The effect of fluid pressure on frictional stability transition from velocity strengthening to velocity weakening and critical slip distance evolution in shale reservoirs

Summary Shale and tight reservoir rocks have pore throats on the order of nanometers, and, subsequently, a large capillary pressure. When the permeability is ultralow (k < 200 nd), as in many shale reservoirs, diffusion might dominate over advection, so that the gas injection might no longer be controlled by the multicontact minimum miscibility pressure (MMP). For gasfloods in tight reservoirs, where k > 200 nd and capillary pressure is still large, however, advection likely dominates over diffusive transport, so that the MMP once again becomes important. This paper focuses on the latter case to demonstrate that the capillary pressure, which has an impact on the fluid pressure/volume/temperature (PVT) behavior, can also alter the MMP. The results show that the calculation of the MMP for reservoirs with nanopores is affected by the gas/oil capillary pressure, owing to alteration of the key tie lines in the displacement; however, the change in the MMP is not significant. The MMP is calculated using three methods: the method of characteristics (MOC); multiple mixing cells; and slimtube simulations. The MOC method relies on solving hyperbolic equations, so the gas/oil capillary pressure is assumed to be constant along all tie lines (saturation variations are not accounted for). Thus, the MOC method is not accurate away from the MMP but becomes accurate as the MMP is approached when one of the key tie lines first intersects a critical point (where the capillary pressure then becomes zero, making saturation variations immaterial there). Even though the capillary pressure is zero for this key tie line, its phase compositions (and, hence, the MMP) are impacted by the alteration of all other key tie lines in the composition space by the gas/oil capillary pressure. The reason for the change in the MMP is illustrated graphically for quaternary systems, in which the MMP values from the three methods agree well. The 1D simulations (typically slimtube simulations) show an agreement with these calculations as well. We also demonstrate the impact of capillary pressure on CO2-MMP for real reservoir fluids. The effect of large gas/oil capillary pressure on the characteristics of immiscible displacements, which occur at pressures well below the MMP, is discussed.

Download Full-text

Investigation on the Influence of Water-Shale Interaction on Stress Sensitivity of Organic-Rich Shale

Geofluids ◽

10.1155/2019/2598727 ◽

2019 ◽

Vol 2019 ◽

pp. 1-13 ◽

Cited By ~ 1

Author(s):

Xiangjun Liu ◽

Yan Zhuang ◽

Lixi Liang ◽

Jian Xiong

Keyword(s):

Salt Water ◽

Ordos Basin ◽

Fluid Pressure ◽

Sensitivity Coefficient ◽

Stress Sensitivity ◽

Working Fluid ◽

Water Type ◽

Natural Fractures ◽

Influence Of Water ◽

Shale Reservoirs

Shale reservoirs are characterized by low permeability and natural fractures. In the process of reservoir development, the working fluid enters the reservoir. This may result in the formation of new fractures or expansion of natural fractures. When shale reservoirs are exploited, the fluid pressure in the fracture or pore is reduced. This destroys the stress balance of the reservoir, produces stress sensitivity damage, and reduces the reservoir permeability. Organic-rich shale from the Yanchang Formation, Chang 7 Member of the Ordos Basin, was selected for core flow experiment with helium. The effects of the type of brine, salinity, and soaking time on the stress sensitivity of an organic-rich shale reservoir were investigated. The acoustic characteristics were also investigated to study the effect of interactions between water and shale on stress sensitivity. The experimental results demonstrate that the interactions of water and shale increase the permeability of shale and reduce its stress sensitivity. Furthermore, when the permeability of the shale is excessively low, the stress sensitivity is high. In the acoustic studies, a higher attenuation coefficient of the acoustic wave corresponds to a larger variation in the shale structure and thus a larger permeability of the shale and smaller stress sensitivity coefficient. Whereas there is no apparent effect of the salt water type on the stress sensitivity, higher salinity levels cause higher stress sensitivity. After reacting with 15000 mg/L brine, the stress sensitivity coefficient of shale did not decrease significantly compared with that before action, all of which were above 0.97. However, after reacting with distilled water or 5000 mg/L brine, the stress sensitivity coefficient of shale decreased significantly, and all of them decreased to less than 0.9. Longer water exposures, corresponding to an increased duration of water-shale interactions, result in higher impacts on the stress sensitivity of shale. After 6 hours of shale-brine interaction, the stress sensitivity coefficient of shale is as high as 0.93, while after 48 hours of shale-brine interaction, the stress sensitivity coefficient of shale is reduced to 0.88. This study provides a highly effective reference with regard to the influence of the working fluid on the reservoir during drilling operations and the study of reservoir characteristics after fracturing.

Download Full-text

Sensitivity of the Seismic Moment Released During Fluid Injection to Fault Hydromechanical Properties and Background Stress

Frontiers in Earth Science ◽

10.3389/feart.2021.638723 ◽

2021 ◽

Vol 9 ◽

Author(s):

Nicolas Wynants-Morel ◽

Louis De Barros ◽

Frédéric Cappa

Keyword(s):

Seismic Moment ◽

Fluid Pressure ◽

Initial Permeability ◽

Fluid Volume ◽

High Rate ◽

Fluid Injection ◽

Injection Point ◽

Dilation Angle ◽

Fault Parameters ◽

Slip Distance

Fluid pressure perturbations in subsurface rocks affect the fault stability and can induce both seismicity and aseismic slip. Nonetheless, observations show that the partitioning between aseismic and seismic fault slip during fluid injection may strongly vary among reservoirs. The processes and the main fault properties controlling this partitioning are poorly constrained. Here we examine, through 3D hydromechanical modeling, the influence of fault physical properties on the seismic and aseismic response of a permeable fault governed by a slip-weakening friction law. We perform a series of high-rate, short-duration injection simulations to evaluate the influence of five fault parameters, namely the initial permeability, the dilation angle, the friction drop, the critical slip distance, and the initial proximity of stress to failure. For sake of comparison between tests, all the simulations are stopped for a fixed rupture distance relative to the injection point. We find that while the fault hydraulic behavior is mainly affected by the change in initial permeability and the dilation angle, the mechanical and seismic response of the fault strongly depends on the friction drop and the initial proximity of stress to failure. Additionally, both parameters, and to a lesser extent the initial fault permeability and the critical slip distance, impact the spatiotemporal evolution of seismic events and the partitioning between seismic and aseismic moment. Moreover, this study shows that a modification of such parameters does not lead to a usual seismic moment-injected fluid volume relationship, and provides insights into why the fault hydromechanical properties and background stress should be carefully taken into account to better anticipate the seismic moment from the injected fluid volume.

Download Full-text