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Rephrase your research questions and make it more solid ,reduce aims and objectives and make it more solid and keep it at 4 and not 5 in the proposal .

Expand your literature review and make it more detailed talking about the advantages and disadvantages of nodal analysis -history matching etc and also in the literature review explain what you will do in the data analysis.make it very comprehensive with enough information to back up your arguments.

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Subject Writing a proposal Pages 12 Style APA







The main aim of the literature review is to present the relevant literature regarding optimization of a single well production system in the Niger Delta using Nodal analysis. The literature scrutinized will present facts and information about the challenges that may be encountered in such a case of a single well production system. The literature review will also provide strategies and solutions of how optimization of a single well production system may be carried out.

Production system

Optimization of a single well production system in Niger Delta using Nodal analysis means that there should be a balance production rate and demand. Hossain (2008) argues that to achieve production optimization, there needs to be a good understanding of the different available production systems and reservoir fluid. Therefore, a production system will include the following components, reservoir, wellbore and surface facilities. The reservoir forms the Inflow Performance Relationship (IPR); the well bore consists of parts such as completions and tubing, and the surface facilities are made up of flow lines, separator, and pipelines, etc.

A production system can come in two different forms, either in simple or complex form. In simple form, the production system may comprise of the reservoir, surface facilities, and tubing. In the complex form, the production system may be made up of an artificial lift system, multiple wells, and a water injection. A typical production system will have a reservoir, which contains a fluid referred to as the reservoir fluid. The reservoir fluid may be identified through compressibility, gas and oil gravities, densities, a bubble point, Gas Oil Ratio (GOR) and Formation Volume Factor (FVF). Any movement of the reservoir fluid requires energy; this energy is important in overcoming the pressure drop and frictional losses. To determine the pressure drop, the initial fluid pressure, and final fluid pressure should be noted. The pressure drop will be the result of the difference between final fluid pressure and initial fluid pressure.

The reservoir and piping system should be taken into consideration. The piping system and reservoir are important because of the interdependence that exists between the fluid amount and the pressure drop. Oil and gas flowing from the reservoir to the well is dependent on the pressure drop within the piping system, while the pressure drop found in the piping system is dependent on the fluid amount passing through the piping system. The production system should be analyzed as a unit of the reservoir and the piping system.

It is important to take some concerns into account before selecting a production system. Such considerations include the reservoir deliverability, the future prices of oil and gas, the value of money in relation to time, transport to the market, flow operability and assurance and how the hydrocarbon will be lifted. The deliverability of the reservoir presents important information on production and the production rate as a function of time. Lifting the hydrocarbon involves different kinds of flow. The flow could be in the form of flow in the wellbore and flow in the tubing. Both forms of flow may be in the form of natural flow and artificial flow. The flow in the well bore and tubing may come as a single phase or multiple phases. Different flow control processes take place at the flow stage such as separation and disposal, flow rate adjustment and pressure maintenance. The main means of transport to the market include pipeline, tankers, and shipping. Underflow operability and assurance, processes carried out are scale formation, Paraffin and Asphaltene deposition, and extensive slugging and hydrate formation (Hossain 2008).

Different production systems can be applied to the single well in Niger Delta to optimize production. The most suitable production system would be the gas lift system.  The gas lift system has been used in cases where the aim was to either start up an oil well or increase the production rates of the well. The production system will also help minimize on both operating and capital costs in the Niger Delta. The single well in the Niger Delta experiences an insufficient pressure in its reservoir and, therefore, cannot raise the fluids to the surface. A gas lift system is a production system under the category of artificial lift systems. These systems also function as tools for removing water from the oil wells so as to maintain production (Sylvester 2015).

According to Alemi (2010), a gas lift system is also used in normal functioning wells. Regardless of a well, operating normally, the first production may require an artificial lift. The first instances of production may be characterized with oil traces of high fluid density. An artificial production system such as the gas lift system will help lighten the oil.

Chikwere (2015) states that a production system can only function well if the operators are aware of the most suitable artificial lift techniques to use. A production system will only function properly if the operators can determine that production optimization is necessary. To determine this, the operators should take logical steps in examining the field’s production facilities in place, from below the surface to the surface. The gas lift system achieves the optimization by maintaining a balance between production deliverability and demand on the wells. Therefore, optimizing a single well through nodal analysis entails using a production system on the well so as to achieve the highest efficiency of the well.

Before the gas lift system can be implemented in the well, different key factors should be considered i.e. operational features of the current lift systems and the well parameters. Geographical and environmental factors also determine the kind of production system that will be used. To choose an efficient production system, the operational criteria to be selected should be unique to the system. The operational criteria will include power sources, the location of the field, depth of the well, the ratio between gas and liquid, inflow performance relationship, and environmental impact. Other factors of minor effect may include reservoir pressure, reservoir fluid properties, and productivity index (Camponogara 2006).

It is important to compare the installation costs of a production system to the expected revenue from the system. A gas lift system is efficient in operating multiple wells, but it comes with a high initial cost. Installation of a compressor is crucial to the operation of a gas lift system and, therefore, can only be economical if the production system can generate substantial revenue. The compressor in a gas lift system helps in lowering hydrostatic pressure into the well.

Optimization of the gas lift system, however, does depend on some functions. These functions may be in the form of one variable or multi-variables. The gas lift system achieves optimization of a well by making it operate under optimal conditions and with minimal difficulties. The different performance analysis software can determine the performance of a production system, for example, the gas lift system. The most popular performance analysis software includes Prosper and Prepsim (Khamehchi 2009).

In Khamehchi (2009) perspective, a gas lift system is a versatile production system if there is insufficient pressure in the well reservoir required to lift the oil. However, this is subject to the availability of gasses for injection from gas reservoirs in an installed compression plant. The production system involves introducing gas via a tubing casing annulus, the gas will aid in aerating the fluid so as to reduce its density. Pressure is built, which in turn lifts the oil column and powers the fluid out of the well. The producing features of the well and the production system arrangement are important factors in determining how the gas will be injected. Depending on these two factors, the gas can be injected continuously or sporadically.

Application of the Gas Lift System

Artificial gas lift is a method of increasing the production of oil or gas from wells that have a low reservoir pressure by injecting gas into the tubing. The gas injected into the tubing usually lowers the hydrostatic pressure within the tubing by mixing with the oil or gas in the reservoir. The mixture of the injected gasses and the fluid in the well reduces the down-hole pressure in the well by reducing the density of the fluid, which increases the well’s production. The artificial gas is usually injected into the well through the annulus after which it reaches the injection valve and gushes into the tubing.

The procedure of the Gas Lift System

  • The production choke is opened allowing gas to enter the tubing, which automatically lowers the pressure in the tubing.
  • The continuous flow of the gas forces the fluids out of the tubing.
  • When the gas lift choke is opened, gas enters the annulus with high pressure and passes through the injection valve into the tubing.
  • The gas rises through the tubing creating low-pressure zone, which forces the oil to flow out of the reservoir and increases the well production
  • The oil production increases as the gas pressure relatively rises until it reaches optimum capacity where a further increase in the gas pressure may cause a decrease in the oil production.

According to Eikrem (2008 ), an increase in the rate of injection of gas into the annulus results in increased production of a gas lift well until the well reaches its maximum production capacity. If the injection of gas into the well continues past its maximum capacity, the production of oil will reduce drastically.

In the modern society, a production system involves some optimization activities. Examples of optimization activities include maintaining reservoir pressure and solving bottlenecks in the flow lines. These optimization activities are important in assisting oil engineers, and scientists understand the relationship between various system components. The optimization activities help improve the efficacy of the production system by ensuring effective oil production. For a production system to achieve optimization in production, it should be able to target reduction in costs, increase in the Net Present Value (NPV) and growth in oil flow rate (Egelle 2014).




Figure 1: Geological map and Location of the Niger Delta Field

Figure 2: Geological Sketch map of the Niger Delta

Figure 3

The wells of the Niger Delta are located in the south western part of the delta. The Niger Delta field was discovered in 1965, but production began in 1968. The field comprises of two major blocks i.e. the western and eastern blocks. A major normal fault separates these two blocks. There is a third minor block located in the north eastern part and is characterized with minimal traces of commercial oil reserves. The majority of the Niger Delta wells were drilled along the Agbada Formation. These wells are located in the lower parts of the Agbada Formation and target the structural outlook of the formation. Whereas the other wells were drilled through the Benin Formation, which is made up of sands saturated with fresh water (Nyantakyi 2013).

The Niger Delta is comprised of 37 wells, of which 23 are deviated, and 14 are vertical. Among the 23 deviated wells, 5 are horizontal at depth. 12 wells are located in the eastern block, and one of the wells is a water injector, whose purpose is to provide pressure support. Different studies have been carried out in the Niger Delta, for example, the recent reservoir simulation study. Based on the results of the reservoir simulation study, it was recommended for more drilling of wells so as to address the water coning problem and optimize production. Through the simulation study, more progress has been made in the form of more discovery of reservoirs, 53 to be specific. The Niger Delta covers a vast area of close to 75,000  explaining why it encompasses a considerable number of wells (Nyantakyi 2013). The Niger Delta is located in West Coast Africa at the top of the Gulf of Guinea.

This research, however, focuses on a single well in one of the fields in the Niger Delta by the name Field H-10. The field H-10 comprises of six wells, but not all wells are operational. Five wells are functioning while one is dormant. The research will, therefore, focus on this single well and arrive at optimization of the single well production system through nodal analysis. The main challenge that this single well is facing is underperformance caused by the production of water from the well. An effective production system should be put in place in the form of a gas lift system to help revive productivity of the well, Reviving productivity of the well will help generate revenue for the company.

2.1.2            Operational Processes of Prosper and Prepsim

Prosper and Prepsim are optimization software used in the optimization of a well production system. Prosper is a software that aims at optimization, design and performance of modeling well-known configurations in the worldwide oil and gas industry. Prosper is an important tool for an oil engineer as it aids in predicting tubing and pipeline temperatures and hydraulics. Optimization of a well is possible through the sensitivity calculation features of Prosper. These features in Prosper also help in assessing the effects of imminent changes in the system constraints (Sylvester 2015).

The design of Prosper allows it to support building consistent and reliable well models. The software can also address all aspects of well-bore modeling, fluid categorization, vertical lift performance (VLP), pressure volume temperature, Inflow Performance Relationship (IPR), tubing pressure loss and calculation of flow line. Production optimization can be achieved through Prosper by going through the following operational processes. The first process is selecting the model option, followed by setting up the model. After finishing up with the selection and setting up of the model, the next step requires the input of Pressure Volume Temperature (PVT) data and then matching the PVT data with the selected model. Matching the data with the model will allow you to come up with the best correlation to use in the system. At the system level, you will be required to make use of the equipment data and the Inflow Performance Relationship (IPR).

The system will be optimized depending on the availability of artificial lift. In a case where there is an artificial lift, data will be input so as to create a new design and match the IPR with the VLP. But, if there is no artificial lift, you will be required to compare directly the IPR with the VLP. The next step would be the correlation comparison followed by determining if there is substantial VLP. If the answer is yes, the last step would be to generate a report on the system (Sylvester 2015).



2.1.3            Procedure of Nodal Analysis

Nodal analysis is a system analysis used in the design of a system that comprises of multiple interacting components. According to Dmour (2013), the first application of the Nodal analysis can be attributed to Gilbert, in his work of 1954. He was the first to use the system analysis approach in the oil and gas wells. However with time, more researchers have been able to popularize this approach. The main objective of the Nodal analysis is to come up with a combination of various production system components so as to estimate production rates and optimization of the production system of a well.

Beggs (2003) describes the Nodal analysis as a method where you consider the whole production system as one unit. He continues by stating that a point should be determined by the input where input and output pressure are equal. From the nodal analysis, we get the word ‘Node’ which is a point where the flow into the point is the same as flow out of the point.  Flow into the point is referred to as inflow while flow out of the point is outflow. These two flows can be represented in equation as follows:

Inflow: Pr – DP = P node; (DP = upstream of the node)

Outflow: P sep + DP = P node; (DP = downstream of the node)

The Nodal analysis works through the intersection of the inflow and outflow; this intersection helps satisfy the set conditions. Any change made either on the inflow or outflow will change the intersection. The node is flexible as it can be selected anywhere on the production system. The different positions that the node may occupy in the production system include the wellhead, safety valve, reservoir, restriction, separator, surface choke and bore hole Pwf. However in most cases, the node will occupy the borehole Pwf.

The nodal analysis is important in inspecting flow through the system. It is important to understand some principles so as to scrutinize the flow of reservoir fluids from under the surface to the surface. These principles are mainly based on the flow of fluids through well hollows and porous surfaces. In such a case of fluid flow, the relative pressure will be accompanying the flow. This pressure will account for the sum of pressure drops taking place across different components of the production system. Normally, the pressure drops are dependent on the kind of interaction that exists between the system components and the compressible nature of oil and gas. This dependency explains why it is important to use an integrated approach to the ultimate design of a production system. A normal system cannot be divided into different components and handled independently, for example, reservoir or piping components. The system components are dependent on each other, for instance, the pressure drop in the production system determines the amount of oil that will be produced from the reservoir. While at the same time, the pressure drop is dependent on the level of fluid flow in the system (Shadizadeh 2009).

The total pressure drop can be calculated by determining the start and end of the production system (Shadizadeh 2009). For example if the separator in the production system is the end while the reservoir is the start, then the pressure drop will be determined by calculating the difference between the average separator pressure and reservoir pressure. The total pressure drop is made up of individual pressure drops noticed through the reservoir fluid flow. The reservoir fluid flow takes place from the reservoir up to the tubing. The total pressure drop also takes into account restrictions, tubing accessories and subsurface safety valves.

Yeten (2003) states that Nodal analysis applies the concept of continuity. A production system will feature a particular production and pressure rate related to a set of conditions. This fact means that the system will determine the changes in the production or pressure rates. For example, if a change occurs in the system, there will be a relative change in the pressure and production rates. The continuity in change makes it possible for the system to be divided according to the two rates of pressure and production. The point where the system gets divided helps in the determination of the continuity of production and pressure rates at the division point. The producing condition of the system is regarded as the continuity. Evaluation of a system component is, therefore, possible as it is flexible enough to divide the production system along points of interest within the system. These points of interest may include the wellhead points or points of perforation.

Various components make up different sections of the system, for example, upstream components of the division point make the inflow section of the system while downstream components represent the outflow section. These two sections of the system bring up relationships within each section that involves the pressure rate. However, the rate of flow in the system is subject to some conditions. The first condition is that the flow into the division point should be equal to the flow out of the division point. The second condition is that the pressure at the division point should be equal to the pressure in both sections of the system i.e. inflow and outflow sections (Dmour 2013).

After you select the division point in the system, relationships in pressure will be developed for both the system inflow and outflow sections and in the process, estimation of the node pressure will be achieved. Pressure drop in either section of the system and any system component acts as the function of flow rate. Therefore, node pressures for each system section can be calculated through a series of flow rates. After the calculation, the relationship between node pressure and production rate for the system sections can be determined.  The effects that arise from changing any system component can be evaluated through recalculation of the node pressure for the new features of the system. A change in the upstream component of the system means that there would be a change in the inflow section of the system. The same applies to the downstream component, where a change in the component will result in a change in the outflow section of the system (Yeten 2003).

Applications of the nodal analysis vary; the analysis may be used to perform various functions in oil and gas wells’ design and analysis. The nodal analysis is important in the evaluation of wells and artificial lift applications; it gives a powerful insight into the design of a system. The system analysis helps in coming up with a qualitative estimate of how a well may function. With the help of nodal analysis, you can be able to analyze current producing wells by detecting performance enhancement opportunities and flow restrictions. The nodal analysis is an important tool for the estimation of flow rates and the selection of tubing size, flow line size, surface choke sizing, and wellhead pressures. Estimation of reservoir pressure depletion effects, gravel pack design, optimization of the injection gas liquid ratio used in the gas lift, evaluation of the perforation density and well stimulation treatments are also possible. The Nodal analysis, therefore, makes it possible to come up with a design of a well and improve performance of an operating well (Dmour 2013).

Cuautle (2003) describes the nodal analysis procedure as one that can be applied to different systems such as electric circuits, centrifugal pumping systems, and pipeline systems. The procedure involves the selections of a division point or a node among the system components where the well system can be divided into an upstream section and a downstream section. The upstream section consists of the components that allow inflow into the well while the downstream components allow outflows from the well. Each component within the system must have a flow rate that is related to the pressure drop within the well. Having determined the different pressures at the exit and entry points of the well, the nodal analysis will be used to determine the rate of flow that a hydraulic system can handle under the existing conditions.

The nodal analysis of components

Reservoir performance

The nodal analysis will be used to determine the pressure loss at the reservoir, which is crucial to the delivery of hydrocarbons into the wellbore. The pressure at the reservoir before the implementation of gas-lift shall be determined and compared to the estimated pressure needed to deliver fluid into the wellbore. From these two measures, the optimum pressure required for the fluid to rise to the stock tank and the surface can be easily estimated. The inflow performance relationship (IPR) functions are commonly used to measure the reservoir performance. The tools used to measure the performance of the reservoir include diagnostics such as transient testing, saturation logging, sonic imaging and production logging. Some of the remedial actions taken to increase reservoir performance include stimulations, squeeze cementing, and high-performance perforating and water control.

Completion performance

Aspects of well completion that are analyzed through nodal analysis include liner slots, sand control screens, a zone of formation damages, perforations and the cement-by-borehole annulus. A reduction in the deliverability of a well is usually an indicator of a reduced flow rate within the well tubing and structure. Some of the helpful measures that may be needed to optimize the completion performance include implementing a cement squeeze in areas that are generating excess water and perforating a larger segment in order to reduce the classical skin on the well. The diagnostic tools used to measure the completion performance include ultrasonic imaging tools, perforation-analysis programs, and economic analysis and production logs.

Flow-conduit performance

Flow-conduit performance is used to assess the performance of wellbore size. The flow efficiency measures the incidence of leaks and restrictions in the wellbore tubing that might affect the smooth of liquid up the well. The same diagnostic tools used in the above processes are also used at this stage with the addition of water-flow logs that are used to determine the frequency and extent of leaks in the system.

Artificial-lift performance

The efficiency of the artificial lift mechanism is a crucial aspect of the performance of a well, which means that its performance directly affects the well deliverability. To measure the efficiency of the artificial lift performance, one can look at the production logs, artificial-lift monitoring system, and the gas-lift valves.

Wellhead pressure

The pressure at the wellhead is a result of the initial pressure of oil as it leaves the reservoir minus all the pressure losses as the oil rises in the well up to the wellhead where the oil has reached the surface. Therefore, the pressure at the wellhead is the final pressure, which can be calculated as below:

Pws – Psep = DPy + DPc + DPp + DPl


DPy = Pws – Pwfs = Pressure reduction in the Reservoir.

DPc = Pwfs- Pwf = Pressure reduction in the Completions.

DPp = Pwf-Pwh = Pressure reduction in the bottom hole pressure.

DPl = Pwh – Psep = Pressure reduction in the flow line.

The appropriate measures for the calculation of the node pressure, as described in (Camargo 2008), can be formulated as below:

Node Input Pressure:

Pwh (Inflow) = Pws – Dpy – Dpc – DPp

Node Output Pressure:

Pwh (Outflow) = Psep + DP1

            In brief, therefore, the optimization procedure through nodal analysis involves: identifying the system components. The second procedure is to select the component to be optimized. Third is to select the best node location to emphasize the effect of the change. The fourth step is to develop an expression for inflow and outflow. Then calculate the pressure drop versus pressure rate for each component and determine the effect of a change of the selecting component. You should repeat the optimization procedure for each component until system optimization.


Choosing the gas list system as the single well production system has its challenges. Implementing gas-lift operations requires a high initial investment that is applied towards gas compression. The gas compression is necessary to accumulate enough gas reserves to ensure continuous gas pressure during the lifetime of the well. There is also a maximum limit to the amount of gas lift that can be applied to a particular well, once this limit is exceeded; the well production starts declining. The decline happens because an increase in the pressure of gas within the tubing increases the amount of friction, which may cause a pressure reduction at some point. The Gas-lift system may also not be very effective on a well that has a low reservoir as the additional backpressure from the gas-lift might hinder the liquid from rising through the tubing. In some cases, engineering well pads in the gas lift systems have a high upfront cost. Operational costs are also high, especially if natural gas is used.

Another challenge facing the gas lift system is the underground heat generated.  The temperatures in such situations can reach up to a high of 220 degree Celsius. Such kinds of temperatures are enough to melt some metallic substances such as tin. In rare cases, the temperatures can reach up to 330 degree Celsius where it is possible for a lead pipe to melt. The high temperatures, therefore, mean that the down-hole pumps used in artificial lift systems such as the gas lift system are under stress (Stonehouse 2010).

Apart from the high underground temperatures, the wild temperature swings too pose a challenge to the gas lift system. The temperature swings can hit a low of -40 degrees Celsius in during periods such as winter and end up stressing the pumps used in the production systems. The pumps expand and contract inconsistently and thereby reducing the pump life. The combination of corrosive liquids and gasses also means that the metal coatings on the pumps are eroded easily. Abrasive sands too, contribute a lot to tear and wear of these pumps. High volumes of produced water and gas can also reduce the lifespan of a pump. The gas and water corrode the materials that make these pumps (Stonehouse 2010).









Past authors have applied linear programming approach to maximize oil production from a well system subject to flow constraints. Mitchell (2015) did a survey on the wide application of optimization or mathematical programming techniques in the petroleum industry. The survey was particularly about problems in the area of design and operations of well production systems, gas lift, and reservoir planning and management. A proposal made from a “heuristic” non-linear programming procedure would optimize production from mature fields, using the oil and gas production from the field as the objective function. The proposal was subject to multiple flow constraints at separators, total gas lift volumes, pressure constraints at precise nodes of the gathering system and maximum velocity constraints for pipelines. The well rates, injection rate, and well allocations to flow lines made up the control variables. The Western Production Optimization Model (WPOM) was developed to optimize production from the Western Prudhoe Bay Field, Alaska. This strategy maximizes oil rate while minimizing processed gas. This model is based on the concept of “incremental GOR” which produces next incremental barrel of produced oil.

The latest methodology for optimizing production from mature fields involves the use of analysis and modeling tools with optimization software such as Prosper and Prepsim. Artificial lift is a commonly used technique to optimize production from mature fields, and gas lift is among the most widely use methods. This technique is also used to optimize production with insufficient reservoir pressure to deliver fluids to the surface. Gas is compressed from the surface through the annulus located between the casing and production tubing to a series of gas lift mandrels. Valves within the mandrels open, causing gas to be injected into the tubing where it mixes with the fluid in the reservoir, lighten it and, consequently, decreasing the bottom well pressure (Mitchell 2015).

According to Adesina (2009), the optimal injection rate depends on factors such as the “inflow performance relationship, tubing and surface hydraulics”. It is very important that engineers must consider a range of factors when designing a gas lift completion. The factors include the cost, handling capacities, availability of gas and surface infrastructure to compress and deliver gas into the well. When planning for the production optimization project, placement of the mandrel within the completion assembly is also critical (Mitchell 2015).

Mitchell (2015), alludes that the production optimization cycle involves analyzing the production data thoroughly using analytical and numerical simulation techniques such as Nodal Analysis. In her work, she used an integrated asset model approach to gas lift optimization by including the reservoir and processing components with the gathering network. This approach captures the changes in reservoir conditions over time enabling a robust optimization. The Integrated Production Modelling tool, developed by Petroleum Experts (Petex) is useful for modeling the complete well production system including wells and the surface gathering system. This tool allows the production and injection system to be evaluated and optimized and production forecast run. Petroleum Experts (2015) applied the PROSPER and GAP simulation programs to increase oil production through optimization of gas injected/fluid-produced oil ratio in an Egyptian oil field. The application involved developing and analyzing a complete production system.

Camargo (2008) has used a similar approach for improving gas lift well production system. Through the nodal analysis approach, a production model was obtained, which allowed the flow rate and pressure drop relationship to be calculated. After a relationship had been established between the two variables, the researcher developed an optimization formula to maximize oil production. The optimization formula can also be used to ensure that the well’s physical specifications are aligned to provide the best environment for oil production. Camargo (2008) conducted an analytical study on gas lift optimization using PROSPER tool and also predicted the production life of eight wells using dynamic reservoir modeling tool. The production rate of 8 wells was successfully optimized.

Nodal analysis technique combined with integrated production modeling was used by Egelle (2014) to optimize production from a mature field in the Niger Delta. The analysis was done by building an integrated model for the wells under study, reservoir and flow lines. The Nodal analysis was used to identify bottlenecks in the complete production system and production rates were optimized. The results of the nodal analysis were used to boost oil production in the mature oil field. The study demonstrated that nodal analysis was useful for increasing production in mature wells. Ayatollahi (2004) also adopted the Nodal analysis methodology to determine an optimization of the artificial lift system in the Aghajari oil field of Southwestern Iran. The analysis was done by determining the optimum gas-lift injection depth and rate and valve placement. The optimum gas-lift injection rate is crucial to ensuring that an oil well operates at maximum capacity because an excessive injection rate usually decreases the production rate of any oil well.





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