Constant Pressure Boundary
The constant pressure boundary is sometimes used to match a late-time drop in the derivative data, as shown below.
Note that the changes in the derivative are due to the short initial production times and the derivative calculation algorithm (more information is available in the training video called Deconvolution).
The three marked PBU tests can be seen in the production history plot below.
In the following well test interpretation, a constant pressure boundary was placed at 517 feet from the well.
By definition, the pressure at this boundary is a constant equal to the initial pressure. As a result, the simulated PBU data stabilizes to this constant pressure and the derivative falls to 0, creating a drop in the log-log plot.
The constant pressure boundary was often used in the past as a source for additional pressure support, in particular for the following cases:
the presence of a gas cap,
the presence of an aquifer with the mobility of the water much greater than that of the oil.
Now Obsolete !
There is no physical mechanism that would explain a static boundary remaining at initial reservoir pressure. The use of this immobile boundary is not plausible.
The constant pressure boundary is in fact an old solution that was developed using the obsolete method of images. This solution should no longer be used, but replaced by the linear composite model and a linear interface.
Linear composite model
The constant pressure boundary model should now be obsolete and replaced by the linear composite model, where the reservoir is divided into various regions of different mobility (kh/µ) and/or storativity (Φ Ct h) values.
The presence of a reservoir region with high fluid mobility (gas cap or aquifer) further away from the well drives the derivative downwards at late times (first statement in the derivative post or in the well test theory video). This sometimes gives the impression that the derivative falls. While a constant pressure boundary would have been used in the past, the modern well test analyst should use a linear composite model.
In this case, the oil reservoir, gas cap and aquifer are represented as three zones of the linear composite model with different values of total compressibility, viscosity and permeability. We consider the same reservoir fluid in all the regions of the model and represent the differences in fluid properties as heterogeneities.
A new vertical well Mu-12 was drilled and quickly cleaned up. After an initial PBU test, the well was put on production.
The figure below shows the pressure and rate data for the first month of production. There were several instances when the well was shut-in for short time periods. These flow interruptions provide some “opportunistic” PBUs and give an idea of reservoir pressure and the changes in effective permeability, in skin and even sometimes in fluid contacts.
The static and PVT data used in the analysis are as follows:
|Formation Volume Factor||1.3||rb/stb|