Page 250 - Hydrocarbon Exploration and Production Second Edition

Well Dynamic Behaviour 237

or both. The distortion of the fluid interface near the horizontal well is referred to as
cresting rather than coning, due to the shape of the interface. Figure 10.8 shows a
schematic view of gas cresting from an overlying gas cap in an oil reservoir.

10.4. Production Testing and Bottom Hole Pressure
Testing

Routine production tests are performed, ideally at least once per month on
each producing well, by diverting the production through the test separator
on surface to measure the liquid flowrate, water cut and gas production rate. The
tubing head pressure (also called the FTHP) is recorded at the time of the
production test, and a plot of production rate against FTHP is made. The FTHP is
also recorded at least once per day and used to estimate the well’s production rate on
a daily basis by reference to the FTHP vs. production rate plot for the well.
It is important to know how much each well produces or injects in order to
identify productivity or injectivity changes in the wells, the cause of which may then be
investigated. For example, the well might be scaling up. Also, for reservoir management
purposes (Chapter 14) it is necessary to understand the distribution of volumes of fluids
produced from and injected into the field. This data is input to the reservoir simulation
model, and is used to check whether the actual performance agrees with the
prediction, and to update the historical data in the model. Where actual and predicted
results do not agree, an explanation is sought, and may lead to an adjustment of the
model (e.g. re-defining pressure boundaries, or volumes of fluid in place).
The production testing through the surface separator gathers information at
surface. Another important set of information collected during bottom hole pressure
testing is downhole pressure data, which is used to determine the reservoir properties
such as permeability and skin. In a production well, which will have been completed
with production tubing, the downhole pressure measurement is typically taken by
running a pressure gauge, on wireline (either electric line or with memory gauges
by slickline), to the depth of the reservoir interval. The downhole pressure gauge is
then able to record the pressure whilst the well is flowing or when the well is shut-in.
A static bottom hole pressure survey (SBHP) is useful for determining the reservoir
pressure near the well, undisturbed by the effects of production. This often cannot
be achieved by simply correcting a surface pressure measurement, because the
tubing contents may be unknown, or the tubing contains a compressible fluid
whose density varies with pressure (which itself has an unknown profile).
A flowing bottom hole pressure survey (FBHP) is useful in determining the pressure
drawdown in a well (the difference between the average reservoir pressure and the
FBHP, P wf ) from which the PI is calculated. By measuring the FBHP with time for
a constant production rate, it is possible to determine the parameters of permeability
and skin, and possibly the presence of a nearby fault, by using the radial inflow
equation introduced in Section 10.2. Also, by measuring the response of the bottom
hole pressure against time when the well is then shut-in, these parameters can be
calculated (Figure 10.9).