Microsiesmic Monitoring & Fracking: Downhole or Surface?

By Sergei Alexandrov, Viktor Mishin, Dmitry Burov, April 10, 2014

of data). For surface monitoring, companies commonly use standard toolsets with option of vertical intensity survey, for downhole monitoring – three-component multipoint digital probes with a controlled hold-down.

Technological Risks of Downhole Hydrofrac Monitoring

When planning the downhole microseismic hydrofrac monitoring, the following factors should be considered:

Large distances between the frac zone and the sensing interval in wells selected as monitoring candidates, as well as the small distances between the mouths of monitoring and frac wells.

High levels of casing vibration. Adverse reception conditions result in resonance phenomena on horizontal seismic sensors of the probe (especially on the component that is transversal to the hold-down lever of the receiving unit). For weak microseismic signals, this means significant distortion of azimuths for emission events and, consequently, errors in determining the horizontal dimensions of the fissure zone due to the “blurring” of the cluster of registered microseismic sources. Sometimes this negative factor forces the producer to use several monitoring wells instead of a single one, boosting the cost of the project.

Using wells of the old stock as monitoring wells. Generally, such wells have unfavorable environment for setting the probe and receiving seismic waves. Furthermore, monitoring in production wells or post-frac wells means that the probe must be placed much – 1 kilometer and more – higher than the target formation (as seismic ray distance is usually much larger than the distance through the formation). In this case, localization of deep microseismic sources requires special methods that provide sufficient resolution at large distances.

Presence of operating segments in the monitoring well. In these cases, the cutoff packer must be used to isolate operating segments in the monitoring well.

Noise in adjacent wells. It is necessary to suspend drilling and other noisy operations near the hydrofrac well. Improper compliance with this rule could lead to serious complications in interpretation of passive microseismic monitoring data – the study area may have a thick cloak of man-made interferences such as tube-wave noise, secondary noise sources, intensive harmonics and other interference.

Distortion between the mouths of the monitoring well and hydrofrac well. To reduce the background noise of heavy equipment running at mouth of frac injection well, it is necessary to choose monitoring well from the different cluster (if the producer uses cluster drilling technology).

And though in the case of a large offset (by layer intersection) between the frac well and monitoring well it is often possible to expand the operation distance, for example, by placing sensors at the formation level next to lower-permeability layers (i.e. waveguides), the high vibration of the casing in the sensing interval forces the operator either to seek other intervals with more favorable conditions for sensing, or to make a decision stating high-precision monitoring is not viable. Regretfully, a definitive answer to this question available only through calibration by perforation gun shots, during test calibration on sources with known coordinates.

Technological Risks of Surface Hydrofrac Monitoring

In Russia, the companies usually use the cheaper, surface monitoring systems requiring areal