0
Research Papers: Petroleum Engineering

An Al/Zr-Based Clay Stabilizer for High pH Applications

[+] Author and Article Information
Ilham A. El-Monier

e-mail: Ilham.el-monier@pe.tamu.edu

Hisham A. Nasr-El-Din

e-mail: hisham.nasreldin@pe.tamu.edu
Petroleum Engineering Department,
Texas A&M University,
507 Richardson Building,
College Station, TX 77843

Contributed by the Petroleum Division of ASME for publication in the Journal of Energy Resources Technology. Manuscript received July 9, 2012; final manuscript received November 12, 2012; published online March 21, 2013. Assoc. Editor: Desheng Zhou.

J. Energy Resour. Technol 135(2), 022903 (Mar 21, 2013) (7 pages) Paper No: JERT-12-1159; doi: 10.1115/1.4023100 History: Received July 09, 2012; Revised November 12, 2012

Sandstone formations are exposed to a variety of high pH fluids, including: hydraulic fracturing using high pH borate gels, alkaline-based chemical enhanced oil recovery (EOR) methods, water-based drilling fluids, and cementing filtrate. High pH values can trigger fines migration, and subsequent loss of permeability and well productivity. An aluminum/zirconium-based (Al/Zr) clay stabilizer was developed to control fines migration at high pH applications. The objective of this study is to assess the effectiveness of this new stabilizer and compare its performance with commercially available stabilizers. Laboratory studies were performed using Berea sandstone (8 wt. % clays; mainly kaolinite) cores, 6 in. length and 1.5 in. diameter. Tetramethyl ammonium chloride (TMAC) and choline chloride were used for comparison as two commercial clay stabilizers. Various coreflood experiments were conducted to determine the effect of the three stabilizers on core permeability (from 64 to 100 mD) at various temperatures up to 300 °F. In these experiments, a preflush that included 2 wt. % stabilizer was injected, followed by injection of 2 wt. % NaOH solution. The latter represented high pH filtrate that can invade the formation during any treatment that includes alkaline fluids. The pressure drop across the core was measured and samples of the core effluent were collected. Inductively coupled plasma optical emission spectrometry (winlab32 software) was used to measure the concentrations of Al, Zr, Fe, Ca, and Mg. ZetaPALS (BIC software) was used to measure the surface charge on the kaolinite particles. Lab results indicated that the new clay stabilizer worked effectively up to 300 °F following 2 wt. % NaOH. No reduction in permeability was noted in any of coreflood tests using sandstone cores of various initial permeabilities. The concentrations of various cations were found to be a function of core mineralogy. TMAC and choline chloride were not effective when followed by fresh water and incompatible with the high pH fluids. The new stabilizer is environmentally friendly, and can be used in hydraulic fracturing, and alkaline-based chemical EOR methods to mitigate clay related problems.

FIGURES IN THIS ARTICLE
<>
Copyright © 2013 by ASME
Your Session has timed out. Please sign back in to continue.

References

Mungan, N., 1965, “Permeability Reduction Through Changes in pH and Salinity,” J. Pet. Technol., 17(12), pp. 1449–1453. [CrossRef]
Schembre, J. M., and Kovscek, A. R., 2005, “Mechanism of Formation Damage at Elevated Temperature,” ASME J. Energy Resour. Technol., 127(3), pp. 171–180. [CrossRef]
Valdya, R. N., and Fogler, H. S., 1992, “Fines Migration and Formation Damage: Influence of pH and Ion Exchange,” SPE Prod. Eng., 7(4), pp. 325–330. [CrossRef]
Kia, S. F., Fogler, H. S., and Reed, M. G., 1987, “Effect of pH on Colloidally Induced Fines Migration,” J. Colloid Interface Sci., 118(1), pp. 158–186. [CrossRef]
Jones, F. O., 1964, “Influence of Chemical Composition of Water on Clay Blocking of Permeability,” J. Pet. Technol., 16(4), pp. 441–446. [CrossRef]
Hibbeler, J., Garcia, T., and Chavez, N., “An Integrated Long-Term Solution for Migratory Fines Damage,” The SPE Latin American and Caribbean Petroleum Engineering Conference, Port-of-Spain, Trinidad and Tobago, Apr. 27–30, SPE, Paper No. 81017. [CrossRef]
Hayatdavoudi, A., 2005, “Formation Sand Liquefaction: A Mechanism for Explaining Fines Migration and Well Sanding,” ASME J. Energy Resour. Technol., 127(3), pp. 181–190. [CrossRef]
Bennion, D. B., and Thomas, F. B., 2005, “Formation Damage Issues Impacting the Productivity of Low Permeability, Low Initial Water Saturation Gas Producing Formations,” ASME J. Energy Resour. Technol., 127(3), pp. 240–247. [CrossRef]
Nasr-El-Din, H. A., 2005, “Formation Damage Induced by Chemical Treatments: Case Histories,” ASME J. Energy Resour. Technol., 127(3), pp. 214–224. [CrossRef]
Wojtanowicz, K., Krilov, Z., and Langlinais, J. P., 1988, “Experimental Determination of Formation Damage Pore Blocking Mechanisms,” ASME J. Energy Resour. Technol., 110(1), pp. 34–42. [CrossRef]
Reed, M. G., 1989, “Formation Damage Prevention During Drilling and Completion,” SPE Centennial Symposium at New Mexico Tech., Socorro, NM, Oct. 16–19, SPE, Paper No. 20149. [CrossRef]
Moghadasi, J., Jamialahmadi, M., Müller-Steinhagen, H., Sharif, A., Izadpanah, M. R., Motaei, E., and Barati, R., 2002, “Formation Damage in Iranian Oil Fields,” SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, LA, Feb. 20–21, SPE, Paper No. 73781. [CrossRef]
Himes, R. E., and Vinson, E. F., 1989, “Fluid Additives and Method for Treatment of Subterranean Formations,” U.S. Patent No. 4,842,073.
Patel, A., Thaemlitz, C. J., McLaurine, H. C., and Stamatakis, E., 1999, “Drilling Fluid Additives and Method for Inhibiting Hydration,” U.S. Patent No. 5,908,814.
Patel, A. D., 2009, “Design and Development of Quaternary Amine Compounds: Shale Inhibition With Improved Environmental Profile,” SPE International Symposium on Oilfield Chemistry, The Woodlands, TX, Apr. 20–22, SPE, Paper No. 121737. [CrossRef]
Smith, C., Oswald, D., and Daffin, M. D., 2006, “Clay Control Additive for Wellbore Fluids,” U.S. Patent No. 2006/0289164 A1.
El-Monier, E. A., and Nasr-El-Din, H. A., 2011, “A Study of Several Environmentally Friendly Clay Stabilizers,” SPE Project and Facilities Challenges Conference at METS, Doha, Qatar, Feb. 13–16, SPE, Paper No. 142755. [CrossRef]
El-Monier, I. A., and Nasr-El-Din, H. A., “A New Environmentally Friendly Clay Stabilizer,” SPE Prod. Oper. J. (accepted).
Masliyah, J. H., and Bhattacharjee, S., 2006, Electrokinetic and Colloid Transport Phenomena, John Wiley & Sons, Inc., New Jersey, Chap. 5.
El-Monier, I. A., and Nasr-El-Din, H. A., 2011, “Mitigation of Fines Migration Using a New Clay Stabilizer: A Mechanistic Study,” SPE European Formation Damage Conference, Noordwijk, The Netherlands, June 7–10, SPE, Paper No. 144180. [CrossRef]
Sydansk, R. D., 1982, “Elevated-Temperature Caustic/Sandstone Interaction: Implications for Improving Oil Recovery,” SPE J., 22(4), pp. 453–462. [CrossRef]

Figures

Grahic Jump Location
Fig. 2

Effect of NaOH injection into Berea sandstone at 300 °F and flow rate = 5 cm3/min. Fines were observed in the core effluent samples directly after the injection of 2 wt. % NaOH with pH = 13.

Grahic Jump Location
Fig. 3

Pressure drop across the core of 2 wt. % stabilizer A at 300 °F as a function of the cumulative injected volume at a flow rate = 5 cm3/min treated later with 2 wt. % NaOH of pH = 13

Grahic Jump Location
Fig. 4

Pressure drop across the core of 2 wt. % TMAC at 300 °F as a function of the cumulative injected volume at a flow rate = 5 cm3/min treated later with 2 wt. % NaOH of pH = 13. Fines were noticed in the samples after less than 0.5 PV of DI water.

Grahic Jump Location
Fig. 5

Pressure drop across the core of 2 wt. % choline chloride at 300 °F as a function of the cumulative injected volume at a flow rate = 5 cm3/min treated later with 2 wt. % NaOH of pH = 13. Fines were noted in the core effluent samples after 0.5 PV of DI water injection.

Grahic Jump Location
Fig. 6

Pressure drop across the core of 2 wt. % choline chloride at 200 °F as a function of the cumulative injected volume followed directly by 2 wt. % NaOH at a flow rate = 5 cm3/min. Fines were noted in the core effluent samples directly after the injection of 2 wt. % NaOH.

Grahic Jump Location
Fig. 7

Pressure drop across the core of 2 wt. % TMAC at 200 °F as a function of the cumulative injected volume followed directly by 2 wt. % NaOH at a flow rate = 5 cm3/min. Fines were noted in the core effluent samples directly after the injection of 2 wt. % NaOH.

Grahic Jump Location
Fig. 8

Zeta potential measurements on kaolinite particles (0.37 μm) as a function of pH in different clay stabilizer solutions

Tables

Errata

Discussions

Some tools below are only available to our subscribers or users with an online account.

Related Content

Customize your page view by dragging and repositioning the boxes below.

Related Journal Articles
Related eBook Content
Topic Collections

Sorry! You do not have access to this content. For assistance or to subscribe, please contact us:

  • TELEPHONE: 1-800-843-2763 (Toll-free in the USA)
  • EMAIL: asmedigitalcollection@asme.org
Sign In