Assessing the effectiveness of hydraulic fractures with microseismicity

Urbancic, Ted; Maxwell, Shawn; Zinno, R.J.

doi:10.1190/1.1817923

Cited by 3 publications

(2 citation statements)

References 2 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…We assume that both the lateral (i.e., along well) and vertical locations of the fractures are normally distributed around the sleeve location, producing an ellipsoid which extends to match the observed microseismic clouds, as well as those observed from other hydraulic fracturing sites (Urbancic et al, 2003;Chorney et al, 2016;Kettlety et al, 2019). This truncated normal distribution has a mean of 0 m, a standard deviation of 25 m, and a limit of ±100 m. For the stages with an obvious gap in microseismicity between the well and the cluster (e.g., Stage 38 and onwards), this assumes that the initial propagation and opening of fractures is mostly aseismic, and then the seismicity observed is the result of changes in stress that occur during injection, promoting slip in a more seismogenic area.…”

Section: Stochastic Hydraulic Fracture Modelmentioning

confidence: 99%

Stress Transfer From Opening Hydraulic Fractures Controls the Distribution of Induced Seismicity

et al. 2020

View full text Add to dashboard Cite

Understanding the dominant physical processes that cause fault reactivation due to fluid injection is vital to develop strategies to avoid and mitigate injection-induced seismicity. Injection-induced seismicity is a risk for several industries, including hydraulic fracturing, geothermal stimulation, oilfield waste disposal and carbon capture and storage, with hydraulic fracturing having been associated with some of the highest magnitude induced earthquakes (M > 5). As such, strict regulatory schemes have been implemented globally to limit the felt seismicity associated with operations. In the UK, a very strict "traffic light" system is currently in place. These procedures were employed several times during injection at the PNR-1z well at Preston New Road, Lancashire, UK, from October to December 2018. As injection proceeded, it became apparent to the operator that stages were interacting with a seismogenic planar structure, interpreted as a fault zone, with several M L > 0.5 events occurring. Microseismicity was clustered along this planar structure in a fashion that could not readily be explained through pore pressure diffusion or hydraulic fracture growth. Instead, we investigate the role of static elastic stress transfer created by the tensile opening of hydraulic fractures. We find that the spatial distributions of microseismicity are strongly correlated with areas that receive positive Mohr-Coulomb stress changes from the tensile fracture opening, while areas that receive negative Mohr-Coulomb stress change are quiescent. We conclude that the stressing due to tensile hydraulic fracture opening plays a significant role in controlling the spatiotemporal distribution of induced seismicity.

show abstract

Section: Stochastic Hydraulic Fracture Modelmentioning

confidence: 99%

Stress Transfer From Opening Hydraulic Fractures Controls the Distribution of Induced Seismicity

et al. 2020

View full text Add to dashboard Cite

show abstract

“…In many cases, such deployment is not experimentally feasible. Further, special software and processing are necessary; see, for example, Zoback and Harjes [1997] for the KTB experiment and Philips et al [2002] and Urbancic et al [2003] for hydrocarbon and geothermal reservoir cases. This process is time-consuming and the corresponding investment is often not justifiable.…”

Section: Introductionmentioning

confidence: 99%

A statistical model for the seismicity rate of fluid‐injection‐induced earthquakes

Parotidis

Shapiro

2004

Geophysical Research Letters

View full text Add to dashboard Cite

[1] We present a model for explaining the seismicity rate of fluid-injection-induced earthquakes. It is assumed that porepressure diffusion is the main triggering mechanism, and that the criticality of the medium is randomly distributed. Based on these and other poroelastic and stochastic assumptions, we derive equations for the induced seismicity rate during and after fluid injection. On this basis, a method is proposed for estimating hydraulic diffusivity using only the observed seismicity rate and an estimate of the activated seismogenic volume. This approach differs from previous methods in that an accurate hypocentral parameter catalog is not required. Numerical investigation of the proposed method indicates that it is relatively robust with respect to the activated seismogenic volume dimension estimate. Application of the technique to two Hot Dry Rock experiments, Fenton Hill and Soultz, produces diffusivity values that are consistent with independent estimates from prior investigations.

show abstract

Single Versus Multiwell Microseismic Recording: What Effect Monitoring Configureation Has On Interpretation

Seibel

Baig²,

Urbancic³

2011

All Days

View full text Add to dashboard Cite

Three monitoring wells with permanently installed 3C geophones were used to locate the microseismicity induced from a steam production cycle. This dataset of 52 high signal-to-noise ratio events were used to examine the location of events by progressively decimating the number sensor arrays. The three-array solutions were contrasted with different array combinations achieved by turning off one or two of the arrays. Event locations revealed the nature and magnitude of the limitations having incomplete coverage of the treatment zone. Most steam and fracture treatments are monitored by a single observation well. Parameters, such as stimulated reservoir volume fracture azimuth and fracture dimensions in treatments like CSS, hydraulic fracturing, SAG-D, are estimated from the distribution of microseismic event locations. By taking three array locations as ground truth, the array configurations that most accurately reflect the actual fracture geometry are determined. The observed distributions of the events relocated with decimated arrays show significant changes in overall fracture trend, geometry, and location accuracy. Progressive decimation of the number of arrays increases the inaccuracies of event locations, which results in the scatter of event locations. Decimation of the number of arrays changes the dimensions and azimuth of fractures, which are readily apparent upon comparison with the three-array solutions. The least biased decimated solutions are those using two arrays, one on either side of the treatment zone. Single array solutions show the most scatter, with the recording distance also controlling the degree of event mislocation. This array decimation analysis shows how the array configuration and number for arrays affect the interpreted fracture volumes, geometries, and accuracy of event location. The different viewing angles from the single and dual array decimated subsets, as well as the different distances from the event clusters to the geophones are important considerations in mitigating the biases due to limiting the recording coverage.

show abstract

Assessing the effectiveness of hydraulic fractures with microseismicity

Cited by 3 publications

References 2 publications

Stress Transfer From Opening Hydraulic Fractures Controls the Distribution of Induced Seismicity

Stress Transfer From Opening Hydraulic Fractures Controls the Distribution of Induced Seismicity

A statistical model for the seismicity rate of fluid‐injection‐induced earthquakes

Single Versus Multiwell Microseismic Recording: What Effect Monitoring Configureation Has On Interpretation

Contact Info

Product

Resources

About