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Candidate Evaluation
Evaluation of candidate wells for dual rod pump
gravity separation (DPGS) is very much an iterative process.
Firstly, water cuts at target production rates based on accurate
in-flow performance relationships (IPR) must be determined. Target
production may be such as to draw the well down, or something
less due to other considerations such as sand production, bubble
point pressures, water coning, etc.
Next, pump sizing for each of the top and bottom pumps must be
determined. This is again based on target production and expected
water cuts but wellbore tubulars obviously come into consideration.
It is recommended to still keep the water cut to surface in the
50% range. This allows for a higher confidence level that oil
is not being carried over to the disposal zone. Estimate pump
efficiencies based on field experience, landing depths, and fluid
properties. Note that it is wise to do a sensitivity analysis
to see how pump efficiencies affect water cuts to surface and
at what point oil will begin to be carried over.
Injection zone information is critical to do a proper evaluation.
Reservoir pressure and an injectivity index are required and ideally
from a step rate injection test on the candidate well, or in practicality,
from offset disposal wells. Note that injectivity index should
be calculated based on peak DPGS system injection rates not the
higher rates usually associated with disposal wells. Some interpolation
is possible given higher rate tests but it is just that - interpolation.
It is important to note that just because a zone "takes water"
doesn't necessarily mean it is a good candidate for DPGS. Remember
that that "good" zone has many meters of hydrostatic
head on it which the DPGS disposal pump does not have the benefit
of. Disposal zone injectivity is critical to rod and jack sizing
and loading so the more accurate the data the better. Some other
issues to consider are near future increases or decreases in injectivity
index due to dynamic reservoir or fluid properties, plus oil,
sand, and scale plugging and the effects of dissimilar waters.
Separation chamber size is determined by size of available tubulars,
distance between producing and disposal perforations, and the
length of the bottom pump.
Final inputs for the evaluation process are a reasonable stroke
length and rate for the available or planned lifting equipment.
Outputs of the evaluation process are firstly water disposal rates
and oil and water cuts to surface. Residence time in the separation
chamber is calculated. A conservative rule of thumb so far has
been 5x a desk top separation time. This is simply the time it
takes for a wellhead fluid cut to separate out to less than 300
ppm oil in a simple test bottle. This ensures a good amount of
time in the separation chamber for oil droplets to coalesce to
the point that they have a net upward velocity relative to the
downward water flow. Ideally this test would be done in a bath
at bottom hole temperature. It is also desirable to keep velocities
in the separation chamber below 1 ft/s. This ensures that an emulsion
will not be formed and again enhances oil droplet coalescence.
Minimum oil droplet size required for upward movement can also
be calculated from Stokes' law. Typically, it has been found that
minimum droplet size requirements are in the 0.010" range.
Research shows that mm sized droplets only occur at very high
flow rates and pressure gradients(12). Also, some basic assumptions
about wellbore in-flow have already been presented and field results
in heavy oil applications support these assumptions(13).
More advanced mathematical models in conjunction with continuing
field data will be able to refine this technique.
Since rod and jack loading is always a major consideration in
rod pumping system design, the DPGS evaluation process also includes
a determination of pump loads which can then be converted into
a simple input to any commercially available rod design software
program. Since we are dealing with two pumps, the crux of the
procedure is to provide a single pump bore size that accounts
for both pumps. This involves determining and converting the intake
and discharge pressures of the water injection pump into an effective
pump bore given the intake pressure and discharge fluid gradient
of the oil concentrate pump.
Figure 3 shows a spreadsheet
developed for the entire above evaluation process.
This is all an iterative process because pump and jack loading
may necessitate the change of pump sizing and/or stroke rate length
which obviously in turn changes water cuts, fluid gradients, and
intake pressures, along with injection rates and pressures.
The final phase of the evaluation process is a sensitivity analysis
to put limits on injectivity based on maximum rod and jack loading.
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