scholarly journals 3-D geomechanical modelling of a gas reservoir in the North German Basin: workflow for model building and calibration

2013 ◽  
Vol 5 (1) ◽  
pp. 767-788 ◽  
Author(s):  
K. Fischer ◽  
A. Henk
Keyword(s):  
Stress Field ◽  
Fractured Reservoirs ◽  
Wellbore Stability ◽  
Fe Model ◽  
North German Basin ◽  
Gas Reservoir ◽  
The North ◽  
In Situ Stresses ◽  
German Basin

Abstract. The optimal use of conventional and unconventional hydrocarbon reservoirs depends, amongst others, on the local tectonic stress field. For example, wellbore stability, orientation of hydraulically induced fractures and – especially in fractured reservoirs – permeability anisotropies are controlled by the recent in situ stresses. Faults and lithological changes can lead to stress perturbations and produce local stresses that can significantly deviate from the regional stress field. Geomechanical reservoir models aim for a robust, ideally "pre-drilling" prediction of the local variations in stress magnitude and orientation. This requires a~numerical modelling approach that is capable to incorporate the specific geometry and mechanical properties of the subsurface reservoir. The workflow presented in this paper can be used to build 3-D geomechanical models based on the Finite Element Method (FEM) and ranging from field-scale models to smaller, detailed submodels of individual fault blocks. The approach is successfully applied to an intensively faulted gas reservoir in the North German Basin. The in situ stresses predicted by the geomechanical FE model were calibrated against stress data actually observed, e.g. borehole breakouts and extended leak-off tests. Such a validated model can provide insights into the stress perturbations in the inter-well space and undrilled parts of the reservoir. In addition, the tendency of the existing fault network to slip or dilate in the present-day stress regime can be addressed.

scholarly journals A workflow for building and calibrating 3-D geomechanical models &ndash a case study for a gas reservoir in the North German Basin

Solid Earth ◽  
2013 ◽  
Vol 4 (2) ◽  
pp. 347-355 ◽  
Author(s):  
K. Fischer ◽  
A. Henk
Keyword(s):  
Stress Field ◽  
Fractured Reservoirs ◽  
Wellbore Stability ◽  
Fe Model ◽  
North German Basin ◽  
Gas Reservoir ◽  
The North ◽  
In Situ Stresses ◽  
German Basin

Abstract. The optimal use of conventional and unconventional hydrocarbon reservoirs depends, amongst other things, on the local tectonic stress field. For example, wellbore stability, orientation of hydraulically induced fractures and – especially in fractured reservoirs – permeability anisotropies are controlled by the present-day in situ stresses. Faults and lithological changes can lead to stress perturbations and produce local stresses that can significantly deviate from the regional stress field. Geomechanical reservoir models aim for a robust, ideally "pre-drilling" prediction of the local variations in stress magnitude and orientation. This requires a numerical modelling approach that is capable to incorporate the specific geometry and mechanical properties of the subsurface reservoir. The workflow presented in this paper can be used to build 3-D geomechanical models based on the finite element (FE) method and ranging from field-scale models to smaller, detailed submodels of individual fault blocks. The approach is successfully applied to an intensively faulted gas reservoir in the North German Basin. The in situ stresses predicted by the geomechanical FE model were calibrated against stress data actually observed, e.g. borehole breakouts and extended leak-off tests. Such a validated model can provide insights into the stress perturbations in the inter-well space and undrilled parts of the reservoir. In addition, the tendency of the existing fault network to slip or dilate in the present-day stress regime can be addressed.

Seismic tomographic interpretation of Paleozoic sedimentary sequences in the southeastern North Sea

Geophysics ◽  
2005 ◽  
Vol 70 (4) ◽  
pp. R45-R56 ◽  
Author(s):  
Lars Nielsen ◽  
Hans Thybo ◽  
Martin Glendrup
Keyword(s):  
North Sea ◽  
Velocity Structure ◽  
Seismic Velocity ◽  
P Wave ◽  
Wide Angle ◽  
North German Basin ◽  
Sedimentary Sequences ◽  
The North ◽  
Crystalline Crust ◽  
German Basin

Seismic wide-angle data were recorded to more than 300-km offset from powerful airgun sources during the MONA LISA experiments in 1993 and 1995 to determine the seismic-velocity structure of the crust and uppermost mantle along three lines in the southeastern North Sea with a total length of 850 km. We use the first arrivals observed out to an offset of 90 km to obtain high-resolution models of the velocity structure of the sedimentary layers and the upper part of the crystalline crust. Seismic tomographic traveltime inversion reveals 2–8-km-thick Paleozoic sedimentary sequences with P-wave velocities of 4.5–5.2 km/s. These sedimentary rocks are situated below a Mesozoic-Cenozoic sequence with variable thickness: ∼2–3 km on the basement highs, ∼2–4 km in the Horn Graben and the North German Basin, and ∼6–7 km in the Central Graben. The thicknesses of the Paleozoic sedimentary sequences are ∼3–5 km in the Central Graben, more than 4 km in the Horn Graben, up to ∼4 km on the basement highs, and up to 8 km in the North German Basin. The Paleozoic strata are clearly separated from the shallower and younger sequences with velocities of ∼1.8–3.8 km/s and the deeper crystalline crust with velocities of more than 5.8–6.0 km/s in the tomographic P-wave velocity model. Resolution tests show that the existence of the Paleozoic sediments is well constrained by the data. Hence, our wide-angle seismic models document the presence of Paleozoic sediments throughout the southeastern North Sea, both in the graben structures and in deep basins on the basement highs.

Predicting Hydraulic Fracturing in a Carbonate Gas Reservoir in Abu Dhabi Using 1D Mechanical Earth Model: Uncertainty and Constraints

2015 ◽  
Author(s):  
Manhal Sirat ◽  
Mujahed Ahmed ◽  
Xing Zhang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Natural Fracture ◽  
Abu Dhabi ◽  
Hydraulic Fractures ◽  
Gas Reservoir ◽  
In Situ Stresses ◽  
Tight Carbonate ◽  
Different Depths

Abstract In-situ stress state plays an important role in controlling fracture growth and containment in hydraulic fracturing managements. It is evident that the mechanical properties, existing stress regime and the natural fracture network of its reservoir rocks and the surrounding formations mainly control the geometry, size and containments of produced hydraulic fractures. Furthermore, the three principal in situ stresses' axes swap directions and magnitudes at different depths giving rise to identifying different mechanical bedrocks with corresponding stress regimes at different depths. Hence predicting the hydro-fractures can be theoretically achieved once all the above data are available. This is particularly difficult in unconventional and tight carbonate reservoirs, where heterogeneity and highly stress variation, in terms of magnitude and orientation, are expected. To optimize the field development plan (FDP) of a tight carbonate gas reservoir in Abu Dhabi, 1D Mechanical Earth Models (MEMs), involving generating the three principal in-situ stresses' profiles and mechanical property characterization with depth, have been constructed for four vertical wells. The results reveal the swap of stress magnitudes at different mechanical layers, which controls the dimension and orientation of the produced hydro-fractures. Predicted containment of the Hydro-fractures within the specific zones is likely with inevitable high uncertainty when the stress contrast between Sv, SHmax with Shmin respectively as well as Young's modulus and Poisson's Ratio variations cannot be estimated accurately. The uncertainty associated with this analysis is mainly related to the lacking of the calibration of the stress profiles of the 1D MEMs with minifrac and/or XLOT data, and both mechanical and elastic properties with rock mechanic testing results. This study investigates the uncertainty in predicting hydraulic fracture containment due to lacking such calibration, which highlights that a complete suite of data, including calibration of 1D MEMs, is crucial in hydraulic fracture treatment.

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