Obtain the data you need to make the most informed decisions by accessing our extensive portfolio of information, analytics, and expertise. Sign in to the product or service center of your choice.
How can gas lifted wells be evaluated in an easy and quickly
manner?
Gas lift is a traditional artificial lift system that helps oil
and gas wells lift fluids from the bottom of the well to the
surface when there is not enough energy to do this in a natural
manner.
In this type of production system, gas is typically injected
into the annular space at the lower part of the tubing string. This
results in a reduction of the flowing gradient in the production
string which leads to a drawdown (ΔP) increase on the production
formation while improving well production.
Typical tasks involving the evaluation of these wells are listed
here:
Calculation of inflow performance relationship (IPR) and
outflow (TPC, VLP or VFP) curves.
Analysis of reservoir and well changes during its producing
life. (e.g. reservoir pressure, skin, tubing and casing pressures,
flow regime, etc).
Evaluation of the compression process.
Analysis of gas liquid ratios.
Assessments of pressure traverse changes.
Estimation of the well potential.
Evaluating these types of wells is not always an easy task for
production engineers because injecting too much gas can add
friction that could end up in an increment of the back pressure
inside the well. This leads to a waste of money on compression
costs. On the other hand, injecting too little gas can leave
valuable production behind if the lower gas lift valves are not
opened.
Fortunately, the PERFORM software from IHS
Markit is very useful for these types of analyses, since it can
model well performance using the nodal analysis technique and has
several built-in tools to sensitize production and reservoir
parameters. In this post, the author will discuss some graphs to
consider for fast and reliable gas lift analyzes.
Nodal Analysis
The easiest way to start evaluating these wells is through the
analysis of the flowing bottomhole pressure and their corresponding
rates. This can be achieved by applying the nodal analysis
technique in the bottom of the well at the current - or last known
- operating conditions.
The resulting IPR (Inflow Performance Relationship) curve will
help you understand the current maximum rate the reservoir can
deliver to the well. A well capable of producing fluids will
exhibit intersecting outflow and IPR curves. In contrast, a missing
intersection between these curves will indicate the differential
pressure required to lift the fluids to the surface, sometimes
referred to in the field as "lack of energy". Figure 1 shows this
type of analysis.
Figure 1: Nodal analysis in an oil well that requires
artificial lift
At this point, it is beneficial to evaluate and propose
different forms of artificial lift (i.e., Gas lift, ESP's, PCP's,
Plungers, Sucker Rod Pumps, Jet Pumps). The typical proposal
includes a design of the artificial system customized to the well
conditions and describes how the "new well" would operate. After
this, the installation of the artificial system proceeds.
With Gas Lift already selected as a suitable form of artificial
lift and valves installed at the most convenient depths, a
comparison of hypothetical injection gas rate scenarios and the
original well condition - at any time - becomes very valuable to
determine the impact on the production rate. Figure 2 shows an
example of the expected rates under five (5) assumed injection rate
scenarios. Being ~1,200 BPD the result of injecting 3 MMscfd on
this well.
Figure 2: Nodal Analysis applying hypothetical gas lift
injection rates
Once this information is known, injection rates and production
rates can be plotted (Figure 3). This is a very useful graph since
its main objective is to help identify the maximum rate, the
technical optimum injection rate, and the economic optimum
injection rate (the injection rate where extra injection costs
balance extra production revenue).
Because the gas lift has a small window to operate efficiently,
injecting more gas at some point may end up in a lower production
rate; this behavior is typically observed after reaching the
maximum technical rate. The reason behind this is the increment in
friction due to a greater volume flowing in the tubing which is
faster than the counterbalanced reduction in the hydrostatic term
in the pressure loss calculation.
Figure 3: Analysis of Gas injection rates
Alternatively, the resulting gas liquid ratio calculated from
each hypothetical injection rate scenario can be plotted against
the production rate. As expected, Figure 4 shows a maximum
production rate of ~1200 BPD.
Figure 4: Gas liquid ratio analysis
Often, reservoir parameters change due to stimulations,
fracking, skin, etc. These changes will affect the IPR curve.
Therefore, the maximum rate (AOF) originally calculated in Figure 1
will also be modified.
Figure 5 shows five (5) scenarios in flowing pressures affected
by reservoir performance assumptions and five (5) hypothetical
injection rates. The outcome is a nodal analysis with a total of
twenty-five (25) potential production rates.
Figure 5: Expected rates of reservoir changes with different
injection rates
A less traditional graph showing the same twenty-five (25)
potential outcomes is shown in Figure 6. In this graph, it can be
observed that the optimum gas injection rate remains the same for
most of the proposed scenarios despite the loss in productivity due
to reservoir changes. Any increment on the injection rate after the
maximum technical rate will attempt to decrease the production rate
due to friction effects in the well.
Figure 6: Production rates analysis
Sensitivities can also be done in the tubing diameter to
understand how much the well would produce if these changes occur
in the future. Figure 7 shows differences in these production rates
at a specified injection rate. As it can be seen, the production
increases rapidly as the tubing OD increases from 2 ⅜" to 3 ½".
Figure 7: Effect of changing the tubing size
Lastly, selecting an appropriate multiphase flow correlation in
the modeling of these cases is critical. A correlation for a gas
lifted well may be different from that one previously selected to
describe the same well performance when it was producing under
natural flow conditions. Figure 8 shows how the use of an improper
correlation can lead to an incorrect prediction of the well
production rate at a specified injection rate.
Figure 8: Effect of multiphase flow correlations
In conclusion, due to the dynamic nature of gas lifted wells, a
robust and reliable model that represents all the above discussed
variables is always valuable, as this will play a critical role in
the field optimization process.
