Containment of a Vertical Tensile Region During Surfactant-Polymer Injection
- Elizabeth Zuluaga (Chevron) | Joseph H Schmidt (Chevron) | Rick Dean (Chevron) | Carlos W. Pardo (Chevron)
- Document ID
- Society of Petroleum Engineers
- Journal of Canadian Petroleum Technology
- Publication Date
- July 2010
- Document Type
- Journal Paper
- 60 - 66
- 2010. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 5.5 Reservoir Simulation, 2.4.3 Sand/Solids Control, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 2.5.2 Fracturing Materials (Fluids, Proppant), 6.5.2 Water use, produced water discharge and disposal, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.6.1 Open hole/cased hole log analysis, 1.2.2 Geomechanics, 2.5.1 Fracture design and containment
- geomechanics, hydraulic fracturing
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- 388 since 2007
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Many studies have been completed concerning 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 (GMRS) that could also fully incorporate the effects of fluid-flow into the analysis. This paper introduces results from a new coupled in-house 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 the simulator 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.
A half unit of a seven-spot pattern was evaluated by using an unstructured grid, which provided more geometric flexibility. The results indicated that injection rates higher than 4000 B/D (0.0074 m3/s) combined with viscosities greater than 10 cp (0.01 Pa-s) will cause the fracture to break into the shales penetrating into the bottom sand. On the other hand, injection rates lower than 2000 B/D (0.0037 m3/s) were shown to be safe, even for the highest viscosity injection fluid tested, viz 30 cp (0.03 Pa-s). Viscosities greater than 20 cp (0.02 Pa-s) cause the injection fluid to break into adjacent sands if flow rates are above 2000 B/D (0.0037 m3/s). As expected, the higher the viscosity and 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 provide safe conditions for surfactant-polymer injection.
|File Size||768 KB||Number of Pages||7|
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