EVALUATION OF THE PERFORMANCE OF BEAM PUMP AND ELECTRIC SUBMERSIBLE PUMP IN OIL PRODUCTION USING PETROLEUM SOFTWARE (PROSPER)


EVALUATION OF THE PERFORMANCE OF BEAM PUMP AND ELECTRIC SUBMERSIBLE PUMP IN OIL PRODUCTION USING PETROLEUM SOFTWARE (PROSPER)  

ABSTRACT:            

Today, Artificial lift optimization has become very important in petroleum industries. A proper lift optimization can reduce cost of production and maximize recovery from the asset. The purpose of artificial lift optimization is to obtain maximum output under specified operating conditions. 

Optimization of Beam pump and electrical submersible pump is a continuous process and a critical one but the use of PROSPER program modelling made field work easy for petroleum engineers. 

The total field optimization involve optimizing the surface facilities and injection rate which can be achieved by the use of standard tool softwares.

Well level optimization can be achieved by optimizing the well parameters such as point of injection, injection rate and injection pressure.

All this aspects have been investigated and presented in this study by using experimental data and PROSPER Simulation programs.

The result show that well head pressure has great influence on the performance of artificial lift. Artificial lift performance can also be improved by controlling the pressure and gas injection of the downhole.

Obtaining optimum gas injection rate is important because excessive gas injection reduces production rate and increases production cost.

CHAPTER ONE

1.0. BACKGROUND OF THE STUDY

Initially, a well produce with natural energy but subsequently the energy depleted which give rise to the need for additional energy or supplementary energy for production to take place. There are many types of artificial lift methods which are used in oil production. Some of the methods include Electrical Submersible Pump, Beam pump, plunger, gas lift, jet pumps and sucker rod. 

1.1 ARTIFICIAL LIFT

Artificial lift is a process used on oil wells to increase pressure within the reservoir and embolden oil to the surface. When the natural drive energy of the reservoir is not strong enough to push the oil to the surface, artificial lift is employed to increase production (Mohamed 2016).

Artificial lift is referred to the use of artificial means to increase the flow of liquids such as crude oil or water, from a production well. Generally, this is achieved by the use of a mechanical device inside the well (known as pump or velocity string) or by decreasing the weight of the hydrostatic column by injecting gas into the liquid some distance down the well (Mohamed 2016).

Artificial lift is needed in wells when there is insufficient pressure in the reservoir to lift the produced fluids to the surface, but often used in naturally flowing wells (which do not technically need it) to increase the flow rate above what would flow naturally. The produced fluid can be oil, water or a mix of oil and water, typically mixed with some amount of gas (Mohamed 2016).

1.1.1 ARTIFICIAL LIFT METHODS

1.1.1.1 Progressing Cavity Pumps

Progressing Cavity Pumps (PCP) are widely used in the oil industry. The PCP consists of a stator and a rotor. The rotor is rotated using either a top side motor or a bottom hole motor. The rotation-created sequential cavities and the produced fluids are pushed to the surface. The PCP is a flexible system with a wide range of applications in terms of rate (up to 5,000 bbl/d (790 m3/d) and depth 6,000 ft (1,800 m)). They offer outstanding resistance to abrasives and solids but they are restricted to setting depths and temperatures. Some components of the produced fluids like aromatics can also deteriorate the stator's elastomer (Lyons 1996).

1.1.1.2. Rodless Pumps

This can be either hydraulic or electric submersible pump. 

The hydraulic uses high pressure power fluid to operate down hole fluid engine. The engine in turn drives a piston that moves the fluid to the surface. The power fluid system can be either open or closed, it depends on whether the power fluid can be mixed with well fluid. This type of system usually has above ground power fluid pumps and a reservoir (Lyons 1996). 

The electric submersible is another type of rodless pumping system. This uses an electric pump submerged in the well and connected to a series of transformers and control equipment that power and control the pumping rate. In this system the electric motor is isolated from the oil by a protector. The fluid intake which is before the pump mechanism has a gas separator, the junction box on the surface helps to dissipate any gas that may have come up the power lines. The rod and rodless pumping mechanisms help to achieve the fluid movement by reducing the bottom hole pressure by displacing the fluid above it all by mechanical means (Lyons 1996). 

Another method is the plunger lift mechanism which utilizes the tubing string as the barrel. It uses gas to power a plunger. It is important to note that there are several variations of these methods that can be used. They include jet pumping involving a hydraulic pump and nozzle that transfers fluid momentum directly to the producing fluid or chamber lift which is a modified gas lift mechanism that has no back pressure. There are also modified rod pumping design units that use either a winch or pneumatic mechanism to work (Lyons 1996).

1.1.1.3 Hydraulic Pumping Systems

Hydraulic pumping systems transmit energy to the bottom of the well by means of pressurized power fluid that flows down in the wellbore tubular to a subsurface pump. There are at least three types of hydraulic subsurface pump:

⦁ A reciprocating piston pump where one side is powered by the (injected) drive fluid while the other side pumps the produced fluid to the surface.

⦁ A  jet pump where the (injected) drive fluid passes through a nozzle-throat venturi combination, mixes with produced fluids and by the venturi-effect creates a high pressure at the discharge side of the pump.

⦁ A hydraulic driven downhole turbine (HSP) whereby the downhole drive motor is a turbine, mechanically connected to the impeller-pump section which pumps the produced fluid to the surface.

These systems are very versatile and have been used in shallow depths (1,000 ft) to deeper wells (18,000 ft), low rate wells with production in the tens of barrels per day to wells producing in excess of 20,000 bbl (3,200 m3) per day. In most cases the drive (injected) fluid can be water or produced fluids (oil/water mix). Certain chemicals can be mixed in with the injected fluid to help control corrosion, paraffin and emulsion problems. Hydraulic pumping systems are also suitable for deviated wells where conventional pumps such as the rod pump are not feasible (Mohamed 2016).

Like all systems, these systems have their operating envelopes, though with hydraulic pumps these are often misunderstood by designers. Some types of hydraulic pumps may be sensitive to solids, while jetpumps for example can pump solids volume fractions of more than 50%. They are considered the least efficient lift method, though this differs for the different types of hydraulic pumps and when looking at full system losses the differences in many installations are negligible (Mohamed 2016).

The life-cycle cost of these systems is similar to other types of artificial lift when appropriately designed, bearing in mind that they are typically low maintenance, with jet pumps for instance having slightly higher operating (energy) costs with substantially lower purchase cost and virtually no repair cost (Mohamed 2016).

1.1.1.4 Gas Lift

Gas lift is another widely used artificial lift method. As the name denotes, gas is injected in the tubing to reduce the weight of the hydrostatic column, thus reducing the back pressure and allowing the reservoir pressure to push the mixture of produce fluids and gas up to the surface. The gas lift can be deployed in a wide range of well conditions from 30,000 bbl/d (4,800 m3/d) to 15,000 ft (4,600 m)). Gas lifts can cope well with abrasive elements and sand and the cost of workover is minimum (Mohamed 2016).

Gas lifted wells are equipped with side pocket mandrels and gas lift injection valves. This arrangement allows a deeper gas injection in the tubing. The gas lift system has some disadvantages. There has to be a source of gas, some flow assurance problems such as hydrates can be triggered by the gas lift (Mohamed 2016).

Gas is injected into the fluid stream which reduces the fluid density and lowers the bottom hole pressure. As the gas rises, the bubbles help to push the oil ahead. The degree of the effect depends on continuous or intermittent flow of the gas. The gas can be injected at a single point below the fluid or may be supplemented by multipoint injection. An intermitter at the surface controls the timing of the gas injection. The mechanisms are either pressure or fluid operated. They may be throttling valves or casing pressure operated valve. Fluid operated valves require a rise in tubing pressure to open and drop to close. A throttling pressure valve is opened by casing pressure build up and closed by casing pressure drop. Conventional gas lift valves are attached to gas lift mandrels and wire line retrievable gas lift valves which are set in side pocket mandrels (Mohamed 2016).

1.1.2 BEAM PUMP

Beam pumping systems are the most commonly applied worldwide artificial lift method, 59% of all Artificial Lift in North America and 71% of 832000 wells for the rest of the world (World Oil 2000). 

A Beam Pump is a device used to facilitate production by the way of an overground drive instead of a piston pump used in an oil well. Beam pump unique structure is well recognized and goes by many different names including pumpjack, donkey pumper, rocking horse, sucker rod pump, and grasshopper pump (Tech-Flo, October 2006).

The size of the beam pump depends on the depth of the oil formation, the amount of oil to be extracted and other factors. Deeper extraction sites require heavier equipment which in turn require more power to lift oil out of the well. The beam pump has a familiar characteristic: the nodding motion. The purpose of the beam pump is to convert the rotary mechanism of the motor to a vertical reciprocating motion that drives the pump shaft down hole (Teach-foo, October 2006).ech-Flo, October 2006).

1.1.2.1  A BEAM PUMP SYSTEM

A beam pumping system is shown in Fig 7.

 The Prime Mover may be either a gas engine or electric motor.  If electric power is available, an electric motor is most often selected because of ease to start and stop when used with a POC. The electric motor is most  dependable with low maintainance cost and good for all weather conditions (Lea & McCoy, 2007).

Belts and Sheaves are usually trouble free when properly tightened and protected with a belt guard. The selection of the motor sheave diameter is used to control the pumping speed (Lea & McCoy, 2007).

The Pumping Unit is a system of linkages that convert the circular motion of the prime mover into a linear up and down motion of the polished rod.  The Pumping Unit structure must support the entire weight of the sucker rods in fluid, the fluid load applied to the rods by the pump plus any additional acceleration loads resulting from moving the rods and pump.  The counter weights are positioned on the Pumping Unit crank arm to uniformly balance the gearbox loading on both up and down stroke in such a way that a maximum of half of the fluid load applied to the rods by the pump, is lifted by the prime mover. The entire weight of the rods and fluid load are applied to the Carrier Bar and the load is applied to the Pumping Unit structure by two strong large diameter wire strand cables (Lea & McCoy, 2007).

The Sucker Rods are held on the Carrier Bar with one or more clamps attached to the Polished Rod. The rubber packed Stuffing Box provides a seal around the Polished Rod to prevent fluid leakage at the well head.  From the surface to the bottom of the well, a large diameter pipe called Casing is installed to hold the wellbore open and allows Tubing and Sucker Rods to be installed into the well from the surface to the Producing Zone  (Lea & McCoy, 2007).

Part of the downhole Pump is attached to the Sucker Rods and part of the Pump is attached to the Tubing. Up and Down motion of the pumping unit causes the Sucker Rods to move the Pump and to produce fluids up the tubing and into the surface Flow Line during each stroke (Lea & McCoy, 2007).

A Gas Anchor should be used to prevent free gas from entering the Pump if setting the pump above the perforations. Sinker Bars are used to prevent damage to the tubing and rods, if the rods buckle. These many features of the Beam Pumping System work together to artificially lift fluids to the surface (Lea & McCoy, 2007).

1.1.2.2 HOW DOES A BEAM PUMP WORK.

Modern beam pumps are powered by a prime mover. A beam pump typically pumps about 20 times a minute and the amount of oil is directly tied to the size of the pump. Some are powered by electricity but many go off grid in case electricity non-availability, while others are powered by gas, propane or diesel fuel. The prime mover runs a set of pulleys to a transmission which drives the cranks that have weights on them to help the motor lift heavy sucker rods. The sucker rods are driven by the sucker rod pump that resides at the bottom of the well. As the beam pump rocks back and forth, the rod string, sucker rod, and sucker rod pump are activated. Similar to a piston inside a cylinder, the sucker rod lift oil from the well formation, up through the tubing and into a holding tank on the surface of the ground (Tech-Flo, October 2006).

1.1.2.3 BEAM PUMP IN OIL PRODUCTION. 

Artificial lift is a method used to lower the producing bottom hole pressure (BHP) on the formation to obtain a higher production rate from the well. Artificial lift can be used to generate flow from a well in which no flow is occurring or used to increase the flow from a well to produce at a higher rate (Tech-Flo, October 2006).

The most common type of artificial lift pump system applied in oil production is beam pump which engages equipment on and below the surface of the ground, to increase pressure and push oil to the surface. Consisting of a sucker rod string and a sucker rod pump, beam pumps are the familiar jack pumps used on onshore oil wells  (Tech-Flo, October 2006).

Beam pump converts the rotary motion of the motor to the vertical reciprocating motion necessary to drive the polished-rod and accompanying sucker rod and column (fluid) load (Tech-Flo, October 2006).

Beam pumps are used to mechanically lift oil out of wells which does not produce enough pressure for the oil to freely flow to the surface. Beam Pumps are commonly found onshore in areas that are high in oil production (Tech-Flo, October 2006).

Beam pumps are the most common method used to remove liquids from gas wells. They can be used to pump liquids up the tubing and to allow gas production to flow up the casing. Their ready availability and ease of operation have promoted their use in a variety of applications; usually when the well has become so weak, othernon-pumping methods cannot be supported (Wells, 2003). 

Beam pump installations typically carry high costs relative to other deliquefying methods, such as foaming, plunger lift, velocity strings, or intermitting. Their initial cost can be high if a surplus unit is not available. In addition, electric costs can be high when electric motors are used to power the prime movers, and high maintenance costs often are associated with beam pumping operations. Because of the expense, alternative methods to deliquefy gas wells should be considered before installing beam pumps, or other powered pumping systems. Regardless of economics, beam pumps can work well to remove liquids from gas wells (Wells, 2003).

If beam pumps are used for gas well liquid production, the beam system often will produce smaller volumes of liquids, especially at depth, because of the usually low volumes required to deliquefy gas wells. The fact that beam pumps do not have a "lower limit" for production and efficiency as do other pumping systems, such as ESPs, they are often used for gas well liquid production (Wells, 2003).

1.1.3 ELECTRIC SUBMERSIBLE PUMP

A submersible pump or sub-pump, electric submersible pump (ESP) is a device which has a deep sealed motor close-coupled to the pump body. The whole assembly is submerged into the fluid to be pumped (Elsevier, 2009). 

Electric Submersible Pumps (ESP) consist of a downhole pump (a series of centrifugal pumps), an electrical motor which transforms the electrical power into kinetic energy to turn the pump, a separator or protector to prevent produced fluids from entering the electrical motor and an electric power cable that connects the motor to the surface control panel. ESP is a very versatile artificial lift method and can be found in operating environments all over the world (Lyons 1996). 

They can handle a very wide range of flow rates (from 200 to 90,000 barrels (14,000 m3) per day) and lift requirements (from virtually zero to 10,000 ft (3,000 m) of lift). They can be modified to handle contaminants commonly found in oil, aggressive corrosive fluids such as H2S and CO2 and exceptionally high downhole temperatures. Increasing water cut has been shown to have no significant detrimental effect on the ESP performance. It is possible to place them in vertical, deviated or horizontal wells, but it is recommended to deploy them in a straight section of casing for optimum run life performance (Lyons 1996).

Although latest developments are aimed to enhance the ESP capabilities to handle gas and sand, they still need more technological development to avoid gas locks and internal erosion. Until recently, ESPs have come with an often prohibitive price tag due to the cost of deployment which can be in excess of $20,000 (Lyons 1996).

Various tools such as Automatic Diverter Valves (ADV), SandCats and other Tubing String and Pump Tools enhance the performance of the ESP. The majority of systems deployed in the market today are Dual ESP Systems which is a simple arrangement of two ESPs in the same well. This delivers a complete downhole system booster or back up - downtime is minimal, less workovers cost, there are savings in other operational areas. ESP Dual Systems bring a significant enhancement of well profitability (Lyons 1996).

Electric submersible pumps (ESPs) are typically reserved for applications where the produced flow is primarily liquid. High volumes of gas inside an electrical submersible pump can cause gas interference or severe damage if the ESP installation is not designed properly. Free gas dramatically reduces the heat produced by an ESP and may prevent the pumped liquid from reaching the surface. In gas reservoirs that produce high volumes of liquids, ESP installations can be designed to effectively remove the liquids from the wells while allowing the gas to flow freely to the surface (Wells, 2003).

The main advantage of this type of pump is that it prevents pump cavitation, a problem associated with a high elevation difference between pump and the fluid surface. Submersible pumps push fluid to the surface as opposed to jet pumps having to pull fluids. Submersibles are more efficient than jet pumps (Elsevier 2009).

1.1.3.1 HISTORY OF ELECTRIC SUBMERSIBLE PUMP

In 1928, Armenian oil delivery system engineer and inventor Armais Arutunoff successfully installed the first submersible oil pump in an oil field (Arutunoff, 2012). In 1929, Pleuger Pumps (Now Pleuger Industries) pioneered the design of the submersible turbine pump, the forerunner of the modern multi-stage submersible pump (Elsevier 2009).

1.1.3.2 HOW ELECTRIC SUBMERSIBLE PUMP WORKS

Electrical submersible pumps (ESPs) look much like vertical turbine pumps in term of design. They are typically used to pump liquid (Thomas, undated)

Electric submersible pump is driven by an electric motor which increases the fluid's kinetic energy. This kinetic energy is then partly converted into pressure which lifts the fluid through the pump. Electric Submersible Pumps are centrifugal pumps with vertical shafts and depend on basic rotating impellers to pressurize fluid (Thomas, undated).

1.1.3.2.1. Centrifugal Pump Basics

 Centrifugal pumps feature rotating impellers, typically made from metal, which contain rotating vanes. These vanes transfer energy from the motor to the fluid they propel. As fluid enters the impeller, it accelerates as the impeller rotates. Eventually, the fluid exits the impeller’s vanes at an increased speed and the kinetic energy is typically converted into pressure (Thomas, undated).

In an Electric Submersible Pump, mechanical seals are used to prevent fluid from flowing into the motor, the motor is coupled to the pump itself, and the entire unit is submerged into the fluid to be pumped. Without mechanical seals protecting the enclosed unit, the motor could short circuit and fail (Thomas, undated).

In cases where more than one impeller is used, the pump is said to be multistage. Multistage centrifugal pumps may feature multiple impellers located on one shaft or impellers on separate shafts. The result of connecting impellers in a series is higher pressure connecting impellers parallel to one another result in increased output. Regardless, the fluid still gather its energy from the electric motor that drives the impellers (Thomas, undated).

1.1.3.2.2 Electric Submersible Pump Applications

Electric Submersible Pumps are used in many different applications. Single-stage pumps can be used for basic drainage and pumping in many industrial applications, and can also handle slurry pumping. Multistage pumps are more often found in water removal applications. This can be used in water and oil wells (Thomas, undated). 

Regardless of the application, double checking manufacturing specifications for a given ESP will help ensure its proper use (Thomas, undated).

1.1.3.2.3 Electric Submersible Pump and Oil Wells

ESPs can work with a variety of flow rates and depths which make them well-suited to work inside oil wells. When used accurately, an ESP pump can decrease well pressure at the bottom enabling the withdrawal of a higher amount of oil than it could be extracted under normal pressure conditions. Pump diameter size ranges from 90 millimeters (mm) to 254 mm, and pumps can be one to 8.7 meters long (Thomas, undated).

1.1.3.2.4 Electric Submersible Pumps and Dewatering Gas Wells

Some gas reservoirs can produce a high amount of liquid but gas can damage ESPs so care must be taken when using an ESP to remove liquid from a gas well. However, ESP systems can be designed to enable the gas flow freely up the pump’s casing, while the pump efficiently removes fluid. The gas flow depend largely on casing head pressure (Thomas, undated). 

There are typically four methods by which ESPs can be used to dewater gas wells, but depending on the exact well condition, all ESP set-ups should be sufficiently researched before a method is employed. (Thomas, Undated).

1.1.3.3 USES OF ELECTRIC SUBMERSIBLE PUMP IN OIL WELLS

Electric Submersible pumps are used in oil production to provide a relatively efficient form of artificial lift. They are able to operate across a broad range of flow rates and depths (Lyons, undated). 

By decreasing the pressure at the bottom of the well (by lowering bottomhole flowing pressure or increasing drawdown), significantly more oil can be produced from the well when compared with natural production. The pumps are typically electrically powered and are referred to as Electrical Submersible Pumps (ESP) (Lyons, undated).

ESP systems consist of both surface components (housed in the production facility, for example an oil platform) and sub-surface components (found in the well hole). Surface components include the motor controller (often a variable speed controller), surface cables and transformers. The subsurface components are deployed by attaching to the downhole end of a tubing string, while at the surface, and then lowered into the wellbore along with the tubing (Lyons, undated).

A high-voltage (3 to 5 kV) alternating-current source at the surface drives the subsurface motor. Until recently, ESPs had been costly to install due to the requirement of an electric cable extending from the source to the motor. This cable had to be wrapped around jointed tubing and connected at each joint. New coiled tubing umbilicals allow for both the piping and electric cable to be deployed with a single conventional coiled tubing unit. Cables for sensor and control data may also be included (Lyons, undated).

The subsurface components generally include a pump portion and a motor portion with the motor downhole from the pump. The motor rotates a shaft that in turn rotates pump impellers to lift fluid through production tubing to the surface. These components must reliably work at high temperatures of up to 300 °F (149 °C) and high pressures of up to 5,000 psi (34 MPa), from deep wells of up to 12,000 feet (3.7 km) deep with high energy requirements of up to 1000 horsepower (750 kW) (Lyons, undated). 

The pump itself is a multi-stage unit with the number of stages being determined by the operating requirements. Each stage includes an impeller and diffuser. Each impeller is coupled to the rotating shaft and accelerates fluid from near the shaft radially outward. The fluid then enters a non-rotating diffuser, which is not coupled to the shaft and contains vanes that direct fluid back toward the shaft. Pumps come in diameters from 90mm (3.5 inches) to 254mm (10 inches) and vary between 1 metre (3 ft) and 8.7 metres (29 ft) in length. The motor used to drive the pump is typically a three phase, squirrel cage induction motor, with a nameplate power rating in the range 7.5 kW to 560 kW (at 60 Hz) (Lyons, undated).

ESP assemblies may also include seals coupled to the shaft between the motor and pump, screens to reject sand and fluid separators at the pump intake that separate gas, oil and water (Lyons, undated). ESPs have dramatically lower efficiencies with significant fractions of gas, greater than about 10% volume at the pump intake, so separating gas from oil prior to the use of the pump is very important (Lyons, undated).

Some ESPs include a water/oil separator which permits water to be re-injected downhole. As some wells produce up to 90% water and fluid lift at a significant cost, reinjecting water before lifting it to the surface can reduce energy consumption and improve economics. Given ESPs high rotational speed of up to 4000 rpm (67 Hz) and tight clearances. ESP are not very tolerant of solids such as sand (Lyons, undated).1.2 PROBLEM STATEMENT

An oil well produces at its maximum rate at the start of its life, the production rate eventually declines to a point at which it no longer produces profitable amounts.

Beam pump is an artificial lift pumping system which is placed above the ground, it uses a surface power source to drive a downhole pump assembly. Beam pump does not require gas or electricity to operate. 

Electric Submersible Pump is an efficient and reliable artificial-lift method for lifting moderate to high volumes of fluids from wellbores. The whole assembly is submerged in the fluid to be pumped. The main advantage of this type of pump is that it prevents pump cavitation, a problem associated with a high elevation difference between pump and the fluid surface. Submersible pumps push fluid to the surface as opposed to beam pumps having to pull fluids. ESP require electricity to operare and save

 time because it is self primed.

Optimizing production system has been a major challenge and problem for production engineer, the choice of artificial lift method to be used inorder to increase oil production rate has been the major concern.

Optimization of oil well performance speed up the production system which inturn increases production rate. Also, there is need to evaluate the components of Oil production system. 

The study is limited to the use of manual methods and PROSPER for designing of ESP and Beam pump so as to optimize heavy oil production. There are other software that can also be used in designing an ESP System but for this project PROSPER is used due to availability. 

1.3 JUSTIFICATION

High production cost and low production rate are few of many problems facing petroleum industries. This study is based on evaluating the effects of optimized beam pump and ESP on oil production rate, cost of production, wellhead pressure, bottom hole pressure and injection rate. 

1.4 OBJECTIVES OF THE STUDY.

The objective of this study includes:

⦁ Evaluating the performance of Beam pump and electric submersible pump when PROSPER software is used in oil production. 

⦁ Ascertaining that problems facing oil production system are overcomed when software PROSPER is used.

⦁ Determining the rate at which beam pump and ESP works when PROSPER software is used.

1.5 SPECIFIC AIM OF THE STUDY 

The specific aim of this study is to evaluate the performance of Beam pump and electric submersible pump in oil production when PROSPER is used.

1.6 SIGNIFICANCE OF THE STUDY

Artificial lift methods are used in oil production to speed up oil production process, reduce production time and increase production outcome, but artificial lift methods had there shortcomings which give rise to the need to optimise oil production system. 

The introduction of PROSPER in oil production system optimizes production rate, reduces production cost and increases output.

The significance of this study include: 

⦁ Evaluating the effect of PROSPER software on Artificial lift (Beam pump and ESP) in oil production. 

⦁ Evaluating the effect of optimization on production rate.

.

EVALUATION OF THE PERFORMANCE OF BEAM PUMP AND ELECTRIC SUBMERSIBLE PUMP IN OIL PRODUCTION USING PETROLEUM SOFTWARE (PROSPER)



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