THE COMPLETION TEST
The completion test is designed to identify potential feed points (fluid entries, aquifers) in
the well to get an estimate of the total effective permeability of the well.
In liquid dominated reservoirs the completion test is done by injecting cold water.
Any test program is normally designed to collect as much data as possible in the available
time. This means making few changes as possible in the cold water pump (injection) rate
in order to minimize any movement of temperature front in the wellbore.
Two basic measurements are taken during pumping:
1. Water loss: The points at which fluid is lost from or gained by the well are
determined from temperature or flow profiles obtained during injection at a steady
state.
2. Permeability: This is obtained by analyzing the pressure transient after a change
in flow rate. The stable change in pressure after each change in flow rate gives the
injectivity-the simplest crude gauge of the total permeability.
WATER LOSS TESTS
In a successful water loss test the temperature profile established in the well during
injection locates the permeable horizon(s).
Figure 1 gives the temperature profiles and the corresponding well pressure profiles that
may be observed in a water loss test.
Figure 1. Temperature and pressure profiles in a water loss test.
Profile A: A gradual rise is observed as the water moves down through the upper section
of the well. This warming is caused by the inward conduction of heat from the
surrounding formation. Below the region of slow warming, a depth is reached at which
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the temperature increases sharply. This can only indicate that cold water is not getting
into the section of the well below this level. Although it does not guarantee that there is
no permeability at deeper levels or that there are no partial losses, this test does identify
the deepest loss zone.
Profile B: This type of profile occurs when there is a partial loss at an upper zone. As
water flows out of the well at the upper zone, the flow of water down the well decreases
at this depth. Beneath this zone the smaller flow of water down the well means that the
conductive flow of heat into the wellbore causes a faster rise in temperature. The break in
gradient corresponds to a decrease in the amount of flow down the well.
Profile C: It shows the temperatures at which water flows into the well at an upper zone.
The step change in temperature identifies an inflow.
Example: A multiple feed/loss zone well, with the potential for inflow from the formation
at some level and for outflow at another. These tests were carried out in well KA17,
Kawerau-New Zealand and the profiles for four tests are displayed in Figure 2. In three of
these (T-2, T-13 and T-17) the well was about 1000 m deep. The fourth (T-18) was
carried out after the well was deepened to 1400 m, and the 650 m feed cemented off.
Figure 2. Injection profiles in well KA17, Kawerau-New Zealand.
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To understand what happens in this case, we look first at the typical well and reservoir
pressure profiles (Figure 3). Assume that there are two high-permeability zones in the
reservoir at depths A and B. In a liquid-dominated reservoir the pressure gradient is near
hot water hydrostatic, in the well the pressure are hydrostatic for the water conditions that
exist in the well (cold or hot). Immediately after drilling, during injection and warmingup, these well waters would be cold. The pressure curves would thus be something like
those illustrated.
In the cold well, zero injection case, the two curves must cross somewhere between the
two-high permeability zones. At the upper level, A, the reservoir pressure is higher than
that of wellbore, therefore a quantity of fluid, W1 (kg/s), move into the well. At the lower
level, since the reservoir pressure is lower than wellbore pressure W1 will move out.
Now consider that there is a fluid injection into the well, the wellbore pressures at two
permeable levels should increase, as a result the crossover point of the pressure curves
will thus go up. Since the pressure difference at the upper level decreases W1 will
decrease. On the other hand, the pressure difference at the lower level will increase, while
the amount of fluid leaving the wellbore will become W+W1, where W is the injection
rate. It is obvious that with sufficient injection rate, the upper inflow could thus be shutoff or even converted to an outflow (loss zone).
Figure 3. Typical pressure profiles during injection.
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Let us now look at the measurements made in KA17 (Figure 2).

T-2, T-13 and T-17: Permeability at two levels, 650 m and 950 m.

T-18: Permeability at two levels, 950 m and 1390 m.

In each case there is a flow into the well at the upper level and out at the lower.
A comparison of the measurements in this well is particularly interesting since a single
change in the conditions corresponds to each pair of measurements:
1. T-13 and T-17, change in injection rate: At the higher injection rate (run T-13) the
temperature step at the upper permeable zone has disappeared and there is only a
change in gradient. This indicates that at the higher injection rate the pressures are
high enough at 650 m to stop the upper inflow.
2. T-13 and T-2, same injection rate at different times: The difference between the
runs lies in the reservoir pressure. In 1967 there was no local drawdown. The
1973 run was carried out after a long period of discharge.
3. T-17 and T-18, tests carried out before and after the well was deepened: We see
that deepening has resulted in the tapping of a deeper permeable zone. The
pressure readjustments has meant that this lower zone is now the main outflow,
and the 950 m zone has become an inflow in this test.
INTERPRETATION OF FLOW PROFILES
Detailed flowmeter measurements can give, for each fluid, an accurate location and
amount of loss or gain to the well. To interpret these in terms of the ability of each zone
to accept or produce fluid requires consideration of the pressure difference between the
reservoir and the well in each state. The most convenient measure of this ability is the
injectivity or productivity of each zone,
W   I(Pi  Pwfi )
Where;
W = Mass flow rate, kg/s
I = Injectivity, kg/s/bar
Pi = Reservoir pressure, bar
Pwfi = Downhole pressure at test depth, bar
To determine the injectivity of a zone one needs to know the reservoir pressure at test
depth (not the stable downhole pressure). Alternatively, with measurements at two
different rates, different inflows and outflows can be measured. The injectivity, I can then
be determined from the change in flow divided by the change in pressure measured in the
well at each flow rate.
I
ΔW
ΔP
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Example: The temperature profiles of two tests in Well NG4 (Ngawha, New Zealand) are
plotted in Figure 4. Flow rates and temperatures were measured throughout the open
section of the hole during these tests. Pressures were calculated from measured pressure
profiles and pressure measurements at 1200 m depth.
Figure 4. Injection temperature and flow profiles in well NG4, Ngawha-New Zealand.
The results indicate two primary permeable zones, the upper one at 740 m and the lower
at 1220 m. Since the pressure at the lower region remained at 11.12 MPa throughout, we
must identify this level with a zone of very high permeability and this pressure with the
pressure at of the reservoir at that level.
In the static well (No injection):
2.7 kg/s entered the well at 740 m
Pressure at 740 m = Pressure at 1220 m – Head of water column between 1220
and 740 m (480 m)
Temperature of water = 230 °C
Density of water at 230 °C = 0.827 kg/dm3
P740 m = 11.12 MPa – 827 kg/m3  480 m  1/1002 m2/cm2 × 9.81E-2 MPa/kg/cm2
P740m = 11.12 – 3.89 = 7.23 MPa
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During injection:
Flow at 740 m is 17 kg/s
But the pressure at this level dropped to 6.85 MPa because of the cooler fluid in
the column between 740 m and 1220 m.
From two tests:
2.7 = (P1i – 7.23) I1
and
17 = (P1i – 6.85) I1
Where P1i is the pressure at 740 m and I1 is the productivity of the feed.
Results:
P1i = 7.29 MPa
and
I1 = 38.6 kg/MPa-s
P2i = 11.12 MPa
and
I2 >> I1
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