Optimizing hydraulic fracturing in the Paradox formation: A geomechanical study of the Cane Creek play

Z. DVORY and B. J. MCPHERSON, Civil & Environmental Engineering & Energy and Geoscience Institute, and J. D. MCLENNAN, Chemical Engineering & Energy and Geoscience Institute, University of Utah  

Introduction 

The Cane Creek play in the Pennsylvanian-age Paradox formation in southeastern Utah is regarded as a promising-yet-challenging, unconventional tight oil play in the U.S., with a history marked by drilling and completion difficulties. Initially identified nearly a century ago, substantial exploration resumed only in the early 1990s with the advent of horizontal drilling technology.  

Despite some successful wells, achieving substantial production remained elusive. Research, sponsored by the U.S. Department of Energy, aims to leverage the basin's geomechanics knowledge and develop sustainable and economic stimulation strategies. A common hypothesis that local operators hold is that the main challenge in developing the Cane Creek play is successfully accessing natural fractures.  

Yet, studies such as Walton & McLennan (2013) have shown that natural fractures may not significantly contribute to productivity. We acknowledge that the natural fractures stimulation approach is valid when there is a tractable number of relatively large conductive fractures or faults or possibly when their orientation relative to the stress field is optimal for slippage. Considering slippage-related conductivity, we recognize two mechanisms that might trigger slip: (1) the decrease in the effective stress, due to pore pressure rise in the vicinity of the propagating hydraulic fracture; and (2) the increase of the differential stress over the fracture surface, due to stress shadow propagation. 

Fig. 1. Research site location in the Paradox basin stretches across Utah, Colorado, Arizona, and New Mexico. The black lines represent the orientations of the maximum horizontal stress (SHmax) delineated by Dvory et al. (2024). This map also demarcates the Paradox basin's depositional and tectonic boundaries, including the Uncompahgre and San Luis uplifts. The positions of the basin's salt wall structures are marked, using gray polygons, aligning with the findings of Trudgill (2011) and Baars (1966).

The two mechanisms depend on the hydraulic fracture propagation and the stimulation fluids leak-off into the rock—the latter will be relatively small from a matrix perspective. Recent Eagle Ford, Permian and Junggar basin studies reported a detailed characterization of hydraulic fracture propagation. These studies showed, from slant core fracture characteristics and fiber optic studies, that hydraulic fractures in those plays typically spread in strands of fracture swarms that are oriented in the direction of the maximum horizontal stress (Gale et al., 2018, 2021; Raterman et al., 2017, 2019; Shi et al., 2022; Ugueto et al., 2021).   

Specifically, Ugueto et al. (2021) showed broadly linear fracture hits in offset wells, which implies that fracture propagation behaviors, such as branching and stepovers, are limited to a small scale. Those findings suggest that in a permeability range representing tight reservoirs (0.01-0.1md), the effect of pore pressure distribution in the far field is localized and, therefore, levels up the potential for slip triggered by the stress shadow distribution. Microseismicity, specifically for multi-stage hydraulic fracturing in horizontal wells, is primarily attributed to shear slip on pre-existing fractures and faults. 

The current study assesses the Cane Creek formation’s natural fracture and fault shearing potential by compiling geomechanical data from two test wells with a stress shadow simulation obtained by a planar fracture modeling approach (McClure et al., 2020) executed by Dvory et al. (2024).  

The Cane Creek Play 

The Cane Creek play in the Paradox basin is in southeastern Utah and southwestern Colorado and extends to Arizona and New Mexico, Fig. 1. Natural fractures play a pivotal role in the functionality of several of the play’s producing wells, yet the success rate of stimulation via induced hydraulic fractures isn't consistent. 

Fig. 2. Fracture distributions along State 16-2 Ln—a horizontal well—from an FMI log (a) and along the 100-ft core of State 16-2 vertical well (b).

It's hypothesized that augmenting production within this play will hinge on a refined fundamental characterization, particularly a more accurate quantification of the stress state. A new dataset, comprising around 110 ft of core well logs, including a Formation Microimager (FMI) image log and a diagnostic fracture injection test (DFIT), was gathered from the State 16-2 vertical test well and the State 16-2 Ln horizontal well. A detailed assessment of the natural fracture distribution in the core from the State 16-2 vertical well was carried out by Cooper and Lorenz (2022). Figure 2 illustrates the fracture distribution from the core analysis and the FMI log of the lateral section of State 16-2 Ln well. 

The 𝑆_Hmax orientation of N104ºE obtained from well logs (Dvory & McLennan, 2014) and a strike-slip faulting regime was mapped in this locality, with 𝑆_V > 𝑆_Hmax > 𝑆_hmin, where 𝑆_V is the vertical principal stress and 𝑆_hmin represents the minimum horizontal principal stress (Lund Snee & Zoback, 2020).  

Insights from Mohr Diagrams 

In the terrestrial crust, brittle rocks are critically stressed, meaning optimally oriented faults for slip within the ambient stress field maintain a state of frictional equilibrium. However, in the Paradox basin's quasi-isotropic stress state, viscoplastic stress relaxation processes in the salts and clastic formation require an additional pore pressure increase of about 840 psi before slip initiation. 

Fig. 3. Natural fracture activation with increased pore pressure illustrated through Mohr circles. Colored dots represent the fracture distance to failure. Black dots are fractures in failure mode. a) Natural fractures are identified from the FMI log under a frictional failure equilibrium state. b) Natural fractures are observed along the core under a frictional failure equilibrium state. c) induced fractures from the FMI log and d) from the core at the frac gradient pore pressure level (Pp ≈ 𝑆hmin).

Figure 3a,b shows fractures mapped in the core and the FMI log in a Mohr diagram normalized by the vertical stress. This plot depicts the shear and normal effective stresses resolved on each plane, given the measured stress state and pore pressure. The colored scale represents the fracture’s proximity to failure. Here, a slight rise in pore pressure for an optimally oriented fracture (colored in red dots) may trigger slip, while fractures colored by dark blue dots are stable. 

During stimulation, fluid injection progressively augments until reaching the frac gradient (Pp ≈ 𝑆_hmin). The current analysis excludes the pressure rise over 𝑆_hmin during stimulation, typically around a few MPa (a few hundred psi) caused by high-rate pumping of a viscous fluid. As pressure ascends, more sub-optimally oriented planes potentially slip (Fig. 3c,d—black dots above the frictional equilibrium line). At this stage, natural fractures and faults undergo shear stimulation, becoming permeable, and their diverse orientations contribute to an interconnected fracture network. 

Notably, while most planes are anticipated to slip upon reaching the frac gradient, several will not (colored dots below the frictional equilibrium line). Figure 4 shows the 177 sub-optimally oriented planes from Fig. 3c that potentially slip along the 7,064 ft that penetrated well 16-2 Ln. On average, a fracture could stimulate every 40 ft, which is relatively poor coverage, compared to the documented performance of the hydraulic fracturing operations at the HFTS 2, where the average distance between fractures is 1.9 ft (Gale et al., 2021).    

Fig. 4. State 16-2 Ln well placement within the Cane Creek play. Yellow dots-induced fractures from the FMI log (Fig. 3c).

Could the stress shadow trigger natural fracture slippage at the Cane Creek stress state? 

In the context of hydraulic fracturing, the term "stress shadow" refers to a zone where the stress dynamics have been altered, due to the expansion of an adjacent fracture. 

Upon creation or expansion, a fracture exerts pressure on the surrounding rock, changing the stress field around it. The propagation of a stress shadow is a complex geomechanical process that falls beyond the ambit of the present study. Nonetheless, we recognize that its contribution to the stress field could be in either principal direction. The magnitude of a stress shadow is not a fixed value. It depends on factors related to the geological setting and the specifics of the hydraulic fracturing operation.  

We considered two components of the stress shadow effect for the ongoing analysis. The first is a poroelastic change, and the second is the stress change, due to the fracture opening. For the poroelastic stress change, we have used a value of 500 psi at the stress shadow front to explore the fracture failure potential in the ‘far field,’ where the effect of the pore pressure perturbation is negligible. Here, we elevated the three-principal stress by the stress shadow magnitude and explored the new stress state and its implication on the failure potential of fractures.  

Fig. 5. Modification of stress state, due to the application of additional stress (∆P) to each principal axis.

Figure 5 illustrates the effective stress as a function of additional stress (∆P) applied to each principal stress. When this “supplement” is added to the maximum horizontal stress, it does not alter the state of stress, since the in-situ stress is already in a normal faulting state. However, for the vertical stress, the stress state transitions to a normal faulting stress state. If the least minimum stress is elevated, then the state of stress transfers to reverse faulting, while the two horizontal stresses interchange.  

A comparable pattern was observed in the Fort Worth basin, where a similar stress state exists. Here, a focal-plane mechanisms analysis of microseismic events obtained during a Barnett shale stimulation exhibits a range of normal and strike-slip behavior (Kuang et al., 2017). The elevated stress that may arise from the poroelastic response increases the tendency to slip. In this case, the difference between the horizontal stresses (𝑆_Hmax - 𝑆_hmin) was higher than the poroelastic response (and most likely higher than the stress shadow), since no reverse faulting behavior was documented. 

Fig. 6. The stress shadow effect after supplementing 500 psi to each principal stress.

Fig. 7. Critical threshold for the stress shadow magnitude to induce slip.

The application of 500 psi for each principal stress is shown in Fig. 6. Since the initial stress state in the Cane Creek play is far from critical, the shear stress on each fracture plane does not reach the critical value despite the additional stress added to the system. Figure 7 illustrates the critical threshold for the stress shadow magnitude to induce slip. We demonstrate that adding 1,650 psi in the S_Hmax direction will transition the reservoir to a failure mode. 

STRESS SHADOW ASSESSMENT FROM PLANAR FRACTURE MODELING 

Fig. 8. Poroelastic stress change along the Shmin direction before stage 11 shutdown in well State 16-2 Ln (For additional simulation parameters, see Dvory et al. 2024).

We utilized a "planar fracture modeling" technique to simulate the poroelastic response and the stress shadow distribution (McClure et al., 2020). Our model is based on the Dvory et al. (2024) fracture propagation investigation that formulated a methodology for constraining fracture length. The basis of the planar fracture model is tensile, not a shear failure. Our slippage analysis strictly relates to the poroelastic and stress shadow changes obtained from the numeric simulation.  

A detailed description of our modeling strategy and results is shown in Dvory et al. (2024). Our simulation process began with calibration, using data from Stage 11 and the associated production dataset. Subsequently, we conducted a sensitivity analysis on the fracture toughness profile and evaluated how varying cluster spacing influences fracture length.

Figure 8 shows the poroelastic effect in the S_hmin direction before the Stage 11 shutdown.  

Fig. 9. Stress shadowing along the Shmin direction before stage 11 shutdown in well State 16-2 Ln. The stress shadow here includes the poroelastic and the fracture opening effects (For additional simulation parameters, see Dvory et al. 2024).

Our results show that the maximum stress shadow develops close to the well and reaches ~232 psi. This value, alone, would not be sufficient to induce slip. Figure 9 illustrates the stress shadow magnitude along the minimum horizontal stress orientation at the stage shutdown. The total stress change comprises the poroelastic effects and the remote mechanical stress associated with fracture opening. The maximum stress shadow at shutdown is around 850 psi in the near-field (red in Fig. 9). The lateral stress change in the Cane Creek unit is less than 100 psi. The latter implies that far-field fractures are less likely to slip since the stress change is below 1,650 psi (Fig. 7). 

DISCUSSION  

Our findings highlight the geomechanical behavior of the Cane Creek play, emphasizing the intricacies involved in triggering natural fractures. While traditional perspectives have underscored the role of natural fractures in productivity, our investigation corroborates the emerging consensus that the stimulation of such fractures may not be inherently linked to productivity. Instead, this study highlights the role of fracture propagation dynamics' criticality and stress shadow effects in fracture stimulation. 

Hydraulic fracture propagation studies, like those from the Eagle Ford shale and Permian basin, shed light on the directional preferences of fracture swarms and underscore the importance of stress orientation in influencing fracture trajectories (Raterman et al., 2019; Gale et al., 2021; Ugueto et al., 2019a; 2019b). Our analysis of the Cane Creek play extends these insights, suggesting that pore pressure distribution and stress shadow propagation are decisive factors in the stimulation process. The localized pore pressure effects and the potential for slip triggered by stress shadows provide a nuanced understanding of fracture behavior in tight reservoirs. 

The planar fracture modeling approach adopted in this study further advances our understanding by providing a granular view of the shear potential of natural fractures and faults (Dvory et al., 2024; Dvory and McLennan 2024). The sensitivity analysis of stress shadow effects, incorporating both poroelastic and fracture opening components, reveals that the stress state in the Cane Creek play is not inherently conducive to slip without significant stress alteration. This observation aligns with the documented behavior in other basins, like the Fort Worth basin (Kuang et al., 2017), offering a comparative framework for assessing the role of stress shadows in different geological settings. 

CONCLUSIONS  

This study of the Cane Creek play within the Paradox formation has brought to light several insights regarding the role of natural fractures and faults in tight oil plays. We demonstrated that the stimulation of natural fractures, traditionally believed to be a cornerstone for well productivity, may not directly correlate with enhanced production. Instead, the critical factors appear to be the directionality of fracture propagation and the intricate dynamics of stress shadow effects. 

Our examination of fracture propagation behavior suggests that while hydraulic fracturing operations successfully generate fracture swarms, their productivity may hinge on localized pore pressure rise and the ability to manipulate stress shadow propagation effectively (which is aspirational only). Our findings underscore the limited potential for distilling natural fracture stimulation under the current geomechanical state of the Cane Creek play, as significant alterations in stress conditions are required to initiate slip-on fracture planes. 

Planar fracture modeling has yielded a nuanced understanding of the shear potential across adjacent, remote natural fractures and faults, indicating that the existing stress state is less than optimal for inducing slip without substantial stress modification in this geologic setting. This aligns with behavior observed in other basins and provides a comparative perspective on the role of stress shadows in various geological contexts. 

Considering these findings, we advocate for a revised approach to hydraulic fracturing that prioritizes a detailed assessment of stress states and fracture propagation dynamics. Such an approach could enable better stress shadow management and, consequently, improve the predictability and efficiency of fracturing operations, leading to more sustainable and economically sound resource extraction. 

Further research should quantify the intricate relationship between pore pressure dynamics, stress shadow development, and fracture orientation. Understanding these relationships is key to incrementally improving stimulation techniques in unconventional plays, potentially altering the course of hydraulic fracturing strategies to meet the dual goals of economic viability and environmental stewardship. 

ACKNOWLEDGMENTS 

This article is based on paper ARMA 24-1158, presented at the 58th U.S. Rock Mechanics/Geomechanics Symposium, held in Golden, Colorado, USA, on June 23–26, 2024. The research presented in this study was funded by the U.S. Department of Energy (DOE) project "Improving Production in the Emerging Paradox Oil Play" (Award No. DE-FE0031775). The authors thank Mark McClure for his valuable feedback and acknowledge the support of the ResFrac academic program. Additionally, the authors express their gratitude to the University of Utah’s industry partner, Zephyr Energy, with special thanks to Gregor Maxwell and Dave List for their contributions.

References 

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1. NO’AM ZACH DVORY is research assistant professor of civil and environmental engineering, as well as the Energy and Geoscience Institute, at the University of Utah. He holds a B.Sc. degree in earth science from Hebrew University of Jerusalem, an M.Sc. degree in geophysics from Hebrew University of Jerusalem, and a Ph.D. in fluid dynamics from Ben Gurion University of the Negev, project: Recharge and Flow. Dr. Dvory’s professional experience includes technical lab manager at I.T.M.; geologist/geophysicist at Geophysical institute of Israel; geologist and project manager at Natural Resources Development Ltd.; and CVO/chief geologist at Etgar A. Engineering Ltd. Dr. Dvory’s research interests focus on nano to reservoir scale geomechanical responses for pore pressure perturbations and thermo-chemical evolution. 
2. BRIAN MCPHERSON is USTAR professor of civil & environmental engineering, as well as the Energy and Geoscience Institute, at the University of Utah. He holds a a B.Sc. degree in geophysics from the University of Oklahoma and earned M.S. and Ph.D. degrees in geophysics from the University of Utah. Dr. McPherson’s professional experience includes hydrologist at the U.S. Geological Survey; research hydrologist in the Geophysical Research Center at New Mexico Institute of Mining and Technology; assistant professor of hydrology at New Mexico Institute of Mining and Technology; senior scientist for the  New Mexico Tech Petroleum Recovery Research Center; and associate professor of hydrology at New Mexico Institute of Mining and Technology. Dr. McPherson’s technical focus areas include groundwater and reservoir simulation, multiphase flow analysis and simulation, rock deformation, and subsurface chemically reactive transport analysis and simulation. 
3. JOHN MCLENNAN is professor of chemical engineering, as well as the Energy and Geoscience Institute, at the University of Utah. He earned a B.A.Sc. degree in geological engineering from University of Toronto, as well as an M.A.Sc. degree and a Ph.D. in civil engineering from University of Toronto. Dr. McLennan’s professional experience includes positions of increasing responsibility at TTI Geotechnical Resources Ltd., Dowell Schlumberger, TerraTek, Inc., Advantek International Corporation and ASRC Energy Services E & P Technology. He has worked on coalbed methane recovery, mechanical properties determinations, produced water and drill cuttings reinjection, as well as casing design issues related to compaction. Dr. McLennan’s recent work has focused on optimized gas production from shales and unconsolidated formations.