Induced seismicity caused by underground fluid injection occurs because of pore pressure changes that lead to stress changes in the reservoir and the surrounding formations. Despite that noticeable seismic events from fluid injection is very rare, proper assessment of possible seismic events is important. The objective of this study is to develop numerical models that simulate stress changes, fault slips, and ground floor movements induced by underground fluids injection.
The numerical analysis process presented in this work consists of three steps. First, stress changes around the reservoir due to fluid injection are analyzed using a FEM-BEM (Finite Element Method - Boundary Element Method) coupled model. Secondly, the stability of faults located near the reservoir is evaluated using the displacement discontinuity method. Thirdly, elastic waves caused by the fault slip is simulated using a FEM model where seismic response on the surface are calculated. A field case study is also presented to demonstrate the applicability of the numerical model developed in this work.
The numerical analysis results indicate that stress concentration occurs around a boundary between the basement and sandstone beneath the reservoir. This affects the stability of existing faults in this region. As a result, when the fault is slipped, seismicity may be triggered. It is assumed that the slip is caused by stress changes in the faulted region as well as a pore pressure change in the fault, which is caused by volumetric strain changes of the fluid in the fault. A field case study based on wastewater injection in the Southwestern region of the United States where injection induced seismicity events have been recently reported, is also performed in this work. In this case study, the variation of rock strength is considered one of important factors in induced seismicity events.
The novelty of our model is the ability to quantitatively assess the risk of induced seismicity due to wastewater injection, which can be also applied to other applications such as CCS and underground gas storages. Moreover, conducting risk assessment by these numerical models can improve safety of underground fluid injection operations.
Lu, Chuan (Department of Civil and Environmental Engineering, University of Alberta) | Brandl, Jakob (Department of Civil and Environmental Engineering, University of Alberta) | Deisman, Nathan (Department of Civil and Environmental Engineering, University of Alberta) | Chalaturnyk, Richard (Department of Civil and Environmental Engineering, University of Alberta)
In this study, a novel experimental system has been developed for static and dynamic elastic properties measurements at seismic frequencies under anisotropic stress and shear deformation conditions. This system focuses on static and seismic range frequencies dynamic (0.1 Hz to 20 Hz) elastic deformation properties of poorly consolidated oil sands and highly overconsolidated (clay) shales. The main body of the experimental system is a computer control servo-hydraulic system. A pair of laser displacement sensors measure nanometer scale displacement during the dynamic tests. A coarse scale and fine scale load cell system was developed for measuring force with high precision during dynamic testing. A novel triaxial cell for use with the loading system was also developed to simulate the reservoir stress and pore pressure condition during static and dynamic testing and allows permeability to be measured during testing. The loading system, dual load cell calibration procedure and results, and results for acrylic and 3D printed sand specimens are presented. The stable and reasonable results demonstrate the capacity of the new experimental system.
Reservoir depletion can induce substantial changes in the stress state of the rock. The coupled interaction between the pore fluid pressure and rock stress will then alter the reservoir permeability, which in turn reversely affects the productivity index of the production well. A new nonlinear analytical solution is developed for the drawdown-dependent productivity index of reservoirs under steady-state flow. Biot's theory of poroelasticity is used to derive the depletion-induced changes in the reservoir rock porosity and permeability. The well-known Mindlin's solution for a Nucleus of Strain in a semi-infinite elastic medium is applied as Green's function and integrated over the depleted volume of reservoir rock to obtain the 3D distribution of stress and volumetric strain distributions. The fluid transport equation is nonlinearly coupled to the solid mechanics solution via the stress-dependent permeability coefficients. A perturbation technique is applied to mathematically treat the described nonlinearity to solve for the coupled equations of pore fluid flow and rock stress under steady-state flow. The good match between the obtained analytical approximations for productivity index and the numerical solutions verifies the correctness and robustness of the proposed model.
Results indicate and confirm the expected strong dependency of the well productivity index to the drawdown magnitude as well as the poroelastic constitutive parameters of the reservoir rock, with the highest sensitivity to drained bulk modulus, followed by the reservoir depth and solid-grain modulus. The lowest PI sensitivity is to the pore fluid modulus and Poisson's ratio. The resulting productivity index is found out to be drawdown-dependent, which can render values substantially different than the productivity index estimate from the conventional flow-only analysis. The presented estimates for the related nonlinear productivity index can be readily used by the practicing engineers.
Yu, Hao (Southwest Petroleum University, China) | Dahi Taleghani, Arash (Pennsylvania State University, United States) | Lian, Zhanghua (Southwest Petroleum University, China) | Lin, Tiejun (Southwest Petroleum University, China)
Microseismic data and production logs in our study area have confirmed an asymmetric development of the stimulation rock volume, while severe casing deformation problems have been reported frequently in this area. In this paper, we investigate the possibility of casing failure due to strong shear stresses developed by asymmetric stimulated zones. Overlapping stimulation zones in adjacent stages may intensify asymmetry of the pore pressure distribution and resultant shear forces. Although induced shearing may have a positive impact on fracture permeability, but it may also cause operational problems by inducing severe casing deformations. While most of the casing deformation models only consider rock deformations very close to the wellbore, we developed a 3D coupled model for fracture network growth and stress re-distribution during hydraulic fracturing to achieve a more realistic model for casing deformation. This reservoir-scale model is tied to a more detailed near-wellbore model including the casing and cement sheath to simulate casing deformations. Case studies were conducted using data from a shale gas well that experienced severe casing deformation during hydraulic fracturing. Impact of stage spacing, and pumping rate are incorporated to investigate their potential impacts on casing and well integrity. Multi-stage hydraulic fracturing considering the development of complex fracture network is simulated at the reservoir scale based on the microseismic events. Continuous re-distribution and re-orientation of stress field near the borehole are tracked during the development of the fracture network which reveals some pocket of tensile stresses along the casing. Asymmetric fractures are observed to generate strong shear stress on the suspended casing. These shear forces result in deflection and S-shape deformations. Some regions receive repeating treatments, which leads to increase formation stress heterogeneity and worsen casing deformation severity. Our analysis has indicated that simply increasing the flexural strength by increasing thickness of casing cannot radically mitigate casing deformation problems. This paper provides a novel workflow for a coupled modelling of casing deformation during hydraulic fracturing operations, while current modelling efforts assume symmetric fracture geometries.
Hydrocarbon production from Shale formations has become an increasingly significant part of the global energy supply since 2010. With the advent of horizontal drilling and multiple-stage hydraulic fracturing, the Utica Shale, which underlies the Marcellus Shale as a natural source rock, is one of the most promising and productive shale plays in the US. However, very few academic papers discuss its geo-stress, pore pressure, permeability, and corresponding DFIT applications, which are essential for the development of the Utica Shale. The objective of this study is to use Diagnostic Fracture Injection Tests (DFITs) data from the field to analyze minimum in-situ stress, closure pressure, reservoir pore pressure, key reservoir properties and fracture geometry in the Utica Shale by different DFIT interpolation methods. The analysis results are compared and discussed in detail to investigate the features of each DFIT interpolation method. In addition, DFIT numerical simulation based on Variable Compliance Model is performed to predict induced fracture geometry and effective formation permeability in the Utica Shale.
DFIT is a commonly applied technique to analyze stress regimes and reservoir properties, while its interpolation can be challenging and difficult for different formations. DFIT interpretation for Shale formations is even more complex. In this study, first overviewing the geology of the Utica Shale and continuing to the summary of DFIT analysis and its governing equations, one can gain a better understanding of the methods and processes used to analyze our DFIT data targeting the Utica Shale. Tangent Line method, Compliance method, and Variable Compliance method are reviewed, and the corresponding assumptions for each method are examined, compared and discussed. Our DFIT data, which is acquired from a horizontal well targeting the Utica Shale, is interpreted by all methods to analyze minimum in-situ stress, closure pressure, initial reservoir pore pressure, key reservoir properties and fracture geometry. The DFIT results are then discussed and compared in detail to investigate the features of each method with its diagnostic signatures. Following that, the induced fracture geometry and the effective formation permeability are predicted by numerical simulation and sensitivity analysis, which also evaluate the impacts of wellbore storage, formation properties and fluid properties on simulated pressure and pressure derivative profiles.
The results from DFIT analysis are very encouraging. The Tangent Line method oversimplified leak off dependence and fracture stiffness, while the obtained minimum in-situ stress, closure pressure, pore pressure, fracture geometry and effective permeability are consistent with the diagnostic plots and our petrophysics studies. The Compliance method is able to identify mechanical closure, but it overestimates the minimum principal stress. The Variable Compliance method can capture the variance in fracture stiffness and pressure dependent leak off during progressive fracture closure, and its estimated closure pressure is an average of the results from the Tangent Line and the Compliance methods. The formation permeability of the Utica Shale is estimated by performing a history match of the pressure and pressure derivative profiles. The physics behind the DFIT simulation and sensitivity analysis is analyzed and discussed in detail. Our study can significantly improve the understanding of pressure/stress regimes, fracture geometry, and reservoir properties in the Utica Shale, as well as features of different DFIT interpolation methods. The knowledge and results demonstrated in this article will indefinitely assist operators in their optimization of multistage fracturing and horizontal drilling design in order to develop the Utica Shale more cost-effectively.
Accurate estimation of mud weight (MW) helps to conserve wellbore stability in real-time drilling operations. Determination of proper MW requires a correct understanding of the stress field, natural fractures, pore pressure, rock strength, borehole trajectories, etc. It is a problematic task especially in, highly inclined wells, deviated wells, and near salt formations due to uneven variations in wellbore stresses. Proper MWs are difficult to apply at target depths of the unstable formations because of uncertainties existing inside the wellbore. There are no reliable tools or techniques available that can precisely determine the optimum value of MW. This paper proposes a novel and more convenient approach to estimate the safe MW for deviated wells using surface measured data. In this study, Bagging and Random forest ensembles have been utilized to model the relationship between sensors measured variables and MW. The proposed framework has been trained and tested on real-time Norwegian post-drilling data. Artificial neural networks (ANNs) and support vector regression (SVR) have also been utilized in this study for comparison purposes. The analysis of prediction results clearly reveals that Random forest ensemble has acquired the highest coefficient of correlation and minimum estimation errors. The performance of Ensemble methods is found to be superior to the ANNs and SVR models. The proposed approach can be useful for the determination of MW required at different depths of reservoir formation and maintaining the wellbore stability during real-time operations.
Numerous questions surround stimulation and depletion in unconventional reservoirs with many important implications. Understanding depletion-induced stress changes is critical for designing in-fill drilling and avoiding phenomenon such as hydraulic fracture growth into depleted areas and hydraulic fractures from in fill wells affecting pre-existing wells (the frac-hit or parent well/child well phenomenon). In this paper, we utilize a fully coupled fracture-poro-mechanical computational model described by Jin & Zoback (
Monitoring data of episodic transient heat and flow conditions, caused by intermittent cold CO2 injection in Aquistore, has shown a linkage between injectivity index and downhole injection temperature. Taking leverage access to invaluable field performance data collected from this highly instrumented Canadian CCS demonstration project, the focus of this paper is to understand and quantify the potential non-isothermal mechanisms involved in cold CO2 injection. Understanding this phenomenon is important as it has serious implications on containment, conformance, and injectivity technologies for effective geological CO2 storage.
To account for transient heat and fluid transport during cold CO2 injection in Aquistore, a non-isothermal EOS-based fluid flow simulation, of a high-resolution detailed geological model built based on an extensive characterization program, was calibrated with periodic monitoring data of downhole pressure, temperature, and injected mass rate. Due to the possibility of non-isothermal effects on near-wellbore stress fields, local induced fractures, and permeability alterations, in addition to dynamics of CO2-brine interactions, coupled reservoir geomechanical modeling techniques were then employed for further calibration. The uncertainties associated with the subsurface geological modeling, leaking aquifer boundaries, reservoir heterogeneity, rock thermal, petrophysical, and geomechanical properties were considered for both isothermal and non-isothermal conditions.
Processing of DTS (Distributed Temperature Sensing) data from both injection and observation wells indicated dynamic perturbations in subsurface temperature due to injection operations. Geological characterization, performed through high-resolution 3D seismic images, core, and log data, and the existence of a leaking aquifer, were found to have significant impacts on CO2 plume evolution. Through history matching process of non-isothermal flow simulation, for both injector and observation wells, the extent of the cold region was estimated, and found to be mainly controlled by rock thermal properties, permeability, and injection rate. Our analysis suggested that cold temperature front was limited to near-wellbore region due to substantial heat loss by conduction, besides radial decay of convective flow.
Further non-isothermal coupled simulations indicated a large, but near-wellbore-limited reduction in effective horizontal stresses, induced by cold CO2 injection. Employing different values of thermal expansion coefficients, local potential open-mode fractures were observed; however, fracturing of entire formation was not experienced. This phenomenon was associated with local permeability enhancement, and potential improvement in CO2 injectivity. A comparison of isothermal and non-isothermal analyses on reservoir performance during CO2 injection was lastly provided.
Our analysis of subsurface injection and coupled processes in relation to geologic CO2 sequestration delivers critical insights on how and under what conditions these non-isothermal effects are generated. This ultimately provides a predictive tool to better characterize the reservoir behaviour, injectivity issues, and spatial location of a subsurface CO2 plume.
Numerous carbonate reservoir discoveries were made in Indonesia (
The process involves multiple cycles—from formation evaluation (e.g., geomechanics analysis, design of an effective fracturing method, and production forecasting) through the economic impact to the operator. During the early phase of this integrated study, the uncertainties of all static and dynamic parameters (i.e., geological complexity, rock physics, and stress profile) were considered for fracturing design. Production performances from multiple fracturing stimulation scenarios were then modeled and compared to select the plan that optimizes production for the Berai Formation.
Results demonstrated an effective multidiscipline approach toward a comprehensive strategy to meet the ultimate objective in optimizing production. This project leveraged formation evaluation and fracturing design to deliver integrated solutions from exploration to accurate production forecast. The well stimulations were performed by carefully selecting fluid characteristics based on geological-petrophysical properties, pressure, and stress profiles within the area. Results yielded excellent production gains—for the best case, up to 50% with an average of 40% in comparison with initial production by using an acid that provides optimum fracture geometry and permeability.
This opportunity demonstrated the importance of understanding formation behavior and the parameters that aid the selection of an appropriate fracturing design for a low porosity/permeability carbonate reservoir.
Petroleum geomechanics is defined as the interaction between the evolving earth stresses and the overburden and reservoir rock mechanical properties. A comprehensive understanding of rock mechanical behaviour is key to successful field appraisal and development. For example, 70% of the world’s oil and gas reserves are contained in reservoirs where rock failure and sand production will become a problem at some point. Wellbore stability issues have been estimated to cost the industry USD 8 billion annually. Around 80%–90% of data comes from “traditional” core and log petrophysics, but the importance of data quality control and a rigorous and consistent petrophysical interpretation is often overlooked by well construction and production engineers.