Tamayo-Mas, Elena (British Geological Survey) | Harrington, Jon (British Geological Survey) | Shao, Hua (Federal Institute for Geosciences and Natural Resources) | Dagher, Elias (Canadian Nuclear Safety Commission / University of Ottawa) | Lee, Jaewon (Korea Atomic Energy Research Institute) | Kim, Kunhwi (Lawrence Berkeley National Laboratory) | Rutqvist, Jonny (Lawrence Berkeley National Laboratory) | Lai, Shu-Hua (National Central University) | Chittenden, Neil (Quintessa Ltd.) | Wang, Yifeng (Sandia National Laboratories) | Damians, Ivan (Universitat Politecnica de Catalunya) | Olivella, Sebastia (Universitat Politecnica de Catalunya)
The processes governing the movement of repository gases through engineered barriers and argillaceous host rocks can be split into two components, (i) molecular diffusion (governed by Fick's Law) and (ii) bulk advection. In the case of a repository for radioactive waste, corrosion of metallic materials under anoxic conditions will lead to the formation of hydrogen. Radioactive decay of the waste and the radiolysis of water are additional source terms. If the rate of gas production exceeds the rate of gas diffusion within the pores of the barrier or host rock, a discrete gas phase will form (Wikramaratna et al., 1993; Ortiz et al., 2002; Weetjens and Sillen, 2006). Under these conditions, gas will continue to accumulate until its pressure becomes sufficiently large for it to enter the surrounding material. In clays and mudrocks, four primary phenomenological models describing gas flow can be defined, see Figure 1: (1) gas movement by diffusion and/or solution within interstitial fluids along prevailing hydraulic gradients; (2) gas flow in the original porosity of the fabric, commonly referred to as two-phase flow; (3) gas flow along localised dilatant pathways, which may or may not interact with the continuum stress field; and (4) gas fracturing of the rock similar to that performed during hydrocarbon stimulation exercises.
Modeling Fault Activation and Seismicity in Geologic Carbon Storage and Shale-gas Fracturing - Under what conditions could a felt seismic event be induced? Summary Coupled fluid flow and geomechanical modeling with explicit and physics based modeling of fault activation is employed to investigate under what conditions a felt seismic event could be induced during deep injection activities associated with Geologic Carbon Storage (GCS) or shale gas fracturing. The analysis shows that for the case representative of GCS, felt seismic events (e.g. In any case, the initial stress field as well as the rock properties, whether more ductile or brittle, are important conditions that will determine whether a felt seismic events could be induced. Introduction The potential for fault reactivation and induced seismicity are issues of concern related to both stimulation of shalegas reservoirs and geologic carbon storage (GCS) (National Research Council, 2012; Zoback and Gorelick, 2012; Rutqvist, 2012; Davies et al., 2013).
ABSTRACT: The coupled fluid flow and geomechanical simulator TOUGH-FLAC was employed to study the mechanisms of depletion-induced reservoir compaction and its impact on hydrocarbon gas production. For consideration of compaction-drive in the sequential coupling between fluid flow and geomechanics, we developed and applied a new alternative approach of linking volumetric strain to the fluid mass balance through a correction of rock compressibility in the fluid flow simulator. Using this approach, we conducted model simulations for understanding the impact of porosity change on deformation and gas production, including sensitivity studies with regard to material properties and operation parameters for the optimization of gas production. The model simulations showed that the reservoir compaction can increase or decrease the gas recovery depending on the specific porosity and the permeability changes in the reservoir. This result shows that the interaction between fluid flow and geomechanics should be considered for optimal reservoir management and TOUGH-FLAC with the implemented coupling approach can be an effective tool for such analysis.
Biogenic gases have become increasingly attractive targets of oil and gas exploration and production activities in the worldwide. However, production of the gases from poorly consolidated or unconsolidated soft sediments in shallow reservoirs can be technically challenging operations because of depletion-induced reservoir compaction. Fluid production from such reservoirs and associated pressure drop may cause reservoir compaction and consequent surface subsidence (Settari, 2002), potentially resulting in surface facility damage (Mayunga, 1969), fault reactivation (Segall, 1989, Odonne et al., 1999), or wellbore instability (Bruno, 1992, Rutqvist et al., 2012). Pore collapse of weak sediments during compaction could drastically degrade reservoir quality by significantly reducing porosity and permeability. Meanwhile, the reservoir compaction can maintain reservoir pressure being an important driving mechanism enhancing oil and gas production (compaction-drive). Therefore, understanding the mechanisms of and impact of reservoir compaction is essential for reservoir management and risk control. However, such interaction between fluid flow and geomechanics may not be properly handled with conventional reservoir simulators where compaction is calculated as a function of pore pressure only, while neglecting stress changes due to deformation.
Yoo, Hwajung (Seoul National University) | Park, Sehyeok (Seoul National University) | Xie, Linmao (Seoul National University) | Min, Ki-Bok (Seoul National University) | Rutqvist, Jonny (Lawrence Berkeley National Laboratory) | Rinaldi, Antonio P. (Swiss Federal Institute of Technology)
Numerical modeling of fractured geothermal reservoir is conducted to describe coupled hydromechanical behavior at Pohang Enhanced Geothermal System (EGS) site. A hydraulic stimulation was conducted in the PX-1 well at the depth of 4,362m in Pohang EGS site from Dec 2016. Stress-induced permeability changes are inferred to have occurred from well head pressure and injection rate versus time curves during the stimulation. A numerical model of Pohang EGS reservoir is built to simulate hydromechanical behavior during the hydraulic stimulation at PX-1 well. The well head pressure and injection rate curves are reproduced considering corresponding permeability changes by effective stress changes and hydroshearing. History in hydromechanical property changes such as permeability during the stimulation is estimated from the modeling results. In addition, a relationship between effective stress and permeability is obtained through model calibration against the well head pressure and injection rate data. For the numerical modeling, TOUGH-FLAC, a simulator for coupled thermal-hydraulic-mechanical processes in geological media, is used.
Pohang Enhanced Geothermal System (EGS) project has been operated in Pohang, South Korea since 2010. The geology consists of sedimentary rock from ground surface to 2.4km deep, and of granodiorite below the depth of 2.4km. Two boreholes, PX-1 and PX-2, are drilled up to 4,217m and 4,348m respectively. Hydraulic stimulations were conducted in PX-2 from Jan. 29 to Feb. 10, 2016, and in PX-1 from Dec 15, 2016 to Jan 11, 2017. In PX-2, 1,970m3 of water was injected, and the maximum wellhead pressure of 89.2MPa was observed. The total amount of injected water to PX-1 was 2,689m3, and maximum wellhead pressure reached 27.7MPa. The main flow path is expected to be one or two major fault zones intersecting PX-1 and PX-2. Hydroshearing on the pre-existing faults is highly likely to have happened at wellhead pressure of around 15MPa during the hydraulic stimulation in PX-1 according to a result interpretation (Park, S. et al., 2017).
Reservoir deformation during steam injection of SAGD operation can result in the increase in formation permeability that can positively impact to the bitumen production. The reservoir deformation behavior is controlled by the mechanical properties of oil sand, which are highly dependent on temperature. This work is focused on the temperature dependency of elastic properties of oil sand and its impact on geomechanical responses during a SAGD operation. Coupled geomechanical and fluid flow modeling technique is employed to illuminate the impact of the change in elastic properties to the reservoir deformation behavior.
Rock physics modeling is conducted at first for quantifying the temperature effect on the elastic properties of oil sand. Based on the investigation of log data from an actual SAGD operation field, we used the soft-sand model to calculate dry-frame elastic properties of the unconsolidated sand. We then applied and investigated several substitution methods to quantify the effect of the pore-filling bitumen on the elastic properties of the oil sand. We selected one of the solid substitution methods instead of Gassmann equation because bitumen behaves like solid at low temperature. The coupled hydraulic, thermal, and geomechanical simulator, TOUGH-FLAC, is used to investigate the effect of oil sand's elasticity on reservoir deformation behavior. The coupled modeling for SAGD is conducted for two simple cases; one case with the elastic properties at original reservoir temperature and the other case with the updated elastic properties considering the increased temperature. Comparison of the results from the two cases demonstrates the importance of considering the effect of temperature on the elastic properties of oil sand. This work is new in terms of combining rock physics modeling for quantitative description of the oil sand elastic properties and the coupled hydraulic, thermal, and geomechanical modeling considering the temperature-dependent elastic properties of oil sand.
Wang, Yuan (College of Civil and Transportation Engineering and Hohai University and Lawrence Berkeley National Laboratory (LBNL) ) | Hu, Mengsu (College of Civil and Transportation Engineering and Hohai University and Lawrence Berkeley National Laboratory (LBNL)) | Rutqvist, Jonny (Lawrence Berkeley National Laboratory (LBNL))
Abstract: In this paper we present developments and applications of a new code for confined-unconfined seepage analysis based on the Numerical Manifold Method (NMM). We approach the problem using an energy-work-based seepage model which provides a clear definition and physical meaning of the seepage energy terms when assembling the governing equations. A unique feature of our approach is that it enables the application of the NMM to non-homogenous seepage analysis, based on our pipe model analogous to the penalty spring commonly applied in mechanical analysis. We verified the proposed model and the NMM code by comparison of our simulation results to analytical solutions for confined seepage and to available numerical models for a number of unconfined fluid flow examples, including a case with non-homogeneous material domain. We show that NMM, based on a two-cover-mesh system, can in the case of unconfined seepage achieve high accuracy and convergence speed with rather coarse meshes and without the need for remeshing as the phreatic surface changes.
Jeanne, Pierre (Lawrence Berkeley National Laboratory) | Rinaldi, Antonio Pio (Lawrence Berkeley National Laboratory) | Rutqvist, Jonny (Lawrence Berkeley National Laboratory) | Cappa, Frédéric (Lawrence Berkeley National Laboratory) | Guglielmi, Yves (CEREGE (UMR7330))
Abstract: In this study, we have examined the influence of the fault zone characteristics on pressure diffusion and fault reactivation by CO2 injection. Especially, we studied the effect of lithological and rock physical properties on the fault zone response inside a multilayer sedimentary system. Through numerical analysis, we compared four models where the complexity of the fault zone internal architecture is considered. Results show how the presence of hydromechanical heterogeneity influences the pressure diffusion, as well as the effective normal and shear stress evolutions. The more complex the fault zone architecture is and the more heterogeneities that are present, the faster the pressurization within the damage zone occurs. But, these hydromechanical heterogeneities (i) strengthen the fault zone resulting in earthquake of smaller magnitude, and (ii) impede fluid migration along the fault. We also show that the effects of the hydromechanical heterogeneities within the reservoir are negligible relative to those between the caprock and the reservoir.
The importance of rock mechanics associated with geological storage of CO2 (GCS) is now widely recognized among GCS stakeholders, especially with respect to the potential for triggering notable (felt) seismic events and how such events could impact the long-term integrity of a CO2 repository (as well as how it could impact the public perception of GCS). To date, no notable seismic event has been reported from any of the current CO2 storage projects, although unfelt microseismic activities have been detected by geophones. However, potential future commercial GCS operations from large power plants will require injection at a much larger scale. For such large-scale injections, a staged, learn-as-you-go approach is recommended, involving a gradual increase of injection rates combined with continuous monitoring of geomechanical changes, as well as siting beneath a multiple layered overburden for multiple flow barrier protection, should an unexpected deep fault reactivation occur.
Lee, Jaewon (School of Mining Engineering, The University of New South Wales, Shahid Bahonar University of Kerman) | Min, Ki-Bok (Department of Energy Systems Engineering, Seoul National University) | Rutqvist, Jonny (Earth Sciences Division, Lawrence Berkeley National Laboratory)
Coupled flow and geomechanics play an important role in the analysis of gas-hydrate reservoirs under production. The stiffness of the rock skeleton and the deformation of the reservoir, as well as porosity and permeability, are directly influenced by (and interrelated with) changes in pressure and temperature and in fluid- (water and gas) and solid- (hydrate and ice) phase saturations. Fluid and solid phases may coexist, which, coupled with steep temperature and pressure gradients, results in strong nonlinearities in the coupled flow and mechanics processes, making the description of system behavior in dissociating hydrate deposits exceptionally complicated.
In previous studies, the geological stability of hydrate-bearing sediments was investigated using one-way coupled analysis, in which the changes in fluid properties affect mechanics within the gas-hydrate reservoirs, but with no feedback from geomechanics to fluid flow. In this paper, we develop and test a rigorous two-way coupling between fluid flow and geomechanics, in which the solutions from mechanics are reflected in the solution of the flow problem through the adjustment of affected hydraulic properties. We employ the fixed-stress split method, which results in a convergent sequential implicit scheme.
In this study of several hydrate-reservoir cases, we find noticeable differences between the results from one- and two-way couplings. The nature of the elliptic boundary value problem of quasistatic mechanics results in instantaneous compaction or dilation over the domain through loading from reservoir-fluid production. This induces a pressure rise or drop at early times (low-pressure diffusion), and consequently changes the effective stress instantaneously, possibly causing geological instability. Additionally, the pressure and temperature regime affects the various phase saturations, the rock stiffness, porosity, and permeability, thus affecting the fluid-flow regime. These changes are not captured accurately by the simpler one-way coupling. The tightly coupled sequential approach we propose provides a rigorous, two-way coupling model that captures the interrelationship between geomechanical and flow properties and processes, accurately describes the system behavior, and can be readily applied to large-scale problems of hydrate behavior in geologic media.