Eagle Ford Shale Research Articles

Effects of pressure on gas generation and pore evolution in thermally matured calcareous mudrock: Insights from gold-tube pyrolysis of the Eagle Ford Shale using miniature core plugs

Together with an increased interest in deep petroleum and shale gas exploration over the last decade, the effects of pressure on gas generation and pore evolution in organic-rich shales have received renewed attention. In this study, miniature core plugs drilled from a thermally matured Eagle Ford Shale sample were pyrolyzed in sealed gold tubes to investigate the effects of pressure on gas generation coupled with pore evolution in the presence of a relatively intact rock fabric. The gold-tube-capsuled samples were isothermally heated at a temperature of 425 °C for 36 h under different confining pressure conditions (10, 25, 35, 50, 68, 80, and 120 MPa), with maturation being induced from the original oil window to the gas window.Experimental results show that increasing the confining pressure from 10 to 120 MPa has initially retards and then promotes the generation of low molecular hydrocarbons (C1–C5 alkanes), whereas gas dryness (C1/C1–5, vol%) increases continuously from 51% to 63% in this pressure range. The inflection pressures that correspond to the maximum retardation of the generation of individual hydrocarbon compounds are shifted to higher values with increasing the molecule carbon number, e.g., 35 MPa for methane, 50 MPa for ethane to butane, and 68 MPa for pentane. Similar pressure effects have also been found for liquid hydrocarbons (C6–14 hydrocarbons and C14+ compounds), with a single inflection pressure of 68 MPa. These observations indicate that high pressure inhibits residual oil cracking but simultaneously favors generation of methane-rich gas. A mechanism for the interaction of retained hydrocarbons and porous matured kerogen (and/or pyrobitumen) is thus suggested to explain the enhanced methane generation. The extent of such interactions is highly dependent on petroleum expulsion efficiency from an intact rock fabric.BET specific surface area and pore volume measured by N2 adsorption decrease significantly for samples matured at 10–35 MPa and then increase at confining pressures above 50 MPa. The simultaneous variations in pore development and methane generation with increasing confining pressure indicate that the observed effect of confining pressure on the evolution of the pore structure of shales depends on both oil retention and gas generation. Our experimental results provide some new insights into gas generation and pore evolution in shale systems, and the retardation effect of pressure on hydrocarbon generation and expulsion as well as pore evolution may provide a mechanism for the Type II kerogen-dominated oil-prone shales to become potential shale gas reservoirs.

Field Gas Huff-N-Puff for Enhancing Oil Recovery in Eagle Ford Shales - Effect of Reservoir Rock and Crude Properties

Field Gas Huff-N-Puff for Enhancing Oil Recovery in Eagle Ford Shales - Effect of Reservoir Rock and Crude Properties

Petrophysical/geophysical approaches to identify ISIP variability in the Eagle Ford shale

Understanding geomechanical properties is essential for an optimal completion strategy that ensures commercial productivity in shale reservoirs with ultra-low permeability. This study provides details to identify the variability of Instantaneous Shut-In Pressure (ISIP) in multidisciplinary approaches using petrophysical and geophysical data. ISIP is one of the input data required for well completion design. Operators commonly ignore the variability of ISIP and use uniform geomechanical assumptions due to cost and time constraints. In the case study, the variability of ISIP was observed up to 30 % in a single horizontal well, which could lower the efficiency of hydraulic fracturing with uniform geomechanical assumptions along a horizontal well trajectory. We propose practical approaches to identify the variability of ISIP from a case study in the Eagle Ford shale. MWD (Measurement While Drilling) Gamma Ray log, which is commonly acquired for a geosteering purpose, was utilized to prove its correlation with actual ISIP data gained at frac-stages in horizontal production wells. Correlation between ISIP and microseismic data was analyzed to identify the integrated relationship among the variability of Gamma Ray, ISIP, and hydraulically-induced fracture. In addition, practical approaches using a series of seismic inversion and attribute data were proposed to help identify geological variabilities affecting ISIP. This study was designed to provide operators hands-on approaches to capturing the variability of ISIP under limited data accessibility. We suggest multifunctional ways using the basic datasets commonly available at field sites. It can be applied to mitigate risks concerning well planning, drilling, and completion design in where operators face frequent challenges from geomechanical heterogeneity in global shale plays.

Experimental and numerical studies of rich gas Huff-n-Puff injection in tight formation

Huff-n-Puff technology is considered one of the most effective methods to increase oil recovery in shale reservoirs. Previous works were mainly focused on Bakken and Eagle Ford shales. This paper is devoted to experimental and numerical studies of rich gas injection in core samples with high organic matter content from a tight oil reservoir in Russia. Eighteen core samples from different well intervals and different sizes were used in a Huff-n-Puff experimental study. Eight of the core samples were investigated at an injection pressure of 15 MPa, while ten core samples were studied at near-miscible pressure conditions of 30 MPa. The experiment results indicate that Huff-n-Puff injection of rich gas could give an oil recovery average of 63.03% and a maximum of 88.40% at 30 MPa injection pressure. A compositional model was created utilizing a commercial simulator and history matched to experimental results. The validated model was used to investigate the effect of molecular gas diffusivity, injection pressure, injection duration, shut-in duration, production duration, and other reservoir properties on the recovery factor. Sensitivity analysis by numerical modeling shows that the molecular gas diffusivity was critical in the history matching of the model. The numerical simulation results imply that the recovery factor could be increased by extending the injection period. In contrast, the duration of a soak period does not significantly influence the recovery factor. Furthermore, the recovery factor could be increased by extension of the production due to a slow decline in the pressure gradient between the matrix and fracture at the later stage of the production. The results of the present study imply that the application of the Huff-n-Puff injection of rich gas could increase oil recovery from tight reservoirs.

Geomechanical characterization of shale samples after pore plugging with nanomaterials

Chemical agents capable of sealing pores and micro-fractures can be used to solve wellbore instability in shales. Nanomaterials, as sealing agents, have been applied to test fluids, and their wellbore strengthening effects were evaluated by triaxial tests. A recommended workflow is given to first conduct pore pressure transmission tests, and then perform triaxial tests to evaluate the influence of drilling fluids (sealing agents) on the strength of shales. Due to the low permeability of shales, the small sample (0.25 in. height and one in. diameter) is used in pore pressure transmission tests. This research gives special loading to handle small samples in triaxial testing and innovative calculation procedure to produce stress-strain curves for the shales. After Pore Pressure Transmission (PPT) tests with nanoparticles of various sizes (10, 40 nm), concentrations (3%, 10%), and types (aluminum oxide, magnesium oxide), triaxial tests were performed on Mancos Shale and Eagle Ford Shale. The best combinations for increasing UCS values (Uniaxial Compressive Strengths) are 10% 40-nm Al2O3 for Eagle Ford Shale and 3% 40-nm MgO for Mancos Shale, according to our test matrix. As shown by the experiments, the application of the appropriate nanoparticles on shales will improve their strength and reduce the risk of wellbore collapse. The methodology developed in this research can be extended to triaxial testing on cuttings-size samples, which provides useful rock characterization information for samples that do not meet standard testing conditions.

Micro- to Nano-Scale Areal Heterogeneity in Pore Structure and Mineral Compositions of a Sub-Decimeter-Sized Eagle Ford Shale

Micro- to Nano-Scale Areal Heterogeneity in Pore Structure and Mineral Compositions of a Sub-Decimeter-Sized Eagle Ford Shale

Comparative analysis of conventional methods for the evaluation of wettability in shales

Wettability has paramount importance in the characterization of shale reservoirs, yet its determination is quite challenging. The conventional techniques popularly applied for wettability determination of shales include contact angle, spontaneous imbibition, and floatation. However, there is no consensus as to the most appropriate method of assessing shale wettability, and which method is most suitable for a given shale sample. In this study, these techniques were employed to measure the wettability of outcrop Eagle Ford, Mancos, and Marcellus shale samples simultaneously to compare their efficacy. Sessile/Captive contact angles were measured on dry and saturated shale samples. The advancing/receding contact angles were also investigated by the drop-volume inflation/deflation method to understand wettability hysteresis. A better evaluation of shale surfaces’ wettability was attained when a water drop was gently placed on the water-saturated chips submerged in the bulk of oil and the contact angle between oil and water was measured. The contact angle and floatation methods showed relatively good agreement, perhaps because both methods relate to shale surficial affinity and mineralogy. However, the wettability of Eagle Ford and Mancos samples derived from contact angle, spontaneous imbibition, and floatation methods were not entirely similar. Only the spontaneous imbibition method was able to evaluate the mixed-wet characteristics of Marcellus shale samples properly because of the overlapped oil and brine saturation due to imbibition. The observed wettabilities are only specified for the studied outcrop samples. A novel approach somewhat like the Amott method is proposed for the quantitative assessment of wettability from spontaneous imbibition datasets, especially for mixed-wet rocks like shales. Overall, the order of reliability of the conventional techniques is spontaneous imbibition > contact angle > floatation. • The inference of shale wettability from contact angle measurements alone is susceptible to reliability issues. • The spontaneous imbibition technique can reveal the extent of pore characteristics and wetting preference of shales. • The order of reliability of the conventional methods is spontaneous imbibition > contact angle > floatation. • A novel wettability assessment approach is proposed for especially mixed-wet rocks like shales.

Effects of Confining Pressure and Microscale Heterogeneity on Hydrocarbon Retention and Pore Evolution from Artificial Maturation of Eagle Ford Shale

Effects of Confining Pressure and Microscale Heterogeneity on Hydrocarbon Retention and Pore Evolution from Artificial Maturation of Eagle Ford Shale

Impacts of Groundwater Pumping for Hydraulic Fracturing on Other Sector Wells in Aquifers Overlying the Eagle Ford Shale, Texas

Impacts of Groundwater Pumping for Hydraulic Fracturing on Other Sector Wells in Aquifers Overlying the Eagle Ford Shale, Texas

Case Study: Patent-Pending Rigless Chemical Process Enhances Oil and Gas Production in Eagle Ford

Hydrocarbon production losses resulting from parent-child well interactions during completion operations are a significant challenge in the Eagle Ford. A patent-pending rigless chemical frac hit remediation process was implemented in the Eagle Ford formation resulting in a 60% increase in oil production, a 30% increase in BOE reserves, and a payback in less than 4 months. A thorough engineering and lab study was conducted to design the process which addressed the damage mechanisms of capillary phase trapping, reduced hydrocarbon relative permeability, paraffin deposition, and minor scale deposition. Background and Challenge The Eagle Ford Shale play located across South Texas is a prolific unconventional resource producing approximately 967,000 BOPD and 6 Bcf/D of natural gas through 2021 (US Energy Information Administration). Like other unconventional reservoirs, Eagle Ford wells have high initial production rates but decline rapidly. Later-life production rates can significantly influence well economics and base production profitability. Production in the Eagle Ford rapidly started increasing around 2010 with the implementation of horizontal drilling and hydraulic fracturing. However, as operators started to develop their acreage, they quickly turned to drilling of infill wells, also known as child wells. Lindsay et al. (SPE 189875) reported that by the beginning of 2015, the number of child wells being drilled in the Eagle Ford surpassed the number of existing or parent wells. This resulted in an acceleration of child-parent interactions, defined as interwell communication between the child and the parent during the fracturing of the child well. Known as fracture-driven interference or frac hits, these interactions have been of intense interest in the industry due to the potential degradation of production in both the parent and child well. Miller et al. (SPE 180200) reported that in 1,210 instances studied in the Eagle Ford, the parent well experienced a negative production event approximately 41% of the time. Kairos Energy Services conducted a study on Eagle Ford parent wells that experienced negative production events from a frac hit to quantify the change in production. A total of six wells were analyzed where each had modern completions and were brought onto production in 2019 or later. Decline curve analysis was run on both the oil and gas streams before the frac hit to generate a forecast to compare against actual post-frac-hit production. Actual and forecast production was averaged across the six wells and production responses were analyzed 6 months before and after the frac hit. Fig. 1 shows the forecast vs. actual cumulative production for both oil and gas, respectively. The divergence in production post frac hit can be clearly seen, resulting in an average per well loss of 20,500 bbl of oil and 245,000 Mcf of gas 6 months following the frac hit. All wells showed a significant increase in water production directly after the frac hit, indicating hydraulic communication. The gas/oil ratio (GOR) was significantly suppressed, decreasing from 4,820 ft3/bbl to 3,850 ft3/bbl 6 months post frac hit. The 30-day average water cut also showed a sustained change, increasing from 46% to 63% 6 months post frac hit.

Impacts to Quail Space Use and Demographics from Oil and Gas Development

Southern Texas contains some of the last relatively unfragmented habitat for northern bobwhite (Colinus virginianus; hereafter, bobwhite) and scaled quail (Callipepla squamata) in the United States. Development of the Eagle Ford Shale hydrocarbon formation in this region could negatively impact quail and their habitat. Our objective was to examine the indirect effects of oil and gas activity (traffic and noise) on bobwhite and scaled quail on 2 private ranches in southern Texas. In 2015 and 2016, we radio-marked bobwhite and scaled quail in 2 areas where oil and gas activity was occurring (disturbed treatment) and 2 areas where little oil and gas activity occurred (undisturbed treatment). We measured vehicle passages and modeled noise propagation from oil and gas infrastructure at 2 biologically relevant frequencies (250 Hz and 1,000 Hz) in our study area to quantify oil and gas disturbance and examine its effects on quail space use (site selection and home range size) and demographics (survival, nest success, and density). Bobwhite and scaled quail selected areas 0–200 m and >425 m, respectively, from the primary, high-traffic roads in the disturbed treatment. In the undisturbed treatment, bobwhite and scaled quail selected areas 0–425 m and 0–300 m from primary roads, respectively. Bobwhite and scaled quail selected areas with sound levels 0–1.6 and 0–2.2 dB above ambient levels at the 250-Hz frequency level, respectively. At 1,000 Hz, bobwhite and scaled quail selected areas with sound levels 0–2 and 0–3.2 dB above ambient levels, respectively. We found no evidence that disturbance variables affected bobwhite and scaled quail home range size, survival, or density. We found bobwhite nest success decreased as sound levels (dB) at 250 Hz increased; we found no relationship between nest success and disturbance for scaled quail, possibly as they avoided major oil and gas disturbances. In calculations of the total footprint of quail habitat loss, indirect loss due to oil and gas activity needs to be considered in addition to direct loss due to conversion of rangeland to oil and gas infrastructure.

Geochemistry of Oils and Condensates from the Lower Eagle Ford Formation, South Texas. Part 3: Basin Modeling

Geochemistry of Oils and Condensates from the Lower Eagle Ford Formation, South Texas. Part 3: Basin Modeling

The impact of supercritical CO2 on the pore structure and storage capacity of shales

Injection of supercritical CO2 (SCCO2) causes significant changes in the petrophysical properties of shales and affects the integrity of geological storage sites. The alteration of mineralogy and pore structure plays a major role in defining the fluid transport in pours media of shale gas during CO2 storage. In this study, a series of SCCO2 treatment experiments were performed on different types of shales to evaluate the alterations of the pore structure and mineralogy. Two types of shales from Eagle Ford and Mancos fields were treated with SCCO2 and analyzed with scanning electron microscope, X-ray diffraction, and low-pressure nitrogen adsorption before and after 30 days at 70 °C and 18 MPa. The experimental results indicated that SCCO2 affected the mineral composition and changed the macropore structure of shales, due to the adsorption-induced expansion effect. The pore structure of clay-rich shales samples was more affected by CO2 treatment compared to quartz-rich shales, due to the dissolution of clay contents in the former, which reduced the overall pore volume by 24% in Eagle Ford shales. Conversely, the development of micro-cracks in Mancos shale surface created new pores and increased the pore volume by more than 13%. The results from nitrogen adsorption isotherms indicated a prominent alteration in the mesopores structure. The specific surface area and total pore volume of Eagle Ford shale reduced by 35.46% and 11.86% respectively after the SCCO2 treatment, while the specific surface area and total pore volume of Mancos shale increased by 27.4% and 25.92% respectively. A positive correlation was reported between the fractal dimension and specific surface area. It appeared that the surface roughness was reduced in Eagle Ford shale and relatively increased in Mancos shales after the treatment. The obtained results suggested that the adsorption capacity of clay-rich shales could be reduced after the CO2 treatment, while quartz-rich shales displayed a uniformed pore size distribution profile, indicating a possible increase in the adsorption capacity. These findings can provide technical support to further understand the effect of CO2 on the pore structure and mineralogical alteration of shale during geological storage.

Multimineral petrophysics of thermally immature Eagle Ford Group and Cretaceous mudstones, U.S. Geological Survey Gulf Coast 1 research wellbore in central Texas

Traditional petrophysical methods to evaluate organic richness and mineralogy using gamma-ray and resistivity log responses are not diagnostic in source rocks. We have developed a deterministic, nonproprietary method to quantify formation variability in total organic carbon (TOC) and three key mudrock mineralogical components of nonhydrocarbon-bearing source rock strata of the Eagle Ford Group by developing a set of log-derived multimineral models calibrated with Fourier transform infrared spectroscopy core data from the research borehole U.S. Geological Survey Gulf Coast 1 West Woodway. We determined that bulk density response is a reliable indicator of organic content in these thermally immature, water-bearing source rocks. Multimineral findings indicate that a high degree of laminae-scale mineralogical heterogeneity exists due to thinly interbedded carbonate cements amid clay-rich mudstone layers. The lower part of the Eagle Ford Group contains the highest average TOC content (4.7 wt%) and the highest average carbonate volume (64.1 vol%), making it the optimal target in thermally mature areas for source-rock potential and hydraulic-fracture placement. In contrast, the uppermost portion of the Eagle Ford Group contains the highest average volume of clay minerals (42.6 vol%), which increases the potential for wellbore stability issues. Petrophysical characterization reveals that porosity is approximately 30% in this relatively uncompacted formation. In this thermally immature source rock, water saturation is nearly 100% and no free hydrocarbons were observed on the resistivity logs. No evidence of borehole ellipticity was observed on the three-arm caliper log, and horizontal stresses are presumed to be directionally uniform in the vicinity of this near-surface wellbore. This shallow wellbore has a temperature gradient of 1.87°F/100 ft (16.3°C/km) and is likely influenced by earth surface heating.

Laboratory Investigations on Field Gas Huff-n-Puff for Improving Oil Recovery in Eagle Ford Shale─Effect of Operating Conditions

Laboratory Investigations on Field Gas Huff-n-Puff for Improving Oil Recovery in Eagle Ford Shale─Effect of Operating Conditions

A Strategy for Choosing Red‐Light Thresholds to Manage Hydraulic Fracturing Induced Seismicity in North America

AbstractInduced earthquakes caused by hydraulic fracturing are a growing concern, with risks that are often managed by traffic light protocols (TLPs). Here, we apply a risk‐informed strategy for choosing TLP red‐light thresholds. We utilize a combination of probabilistic maximum magnitudes, formation depth, site amplification, ground motion relationships, felt/damaging shaking tolerances, and population information to simulate the spatial distribution of nuisance and damage impacts. We apply this approach to many of the prominent North American shale plays that have caused earthquakes: the Horn River Basin, the Duvernay Formation, the Montney Formation, the Utica Shale, the Marcellus Shale, the SCOOP & STACK play in Oklahoma, the Eagle Ford Formation, and the Delaware Basin. We find that induced earthquake impacts are spatially heterogeneous, depending most strongly on population density. These spatial heterogeneities vary on different length scales, depending on if they are related to nuisance (longer range, 100s kms) or damage (shorter range, 10s kms). Because of this variability, we suggest an approach that sets red‐light magnitudes based on tolerances to nuisance and damage risks (varying between Mw 2.0–5.0). Comparison of the results between North American shale plays where TLPs have been enacted suggests that nuisance risks have been an influencing factor in determining red‐light thresholds. Our method provides quantitative guidelines for traffic light protocols designed in a risk‐informed manner that retains the implementational simplicity of magnitude‐based thresholds. In addition, our results provide a benchmark for jurisdictional nuisance tolerances that future TLPs could be guided by.

An Early‐Time Solution of Pulse‐Decay Method for Permeability Measurement of Tight Rocks

AbstractThis contribution presents an early‐time solution for permeability evaluation in pulse‐decay tests. A nonlinear governing equation for gas transport in the sample is derived considering the pressure dependence of gas compressibility and Klinkenberg slippage effect, and the early‐time solution is obtained through the integral balance analysis. The permeability coefficient can be determined by the proposed solution through the pressure transients during the early‐time stage of the tests, that is, before the upstream pressure pulse penetrates through the core sample and reaches the downstream side. To test the proposed solution, measurements were performed on a core sample of the Cretaceous Eagle Ford shale, Texas, USA, under different pore and confining pressures. Helium was used as the testing fluid to minimize the Joule‐Thomson effect and adsorption. The experimental results show that the permeability coefficients obtained from this new solution agree well with those from the late‐time solution, and prove our solution accurate and efficient for permeability evaluation. The present approach provides a good supplement to the pulse‐decay method and is suitable for measurements of low‐permeable rocks.

Effect of Fluid Properties on Contact Angles in the Eagle Ford Shale Measured with Spontaneous Imbibition.

Models of fluid flow are used to improve the efficiency of oil and gas extraction and to estimate the storage and leakage of carbon dioxide in geologic reservoirs. Therefore, a quantitative understanding of key parameters of rock–fluid interactions, such as contact angles, wetting, and the rate of spontaneous imbibition, is necessary if these models are to predict reservoir behavior accurately. In this study, aqueous fluid imbibition rates were measured in fractures in samples of the Eagle Ford Shale using neutron imaging. Several liquids, including pure water and aqueous solutions containing sodium bicarbonate and sodium chloride, were used to determine the impact of solution chemistry on uptake rates. Uptake rate analysis provided dynamic contact angles for the Eagle Ford Shale that ranged from 51 to 90° using the Schwiebert–Leong equation, suggesting moderately hydrophilic mineralogy. When corrected for hydrostatic pressure, the average contact angle was calculated as 76 ± 7°, with higher values at the fracture inlet. Differences in imbibition arising from differing fracture widths, physical liquid properties, and wetting front height were investigated. For example, bicarbonate-contacted samples had average contact angles that varied between 62 ± 10° and ∼84 ± 6° as the fluid rose in the column, likely reflecting a convergence–divergence structure within the fracture. Secondary imbibitions into the same samples showed a much more rapid uptake for water and sodium chloride solutions that suggested alteration of the clay in contact with the solution producing a water-wet environment. The same effect was not observed for sodium bicarbonate, which suggested that the bicarbonate ion prevented shale hydration. This study demonstrates how the imbibition rate measured by neutron imaging can be used to determine contact angles for solutions in contact with shale or other materials and that wetting properties can vary on a relatively fine scale during imbibition, requiring detailed descriptions of wetting for accurate reservoir modeling.

Data-driven model-based rate decline prediction in unconventional eagle ford shale oil wells

The main objective of this paper is to develop a novel data-driven-based model that can accurately predict the decline curves and EUR (Estimated Ultimate Recovery) for new wells based on the data collected from nearby wells. This is because decline curves are easier and faster alternative to complex reservoir simulators which perform computationally expensive operations. In contrast to this, decline curves require only a few parameters in the equation which can be easily collected from the existing data of the wells. The predictor variables were successfully linked to SEDM (Stretched Exponential Decline Model) decline curve parameters (n and τ) in a random set of oil field well data. The relative influences of various well parameters were also examined to determine the hidden relationship between them. The novelty in this study lies in the algorithm and dataset that we used for the rate decline prediction in Eagle Ford data set. Although, this paper has referenced some previous papers where machine learning has been used to make prediction, but this paper presents use of new algorithm as well as a new dataset. As more data get available, there is definitely extra room for further data analysis and improved results.

Specific surface area: A reliable predictor of creep and stress relaxation in gas shales

In recent years, short-term creep parameters determined in the laboratory from cylindrical gas shale samples subjected to triaxial (in-situ) stress conditions have been used successfully to infer long-term deformation and stress relaxation at the reservoir scale across geologic time scales. Due to the viscoelastic formalism, both the laboratory creep response and field-scale stress relaxation can be modeled with power law functions of time involving the elastic compliance of the shale B, the time-dependence exponent n, and the amount of total strain ∊. Gas shales often exhibit a high specific surface area associated with their high content in clay minerals and/or total organic carbon (TOC). The low-pressure nitrogen adsorption technique can be used advantageously to estimate specific surface area (SN2); i.e., it is a relatively fast and cost-effective measurement conducted on powdered samples of shale material. A robust global empirical correlation between gas shale creep parameters and SN2 emerges from the analysis of laboratory data collected from multiple gas shale formations in Australia (the prospective Goldwyer Formation) and the United States (Barnett, Haynesville, and Eagle Ford formations), and spanning a broad range of clay content, organic matter, maturity, and porosity values. This data set also shows that the summed fractions of clay minerals, TOC, and porosity, the so-called weak phase fraction, correlates nearly as well with primary creep parameters. The weak phase fraction can also be estimated from faster and more cost-effective measurements or from well logs. To evaluate its predictive capacity, the key correlation between SN2 and creep parameters is used in a case study to predict the magnitude of present-day least principal stress Shmin across six depth intervals/lithologic layers in a prolific unconventional shale formation in the northeastern United States. Several Shmin measurements are available for verification, and our approach successfully captures the observed layered variation of stress with depth.