With the advent of horizontal drilling and fracturing low-permeability reservoirs to produce hydrocarbons, it has become common practice within most fields to drill wells in the direction of minimum horizontal stress in a normal stress region to maximize production and minimize drilling risk. The primary reason for this is that induced fractures tend to propagate along the plane containing the intermediate and maximum stresses (typically overburden and maximum horizontal stresses in a normally stressed region), which, under these conditions, is perpendicular to the horizontal wellbore. This allows for maximum extension away from the wellbore into the reservoir allowing for maximum reservoir contact by the induced fractures. This has been consistently demonstrated to provide the maximum coverage. However, it is sometimes the case that wells are drilled at an azimuth that is not in line with the minimum stress. This might be due to such things as irregular lease boundaries or perhaps even variations in localized stress regimes that cause the stress direction to shift from the expected regional stress directions. These changes in a drilled well's azimuth with respect to minimum in-situ stress can have a significant effect on stimulation effectiveness and, eventually, the estimated ultimate recovery (EUR) of the wells. A study of off-azimuth drilling addressed issues of how to determine minimum stress direction, the effect of such drilling on wellbore stability and the safe mud-weight window, how the completion design might be affected, and how to estimate the expected changes in productivity. Theoretical and empirical data were used to quantify these effects; data used included wireline logs, publicly available production data, microseismic data, and computer simulations, with a particular emphasis on the Marcellus shale.

Observations of microseismic data collected during hydraulic fracturing treatments in horizontal wells often show variations in the numbers of events and/or the locations of the events that cannot be attributed to differences in the treatment schedule, local variations in geology, or rock properties. These variations might be related to induced stresses from previously completed hydraulic fracturing treatments in the same well or in nearby offset wells. The responses to local changes in stress can be difficult to visualize. A method to identify and evaluate the possible influences of induced stress using seismic moment is proposed. Seismic moment is a measure of the intensity of the energy release that is detected as a microseismic event. Moment values can be related to the strains resulting from the deformation that produced the microseismic event. A simple summation of the moment values provides a measurement of the total deformation associated with the microseismic events and is used to compare the microseismic responses of offset fracturing treatments. The cumulative moment responses can be compared to both the separation between consecutive stimulation treatments and the intervening time between those treatments. Two case histories are used to illustrate the observed responses. The first example highlights the effect that resting time between stimulation treatments in a single well has on the microseismic response. The second example examines the contemporaneous completion of multiple wells on a single drilling pad. The initial results presented in this paper show that microseismic responses can be affected by both the time between stimulation treatments and the distance separating offset fracturing treatments even though there appears to be little difference in the external dimensions of the event clouds. The evaluation technique used minimizes monitor well bias when the monitoring tools are deployed in nearby wells. Cumulative moment-based responses therefore provide an analytical tool that can be used to evaluate microseismic responses during hydraulic fracturing treatments that incorporates the characteristics of the microseismic events.

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