Journal of Canadian Petroleum Technology
Volume 49, Number 7, July 2010, pp. 60-66

SPE-139431-PA

Containment of a Vertical Tensile Region During Surfactant-Polymer Injection

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DOI  More information 10.2118/139431-PA http://dx.doi.org/10.2118/139431-PA

Citation

  • Zuluaga, E., Schmidt, J.H., Dean, R.H., and Pardo, C. 2010. Containment of a Vertical Tensile Region During Surfactant-Polymer Injection. J Can Pet Technol  49 (7): 60-66. SPE-139431-PA. doi: 10.2118/139431-PA.

Discipline Categories

  • 6.4.6 Chemical Flooding Methods Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex)
  • 6.5.1 Simulator Development
  • 5.3.3 Hydraulic Fracturing and Gravel Packing

Keywords

  • hydraulic fracturing, geomechanics

Summary

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.

© 2010. Society of Petroleum Engineers

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History

  • Original manuscript received: 18 December 2007
  • Meeting paper published: 18 June 2008
  • Revised manuscript received: 5 May 2010
  • Manuscript approved: 7 May 2010
  • Published online: 1 July 2010
  • Version of record: 1 July 2010