing valve closed; full fluid load stretched tubing down to most elongated position. Tension in tubing at maximum for cycle. No buckling

Upstroke Traveling valve closed; portion of fluid load transferred to rods. Tubing relieved of load contracts. Tension in tubing at minimum for cycle. Buckling occurs from pump to neutral point

Breathing

Copyright 2007,


“F”

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 Copyright 2007,


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% Copyright 2007,


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. Copyright 2007,


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)

Copyright 2007,


Rod Design Considerations • • • • • • • • • • • Copyright 2007,

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 , All rights reserved

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 Copyright 2007,


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

Copyright 2007,


Gas Separators

P

Copyright 2007,


WF

• 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.

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

Copyright 2007,


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 Copyright 2007,


• 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”

Copyright 2007,


CONVENTIONAL DYNAGRAPH CARD

Load

Upstroke

Downstroke

Displacement

Copyright 2007,


Dynamometer Card

Polished Rod Load

Upstroke

F Maximum load

End of upstroke and beginning of downstroke

D C

E

End of downstroke and beginning of upstroke

A

B

Minimum load

Downstroke

Copyright 2007,


Polished Rod Position (0 - stroke length)

Sonolog Fluid Level Survey

Charge ignited

Sonolog

Sound reflection Tubing collars

Fluid level Fluid level

Copyright 2007,


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

Copyright 2007,


BEAM PUMPING WELL OPTIMIZATION

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

Copyright 2007,


AUTOMATIC BEAM PUMPING WELL TARGET OPTIMIZATION

(a) Full pump card Load

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 .

Displacement

Load

(b) Pump off card

Displacement Copyright 2007,


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 CONVENTIONAL DYNAGRAPH CARD

Load

(b) Restriction in the well

(c) Sticking Plunger

Displacement Copyright 2007,


Load

Load

Displacement

(d) Excessive friction in the pumping system

Displacement

Load

Load

PUMP ROD PERFORMANCE FROM CONVENTIONAL DYNAGRAPH CARD

Displacement

Displacement (f) Gas pound

Load

Load

(e) Liquid pound

Displacement

(g) Gas lock Copyright 2007,


Displacement (h) Plunger undertravel

PUMP OFF CONTROLLER

Pump off Controller

Copyright 2007,


Typical ESP Installation

Copyright 2007,


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

Copyright 2007,


ELECTRICAL SUBMERSIBLE PUMP

Range of Application • 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.

Copyright 2007,


The Basic ESP System

– 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).

Copyright 2007,


ELECTRICAL SUBMERSIBLE PUMP SCHEMATIC

Oil flows up, through suction side of impeller, and is discharged with higher pressure, out through the diffuser. Impeller Diffuser Shaft video Copyright 2007,


ESP PRESSURE GRADIENT PROFILE

Pwh Pressure Pwh

Depth

gas

ESP

Pdn

Pdn

Pup ΔP

Pup Pwf

Copyright 2007,


Pwf

Pr

NODAL ANALYSIS FOR A PUMPING SYSTEM

FLOWING PRESSURE

Discharge Pressure, Pdn

ΔP

ΔP Intake Pressure, Pup

0

0

FLOW RATE, QL HP = 1.72x10-5ΔP (QoBo + QwBw)

Copyright 2007,


ELECTRICAL SUBMERSIBLE PUMP PERFORMANCE CURVE

OPTIMUM RANGE

HORSE POWER SP. GR: =1.0

0 Copyright 2007,

100 PUMP EFFICIENCY,%

PUMP EFFICIENCY

HP MOTOR LOAD

HEAD, ft / stage

HEAD CAPACITY

0

0


FLOW RATE, QL

ESP SELECTION

1) TOTAL DYNAMIC HEAD = ΔP / fluid density 2) FROM TYPICAL PUMP PERFORMANCE CURVE DETERMINE HEAD (FT) PER STAGE AND EFFICIENCY TOTAL DYNAMIC HEAD

3) NUMBER OF STAGES = FEET/STAGE

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

Copyright 2007,


Progressive Cavity Pump

Copyright 2007,


PROGRESSIVE CAVITY PUMP SYSTEM

Gear Box Drive head

Wellhead

Electric motor

ROTOR

Flowline

Casing Tubing Rod String

STATOR

Rotor Stator

Stop pin

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.




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.




Range of Application and Capabilities

• 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. , All rights reserved

Copyright 2007,


Range of Application and Capabilities (cont.)

• Able to produce: – High concentrations of sand. – High viscosity fluid. – High percentages of free gas.

Copyright 2007,


Progressive Cavity Pump Advantages • Simple two piece design • Capable of handling solids & high viscosity fluids • Will not emulsify fluid • High volumetric efficiencies

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Progressive Cavity Pump Limitations • 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. Copyright 2007,


PROGRESSIVE CAVITY PUMP WITH BOTTOM DRIVE MOTOR Tubing

APPLICATIONS:

Progressing Cable Cavity Pump

• Horizontal wells • Deep wells

Rotor Stator

Intake Gear Box & Flex Drive

Intake Gearbo x

Protector Protect or

• Deviated wells with severe dogleg Motor

Copyright 2007,


Motor

Applications

• Heavy oil and bitumen. • Production of solids-laden fluids. • Medium to sweet crude. • Agricultural areas. • Urban areas.

Copyright 2007,


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

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Progressing Cavity Pump Basics Displacement

Copyright 2007,


Progressing Cavity Pump Basics Flow Characteristics

• Non Pulsating • Pump Generates Pressure Required To Move Constant Volume • Flow is a function of RPM

Copyright 2007,


Progressing Cavity Pump Basics Pulsationless Flow

Q Copyright 2007,

FLOW RATE


=A

V

CAVITY AREA

FLUID CAVITY VELOCITY

Progressing Cavity Pump Basics PC Pump Types

CONVENTIONAL 1:2

Copyright 2007,


MULTILOBE 2:3

Progressing Cavity Pump Basics 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.

Copyright 2007,


Progressing Cavity Pump Basics PCP Description

Stator Pitch (one full turn)

Eccentricity

Stator

Copyright 2007,


Rotor

Progressing Cavity Pump Basics PCP Description D = Minor Diameter of Stator Major Diameter of Stator

D

D

P

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

E

Copyright 2007,


4E

Progressing Cavity Pump Basics Pumping Principle

• 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.

Copyright 2007,


Progressing Cavity Pump Basics 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

Copyright 2007,


Example 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

Copyright 2007,


HYDRAULIC JET PUMP

NOZZLE THROAT DIFUSSER

FLUIDOFLUID DE POWER COMBINED POTENCIA FLUID RETURN PRODUCTION INLET BOQUILLA NOZZLE CHAMBER THROAT

CASING REVESTIDOR

DIFUSSER DIFUSOR

FLUIDOS FLUIDS FORMATION FORMACION



HYDRAULIC JET PUMP 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 Copyright 2007,


Artificial Lift

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