PTRT 2331- Well Completion and Servicing

Chapter 4: Artificial Lift

4.1. Pumping 4.2. Gas lift 4.3. Choosing an artificial lift process

Introduction Artificial lift allows wells that are non-flowing or insufficiently flowing to be produced . It can also be used to increase the flow from a well to produce at a higher rate. Artificial lift is mainly designed for oil producers but the technology may also be applied to water production or water injection. Most oil wells require artificial lift at some point in the life of the field, and many gas wells benefit from artificial lift to take liquids off the formation so gas can flow at a higher rate. Artificial lift is used in 90% of the wells worldwide. Almost every well in US uses artificial lift Artificial lift lowers the producing bottom hole pressure (BHP) on the formation in order to obtain a higher production rate from the well. Lifting can be done mechanically by pumping with a positive-displacement down hole pump, such as a beam pump or a progressive cavity pump (PCP). It also can be done with a down hole centrifugal pump, which could be a part of an electrical submersible pump (ESP) system. A lower bottom hole flowing pressure and higher flow rate can be achieved with gas lift in which the density of the fluid in the tubing is lowered and expanding gas helps to lift the fluids.

Most pumping operations occur after the fluid is below the bubblepoint pressure

Other types of pumping: Hydraulic pumping: a downhole plunger pump is coupled to hydraulic motor

by a jet pump or by centrifugal turbine pump Moyno rotary pumping: designed for high GOR wells with very viscous

crudes loaded with sand

Pumping There are two major types of pumping (based on mechanism): Positive displacement pumping such as by sucker rod pump

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).

Pump is actuated from the surface via rods and a reciprocating system Dynamic or centrifugal pumping

A dynamic pump works by causing fluid to move from inlet to outlet under its own momentum, as is the case with a centrifugal pump.

Dynamic pumps commonly used in artificial lift include electrical submersible pumps (ESPs) and hydraulic jet pumps

Sucker Rod Pump

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Sucker rod pumps, also called Donkey pumps or beam pumps, are the oldest and most common artificial-lift system used in land-based operations; they are simple in design.

A motor drives a reciprocating beam, connected to a polished rod passing into the tubing via a stuffing box. The sucker rod continues down to the oil level and is connected to a plunger with a valve. On each upward stroke, the plunger lifts a volume of oil up and through the wellhead discharge. on the downward stroke it sinks with oil flowing through the valve.

The motor speed and torque is controlled for efficiency and minimal wear with a Pump off Controller (PoC). Use is limited to shallow reservoir down to a few hundred meters, and flows up to 40 liters (10 gal) per stroke.

This system allows the beam to rock back and forth, moving the downhole components up and down in the process. The entire surface system is run by a prime mover, V-belt drives, and a gearbox with a crank mechanism on it. When this type of system is used, it is usually called a beam-pump installation. However, other types of surface-pumping units can be used, including hydraulically actuated units (with and without some type of counterbalancing system), or even tall-tower systems that use a chain or belt to allow long strokes and slow pumping speeds. The more-generic name of sucker-rod lift, or sucker-rod pumping, should be used to refer to all types of reciprocating rod-lift methods. Linked rods attached to an underground pump are connected to the surface unit. The linked rods are normally called sucker rods and are usually long steel rods, from 5/8 to more than 1 or 1 1/4 in. in diameter. The steel rods are normally screwed together in 25- or 30-ft lengths; however, rods could be welded into one piece that would become a continuous length from the surface to the downhole pump. The steel sucker rods typically fit inside the tubing and are stroked up and down by the surface-pumping unit. This activates the downhole, positive-displacement pump at the bottom of the well. Each time the rods and pumps are stroked, a volume of produced fluid is lifted through the sucker-rod tubing annulus and discharged at the surface.

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Principle

Pumping cycle

Upward stroke: plunger valve or traveling valve is closed; the column of liquid corresponding to the stroke will be lifted up to the surface Downward stroke: hollow plunger valve opens and the standing valve closes preventing liquid from returning to the pay zone

Q = S x N x A

Sucker rod components

A sucker-rod pumping system is made up of several components, some of which operate aboveground and other parts of which operate underground, down in the well.

Miscellaneous surface equipment like the pumping head is located at the top of the wellhead. Comparing the rod pump and the tubing pump: The tubing pump has a higher output than the rod pump. The disadvantage of the tubing pump is that it requires the tubing to be pulled out in order to replace the pump.

The surface-pumping unit, which drives the underground pump, consists of a prime mover (usually an electric motor) and, normally, a beam fixed to a pivotal post. The post is called a Sampson post, and the beam is normally called a walking beam.

Selection of subsurface rod pumps

Pumps for sucker-rod lifted wells should be selected on the basis of numerous variables that are provided by the well, the operating conditions, and the life of the pump. The main variables to consider are as follows: Well depth Bottomhole temperature Fluid viscosity Amount and size of particulates in the produced fluids Produced-fluids corrosivity Required production rate vs. pump capacity Fluid-specific gravity Casing/tubing size Well-completion type Gas/liquid ratio (GLR) Pump-intake pressure vs. fluid bubblepoint Spare/surplus pumps and components New purchase and repair costs

These variables influence: Stresses on the pump Type of pump used Component metallurgy Pump size Internal-fit tolerance Ability to handle solids/gas

Selection of rod string The primary factors affecting the selection and sizing of rods and the rod system are as follows: Size of pump and tubing Liquid viscosity and pourpoint Kind of corrosion [e.g., H2S, carbon dioxide (CO2), or saltwater] Conditions for unseating the downhole pump Pump setting depth Production rate Sand, paraffin, salt crystals, scale, foam, and GLR These factors should be considered when manual (according to API RP 11L) or computer design calculations are performed to size the rod string and the related production equipment for a specific well.

The weight of the sucker-rod string is distributed along its length, and any section has to carry at least the weight of the rods below it. This fact suggests that the ideal sucker-rod string would be a continuous taper from top to bottom. Since such a shape is practically impossible to achieve, one tries to approach the ideal construction by designing tapered strings with sections of increasing diameters toward the surface. For lower depths, straight rod strings made up from one rod size only are also used, but deeper wells inevitably require the application of tapered strings.

Design and operation considerations

Gas venting When pumping through tubing in the absence of a production packer, free gas, which breaks out of the oil, should be vented up from the casing/tubing annulus. However, when it is necessary to produce from beneath a production packer, a vent string can be installed. The possibility of needing a vent string should be considered when planning casing sizes for a new well.

Effects of gas on pump performance Gas that remains in solution when the liquid enters the pump increases the volume of total fluid through the pump compared to the liquid measured at the surface by the formation volume factor at pump-intake conditions. The gas also decreases the density of the fluid and, thus, the head or pressure to be pumped against in the tubing. Free gas that enters the pump must be compressed to a pressure equivalent to the head required to lift the fluid. This free gas will reduce the volume of both the produced liquid that enters the pump and the liquid measured at the surface. Any time the pump does not compress the free gas to a pressure greater than that exerted on the pump by the fluid column in the producing string, production ceases and the pump is said to be "gas locked." This condition can exist in both plunger and centrifugal pumps.

Downhole gas separators and anchors Downhole gas separators are used in gassy wells to increase the volume of free gas removed from the liquids before reaching the pump. However, they are not 100% effective in separating the gas. In sucker-rod-pumped wells, these separators are normally called "gas anchors." Gas anchors are usually designed and built in the field; there are six common types. The most commonly used are the "natural" gas anchor and the "poor boy" gas anchor . Typically, there are two major components for these gas anchor assemblies, the mud anchor run on the bottom of the tubing string and the dip tube or strainer nipple run on the bottom of the pump.

Choosing pumping rate

There are two parameters that affect choosing a pump, these are: 1. Depth of the pump which depends on bottom hole flowing pressure 2. Parameters related to flow rate which depends on

(i) the diameter of the plunger (ii)the pump stroke and the pumping rate

For the depth, the bottom hole flowing can be calculated from the flow rate equation:

PI

qppwf

It is best to choose the pumping rate limit under 20 strokes per minute. Below are the formulas that can be used to calculate the number of strokes per minute of a single size rod string and a tapered rod string (a) For a single size rod string

(b) For a tapered rod string

L = depth of the pump in ft N (asy)= asynchronous number of strokes per min K = 0.5 added to a whole number e.g. 1.5, 2.5, 3.5, 4.5

Home work Choose an asynchronous pumping rate for a pump located at a depth of 4950ft driven by a single rod string with K ranges from 1.5 to 6.5. Compare your results and explain the reason for your choices.

K 1.5 2.5 3.5 4.5 5.5 6.5

N (asy)

Summary The pump flow rate depends on 1. The diameter of the plunger 2. The pump stroke 3. The pumping speed or rate Mechanical fatigue of the rod depends mainly on: - The pumping rate or number of cycles - The maximum load in relation to the yield strength - The difference between the maximum tensile load during upstroke and the minimum tensile load during the down stroke.

Advantages and disadvantages

Centrifugal Pump 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. It is run into it position at the end of the production tubing into the casing.

There are three (3) main components of the centrifugal pump namely: - The pump - The electric motor - The protector or seal section

Electric submersible pump systems employ a centrifugal pump below the level of the reservoir fluids. Connected to a long electric motor, the pump is composed of several impellers, or blades, that move the fluids within the well. The whole system is installed at the bottom of the tubing string. An electric cable runs the length of the well, connecting the pump to a surface source of electricity.

The electric submersible pump applies artificial lift by spinning the impellers on the pump shaft, putting pressure on the surrounding fluids and forcing them to the surface. A mass producer, electric submersible pumps can lift more than 25,000 barrels of fluids per day.

The Pump: goes through different stages which are stacked up inside a liner, and each of these stages consist of a ROTARY IMPELLER which provides energy (in form of velocity) to the fluid needed to be pumped. STATIC DIFFUSER which transforms the kinetic energy into pressure energy before sending it to the impeller. The Motor: is enclosed in a steel housing unit with oil to lubricate its bearing. It is never placed below the perforation where the produced fluid flows up the well, which may damage the motor especially when there is inadequate fluid flow rate which could cause abnormal heating. The motor and cable are usually designed to be use up to a temperature of 150 F, there are some special design which can be used up to 400 F. The Seal or Protector: provides a tight connection between the motor and the pump. It also prevents the oil from moving along the shaft.

The Components

Advantages It is the most efficient lift methods on a cost-per-barrel basis. It has a high flow rate: 100 to 60,000 B/D, including high water-cut fluids. It works 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.

Disadvantages ESP pumps can be damaged from gas lock. In wells producing high GOR fluids, a

downhole gas separator must be installed. 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.

Hydraulic pump system

Hydraulic pump systems use a power fluidusually light oil or waterthat is injected from the surface to operate a down hole pump. Multiple wells can be produced using a single surface power fluid installation. Hydraulic pumping systems are suitable for wells with deviated or crooked holes that can cause problems for other types of artificial lift. The surface facilities can have a low profile and may be clustered into a central battery to service numerous wells. This can be advantageous in urban sites, offshore locations, areas requiring watering systems (sprinkle systems), and environmentally sensitive areas. There are two primary kinds of hydraulic pumps: Jet pumps Reciprocating positive-displacement pumps For jet pumps, high-pressure power fluid is directed down the tubing to the nozzle where the pressure energy is converted to velocity head (kinetic energy). 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.

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.

Hydraulic pump

Hydraulic pump system

Advantages Hydraulic pumping has the following advantages. Being able to circulate the pump in and out of the well is the most obvious and

significant feature of hydraulic pumps. It is especially attractive on offshore platforms, remote locations, and populated and agricultural areas.

Positive-displacement pumps are capable of pumping depths to 17,000 ft and deeper. Working fluid levels for jet pumps are limited to approximately 9,000 ft.

By changing the power-fluid rate to the pumps, production can be varied from 10 to 100% of pump capacity. The optimum speed range is 20 to 85% of rated speed. Operating life will be significantly reduced if the pump is operated above the maximum-rated speed.

Deviated wells typically present few problems to hydraulic free pumps. Jet pumps can even be used in through flow line installations.

Jet pumps, with hardened nozzle throats, can produce sand and other solids. There are methods in which positive-displacement pumps can handle viscous oils

very well. The power fluid can be heated, or it can have diluents added to further aid lifting the oil to the surface.

Corrosion inhibitors can be injected into the power fluid for corrosion control. Added fresh water can solve salt-buildup problems.

Disadvantages Hydraulic pumping has the following disadvantages. Removing solids from the power fluid is very important for positive-displacement

pumps. Solids in the power fluid also affect surface-plunger pumps. Jet pumps, on the other hand, are very tolerant of poor power-fluid quality.

Positive-displacement pumps, on average, have a shorter time between repairs than jet, sucker rod, and ESPs. Mostly, this is a function of the quality of power fluid but, on average, the positive-displacement pumps are operating from greater depths and at higher strokes per minute than for a beam pump system. Jet pumps, on the other hand, have a very long pump life between repairs without solids or if not subjected to cavitation. Jet pumps typically have lower efficiency and higher energy costs.

Positive-displacement pumps can pump from a low BHP (< 100 psi) in the absence of gas interference and other problems. Jet pumps cannot pump from such low intake pressures, especially when less than the cavitation pressure. Jet pumps require approximately 1,000 psi BHP when set at 10,000 ft and approximately 500 psi when set at 5,000 ft.

Positive-displacement pumps generally require more maintenance than jet pumps and other types of artificial lift because pump speed must be monitored daily and not allowed to become excessive. Power-fluid-cleaning systems require frequent checking to keep them operating at their optimum effectiveness. Also, well testing is more difficult.

Progressive cavity pumps A progressive cavity pump is a type of positive displacement pump; it transfers fluid by means of the progress, through the pump, of a sequence of small, fixed shape, discrete cavities, as its rotor is turned. The cavities taper down toward their ends and overlap with their neighbors, so that, in general, no flow pulsing is caused by the arrival of cavities at the outlet, other than that caused by compression of the fluid or pump components. These pumps are often referred to by the specific manufacturer or product names. Hence names can vary from industry to industry and even regionally; examples include: Moineau (after the inventor, Ren Moineau), Mono pump, Moyno pump.

Progressive cavity pumps are unique among positive displacement pumps for their ability to pump a wide range of fluids. Such as clean, water-like liquids, delicate products such as maraschino cherries and viscous, solids-laden fluids are all appropriate applications for progressive cavity pumps. The progressive cavity pump is a progressing pump which can produce pressures that may cause the bursting of vessels or pipes. The power transmission train (shaft, coupling rod, joints and rotor) of the pump may be overloaded thus resulting in damage or breakage. Also the pump housing parts with their connections may be overloaded and break. Never run the pump against a closed inlet or outlet valve.

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Rubber stator

Progressive cavity pumps

They 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 torsional stresses placed on rod strings and temperature limitations on the stator elastomers, they are not used in deeper wells.

Gas Lift 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. This artificial lift production technique can be used to make a non-flowing or insufficiently flowing well come on stream by reducing the hydrostatic back pressure between the bottom of the hole and the surface. This is done by injecting gas at the base of the production string

TYPES OF GAS LIFT Gas lift can be classified according to 1. Injection Method 2. Surface Injection Circuit 3. Type of Completion

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Gas lift injects compressed gas into the well to reestablish pressure, making it produce. Even when a well is flowing without artificial lift, it many times is using a natural form of gas lift.

The injected gas reduces the pressure on the bottom of the well by decreasing the viscosity of the fluids in the well. This, in turn, encourages the fluids to flow more easily to the surface. Typically, the gas that is injected is recycled gas produced from the well. With very few surface units, gas lift is the optimal choice for offshore applications. Occurring downhole, the compressed gas is injected down the casing tubing annulus, entering the well at numerous entry points called gas-lift valves. As the gas enters the tubing at these different stages, it forms bubbles, lightens the fluids and lowers the pressure.

There are two kinds of injection method: - Continuous gas lift - Intermittent gas lift

Injection Method

Continuous gas lift Gas is injected in a constant, uninterrupted stream, at a given pressure and flow rate, at the base of the production string. This lowers the overall density of the fluid column and reduces the hydrostatic component of the flowing bottom hole pressure. This method is generally applied to wells with high productivity indexes.

Intermittent gas lift It is designed for lower-productivity wells. Pressurized gas is injected from time to time at a high flow rate at the lower part of the production string. 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.

Flowing pressure gradient traverses above and below the depth of gas injection in a continuous-flow gas lift well.

Production is higher in continuous gas lift than in intermittent gas lift; continuous gas lift has a liquid output of 200-20000b/d while intermittent method has a liquid output of less 500b/d

The continuous gas lift can be used in a well with good productivity index (PI) of about 0.45bbl/d/psi and above while the intermittent gas lift can be used in a well with low/poor productivity index

Continuous gas lift vs. Intermittent gas lift

Based on efficiency, the intermittent gas lift is much lower than that of continuous version because the energy of the compressed gas under the liquid slug is lost as the gas gets to the surface.

The intermittent gas lift method is possible in good producers with low downhole pressure because the reservoir pressure was originally low or has been depleted

About 95%of wells using gas lift is produced by continuous method while the remaining 5% uses intermittent method.

Advantages and disadvantages of Intermittent gas lift Advantages It has a significantly lower producing BHP than continuous gas-lift methods. It has the ability to handle low volumes of fluid with relatively low production BHPs. The average producing pressure of a conventional intermittent lift system is still

relatively high when compared with rod pumping Disadvantages Intermittent gas lift is limited to low volume wells. For example, an 8,000-ft well

with 2-in. nominal tubing can seldom be produced at rates of more than 200 B/D with an average producing pressure much below 250 psig.

The power efficiency is low. Typically, more gas is used per barrel of produced fluid than with constant flow gas lift; the fallback of a fraction of liquid slugs being lifted by gas flow increases with depth and water cut, making the lift system even more inefficient. Liquid fallback can be reduced by the use of plungers, where applicable.

Fluctuations in rate and BHP can be detrimental to wells with sand control. The produced sand may plug the tubing or standing valve. Also, pressure fluctuations in surface facilities cause gas- and fluid-handling problems.

Intermittent gas lift typically requires frequent adjustments. The lease operator must alter the injection rate and time period routinely to increase the production and keep the lift gas requirement relatively low.

Schematic of continuous gas lift

Surface Injection Circuit There are two kinds of surface injection circuit : - Closed Circuit - Open Circuit In closed circuit, the gas recovered from the produced crude is sweetened by removal of liquid and re-injected into the well. The required injection pressure and its corresponding injection flow rate are determined based on the injection depth. In open circuit, gas recovered from the produced crude is either flared or sweetened and sold. The maximum injection depth and its corresponding minimum injection flow rate are determined based on its available injection pressure.

Completion Type

There are two (2) types of completion used namely - DIRECT - REVERSE In direct method, gas is injected through the casing annulus and produced from the tubing string. In reverse method, gas is injected through the tubing string and produced through the casing annulus

Advantages and disadvantages of Gas Lift

Advantages Gas lift is the best artificial lift method for handling sand or solid materials. Many

wells produce some sand even if sand control is installed. Produced sand causes few mechanical problems in the gas-lift system; whereas, only a little sand plays havoc with other pumping methods, except the progressive cavity pump (PCP)

Deviated or crooked holes can be lifted easily with gas lift. This is especially important for offshore platform wells that are usually drilled directionally.

Gas lift permits the concurrent use of wireline equipment, and such down hole equipment and is easily and economically serviced. This feature allows for routine repairs through the tubing.

normal gas-lift design leaves the tubing fully open. This permits the use of BHP surveys, sand sounding and bailing, production logging, cutting, paraffin, etc.

High-formation GORs are very helpful for gas-lift systems but hinder other artificial lift systems. Produced gas means less injection gas is required; whereas, in all other pumping methods, pumped gas reduces volumetric pumping efficiency drastically.

Advantages of Gas Lift contd

Gas lift is flexible. A wide range of volumes and lift depths can be achieved with essentially the same well equipment. In some cases, switching to annular flow also can be easily accomplished to handle exceedingly high volumes.

A central gas-lift system easily can be used to service many wells or operate an entire field. Centralization usually lowers total capital cost and permits easier well control and testing.

A gas-lift system is not obtrusive; it has a low profile. The surface well equipment is the same as for flowing wells except for injection-gas metering. The low profile is usually an advantage in urban environments.

Well subsurface equipment is relatively inexpensive. Repair and maintenance expenses of subsurface equipment normally are low. The equipment is easily pulled and repaired or replaced. Also, major well work overs occur infrequently.

Installation of gas lift is compatible with subsurface safety valves and other surface equipment. The use of a surface-controlled subsurface safety valve with a 1/4-in. control line allows easy shut in of the well.

Gas lift can still perform fairly well even when only poor data are available when the design is made. This is fortunate because the spacing design usually must be made before the well is completed and tested.

Disadvantages Relatively high backpressure may seriously restrict production in continuous gas

lift. This problem becomes more significant with increasing depths and declining static BHPs. Thus, a 10,000-ft well with a static BHP of 1,000 psi and a PI of 1.0 bpd/psi would be difficult to lift with the standard continuous-flow gas-lift system. However, there are special schemes available for such wells.

Gas lift is relatively inefficient, often resulting in large capital investments and high energy-operating costs. Compressors are relatively expensive and often require long delivery times. The compressor takes up space and weight when used on offshore platforms. Also, the cost of the distribution systems onshore may be significant. Increased gas use also may increase the size of necessary flow line and separators.

Adequate gas supply is needed throughout life of project. If the field runs out of gas, or if gas becomes too expensive, it may be necessary to switch to another artificial lift method. In addition, there must be enough gas for easy startups.

Operation and maintenance of compressors can be expensive. Skilled operators and good compressor mechanics are required for reliable operation. Compressor downtime should be minimal (< 3%).

Disadvantages of Gas Lift contd

There is increased difficulty when lifting low gravity (less than 15API) crude because of greater friction, gas fingering, and liquid fallback. The cooling effect of gas expansion may further aggravate this problem. Also, the cooling effect will compound any paraffin problem.

Good data are required to make a good design. If not available, operations may have to continue with an inefficient design that does not produce the well to capacity.

Potential gas-lift operational problems that must be resolved include: Freezing and hydrate problems in injection gas lines Corrosive injection gas Severe paraffin problems Fluctuating suction and discharge pressures Wireline problems Other problems that must be resolved are: Changing well conditions Especially declines in BHP and productivity index (PI) Deep high-volume lift Valve interference (multipointing)

Gas lift in general 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 down hole pressure surges and lead to increased sand production.

Choosing an artificial lift process

Determining which artificial lift system that will recover oil the fastest in the largest amounts at the lowest cost is actually a problem. Choosing the best artificial lift method for a particular well requires a study of all possible processes beforehand without any preconceived notions. The aim is to determine which one is the most compatible with the requisite production specifications (e.g wellhead pressure and flow rate) and the constraints due to the reservoir and its environment. There are three (3) types of criteria needed in the choice:

1. Energy source necessary for the process, its availability and access cost 2. Pump pressure head and liquid flow rate to be produced, with the product of

the two representing the installed power that is needed. 3. All the different operating constraints that stem from the following factors :

(a) the environment (b) the infrastructure on the surface and immediate environment (c) the well architecture (d) the characteristics of the effluent that will be produced.

Selecting an artificial lift system To realize the maximum potential from developing any oil or gas field, the most economical artificial lift method must be selected. The methods historically used to select the lift method for a particular field across the industry include: Operator experience What methods that are available for installations in certain areas of the world What is working in adjoining or similar fields Determining what methods will lift at the desired rates and from the required

depths Evaluating lists of advantages and disadvantages Evaluation of initial costs, operating costs, production capabilities, etc. with the

use of economics as a tool of selection, usually on a present-value basis These methods consider: Geographic location Capital cost Operating cost Production flexibility Reliability Mean time between failures

IPR: A wells inflow 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

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.

Key factors that influence the selection of an artificial lift method

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.

Flow rates: Flow rates are governed by wellhead pressures and backpressures in surface production equipment (i.e., separators, chokes and flow lines).

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.

Key factors that influence the selection of an artificial lift method contd

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.

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 personnel and support services: Some artificial

lift systems are relatively low-maintenance; others require regular monitoring and adjustment. Servicing requirements (e.g., work over rig versus wireline unit) should be considered. Familiarity of field personnel with equipment should also be taken into account.

Key factors that influence the selection of an artificial lift method contd

In the US, the majority of wells, 82%, employ a beam pump. 10% use gas lift, 4% use electric submersible pumps, and 2% use hydraulic pumps.

The four most common artificial lift methods will be looked at excluding other processes which are currently more marginal such as The moyno pump, The turbine pump, Intermittent gas lift The four most common are

1. Sucker rod pumping 2. Submerged centrifugal pumping 3. Plunger or jet hydraulic pumping 4. Continuous gas lift

Advantages and disadvantages of artificial lifts

Sucker Rod Pumping ADVANTAGES - It is the most widespread technology, relatively simple and well known in the industry. - It is well suited to low and moderate flow rate as long as the pump is not too deep. - Its flow rate can be changed easily, i.e., it has a flexible operation. - It is compatible with very low bottom hole pressure. - Any subsurface problem can be solved by a relatively lightweight servicing unit. - It is suited to isolated wells. - Its mechanical beam units are simple and durable, with low operating expenses as a

result. - Its hydraulic units occupy little space and its long stroke unit is very useful for viscous

and gassy crudes DISADVANTAGES (DRAWBACKS) Its flow rate decreases severely with the depth required for the pump. It has a reduced volumetric efficiency in wells with high GORs. Its beam pumping units takes up too much space and is heavy for offshore platforms. The initial investment cost is high for sophisticated large-capacity pumps, especially for

hydraulic units. It is ill suited to crooked well profiles. The major problem of sucker rod strength is when there is a corrosive effluent.

Submerged Centrifugal Pumping ADVANTAGES High flow rates are possible at shallow or average depths It is well suited to production with a high water cut. Its surface equipment takes up little space Its daily monitoring problems is reduced to a minimum unless the pump breaks

down. It has good energy efficiency which is advantageous if there is access to an existing

cheap power network. DISADVANTAGES Its output capacity is strongly influenced by depth. Its ill-suited to low flow rates. In case of problem, tubing must be pulled out. It is not normally recommended in a well with high GOR or well that are prone to

gas breakthrough. It performs poorly in the presence of sand. It has little flexibility except if variable-speed controller is used on the surface.

Hydraulic Pumping ADVANTAGES It is suited to great depths and deviated wells. Depending on the installation of the pump, it can be pumped up to the surface so

that it is not necessary to pull the tubing. Working fluid can serve as a carrier fluid for injecting an additive Advantages for plunger pump The size and rate of the pump can easily be modified to adapt to well conditions Viscous heavy crudes benefit from being mixed with a lighter working fluid Production is possible with extremely low bottom hole pressures

Advantages for jet pump High production flow rate is possible with jet pump It has no moving part inside the well It has minor problem only if sand or gas are present

DISADVANTAGES Initial investment in the surface equipment is high and its maintenance is

expensive Its high pressure pump feed circuit with consequent safety risks Well testing causes problems especially assessment of produced fluids

Disadvantages for plunger pump There is rapid wear and tear on the pump if the fluid is corrosive or abrasive The pump efficiency will drastically lower if free gas is present.

Disadvantages for jet pump Low efficiency of about 25 to 30% (70% for plunger). It needs bottom hole flowing pressure of over 3.5 MPa (500psi),else

detrimental cavitation will take place in the flow nozzle. It is prone to form emulsions or foam.

Continuous Gas Lift ADVANTAGES It is well suited to average or high flow rates. It is also suited to wells with a good PI and relatively high bottom hole pressure. Its well equipment is simple and gas lift valves can be retrieved by wireline, also its

operating conditions can be modified without having to pull the tubing. The initial investment can be low if a source of high pressure gas is available. Though

this is no longer true if compressors are installed. There is no production problems when sand is present An additive (e.g corrosion inhibitor) can be injected at the same time as the gas. It is suited in deviated wells. It is also well suited to starting up wells DISADVANTAGES It is needed for bottom hole pressure that is not too low, so sometimes the artificial lift

method has to be changed at the end of the wells lifetime The required injection gas volume may be excessive for wells with a high water cut. It cannot be applied if the casing is in bad shape Gas processing facilities (dehydration, sweetening) can compound compression costs. Foaming problems may get worse Surface infrastructure is particularly expensive if wells are scattered over a large area. It has a low efficiency especially in a deep well

BFPD = Barrels of Fluid Per Day

General Guidelines