Abstract

The geomechanical properties of an unconventional reservoir or shale, especially the minimum in-situ stress and fracture gradients, are important for several applications such as mud weight optimization and completion design. Two common methods of direct stress testing are using a wireline formation tester (WFT) with straddle packers and surface-pressure-based fracture injection tests (FITs).

Microfracturing was performed at several depths using a WFT in tight clastic and shale oil formations in a well in west Texas. In the same well, microfracturing was also performed using the FIT method, and hence, the two results could be compared. Imaging logs show many drilling-induced fractures in the target intervals, but formation testing with straddle packers did not provide any successful pressure measurements or formation fluid samples because of the low permeability and lack of a natural fracture network in the near-wellbore region. However, fractures were successfully induced in multiple zones by using the WFT microfracturing tool, and the results compare favorably with the geomechanical logs. Downhole quartz pressure gauges used with the microfracturing are very sensitive and can be used to calibrate surface-pressure-based FITs. Microfractures can be induced with less than a few gallons of drilling mud, and the pressure response is observed downhole without any frictional losses or time lag. In addition, the closure time derived from microfracturing is much shorter than the surface FIT-based closure time; however, microfracturing entails additional rig time.

In-situ stresses control the orientation and propagation direction of hydraulic fractures. Microfractures are tensile fractures that open in the direction of least resistance. These fractures are also affected by hoop stress in the near-wellbore region, drilling induced fractures, and borehole breakouts. Results indicate that stress gradients, which vary widely across the basin and lithofacies, are controlled by local and regional stresses. The stress gradients derived from microfractures are compared to sonic-log derived gradients and indicate that a symbiotic relation exists in calibrating and quality controlling sonic logs, image logs, and microfracture testing.

Intervals with drilling-induced fractures that extend beyond 3 feet tend to give lower stress gradients from microfracture testing and these zones should be avoided for microfracturing. Existing natural open fractures reduce the ability of the WFT tool to seal against the borehole and to create and propagate a fracture in the formation. The location of unaltered formation should be promptly identified for testing prior to entry into the borehole. This may entail having wellsite interpreters as data transmission speeds can pose a constraint while uploading and interpreting image logs offsite. Sonic-log-derived models for stress gradients can be calibrated with pore pressure and overbalance from WFT. Stress gradients generated from microfracture testing can be used to calibrate parameters such as Biot's constant in the sonic stress gradient models derived from poroelastic theory. Ideally, several lithofacies should be targeted for microfracturing to provide a representative stress profile. Imaging logs run after microfracturing can give an indication of the extent and direction of microfractures.

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