Technology portfolio for field applications.

This study develops a quantitative workflow for evaluating how post-fracturing surface morphology affects fracture conductivity. Representative shale fracture surfaces are classified as bedding-related, mirror-like hydraulic, step-like, or reactivated structural fractures. High-resolution 3D laser scanning is used to obtain surface point clouds and calculate Ra, Rq, and Rz roughness parameters, together with scale-dependent roughness behavior and a two-dimensional box-counting fractal dimension.

The results show that bedding-related and step-like fractures generally have stronger surface undulation and geometric complexity than smoother mirror-like fractures. Saturation-type functions describe the evolution of roughness with measurement scale, and the Hill function provides flexible fitting for heterogeneous surfaces. The study then proposes a morphology-aware upscaling framework that connects roughness, contact behavior, equivalent hydraulic aperture, and stress-sensitive conductivity.

ARMA 26-0068, presented at the 60th U.S. Rock Mechanics/Geomechanics Symposium, Tucson, Arizona, June 21-24, 2026.

This paper evaluates proppant blends for oil-bearing fractures that may be reopened during shale-oil refracturing. Artificially split shale cores were packed with 20/40, 40/70, and 70/140 mesh proppants in single-size and mixed-size combinations. Conductivity was measured under crude-oil and fracturing-fluid flow, while NMR T2 analysis was used to evaluate residual water, residual oil, and movable-oil behavior within the propped fracture system.

Coarse-dominated packs generally preserve larger flow channels and provide higher fracture conductivity. Mixed-size packs do not always maximize conductivity, but they can improve fluid redistribution and movable-oil saturation. The 40/70:20/40 = 5:5 blend provides a practical balance between conductivity and fluid occupancy, while a three-stage mixed-size blend shows an advantage in promoting oil-phase mobility. The results support multi-objective proppant optimization rather than conductivity-only ranking.

ARMA 26-0073, presented at the 60th U.S. Rock Mechanics/Geomechanics Symposium, Tucson, Arizona, June 21-24, 2026.

This study compares hydraulic-fracture growth in medium-deep coal, deep coal, and deep tight sandstone using true triaxial tests on 100 mm cubic specimens. Injection rate and fracturing-fluid viscosity were varied under controlled stress conditions. Pre- and post-fracturing CT scans, 3D reconstruction, and two-dimensional fractal-dimension analysis were used to characterize breakdown behavior, fracture branching, and network complexity.

The experiments show that treatment response is strongly reservoir dependent. Medium-deep coal develops increasingly complex fractures as injection rate and viscosity increase. Deep coal reaches maximum complexity at intermediate rate and viscosity, while values that are too low or too high produce simpler geometries. Deep tight sandstone shows a similar intermediate optimum. The fractal results agree with CT-based reconstructions and provide a quantitative basis for selecting reservoir-specific pumping parameters.

ARMA 26-0074, presented at the 60th U.S. Rock Mechanics/Geomechanics Symposium, Tucson, Arizona, June 21-24, 2026.

This paper presents an integrated workflow for evaluating the benefits and risks of shut-in imbibition in shale-oil reservoirs. Core samples from the Dongyuemiao Member and Lianggaoshan Formation were studied using NMR T2 spectroscopy, pulse-decay permeability testing, and micro-CT imaging. The combined measurements track apparent pore-scale oil mobilization, dry-state permeability response, and representative pore or fracture structural changes before and after imbibition.

Both tested imbibition agents improve oil recovery, with a clear response near 0.10% concentration. Agent 2 performs better than Agent 1, particularly in Lianggaoshan shale. NMR results show limited mobilization from the finest pores, while micro-CT indicates stronger weak-plane opening and microfracture connectivity in Lianggaoshan shale. Most shale samples show apparent permeability enhancement, whereas sandstone and limestone exhibit moderate attenuation. The workflow supports lithology-specific shut-in and flowback optimization.

ARMA 26-0057, presented at the 60th U.S. Rock Mechanics/Geomechanics Symposium, Tucson, Arizona, June 21-24, 2026.

This paper develops a practical method for quantifying dynamic inter-well connectivity in naturally fractured tight sandstone gas reservoirs. Using the Keshen Gas Field as the study area, pressure interference-test responses and lag-time interpretation are combined with a U-tube pressure-communication analogy. Corrected bottom-hole flowing-pressure data from paired wells are analyzed using production-pressure correlation coefficients before and after operating changes at the stimulation well.

Applications in the Keshen 8, Keshen 13, and Keshen 24 blocks show that higher pressure-correlation coefficients generally correspond to shorter interference lag times and stronger hydraulic connectivity. A field-calibrated classification system is then applied to water-invaded wells in the Keshen 10 block. The resulting connectivity classes support targeted decisions for refracturing, proppant-based water control, fracture plugging, drainage diversion, and enhanced drainage.

ARMA 26-0685, presented at the 60th U.S. Rock Mechanics/Geomechanics Symposium, Tucson, Arizona, June 21-24, 2026.

This study screens and optimizes low-damage fracturing fluids for ultra-deep coal-bearing gas reservoirs in the Kuche Depression of the Tarim Basin. The target reservoirs combine approximately 115 C temperature, high in-situ stress, strong water sensitivity, and micro-nano pore systems. A total of 23 fluid systems - eight guar-based and fifteen slickwater formulations - were evaluated using rheological testing, gel-breaking and residue analysis, and core-damage experiments.

Guar-based fluids generally maintain higher post-shear viscosity, but they also generate more residue and greater formation damage. Selected slickwater systems provide better cleanup and damage control. The preferred weakly crosslinked system, S2, balances transport performance, breaking behavior, residue control, and permeability protection. Its recommended formulation is 0.40% drag reducer, 0.20% multifunctional additive, 0.10% crosslinker, and 0.0025% ammonium persulfate breaker.

ARMA 26-0195, presented at the 60th U.S. Rock Mechanics/Geomechanics Symposium, Tucson, Arizona, June 21-24, 2026.

This study quantifies how shale bedding controls directional porosity and permeability in core samples from the Fuling shale gas reservoir. Plugs were prepared parallel and perpendicular to bedding and tested over multiple confining-pressure conditions. High-resolution CT scanning and 3D reconstruction were used to characterize bedding occurrence, continuity, and density.

Porosity shows limited directional difference, but permeability exhibits strong interval- and stress-dependent anisotropy. Where bedding remains open and hydraulically connected, permeability parallel to bedding is distinctly higher than cross-bedding permeability. Quantitative CT analysis shows that horizontal permeability tends to increase with bedding count, while vertical permeability tends to decrease as bedding density rises. The results confirm the dual role of bedding as a preferential pathway for along-bedding flow and a barrier to cross-bedding flow, with anisotropy becoming more important under elevated stress.

ARMA 26-0060, presented at the 60th U.S. Rock Mechanics/Geomechanics Symposium, Tucson, Arizona, June 21-24, 2026.

This study quantifies how shale bedding controls directional porosity and permeability in core samples from the Fuling shale gas reservoir. Plugs were prepared parallel and perpendicular to bedding and tested over multiple confining-pressure conditions. High-resolution CT scanning and 3D reconstruction were used to characterize bedding occurrence, continuity, and density.

Porosity shows limited directional difference, but permeability exhibits strong interval- and stress-dependent anisotropy. Where bedding remains open and hydraulically connected, permeability parallel to bedding is distinctly higher than cross-bedding permeability. Quantitative CT analysis shows that horizontal permeability tends to increase with bedding count, while vertical permeability tends to decrease as bedding density rises. The results confirm the dual role of bedding as a preferential pathway for along-bedding flow and a barrier to cross-bedding flow, with anisotropy becoming more important under elevated stress.

ARMA 26-0060, presented at the 60th U.S. Rock Mechanics/Geomechanics Symposium, Tucson, Arizona, June 21-24, 2026.

This paper develops an experimental and modeling framework for evaluating whether proppant can enter narrow natural-fracture branches in ultra-deep tight sandstone. A laboratory fracture-network apparatus with controlled branch apertures was designed around the 1/3 bridging concept. Four proppant size classes - 30/50, 40/70, 70/140, and 100/200 mesh - were tested over different fracture widths and blending ratios.

Entry performance is quantified using proppant entry efficiency and effective supported area. The results show that entry capability decreases exponentially as the particle-diameter-to-fracture-width ratio, d/w, increases. A transition zone marks the onset of bridging-dominated restriction. An empirical-mechanistic model is proposed to predict entry capacity and in-fracture particle count from the size-width ratio. The framework provides a screening tool for mesh selection, staged fine-to-coarse pumping, and placement optimization in narrow fracture networks.

ARMA 26-0062, presented at the 60th U.S. Rock Mechanics/Geomechanics Symposium, Tucson, Arizona, June 21-24, 2026.

This study links nonuniform proppant placement to post-placement fracture conductivity in a transparent multi-branch fishbone-fracture system. The apparatus visualizes particle migration, settling, branch-wise deposition, and fine-coarse segregation under controlled pumping schedules. Branch-inlet pressures are monitored during placement to track deposition-driven flow redistribution.

After the proppant settles, apparent conductivity is measured under proppant-free slickwater flow using target-branch pressure and outlet flow rate. Two equivalent geometries are applied: rectangular planar flow and semi-circular radial flow. The radial method produces higher absolute conductivity values, but both methods preserve the same rankings across pumping designs. Image-based placement footprints and particle-size partitioning show that similar total deposited areas can still produce large conductivity differences when fine and coarse particles segregate differently. The workflow supports conductivity ranking based on actual placement morphology rather than an ideal uniform pack.

ARMA 26-0063, presented at the 60th U.S. Rock Mechanics/Geomechanics Symposium, Tucson, Arizona, June 21-24, 2026.

This paper characterizes the directional mechanical behavior of shale-oil reservoir rocks from the Chang 6, Chang 71, and Chang 72 intervals in the Ordos Basin. The experimental program combines CT screening, XRD mineral analysis, ultrasonic velocity testing, triaxial compression, Brazilian tensile testing, semi-circular bend testing, and micro-indentation. Samples are prepared parallel and perpendicular to the bedding-related structural direction.

The results show clear stratigraphic and directional differences in dynamic and static elastic parameters, compressive strength, tensile strength, and fracture toughness. Dynamic modulus is generally higher than static modulus, but the conversion relationship varies by interval and orientation. The rocks therefore cannot be represented by one isotropic parameter set or one universal dynamic-to-static conversion. Macro-scale fracture toughness and micro-scale indentation response also do not show a simple one-to-one relationship, confirming the importance of scale effects.

ARMA 26-0065, presented at the 60th U.S. Rock Mechanics/Geomechanics Symposium, Tucson, Arizona, June 21-24, 2026.