Lot of attention has been placed in the evaluation of fracture height growth during hydraulic fracturing. While there are analytical solutions available to estimate vertical fracture growth, a more comprehensive solution requires the use of coupled geomechanics-reservoir simulators that could also fully incorporate the effects of fluid flow into the analysis. This paper introduces results from a coupled geomechanical/reservoir simulator, GMRS?, to estimate the extent of vertical tensile regions developed in the sand interval that could break into adjacent shales during surfactant-polymer injection for a well located onshore Asia. The reservoir was treated as an elastic material and the injection zone was treated as a zone of higher permeability after the weakly consolidated formation reached a tensile stress state.
The geomechanical information for GMRS was obtained from triaxial tests, well logs, and minifracs. Reservoir and fluid data were extracted from the in-house reservoir simulator model available for the field (CHEARS).
We evaluated half unit of a seven spot pattern by building an unstructured grid, which provide more flexibility in terms of geometry. The results indicated that injection rates higher than 4000 B/D combined with viscosities greater than 10 cp will cause the fractures to break into the shales, reaching the bottom sand. Additionally, injection rates lower than 2000 B/D were shown to be safe even for the highest viscosity tested, viz 30 cp. Viscosities greater than 20 cp will cause the injection fluid to break into adjacent sands if the flow rates are above 2000 B/D. As expected, the higher the viscosity and the injection rate, the higher the tendency of the fractures to grow out of containment. A chart with safe limits for surfactant-polymer injection was provided to the business unit to guide them in the design of new injectors and conditions for safe surfactant-polymer injection.
Modeling fracture growth is the main goal of fracturing modeling. The growth of fractures in layered reservoirs has been mainly attributed to the minimum in-situ stress contrast; while the Young's modulus contrast has considered only secondary in importance. (Warpinski et al, Hongren and Siebrits, Liu et al., 1998). Some parameters that have been found to play important roles in fracture growth are listed as:
Shear stress at the interface (Hanson et al)
Elastic properties, in-situ stresses and pressure gradients
Joints, faults and bedding planes
Intefacial slippage
In laminated sand and shale sequences, Miskimins and Barree (2003) indicate slippage at the boundaries, rock mechanics property contrast; in particular contrast in Young's Modulus values for the sand and shales, and contribution of differences in poroelasticity for shale and sand as the most significant parameters in laminated reservoirs.
Pump rate and rheologic parameters of the injecting fluid have also been found to affect height propagation (Liu, S. et al., 1998)
There are no many tools available to model the mechanics of a plethora of individual fractures in a reservoir condition.