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1.1       Background of Study

After the completion of a given well or group of wells, they are then put under production. During this phase of operation, every operator looks for means to minimize operating cost and maximize cumulative oil production in the most cost-effective manner for the entire field. This stage of operation is what is generally termed production optimization. A true optimization requires an operator to take a logical look at the field’s production systems from the sub-surface to surface facilities.

Production optimization implies striking a balance between production deliverability of the wells and demand which basically aim at increasing the rate at which a well flows fluid from the reservoir without restriction to the surface storage tank(s). One of the most common means of conducting production optimization is through nodal analysis. This is normally done to optimize production from single wells or other smaller production systems. Large complex systems demand a much more sophisticated approach to predict the response of a large complicated production system accurately and to examine alternative operational scenarios efficiently. Beggs (1991) stated that optimization is directly dependent on some functions. The functions may be a single variable or more than one variable (multivariate optimization). A well is said to be optimized when it is producing at optimum conditions with minimum problems (Bath, 1998).

Most wells upon completion in oil producing sand formations will flow naturally for some period of time. Production at this stage will be initiated by the existing reservoir pressure. This reservoir pressure will provide all the initial energy needed to bring fluid from the well to the surface. As the well produces, this energy is consumed and at some point, there will no longer be enough energy to bring fluid to the surface. The well at this state, will cease to flow. When this happens, there is need for the well to be put under some form of artificial lift method in order to provide the energy needed to bring the fluid to the surface. It should be pointed out that artificial lift systems can also be used in de-watering of gas wells to sustain production.Basically, there are two methods of artificial lift systems. These are: pumping system (electrical submersible pump, sucker rod etc.) and Gas lift system.

There are different key factors that are considered prior to artificial lift installation in the field which include analysis of the individual well’s parameters and the operational characteristics of the available lift systems. For the different pumps and lift systems available to the oil and gas industry, there are unique operational/engineering criteria particular to each system, but they all require similar data to properly determine application feasibility. Such as the inflow performance relationship, liquid production rate, Gas liquid ratio, water cut, well depth, completion type, wellbore deviation, casing and tubing sizes, power sources etc. Each of the artificial lift systems has economic and operating limitations that rule out it consideration under certain operating conditions.

An extensive overview of artificial lift design considerations was presented by Clegg et al. (1993). Clegg mentioned some economic factors such as: revenue, operational and investment costs as the basis for artificial lift selection.Ayatollahi et al., (2001): Selection of the proper artificial lift method is critical to the long-term profitability of the oil well; a poor choice will lead to low production and high operating costs.For the purpose of this work, Gaslift method will be considered with a view to optimizing production from an oil well and hence optimal production from the field.

1.1.1    Gaslift system

Gaslift is the method of artificial lift which utilizes an external source of high pressure gas for supplementing formation gas in order to reduce the bottom-hole pressure and lift the well fluids. The mechanism of gas-lift is fairly simple. Gas is injected into the tubing string to lighten the liquid column and decrease the bottom-hole pressure, which allows the reservoir to push more fluids into the wellbore. At the same time, increased flow rates in the tubing string and surface flow lines result in higher backpressure on the well and adjacent wells that share a common flow line. This in turn causes a reduction in well production rates. Therefore, liftgas has to be carefully allocated to achieve maximum efficiency. The primary consideration in the selection of a gaslift system for lifting a well or group of wells is the availability of gas and cost of compression.

Of all artificial lift methods, gaslift most closely resembles natural flow and has long been recognized as one of the most versatile artificial lift methods. Because of its versatility, gaslift is a good candidate for removing liquids from gas wells under certain conditions. Again, Production of solids will reduce the life of any installed device that is placed within the produced fluid flow stream, such as a rod pump or ESP. Gaslift systems generally are not susceptible to erosion due to sand production and can handle a higher solids production than conventional pumping systems. In addition to the above mentioned advantages, gaslift systems can also be employed in deviated wells without mechanical problems.

Gas compressors are usually installed for gas injection or as booster compressors. There are various methods of injecting gas into a well during gas lifting operations. But the most commonly practiced method is the continuous flow gaslift system. Here, the utilization of gas energy is accomplished by the continuous injection of a controlled system of gas into a rising stream of well fluids in such a manner that useful work is performed in lifting the well fluids.

It is important to note that a number of factors affect the performance of a well. An understanding of these factors will allow the designer of a given production system to appreciate the need to obtain all available data before his design work begins. Some of the most common factors that will be considered in view to production optimization are discussed below:

1.1.2    Productivity Index (PI) and well Inflow Performance Relationship

Accurate prediction of the production rate of fluids from the reservoir into the wellbore is essential for efficient artificial lift installation design. In order to maximize production of oil from a gas liftedsystem, it is often necessary to determine the well’s production. The accuracy of this determination can affect the efficiency of the design.

One simple method of predicting a well’s inflow performance is the calculation of a productivity index (PI). The PI is the ratio of fluid production in barrels per day to the difference between the static reservoir pressure and the flowing bottom hole pressure in pounds per square-inch. This can be written mathematically as:

PI = J =

The Productivity Index represents a linear relationship as can be seen from Figure 1.1:

Figure 1.1: A typical Productivity Index curve

PI has been a useful tool for predicting the inflow performance of a well’s production rate at a specific flowing bottom-hole pressure. Studies over some given well’s producing life has brought the accuracy of the PI into question. It has been found that whenever there is a two phase gas-liquid inflow, the linear relationship between these variables will cease to exist. This makes it conclusive that the PI is valid for one phase production rate.

One of the basic assumption of Productivity Index is the availability of a stabilized bottom hole flowing pressure. It is this word ‘stabilized’ that makes the PI a topic of concern in the oil and gas industry. This is because, there is no reservoir in the real world that can be found to have a stabilized bottom hole pressure as production unfolds.

The PI is also a function of existing reservoir drive mechanisms. The term ‘drive mechanism’ as used in this context is used to differentiate between reservoirs whose motive power is primarily a displacement type as opposed to a depletion type.

Displacement type refers to strong active aquifer or gas cap drive and depletion type refers to a closed reservoir or one in which the motive power in the reservoir is primarily from gas dissolved in the oil. It should be noted that reservoirs with the displacement type drive will generally produce more reliable PI’s from well test rather than will the depletion type. In the displacement type, there is little or no free gas (aside from those existing in a gas cap) and; hence the reservoir capability to the single phase liquid is greater than it would be if the free gas were present. It should be pointed out that under certain conditions, there can be serious limitations to PI determination from this type of reservoir (displacement type). If a well is pulled too hard, then a localized depletion drive will result and obviously the PI as determined will not be reliable for predicting the well’s performance.

The depletion type reservoirs will yield fair reliable PI’s only when the pressure draw- down is small compared to the shut-in reservoir pressure.

Another approach to the correct prediction of a well’s performance is to plot flowing bottom-hole pressure against production rate. This plot is commonly called the ‘inflow performance curve’ and it was first used by Gilbert in describing well performance. Typical curves are illustrated in figure 1.2 below and they differ depending upon the type of reservoir. The curve for strong water drive is essentially a straight line as discussed above under Productivity Index. The determination of the non-linear relationship observed for solution gas drive wells present a significant problem. A publication by Vogel in January, 1968 offered a solution in determining Inflow Performance Curve for a solution gas drive reservoir when undergoing production below burble point. He was able to show that flowing bottom-hole pressure versus rate plot is a function of cumulative recovery changed. This then results in a progressive deterioration of the IPR’s as depletion proceeds in a solution gas drive reservoir system.

Figure 1.2: Typical Inflow Performance Curve


1.1.3    Outflow Performance Relationship/ Vertical Lift Performance

The outflow pressure drop required to lift the fluid from the perforations to the wellhead is another factor that must well be understood in order to accurately predict well performance. This outward flow of fluid from the wellbore to the surface is what is generally called the Vertical Lift Performance (VLP). The VLP is completely independent of IPR, but are closely related because flow from the reservoir and subsequent outward flow through the tubing must be equal at the wellbore.

Vertical Lift Performance predictions for various tubular string size is a very critical area in production optimization as up to 75% of all flowing pressure loss occurs along the tubing. The prediction of the outflow performance relationship is complicated by the multi-phase flow nature of the fluids. Analysis of the outflow performance therefore requires the accurate prediction of phase behavior of fluids at the various flow regimes along tubular string, flowing temperatures, effective fluid density and frictional pressure losses.

The results of the outflow performance are usually presented graphically. The most common plot depicts how the flowing bottom hole pressure (Pwf), varies with the flowrate for a fixed back pressure (usually the wellhead or separator pressure). The resulting curves are termed Tubing Performance Curves (TPC).  Any point on the curve gives the pressure required at bottom-hole condition, Pwf to achieve the given surface flowrate against a specified back pressure.

1.1.4    Control variables

Control variables can be seen as those production operation settings to be optimized. In this work, the control variables are: the production rates and the lift gas rates.

1.2       Statement of Problem

Optimum oil and gas production, a function of existing reservoir pressure, is the goal of every major player in the ever increasing oil and gas sector. Often times, during the primary stage of production, existing natural reservoir pressure may not be sufficient to cause fluid flow from the reservoir into the wellbore region through the production tubing to surface facilities; this might probably be due to the viscous nature of the oil (i.e. high viscosity). This inadequacy of the reservoir energy to lift the produced reservoir fluid from the wellbore to the surface may be caused by one, or a combination of the following factors: unwanted excessive pressure drop along the column of the tubing, the effect of downward drag on the moving fluid due to its viscous nature, wells mismanagement, improper perforation, over-sizing or under-sizingof production tubing etc. For these reasons, an artificial lift system installation is often considered during the development of a well or field. Even after the installation of this production aiding system, the issue of excessive pressure drop and deviation in rate values of actual production from anticipated production is not totally solved. This is due to the fact that production related problems such as: rate allocation problem of lift gas, corrosion handling ability, temperature limitation, well depth, production rates, flexibility of the installation, space, high GOR etc. still exist as a result of flow movement from the bottom of the well bore to the surface.

Hence, the need to carry a sensitivity analysis on some of these factors affecting production in order to properly optimize oil production from wells that require gas lifting.


1.3       Aim and Objectives of Study

The ultimate aim of this study is to formulate measures/means to properly maximize production (profitability) from a gas-lifted field in a safe and cost-effective manner as compared to natural flowing wells of a given field.

The objectives include:

1.      To use Production and System and Performance software (PROSPER) to optimize production from each of the gas-lifted wells in the field.

2.      To develop a gas lift performance curve for each well.

3.      And by extension, to also derive a lift gas performance curve for the entire field.


1.4       Methodology

The methodologies that will be employed in achieving the already stated objectives are presented as follows:

*         Literature review on the subject matter.

*         Collection of well and production data from a gas-lifted field in the Niger Delta.

*         Using Production and Systems Performance analysis software (PROSPER) to build a single well model from the available data.

*         Using PROSPER to optimize production from the entire field.


1.5       Relevance of Work

The aspect of research work on production optimization from developed structures cannot be over emphasized. It is no doubt that every operator in the oil and gas sector wants to make maximum profit from optimum production of oil via a cost-effective investment operation. Therefore, for a gas lifted well to be able to produce optimally, a thorough sensitive analysis on some of the existing problems affecting production optimization for a gas lifted system must be carried out. Hence, this research work is relevant in the following areas:

1.      To maximize well production rate.

2.      To increase the producing life of an oil well through proper gas lift management operations.

3.      To solve some of the lingering production problems affecting the smooth operations of a gas lift installation.

4.      To enhance production of highly viscous crude accumulated at the well bore vicinity.


1.6       Scope and Limitation of Work

This research work is basically carried out to optimize oil production from gaslifted wells via the installation of gaslift system. Data from XT field, a field in the Niger Delta will be used as a case study. PROSPER software will be used to design the well models. To fully optimize the XT field production system, sensitivity analysis will be performed to ascertain the effect of changing the tubing, water cut, surface choke, sub-surface safety valve sizing, skin and Gas-Oil Ratio (GOR) on the general well production system.

Gaslift design is a wide field, and a detailed description of the design process of a gas lift system is beyond the scope of this work.


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A Research proposal for assessment of safe and cost effective methods to maximize production (profitability) from a gas-lifted field:
Reviews: A Review on assessment of safe and cost effective methods to maximize production (profitability) from a gas-lifted field, assessment, safe, cost project topics,, project topic, list of project topics, research project topics, journals, books, Academic writer.
This research work is basically carried out to optimize oil production from gaslifted wells via the installation of gaslift system. Data from XT field, a field in the Niger Delta will be used as a case study. PROSPER software will be used to design the well models. To fully optimize the XT field production system, sensitivity analysis will be performed to ascertain the effect of changing the tubing, water cut, surface choke, sub-surface safety valve sizing, skin and Gas-Oil Ratio (GOR) on the general well production system... oil and gas/ petrochemical engineering project topics


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