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.
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.
The increase in temperature due to the steam injection during SAGD acts to reduce the elastic moduli of oil sands and may induce shear dilation and consequent permeability increase. This would enhance the steam chamber growth, increasing the efficiency of bitumen production. Motivation of this study is to quantitatively understand the evolution in the oil sand’s elastic properties as well as strain-induced permeability increase during SAGD process. Rock physics modeling was conducted for the investigation of elastic properties of oil sand. Assuming pure quarts and bitumen as the two end members, the lower Hashin-Shtrikman bound underestimates the measured P-wave velocity. This indicates that the quartz grains of oil sand are not suspended in bitumen but constitute a load-bearing framework. Based on this observation, we used the soft-sand model and calculated dry-frame elastic properties of oil sands. The effect of the pore-filling bitumen on the elastic properties is quantified by using the solid substitution. The temperature dependent elastic properties of bitumen are obtained from published data. The rock physics model offered here relates the elastic moduli of oil sand to its temperature. Dilation-induced permeability change was discussed by using core measurements of porosity and permeability. Oil sand cores are dilated when they are brought to the surface and released from the confining stress. Porosity and permeability measurements of these samples of dilated sand are cross-plotted versus each other and the theoretical Kozeny-Carman curves are superimposed on these data. This plot indicates that the Kozeny constant varies with strain where porosity is low but remains constant where porosity is high. The purpose of this study is to provide basic understanding of temperature effects on the elastic properties of oil sand and permeability changes during shear dilation to help develop a constitutive model for a prospective coupled geomechanical and fluid flow modeling of SAGD.
Sub-seismic scale permeability heterogeneity due to the existence of mud clasts can adversely affect steam chamber growth during the steam assisted gravity drainage (SAGD) process. Using stochastic approach integrating core, log and seismic data from the Athabasca Oil Sands, Canada to obtain representative permeability values for grid modeling enables reconstruction of heterogeneity with sub-seismic scale resolution for flow simulation in SAGD production forecasting.
A procedure consisting of facies modeling, mud volume modeling and permeability transformation was applied to the field data set where facies modeling addresses difficulty in discriminating between sand with mud clasts facies and sand with thin mud layers facies, and permeability transformation upscales core scale permeability to grid scale permeability. Geostatistics in combination with probabilistic neural network implementing multiple seismic attributes successfully discriminates between the existence of mud clasts and thin mud layers. Core scale permeability is upscaled to modeling grid scale permeability using flow simulation applied to mini-models generated by randomly distributing ellipsoidal objects simulating mud clasts to provide a permeability reduction curve as a function of increasing mud clast volume.