1.0             INTRODUCTION


Naturally flowing well is a well in which the formation pressure is sufficient to produce the oil at a commercial rate to the surface without requiring a pump. Most reservoirs are initially at pressures high enough to allow a well to flow naturally. In other words, it is a well that can flow to the surface unassisted. However, during the well‘s life, pressures will drop to a point where it will no longer flow by its own accord. At this point, methods including artificial lift and enhanced oil recovery (EOR) will be employed to ensure the maximum reserves are recovered.

Based on this project, a natural flowing well is going to be focused upon. Naturally flowing wells normally use the energy inherent in the reservoir. This is referred to as the reservoir drive mechanism. The drive mechanism of the reservoir affects some of the fluid properties such as the gas oil ratio (GOR), water oil ratio (WOR) and parameters like the reservoir pressure and the flowing life span.


Water drive: A substantial percentage of petroleum reservoirs worldwide produce under water drive mechanism. In water drive, the energy responsible for production comes from the expansion of the aquifer underlying the reservoir. In some cases, water drive also results from the expansion of unknown hydrocarbon trapped within the aquifer or the expansion of connate water within the reservoir.

Characteristics of water drive

a)                  The reservoir pressure is high and fairly constant over a long period of time.

b)                  The GOR is low and fairly constant.

c)                  The production of water is fairly high.

d)                  The well has a long flowing lifespan.

e)                  Produces mostly under saturated oil and no gas at the wellbore.

f)                   It has a straight line IPR.

Gas cap drive: In a gas cap drive, the energy of production comes from the expansion of the free gas overlaying the oil zone. The factors that enhance the gas cap drive are dependent of the size of the gas cap, high vertical permeability, low oil viscosity, low density difference between oil and gas and finally dipping beds.

Characteristics of gas cap drive

a)                  High initial reservoir pressure, but declines eventually and gradually.

b)                  There is little or no water production.

c)                  The GOR is high and ever increasing.

d)                  The well flowing lifespan is shorter than that of the water drive.

e)                  The well produces saturated oil (Two phase flow).

f)                   Since saturated oil is being produced, straight line IPR cannot be used to describe the inflow performance relationship, hence Vogel IPR is used.

Solution gas drive: In the solution gas drive, the energy for production comes from the expansion of oil and it dissolved gas.

Characteristic of solution gas drive

a)                  Reservoir pressure declines rapidly.

b)                  Water production is nil or negligible, hence (BSW=0)

c)                  GOR is initially low and fairly constant, but rises rapidly and then declines.

d)                  It has a short well life span.

e)                  Most reservoirs with solution drive pressure require pressure maintenance and artificial lift.

In practice, the three above mentioned drive mechanisms are the basic types, but there are some others such as compaction drive mechanism or rock compressibility drive, gravity segregation (In high dipping reservoirs, substantial energy result from gravity especially perforating down dip), and lastly combination drive.


The selection and determination of tubing sizes is an important link in the well completion processes. The traditional practices are that the hole structure is designed and the production casing size is determined by the drilling engineer. After a well has been drilled and completion is to be done, the tubing size and the mode of production are selected and determined by the production engineer on the basis of the production casing that has been determined. The outcome of this practice is that the production operations are limited by the production casing size. For instance if production rate is to be increased by increasing the tubing size, casing size will become a dependency factor. In order to avert this traditional practice, this project will prove the rational determination and selection of the optimum tubing size for production wells. In accordance with the reservoir energy and the requirement of production engineering, the rational tubing size should first be determined under a different production mode, and the admissible minimum production casing size is then determined and selected. At the flowing production stage, the rational tubing size can be determined and selected using the sensitivity analysis of tubing size which is based on nodal analysis. Pressure drop is known to occur from the reservoir itself up to the surface separator, and without this pressure differential, production cannot take place. Therefore the production system of an oil and gas well can be simplified into two large parts, namely the inflow and the outflow part. Hence developing a relationship between the inflow and the outflow with respect to tubing size is a critical means of determining the optimum tubing size for an optimum production rate. The project will also take into consideration the relevance of flow line sizing in the optimal production of a well.


Any oil well production system has an optimum tubing size to achieve an optimum production rate. When an undersized tubing is run into a well, pressure drop across the length of the tubing will be excessive leading to increased frictional resistance which will limit production rate, while on the other hand, when an oversized tubing is run into a well, pressure drop in the tubing will be low and a low flow velocity is experienced such that the flow velocity is not sufficient enough to lift the fluid to the surface and a phenomena called `` SLIPPAGE” begins to occur in which different phases of fluids are moving in the same direction with different velocities. In this scenario, liquid hold up is bound to occur and only gas is then being produced to the surface.

However, this project will focus on carrying out sensitivity analysis of tubing size using nodal analysis method, so as to determine the optimum tubing size for a production system.


The aim of this project is to use the nodal analysis technique for selecting the optimum tubing size to achieve an optimum production rate in naturally flowing well via modelling. The objectives of this project include:

To identify key variables that affect tubing sizes production optimization. To determine the sensitivity of the tubing sizes for production optimization. To evaluate the techniques required in the optimization of tubing sizes.


This project consists of five chapters as well as references and appendices. Chapter one comprises the introductory part of the project which unveiled the study and gave the background, statement of the problems, purpose and objective of the project and the organization of the project. The second chapter present the literature review that comprised of previous work done by other researchers on the subject matter, while the chapter three focuses on the methodology. Chapter four consist of data presentation, interpretation and discussion of findings and chapter five concludes and gives recommendation followed by references and appendices.


The goal of any oil company is to maximize profits by producing her wells optimally. This project is aimed at selecting optimum tubing size to achieve an optimum production rate, while utilizing the reservoir energy optimally. The relevance of this work include,

Optimising production with optimum tubing size. Minimizing pressure drop in the tubing. Lowest energy consumption for lifting the hydrocarbon. Minimal frictional flow resistance. Longest flowing time. Maximum energy utilization efficiency.


The modelling for tubing size selection will be done via sensitivity analysis of tubing size using a software called PROSPER with the aid of collected field data. The modelling will be that of a two phase flowing well (gas driven reservoir or depleted drive reservoir) which is a naturally flowing well.

In many circumstances, the conditions of surface flow line cannot be determined in advance and the tubing pressure derived from a given separator pressure method cannot be used for the sensitivity analysis of tubing size. Thus, the tubing size is optimized by setting wellhead tubing pressure (pwf).



The optimum tubing size for the naturally flowing reservoir 09.12 and P1.00 has been successfully determined by carrying out sensitivity analysis for the different tubing sizes. The operating point or in other words, the production rate for the different tubing sizes was obtained at the point of intersection between the Inflow Performance Curve (IPC) and the Vertical Lift Performance curve (VLP). The optimum tubing size gave the optimum or highest production rate when compared to the production rate of the other tubing sizes. Based on the result of this study, the following conclusions can be drawn:

⦁    From tubing size sensitivity analysis result of reservoir 09.12, it can be deduced that the optimum tubing size that should be used to complete the well is 4Image inches tubing, because it yielded an optimum production rate of 1745.1 STB/day.

⦁    From tubing size sensitivity analysis result of reservoir P1.00, it can be deduced that the optimum tubing size that should be used to complete the well is 4Image inches tubing, because it yielded an optimum production rate of 1479.0 STB/day.

⦁     Since optimum tubing size for the both reservoir is 4 ½ inches tubing, it can be said that optimum production with respect to optimum tubing size cannot be achieved via dual completion using a 9 Image inches casing size.

⦁    For optimal production of the reservoirs, a single string completion of a 4Image inches tubing is recommended.

⦁    If the well must be dual, then the production casing should be 13Image inches instead of the 9Image inches.


⦁    A non-linear optimisation software should be used for the modelling also, so as to correlate with PROSPER optimisation result and for validation.

⦁    For optimum production at the surface, it is recommended to carry out further modelling such as modelling to determine the optimum flowline size.




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