Integrating induced seismicity with rock mechanics: a conceptual model for the 2011 Preese Hall fracture development and induced seismicity

Abstract

By integrating multiple datasets with relevant theory, covering fluid injection and fracturing, a conceptual model has been developed for the fracture development and induced seismicity associated with the fracking in 2011 of the Carboniferous Bowland Shale in the Preese Hall-1 well in Lancashire, NW England. Key features of this model include the steep fault that has been recognized adjoining this well, which slipped in the largest induced earthquakes, and the presence of a weak subhorizontal 'flat' within the depth range of the fluid injection, which was 'opened' by this injection. Taking account of the geometry of the fault and the orientation of the local stress field, the model predicts that the induced seismicity was concentrated ~700 m SSE of the Preese Hall-1 wellhead, in roughly the place where microseismic investigations have established that this activity was located. A further key observation, critical to explaining the subsequent sequence of events, is the recognition that the fluid injection during stage 2 of this fracking took place at a high net pressure, ~17 MPa larger than necessary. As a result, the fluid injection 'opened' a patch of the 'flat', making a hydraulic connection with the fracture network already created during stage 1. Continued fluid injection thus enlarged the latter fracture network, which ultimately extended southward far enough to intersect the steep part of the fault and induce the largest earthquake of the sequence there. Subsequent fluid injection during fracking stages 3 and 4 added to the complexity of this interconnected fracture network, in part due to the injection during stage 4 being again under high net pressure. This model can account for many aspects of the Preese Hall record, notably how it was possible for the induced fracture network to intersect the seismogenic fault so far from the injection point: the interconnection between fractures meant that the stage 1 fracture continued to grow during stage 2, rather than two separate smaller fractures, isolated from each other, being created. Calculations indicate that, despite the high net pressure, the project only 'went wrong' by a narrow margin: had the net pressure been ~15 MPa rather than ~17 MPa the induced seismicity would not have occurred. The model also predicts that some of the smaller induced earthquakes had tensile or 'hybrid' focal mechanisms; this would have been testable had any seismographs been deployed locally to monitor the activity. The analysis emphasizes the undesirability of injecting fracking fluid under high net pressure in this region, where flat patches of fault and/or subhorizontal structural discontinuities are present. Recommendations follow for future 'best practice' or regulatory guidelines. Supplementary material: Background information on the stratigraphy, structural geology, rockmechanical properties of the study region, and its state of stress, as well as theory for fluid injection, hydraulic fracturing, and Coulomb failure analysis, is available at http:

Seismicity at Newdigate, Surrey, during 2018–2019: A Candidate Mechanism Indicating Causation by Nearby Oil Production

“…Production will reduce the fluid pressure in the reservoir being pumped. Fluid pressure changes within faults are well known as a cause of anthropogenic seismicity (e.g., [9,10]); however, rather than a decrease, the causative change is usually an increase in fluid pressure as, for example, for the Preese Hall earthquake sequence in 2011, caused by injection of water under pressure during 'fracking' for shale gas (e.g., [11]).…”

Fault “Corrosion” by Fluid Injection: A Potential Cause of the November 2017 MW 5.5 Korean Earthquake

“…This analysis extrapolated in situ stress measurements made in shallower boreholes to greater depths; the data include the σ H azimuth (with the intermediate principal stress vertical) of 135 ± 3°(S45 ± 3°E) at~700 m depth from hydraulic fractures and 136 ± 4°(S44 ± 4°E) at~800 m depth from drilling-induced fractures [58], these measurements being made in Early Miocene tuff (Table 1) in a borehole~4 km SW of the Pohang EGS site. However, other case studies indicate that such extrapolation cannot be done with confidence, as the stress tensor orientation may change significantly with depth (especially between contrasting lithologies) (e.g., [21,59]), a phenomenon recognized in Korea [57]. For example, Chang et al [56] reported a typical WSW-ENE maximum principal stress and a typical vertical minimum principal stress in SE Korea from measurements in shallow (depth <350 m) boreholes.…”

“…Three dimensional geomechanics case studies such as this can in principle be analyzed trigonometrically (e.g., [61,62]). However, we have instead used a vector geometry approach [21] as this produces equivalent results with simpler calculations. Searching through the combinations of magnitudes and orientations of the principal stresses proposed by Park et al [15], the focal mechanism by Kim et al [7] (Figure 5(b)) is thus consistent with a maximum principal stress oriented at azimuth N64°E (064°) whereas that by Grigoli et al [6] (Figure 5(c)) is consistent with S76°E (114°).…”

“…In general, the Coulomb condition for shear failure can also be visualized graphically using the standard Mohr circle construction, which can be plotted on a graph of τ against effective normal stress σ N ′, defined as σ N − P f (Figure 7). Nonetheless, it should be noted that in rocks that are impermeable and fluid pressure only acts in the direction perpendicular to an existing fault, a conventional Mohr circle has no meaning and only points in Mohr circle space that correspond to the orientation of preexisting 9 Geofluids faults should be considered (e.g., [21,62]); to emphasize this, the Mohr circles in Figure 7 are drawn dashed. A fault within unaltered granite is expected to have c~0.6 (e.g., [64]; as already noted, granite cuttings from the Pohang wells have c in the range 0.54 to 0.68, with a mean value of 0.63 according to [5]).…”

“…Regarding any temporal association, full details of the subsequent injection experiments have not been reported by the developers; however, the published summary [7] includes injection in well PX-1 in August 2017 and in well PX-2 in September 2017, respectively, three and two months before the mainshock. Although physical mechanisms are known that can cause seismicity delayed following fluid injection (e.g., [20,21]), none has hitherto explained a delay as long as 2-3 months. One potential candidate mechanism, poroelastic diffusion of stress, has been proposed as the cause of "natural" seismicity with delays of months following climatic triggering (e.g., [22]).…”