Page 236 - Geothermal Energy Systems Exploration, Development, and Utilization

212 4 Enhancing Geothermal Reservoirs
properties during the treatment and prevented a better result of the stimulation
treatments.
To determine the hydraulic parameters of the stimulated reservoir in more detail
and to obtain stable conditions over a longer period, a long-term pumping test
was performed in summer 2002 (Zimmermann, 2004; Reinicke et al., 2005). A
downhole pump was installed at 330 m depth (the water level is in equilibrium at
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250 m). The flow rate was set to approximately 1 m h −1 over a period of 37 days. In
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total, 580 m formation fluids were extracted during this test, which is equivalent
to approximately five borehole volumes. The draw down reached a constant level
after 10 days, but steady state conditions were not reached until the end of the test.
The productivity-index was estimated at pseudo steady state conditions to 0.6 m 3
−1
(h MPa) .
Transmissibility of the productive formations was estimated from pressure build
up toward the end of the shut-in to assure pseudo radial flow conditions and
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was calculated to 3.1 × 10 −14 m . The minimum extension of the reservoir was
calculated from maximum radius of investigation to R = 617 m (assuming total
height of reservoir = 100 m; porosity = 0.05; fluid viscosity = 4 × 10 −4 Pa s; total
−1
compressibility = 5 × 10 −10 1Pa ) (e.g., Carslaw and Jaeger, 1959; Lee, 1981).
Another parameter to improve the results of reservoir stimulation is the total
volume of injected frac fluid in a forthcoming experiment. Therefore, it was
intended to continue the stimulation experiments with a procedure injecting at
least two orders of magnitude higher volume into the reservoir.

4.10.1.4 Hydraulic fracturing in Volcanics (Waterfrac Stimulation)
The first waterfrac treatment started in January 2003 with a moderate injection test
3
with a flow rate of 3.6 m h −1 over a period of 200 hours. The aim of this pretest was
to obtain initial injection properties of the reservoir and to compare these results
with the former short-term and long-term production tests carried out in spring and
summer 2002. After 48 hours the injectivity index (ratio of injection flow rate and
3
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differential pressure) was 1.15 m (h MPa) −1 and decreased to 0.83 m (h MPa) −1
at the end of the test after 200 hours (Tischner, 2004). The observed injectivity
corresponds to the productivity derived in former production tests at similar low
differential pressure. For this reason it can be assumed that the hydraulic response
of the reservoir is similar for production and injection for a pressure change up to
10 MPa (decreasing for injection as well as increasing for production).
Thereafter, the first waterfrac treatment was performed in whose progression a
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total amount of 4284 m fluid was injected under high pressure into the reservoir.
In the first part, a pressure step test with gradually increasing injection rates up
to 24 l s −1 was performed. The results show that starting with an injection rate
of 8 l s −1 the pressure increase is reduced due to an enhanced injectivity of the
formation. This effect can be interpreted as a mechanical reaction of the rock
due to an opening of the generated artificial fractures as well as the extension of
pre-existing fracture in the conglomerates and volcanic rocks at the bottom of the
well (Huenges et al., 2006).