Coupled Fluid Flow and Geomechanical Modeling of Seismicity in the Azle Area North Texas

Abstract

A series of earthquakes was recorded along a mapped fault system near Azle, Texas in 2013. To identify the mechanism of seismicity, coupled fluid flow and geomechanical simulation is carried out to model fluid injection/production and the potential onset of seismicity. Sensitivity studies for a broad range of reservoir and geomechanical parameters are performed and the calibrated models are used to identify controlling mechanisms for seismicity in the Azle area, North Texas and its relationship to hydrocarbon production and fluid injection in the vicinity. Geologic, production/injection, and seismicity data are gathered to build a detailed simulation model with coupled fluid flow and geomechanics. Geomechanical simulation results are used to calculate cumulative seismic moment magnitude. Sensitivity analyses for injection well head pressure and earthquake data are performed over a range of reservoir and geomechanical parameters. Influential parameters are selected to perform a pareto-based multi-objective history matching of well head pressures and seismic moments. Geomechanical interaction has significant impact on seismicity in the Azle area. Unbalanced loading (overall injection and production) on different sides of the fault generates accumulation of strain change, resulting in the onset of seismicity. Previous studies seem to have significantly underestimated the fluid withdrawal rates, almost by an order of magnitude. The equivalent bottom-hole fluid rate used in this study suggests a drop in reservoir pore pressure which is consistent with the BHP trends. Thus, pore pressure increases may not explain the seismicity near the Azle area, as indicated in previous studies. Instead geomechanical effects and strain propagation to the basement appear to be the dominant mechanisms. The low fault cohesion and minimum horizontal stress obtained from history matching suggest that the faults must be near or at the critically-stressed state before the initiation of fluid production/injection. A sensitivity analysis indicates that the minimum horizontal stress and fracture gradient each play a critical role in the potential risk for seismicity related to fluid injection/production. Streamline flow pattern further proves that there is no fluid movement in the basement formation and the unbalanced loading from different sides of the fault is the controlling mechanism. This is the first study coupling fluid flow and geomechanics in the Azle area and the first to simultaneously calibrate the models with fluid flow and seismicity data.

Hydromechanical Controls on the Spatiotemporal Patterns of Injection‐Induced Seismicity in Different Fault Architecture: Implication for 2013–2014 Azle Earthquakes

“…Based on previous geologic characterization as well as modeling studies (Chen et al, 2020; Hornbach et al, 2015), our model consists of five layers: overburden, Marble Falls limestone, Barnett shale, Ellenburger dolomite, and basement in a 3‐D cubic domain with a length of 10 km. By linking the spatial distributions of seismic events with regional geology, a main normal fault (6 km [ L ] × 10 m [ W ] × 7 km [ H ]; N225°/65°NW), extended downdip to a depth of 8 km, and a shallower antithetic normal fault (3 km [ L ] × 10 m [ W ] × 2.1 km [ H ]; N225°/75°NE), hydraulically disconnected to the main fault, are modeled as shown in Figure 9b.…”

“… a Poroelastic and transport properties and fault characteristics are from Hornbach et al (2015) and Chen et al (2020). …”

Pore Pressure Threshold and Fault Slip Potential for Induced Earthquakes in the Dallas‐Fort Worth Area of North Central Texas

“…Chen et al. (2018), Haddad and Eichhubl (2020), and Zhai and Shirzaei (2018) added that poroelastic stress change from pore pressure increase (ΔPp) contributes. No works to date have implicated hydraulic fracturing as a direct agent of causation in the FWB.…”