Deeply buried aquifers in the North German Basin with formation temperatures of up to 150°C
are investigated to develop stimulation methods to increase the permeability by enhancing or creating secondary
porosity and flow paths. The final goal is to test the generation of geothermal electricity from such
low-enthalpy reservoirs using a doublet of borehole, one to produce deep natural water and
the other to re-inject the utilized water. For these purposes, an in-situ downhole laboratory was
established in Groß Schönebeck, north of Berlin, Germany.
This article describes the challenges and experiences of drilling the geothermal research well into a
deep sedimentary geothermal reservoir. The lessons learnt covers drilling large diameter in sheet silicate bearing
rocks, directional drilling through and beneath salty formations, and various mud concepts with the goal
of minimized formation damage.
At present, two 4.3 km deep boreholes have been drilled. The first well GrSk 3/90, originally completed
in 1990 as a gas exploration well and abandoned due to non-productivity, was re-opened in 2000
and was hydraulically stimulated in several treatments between 2002 and 2005. In 2006, the second well
GrSk 4/05, planned for extraction of thermal waters, was drilled in order to realize a doublet system with two
hydraulically connected boreholes. It is planned to stimulate in the second well both, the Lower Permian
sandstones and the underlying volcanic rock. The resulting engineered reservoir should have an increased productivity
being operated with minimized auxiliary energy to drive the thermal water loop and should have a minimized
risk of a temperature short circuit of the system during a planned 30-year utilization period.
The forthcoming phase is designed to demonstrate sustainable hot water production from the reservoir between
the two wells through a long-term circulation experiment.
The new well GrSk 4/05 is located at the same drill site as GrSk 3/90, the surface distance of both
wells is about 27 m. Drilling operation begun in April 2006 and were finished in January 2007 at 4400 m depth.
The design and drilling of the second well considered the following issues (1) to (3):
(1) the deep static water table of the reservoir and the respective withdrawal during production (housing
for the submersible pump), which requires a large hole diameter,
(2) the distance between the two wells of the doublet in the target horizon and the opportunities
of increasing the inflow conditions by an inclined well and later by implementation of multiple fracs,
by using the directional drilling techniques, and
(3) a drilling mud concept, which avoids formation damage of the reservoir as much as possible.
The following chapters focus on the encountered drilling experiences ranging from circulation loss during cementation
via collapsing of casings within Upper Permian evaporites up to the occurrence of acid gas indications.
Finally the entry into the reservoir is described.
The drilling started with the large hole diameter (23”) with difficulties in clay dominated depth sections.
Therefore, sufficient pumping capabilities beyond 4000 l/min were required. A complete casing cementation was necessary,
because during hot water production thermally induced stress might cause casing damage on the non-cemented pipes.
A total fluid loss and uncontrolled hydrofracturing occurred during the bottom up cementation of the combined
16“ x 13 3/8“ casing, performed with a mean slurry density of 1450 kg/m³. Therefore, squeeze cementation was performed
from top of the well to the former cement infiltration zone. The successful placement of the cement
was controlled by thermal logging.
After drilling 1600 m thick Upper Permian evaporates counterbalanced with a mud density of 2000 kg/m³,
a the 9 5/8“ liner was installed which - despite of a strength with a safety factor of 1.8 - collapsed
in the bottom region after reduction of the mud density back to 1060 kg/m³. Presumably,
additional stress components from anisotropic stress by the well inclination of about 20° in connection
with temperature induced high ductile rocksalt (temperatures of 110°C in 3800 m depth) caused this failure.
Stress concentration in interbedded anhydritic layers might have increased anisotropic stresses. The collapsed 9 5/8“ liner
was replaced with a combined 7“x 7 5/8“ liner after sidetracking. The latter caused further challenges as the
setting of the mechanical anchor of the whipstock required a modification of the anchor for a reliable
operation in mud with 40% baryte content. Furthermore, the borehole design needed to be adjusted due to the loss of one casing dimension.
Therefore, the borehole was deepened with 5 7/8“ diameter drilling into the geothermal reservoir of the Lower
In order to avoid induced permeability decreases through invaded drilling mud, this reservoir
below 3900 m was drilled with a near balanced mud density of 1030 kg/m³.
However, borehole wall breakouts at 3940 m forced a cleaning run and an elevation of mud pressure to 1100 kg/m³.
This specific mud pressure was provided by a geomechanical study that investigated the initiation of borehole
breakouts in the reservoir successions under low mud pressures.
Another reason for increasing the near-balanced mud weight was the occurrence of HC -gas with H2S - content
below the 7 5/8“ casing shoe (within fissured lowermost Upper Permian). To prevent this gas inflow,
the mud density had to be increased up to 1200 kg/m³.
We used a marble flour based mud (OptiBrigdeTM) to minimise fluid losses into the productive
sandstone formations of the target horizon. Due to the danger of differential sticking and formation
damage the mud weight was slightly decreased in the further drilling operations. Fluid losses were
not significantly observed during the rest of drilling and casing operations.
The well followed its foreseen path and target and a combined 5“ liner with a non-cemented
section of pre-perforated pipes at the bottom was installed in the lowermost section at 4400 m depth.
In the North East German Basin, 4000 m deep Lower Permian sandstones and volcanic rocks have been
explored for geothermal energy production. Within this context, the gained drilling experiences show
(1) that drilling a large hole diameter (23”) is feasible but challenging especially in clay dominated layers,
(2) that directional drilling can be applied as a standard operation, and
(3) that a variable mud concept needs be applied in order react to unforeseen operational requirements
such as formation damage, breakouts, or inflows. In this project, technical and scientific challenges were
successfully met and the lessons learnt provide essential know how for developing future drilling strategies
in deep sedimentary geothermal systems, especially in the Central European Basin System.