While the supercritical Co2 injection technology has been successfully employed for utilization operations such as enhanced oil recovery, there are some social and technical challenges with its large-scale implementation for storage purposes. Induced seismicity due to Co2 injection is one of primary concerns associated with the technology and it needs to be properly addressed. In this study, a set of 2D coupled Thermo-Hydro-Mechanical (THM) modeling was performed to investigate the effects of the reservoir porosity and thickness on the magnitude of induced seismic events. The model included a limited-dimension pre-existing fault which cannot be easily detected by geophysical surveys. The numerical modeling was used to simulate changes in the stress distribution in the reservoir, fault and surrounding rock due to Co2 injection. The fault slip obtained from the model was then correlated to the magnitude of earthquake for each case. Three reservoir thicknesses and three reservoir porosities were examined in parametric studies. The results showed that thin reservoirs have higher probability of failure and will result in larger-magnitude induced seismic events. Reservoirs with higher porosity were shown to have longer rupture time and larger events.
This paper investigates the effects of inflating a reservoir via carbon sequestration or water flooding on the state of stresses in surrounding ductile formations. A better control is needed on the assessment of stresses in the caprock and how would they change due to the inflation process in order to avoid geomechanical problems such as seal integrity and induced seismicity. An important factor in analyzing the reservoir-caprock interaction is the compression-inflation model used to estimate reservoir behavior. A finite elements model of a simple circular disc is created to study the stress redistribution around an inflating reservoir using the commercial software ABAQUS. The paper analyzes the results using well known methods, namely; the Ellipsoidal Inclusion Approach and the Deformation Analysis in Reservoir Space Approach. The analysis verified the results of the Finite Elements Simulation and gave insight to generic redistribution of stresses around an inflating reservoir. The paper also compared two different compression-inflation models; the Modified Cam Clay Model (MCC) and the MIT-E3 model. The MIT-E3 model utilizes a non-linear elastic inflation model and estimates larger redistribution of stresses around the inflating reservoir.
In this study, a coupled poro-elasto-plastic Finite Element Method (FEM) is used to calculate a set of scenarios of fault reactivation which could occur. The potential for fault reactivation is estimated numerically for faults surrounding a well designed for drilling cuttings reinjection in offshore West Africa. This well is in a block bordered with 3 major faults. The results of these calculations on fault reactivation are used to design the injection pressure and further control the total volume of drilling cuttings which can be safely injected. Numerical results obtained with the FEM model include: distribution of equivalent plastic strain within the whole model, distribution of von Mises equivalent stresses, and the displacement field under a given pore pressure boundary condition at the bottom of the model. The plastic region is the area where the fault is being reactivated. In this way, results of both the location and the level of fault reactivation are obtained and visualized. The numerical results are shown for the plastic strain distribution at the stage where the plastic region is growing up to the top of the fault zone and the distribution of the von Mises stresses.
In recent years, the development of oil and gas from shale has proceeded quickly in the world due to the application of multi-stage fracturing technology in horizontal wells. It is imperative to study the poroelastic characteristics of the rock for modeling the performance of rock under in-situ conditions, thus ensuring the success of hydraulic fracturing. Biot's coefficient is one of the key poroelastic parameters for calculating the effective stress for creating artificial fractures in the shale formations. In this study, we propose anew method to measure the Biot's coefficient. Our method simplified the measuring procedures to obtain the Biot's coefficient by controlling the confining pressure, which isused to maintain the volume of the sample, while altering the pore pressure. Shales amples recovered form Bakken formation in Willistion Basin is tested using this method. The results of our experiments show that the Biot's coefficient of Bakken samples obtained from horizontal drilling and vertical drilling are significantly different from each other. This significant difference of Biot's coefficient with different drilling-direction provides scientists and engineers a solid base for in-situ stress analysis during multi stage hydraulic fracturing and reservoir depletion due to production.
Hydraulic fracturing technique has been widely applied in the enhanced geothermal systems, to increase injection rates for geologic sequestration of CO2, and most importantly for the stimulations of oil and gas reservoirs, especially the unconventional shale reservoirs. One of the key points for the success of hydraulic fracturing operations is to accurately estimate the redistribution of pore pressure and stresses around the induced fracture and predict the reactivations of pre-existing faults. The fracture extension as well as pore pressure and stress regime around it are affected by: poro- and thermoelastic phenomena as well as by fracture opening under the combined action of applied pressure and in-situ stress. A couple of numerical studies have been done for the on this for the purpose of analyzing the potential for fault reactivation resulting from pressurization of the hydraulic fracture. In this work, a comprehensive analytical model is constructed to estimate the stress and pore pressure distribution around an injection induced fracture from a single well in an infinite reservoir. The model allows the leak-off distribution in the formation to be three-dimensional with the pressure transient moving ellipsoidcally outward into the reservoir with respect to the fracture surface. The pore pressure and the stress changes in three dimensions at any point around the fracture caused by thermo- and poroelasticity and fracture compression are investigated. Then, the problem of constant water injection into a hydraulic fracture in Barnett shale is presented. In particular, with Mohr-Coulomb failure criterion, we calculate the fault reactivation potential around the fracture. This study is of interest in interpretation of micro-seismicity in hydraulic fracturing and in assessing permeability variation around a stimulation zone, as well as in estimation of the fracture spacing during hydraulic fracturing operations.
Luo, D. (University of Alaska Fairbanks) | Chen, G. (University of Alaska Fairbanks) | Patil, S. (University of Alaska Fairbanks) | Abhijit, D. (University of Alaska Fairbanks) | Santanu, K. (University of Alaska Fairbanks)
Wellbore stability is of critical importance in all drilling operations. Wellbore instability may cause stuck pipes, lost circulation, and/or collapse of the wellbore, resulting in high drilling cost and significant time loss. In this study, computer simulations using FLAC (Fast Lagrangian Analysis of Continua) were conducted on the stability of horizontal wells in shale formations. Laboratory-tested geomechanical properties of seven shale samples and in-situ stress conditions collected from the literature were used. Computer simulations were carried out to estimate minimum downhole pressures for maintaining wellbore integrity in each type of shale formation under different states of in-situ stresses. The results showed that the minimum downhole pressure to maintain wellbore stability is positively related to stress differentiation and pore pressure, and negatively related to internal frictional angle and cohesion of the surrounding rock. The determination of the minimum downhole pressure from the regression analyses may serve as a basis for engineers to quickly select proper mud density when drilling horizontal wells in potentially problematic rock formations, particularly shale formations.
We developed recently a new apparatus which allows laboratory fracturing experiments under tri-axial compression up to 15 MPa with pore water pressure up to 15 MPa. Silica sands with particle size of about 125μm are used as the simulated formation materials. In addition to the sand, some amount of kaolinite flour is mixed for adjusting permeability. The mixture is layered in a mold to form a cubical specimen of 200 × 200 × 200 mm3 with aid of a specially-designed press machine. A fracturing fluid with viscosity of 300 mPa s is injected into a specimen through a slit of a steel pipe buried in the specimen. After the tests, we excavate the specimen bit by bit and observe how the fracturing fluid has invaded into the specimen. In the present study, to examine the effect of pore water on the fracture formation, we carried out the tests for the specimens under various conditions of water saturation, pore pressure and confining stresses. Then we found that the fracturing pressure changes in proportion to the confining stress, and it is not influenced by water saturation and the initial value of pore pressure.
Hydraulic fracturing re-distributes pore pressure and stresses inside rock and causing failure by fracture initiation and/or activation of discontinuities such as natural fractures or layering boundaries. The clear result of this process would be enhancement of the formation permeability. In this paper, poroelastic numerical method is employed to investigate interactions of hydraulic fractures and porous rock. Besides, evolution of potential failure (microseismic events) during hydraulic stimulation is studied. The model uses indirect boundary element method. Temporal variations and pressure-dependent leak-off, hydro mechanical response of porous matrix, fluid flow in matrix, couplings of matrix volumetric deformation and pore fluid dissipation, and hydraulic fractures interaction are taken into account. Results clearly show the modification/redirection of principal stresses around pressurized hydraulic fracture. It also shows that modified stresses cause failure around the fracture tip which generally covers a bigger area than the fracture itself and could results in an overestimation of the stimulated reservoir volume. Then, pressurization of multiple parallel fractures studied. As expected, it is found that fracture geometry and the distance between hydraulic fractures are the most important factors in modifying the stress state and pore pressure and consequently extent of failure region. It was also observed that the opening of a fracture induces shear stresses on adjacent fractures. The SIF for pressurized cracks was calculated for Mode I and Mode II, and it was shown that when the distance between hydraulic fractures increases, the Mode I SIF also increases and the Mode II SIF decreases.'ép.
Often, a key factor in the successful hydraulic fracture stimulation of unconventional reservoirs is the opening or shearing (and later extension) of natural fractures or weakness planes around a created hydraulic fracture. The behavior of natural fractures, or weakness planes, in response to hydraulic fracture stimulation can be complicated. Furthermore, the stimulation of these fractures and weakness planes is dependent on several critical, in-situ conditions that can increase (or decrease) the contribution of natural fractures and weakness planes to well production. The optimal economic completion, then, requires considering these factors during both stimulation design and post-stimulation evaluations.
The simplistic, and traditional, assumption that hydraulic fractures are bi-wing, planar and symmetric around the wellbore has tended to bias the interpretation of different aspects of the stimulation process. However, hydraulic fracture monitoring methods, such as microseismicity, pressure evaluations, and the coring through of hydraulic fractures, have confirmed the complex nature of fracture propagation in unconventional plays, often due to the presence of natural fractures and weakness planes. Therefore, an improved consideration of natural fracture and weakness plane behavior during hydraulic fracturing will result in a better understanding of fluid treating pressures and hydraulic fracture geometry, which will help lead to more accurate estimations of production for unconventional plays.
In this paper, the results of an extensive parametric study of in-situ stress conditions, in-situ pressure, natural fracture mechanical properties (cohesion and friction angle) and characteristics (joint orientation and initial aperture), and different operating conditions (single stage, simultaneous hydraulic fracture stages, and sequential hydraulic fracture stages) on injection (net) pressure behavior is presented. The results were generated using a 2-D distinct element model and capture the important role that, for example, initial natural fracture aperture and in-situ pressure play in the development of hydraulic fracture injection pressures in unconventional reservoirs.
Existing laboratory methodologies for characterizing the pore volume compressibility of rocks are summarized. Special emphasis is placed on the two most common in the industry pore volume compressibility tests—uniaxial strain pore pressure depletion tests and uniaxial strain effective stress loading tests. We carefully overviewed a rigorous mathematical description of uniaxial deformation of porous rocks implemented in these tests, derivation of pore volume compressibility coefficients from stress-strain data, and assumptions made in these models. Many industry-relevant porous rocks demonstrate nonlinear stress-strain behavior. As a practical workflow for characterization of pore volume compressibility, we propose using piecewise linear approximations of loading diagrams with constant compressibility coefficients. The linearized model provides a suitable description of nonlinear rock response within certain limited intervals of loading trajectory. For the correct use of established pore volume compressibility properties in applications, it is important to validate that predictions are made for the equivalent loading paths, stress, and pressure levels as used in the linearization intervals. Several examples of mechanical rock behavior were considered, focusing on the end-member cases of high- and low-grain compressibility compared with bulk compressibility. We also discussed implications of some rock microstructures, including mudstones, on mechanical properties, to provide a reference for better interpretation of real rock behavior.