Retarding HCl Acid Reactivity Without Gelling Agents, Emulsifiers, or Polymers for Low to High Temperature Acidizing Applications
- Enrique Reyes (Halliburton) | Aaron Beuterbaugh (Halliburton) | Paul Ashcraft (Halliburton) | Renata Pires (Halliburton) | Heloisa Althoff (Halliburton)
- Document ID
- Society of Petroleum Engineers
- SPE International Conference and Exhibition on Formation Damage Control, 19-21 February, Lafayette, Louisiana, USA
- Publication Date
- Document Type
- Conference Paper
- 2020. Society of Petroleum Engineers
- 4.1 Processing Systems and Design, 5.8 Unconventional and Complex Reservoirs, 5 Reservoir Desciption & Dynamics, 4 Facilities Design, Construction and Operation, 2 Well completion, 1.6 Drilling Operations, 1.6.9 Coring, Fishing, 1.6.6 Directional Drilling, 1.8 Formation Damage, 5.8.7 Carbonate Reservoir, 2.6 Acidizing, 4.1.2 Separation and Treating
- PVbt, Low injection rates, Polymer free, HCl, Anti-Sludge
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- 114 since 2007
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Placement of highly reactive stimulation fluid based on hydrochloric acid (HCl) into high temperature reservoirs or long pay intervals can be challenging and requires proper techniques to limit near-wellbore (NWB) spending, deconsolidation, and to extend the depth of fluid penetration. This is important when long laterals or interval characteristics limit injection rates away from the optimum, causing inefficient use of stimulation fluid. HCl acid, although readily accessible and widely used, can be highly problematic for far-field placement and stimulation.
The addition of a low viscosity and nonpolymeric, fully water soluble surface modifying agent into 15 to 28% HCl acid formulations generates a fluid with a very distinct interaction on a carbonate-laden matrix, facilitating the control of premature spending in the NWB area. Core flow studies using Indiana limestone (IL) demonstrated that this surface-binding agent results in minimal core face erosion and spending, a minimization of pore volume to breakthrough (PVbt), and overall improved fluid efficiency. The fluid formulations tested and corresponding results confirm them to be effective over a broad range of temperature from 150 to 300°F, porosity from 8 to 20%, permeability from 0.2 to 800 mD, and flow regimes from 0.5 to 100 mL/min, thus highlighting the flexibility and ease of use.
For all tests using the low viscosity HCl acid formulation, PVbt volumes were reduced in comparison to plain HCl acid, whereas the most notable volume reduction occurred when nonoptimal flow regimes were used. At flow rates of 1 mL/min, the formulated HCl acid fluid provides more than a five-fold PVbt reduction under similar conditions. More importantly, core face dissolution, characterized by computed tomography (CT) imaging, demonstrates that rock integrity is maintained even under extreme conditions, such as extremely low flow rate injection or temperature in excess of 300°F. On the contrary, even core flow tests performed at optimal flow rates provide a half-PVbt reduction when compared to plain HCl acid. The low viscosity HCl acid formulation has exhibited improved results across a breadth of downhole conditions that signify greater penetration and stimulation of carbonate reservoirs. Fluid compatibility with several necessary or expected HCl acid additives or stabilizers has been conducted and thoroughly tested, and such results indicate complete efficacy. Using the nonpolymeric surface agent in HCl acid fluid can provide a benefit in terms of equipment use and can facilitate stimulation treatments when pumping or completion limitations dictate low injection rates.
Helping prevent inefficient and undesired spending allows the reactive fluid to penetrate deeper into the formation, accessing more reservoir area and providing larger drainage of the stimulated reservoir while helping prevent formation damage under high temperature or low injection rates.
|File Size||7 MB||Number of Pages||11|
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