Impairment of Fracture Conductivity in the Eagle Ford Shale Formation
- Jesse Guerra (Texas A&M University) | Ding Zhu (Texas A&M University) | Alfred D. Hill (Texas A&M University)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- November 2018
- Document Type
- Journal Paper
- 637 - 653
- 2018.Society of Petroleum Engineers
- fracture conductivity, water damage, shale formation
- 9 in the last 30 days
- 458 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 12.00|
|SPE Non-Member Price:||USD 35.00|
Fracture conductivity in shale formations can be greatly reduced because of water/rock interactions depending on the properties of formation rock and reservoir/fracture fluids. The mechanisms of water damage to fracture conductivity include clay swelling, surface softening, excessive proppant embedment, and fines migration caused by fracture-surface spalling and failed proppant particles. Fracture conductivity is influenced by closure stress, bulk and surface rock mechanical properties, fracture-surface topography, fracture-surface elemental composition, rock mineralogy, and proppant type and concentration, among other factors. This paper presents a study considering several of the aforementioned factors, centered primarily on saline-water-induced fracture-conductivity impairment of the Eagle Ford Shale Formation and its five vertical lithostratigraphic units.
Laboratory experiments were conducted to investigate and quantify the effect of flowback water on fracture conductivity for samples of Eagle Ford Shale. The majority of test samples were obtained from an outcrop in Antonio Creek, Terrell County, Texas, while the remaining samples were obtained from downhole core provided by an industry partner. The different lithostratigraphic units present in the Eagle Ford Shale formation were accounted for. Saline water with a chemical composition similar to that of the typical field flowback water was used.
Fracture-conductivity measurements were conducted in three stages. In the first stage, dry nitrogen was flowed to ascertain the undamaged initial fracture conductivity. In the second stage, the saline solution was injected into the fracture until steady-state behavior was observed. In the third and final stage, dry nitrogen was once again flowed to quantify the recovered fracture conductivity. Reported mechanical properties from the same outcrop-rock samples, consisting of Poisson’s ratio and the Brinell hardness number (BHN), were considered in this study. In addition, reported mineralogy obtained by use of X-ray-diffraction (XRD) microscopy was taken into consideration. The elemental composition along the fracture surface was obtained by use of X-ray-fluorescence (XRF) microscopy, and fracture-surface topography was obtained by use of a laser surface scanner and profilometer.
Results support findings that bulk and surface mechanical properties influence fracture conductivity, as well as surface topography and related attributes such as fracture surface area. Furthermore, the bulk mineralogical composition of the rock and the elemental composition of the rock fracture surface have a significant effect on fracture conductivity when flowing saline water to simulate flowback. Clay content was observed to directly influence fracture conductivity. The results of this study show a loss of fracture conductivity for the Eagle Ford Formation ranging from approximately 4 to 25% after flowing saline water, compared with the initial conductivity measured by flowing dry nitrogen before saline-water exposure. This is not a large loss in conductivity caused by water damage, and suggests that water damage may not be the major cause of the large early decline rates observed in most Eagle Ford Shale producing wells.
|File Size||3 MB||Number of Pages||17|
Akrad, O. M., Miskimins, J. L., and Prasad, M. 2011. The Effects of Fracturing Fluids on Shale Rock Mechanical Properties and Proppant Embedment. Presented at the SPE Annual Technical Conference and Exhibition, Denver, 30 October–2 November. SPE-146658-MS. https://doi.org/10.2118/146658-MS.
Ali, M., and Hascakir, B. 2015. Water-Rock Interaction for Eagle Ford, Marcellus, Green River, and Barnett Shale Samples. Presented at the SPE Eastern Regional Meeting, Morgantown, West Virginia, 13–15 October. SPE-177304-MS. https://doi.org/10.2118/177304-MS.
API RP 61, Recommended Practices for Evaluating Short Term Proppant Pack Conductivity, first edition. 1989. Washington, DC: API.
Awoleke, O. 2013. Dynamic Fracture Conductivity: An Experimental Investigation Based on Factorial Analysis. PhD dissertation, Texas A&M University, College Station, Texas (May 2013).
Cooke, C. E. Jr. 1975. Effect of Fracturing Fluids on Fracture Conductivity. J Pet Technol 27 (10): 1273–1282. SPE-5114-PA. https://doi.org/10.2118/5114-PA.
Donovan, A. D. and Staerker, T. S. 2010. Sequence Stratigraphy of the Eagle Ford (Boquillas) Formation in the Subsurface of South Texas and the Outcrops of West Texas. Gulf Coast Assoc. Geol. Soc. Trans. 60: 861–899.
Donovan, A. D., Staerker, T. S., Pramudito, A. et al. 2012. The Eagle Ford Outcrops of West Texas: A Laboratory for Understanding Heterogeneities Within Unconventional Mudstone Reservoirs. CGAGS J. 1: 162–185.
Enriquez-Tenorio, O. 2016. A Comprehensive Study of the Eagle Ford Shale Fracture Conductivity. Master’s thesis, Texas A&M University, College Station, Texas (August 2016).
Enriquez-Tenorio, O., Knorr, A., Zhu, D. et al. 2016. Relationships Between Mechanical Properties and Fracturing Conductivity for the Eagle Ford Shale. Presented at the SPE Asia Pacific Hydraulic Fracturing Conference, Beijing, 24–26 August. SPE-181858-MS. https://doi.org/10.2118/181858-MS.
Fredd, C. N., McConnell, S. B., Boney, C. L. et al. 2000. Experimental Study of Hydraulic Fracture Conductivity Demonstrates the Benefits of Using Proppants. Presented at the SPE Rocky Mountain Regional/Low-Permeability Reservoirs Symposium and Exhibition, Denver, 12–15 March. SPE-60326-MS. https://doi.org/10.2118/60326-MS.
Fredd, C. N., McConnell, S. B., Boney, C. L. et al. 2001. Experimental Study of Fracture Conductivity for Water-Fracturing and Conventional Fracturing Applications. SPE J. 6 (3): 288–298. SPE-74138-PA. https://doi.org/10.2118/74138-PA.
Gardner, R., Pope, M. C., Wehner, M. P. et al. 2013. Comparative Stratigraphy of the Eagle Ford Group Strata in Lozier Canyon and Antonio Creek, Terrell County, Texas. GCAGS J. 2: 42–52.
Horner, P., Halldorson, B., and Slutz, J. A. 2011. Shale Gas Water Treatment Value Chain—A Review of Technologies, Including Case Studies. Presented at the SPE Annual Technical Conference and Exhibition, Denver, 30 October–2 November. SPE-147264-MS. https://doi.org/10.2118/147264-MS.
ISO 13503-5:2006, Petroleum and Natural Gas Industries—Completion Fluids and Materials—Part 5: Procedures for Measuring the Long-Term Conductivity of Proppants, first edition. 2006. Geneva, Switzerland: International Organization for Standardization.
Kamenov, A. N. 2013. The Effect of Proppant Size and Concentration on Hydraulic Fracture Conductivity in Shale Reservoirs. Master’s thesis, Texas A&M University, College Station, Texas (May 2013).
King, G. E. 2010. Thirty Years of Gas Shale Fracturing: What Have We Learned? Presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, 19–22 September. SPE-133456-MS. https://doi.org/10.2118/133456-MS.
Knorr, A. F. 2016. The Effect of Rock Properties on Fracture Conductivity in the Eagle Ford. Master’s thesis, Texas A&M University, College Station, Texas (May 2016).
Miceli-Romero, A. A. 2014. Subsurface and Outcrop Organic Geochemistry of the Eagle Ford Shale (Cenomanian-Coniacian) in West, Southwest, Central, and East Texas. PhD dissertation, University of Oklahoma, Norman, Oklahoma.
Palisch, T. T., Duenckel, R. J., Bazan, L. W. et al. 2007. Determining Realistic Fracture Conductivity and Understanding Its Impact on Well Performance—Theory and Field Examples. Presented at the SPE Hydraulic Fracturing Technology Conference, College Station, Texas, 29–31 January. SPE-106301-MS. https://doi.org/10.2118/106301-MS.
Parker, M. A. and McDaniel, B. W. 1987. Fracturing Treatment Design Improved by Conductivity Measurements Under In-Situ Conditions. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, 27–30 September. SPE-16901-MS. https://doi.org/10.2118/16901-MS.
Ramurthy, M., Barree, R. D., Kundert, D. P. et al. 2011. Surface Area vs. Conductivity-Type Fracture Treatments in Shale Reservoirs. SPE Prod & Oper 26 (4): 357–367. SPE-140169-PA. https://doi.org/10.2118/140169-PA.
Slutz, J. A., Anderson, J. A., Broderick, R. et al. 2012. Key Shale Gas Water Management Strategies: An Economic Assessment. Presented at the International Conference on Health, Safety and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11–13 September. SPE-157532-MS. https://doi.org/10.2118/157532-MS.
Tek, M. R., Coats, K. H., and Katz, D. L. 1962. The Effect of Turbulence on Flow of Natural Gas Through Porous Reservoirs. J Pet Technol 14 (7): 799–806. SPE-147-PA. https://doi.org/10.2118/147-PA.
Wang, F. P. and Gale, J. F. 2009. Screening Criteria for Shale Gas Systems. Gulf Coast Assoc. Geol. Soc. Trans. 59: 779–793.
Xu, J., Fisher, K., Qiu, F. et al. 2016. Impact of Ash Beds on Production in Eagle Ford Shale. Presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 9–11 February. SPE-179110-MS. https://doi.org/10.2118/179110-MS.
Zhang, J. 2014. Creation and Impairment of Hydraulic Fracture Conductivity in Shale Formations. PhD dissertation, Texas A&M University, College Station, Texas (August 2014).
Zhang, J., Ouyang, L., Hill, A. D. et al. 2014. Experimental and Numerical Studies of Reduced Fracture Conductivity Due To Proppant Embedment in Shale Reservoirs. Presented at the SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. SPE-170775-MS. https://doi.org/10.2118/170775-MS.
Zhang, J., Zhu, D., and Hill, A. D. 2015. Water-Induced Fracture Conductivity Damage in Shale Formations. Presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 3–5 February. SPE-173346-MS. https://doi.org/10.2118/173346-MS.
Zhang, L., Marcantonio, F., Haskakir, B. et al. 2016. Solid and Soluble Products of Engineered Water/Rock Interactions in Eagle Ford Group Chemofacies. Presented at the Berg-Hughes Center for Petroleum and Sedimentary Systems 7th Annual Research Symposium, Graduate Student Symposium Poster Session, College Station, Texas, 11 October.