Map view of micro-seismic events shows offset from perpendicular. (All graphics courtesy of Pinnacle Technologies Inc.)

Microseismic fracture mapping has been applied in various forms for almost 30 years at the time of this writing. Today, more than a thousand fracture treatments are mapped per year in North America alone using Pinnacle’s microseismic technology. The majority of these jobs are performed in tight gas wells, but fracture treatments of higher permeability gas and oil reservoirs are also mapped in North America and around the world. Several microseismic mapping projects have recently been performed in China, using this same technology. This article presents a case study that illustrates the application of microseismic fracture mapping to a first-stage fracture treatment on a horizontal well drilled in a tight oil reservoir in the Jilin oil field. The horizontal well was drilled to target a tight, normally pressured oil reservoir with a net pay of 33 ft (10 m) at a mid-pay depth of 7,267 ft (2,215 m). The effective permeability for the target zone was estimated to be 0.5 mD and the reservoir has a porosity of 14%. The crude oil has a gravity of 35° API.

The Jilin oil field is located in the Jilin Province section of the Songliao Basin, which stretches across Heilongjiang, Jilin and Liaoning provinces in northeastern China. The Jilin oil field is a huge complex consisting of over 20 individual fields and the majority of the target zones in these fields are low permeability oil reservoirs with net pays ranging from 8 ft (2.5 m) to 66 ft (20 m), buried at depths from 1,640 ft (500 m) to 8,200 ft (2,500 m). Its first oil field was discovered in 1955, but commercial development in the Jilin oil field really began in the early 1960s. The entire Jilin oilfield complex currently produces over 40 million boe/year. Water flooding has become a viable reservoir development strategy to sustain reservoir pressure and to maximize oil recovery in these oil reservoirs. Fracture treatments are widely used to achieve economic well productivity, and are also common for injection wells to enhance water injectivity.

A lateral length of 2,625 ft (800 m) for the horizontal well was drilled with the intention to complete it with multiple transverse hydraulic fractures; namely, all the fractures would be perpendicular to the horizontal lateral. The orientation of hydraulic fractures in the region was previously estimated to be in the due West-East direction. Microseismic fracture mapping was performed from an offset vertical well to measure the azimuth and geometry of the hydraulic fracture created during the first-stage fracture treatment on this horizontal well. Microseismic fracture mapping results shown in Figure 1 indicated a fracture orientation of N74°W, which is 16° off the previous estimate. Mapping results further indicated that the treatment appeared to have extended away from the horizontal wellbore past the toe and did not grow directly adjacent to the perforation intervals. A fracture half-length of 1,378 ft (420 m) was measured on the east wing because microseismic events on the far (west wing) side of the well were harder to detect due to an observation well distance bias. An overall fracture height of 213 ft (65 m) was measured. Because the fracture grew very close to the observation well, the measurements of the fracture half-length on the east wing and the overall fracture height were obtained with high confidence. Figure 2 reveals that the fracture appeared to grow downward toward the east wing. Geologic structural data indicated that the downward trending growth was consistent with the formation dip of about 10°, which meant that the fracture grew preferably along the sand body in the reservoir.

The microseismic fracture mapping results indicated that the fracture appeared to have extended beyond the toe, about 164 ft (50 m) away from the perforations, which helped to explain near-wellbore tortuosity problems that occurred during the treatment. As shown in Figure 3, the treatment initially screened out on a small proppant slug pumped during the pad. Proppant slugs are generally very effective in reducing fracture entry friction. However, the proppant slug in this case appears to have dissipated somewhere along the poorly cemented annulus outside the casing. After the initial screenout, a series of low rate injections were initiated, but even the low-rate pumping nearly caused another screenout. The final propped treatment, consisting of 1,465 bbl of cross-linked fluid and 105,000 lb of 20/40 proppant, was successfully pumped at an average rate of 22 bbl/min, due to incorporating a number of carefully timed proppant slugs. There were thus no problems in finally placing the designed amount of proppant during the main treatment after the proppant slugs had reduced treatment friction by about 1,910 psi. As the mapping results indicated, proppant-laden slurries had to travel through a tortuous pathway from the perforation locations to the location with the lowest stress where the fracture was initiated. It was reasonable to believe that the proppant slugs had eroded away some cement debris and created a more conductive pathway outside of the casing to allow better proppant transport.

A 3-D fracture model was calibrated by matching both the measured hydraulic fracture dimensions and the net pressure behavior for the first-stage fracture treatment. As a result of the fracture modeling analysis, Figure 4 shows the fracture geometry and conductivity profile predicted by the calibrated fracture model. Although the hydraulic fracture half-length and height were very similar to the mapping results, the propped fracture geometry where proppants were placed appeared significantly smaller than the hydraulic fracture geometry: a propped half-length of 988 ft (301 m) and a propped height of 146 ft (44 m) were predicted. In addition to the smaller propped fracture geometry, the fracture conductivity predicted by the calibrated model was very low, hinting at a restricted fracture for production or injection enhancement. Reservoir modeling further indicated that doubling the fracture conductivity could increase one-year cumulative production by 50%. However, reducing the propped fracture length by half resulted in a decrease of one-year cumulative production only by 5%.

Three transverse fractures were planned for the horizontal well, with the second stage located around the middle part of the lateral and the last stage located near the heel of the horizontal well bore. The fracture treatment for the second stage was performed without microseismic fracture mapping. The treatment initially failed due to extremely high pumping pressure, but was eventually pumped with success by incorporating a number of proppant slugs. The final treatment size for the second stage was similar to that of the first stage. The planned fracture treatment for the third stage was not performed because a highly water saturated or flooded zone was encountered near the heel during drilling. After the completion of the first two fracture treatments, the well was put into production for about 20 days before converting it to a water injector. Detailed production and injection data were not available at the time of this writing.

The following lessons were learned from this investigation: 1) if transverse fractures were intended, future horizontal wells should be drilled in an orientation perpendicular to the mapped fracture orientation; this should minimize at least some of the tortuosity effects; 2) cementing quality/zonal isolation should be improved for future horizontal well completions; and 3) more viscous fracturing fluids and higher conductivity proppants should be considered for future fracture treatments, in order to increase both the fracture width and conductivity while decreasing the fracture length. E&P