This study focuses on simulating volume-increasing processes caused by natural hydrogen-generating serpentinization, a reaction in which olivine and pyroxene typically transform into serpentine minerals. The volume increase leads to crack propagation along grain interfaces and new crack generation within unreacted crystals (aka grains). The interplay between thermo-hydro-mechanical-chemical (THMC) conditions plays a critical role in the initiation, propagation, and coalescence of various fracture surfaces, which enhances permeability and can accelerate serpentinization and hydrogen production rates. In the scenarios considered, chemical reactions between formation brine and reactive minerals result in volumetric expansion, generating stress and promoting the propagation of micro-cracks. Our results show that these micro-cracks can progressively evolve into intricate networks, depending on local stress conditions, material properties, fluid transport, and reaction kinetics. Importantly, if THMC processes can be engineered to optimize these dynamics, they could lead to a commercially viable approach for in-situ hydrogen generation, leveraging naturally reactive systems to create sustainable energy solutions

ABSTRACT: Proppant placement determines the long-term well productivity. In this work, a genetic algorithm (GA) optimization module is integrated with a simplified three-dimensional displacement discontinuity method (S3D DDM) hydraulic fracture model. The proposed workflow is used to algorithmically optimize completion parameters to maximize the propped area. The S3D DDM hydraulic fracture model simulates 3D geometries of multiple simultaneously propagating hydraulic fractures. The associated proppant transport model uses an Eulerian-Lagrangian regime to solve slurry flow and proppant transport. Using numerical case studies, we analyze the effects of slurry properties and pumping schedules on proppant placement within a single hydraulic fracture. Additionally, we examine the impact of cluster placement on proppant distribution in multi-cluster stages. Results show that optimizing one pumping parameter improves proppant placement, and optimizing these parameters altogether supersedes optimizing an individual one. In the case of multi-cluster stage, the optimized cluster placements increase the effective propped areas in all scenarios with different numbers of clusters. Interestingly, although not all fractures in the optimized stages have propped areas, adding a cluster alters the fracture geometries and may increase the total effective propped area of the stage. 1. INTRODUCTION Propped hydraulic fractures serve as pathways for hydrocarbon in unconventional reservoirs, and propped area has been a metric to quantify hydraulic fracturing effectiveness (Novotny, 1977). Many studies have been done to simulate proppant transport in multi-cluster stages. Mao et al. (2021) used an efficient three-dimensional (3D) multiphase particle-in-cell (MP-PIC) method to simulate proppant transport among multiple fractures at the field scale. Sinkov et al. (2021) applied a numerical model to simulate the propagation of multiple hydraulic fractures with proppant transport. Yang et al. (2023) established a displacement discontinuity method (DDM) hydraulic fracture model with an Eulerian-Eulerian approach proppant model to investigate proppant transport in multi-cluster and multi-well completions. These numerical models have also supported the optimization of completion designs, while most of the studies on completion design optimization used manual-tuning of completion parameters. For example, Pei and Xiong (2022) optimized well performance and operator profit by manually setting up various completion designs and summarizing the beneficial effects. Modern complex unconventional reservoir development has gained complexity such as the involvement of parent-child well and multi-stage completion (Pei et al. 2023). Therefore, the number of input parameters of a numerical model also increases to accommodate increased amount of simulated physics, which promotes the needs of algorithmically optimization approach. Yi et al. (2020) used a genetic algorithm (GA) to optimize perforation and pumping schedules to create an even distribution among all perforation clusters. Wang et al. (2021) built a proppant transport experimental device and a back propagation neural network. They trained the neural network model with the experimental results and used the trained model to locate the optimal pumping schedule giving the best proppant filling ratio.

ABSTRACT In the earth's crust, while tectonic processes can mechanically create natural fractures, cementation can simultaneously grow on the surfaces of the fractures. This crystallization can affect the growth of the fractures. To more accurately address the modeling of natural fracture development, both mechanical deformation and chemical diagenesis should be carried out in an integrated manner. We achieve this with a three-dimensional (3D) simulator that couples mechanical and chemical processes for natural fracture pattern development in layer confined situations. Tectonic loading over geologic time is mimicked by displacement driven boundary conditions in a 3D displacement discontinuity method (DDM) scheme. Quartz diagenesis competes with mechanical fracture opening, resulting in three different cementation conditions - open, bridging or fully infilled – which define fracture element stiffness that is used as feedback within the 3D-DDM code during propagation. An important milestone of this work is that this coupled structural diagenetic model can reproduce power-law aperture population statistics which cannot be generated using mechanics alone. More accurately estimated mechanical fracture apertures and their cementation condition is a critical step toward better permeability estimation and fluid path analysis for subsurface reservoirs. INTRODUCTION Natural fractures are important to characterize for many purposes, such as stimulation of unconventional shale reservoirs, enhanced oil recovery methods in tight carbonates, and the design of geothermal injection operations, among others. The presence of open fractures may be critical for low permeability formations because the fracture network could be a highway for fluid flow. Additionally, the existence of natural fractures may augment permeability arising from hydraulic fracturing operations (e.g., Weisenberger et al., 2019). Observation of subsurface fracture systems is inherently challenging (e.g., Laubach et al., 2019), so subsurface reservoir characterization often relies heavily on models. While stochastic-based modeling studies using discrete fracture network (DFN) are widely used, models that account for the physics and chemistry of pattern development have many additional potential benefits (Laubach et al., 2019).

Recent Interferometric Synthetic Aperture Radar (InSAR) observations depict centimeter-level surface uplift/ subsidence signals in west Texas that correlate spatially and temporally with increased fluid extraction and injection activities over the past decade. Linear subsidence features from InSAR data near the Pecos area, that align well with maximum horizontal stress orientations and recent clusters of seismic events, suggest fault motion is also associated with this deformation. In this study, we investigate the relationship between observed surface displacement and inferred subsurface fault slip and reservoir compaction/inflation by inversely solving a combined model of elastic dislocation (Okada, 1985, 1992) and poroelastic reservoir compaction/inflation model (Geertsma, 1973). Our geomechanical analysis coupled with InSAR observations are consistent with the idea that both fault slip and reservoir inflation/compaction are occurring associated with fluid injection and withdrawal in the Pecos area. Numerical results show that the linear surface displacement patterns can be accurately reproduced using clusters of finite slip on multiple elastic dislocations in the subsurface, but also matching the broader areal subsidence and uplift signals requires the addition of poroelastic subsurface inflation and depletion. The inverted areal reservoir pressure distribution correlates well with known injection and withdrawal operations in the area. The best-fit surface deformation locates most fault slips patches at depths of 1-3 km, which is shallower than most reported earthquakes in this area. The difference in the estimation of depth suggests there could be aseismic fault slippages.

Natural fractures are widespread in rock. Fracture development depends on a wide range of factors such as burial history, temperature, strain rate, mechanical properties, layer geometry, and chemical reactions. We developed a three-dimensional (3D) simulator that couples tectonic strain with diagenesis (cement accumulation) to model the development and preservation of fracture aperture more fully. Displacement boundary conditions represent realistic large-scale tectonic strain through geological time and concurrent cement precipitation at fracture surfaces represents diagenesis. In a coupled model, cement effects on fracture opening can be conceptualized (and simplified) as; 1) fully cemented, 2) bridged, and 3) fully open. The mechanical effects of these conditions are simulated by different normal stiffness in fractures. Results of 3D models with diagenesis compare more favorably to field observations than those without diagenesis, exemplified by the reproduction of power-law aperture distributions.

Wing fractures and solution surfaces formed in the vicinity of sliding fault tips are natural examples of mixed-mode fracture propagation. Classical fracture propagation models neglect the remote and crack frictional stresses and have limitations on estimating the kink angles of wing fractures from frictional interfaces under compression. Other methods, utilizing the cohesive end zone, improve the match with the field observations. However, limitations still exist for predicting the angles of wing fractures and solution surfaces simultaneously. We analyze the near-tip stress field including the non-singular terms to estimate the kink angles of wing fracture and solution surface. The estimated kink angles of wing fractures from closed fractures are smaller than the angles from open fractures, agreeing well with the experimental results. The introduced approach predicts that the greater the friction coefficient the smaller the kink angle. The predicted angle between a wing fracture and a solution surface varies between 90 and 141 depending on the remote stress ratio and the friction coefficient. From the published image of wing fractures and stylolites in limestone in Southern France, we were able to estimate the friction coefficient of the sliding faults and the relative magnitude of the horizontal stresses.

The vast shale gas and tight oil reservoirs cannot be economically developed without multi-stage hydraulic fracture treatments. Owing to the disparity in the density of natural fractures and the different in-situ stress conditions in these formations, micro-seismic fracture mapping has shown that hydraulic fracture treatments develop a range of large-scale fracture networks. The effect of these various fracture geometries on production is a subject matter in question. The fracture networks approximated with micro-seismic mapping are integrated with a commercial numerical production simulator that discretely models different network structures. Two fracture geometries have been broadly proposed, i.e., orthogonal and transverse. The orthogonal pattern represents a network with cross-cutting fractures orthogonal to each other, whereas transverse profile maps uninterrupted fractures achieving maximum depth of penetration into the reservoir. The response for a single stage is further investigated by comparing the propagation of each stage to be dendritic versus planar. A dendritic propagation is a bifurcation of the induced hydraulic fracture due to the intersection with the natural fracture (failure along the plane of weakness). For the same injected fracture treatment volume, the transverse network attains a higher penetration into the reservoir, achieves a higher stimulated reservoir volume (SRV), and produces around 40-65% more than the orthogonal network over a timespan of 10 years. The SRV will largely dictate the drainage area in a tight environment. The cumulative production rises until the pressure drawdown reaches the extent of the fracture fairway. For the orthogonal network, the unstimulated reservoir boundary is reached at a sooner time than the transverse network. It is found that by increasing the fracture spacing in both the networks from 100 ft to 150 ft, the relative production was enhanced in the orthogonal network by 41%, but when it was further increased to 200 ft- there was a minor drop (not increase) in the relative production (4.5%). For an infinite conductivity fracture, the width of the fracture has minimal effect on oil and gas production. For the dendritic pattern, the size of the SRV created due to the interaction between the induced and natural fractures largely depends on the length of natural fractures and the point of interaction (center, off-center, or extremity). Effect of length, distance of natural fracture from wellbore, and the point of interaction is evaluated. A novel approach for reservoir simulation is used, where porosity (instead of permeability) is used as a scaling parameter for the fracture width. The forward modeling effort, including the comparative fracture geometries setup, induced, and natural fracture interaction parametric study, is unique.

Earth and Space Science Open Archive PosterOpen AccessYou are viewing the latest version by default [v1]Cumulative and Transient Surface Deformation Signals in the Permian BasinAuthorsScottStaniewicziDJingyiChenHunjooLeeJonOlsonAlexandrosSavvaidisiDPeterHenningsiDSee all authors Scott StaniewicziDCorresponding Author• Submitting AuthorUniversity of Texas at AustiniDhttps://orcid.org/0000-0002-3055-5731view email addressThe email was not providedcopy email addressJingyi ChenUniversity of Texas at Austinview email addressThe email was not providedcopy email addressHunjoo LeeUniversity of Texas at Austinview email addressThe email was not providedcopy email addressJon OlsonUniversity of Texas at Austinview email addressThe email was not providedcopy email addressAlexandros SavvaidisiDUniversity of Texas at AustiniDhttps://orcid.org/0000-0001-6373-5256view email addressThe email was not providedcopy email addressPeter HenningsiDUniversity of Texas at AustiniDhttps://orcid.org/0000-0002-1714-4997view email addressThe email was not providedcopy email address

We propose an adaptive Eulerian-Lagrangian (E-L) proppant module and couple it with our simplified three-dimensional displacement discontinuity method (S3D DDM) hydraulic fracture model. The integrated model efficiently calculates proppant transport during three-dimensional (3D) hydraulic fracture propagation in multi-layer formations. The results demonstrate that hydraulic fracture height growth mitigates the form of proppant bed, so the proppant placement is more uniform in the hydraulic fracture under a smaller stress contrast. A higher fracturing fluid viscosity improves the suspension of proppant particles and generates a fracture larger in height and width but shorter in length. Lower proppant density and particle size reduce the proppant settling and create more uniform proppant placements, while they do not affect the hydraulic fracture geometry. Moreover, a larger proppant particle size limits the accessibility of the hydraulic fracture to the proppant, so the larger proppant particles do not fill the fracture tip and edge where the fracture width is small.

Here we used Sentinel-1 interferometric synthetic aperture radar (InSAR) data acquired between November 2014 to January 2019 to map how the basin's surface has deformed in response to fluid injection and extraction. While our stacking approach has low complexity, its accuracy increases with the Sentinel-1 data volume. With an automated outlier removal algorithm, we achieved similar to 2 mm/year accuracy across the basin in the presence of up to +/- 15 cm tropospheric noise. We observed numerous subsidence and uplift features near active production and disposal wells, with the maximum deformation rate occurring in 2018 when production peaked. The most important deformation signatures are linear patterns that extend tens of kilometers near Pecos, TX, where a cluster of increased seismic events was cataloged by the Texas Seismological Network (TexNet). Our elastic modeling results demonstrate that fluid extraction and dip slip along normal faults are potential causes for the observed seismicity and deformation patterns.

Linear Elastic Fracture Mechanics (LEFM) is a widely applied theory to numerically simulate hydraulic fracture initiation and propagation in the subsurface. However, LEFM with the typical fracture toughness measured from unconfined laboratory tests does not apply to hydraulic fracturing applications under subsurface conditions because the fracture toughness is affected by the confining stress and fluid lag at the fracture tip. Thus, the apparent fracture toughness was proposed by Rubin (1993) to consider the contributions of fluid lag and confining stress. The main objective of this study is to validate the applicability of LEFM with the apparent fracture toughness in simulating hydraulic fracture under subsurface conditions. We utilized the finite element models to compare the near-tip stress state between the LEFM approach and the cohesive zone model (CZM), which considers the effect of confining stress and fluid lag. In addition, we compared the analytical solutions of fracture energy between LEFM and CZM. This study showed that the near-tip stress state of CZM outside the fluid lag and cohesive zone is comparable to the stress field predicted by LEFM with the apparent fracture toughness. However, LEFM with the fracture toughness measured from standard unconfined laboratory tests underestimates the near-tip stress state of fractures under confining stress. This study also revealed that the fracture energy of fluid-driven fractures calculated by CZM is identical to the fracture energy estimated from the approach of LEFM with the apparent fracture toughness. Thus, this study demonstrated that LEFM with the apparent fracture toughness is an appropriate and accurate method to simulate hydraulic fracture propagation in the subsurface.

Using double-torsion load-relaxation tests, we evaluated the effect of chemical environment on fracture toughness and subcritical fracture growth index (SCI) in silicified fault rocks collected in the vicinity of the Dixie Valley, NV, geothermal system. Testing environments included: ambient air, deionized water, dilute HCl, NaOH, and NaCl solutions, and deionized water at elevated temperatures. We observed reductions in SCI in all aqueous environments, with > 60% reduction in alkaline solutions. These results suggest that physiochemical conditions in hydrothermal systems may facilitate fracture growth, with chemically aided fracture growth and flow conduit formation competing with precipitation and sealing in reactive systems.

For maximum productivity enhancement when targeting low permeability formations, horizontal wells must be made to induce multiple transverse fractures. An orientation criterion for fracture initiation is developed using analytically-derived approximations for the longitudinal and transverse fracturing stresses for perforated wellbores from the literature. The validity of the criterion is assessed numerically and is found to overestimate transverse fracture initiation, which occurs under a narrow range of conditions; pertaining to low breakdown pressure and low formation tensile strength. A three-dimensional numerical model shows that contrary to existing approximations, the transverse fracturing stress from perforated horizontal wells becomes more compressive as wellbore pressure increases. This shrinks the "breakdown pressure window," which is the range of wellbore pressures over which transverse fracture initiation takes place. This creates a second constraint for transverse fracture initiation, which is the "critical tensile strength" value. This determines the maximum formation tensile strength at which transverse fracture initiation is possible for a given in-situ stress state and perforation direction. Sensitivity analyses are performed based on data from seven unconventional shale reservoirs (Barnett, Bakken, Fayetteville, Haynesville, Niobrara, Marcellus and Vaca Muerta) for horizontal wells drilled parallel to S-hmin. The frequent longitudinal fracture initiation occurrence indicated suggests fracture reorientation in the near-wellbore region to be a common event, through which the propagating fractures become aligned with the preferred fracture plane (perpendicular to the least compressive principal stress). This induces near-wellbore fluid tortuosity, which in turn can lead to completions and production-related problems, such as early screenouts and poststimulation well underperformance.

Using the double torsion method, we investigated the fracture mechanical properties of clay-rich Woodford and Mancos Shales, and carbonate-rich Marcellus Shale under conditions of varying fluid salinity, pH, and temperature. Both fracture toughness and subcritical fracture growth properties for clay-rich Woodford and Mancos Shales are sensitive to fluid salinity but not sensitive to pH. With increasing salinity, mean fracture toughness increased up to 34% and 39% for Woodford and Mancos Shale, respectively, and mean subcritical fracture growth index increased up to 99% for Woodford Shale. In contrast, fracture toughness for carbonate-rich Marcellus Shale is unaffected by fluid chemistry, but subcritical fracture growth index increases with increasing pH. Subcritical fracture growth index is reduced by 51% with a decrease in pH from 7 to 1.2. Clay-water interaction is identified as the mechanism for enhanced subcritical fracture growth in clay-rich Woodford and Mancos Shales while enhanced calcite dissolution is accountable for the positive correlation between pH and subcritical fracture growth index in carbonate-rich Marcellus Shale. Increasing solution temperature from 23 degrees C to 63 degrees C shifts the K-V curves toward lower stress intensity and amplifies the salinity dependence in the shift of the K-V curves for Woodford Shale. The increase in subcritical fracture growth rate at elevated temperature observed in both clay-rich and carbonate-rich shales is interpreted to reflect faster diffusion rates of fluid from the propagating fracture into the matrix at elevated temperature. Our results emphasize the dependence of critical and subcritical fracture behavior on fluid chemical environment with implications for hydraulic fracture growth in shale reservoirs, and for caprock integrity of wastewater and CO2 storage reservoirs. In these applications, fluid chemistry can both strengthen and weaken caprocks depending on caprock lithology and induced changes in formation water chemistry. Published by Elsevier Ltd.

An edited version of this paper was published by AGU. Copyright (2019) American Geophysical Union. Callahan, O. A., Eichhubl, P., Olson, J. E., & Davatzes, N. C. (2019). Fracture Mechanical Properties of Damaged and Hydrothermally Altered Rocks, Dixie Valley‐Stillwater Fault Zone, Nevada, USA. Journal of Geophysical Research: Solid Earth, 124(4), 4069-4090. http://dx.doi.org/10.1029/2018jb016708

Recognition of the potential for subcritical fracture growth of rocks is essential for the evaluation of long‐term stability of fluids trapped in geologic structures. In shales, subcritical fracture growth may control migration of hydrocarbons in source rock and unconventional reservoirs and of sequestered CO2 across top seals. Using the double torsion method, we investigated the mode‐I fracture mechanical properties of three shales of different composition, namely, Woodford Shale, Mancos Shale, and Marcellus Shale, under water‐saturated conditions, in ambient air, and in dry CO2 gas conditions to systematically investigate the effect of water on the fracture growth properties of shales. The clay‐rich (illite with minor kaolinite) Woodford and Mancos Shales demonstrate a strong water‐weakening effect despite their low smectite content, with the fracture toughness reduced by up to 54% and the subcritical fracture growth index by up to 77% under water‐saturated conditions compared to tests in ambient air. Carbonate‐rich Marcellus Shale, in contrast, displays negligible water‐weakening effects. The clay‐CO2 interaction is minor for the three shales. Specimens treated with a hydrophobic surface coating were also tested to limit water‐weakening effects to the fracture tip. Data from these tests reveal rate‐dependent stress intensity factor‐velocity curves for clay‐rich Woodford and Mancos Shales suggesting a competition between mechanical fracture growth and physicochemical water‐rock interactions. Our results suggest that subcritical failure by water‐enhanced subcritical fracture growth could significantly increase brittle failure in clay‐rich shales.