SPE Journal
Volume 16, Number 4, December 2011, pp. 993-1001

SPE-128047-PA

Propagation and Retention of Viscoelastic Surfactants Following Matrix-Acidizing Treatments in Carbonate Cores

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DOI  More information 10.2118/128047-PA http://dx.doi.org/10.2118/128047-PA

Citation

  • Yu, M., Mahmoud, M.A., and Nasr-El-Din, H.A. 2011. Propagation and Retention of Viscoelastic Surfactants Following Matrix-Acidizing Treatments in Carbonate Cores. SPE J.  16 (4): 993-1001. SPE-128047-PA. http://dx.doi.org/10.2118/128047-PA.

Discipline Categories

  • 5.3 Production Enhancement

Keywords

  • Production and Operations

Summary

Viscoelastic surfactants have been used extensively in the field. They have the ability to form long rod-like micelles with an increase in pH and calcium concentration, which results in increasing the viscosity and elasticity of partially spent acids. There is ongoing debate in the industry about whether the gel generated by these surfactants causes formation damage, especially in dry-gas wells. The objectives of the present study are to quantitatively determine surfactant retention in calcite cores and assess the benefits of using mutual solvents to break the surfactant gel formed inside the cores.

Coreflood tests were performed using Pink Desert limestone cores (1.5 in. in diameter and 20 in. in length). The cores were injected with a surfactant-based acid that contained 15 wt% HCl, 7 vol% viscoelastic surfactant, and 0.3 vol% corrosion inhibitor. Coreflood tests were conducted at a constant injection flow rate ranging from 1.5 to 40 cm3/min. Surfactant and calcium concentrations were measured in the injected acid and core effluent. Mutual solvent (ethylene glycol monobutyl ether) was used in several tests to break surfactant gel.

Propagation of viscoelastic surfactants in linear calcite cores was found to be a function of flow rate. Surfactant lagged calcium in the core effluent samples, especially at low flow rates. The volume of acid needed to break through the core and the amount of surfactant retained varied with acid injection rate, and exhibited a minimum at 10 cm3/min. A significant amount of surfactant was retained in the cores. Injection of 2 pore volumes (PV) of 10 vol% mutual solvent removed only 20% of the surfactant injected. Based on these results, there is a need to use internal breakers when surfactant-based acids are used in dry-gas wells or water injectors.

© 2011. Society of Petroleum Engineers

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History

  • Original manuscript received: 24 November 2009
  • Meeting paper published: 11 February 2010
  • Revised manuscript received: 26 July 2010
  • Manuscript approved: 3 March 2011
  • Published online: 7 July 2011
  • Version of record: 23 December 2011