Click to view article in PDF format.
Predicting Stress and Fracture Orientations with Geomechanical Reservoir Models - Lessons Learned from a Case Study*
A. Frischbutter1 and A. Henk2
Search and Discovery Article #40596 (2010)
Posted September 7, 2010
*Adapted from oral presentation at AAPG Convention, New Orleans, Louisiana, April 11-14, 2010
1Wintershall Holding AG, Rijswijk, Netherlands
2Albert‐Ludwigs‐Universitat Freiburg, Breisgau, Germany ([email protected])
This study evaluates the potential of geomechanical reservoir models for a prediction of tectonic stresses and fracture networks. Such pre-drilling knowledge is desired for a variety of tasks like borehole stability and planning of hydraulic fracs, among others. A comprehensive workflow is presented describing the various steps and data requirements to set up, run and calibrate a geomechanical model. Special focus is on integration of the modeling
work with a Petrel® project. The
modeling
concept is applied to a data set from the eastern Sirte Basin in Libya to assess its practical value. The reservoir geometry is constrained by 3D
seismic
, and stress and fracture data from three wells were used to check the model predictions.
Modeling
is carried out as a history match to mimic the increase in information during the exploration and appraisal stage. The case study shows that a robust prediction of the stress field, including
its local perturbations near faults, can be based primarily on the reservoir geometry. Fracture prediction is more complex and requires well data for calibration as the model has to use several poorly constrained parameters like the magnitude of the paleo-stresses to infer the fracture orientations
|
Tectonic stresses are relevant for hydrocarbon exploration and production for a variety of reasons. Paleo-stress fields were responsible, for example, for fracture formation and reactivation, whereas present-day tectonic stresses are of critical importance for borehole stability, orientation of hydraulically induced fractures, fluid flow anisotropies as well as the slip and dilation tendency of the existing faults and fractures, among others. Thus, a robust – ideally pre-drilling – prognosis of past and recent tectonic stresses in a reservoir is desired to optimize exploration and production, particularly of tight gas and fractured reservoirs.
Any reliable stress prognosis – either prior to the first exploration well or for the interwell space of a reservoir – is impeded by the fact that the orientation and magnitude of the stress field in reservoirs can be highly variable. Particularly near faults, within fault compartments and at lithological boundaries (e.g. salt structures) the local stress orientations, and hence the geometry and hydraulic properties of the fracture network can differ by up to 90° from the regional trend (e.g., Maerten et al., 2002; Yale, 2003). In such cases, inference of reservoir in-situ stress orientations and fracture geometries from regional-scale data compilations would inevitably lead to incorrect predictions. Any robust prognosis has to incorporate the specific reservoir geometry and the specific mechanical properties of the reservoir rocks. Regarding the complexity of real reservoirs, such a prediction can only be provided by a numerical
The goal of the present study is to demonstrate the potential of geomechanical reservoir models to predict tectonic stresses (past and recent) and the geometry of the natural fracture network.
Static vs. Dynamic Geomechanical Models
Two different modelling approaches have to be distinguished: static and dynamic. Static models are based on the present-day reservoir geometry and the present-day ambient stress field. Modelling results provide a quantitative basis to predict the recent stress distribution within the reservoir, particularly the local perturbations near faults (e.g., Maerten et al., 2002; Henk, 2005). The corresponding stress tensor data can then be used to calculate, for example, shear and normal stresses relative to the existing fault and fracture surfaces and infer the corresponding slip and dilation tendencies, respectively. In contrast, fracture formation and possible reactivation typically took place under stress conditions which were different from the present-day situation. Therefore, dynamic models have to account for the tectonic evolution of the reservoir and temporal changes in regional stress fields and/or reservoir geometry have to be incorporated. If the reservoir geometry has been modified substantially, the tectonic evolution can be divided into several modelling stages with different model geometries. In such cases, past reservoir geometries can be generated using geometrical balancing techniques, (e.g. Henk and Nemcok, 2008). Ideally, the reservoir evolution should be described by a continuous forward model.
The workflow for building a geomechanical reservoir model is schematically depicted in Figure 1. Two different types of data are required: input data (reservoir geometry, material parameters, boundary conditions) and independent calibration data (in situ stress measurements, fractures from cores and logs) to compare observations with model predictions. Such calibration data usually is only available if wells have already been drilled. Further work steps include import of the subsurface geometry into the numerical simulation software, population of the model with lithology-specific material parameters and assignment of boundary conditions. During the subsequent calibration stage input parameters are modified iteratively within reasonable limits until a satisfactory fit between model calculations and field observations is achieved. This validated model can then be used to predict tectonic stresses and fracture characteristics in the undrilled parts of the reservoir.
The
In order to assess the practical value of the geomechanical
Static modelling results indicate a rather uniform stress orientation parallel to the regional σHmax throughout most of the reservoir. This is in accordance with stress observations at two of the calibration wells. Some local perturbations (up to 30°) are predicted for individual fault-controlled compartments and for the immediate vicinity of faults. The latter is actually observed in the third well and can be predicted with considerable accuracy if a corresponding fault model is used.
Dynamic modelling and pre-drilling fracture prediction, respectively, are less robust. This is partly due to uncertainties with respect to the exact tectonic regime in the Upper Cretaceous (normal faulting vs. strike-slip) and hence the orientation of the predicted conjugate shear fracture set differs by about 30°. In addition, the impact of paleo-pore pressures on the formation of tensile fracture is not known. Thus, some calibration wells are required to constrain the appropriate boundary conditions and choose the actual fracture orientations from the various options theoretically possible. In the present case study from the eastern Sirte Basin, this differs between individual fault blocks, thus following calibration a robust prediction may only be limited to the same fault compartment.
The case study shows that the general modelling concept can be applied successfully utilizing the data sets typically available during the exploration and appraisal stage. In particular, it illustrates that geomechanical modelling for stress and fracture prediction can be fully integrated into a corresponding Petrel® project of the reservoir. The case study indicates that a robust prediction of the stress field, including its local perturbations near faults, can be based primarily on the reservoir geometry with only sparse well control. Fracture prediction is more complex and definitely requires well data for calibration as the model has to use several poorly constrained parameters like the magnitude of the paleo-stresses and the paleo-pore pressures to infer fracture orientations. Once the geomechanical models are calibrated they provide a valuable tool for a variety of tasks like optimizing well trajectories (borehole stability), pre-drilling planning of hydraulic fracture treatments, e.g. multiple fracs in horizontal wells, as well as positioning of wells in zones of enhanced fracture intensity.
Ambrose, G., 2000, The geology and hydrocarbon habitat of the Sarir Sandstone, SE Sirte Basin, Libya: Journal of Petroleum Geology, v. 23, p. 165-192.
Ben-Suleman, A., 2006, Active tectonics and related stress fields of northern Libya: Geophysical Research Abstracts, 8, 08954, SRef-ID: 1607-7962/gra/EGU06-A-08954.
Henk, A., 2005, Pre-drilling prediction of the tectonic stress field with geomechanical models: First Break, v. 23, no. 11, p. 53-57.
Henk, A. and M. Nemcok, 2008, Stress and fracture prediction in inverted half-graben structures: Journal of Structural Geology, v. 30, no. 1, p. 81-97.
Maerten, L., P. Gillespie, and D.D. Pollard, 2002, Effects of local stress perturbations on secondary fault development: Journal of Structural Geology, v. 24, no. 1, p. 145-153.
Yale, D.P., 2003, Fault and stress magnitude controls on variations in the orientation of in situ stress, in M. Ameen, (ed.), Fracture and In-Situ Stress Characterization of Hydrocarbon Reservoirs: Geological Society, London, Special Publications 209, p. 55-64.
Copyright © AAPG. Serial rights given by author. For all other rights contact author directly. |