Passive microseismic monitoring is a technology that exploits naturally occurring microearthquakes, or microseismic events, to evaluate hydraulic fracture propagation. The importance of this technology is that it can provide real-time assessments of the fracturing process for the operator and stimulation engineer while the job is underway. As a result, operators can optimize their infill drilling program, improve their subsequent frac jobs and minimize the uncertainty in their fracturing programs.

Applications of passive microseismic monitoring include mapping the extent of fractures

Figure 1. ExactFrac mapping showing near-symmetrical bi-wing fracture with minimal out-of-zonal fracture height growth. (Images courtesy of Halliburton)
during hydraulic fracture treatments, fault mapping, and tracking a gas or water front for assisted recovery production. In order to improve on the application of 3-D hydraulic fracturing modeling and processes, the location and growth of hydraulic fractures in real time must be known in terms of fracture azimuth, length of each wing, height and growth history. To accomplish this goal, each microseismic event detected by the seismic acquisition system during a stimulation treatment is transferred to a second computer system to determine the location of the event in time and XYZ coordinates with respect to the treatment well bore, then time-stamped to the real-time stimulation job data (treating pressure, rate, proppant concentration, etc.).

Fracture monitoring
Fracture monitoring using microseismic technology was conceived approximately 40 years ago as an extension of fault movement monitoring. This technology has enjoyed resurgence during the last 10 years due to technology developments in borehole seismic sensors.
Articles published in the mid-1980s discuss hydraulic fracture monitoring using a triaxial geophone located in the same borehole in which the hydraulic fracture treatment was being applied. Monitoring in the same borehole creates many obstacles: microseismic monitoring cannot be performed during pumping due to the background noise of the treating fluid flowing past the seismic sensors and the required reduction in injection rate due to the string of tools in the well bore. Monitoring in the same well bore as the treatments can only be performed after pumping, and the events are generally located in the far field.
However, current technology generally prefers a two-well process for hydraulic fracture monitoring. On pad locations, a single monitor well can be used for multiple well stimulation operations.

To exploit the benefits of passive microseismic monitoring, Halliburton recently developed ExactFrac technology, which combines logging and borehole seismic technologies with the science of microearthquakes to allow the monitoring of fractures while they are created. Thus, fracturing engineers can obtain the answers they require from this new approach to logging that offers both dipole sonic used for the pre-stimulation vertical stress profile modeling and the velocity profile for the borehole seismic modeling.

The system is based on proven borehole seismic sensor technology and has been designed for use in open and cased holes using standard seven-conductor cable. An array of 3-in. outer diameter (OD) downhole geophone sensors rated at 20,000 psi and 354°F (179°C) are available to be used in hole sizes from 3 1/2 in. to 22 in. A special high-pressure version can be used for pressures up to 25,000 psi. Sensors with a temperature rating of 400°F (204°C) will be available later this year.

Job execution
Generally, the seismic acquisition and processing software system is set up the day before the fracture treatment is to be performed in the monitor well. During emplacement of the
Figure 2. ExactFrac mapping of a bi-wing fracture with extensive vertical out-of-zonal growth due to probable fracture propagation along a fault plane.
seismic receiver array in the borehole, the individual geophones are clamped to the wall of the casing by an internal mechanism. The orientation of the individual tri-axial sensors can be on any fixed X-Y direction. Pre-job set-up requires conducting perforation or string shots in the treatment well and recording the resulting waveform in the monitor well. This process of mathematically rotating the individual geophone sensors to a standard reference direction is known as “orientation.” If a perforating or string shot cannot be performed, a surface vibroseis truck can be used for the orientation process.

Several methods including direct downhole measurement or purposeful source activation (“shooting”) are available to obtain the angular information used in the orientation process. In any case, software implementation of the fracture monitoring processing system allows for, and can use, the orientation provided by the seismic software processing system, or optionally the orientation can be recomputed for any number of perforations or frac stages.

During a hydraulic fracturing treatment, the borehole sensors in the monitor well detect the sound generated from the changes in stress and pore pressure associated with hydraulic fracture propagation. This seismic event is detected by an array of triaxial receivers situated in a monitor well at a depth comparable to the microseismic “events.” The compressional (primary or P) and shear (secondary or S) waves from the events are detected, and the location of the events (X-Y-Z distance and azimuthal orientation) from the treatment well are determined in real time. Because these microseisms are extremely small, sensitive and accurate receiver systems are used to obtain valid results.

Background noise and microseismic events are continually recorded by the borehole seismic array and transmitted uphole by the seismic acquisition system for processing and analysis during and after the frac treatment. Such spurious information continues for a period of time after the pumping operation has ceased until no additional events are detected. While the data is acquired, events detected by the acquisition system are processed on a second computer, which allows real-time event location and optimization of the processing parameters. It should be noted that seismic acquisition event detection is generally quite simple and is based upon both P-wave and S-wave arrivals.

Also, the availability of a second computer provides the onsite “frac monitoring system” the
Figure 3. Using the ExactFrac service to monitor the fracturing processes, Halliburton’s experts optimize frac programs, future well locations and field development.
option of re-analyzing all complete data records using later-in-time optimized processing parameters. Alternatively, the system can analyze just selected data acquisition segments, typically of 1 second duration, for which an event has been detected by the acquisition system. The time-stamped mcroseismic event locations with respect to the treatment well are transmitted to the wellsite stimulation tech command center and to the client’s office.

Case histories
Fracturing interbedded sandstones. A major operator was seeking more accurate placement of his fracturing treatments in a reservoir that consisted of many thousands of feet of interbedded sandstones and shale sequences. Lenticular sandstones can be referred to as stratigraphic plays and are often difficult to correlate from well to well. A simple geological explanation is to picture the sand bodies as stacked ellipsoids with random symmetry with respect to the well bore.

After consideration of his options, the operator selected the new technology to map his stimulation treatments. The mapping of the many stimulation stages provided a 3-D picture of the reservoir and of the fracture drainage patterns.

As a result of the mapping, many asymmetrical fracture wings were shown that described the limited lateral extent of some of the sand lenses from the well bore along the strike of the fracture azimuth. The fracture height correlated with the thickness of many of the sand members. This allowed the operator to identify locations for future well placement for reservoir recovery optimization. Additionally, the mapping of the out-of-zonal fracture height between successive stages identified probable fault planes in the reservoir.

Poor wellbore communication. Plagued by previous fracturing treatments that resulted in poorly stimulated zones, this independent operator was seeking answers and a solution.
Convinced the new technology could provide insight into the problem, the operator elected to apply the technology to monitor hydraulic fracture propagation in a horizontal well. Seismic sensors were installed in a nearby vertical well for the monitoring. The completion design specified seven stages equally spaced from the toe to the heel of the horizontal section. External casing packers (ECPs) and ball-operated sliding sleeves were used for well bore isolation and access to the formation.

The real-time fracture monitoring indicated poor communication along the wellbore due to probable ECP-related issues. Microseismic events were detected in two different sands while fracturing through one sliding sleeve. The mapping of the fractures identified shorter- than-anticipated fracture half-lengths due to the inadvertent simultaneous stimulation of two sands. Knowledge gained from the mapping allowed subsequent fracture treatments to attain improved production from fractures in the same formation.

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