1_IntroductionToArtificialLiftMethods

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Advanced Artificial Lift Methods

Introduction to Artificial Lift Methods

Advanced Artificial Lift Methods PE 571

Introduction
http://www.nmt.edu/


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Instructor: Tan Nguyen

Class: Tuesday & Thursday

Time: 09:30 AM - 10:45 AM

Room: MSEC 367

Office: MSEC 372

Office Hours: Tuesday & Thursday 2:004:00 pm

Phone: ext-5483

E-mail: [email protected]

Class Schedule
http://www.nmt.edu/


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Brown, Kermit E. (1980).The Technology of Artificial Lift Methods, Volumes 1,

2a and 2b. Tulsa, OK: PennWell Publishing Co.

Brown, Kermit E. (1982). Overview of Artificial Lift Systems. Journal of

Petroleum Technology, Vol. 34, No. 10. Richardson, TX: Society of Petroleum

Engineers.

Clegg, J.D., Bucaram, S.M. and Hein, N.W. Jr. (1993).Recommendations and

Comparisons for Selecting Artificial Lift Methods. Journal of Petroleum

Technology(December), p. 1128. Richardson, TX: Society of Petroleum

Engineers.

Moineau, Rene (1930). Un Nouveau Capsulisme. Extracts from doctoral

thesis, University of Paris.

References
http://www.nmt.edu/


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Takcs, Gabor (2005).Gas Lift Manual. Tulsa , OK : PennWell Publishing.

Weatherford International Ltd. (2003, 2005).Artificial Lift Products and

Services . Houston : Weatherford International Ltd.

Schmidt, Z. and Doty, D.R (1989): "System Analysis for Sucker-Rod Pumping."

SPE Production Engineering (May), p. 125. Richardson , TX : Society of

Petroleum Engineers.

Zaba, J., (1968), Modern Oil Well Pumping. Tulsa, OK: PennWell Publishing Co.

References
http://www.nmt.edu/


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Chapter 1: Electrical Submersible Pump

Chapter 2: Rod Sucker Pump

Chapter 3: Gas Lift

Chapter 4: Plunger Lift

Chapter 5: Progressive Cavity Pump

Chapter 6: Hydraulic Pump

Course Outline
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Homework 15 %

Quizzes 20 %

Project 30 %

Final 35 %

Course Outline
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Introduction to Artificial Lift

IPR vs. OPR

q = PI (Pavg- Pwf)
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A well never actually attains its absolute flow potential, because in order for it toflow, Pwf must exceed the backpressure that the producing fluid exerts on the

formation as it moves through the production system. This backpressure or

bottomhole pressure has the following components:

Hydrostatic pressure of the producing fluid column

Friction pressure caused by fluid movement through the tubing, wellhead and

surface equipment

Kinetic or potential losses due to diameter restrictions, pipe bends or

elevation changes.


Inflow Performance Relationship (IPR)
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Artificial lift is a means of overcoming bottomhole pressure so that a well canproduce at some desired rate, either by injecting gas into the producing fluid

column to reduce its hydrostatic pressure, or using a downhole pump to provide

additional lift pressure downhole.

We tend to associate artificial lift with mature, depleted fields, where Pavg has

declined such that the reservoir can no longer produce under its natural energy .

But these methods are also used in younger fields to increase production rates

and improve project economics.


Artificial Lift
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Gas lift involves injecting high-pressure gas from the

surface into the producing fluid column through one or

more subsurface valves set at predetermined depths


Gas Lift
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There are two main types of gas lift:

Continuous gas lift, where gas is injected in a constant, uninterrupted stream.

This lowers the overall density of the fluid column and reduces the hydrostatic

component of the flowing bottomhole pressure. This method is generally

applied to wells with high productivity indexes.

Intermittent gas lift, which is designed for lower-productivity wells. In this type

of gas lift installation, a volume of formation fluid accumulates inside the

production tubing. A high-pressure slug of gas is then injected below the

liquid, physically displacing it to the surface. As soon as the fluid is produced,

gas injection is interrupted, and the cycle of liquid accumulation-gas injection-

liquid production is repeated.


Gas Lift
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Advantages: Gas lift can be used in deviated or crooked wellbores, and in high-

temperature environments that might adversely affect other lift methods, and it

is conducive to maximizing lift efficiency in high-GOR wells. Wireline-

retrievable gas lift valves can be pulled and reinstalled without pulling the

tubing, making it relatively easy and economical to modify the design.

Disadvantages: the availability of gas and the costs for compression and

injection are major considerations. Lift efficiency can be reduced by corrosion

and paraffin. Another disadvantage of gas lift is its difficulty in fully depleting

low-pressure, low-productivity wells. Also, the start-and-stop nature of

intermittent gas lift may cause downhole pressure surges and lead to increased

sand production.


Gas Lift


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Downhole pumps are used to increase pressure at the bottom of the tubing

string by an amount sufficient to lift fluid to the surface. These pumps fall into

two basic categories:positivedisplacementpumps and dynamic displacement

pumps.

A positive displacement pump works by moving fluid from a suction chamber to

a discharge chamber. This basic operating principle applies to reciprocating

rod pumps, hydraulic piston pumps and progressive cavity pumps (PCPs).

A dynamic displacement pump works by causing fluid to move from inlet to

outlet under its own momentum, as is the case with a centrifugal pump.

Dynamic displacement pumps commonly used in artificial lift include electrical

submersible pumps (ESPs) and hydraulic jet pumps.


Pump-Assisted Lift


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Beam pumping is the most common artificial lift

method. It can be used for a wide range of

production rates and operating conditions, and rod

pump systems are relatively simple to operate and

maintain. However, the volumetric efficiency(capacity) of a rod pump is low. its initial

installation may involve relatively high capital

costs. Its application is very limited for deep,

inclined and horizontal wells.


Pump-Assisted Lift Reciprocating Rod Pump


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As the rotor turns, cavities between the rotor and

stator move upward.

Progressive cavity pumps are commonly used for

dewatering coalbed methane gas wells, for

production and injection applications in waterflood

projects and for producing heavy or high-solids oil.

They are versatile, generally very efficient, and

excellent for handling fluids with high solids

content. However, because of the torsionalstresses placed on rod strings and temperature

limitations on the stator elastomers, they are not

used in deeper wells.


Pump-Assisted Lift PCP


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Hydraulic pump systems use a power fluid

usually light oil or waterthat is injected from the

surface to operate a downhole pump. Multiple

wells can be produced using a single surface

power fluid installation


Pump-Assisted Lift Hydraulic Pump


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With a reciprocating hydraulic pump, the injected power fluid operates a

downhole fluid engine, which drives a piston to pump formation fluid and spent

power fluid to the surface.

A jet pump is a type of hydraulic pump with no moving parts. Power fluid is

injected into the pump body and into a small-diameter nozzle, where it becomes a

low-pressure, high-velocity jet. Formation fluid mixes with the power fluid, and

then passes into an expanding-diameter diffuser. This reduces the velocity of the

fluid mixture, while causing its pressure to increase to a level that is sufficient to

lift it to the surface




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Used at depths from 1000 to 17,000 feet and are capable of producing at rates

from 100 to 10,000 B/D. They can be hydraulically circulated in and out of the well,

thus eliminating the need for wireline or rig operations to replace pumps and

making this system adaptable to changing field conditions. Another advantage is

that heavy, viscous fluids are easier to lift after mixing with the lighter power fluid.

Disadvantages of hydraulic pump systems include the potential fire hazards if oil is

used as a power fluid, the difficulty in pumping produced fluids with high solids

content, the effects of gas on pump efficiency and the need for dual strings of

tubing on some installations.




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An electric submersible pumping (ESP)

assembly consists of a downhole centrifugal

pump driven by a submersible electric

motor, which is connected to a power

source at the surface


Pump-Assisted Lift ESP


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Advantages:

The most efficient lift methods on a cost-per-barrel basis.

High rate: 100 to 60,000 B/D, including high water-cut fluids.

Work in high-temperature wells (above 350F) using high-temperature motors

and cables.

The pumps can be modified to lift corrosive fluids and sand.

ESP systems can be used in high-angle and horizontal wells if placed in

straight or vertical sections of the well.




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Disadvantages:

ESP pumps can be damaged from gas lock. In wells producing high GOR

fluids, a downhole gas separator must be installed. Another disadvantage is

that ESP pumps have limited production ranges determined by the number and

type of pump stages; changing production rates requires either a pump change

or installation of a variable-speed surface drive. The tubing must be pulled for

pump repairs or replacement.



Ad d A ifi i l Lif M h d


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Artificial lift considerations should ideally be part of the well planning process.

Future lift requirements will be based on the overall reservoir exploitation

strategy, and will have a strong impact on the well design.

Some of the key factors that influence the selection of an artificial lift method.

IPR: A wellsinflow performance relationship defines its production potential

Liquid production rate: The anticipated production rate is a controlling factor

in selecting a lift method; positive displacement pumps are generally limited to

rates of 4000-6000 B/D.

Water cut: High water cuts require a lift method that can move large volumes

of fluid


Selecting an Artificial Lift Method Reservoir Characteristics

Ad d A tifi i l Lift M th d


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Gas-liquid ratio:A high GLR generally lowers the efficiency of pump-assisted lift

Viscosity: Viscosities less than 10 cp are generally not a factor in selecting a lift

method; high-viscosity fluids can cause difficulty, particularly in sucker rod

pumping

Formation volume factor: Ratio of reservoir volume to surface volume

determines how much total fluid must be lifted to achieve the desired surface

production rate

Reservoir drive mechanism: Depletion drive reservoirs: Late-stage production

may require pumping to produce low fluid volumes or injected water.

Water drive reservoirs: High water cuts may cause problems for lifting systems

Gas cap drive reservoirs: Increasing gas-liquid ratios may affect lift efficiency.


Selecting an Artificial Lift Method Reservoir Characteristics



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Well depth: The well depth dictates how much surface energy is needed to move

fluids to surface, and may place limits on sucker rods and other equipment.

Completion type: Completion and perforation skin factors affect inflow

performance.

Casing and tubing sizes: Small-diameter casing limits the production tubing size

and constrains multiple options. Small-diameter tubing will limit production rates,

but larger tubing may allow excessive fluid fallback.

Wellbore deviation: Highly deviated wells may limit applications of beam

pumping or PCP systems because of drag, compressive forces and potential for

rod and tubing wear.


Selecting an Artificial Lift Method Hole Characteristics



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Flow rates: Flow rates are governed by wellhead pressures and backpressures in

surface production equipment (i.e., separators, chokes and flowlines).

Fluid contaminants: Paraffin or salt can increase the backpressure on a well.

Power sources: The availability of electricity or natural gas governs the type of

artificial lift selected. Diesel, propane or other sources may also be considered.

Field location: In offshore fields, the availability of platform space and placement

of directional wells are primary considerations. In onshore fields, such factors as

noise limits, safety, environmental, pollution concerns, surface access and well

spacing must be considered.


Selecting an Artificial Lift Method Surface Characteristics



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Long-range recovery plans: Field conditions may change over time.

Pressure maintenance operations: Water or gas injection may change the

artificial lift requirements for a field.

Enhanced oil recovery projects: EOR processes may change fluid properties

and require changes in the artificial lift system.

Field automation: If the surface control equipment will be electrically powered, an

electrically powered artificial lift system should be considered.

Availability of operating and service personneland support services: Someartificial lift systems are relatively low-maintenance; others require regular

monitoring and adjustment. Servicing requirements (e.g., workover rig versus

wireline unit) should be considered. Familiarity of field personnel with equipment

should also be taken into account.


Selecting an Artificial Lift Method Field Operating Characteristics



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General Guidelines (Weatherford 2005)



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1_IntroductionToArtificialLiftMethods

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