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Mechanical Zonation of Rock Properties and the Development of Hydrothermal Fluid Circulation Pathways: Implications for Enhanced Geothermal Systems

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Mechanical Zonation of Rock Properties and the Development of Hydrothermal Fluid Circulation Pathways: Implications for Enhanced Geothermal Systems Mechanical Zonation of Rock Properties and the Development of Hydrothermal Fluid Circulation Pathways: Implications for Enhanced Geothermal Systems Oladoyin Kolawole ( [email protected] ) Bob L. Herd Department of Petroleum Engineering, Texas Tech University https://orcid.org/0000-0001- 9202-172X Ion Ispas Texas Tech University Folarin Kolawole School of Geosciences, University of Oklahoma Christophe Germay EPSLOG S.A John D McLennan Department of Chemical Engineering, University of Utah Research Keywords: Enhanced geothermal system, Geomechanics, Hydrothermal alteration, Mechanical stratigraphy, Fracture mechanics Posted Date: December 10th, 2020 DOI: https://doi.org/10.21203/rs.3.rs-122204/v1 License: This work is licensed under a Creative Commons Attribution 4.0 International License. Read Full License 1 Mechanical Zonation of Rock Properties and the Development of 2 Hydrothermal Fluid Circulation Pathways: Implications for Enhanced 3 Geothermal Systems 4 1,2 1,2 3,4 5 5 Oladoyin Kolawole *, Ion Ispas , Folarin Kolawole , Christophe Germay , John D. 6 6 McLennan1Rock Mechanics Laboratory, 101 Terry Fuller Petroleum Engineering Research Building, Texas 7 Tech University, Lubbock, TX, USA 8 2Bob L. Herd Department of Petroleum Engineering, Texas Tech University, Lubbock, TX, USA 9 3School of Geosciences, University of Oklahoma, Norman, OK, USA 10 4Now at BP America Inc., Houston, TX, USA 11 5EPSLOG S.A., Liege, Belgium 12 6Department of Chemical Engineering, University of Utah, Salt Lake City, UT, USA 13 14 *Corresponding author: [email protected] (Oladoyin Kolawole) 15 ORCID: O.K - 0000-0001-9202-172X; I.I - 0000-0003-3426-4031; F.K - 0000-0002-5695- 16 2778; JD.M - 0000-0002-6663-5063 17 ABSTRACT 18 19 Oil and gas operations in sedimentary basins have revealed significant temperatures at 20 depth, raising the possibility of major geothermal resource potential in the sedimentary 21 sequences. The efficient development of such a resource may require enhancement by 22 hydraulic stimulation. However, effective stimulation relies on an initial assessment of in- 23 situ mechanical properties and a Discrete Fracture Network (DFN) model of the rock 24 response. Here, we UCSexamine the distribution of mechanical properties (unconfined 25 compressive strength, ; ultrasonic velocity-derived Poisson ratio, ν; and, scratch-derived s 26 fracture toughness, K ) along the cored interval of a sedimentary formation with a known 27 geothermal anomaly in the Permian Basin, U.S. Our results reveal the mechanical 28 heterogeneity of the rock, demonstrated by four distinct alternating mechanical zones, which include: (1.) mechanically weaker 0.17 m-thick Zone-A and 0.18 m-thick Zone-C with mean 1 29 UCS s 30 = 110 MPa, ν = 0.25, K = 1.89 MPa·√m; and (2.)UCS mechanically stronger 0.41 m-thick s 31 Zone-B and 0.15 m-thick Zone-D which show mean = 166 MPa, ν = 0.22, and K = 2.87 32 MPa·√m. Although X-ray Diffraction analyses of the samples suggest that the entire rock 33 matrix is dominated by dolomite, the stronger zones show a higher abundance of quartz 34 (>30%) and relatively lower phyllosilicate mineral content (<2%) than the weaker zones. 35 Further, we observe that the mechanically stronger zones have the greatest occurrences of 36 hydrothermal alterations (anhydrite veins and nodules), indicating that the cored interval 37 had experienced hydrothermal fluid circulation in the past. We infer that the denser 38 clustering of fractures in the stronger zones which facilitated the hydrothermal vein 39 development was due to the influence of mechanical stratigraphy on the brittle deformation 40 and alteration of the sedimentary-hosted hydrothermal reservoir. Thus, we suggest that the 41 stronger zones represent viable targets for hydraulic stimulation of a geothermal reservoir, 42 both for the emplacement of new fractures and the linkage of pre-existing fractures. Our 43 findings in this study provide an analog for hydraulic stimulation of viable geothermal 44 reservoir targets at higher in-situ temperatures and higher geothermal gradients. 45 Keywords: 46 Enhanced geothermal system; Geomechanics; Hydrothermal alteration; 47 Mechanical stratigraphy; Fracture mechanics 48 1. Introduction 49 50 Enhanced geothermal systems (EGS) are reservoirs that have been stimulated to efficiently 51 extract heat from low permeability high-temperature rocks (Nadimi et al. 2020). Hydraulic 52 fracturing is one of the most efficient stimulation techniques currently considered for heat 53 extraction from an EGS, through the injection of highly pressurized fluid into the formation 54 to initiate and propagate or reactivate natural fractures. Hydraulic fractures (HF) play an 55 important role in improving the heat extraction performance of an EGS (Murphy et al. 1977; 56 Campbell et al. 1981; Zhou et al. 2018; Zhang et al. 2020). In assessing a viable geothermal 57 reservoir, three important components are required for consideration, and they are heat, mobile fluid, and permeability (Nadimi et al. 2020). Reactivation of pre-existing natural 2 58 59 fractures (NF) induced by injection fluid has become widely accepted as an important 60 mechanism for fracture network connectivity and permeability enhancement in EGS 61 reservoirs (Pine and Batchelor 1984; McClure and Horne 2013; Finnila et al. 2015; Sheng et 62 al. 2018). Various EGS stimulation mechanisms have been proposed, based on field 63 observation and laboratory programs. Specific mechanisms depend on the geology, in-situ 64 stress, fault structures, and pre-existing natural fractures (McClure and Horne 2014; Nadimi 65 et al. 2020). 66 Studies have shown that EGS is characterized by heterogeneous geology, which includes pre- 67 existing fracture networks that are mineralized (Callahan et al. 2019a, 2019b, 2020). It is 68 also known that during hydraulic fracturing stimulation, propagating hydraulic fractures are 69 known to link and connect pre-existing natural fractures (NF) (Kolawole and Ispas 2020a). 70 During a hydraulic fracturing treatment, complex fracture networks are often generated, and 71 the HF-NF interaction significantly influences the complexity of the networks created. Some 72 of these pre-existing natural fractures include veins, and their reactivation can result in 73 induced seismicity (Kolawole et al. 2019). Veins are open fractures that are occluded 74 minerals. 75 Drilling, completion, injection, and production from very deep, High-Temperature High- 76 Pressure (HPHT) reservoirs is an expensive operation, and its success demands an 77 understanding of the in-situ rock mechanical properties. These rock mechanical properties 78 have implications for subsurface energy (oil and gas) exploration, recovery of high- 2 79 temperature fluids from geothermal reservoirs (Toth 2020), and geological CO storage 80 (GCS). The behavior of fractured, low-permeability reservoirs, as in an EGS setting, is a 81 critical consideration in achieving the successful extraction of resources from such 82 reservoirs (Crandall et al. 2019). 83 Modeling and prediction of in-situ rock failure behavior as a function of rock type, pore 84 pressure, spatio-temporal stresses, and fault-reactivation potential provide critical 85 information for proactive decision-making to achieve successful energy production and heat 86 extraction operations (Dotsey and Deighton 2012; Wang and Ghassemi 2012; Stober and Bucher 2013; Shao et al. 2016; Nadimi et al. 2020; Zhang et al. 2020; Ziegler and Heidbach 3 87 88 2020). In addition, the post-primary mineral precipitation during hydrothermal alterations 89 has a significant impact on the mechanical properties of a geothermal reservoir (Meller and 90 Kohl 2014). However, the rock mechanical properties of EGS reservoirs adopted in 91 numerical models are often overestimated since the effects of pre-existing NF and geological 92 heterogeneity are often not fully accounted for (Frash et al. 2013; Gholizadeh Doonechaly et 93 al. 2013; Riahi et al. 2015; Han et al. 2019; Ishibashi et al. 2019). Therefore, there is a need 94 to better constrain the modeling of the rock mechanical response due to the pre-existing 95 geological heterogeneity of target geothermal reservoirs, by considering its geomechanical 96 and mineralogical properties, in addition to its fractomechanical behavior. 97 Here, we examine the distribution of mechanical properties along the cored interval of a 98 high-temperature sedimentary formation, and the implications for the extraction of heat 99 from a target EGS reservoir. We utilize the Scratch Test method to characterize the 100 mechanical properties of a core from a potential geothermal area in the Central Basin 101 Platform of the Permian Basin, United States. Our results show heterogeneous mineralogy 102 and rock strength distributions over the core length, with alternating mechanically weak and 103 strong intervals. Further, we find denser clustering of fractures in the stronger zones the 104 cored intervals (1705.12 – 1705.53 m and 1705.71 – 1705.86 m) which facilitated the 105 hydrothermal vein development, was due to the influence of mechanical stratigraphy on the 106 brittle deformation and alteration of the sedimentary-hosted hydrothermal reservoir. Our 107 findings in this study provide an analog for hydraulic stimulation of viable geothermal 108 reservoir targets at higher in-situ temperatures and higher geothermal gradients. 109 2. Permian Basin Geothermal Areas 110 2 111 The Permian Basin is a large (220,000 km ) Late Paleozoic sedimentary basin, spanning 112 parts of West Texas and Southeastern New Mexico, United States. The Permian Basin is 113 composed of three smaller components known as the Delaware Basin, the Central Basin 114 Platform, and the Midland Basin (Tang 2015). The Central Basin Platform, which lies 115 between the Midland and Delaware Basins, is a zone of Permian tectonic uplift and hosts a significant sequence of carbonate reservoir units, and has a geothermal gradient in the range 4 116 117 of 23.04 – 28.51 °C/km (Erdlac Jr and Swift 2004; Ruppel et al. 2005). Among these is the 118 prominent San Andres Formation which is known to have an average porosity of ~7% and 119 permeability in the range of 1-100 mD (Saller et al.
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