Laboratory Study of Diversion Using Polymer-Based In-Situ-Gelled Acids
- Ahmed M. Gomaa (Texas A&M University) | Mohamed A. Mahmoud (Texas A&M University) | Hisham A. Nasr-El-Din (Texas A&M University)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- August 2011
- Document Type
- Journal Paper
- 278 - 290
- 2011. Society of Petroleum Engineers
- 3.2.4 Acidising, 5.8.7 Carbonate Reservoir, 4.1.2 Separation and Treating, 1.10 Drilling Equipment, 1.6.9 Coring, Fishing
- production and operations
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- 772 since 2007
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In-situ-gelled acids that are based on polymers have been used in the field for several years and were the subject of many laboratory studies. These acids are used in stages to block the treated zone and force the next regular-acid stages to the untreated zones. An extensive literature survey reveals that there are conflicting opinions about using these acids. On one hand, these acids were used in the field, with mixed results. On the other hand, recent laboratory work indicated that these acids can cause damage under certain conditions.
The ability of polymer-based in-situ-gelled acids to divert regular acids was studied using a parallel-coreflood setup. The sequence of the injection involved in-situ-gelled acid at 5 wt% hydrochloric acid (HCl) stage followed by regular acid at 15 wt% HCl until acid breakthrough. Experimental results show that flow was initially distributed between the two cores according to the preacid permeability ratio. Permeability grew slightly faster in the higher-permeability core until breakthrough occurred. Therefore, diversion was needed for all acid treatments. At an injection rate of 1 cm3/min, in-situ-gelled acid plugged the two cores. For low permeability contrast (1:2), polymer was able to divert the acid, with permeability enhancement in both cores.
For high permeability contrast (1:20 up to 1:25), in-situ-gelled acid was able to divert the acid only at an injection rate less than 10 cm3/min. However, at higher injection rates, in-situ-gelled acid was not able to build enough pressure to force the regular acid into the low-permeability core. Increasing the injection rate reduced the viscosity of the in-situ-gelled acid. Therefore, acid-injection rate should be determined on the basis of the expected fluid viscosity in the formation. The results obtained can be used to design acid treatments in carbonate reservoirs better.
|File Size||1 MB||Number of Pages||13|
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