Completed. Immediate Delivery. More Efficient Hydraulic Fracturing Systems for Ultra-tight Shale Reservoirs. Ian Walton II 01024

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1 Completed Immediate Delivery Principal Investigators: Ian Walton, Ph.D. Senior Research Scientist New Sponsors Receive Full Report On-site Presentation More Efficient Hydraulic Fracturing Systems for Ultra-tight Shale Reservoirs Dr. Dr. Ian Ian Walton Walton II Work Flow Integration Sponsor Cost $40k (USD) Energy & Geoscience Institute PHONE: (801) Project I egi.utah.edu EGI... the science to find energy EGIDirector@egi.utah.edu October 29, :24 AM approved 22Jun17 28Jun17

2 Executive Summary Over the last twenty or so years, commercial development of ultra-tight shale reservoirs has been achieved by the implementation of multi-stage hydraulic fracturing of long horizontal wells. Favorable results have been associated with the creation of a large fracture surface area in contact with the shale matrix this surface area often being created by high-rate and high-volume injection of low viscosity water-based fluids. The environmental and economic implications of using large volumes of water (millions of gallons per well) are attracting considerable stakeholder and regulatory attention. The fracture systems created by this process are often complex, involving both hydraulic fractures and a subsidiary fracture network that may originate in natural fractures already present in the rock fabric. However, previous studies at EGI have suggested that gas production comes mainly from the hydraulic fractures. We have concluded that the current process is highly inefficient in that only a small fraction of the injected fracturing fluid serves to create the productive fractures. In this project we have investigated a route to More Efficient Fracturing for Shale Gas Developments. We have determined fracturing protocols under which a higher percentage of the injected fracturing fluid remains within the hydraulic fractures. This is achieved by reducing the rate of fluid loss into the re-opened natural fracture network. Fluid loss from the hydraulic fractures into the natural fractures is modeled in terms of fluid flow into fissures so-called pressure-dependent leakoff. We have been able to demonstrate that in the absence of fluid loss, the length of the main fracture is increased by using a low viscosity fluid. However, fluid loss is also increased when using a low viscosity fluid, which results in a reduction in fracture length. Trade off of these competing effects results in an estimate of an optimal fracture fluid viscosity that maximizes the fracture length. Using semi-analytic mathematical models of fracture development and pressure-dependent leak-off we have been able to provide for the first time an estimate of the optimal fluid viscosity that maximizes hydraulic fracture length and productivity. The efficiency of this optimal fracturing system is significantly higher than in more conventional operations that use slickwater as the fracturing fluid. The results of our analysis have been distilled down to an analytic formula that allows an estimate to be made of the optimal fluid viscosity in terms of operating parameters and reservoir properties. All other parameters being equal, increasing the viscosity of the fracturing fluid up to the optimum value will result in an increase in the length of the primary fracture and an increase in fracturing efficiency. Alternatively, a desired primary fracture length could be achieved by pumping less fluid. 2

3 Sponsors Table of Contents Executive Summary... ix Section 1 Introduction... 1 Section 2 Fracturing Fluids for Ultra-tight Shales...11 Section 3 Hydraulic Fracture Models with Zero Leakoff...17 Section 4 Conventional Fracture Leakoff and its Impact on Fracture Geometry Fracture Development with Low Leakoff Rate Fracture Development at High Leakoff Rate Fracture Development at Moderate Leakoff Rate: General Solution Conventional Leakoff: Implications Fracture Length Fracturing Efficiency Section 5 Pressure-dependent Leakoff into Fissures...53 Section 6 Conclusions...59 Section 7 Parameter Value Tables and Nomenclature Nomenclature References...67 Appendix A Similarity Solution for PKN Model with No Leakoff...71 Appendix B PKN Solution for High Leakoff Rate

4 List of Figures Figure 1.1 Representation of primary fractures (solid lines) and rudimentary secondary fracture networks (thin lines) created by slickwater fracturing of a horizontal well... 3 Figure 1.2 Comparison of cross-linked gel frac and water re-frac micro-seismic observations from a horizontal Barnett well (from Cipolla et al. 2009) Figure 1.3 Representation of various kinds of fractures that may be present in stimulated shale reservoirs Figure 1.4 Experimental measurements of unpropped fracture conductivity, Fredd et al Figure 1.5 Conceptual pictures of the stimulated zones around a multi-fractured horizontal well Figure 2.1 Typical composition of slickwater (Source: DOE Energy Primer)...14 Figure 3.1 Diagram of PKN fracture geometry...19 Figure 3.2 Variation of fracture width with distance from the fracture entrance at several different times. All quantities are dimensionless Figure 3.3 Variation of the net pressure (or fracture width) with time at several different distances from the fracture entrance. All quantities are dimensionless Figure 3.4 Variation of the fracture width with distance from the fracture entrance at several different times. All quantities are dimensionless Figure 3.5 Variation of the net pressure (or fracture width) with time at several different distances from the fracture entrance. All quantities are dimensionless Figure 3.6 Evolution of the fracture length with time computed by solving the partial differential equation for the dimensionless fracture width (Equation A1 )...27 Figure 3.7 The time at which the fracture tip reaches a specified distance from the fracture entrance, computed by solving the partial differential equation for the dimensionless fracture width (Equation A1 )...27 Figure 4.1 Fracture length against time for C LD = 0, 0.02, and Figure 4.2 Exposure time against distance from the fracture entrance for CLD = 0, 0.02, and Figure 4.3 Dependence of the final fracture length, index n and fracture efficiency with leakoff coefficient. All quantities are dimensionless...34 Figure 4.4 Variation of dimensionless fracture length with dimensionless time. Nordgren s numerical solution is compared with the zero leakoff and high leakoff asymptotic solutions...40 Figure 4.5 Variation of dimensionless fracture length with dimensionless time. Our composite analytical approximation is compared with the zero leakoff and high leakoff asymptotic solutions...41 Figure 4.6 Variation of maximum fracture width with distance from the fracture entrance (after Nordgren)

5 Figure 4.7 Variation of dimensionless fracture width with dimensionless time. Nordgren s numerical solution is compared with the zero leakoff and high leakoff asymptotic solutions (after Nordgren 1972)...43 Figure 4.8 Variation of dimensionless fracture length with dimensionless time. Our composite analytical approximations are compared with the zero leakoff and high leakoff asymptotic solutions...44 Figure 4.9 Variation of normalized fracture length with normalized fluid viscosity for several values of the parameter α Figure 4.10 Estimate of the fracturing efficiency against dimensionless time...51 Figure 5.1 Stages in the dilation of a fissure intersected by a hydraulic fracture: the fissure begins to dilate when the fluid pressure in the fracture exceeds a critical value to overcome the confining stress normal to the fissure surface...54 Figure A.1 Solution of Equation A11 with boundary condition A List of Tables Table 7.1 Typical parameter values appropriate for fracturing with a thin fracturing fluid (water) in an ultra-tight reservoir (shale)...64 Table 7.2 Typical parameter values appropriate for fracturing with a thin fracturing fluid (water) in an ultra-tight reservoir (shale) in which leakoff is dominated by flow into natural fractures or fissures

6 Senior Research Scientist Ian Walton, Ph.D. Phone Research Interests Unconventional gas production Rock-fluid interactions Near-wellbore geomechanics Fluid processes Ian holds a Ph.D. in Applied Mathematics from the University of Manchester and a B.Sc. in Mathematics from University College London. He has a total of 11 years academic experience between Imperial College London and the University of California, Los Angeles (UCLA) where he was a Visiting Professor. Ian s 25 years of oil industry experience began with BP Research in Sunbury and then at various Schlumberger locations, including Schlumberger Cambridge Research, Dowell Tech Center, Tulsa, Perforating Research in Rosharon, Texas and, most recently, the Regional Technology Center for Unconventional Gas in Dallas. He has published more than 70 papers and has been awarded eight patents. Professional Philosophy Unconventional Gas Production By developing mathematical models of the production process, Ian has been able to provide fundamental insights into production mechanisms, identify the main production drivers, and relate those drivers to measurable formation, reservoir, and fluid parameters, and to specific completions practices. His recent work has focused on the role of induced and natural fractures in the production process and the distribution and flowback of pumped fracturing fluid. The models also facilitate history matching of production data and provide more accurate estimates of future production than do conventional techniques. Rock-fluid interactions The development of mathematical models has facilitated better understanding of processes such as imbibition and desorption that are important for shale gas production. Models have also been developed to interpret and enhance laboratory measurements of capillary pressure, permeability, relative permeability and porosity. Near-wellbore Geomechanics Ian has worked on the impact of rock properties on shaped charge perforating and the identification of optimal perforating systems for the generation of hydraulic fractures, specifically in multi-fractured horizontal wells. The near-wellbore fracture geometry for horizontal gas shale wells is a current focus. Fluid Processes Throughout his career, Ian has developed fluid mechanics models for many different oil field applications, whether they are in the wellbore (non-newtonian and two-phase fluid pressure losses, pressure transients and sand transport) or in the reservoir itself. egi.utah.edu EGI... the science to find energy EGIDirector@egi.utah.edu April 10, :15 AM 28Jun17