Surface based microseismic monitoring was done to assess the effectiveness of slick-water and nitrogen fracture stimulations in a horizontal well with a 3500’ lateral drilled in the Arkoma Basin of Oklahoma. Water production from this shale as well as the located events from the microseismic monitoring suggested the fracs were not contained and contacted foreign water. The observed distribution of microseismic events suggested that planar fractures were created with varying complexity. The azimuths of the produced trends suggested that a strong influence from the pre-existing natural fractures directed the induced fractures. A direct comparison of the slickwater treatment to the nitrogen treatment revealed multiple advantages with the latter, such as more in-zone events, more energy per event, and more complexity in resulting fractures.
The area monitored is located in the Arkoma Basin of Oklahoma, an area where the basin tectonics are inactive, but the weather is not. The surface array used to perform the surface monitoring of the slick-water and nitrogen treatments was designed to locate induced microseismic events by beamforming. The array consisted of 1078 stations of 12 geophones laid out in a radial pattern around the treatment well (Figure1). Although the treatments were two months apart, the array geometry was identical with the exception of removal of 11 stations from the array during the nitrogen treatment. The geophones were buried to a depth of one foot to maximize the signal to noise ratio by reducing the interference of the frequent seasonal rainfall. Cultural sources of noise such as traffic and inherent pad noises were taken into account by surface array design and seismic processing.
Seismic data was recorded over the entire array for the duration of both treatments. 25 hours of data were recorded and processed. Microseismic events induced by the hydraulic fracturing were located by a beamforming process, essentially a one-way depth migration. As with any migration process, an accurate velocity model is critical to success.
A constant velocity model was calculated for each treatment using the perforation shots as sources for calibration events. By taking a measurement of the arrival times across the array and plotting them against the distance between receivers a velocity estimate from the well depth to the surface was derived. The derived velocities were consistent with RMS velocities calculated from a sonic log of the well bore. Receiver statics were then calculated from the perforation shot arrivals and used to complete the calibration of the model. Using the calibrated model, the events corresponding to the perforation shots located to within 50 feet of their measured location in the well bore.
Figure 1: Plan view of the array. Axis units are in feet. The lateral was treated in two ways: the toe portion of the lateral was stimulated with a slick-water frac consisting of 8 stages while the heel portion of the lateral was treated with a nitrogen frac consisting of 4 stages.
Microseismic results from the monitoring of the treatments showed fracture events extending as far as 300 feet (+/- 50 feet) above the target interval for both treatments.
