EFFECT OF GAS-OIL-RATIO ON OIL PRODUCTION
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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.
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
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.
EFFECT OF GAS-OIL-RATIO ON OIL PRODUCTION
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