ABSTRACT
Maximum production from an oil well can be achieved through proper selection of tubing size. The selection of optimum tubing size must be evaluated when completing a well in any type of reservoir especially solution gas drive reservoir since there is likelihood of producing more gas as the reservoir pressure declines. The most widely used methods such as Tarner, Muskat and Tracy methods for predicting the performance of a solution gas drive reservoir were discussed and used to estimate the behaviour of producing GOR. A comparison was made between the results from each method. System analysis approach was adopted for this study. The future IPR curves were determined by a combination of Vogel and Fetkovich correlation. Beggs and Brill multiphase spreadsheet was used to produce the TPR curves by estimating flowing bottomhole pressure for several tubing size using the predicted GOR produced and a range of flowrates. The effect of water production was also considered in this study. The results showed that for IPR5 as GOR increased from 1052 to 1453 scf/stb, oil production rate for 2 7/8-in increased by 17.6% and 3.3% for a further increase in GOR at 2610 scf/stb. At a GOR of 2610 scf/stb oil production decreased by 3.17% at water-cut of 5% and 9.5% at water-cut of 25%. All things being equal, the percentage reduction in production reduces as GOR increases from 2610 to 5635 scf/stb for all the tubing sizes used.
CHAPTER 1
INTRODUCTION
Production optimization identifies the opportunities to increase production and reduce operating costs. The overall goal is to achieve the optimum profitability from the well. To achieve and maintain this, it is essential to evaluate and monitor different sections of the production system including, the wellbore sandface, reservoir, produced fluids, production equipment on surface and downhole. Several methods are being used for production optimization. The most common and widely used method is the system analysis approach commonly known as nodal analysis.
Optimization of the wellbore is considered mainly during well completion stages. Tubing joints vary in length from 18 to 35 feet although the average tubing joint is approximately 30 feet. Tubing is available in a range of outer diameter sizes. The most common sizes are 2 3/8-in, 2 7/8-in, 3 1/2-in and 4 1/2-in. The API defines tubing as pipe from 1-in to 4 1/2-in OD. Larger diameter tubulars (4 1/2-in to 20-in) are being termed casing. (Schlumberger, 2001)
The flow rate per well is the key parameter. It governs the number of wells that need to be drilled to achieve the optimum economic output of the field. The first parameter that needs to be considered in the tubing string selection is the nominal tubing diameter. The grades of steel and nominal weight are chosen based on the stress the tubing will have to withstand during production. Thirdly, depending on the how corrosive the existing and future effluents, the type of connection and the metallurgy are selected. In fact the different stages mentioned above overlap and sometimes make the choice of tubing a difficult job. In the determination of the nominal pipe diameter, the nominal diameter through the weight governs the inside through diameter of the pipe. The flows that can pass through it depend on the acceptable pressure losses but are also limited by two parameters: the maximum flow rate corresponding to the erosion velocity and the minimum flow rate necessary to achieve lifting of water or condensate. Tubings with diameter less than 2 7/8-in are mostly reserved for operations on well using concentric pipe and are termed macronic string. Note also that the space required by couplings of the tubing limits the nominal tubing diameter that can be run into the production casing. (Perrin, et al., 1999).
1.1 Vertical Lift Problems relating to tubing
In lieu of the usefulness of tubing strings in oil and gas production, it can have some limitations. Tubing wear occurs most often in pumping wells. It depends little upon whether the hole is vertical or slanting, but it is much worse in dog-legged holes regardless of the deviation. It may either be external or internal. If external, it is usually the couplings which are affected and the cause is the rubbing against the inside of the casing in phase with the reversing strokes of the sucker rods. If the wear is internal, it is caused by the sucker rods. There can be leakage from the inside to the outside or vice versa. This can be attributed to the API thread shape used (the V-shaped or round thread shape.) The tubing string can be flattened from wall to wall by either having a higher hydrostatic pressure or as a result of diastrophic shifting of formation caused by an earthquake. Since some 90 percent of all oil-well tubing is upset design, practically all failures are in the body of the pipe. However, any tension failures are rare because tubing is almost always run inside of casing and except for occasional trouble of unseating packers; it seldom becomes stuck and therefore needs not be pulled on. As with upset casing, upset tubing will stretch before failing. The tubing will burst when the pressure inside the tubing string is higher than the pressure in that annulus. This tubing trouble is commonly seen in high pressure wells and can be exceeding serious. (Hexter, 1955)
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