This study evaluates hydraulic fracturing strategies and their interplay with natural fracture activation in the Cane Creek Unit of Utah’s Paradox formation. A planar fracture modeling approach simulated stress shadow effects and pore pressure increases, revealing their impact on natural fracture activation and hydraulic fracture containment. Results emphasize the importance of balancing stimulation designs to optimize reservoir connectivity while mitigating operational challenges posed by surrounding salt formations.
N. Z. DVORY and B. J MCPHERSON, Civil & Environmental Engineering and Energy & Geoscience Institute, University of Utah; J. D. MCLENNAN, Chemical Engineering and Energy & Geoscience Institute, University of Utah
INTRODUCTION
The dispute over the relative efficiency of hydraulic versus natural fractures in enhancing reservoir hydraulic properties and stimulation efficiency is central to optimizing resource extraction in unconventional reservoirs and, recently, improving the hydraulic properties of enhanced geothermal systems (Kolawole and Ispas 2020; Makedonska et al. 2020). Both fracture types have unique roles in fluid flow and reservoir permeability. Still, their contributions to long-term productivity and stimulation efficiency remain subjects of active discussion in reservoir engineering.
Hydraulic fractures are intentionally created during stimulation to enhance permeability and establish flow paths through low-permeability rock (Economides and Nolte 2013). Their geometry, orientation and conductivity can be controlled to some extent through operational parameters, such as fluid injection rates, proppant selection, and fracture spacing. Hydraulic fractures extend from the wellbore into the reservoir in predictable patterns, perpendicular to the local minimum principal stress, enhancing permeability by connecting the well to previously isolated reservoir sections (Zoback and Kohli 2019).
Hydraulic fractures can be highly effective at increasing stimulation efficiency, because they can be engineered to target specific reservoir zones. However, hydraulic fractures could fail to maintain open channels for long-term flow, due to proppant embedment, fracture closure, and chemical interactions with the reservoir rock (Hakso and Zoback 2019). Creating these fractures also can inadvertently induce stress shadows that inhibit or alter the growth of subsequent fractures, potentially limiting the overall stimulated volume (Singh et al. 2019, 2020). In some reservoirs, as in the Cane Creek Unit, hydraulic fractures may propagate into non-target zones, such as adjacent salt layers, compromising production efficiency and increasing operational costs (Dvory et al. 2024a).
Natural fractures are pre-existing discontinuities in the reservoir rock, formed through geological processes over time. These fractures have often been emphasized in stimulation designs, due to their potential to increase connectivity within the reservoir (Makedonska et al. 2020). Natural fractures reactivating during stimulation can lead to a more extensive fracture network, improving fluid flow and reservoir permeability over larger areas than engineered hydraulic fractures alone.
Natural fractures can create a network of flow paths that may connect isolated rock volumes to the well, facilitating hydrocarbon flow and improving stimulation efficiency without requiring additional fractures to be created. However, relying on natural fractures comes with challenges (Walton and McLennan 2013). Unlike hydraulic fractures, natural fractures are not uniformly distributed, and their geometry and orientation are often unpredictable, complicating stimulation planning. They may also be oriented sub-optimally relative to the in-situ stress field, making them less likely to slip and contribute to flow under typical stimulation pressures (Dvory et al. 2024b). Furthermore, natural fractures are typically unpropped, making them susceptible to closure under native stress conditions, which can reduce permeability over time and lead to diminished production (Gale et al. 2018, 2021).
The Cane Creek Unit, in the Pennsylvanian-age Paradox formation in southeastern Utah, is recognized as a promising-but-challenging unconventional tight oil play in the United States, with a documented history of drilling difficulties and inconsistent stimulation outcomes (Jagniecki et al. 2019; Ochoa et al. 2024). Originally identified nearly a century ago, significant exploration in the area resumed only in the early 1990s with the advancement of horizontal drilling technology. Despite some initial successes, consistent high production remains challenging.
Particularly, designing and constraining hydraulic fractures in the Cane Creek Unit poses unique challenges, due to the complex interplay between the formation's stress state, fracture toughness, and adjacent salt layers. In salt-bearing formations, the behavior of hydraulic fractures is further complicated by the time-dependent viscoplastic response of halite to in-situ stress. Salt deformation mechanisms—primarily creep by pressure solution and dislocation—can promote rapid fracture closure, especially under low differential stress conditions (Urai et al. 1986; Spiers et al. 1990; Bérest et al. 2023).
At elevated stress levels, halite may deform plastically through dislocation creep, impacting fracture aperture persistence. Moreover, salt’s low fracture toughness allows for preferential fracture propagation into evaporite intervals, diverting stimulation efforts away from the hydrocarbon-bearing clastics. These characteristics make halite-rich layers particularly challenging during stimulation design and necessitate tailored strategies to ensure hydraulic fracture confinement within the productive units (Dvory et al. 2024a).
Additionally, triggering slip on natural fractures for enhanced connectivity is difficult, because many natural fractures are not optimally oriented for slippage within the current stress field. The quasi-isotropic stress state of the Paradox formation further complicates this process, as effective stimulation may require stress alterations or pore pressure increases to initiate slip. These factors make it challenging to develop a balanced fracturing design that maximizes connectivity within the oil-bearing zones while preventing fracture extension into non-productive salt layers.
The current study aims to evaluate the potential for reservoir stimulation in the Cane Creek Unit by combining hydraulic fracturing and the activation of natural fractures through mechanisms of elevated pore pressure and stress shadow effects. To achieve this, we employ a "planar fracture modeling" approach to simulate stress shadow distribution in the far field, providing insights into how hydraulic fractures influence the surrounding stress field. Additionally, we apply Mohr-Coulomb failure criteria to assess the stability of natural fractures under varying stress conditions, examining their likelihood of slip when subjected to pore pressure increases and stress shadowing. Together, these methods offer a holistic framework for understanding the interplay between hydraulic and natural fractures in enhancing reservoir connectivity and improving overall stimulation efficiency.
THE CANE CREEK UNIT: BOUNDING SALTS AND STATE OF STRESS
The Cane Creek Unit resides within the Pennsylvanian-age Paradox formation, part of the Paradox basin in southeastern Utah. This structural basin developed in response to regional tectonic forces during the Ancestral Rocky Mountain orogeny. Figure 1 shows the research site in the northern Paradox basin, west of the basin’s salt tectonic boundary (Trudgill 2011). In this area, the Paradox formation comprises cyclic deposition of clastic, carbonate and evaporite layers (Matheny and Longman 1996; Whidden et al. 2013; Heath et al. 2017; Jagniecki et al. 2019). It produces a distinctive geological sequence characterized by alternating organic-rich shales, siltstones, dolomitic mudstones, and extensive halite and anhydrite beds, Fig. 2. This layered stratigraphy results from repeated transgressive-regressive cycles in a restricted marine environment, where fluctuating sea levels lead to the periodic formation of evaporite-rich layers.
The Paradox basin’s structural complexity is compounded by regional faulting and folding, which created numerous anticlines, faults, and fractures that continue to influence its subsurface characteristics (Trudgill 2011; Runyon et al. 2022; Dvory and McLennan 2024). Within the Paradox formation, the Cane Creek interval is an unconventional tight oil play consisting primarily of dolomitic mudstones and siltstones interbedded with anhydrite and halite (Jagniecki et al. 2019). The Cane Creek Unit is divided into several stratigraphic units (commonly referred to as the A, B and C zones), with each unit exhibiting distinct lithological properties and variable porosities, organic contents, and fracture networks. The A and C zones are situated above and below salt beds, respectively, and are typically composed of interbedded and nodular anhydrite with dolomitic mudstone. In contrast, the B zone contains significantly less anhydrite than the A and C zones. Within the B zone, siltstone and very fine-grained sandstone beds serve as the primary horizontal drilling targets in the Cane Creek Unit.
One of the challenges in developing the Cane Creek Unit is the presence of thick salt layers above and below the hydrocarbon productive zones (Dvory and McLennan 2024). These salt deposits exhibit low fracture toughness, making them susceptible to fracturing, which can lead to hydraulic fracture propagation outside the intended reservoir zones. This is particularly problematic as fractures extending into the salt layers can introduce highly saline fluids into the production stream, complicating flowback and increasing operational costs. Additionally, the quasi-isotropic stress state within the Paradox formation, combined with the heterogeneous distribution of natural fractures, creates a complex environment where hydraulic fractures can behave unpredictably.
The natural fracture networks within the Cane Creek interval could potentially play a crucial role in reservoir performance. These fractures vary widely in their orientation, connectivity and stability. While some fractures are well-oriented for slip and enhanced flow, others are not optimally aligned within the current stress field, presenting challenges for their stimulation. The Paradox basin stress field undergoes spatial variations, transitioning from a normal faulting stress state west of the basin at the Wasatch Fault Zone to a strike-slip regime in the basin’s central and northern areas (Dvory and McLennan 2024). In the northern Paradox basin, the orientation of the maximum horizontal stress (SHmax) is east-southeast (ESE), consistent with the regional stress regime, Fig. 1.
A multi-well data acquisition effort was carried out in the northern Paradox basin to evaluate drilling, completion and stimulation strategies within the structurally complex Pennsylvanian Cane Creek Unit and adjacent organic-rich clastic intervals. The campaign included one vertical (State 16-2) and two horizontal wells (State 16-2 LN and State 36-2), with a focus on identifying cost-effective approaches in tight, salt-bounded formations. A diagnostic fracture injection test (DFIT) was conducted in State 16-2, and it showed pore pressure of about 65.5 MPa and minimum horizontal principal stress (Shmin) of 71.3 MPa at a depth of 2,956.8 m. The DFIT results indicated elevated pore pressure and Shmin, reflecting the overpressure in this area and minor differential stress that indicates a semi-isotropic stress state. Post-drilling creeping of the State 16-2 LN well indicates that the SHmax orientation is 104° and is consistent with the broader regional stress orientation across the Paradox formation’s evaporite zones and beyond the basin depositional boundaries (Dvory and McLennan 2024).
Approximately 33.5 m of core, along with well logs, including a Formation Microimager, were acquired from State 16-2 and State 16-2 LN. Core analysis of State 16-2 by Cooper and Lorenz (2022) identified 100 fractures within the Cane Creek, while image log analysis of State 16-2 LN identified 270 fractures along a vertical interval of 2,153.1 m, Martin et al. (2021). Figure 3 illustrates the fracture strike distributions in relation to the in-situ maximum horizontal compressional stress orientation of 104°. Within the horizontal section of State 16-2 LN, 102 high-angle fractures (>70°) primarily strike ENE-WSW. There are 157 low-angle fractures (dips between 30° and 70°) exhibiting a broader scatter in strike directions, ranging from NE-SW to ESE-WNW. The State 16-2 core provides complementary data, showing that most fractures are high-angle extension fractures, with ENE-WSW strike orientations and dips ranging from 65° to 90° relative to bedding (Cooper and Lorenz 2022). These high-angle fractures are likely important for reservoir permeability, due to their high remnant porosity and widespread distribution within the Cane Creek interval's A and upper B zones. Intermediate-angle shear fractures, characterized by more variable strikes and dips between 40° and 70°, may also contribute to connectivity by linking high-angle fractures. Additionally, bed-parallel and low-angle shear fractures are present in specific lithologies, such as organic-rich mudstones, where they may localize deformation but have limited vertical connectivity.
FRACTURE TOUGHNESS MEASUREMENTS
Samples for fracture toughness testing were selected from core sections obtained from State 16-2. Core analysis identified representative lithologies, including anhydritic dolomudstone, anhydritic siltstone, calcareous mudstone, calcareous siltstone, and halite, to capture the range of mechanical properties in the Cane Creek and adjacent salt intervals (Salt 22). Testing was conducted on these samples, using ISRM standardized Mode I (tensile) fracture toughness tests, which measure resistance to crack propagation under planar tension, simulating conditions relevant to hydraulic fracturing (Kuruppu et al. 2014). All fracture toughness tests were conducted with the direction of loading oriented perpendicular to the bedding planes. This configuration was chosen to simulate the most likely orientation of hydraulic fracture propagation in the field, relative to the stratigraphy and the state of stress.
The Mode I fracture toughness (K1) is calculated, using the following equation:
KI =(σ’√πa)/Y (1)
where is the stress intensity factor for Mode I fractures, is the applied stress, is the crack length, and is the geometric factor that accounts for the sample and crack geometry.
Figure 4 presents the measured fracture toughness values alongside the mineralogical compositions derived from XRD analysis. These data suggest that fracture propagation resistance is generally lower in salt-bearing intervals than in quartz-rich clastics. A clear, positive correlation is observed between quartz content and fracture toughness: samples such as WC4_2_08H (56% quartz) and WC5_1_06H (54% quartz) exhibit high fracture toughness values (>1.0 MPa·m¹ᐟ²), whereas samples with minimal quartz content, including WC3_1_03 and WC10_01EP (~3% quartz), show significantly lower values (<0.6 MPa·m¹ᐟ²), as illustrated in Fig. 5.
A moderate positive correlation is also evident with dolomite content; for instance, samples containing 13–21% dolomite (e.g., WC2_1_04H and WC5_1_06H) exhibit toughness values exceeding 1.15 MPa·m¹ᐟ². Anhydrite appears to contribute positively when present in low concentrations (>2%), although this trend is not consistent—sample WC1_2_03HEP, which contains more than 50% anhydrite, displays the lowest recorded toughness in the dataset. The halite-dominated sample ST16_6EP (98% halite) also shows a low fracture toughness value (0.30 MPa·m¹ᐟ²).
These findings are consistent with previous experimental studies on evaporitic rocks, which report lower fracture toughness values in salt rocks comparing to gypsum and anhydrite gearing rooks (e.g., Meng et al. 2015; Li et al. 2020; Wang et al. 2022). Calcite and clay minerals—including illite, chlorite, and kaolinite—do not show a clear correlation with toughness, likely due to their relatively low concentrations. These observations imply that hydraulic fractures initiated within the classic Cane Creek Unit are more likely to propagate vertically into surrounding salt intervals, where the mechanical resistance to fracture growth is lower.
STATE 16-2 LN STIMULATION
In State 16-2 LN, hydraulic fracturing operations were pumped down 14 cm, 29.76 kg/m P-110 grade tubing to a targeted depth of 4,380 m. The fracturing program comprised 14 stages, each approximately 48.8 m long, with five perforation clusters spaced at 9.75 m per stage. Each cluster contained six shots, totaling 30 shots per stage, with an estimated entry hole diameter of 8.38 mm.
Stage 11 can be taken as a representative example of the fracturing procedure. Crew injected 384.5 m3 of clean fluid and 421.4 m3 of slurry during this stage. The fracturing program included a 7.5% hydrochloric acid spearhead, followed by slickwater and 46,983 Kg of 20/40 and 100 mesh Northern White proppant. Surface pressures peaked at 64 MPa, with an average of 59.33 MPa, and the maximum treating rate was 12.94 m3/min. The fracturing gradient was approximately 24.66 KPa/m.
In well State 16-2 LN, stress data from 14 Instantaneous Shut-In Pressure (ISIP) measurements gathered during stimulation suggest that the minimum principal stress varies by depth and rock type. Figure 6 illustrates the wellbore trajectory through the Cane Creek Unit and the ISIP for each stimulation stage (red dots), showing directional changes and the final landing within the target horizon of the Cane Creek unit. The 14 ISIP measurements were correlated with seven stratigraphic units within the Cane Creek sequence. The highest proxy for the minimum horizontal stress (Shmin) value occurs in the lower section of the B Zone, creating a stress barrier (Dvory et al. 2024a). Fractures propagating upward encounter a smaller stress barrier in the upper part of this unit, which may influence fracture containment and reservoir connectivity.
PLANAR FRACTURE MODELING APPROACH, SIMULATION SETUP AND NATURAL FRACTURES STIMULATION
Using a "planar fracture modeling" approach, we simulated pore pressure perturbation, poroelastic responses and stress shadow distributions (McClure et al. 2020). Our model builds on Dvory et al.'s (2024a) methodology, designed to constrain fracture length, primarily under tensile, not shear, failure. The model uses a rectilinear grid to represent the matrix, refined perpendicular to fractures. An artificial “external fracture” was introduced on the well’s toe side in the model to account for stress shadows from prior stages. The viscoelastic stress relaxation method was applied for initial minimum horizontal stress (Shmin) estimation, leveraging geophysical log data and DFIT measurements to capture stress variations with depth. Based on a geomechanical model of viscoelastic stress relaxation in clay-rich rocks, this approach provides continuous Shmin variation with depth (Singh et al. 2021; Dvory et al. 2023).
Our Baseline simulations were calibrated, using Stage 11 field data, which involved slickwater and 20/40 Northern White proppant injected into five perforation clusters over a 48.8-m stage length. Subsequent simulations adjusted parameters, such as cluster spacing, fluid and proppant volumes to explore alternative configurations. Following calibration, a sensitivity analysis on fracture toughness and cluster spacing was conducted to assess their impacts on fracture length. The pore pressure, stress shadow, and poroelastic changes obtained through this numerical model directly inform our slippage analysis. Detailed modeling strategy and results are further outlined in Dvory et al. (2024a).
During well stimulation, pore pressure increases, and stress shadow effects may induce slippage along natural fractures. As hydraulic fractures propagate, fracturing fluid leaks off into the surrounding matrix and any open or opened secondary fractures, locally elevating pore pressure and reducing the effective normal stress on nearby fractures. This reduction brings fractures closer to their failure envelope, increasing the likelihood of slippage. Conversely, stress shadow effects emerge from the redistribution of stress caused by hydraulic fracture propagation, altering shear and normal stresses on adjacent fractures. These differential stress changes can either promote or inhibit slip, depending on the fractures' orientation and proximity to the hydraulic fracture. Pore pressure effects are localized near the hydraulic fracture and depend on fluid diffusion, whereas stress shadow effects extend over a broader area and act immediately upon fracture propagation.
Figure 7 represents the pore pressure alteration distribution (ΔPp) and stress shadow magnitudes (ΔP) across the principal stress directions at the middle of the Cane Creek Unit at stage shutdown. The simulation confirmed that pore pressure increases over the fracture gradient (Pp ≈ Shmin) only close to the well. The stress shadow magnitude varies between the three principal stresses, where the maximum change was calculated along the Shmin direction and reached 9.3, 10.0, and 8.3 MPa at the top, middle, and base of the Cane Creek Unit. A similar pattern was observed in the SHmax direction, indicating that the horizontal stress shadow magnitude is in the near field and directly affects the target formation. The highest and intermediate vertical stress shadow magnitudes at the base and the top of the Cane Creek Unit, indicating a limited effect of the fracture opening in this direction, are expected at the margins of the pressurized area.
The increase in pore pressure, shown in Fig. 7, reaches the fracture gradient close to the well, triggering sub-optimally oriented fracture slippage, as shown by Dvory et al. (2024b). Figure 6 illustrates 177 sub-optimally oriented planes that may slip, due to pore pressure rise along the 2,153 m across the Cane Creek Unit penetrated by well 16-2 LN. In this case, it takes an optimistic assumption that leak-off and continuous pore pressure rise occur along the well, and one fracture could be stimulated every 12.2 m. This is substantially lower than the fracture density observed at HFTS 2, where hydraulic fracturing created fractures approximately every 0.58 m (Gale et al. 2021). However, as shown below, stress shadow management can potentially trigger additional fractures in the near field.
The stress shadow differential alteration of in situ principal stresses shown in Fig. 7 may alter the local stress state. For instance, our analysis identified locations where an increase in the minimum horizontal stress shifted the local stress regime from normal faulting to reverse faulting. Similar phenomena have been observed in other locations, such as the Fort Worth basin, where focal-plane mechanisms of microseismic events during Barnett shale stimulation showed normal and strike-slip tensors, indicating a transition toward a compressional stress state (Kuang et al. 2017).
To evaluate the spatial change in the stress state and its implications for the current analysis, we calculated the relative magnitudes of the three principal stresses (Simpson 1997). This method uses a single interpolated parameter, , that provides a continuous illustration of changes in the stress field, with values ranging from 0 (extensional, radial normal faulting) to 3 (compressive, radial reverse faulting) (Lundstern and Zoback 2018).
The parameter is expressed as:
Aϕ = n + 0.5 + (-1)n ((S2 -S3) / (S1 -S3 ) - 0.5) (2)
where S1, S2, and S3 are the magnitudes of the maximum, intermediate and minimum principal stresses, respectively, and n corresponds to faulting regimes: 0 for normal faulting, 1 for strike-slip faulting, and 2 for reverse faulting.
Fig. 8 shows the magnitude and spatial distribution of the stress shadow spatial variation in stress states at the top, middle and bottom of the Cane Creek Unit. The figure indicates that significant changes in the stress state occur near the well, with the parameter increasing from 1.41 to 2.17 at the top, 1.42 to 2.28 at the middle, and 1.51 to 2.02 at the base of the Cane Creek Unit. All levels show a transition into a compressional stress state, with the highest magnitude close to the well, in the middle of the Cane Creek Unit.
The local rotation in the stress field may trigger slippage along near-field pressurized faults that are not critically stressed in the in-situ stress state. Farther in the Cane Creek Unit, the magnitude of the stress shadow, without elevated pore pressure, remains insufficient to induce slip. Figure 9 illustrates the stress state evolution of unpressurized natural fractures under extreme stress shadow effects at the middle of the Cane Creek Unit. This figure highlights the maximum stress shadow magnitudes (ΔP) across a principal stress direction.
At the top of the Cane Creek Unit, maximum ΔP changes in minimum horizontal stress and the overburden stress directions shift the stress state from strike-slip to reverse faulting, primarily near regions of intense stress shadow development. Similarly, at the middle of the unit (Fig. 9), significant ΔShmin and ΔSv changes also induce a transition from strike-slip to reverse faulting, while differential stress between ΔShmin and ΔSv is notably reduced in zones with extreme ΔSHmax changes. At the base of the Cane Creek Unit, extreme ΔShmin changes dominate the transition from strike-slip to reverse faulting, with reduced differential stress observed in areas where stress shadow effects are most pronounced.
EVALUATING HYDRAULIC FRACTURE DESIGN AND STRESS SHADOW IMPACTS ON NATURAL FRACTURE STIMULATION
The limited triggering potential of natural fractures described here and by Dvory et al. (2024b), combined with the reduced production rates in well 16-2 LN caused by salt obstructing production, underscores the challenges associated with hydraulic fractures extending into salt formations and the limited effectiveness of reactivating natural fractures in the Cane Creek Unit. A key challenge in stimulating this unit lies in enhancing shear activation on natural fractures and generating new shear fractures while confining hydraulic fracture propagation within the Cane Creek Unit to avoid extension into the surrounding salts. To address this, Dvory et al. (2024a) evaluated nine stimulation designs, varying cluster spacing at 9.75 m (baseline), 4.88 m, and 3.05 m, along with fluid volumes set at 100%, 50%, and 25% of the original stimulation volumes.
Their findings indicated that a 16-cluster design with a 25% reduction in injection volume achieved a more balanced fracture distribution, limiting salt exposure to less than 33% of the fracture area and reducing salt exposure to 13% of the original design. However, the fracture surface area within the Cane Creek Unit was reduced 60%, limiting leak-off, stress shadow distribution, and potentially impacting production. Here, we assess the impact of a 16-cluster design using the original stimulation volumes. This configuration results in a 60% increase in the fracture surface area within the Cane Creek Unit, amplifying seepage and the stress shadow effect within the target formation. Moreover, it also leads to a 17% increase in the proportion of the fracture area contained within the Cane Creek Unit, relative to the overall fracture area extending into the salts.
Fracture propagations, pore pressure, and stress evolution at the 16-cluster scenario at the middle of the Cane Creek Unit at stage shutdown is shown in Fig. 10. This strategy reduced the overall fracture penetration into salts in the far field. Moreover, the stress shadow depression of some fracture propagation and their limited extent in the nearfield enabled intensified seepage into the target formations. An elevated stress shadow is seen near the borehole with extreme ΔShmin values of 13.2, 16.5, and 10.5 MPa at the top, middle, and base of the Cane Creek Unit, Fig. 11. As in the five-cluster design, the greatest horizontal stress shadow magnitude is observed in the middle of the Cane Creek Unit.
The highest and intermediate vertical stress shadow magnitudes are at the Cane Creek Unit's base and top. The maximum magnitude of the stress shadow in the minimum horizontal stress direction at the middle of the Cane Creek Unit in this simulation is higher by 65%, compared with the original design. Consequently, a greater transition into a compressional stress state occurs. Indeed, Fig. 8 shows elevated parameter in the middle and the top of the Cane Creek Unit. This compressional transition is limited to the near-field and extreme parameter magnitude of 2.66, 2.94, and 2.74 at the top, middle, and base of the Cane Creek Unit. Specifically, at the middle of the Cane Creek Unit (Fig. 11), extreme ΔP changes in all principal directions shift the stress state from strike-slip to reverse faulting. A modest effect of the stress shadow is observed at the base of the Cane Creek, where only an extreme ΔP in the ΔShmin direction moves the stress state toward reverse faulting.
DISCUSSION
The findings of this study emphasize the complexities involved in optimizing hydraulic fracturing designs for the Cane Creek Unit, given its challenging geomechanical properties and adjacent salt formations. While hydraulic fractures are essential for establishing flow paths, their extension into salt layers poses operational risks, including increased brine backflow, reduced production efficiency, and higher operational costs. Moreover, we show that the local stratigraphy elevates this challenge, as the quartz-rich Cane Creek Unit exhibited higher fracture toughness and the halite-dominated intervals showed significantly lower toughness, facilitating fracture extension into the salts (Dontsov and Suarez-Rivera 2020a, b).
Our study demonstrated that the interaction between pore pressure changes and stress shadow effects is critical in determining fracture propagation and slippage. The potential for natural fracture activation is limited by the quasi-isotropic stress state and the sub-optimal orientation of many fractures within the Cane Creek Unit. This could be managed by a careful stress shadow design. Pore pressure increases localized near the hydraulic fracture reduce effective stress and promote natural fracture slippage. In contrast, stress shadows act over a broader area, altering the shear and normal stresses on adjacent fractures. The interplay of these mechanisms suggests that effective stimulation strategies must balance fluid injection rates and cluster spacing to optimize fracture connectivity while minimizing the risks of non-productive fracture propagation.
Still, it is important to note that the stress shadow and pore pressure results presented in this study represent conditions at the moment of stage shut-in. While this provides a useful upper-bound estimate for stress perturbations near the hydraulic fractures, the timing of natural fracture reactivation is likely more complex. Slippage of distant natural fractures depends on delayed pore pressure diffusion from the fracture face and may occur after the fracture has partially or fully closed. A more detailed assessment would require incorporating time-dependent diffusion and fracture closure behavior to capture the evolving geomechanical environment and provide a more conservative lower-bound evaluation of natural fracture activation.
Nonetheless, even under the elevated pore pressure conditions observed at shut-in, the magnitude of pressure increase remains insufficient to induce slip across all of the mapped natural fractures. It is possible that additional pore pressure rise may occur during early closure as the fractures compact, which could transiently increase slip potential—though this remains speculative without further analysis.
The simulation results also shed light on spatial variability in stress shadow magnitudes across the Cane Creek Unit. Notably, the reduction in ΔShmin observed at the base of the unit in the 5-cluster design can be attributed to the limited vertical extent and lower fracture density in this configuration. In such scenarios, stress perturbations decay more rapidly with distance from the fracture, due to geometric attenuation and reduced cumulative effects. By contrast, the 16-cluster case shows a denser and more extensive fracture network, which enhances stress shadow magnitudes at the base through overlapping stress fields from adjacent clusters. Additionally, the amplified ΔSHmax signal at the base likely reflects lateral stress redistribution in response to constrained vertical fracture growth, resulting in dominant horizontal displacement.
While stress contrast is widely recognized as the first-order control on fracture height growth, our results suggest that the relatively low differential stress in the Cane Creek Unit limits the contrast in horizontal stress across stratigraphic interfaces and provides minimal resistance to vertical propagation. Consequently, fracture toughness contrast emerges as a secondary—but contextually significant—mechanical control. Experimental results demonstrate a substantial drop in toughness between quartz-rich facies (~1.2–1.4 MPa·m¹ᐟ²) and adjacent halite layers (~0.3 MPa·m¹ᐟ²), which corresponds with the simulated upward and downward fracture extension into the salts (Dvory et al., 2024a).
Simulation results confirmed that tighter cluster spacing and reduced fluid volumes enhance stimulation efficiency within the Cane Creek Unit by confining fractures to productive zones. The “ideal” 16-cluster design with reduced injection volumes proved effective in limiting fracture extension into salt layers, although it resulted in reduced fracture surface area within the Cane Creek Unit. Higher injection volumes increase the fracture propagation into the salts but elevates the stress shadow effect (>2) and potentially may trigger low-angle shear fractures that are associated with organic-rich mudstones (Cooper and Lorenz 2022). This trade-off underscores the need for tailored designs that account for the specific geomechanical and lithological characteristics of the reservoir.
CONCLUSION
This study provides insights into the hydraulic fracturing and stimulation challenges within the Cane Creek Unit of the Paradox Fformation. Key findings highlight the interplay between lithological heterogeneity, geomechanical conditions, and fracture propagation dynamics, emphasizing the importance of tailored stimulation strategies to optimize production while mitigating risks associated with salt formations.
The fracture toughness experiments revealed that quartz content strongly influences fracture toughness, while halite significantly reduces it, leading to uncontrolled fracture propagation into adjacent salts. Simulation results demonstrated that tighter cluster spacing, and controlled fluid volumes, can limit fracture extension into non-productive salt layers and managed the stress shadow propagation. We underscore the critical role of stress shadow effects and pore pressure increases in influencing fracture behavior. While pore pressure alterations promote slippage of sub-optimally oriented fractures, stress shadow effects exert broader control on fracture propagation and connectivity. Balancing these mechanisms is essential for enhancing reservoir performance. WO
ACKNOWLEDGMENTS
This research was supported by the U.S. Department of Energy through the National Energy Technology Laboratory under cooperative agreement DE-FE0031775. Field operations and data acquisition were conducted in collaboration with the University of Utah and Zephyr Energy. We extend our gratitude to Dave List and Gregor Maxwell (Zephyr Energy), and to Jim Marquardt, Kevin McCormack, and Carlos Vega-Ortiz (University of Utah) for their valuable discussions. Special thanks to Mark McClure for his insightful feedback and for providing the ResFrac academic license.
COMPLIANCE WITH ETHICAL STANDARDS
The authors declare no conflict of interest.
LIST OF SYMBOLS
Pp pore pressure
ΔPp pore pressure difference
S1 total maximum principal stress
S2 total intermediate principal stress
S3 total minimum principal stress
SV total vertical stress
Sh total minimum horizontal stress
SH total maximum horizontal stress
relative magnitudes of the three principal stresses
n faulting regime parameter
ΔP stress shadow pressure difference
ΔShmin stress shadow in the minimum principal stress direction
ΔSHmax stress shadow in the maximum principal stress direction
ΔSv stress shadow in the vertical principal stress direction
effective stress
minimum horizontal effective stress
maximum horizontal effective stress
vertical effective stress
shear stress
friction coefficient
fracture toughness
applied stress
crack length
geometric factor
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DR. 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.
DR. 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.
DR. 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 enhanced geothermal systems and he serves as a co-PI at Utah FORGE, the DOE’s leading geothermal field laboratory.