0
Research Papers: Petroleum Engineering

Challenges During Shallow and Deep Carbonate Reservoirs Stimulation

[+] Author and Article Information
Mohamed Mahmoud

Assistant Professor,
King Fahd University of Petroleum and Minerals,
Dhahran 31261, Saudi Arabia
Suez University,
Suez 43721, Egypt
e-mail: mmahmoud@kfupm.edu.sa; mohnasreldin80@gmail.com

Hisham Nasr-El-Din

Professor
Texas A&M University,
College Station, TX 77843
e-mail: Hisham.nasreldin@pe.tamu.edu

Manuscript received November 8, 2013; final manuscript received August 1, 2014; published online August 27, 2014. Guest Editor: Mayank Tyagi.

J. Energy Resour. Technol 137(1), 012902 (Aug 27, 2014) (8 pages) Paper No: JERT-13-1314; doi: 10.1115/1.4028230 History: Received November 08, 2013; Revised August 01, 2014

Carbonate reservoir stimulation has been carried out for years using HCl or HCl-based fluids. High HCl concentration should not be used when the well completion has Cr-based alloy in which the protective layer is chrome oxide which is very soluble in HCl. HCl or its based fluids are not recommended either in shallow reservoirs where the fracture pressure is low (face dissolution) or in deep reservoirs where it will cause severe corrosion problems to the well tubular. Different chelating agents have been proposed to be used as alternatives to HCl in the cases that HCl cannot be used. Chelating agents, such as HEDTA (hydroxyl ethylene diamine triacetic acid) and GLDA (glutamic –N, N-diacetic acid), have been used to stimulate carbonate cores. The benefits of chelating agents over HCl are the low reaction, low leak-off rate, and low corrosion rates. In this study, the different equations and parameters that can be used in matrix acid treatment were summarized to scale up the laboratory conditions to the field conditions. The conditions where HCl or chelating agents can be used were optimized and in this paper. The leak-off rate was determined using the data from coreflood experiments and computed tomography (CT) scans. Indiana limestone cores of average permeability of 1 md and core lengths of 6 and 20 in. were used in this study. Chelating agents will be used at pH value of 4 and at concentration of 0.6M, and their performance will be compared with the 15 wt.% HCl. The experimental results showed that HCl has high leak-off rate and caused face dissolution at low injection rate. The model to scale up the linear coreflood results to radial field conditions was developed and can be used to design for the optimum conditions of the matrix acid treatments. Chelating agents can be used to stimulate shallow reservoirs in which HCl may cause face dissolution, because they can penetrate deep with less volume and also they can be used in deep reservoirs where HCl may cause severe corrosion to the well tubular.

FIGURES IN THIS ARTICLE
<>
Copyright © 2015 by ASME
Your Session has timed out. Please sign back in to continue.

References

Jacobs, I. C., and Thorne, M. A., 1986, “Asphaltene Precipitation During Acid Stimulation Treatments,” SPE Symposium on Formation Damage Control, Lafayette, LA, February 26–28, Paper No. SPE 14823. [CrossRef]
Zhang, Y., Xie, X., and Morrow, N. R., 2007, “Waterflood Performance by Injection of Brine With Different Salinity for Reservoir Cores,” SPE Annual Technical Conference and Exhibition, Anaheim, CA, November 11–14, Paper No. SPE109849. [CrossRef]
Leontaritis, K. J., 2005, “Asphaltene Near-Well-Bore Formation Damage Modeling,” ASME J. Energy Res. Technol., 127(3), pp. 191–200. [CrossRef]
Jacobs, I. C., 1989, “Chemical Systems for the Control of Asphaltene Sludge During Oil Well Acidizing Treatments,” International Symposium on Oilfield Chemistry, Houston, TX, February 8–10, Paper No. SPE 18475. [CrossRef]
Gomaa, A., and Nasr-El-Din, H. A., 2011, “Propagation of Regular HCl Acids in Carbonate Rocks: The Impact of an In Situ Gelled Acid Stage,” ASME J. Energy Res. Technol., 133(2), p. 023101. [CrossRef]
Penny, G., Pursley, J. T., and Holcomb, D., 2005, “Microemulsion Additives Enable Optimized Formation Damage Repair and Prevention,” ASME J. Energy Res. Technol., 127(3), pp. 233–239. [CrossRef]
Jahediesfanjani, H., and Civan, F., 2005, “Damage Tolerance of Well-Completion and Stimulation Techniques in Coalbed Methane Reservoirs,” ASME J. Energy Res. Technol., 127(3), pp. 248–256. [CrossRef]
Fredd, C. N., and Fogler, H. S., 1997, “Chelating Agents as Effective Matrix Stimulation Fluids for Carbonate Formations,” International Symposium on Oilfield Chemistry, Houston, TX, February 18–21, Paper No. SPE 37212. [CrossRef]
Nunes, M., Bedrikovetsky, P., Paiva, R., Furtado, C., De Souza, A. L., and Newbery, B., 2010, “Theoretical Defnition of Formation Damage Zone With Applications to Well Stimulation,” ASME J. Energy Res. Technol., 132(3), p. 033101. [CrossRef]
Nasr-El-Din, H. A., 2005, “Formation Damage Induced by Chemical Treatments: Case Histories,” ASME J. Energy Res. Technol., 127(3), pp. 214–224. [CrossRef]
Gupta, A., 2012, “Performance Optimization of Abrasive Fluid Jet for Completion and Stimulation of Oil and Gas Wells,” ASME J. Energy Res. Technol., 143(2), p. 021001. [CrossRef]
Mahmoud, M. A., Mohamed, I. M., Nasr-El-Din, H. A., and De Wolf, C. A., 2011, “When Should We Use Chelating Agents in Carbonate Stimulation?,” SPE Saudi Arabia Section Technical Symposium and Exhibition, Alkhobar, Saudi Arabia, May 15–18, Paper No. SPE 149127. [CrossRef]
Frick, T. P., Mostofizadeh, B., and Economides, M. J., 1994, “Analysis of Radial Core Experiments for Hydrochloric Acid Interaction With Limestone,” SPE International Symposium on Formation Damage Control, Lafayette, LA, February 7–10, Paper No. SPE 27402. [CrossRef]
Fredd, C. N., Tjia, R., and Fogler, H. S., 1997, “The Existence of an Optimum Damkohler Number for Matrix Stimulation of Carbonate Formations,” SPE European Formation Damage Conference, The Hague, The Netherlands, June 2–3, Paper No. SPE 38167. [CrossRef]
Mahmoud, M. A., and Nasr-El-Din, H. A., 2011, “Effect of Reservoir Fluid Type on the Stimulation of Carbonate Cores Using Chelating Agents,” Brazil Offshore Conference and Exhibition, Macaé, Brazil, June 14–17, Paper No. SPE 143086. [CrossRef]
Huang, T., Hill, A. D., and Schechter, R. S., 2000, “Reaction Rate and Fluid Loss: The Keys to Wormhole Initiation and Propagation in Carbonate Acidizing,” Soc. Pet. Eng. J., 5(3), pp. 287–292. [CrossRef]
Huang, T., Zhu, D., and Hill, A. D., 1999, “Prediction of Wormhole Population Density in Carbonate Matrix Acidizing,” European Formation Damage Conference, The Hague, the Netherlands, May 31–June 1, Paper No. SPE 54723. [CrossRef]
Wang, Y., Hill, A. D., and Schechter, R. S., 1993, “The Optimum Injection Rate for Matrix Acidizing of Carbonate Formations,” Annual Technical Conference and Exhibition, Houston, TX, October 3–6, Paper No. SPE 26578. [CrossRef]
Rabie, A. I., Mahmoud, M. A., and Nasr-El-Din, H. A., 2011, “Reaction of GLDA With Calcite: Reaction Kinetics and Transport Study,” SPE International Symposium on Oilfield Chemistry, Woodlands, TX, April 11–13, Paper No. SPE 139816. [CrossRef]
Frenier, W., Brady, M., Al-Harthy, S., Arangath, R., Chan, K. S., Flamant, N., and Samuel, M., 2004, “Hot Oil and Gas can be Stimulated Without Acids,” SPE Prod. Facil., 21(2), pp. 194–204. [CrossRef]
Fredd, C. N., 1998, “The Influence of Transport and Reaction on Wormhole Formation in Carbonate Porous Media: A Study of Alternative Stimulation Fluids,” Ph.D thesis, Univerisity of Michigan, Ann Arbor, MI.
Schechter, R. S., 1992, Oil Well Stimulation, Prentice Hall, New York, pp. 528–547.

Figures

Grahic Jump Location
Fig. 1

Pore volume to breakthrough as a function of injection rate for scenario#1

Grahic Jump Location
Fig. 2

Pore volume to breakthrough as a function of injection rate for scenario#2

Grahic Jump Location
Fig. 3

A schematic diagram of wormhole formation in a linear core (after Wang et al. [18])

Grahic Jump Location
Fig. 4

Leak-off rate as a function of wormhole radius and wormhole length in 1.5 × 6 in. Indiana limestone cores at different injection rates using 15 wt.% HCl at room temperature

Grahic Jump Location
Fig. 5

Core inlet after treating Indiana limestone cores by 15 wt.% HCl at room temperature showing face dissolution due to high leak-off rate

Grahic Jump Location
Fig. 6

Leak-off rate as a function of wormhole radius and wormhole length in 1.5 × 6 in. Indiana limestone cores at different injection rates using 0.6M GLDA at room temperature. Wormholing data for GLDA from Refs. [12], [15], and [19].

Grahic Jump Location
Fig. 7

Performance of GLDA and HCl at low and high temperature. Data for GLDA from Refs. [12], [15], and [19].

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