Multiscale Experimental Studies on Interactions Between Aqueous-Based Fracturing Fluids and Tight Organic-Rich Carbonate Source Rocks
- Feng Liang (Aramco Services Company) | Jilin Zhang (Aramco Services Company) | Hui-Hai Liu (Aramco Services Company) | Kirk M. Bartko (Saudi Aramco)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- May 2019
- Document Type
- Journal Paper
- 402 - 417
- 2019.Society of Petroleum Engineers
- tight carbonate, aqueous-based fracturing fluids, interactions, morphology, permeability
- 6 in the last 30 days
- 155 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 12.00|
|SPE Non-Member Price:||USD 35.00|
Hydraulic fracturing has been widely used for unconventional reservoirs, including organic-rich carbonate formations, for oil and gas production. During hydraulic fracturing, massive amounts of fracturing fluids are pumped to crack open the formation, and only a small percentage of the fluids are recovered during the flowback process. The negative effects of the remaining fluid on the formation, such as clay swelling and reduction of rock mechanical properties, have been reported in the literature. However, the effects of the fluids on source-rock properties—especially on microstructures, porosity, and permeability—are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and the corresponding changes in permeability and porosity are reported.
Two sets of tight organic-rich carbonate-source-rock samples were examined. One sample set was sourced from a Middle East field, and the other was an outcrop from Eagle Ford Shale that is considered to be similar to the one from the Middle East field in terms of mineralogy and organic content. Three fracturing fluids—2% potassium chloride (KCl), 0.5 gal/1,000 gal (gpt) slickwater, and synthetic seawater—were used to treat the thin section of the source-rock and core samples. Modern analytical techniques, such as scanning electron microscopy (SEM) and energy-dispersive spectroscopy (EDS), were used to investigate the source-rock morphology and mineralogy changes before and after the fluid treatment, at the micrometer scale. Permeability as a function of effective stress was quantified on core samples to investigate changes in flow properties caused by the fracturing-fluid treatments.
The SEM and EDS results before and after fracturing-fluid treatments on the source-rock samples showed the microstructural changes for all three fluids. For 2% KCl and slickwater fluid, reopening of some mineral-filled natural fractures was observed. The enlargement of the aperture for pre-existing microfractures was slightly more noticeable for samples treated with 2% KCl compared with slickwater at the micrometer scale. In one sample, dissolution of organic matter was captured in the slickwater-fluid-treated rock sample. Mineral precipitation of sodium chloride (NaCl) and generation of new microfractures were observed for samples treated with synthetic seawater. The formation of new microfractures and the dissolution of minerals could result in increases in both porosity and permeability, whereas the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stress for the core-plug samples. This effect on absolute-gas-permeability increase might have an important implication for hydrocarbon recovery from unconventional reservoirs.
This study provides experimental evidence at different scales that aqueous-based fracturing fluid might potentially have a positive effect on gas production from organic-rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new fractures or reopening of existing microfractures. This observation will be beneficial to the future use of freshwater-and seawater-based fluids in stimulating gas production from organic-rich carbonate formations.
|File Size||2 MB||Number of Pages||16|
Abass, H. H., Ortiz, I., Khan, M. R. et al. 2007. Understanding Stress Dependent Permeability of Matrix, Natural Fractures, and Hydraulic Fractures in Carbonate Formations. Presented at SPE Saudi Arabia Section Technical Symposium, Dhahran, Saudi Arabia, 7–8 May. SPE-110973-MS. https://doi.org/10.2118/110973-MS.
Akin, S., Schembre, J. M., Bhat, S. K. et al. 2000. Spontaneous Imbibition Characteristics of Diatomite. J. Pet. Sci. Eng. 25 (3): 149–165. https://doi.org/10.1016/S0920-4105(00)00010-3.
Akrad, O., Miskimins, J., and Prasad, M. 2011. The Effects of Fracturing Fluids on Shale Rock Mechanical Properties and Proppant Embedment. Presented at the SPE Annual Technical Conference, Denver, 30 October–2 November. SPE-146658-MS. https://doi.org/10.2118/146658-MS.
Anders, M. H., Laubach, S. E., and Scholz, C. H. 2014. Microfractures: A Review. J. Struct. Geol. 69B (December): 377–394. https://doi.org/10.1016/j.jsg.2014.05.011.
Babadagli, T. 2001. Scaling of Cocurrent and Countercurrent Capillary Imbibition for Surfactant and Polymer Injection in Naturally Fractured Reservoirs. SPE J. 6 (4): 465–478. SPE-74702-PA. https://doi.org/10.2118/74702-PA.
Back, W., Hanshaw, B. B., Herman, J. S. et al. 1986. Differential Dissolution of a Pleistocene Reef in the Ground-Water Mixing Zone of Coastal Yucatan, Mexico. Geology 14 (2): 137–140. https://doi.org/10.1130/0091-7613(1986)14<137:DDOAPR>2.0.CO;2.
Barati, R., Hutchins, R. D., Friedel, T. et al. 2009. Fracture Impact of Yield Stress and Fracture-Face Damage on Production With a Three-Phase 2D Model. SPE Prod & Oper 24 (2): 336–345. SPE-111457-PA. https://doi.org/10.2118/111457-PA.
Bennion, D. B. and Thomas, F. B. 2005. Formation Damage Issues Impacting the Productivity of Low Permeability, Low Initial Water Saturation Gas Producing Formations. J. Energy Resour. Technol. 127 (3): 240–247. https://doi.org/10.1115/1.1937420.
Bybee, K. 2004. Acid Fracturing a Carbonate Reservoir. J Pet Technol 56 (7): 49–52. SPE-0704-0049-JPT. https://doi.org/10.2118/0704-0049-JPT.
Cash, R., Zhu, D., and Hill, A. D. 2016. Acid Fracturing Carbonate-Rich Shale: A Feasibility Investigation of Eagle Ford Formation. Presented at the SPE Asia Pacific Hydraulic Fracturing Conference, Beijing, 24–26 August. SPE-181805-MS. https://doi.org/10.2118/181805-MS.
Cheng, C.-L., Perfect E., Donnelly, B. et al. 2015. Rapid Imbibition of Water in Fractures Within Unsaturated Sedimentary Rock. Adv. Water Resour. 77 (March): 82–89. https://doi.org/10.1016/j.advwatres.2015.01.010.
Cheng, Y. 2012. Impact of Water Dynamics in Fractures on the Performance of Hydraulically Fractured Wells in Gas-Shale Reservoirs. J Can Pet Technol 51 (2): 143–151. SPE-127863-PA. https://doi.org/10.2118/127863-PA.
Cramer, D. D. 2008. Stimulating Unconventional Reservoirs: Lessons Learned, Successful Practices, Areas for Improvement. Presented at the SPE Unconventional Reservoirs Conference, Keystone, Colorado, 10–12 February. SPE-114172-MS. https://doi.org/10.2118/114172-MS.
Dehghanpour, H., Lan, Q., Saeed, Y. et al. 2013. Spontaneous Imbibition of Brine and Oil in Gas Shales: Effect of Water Adsorption and Resulting Microfractures. Energy Fuels 27 (6): 3039–3049. https://doi.org/10.1021/ef4002814.
Dehghanpour, H., Zubair, H. A., and Chhabra, A. 2012. Liquid Intake of Organic Shales. Energy Fuels 26 (9): 5750–5758. https://doi.org/10.1021/ef3009794.
Engelder, T. 2012. Capillary Tension and Imbibition Sequester Frack Fluid in Marcellus Gas Shales. Proc. Natl. Acad. Sci. US 109 (52): E3625. https://doi.org/10.1073/pnas.1216133110.
Gale, J. F. W., Laubach, S. E., Olson, J. E. et al. 2014. Natural Fractures in Shale: A Review and New Observations. AAPG Bull. 98 (11): 2165–2216. https://doi.org/10.1306/08121413151.
Gdanski, R. D., Fulton, D. D., and Shen, C. 2009. Fracture-Face-Skin Evolution During Cleanup. SPE Prod & Oper 24 (1): 22–34. SPE-101083-PA. https://doi.org/10.2118/101083-PA.
Ghanbari, E. and Dehghanpour, H. 2015. Impact of Rock Fabric on Water Imbibition and Salt Diffusion in Gas Shales. Int. J. Coal Geol. 138 (15 January): 55–67. https://doi.org/10.1016/j.coal.2014.11.003.
Hakami, A., Al-Mubarak, A., Al-Ramadan, K. et al. 2016. Characterization of Carbonate Mudrocks of the Jurassic Tuwaiq Mountain Formation, Jafurah Basin, Saudi Arabia: Implications for Unconventional Reservoir Potential Evaluation. J. Nat. Gas Sci. Eng. 33 (July): 1149–1168. https://doi.org/10.1016/j.jngse.2016.04.009.
Hiorth, A., Cathles, L. M., and Madland, M. V. 2010. The Impact of Pore Water Chemistry on Carbonate Surface Charge and Oil Wettability. Transport Porous Med. 85 (1): 1–21. https://doi.org/10.1007/s11242-010-9543-6.
Holditch, S. A. 1979. Factors Affecting Water Blocking and Gas Flow from Hydraulic Fractured Gas Wells. J Pet Technol 31 (12): 1515–1524. SPE-7561-PA. https://doi.org/10.2118/7561-PA.
Jones, S. C. 1997. A Technique for Faster Pulse-Decay Permeability Measurements in Tight Rocks. SPE Form Eval 12 (1): 19–25. SPE-28450-PA. https://doi.org/10.2118/28450-PA.
Kamath, J. and Laroche, C. 2003. Laboratory-Based Evaluation of Gas Well Deliverability Loss Caused by Water Blocking. SPE J. 8 (1): 71–80. SPE-83659-PA. https://doi.org/10.2118/83659-PA.
Khan, M. and Teufel, L. W. 2000. The Effect of Geological and Geomechanical Parameters on Reservoir Stress Path and Its Importance in Studying Permeability Anisotropy. SPE Res Eval & Eng 3 (5): 394–400. SPE-66184-PA. https://doi.org/10.2118/66184-PA.
King, G. 2012. Hydraulic Fracturing 101: What Every Representative, Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor and Engineer Should Know About Estimating Frac Risk. J Pet Technol 64 (4): 34–42. SPE-0412-0034-JPT. https://doi.org/10.2118/0412-0034-JPT.
Lai, B., Liang, F., Zhang, J. et al. 2016. Fracturing Fluids Effects on Mechanical Properties of Organic Rich Shale. Presented at the 50th US. Rock Mechanics/Geomechanics Symposium, Houston, 26–29 June. ARMA-2016-180.
Lan, Q., Xu, M., Binazadeh, M. et al. 2015. A Comparative Investigation of Shale Wettability: The Significance of Pore Connectivity. J. Nat. Gas. Sci. Eng. 27 (November): 1174–1188. https://doi.org/10.1016/j.jngse.2015.09.064.
Laubach, S. E., Olson, J. E., and Gale, J. F. W. 2004. Are Open Fractures Necessarily Aligned With Maximum Horizontal Stress? Earth Planet. Sci. Lett. 222 (1): 191–195. https://doi.org/10.1016/j.epsl.2004.02.019.
Lavrov, A. 2017. Fracture Permeability Under Normal Stress: A Fully Computational Approach. J. Pet. Explor. Prod. Tech. 7 (1): 181–194. https://doi.org/10.1007/s13202-016-0254-6.
Liang, F., Lai, B., Zhang, J. et al. 2017. An Experimental Study on Interactions Between Imbibed Fracturing Fluid and Organic-Rich Tight Carbonate Source Rocks. Presented at the Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, 13–16 November. SPE-188338-MS. https://doi.org/10.2118/188338-MS.
Mahadevan, J., Sharma, M. M., and Yortsos, Y. C. 2007. Capillary Wicking in Gas Wells. SPE J. 12 (4): 429–437. SPE-103229-PA. https://doi.org/10.2118/103229-PA.
Makhanov, K., Dehghanpour, H., and Kuru, E. 2012. An Experimental Study of Spontaneous Imbibition in Horn River Shales. Presented at SPE Canadian Unconventional Resources Conference, Calgary, 30 October–1 November. SPE-162650-MS. https://doi.org/10.2118/162650-MS.
McLeod, H. O. 1984. Matrix Acidizing. SPE J. 36 (12): 2055–2069. SPE-13752-PA. https://doi.org/10.2118/13752-PA.
McLeod, H. O. 1989. Significant Factors for Successful Matrix Acidizing. Presented at SPE Centennial Symposium at New Mexico Tech, Socorro, New Mexico, 16–19 October. SPE-20155-MS. https://doi.org/10.2118/20155-MS.
Morrow, N. R. and Mason, G. 2001. Recovery of Oil by Spontaneous Imbibition. Curr. Opin. Colloid Interf. Sci. 6 (4): 321–337. https://doi.org/10.1016/S1359-0294(01)00100-5.
Morsy, S. and Sheng, J. J. 2014. Imbibition Characteristics of the Barnett Shale Formation. Presented at the SPE Unconventional Resources Conference, The Woodlands, Texas, 1–3 April. SPE-168984-MS. https://doi.org/10.2118/168984-MS.
Muralidharan, V., Putra, E., and Schechter, D. S. 2004. Experimental and Simulation Analysis of Fractured Reservoir Experiencing Different Stress Conditions. Presented at Canadian International Petroleum Conference, Calgary, 8–10 June. PETSOC-2004-229. https://doi.org/10.2118/2004-229.
Nasr-El-Din, H. A., Lynn, J. D., and Al-Dossary, K. A. 2002. Formation Damage Caused by a Water Blockage Chemical: Prevention Through Operator Supported Test Programs. Presented at the International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 20–21 February. SPE-73790-MS. https://doi.org/10.2118/73790-MS.
O’Brien, P., Onyia, D., and Astarita, G. 2015. Middle East Bucking the Trend in Drive for New EOR Technology. E&P Magazine, 3 August 2015, https://www.epmag.com/middle-east-bucking-trend-drive-new-eor-technology-812011 (2 January 2019).
Olsen, T. N. and Karr, G. K. IV. 1986. Treatment Optimization of Acid Fracturing in Carbonate Formations. Presented at SPE Rocky Mountain Regional Meeting, Billings, Montana, 19–21 May. SPE-15165-MS. https://doi.org/10.2118/15165-MS.
Ortega, O. J., Marrett, R. A., and Laubach, S. E. 2006. A Scale-Independent Approach to Fracture Intensity and Average Spacing Measurement. AAPG Bull. 90 (2): 193–208. https://doi.org/10.1306/08250505059.
Parmar, J. S., Dehghanpour, H., and Kuru, E. 2012. Unstable Displacement: A Missing Factor in Fracturing Fluid Recovery. Presented at SPE Canadian Unconventional Resources Conference, Calgary, 30 October–1 November. SPE-162649-MS. https://doi.org/10.2118/162649-MS.
Parmar, J. S., Dehghanpour, H., and Kuru, E. 2013. Drainage Against Gravity: Factors Impacting the Load Recovery in Fractures. Presented at the SPE Unconventional Resources Conference–USA, The Woodlands, Texas, 10–12 April. SPE-164530-MS. https://doi.org/10.2118/164530-MS.
Parmar, J., Dehghanpour, H., and Kuru, E. 2014. Displacement of Water by Gas in Propped Fractures: Combined Effects of Gravity, Surface Tension, and Wettability. J. Unconven. Oil Gas Resour. 5 (March): 10–21. https://doi.org/10.1016/j.juogr.2013.11.005.
Pommer, M. and Milliken, K. 2015. Pore Types and Pore-Size Distribution Across Thermal Maturity, Eagle Ford Formation, Southern Texas. AAPG Bull. 99 (9): 1713–1744. https://doi.org/10.1306/03051514151.
Ross, G. D., Todd, A. C., Tweedie, J. A. et al. 1982. The Dissolution Effects of CO2-Brine Systems on the Permeability of U.K. and North Sea Calcareous Sandstones. Presented at SPE Enhanced Oil Recovery, Tulsa, 4–7 April. SPE-10685-MS. https://doi.org/10.2118/10685-MS.
Roychaudhuri, B., Tsotsis, T. T., and Jessen, K. 2011. An Experimental and Numerical Investigation of Spontaneous Imbibition in Gas Shales. Presented at the SPE Annual Technical Conference and Exhibition, Denver, 30 October–2 November. SPE-147652-MS. https://doi.org/10.2118/147652-MS.
Roychaudhuri, B., Tsotsis, T. T., and Jessen, K. 2013. An Experimental Investigation of Spontaneous Imbibition in Gas Shales. J. Pet. Sci. Eng. 111 (November): 87–97. https://doi.org/10.1016/j.petrol.2013.10.002.
Scott, H., Patey, I. T. M., and Byrne, M. T. 2007. Return Permeability Measurements—Proceed With Caution. Presented at the European Formation Damage Conference, Scheveningen, The Netherlands, 30 May–1 June. SPE-107812-MS. https://doi.org/10.2118/107812-MS.
Shen, Y., Ge, H, Meng, M. et al. 2017. Effect of Water Imbibition on Shale Permeability and Its Influence on Gas Production. Energy Fuels 31 (5): 4973–4980. https://doi.org/10.1021/acs.energyfuels.7b00338.
Soeder, D. J. 2017. Unconventional: The Development of Natural Gas From the Marcellus Shale, first edition. Boulder, Colorado: Geological Society of America.
Strand, S., Høgnesen, E. J., and Austad, T. 2006. Wettability Alteration of Carbonates—Effects of Potential Determining Ions (Ca2+ and SO42–) and Temperature. Colloid. Surface. A 275 (1–3): 1–10. https://doi.org/10.1016/j.colsurfa.2005.10.061.
Takahashi, T. and Kovscek, A. R. 2010. Spontaneous Countercurrent Imbibition and Forced Displacement Characteristics of Low-Permeability, Siliceous Shale Rocks. J. Pet. Sci. Eng. 71 (1–2): 47–55. https://doi.org/10.1016/j.petrol.2010.01.003.
Tian, Y. 2014. Experimental Study on Stress Sensitivity of Naturally Fractured Reservoirs. Presented at the SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. SPE-173463-STU. https://doi.org/10.2118/173463-STU.
Wu, W. and Sharma, M. M. 2017. Acid Fracturing in Shales: Effect of Dilute Acid on Properties and Pore Structure of Shale. SPE Prod & Oper 32 (1): 51–63. SPE-173390-PA. https://doi.org/10.2118/173390-PA.
Yan, Q., Lemanski, C., Karpyn, Z. T. et al. 2015. Experimental Investigation of Shale Gas Production Impairment Due to Fracturing Fluid Migration During Shut-In Time. J. Nat. Gas Sci. Eng. 24 (May): 99–105. https://doi.org/10.1016/j.jngse.2015.03.017.
Yousef, A. A., Al-Saleh, S., Al-Kaabi, A. U. et al. 2010. Laboratory Investigation of Novel Oil Recovery Method for Carbonate Reservoirs. Presented at Canadian Unconventional Resources and International Petroleum Conference, Calgary, 19–21 October. SPE-137634-MS. https://doi.org/10.2118/137634-MS.
Yousef, A. A., Al-Salehsalah, S. H., and Al-Jawfi, M. S. 2011a. New Recovery Method for Carbonate Reservoirs Through Tuning the Injection Water Salinity: Smart WaterFlooding. Presented at SPE EUROPEC/EAGE Annual Conference and Exhibition, Vienna, Austria, 23–26 May. SPE-143550-MS. https://doi.org/10.2118/143550-MS.
Yousef, A. A., Al-Saleh, S., and Al-Jawfi, M. S. 2011b. Smart WaterFlooding for Carbonate Reservoirs: Salinity and Role of Ions. Presented at SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 25–28 September. SPE-141082-MS. https://doi.org/10.2118/141082-MS.
Yousef, A. A., Al-Saleh, S., and Al-Jawfi, M. S. 2012a. The Impact of the Injection Water Chemistry on Oil Recovery From Carbonate Reservoirs. Presented at SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 16–18 April. SPE-154077-MS. https://doi.org/10.2118/154077-MS.
Yousef, A. A., Al-Saleh, S., and Al-Jawfi, M. S. 2012b. Improved/Enhanced Oil Recovery From Carbonate Reservoirs by Tuning Injection Water Salinity and Ionic Content. Presented at SPE Improved Oil Recovery Symposium, Tulsa, 14–18 April. SPE-154076-MS. https://doi.org/10.2118/154076-MS.
Zhang, P. and Austad, T. 2006. Wettability and Oil Recovery From Carbonates: Effects of Temperature and Potential Determining Ions. Colloid. Surface. A 279 (1–3): 179–187. https://doi.org/10.1016/j.colsurfa.2006.01.009.
Zhang, X., Morrow, N. R., and Ma, S. 1996. Experimental Verification of a Modified Scaling Group for Spontaneous Imbibition. SPE Res Eng 11 (4): 280–285. SPE-30762-PA. https://doi.org/10.2118/30762-PA.
Zhou, D., Jia, L., Kamath, J. et al. 2002. Scaling of Counter-Current Imbibition Processes in Low-Permeability Porous Media. J. Pet. Sci. Eng. 33 (1–3): 61–74. https://doi.org/10.1016/S0920-4105(01)00176-0.