Monitoring microseismicity during reservoir production and injection is an area of growing interest.

Landsat 7 image of part of western North Dakota. Two regional lineament trends are visible in the image, one oriented northeast-southwest, the other oriented southeast-northwest. These lineaments outline major structural features in the Williston Basin that influence fracture orientation during frac treatments.

The unconventional resource play has taken off like gangbusters in North America and is beginning to attract attention in Europe and the Middle East. These reservoirs often have permeabilities so low that the only thing tighter in the well is the casing, hence the need for hydraulic stimulation. Stimulations of this sort have been practiced for at least 60 years, but only with the advent of microseismic monitoring have we been able to get a realistic picture of how the rocks are actually responding to the tremendous pressures, fluid volumes, and proppant volumes that are being pumped down the well. These pictures have offered up many surprises. While not all the surprises have been good news (geology can be more complex than we would like) the value proposition of microseismic frac monitoring has been broadly recognized such that the number of jobs monitored has increased by an order of magnitude in the last five years.

As the technology of microseismic monitoring advances, one of the things that we have come to accept is that the “norm” for fracture geometry is not a
single symmetric bi-wing fracture plane extending away from the well bore. This acknowledgement of high-complexity failure mechanisms around the well bore requires some interpretation before microseismic data can be effectively used to plan stimulation and drilling programs. We now have a better understanding of what kinds of things can really happen during a hydraulic fracture treatment of a well: for instance, in most basins the way in which the rock fractures is determined by a complex interaction with the geology and the natural fracture network. Quantifying that complexity and turning the clouds of points into a geologically reasonable result represents the way to the next technological phase for microseismic technology.

Joining forces

A logical marriage between two technology disciplines can be made — fracture modeling using structural analysis and fracture mapping using microseismic monitoring. As “the other 4-D,” (see E&P March 2006), microseismic monitoring also provides information about sub-seismic scale features in a reservoir. A combination of strain analysis and seismic anisotropy attributes can provide information geologists can use to create a general picture of fracture orientations in a reservoir as well as some information about the spatial distribution of fracture intensity. But significant unknowns remain. So far no data are available that provide a direct measure of how big the fractures are.

For the structural geologist or reservoir modeler who needs to refine a reservoir fracture model, the inclusion of microseismic events as an actual location for a fracture is an exciting new development. In addition, the amplitude information of the events provides a constraint that can be used to define fracture size in a fractured reservoir model.

For hydraulic fracture treatments, the geology-based mapping can readily explain why a fracture does not form symmetrically about the well bore, or why a fracture is not perpendicular to the well bore, or even why the events line up along a trend that is not one plane. The capability to determine the polarity events allows full characterization of the type of failure that occurred during the treatment. Figure 1 shows a cross-section view of microseismic events recorded during one of the stages of a frac of a vertical well in the Barnett Shale. The events occur on only one side of the well bore, indicating reactivation of an existing fault or fracture. The distance between the well bore and the event cloud is also of interest since it indicates that the rock failure associated with the largest amplitude events does not emanate from the well bore, but occurs a few hundred feet away. A map view of the microseismic events reveals even more complexity (Figure 2). The orientation of the inferred fracture plane is east-west close to the well and then takes an abrupt bend to the southeast. Analyzed in time series, the events can be seen to originate first nearer the well bore. The southeastern trending events develop later during the treatment. The geological interpretation is one of fault interaction — two fault planes of different orientations have interacted and failed by different mechanisms within the in-situ stress field. Identifying these types of existing structures and how they will react to the frac treatment greatly improves the quality of the well development plan.

Basin deformation

In frac treatment scenarios where the microseismic events do not line up so nicely along trends, the geological context supports interpretation. In the Williston Basin, deep reservoirs and low signal impact the results of microseismic mapping to the point where visible trends for fracture orientations are difficult to detect. To add to the complications, deformation within the Williston Basin is widespread but subtle. Fault mapping from the sparse seismic lines in the basin generally does not reveal structures that could be used to guide interpretation, and the stress in the basin is low and difficult to measure. Combining surface lineament analysis with microseismic monitoring data goes a long way toward explaining the types of trends that can be seen in the data. Figure 3 shows a satellite image of central-western North Dakota where structural trends can be seen on the ground. Microseismic event mapping reveals these trends also in the subsurface.

Interpreting microseismic events as fractures in the subsurface will not only aid the effectiveness of reservoir stimulation and well planning programs, but also will be very useful for reservoir production and simulation projects. The capability to use event polarities to define fracture orientations will greatly reduce the uncertainties related to fractured reservoir modeling. When structural geologists use deformation history to model fracture development, conditions of deformation have to be inferred based on what rock properties and stress conditions are believed to have existed at the time of deformation. Most basins have undergone more than one deformation phase, leading to multiple different fracture and fault orientations.

Smaller-scale faults and fractures in a basin are not necessarily the same orientation as the large-scale features identifiable in seismic and well data. For example, in the Williston Basin, structural analysis of regional lineaments helps to explain the orientations of features that do not line up with the regional trends. The most important fractures are the ones that are open and flowing under reservoir conditions, and it is these fractures that are being identified by the microseismic mapping.

Monitoring microseismicity during reservoir production and injection is an area where great advances are currently being made. Activity can be monitored near well bores to monitor drainage efficiency. Pressure changes related to injection well activity can be monitored to make sure reservoir integrity is maintained. By turning the microseismic events into fracture planes with transmissibility properties, these data points can be used to generate permeability tensors that can, in turn, be input to reservoir simulation models to do history matching and to predict reservoir behavior.

A recent SPE Forum on Reservoir Geomechanics focused on integrating wellbore information, microseismic data, and reservoir simulation with the geologic context serving as a sort of unifying foundation. Well log analysis to determine rock material properties is well established, and the combination of these types of borehole measurements with our improved methods of rock mechanical analysis allows us to determine whether the fractures generated are new fractures or reactivated natural fractures. The extensive improvements in understanding of wellbore geomechanics can now be extended into the geology away from the well bore, leading the way for development of a fully constrained geomechanical earth model validated by data from different angles.