Your account already exists. Please login first to continue managing your settings.
Current passive seismic monitoring of hydraulic fracture operations puts the spotlight on the Marcellus shale.
In today’s burgeoning operations to recover gas from shale plays such as the Marcellus in the eastern US, the benefit of monitoring hydraulic fracturing using passive seismic recording from surface or near-surface arrays is being increasingly acknowledged.
The reason for the rise of surface and shallow buried-array microseismic monitoring – “tracking the fracing” – is that it acts as an extremely cost-effective enabler for shale operators to better understand the impact of hydraulic fracturing over a much wider area of the reservoir than was previously possible. Real-time data collection allows operators to make more informed reservoir management decisions on key issues such as drainage, well spacing, and completions without the distance or detection bias of legacy technologies such as downhole monitoring arrays. This ultimately leads to more profitable production. Monitoring on this field-wide scale also can provide early warning of potential geological hazards such as faults, karst collapse features, and the proximity of deep water-bearing formations that could compromise well production.
Less than five years ago frac monitoring relied on established but limited technology, necessitating the costly drilling of special monitoring wells separate from the producing borehole. This type of monitoring using seismic recording equipment in the borehole can only provide effective imaging of hydraulic fracturing activity in the immediate vicinity of the producing well, a distance of not much more than 500 m (1,500 ft). It is unable to deliver a field-wide picture of how a formation is responding to the injection of frac fluids and proppants.
In contrast, MicroSeismic’s technique for the Marcellus and other US shale plays can map the impact of every hydraulic fracturing stage across the whole reservoir. Developed from techniques used for the detection of earthquakes, MicroSeismic deploys a series of geophones to record events in the subsurface caused by drilling and production operations. In this way multiple simultaneous frac operations can be monitored in real time over the required reservoir coverage area.
Passive seismic emission tomography (PSET) mapping and analysis technology processes this acquired data by focusing event energy so the location of microseismic events can be identified across a field with a high degree of accuracy. The deployment of many geophone stations overcomes the issue of signal attenuation by the overburden that makes conventional seismological earthquake location techniques ineffective. With PSET it is possible to use the dense array of geophones to “beam-steer” or sum the output of the entire array to locate the microseismic activity deep below the earth’s surface. Comparing where and when the events took place with the pressure, slurry rate, and proppant density at the same moment provides the evidence of how well the formation is being stimulated.
There is both a temporary and a proprietary life-of-field implementation for microseismic monitoring of hydraulic fracturing. FracStar uses a temporarily deployed-on-surface array of geophones to monitor long laterals and pad drilling over a large area. The array’s large aperture and PSET-based microseismic monitoring can image how the stimulation-induced fractures interact with a reservoir’s natural fracture networks. The BuriedArray system comprises an array of geophones permanently installed and buried at a depth of between 60 m and 300 m (200 ft and 985 ft) for those operators who need to monitor multiple wells over a long period for strategic planning and development purposes.
Monitoring the Marcellus
Microseismic monitoring has proven to be very effective in optimizing well deliverability from Marcellus shale and provides a good illustration of the issues and how they can be resolved. Marcellus shale is lower Devonian in age, and two different deformation episodes created regional joint sets J1 and J2. J1, formed as a result of tectonic stress during the pre-Alleghanian Orogeny (responsible for the Appalachian mountains) and a change in the direction of the maximum horizontal stress ( S Hmax ) during the late Alleghanian, led to the formation of the younger J2 joints. The two joints are usually found perpendicular to each other within the basin and are associated with increased pore pressures from hydrocarbon generation.
A complicating factor for interpreting failure in the Marcellus shale is that the J1 joint is usually parallel to S Hmax . So one question arises as to whether new hydraulic fractures are being generated parallel to S Hmax or whether J1 joints are being activated (Figure 1).
Identifying and differentiating between fracture stimulation and fault activation turns out to be a crucial distinction in which micro-seismic technology can play a significant role. The idea of a frac job is to stimulate an existing network of natural fractures. But of course it is not always that simple.
To understand why, the source mechanisms at work must be identified: This is the characterization of the instantaneous deformation of the rock at the location of the event, considered as a point source of failure. The primary types of source mechanisms that are of interest in hydraulic fracturing are the shear failure and tensile failure sources. Tensile failure occurs when the rock gets opened up by the frac and is the expected type of rock breaking for hydraulic fracturing of rock that is not naturally fractured. Shear failure is typically associated with geological faulting and fracture reactivation, the latter being the desired outcome of the stimulation.
The three types of faulting modes – normal faulting, strike-slip faulting, and reverse faulting – relate to three different earth stress states as shown in Figure 2. Examination of the source mechanisms identifies which of these stress states were at work during the treatment, and only the field-wide and large-area microseismic monitoring can provide the information required to determine the source mechanisms consistently over all the monitored wells. Figure 3 summarizes the source mechanism groups that can be observed from just one project.
Figure 4 shows the microseismic result for some wells in the Marcellus with events colored by two broad categories of shear failure types: dip-slip and strike-slip. Most of the events are actually oblique-slip, but they have been categorized by the dominant component. This is just an example of the multiple source mechanisms data that, with more detailed analysis, can be used to model a possible stress state to explain observed slip directions.
Being able to identify the source mechanisms provides the information needed to do the stress inversion. By analyzing the slip directions and failure plane orientations, stress orientations can be determined. In the same way that stress states that led to deformation episodes over millions of years in geologic time can be identified, different stress states also can be identified during the frac over a few hours of treatment time.
Looking statistically at the timing of the different source mechanisms, the frequency of dip-slip source mechanisms is relatively higher at the beginning of the frac treatment, indicating that the vertical stress is the maximum stress. In this case the J1 joint sets are being reactivated in dip-slip at the beginning with some oblique-slip failure also occurring. Near the end of the frac treatment, strike-slip source mechanisms are more frequent, indicating that the maximum stress is horizontal near the end of the treatment stage. In other words, the vertical stress is the maximum stress at the beginning of a treatment stage, and at that time the J1 joints are being reactivated. As the treatment progresses and the maximum stress becomes horizontal, strike-slip failure occurs on both J1 and J2 joints.
But this still does not tell the full story of what is actually happening in the reservoir. Figure 6 shows a horizontal well bore with fracture orientations typical for the Marcellus shale and a well bore roughly perpendicular to S Hmax . J1 joints are northeast-southwest, and J2 joints are northwest-southeast. When the hydraulic fracture initiates and grows toward S Hmax , it can expand with the increased pressure. As the J1 joints expand, the horizontal stress increases so that it can eventually become greater than the vertical stress. Also, as the J1 joints open up, fracture interactions can occur that lead to strike-slip failure on J2 joints as the expanding J1 joints intersect them. The result is reactivation on both existing natural fracture planes. Since both planes are reactivated, more surface area can be generated, increasing the amount of hydrocarbons that can be delivered to the well bore via the fracture network. The result is a complex frac that improves well production. With this picture, microseismic monitoring has done its job.