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.

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 t



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