Fractured Shale Research Articles

Experimental study on the mechanical controlling factors of fracture plugging strength for lost circulation control in shale gas reservoir

The geological conditions of shale reservoir present several unique challenges. These include the extensive development of multi-scale fractures, frequent losses during horizontal drilling, low success rates in plugging, and a tendency for the fracture plugging zone to experience repeated failures. Extensive analysis suggests that the weakening of the mechanical properties of shale fracture surfaces is the primary factor responsible for reducing the bearing capacity of the fracture plugging zone. To assess the influence of oil-based environments on the degradation of mechanical properties in shale fracture surfaces, rigorous mechanical property tests were conducted on shale samples subsequent to their exposure to various substances, including white oil, lye, and the filtrate of oil-based drilling fluid. The experimental results demonstrate that the average values of the elastic modulus and indwelling hardness of dry shale are 24.30 GPa and 0.64 GPa, respectively. Upon immersion in white oil, these values decrease to 22.42 GPa and 0.63 GPa, respectively. Additionally, the depth loss rates of dry shale and white oil-soaked shale are determined to be 57.12% and 61.96%, respectively, indicating an increased degree of fracturing on the shale surface. White oil, lye, and the filtrate of oil-based drilling fluid have demonstrated their capacity to reduce the friction coefficient of the shale surface. The average friction coefficients measured for white oil, lye, and oil-based drilling fluid are 0.80, 0.72, and 0.76, respectively, reflecting their individual weakening effects. Furthermore, it should be noted that the contact mode between the plugging materials and the fracture surface can also lead to a reduction in the friction coefficient between them. To enhance the bearing capacity of the plugging zone, a series of plugging experiments were conducted utilizing high-strength materials, high-friction materials, and nanomaterials. The selection of these materials was based on the understanding of the weakened mechanical properties of the fracture surface. The experimental results demonstrate that the reduced mechanical properties of the fracture surface can diminish the pressure-bearing capacity of the plugging zone. However, the implementation of high-strength materials, high-friction materials, and nanomaterials effectively enhances the pressure-bearing capacity of the plugging zone. The research findings offer valuable insights and guidance towards improving the sealing pressure capacity of shale fractures and effectively increasing the success rate of leakage control measures during shale drilling and completion.

Study of Permian Basin Provides Insight Into Parent-/Child-Well Interactions

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211899, “Results From a Collaborative Parent/Child Industry Study: Permian Basin,” by Mark McClure, SPE, ResFrac; Magdalene Albrecht, SM Energy; and Carl Bernet, Ovintiv, et al. The paper has not been peer reviewed. _ The complete paper summarizes results from a collaborative industry study involving seven operators and 10 pad-scale data sets across four different shale plays. The paper specifically focuses on a subset of the data sets from the Midland and Delaware Basins. The project had three main objectives: compare and contrast observations between data sets and basins, develop general insights into parent- and child-well interactions, and provide customized economic optimization recommendations for each individual operator and data set. The simulations reveal that economic performance can be optimized with customized selection of well spacing, job size, and landing depth based on each company’s objectives and price deck. Methods Modeling Approach. The simulations were performed with a fully integrated hydraulic fracturing, wellbore, geomechanics, and reservoir simulator. The entire life cycle of the wells is captured in a single continuous simulation. The fractures are meshed as true cracks, with apertures on the order of microns to millimeters. Constitutive relations are used to capture transitions from being mechanically open to mechanically closed and vice versa. The simulations are fully 3D, and the equations are solved with a fully coupled scheme. For efficiency, the simulations include only one or a few stages along the wells. Fracture geometry is assumed to be planar, with no more than one dominant hydraulic fracture strand propagating per cluster. The modeling approach is based on the industry’s emerging recognition that hydraulic fractures in shale are planar at large scale, while being rough and complex at small scale. In the simulator, constitutive relations are used to account for the effect of small-scale complexity on processes such as proppant transport, fluid leakoff, and fracture propagation. Modeling Work Flow. For each data set, the modeling process consisted of the following steps: 1. Gather and organize data. 2. Create an initial model based on this data. 3. Create a list of key observations from the data set that constitute the objectives for the history-matching process. 4. Present the initial model and the list of key observations to stakeholders to obtain feedback and check communication. 5. Vary simulation input parameters to match the key observations while frequently communicating with stakeholders. 6. After finalizing the history match, perform a set of sensitivity analysis simulations, varying parameters such as well spacing and parent-well age. 7. Set up an economics model and perform a quantitative optimization of net present value (NPV)/section or discounted return on investment [DROI; defined as time-discounted revenue minus time-discounted operating expense divided by time-discounted capital expenditure (CAPEX)]. The steps of this work flow are detailed in the complete paper.

Hydrocarbon Potential and Reservoir Characteristics of Lacustrine Shale: A Case of Lower Jurassic in the Western Qaidam Basin, NW China

The Lower Jurassic lacustrine shale is well developed in the western Qaidam Basin and characterized by significant thickness and continuous distribution. Previous investigations have indicated its substantial potential as a shale gas resource. Based on experiments of organic carbon content, vitrinite reflectance, rock-eval pyrolysis, X-ray diffraction, and low-temperature nitrogen adsorption, the hydrocarbon potential and reservoir characteristics of Lower Jurassic lacustrine shale in the western Qaidam Basin were systematically analyzed. The results show that the total organic carbon (TOC) content ranges from 1.71% to 4.49%, with an average of 2.98%. The kerogen belongs to type II–III. The vitrinite reflectance (Ro) ranges from 1.05% to 1.95%, with an average of 1.62%, indicating that the kerogen has reached the high thermal maturity stage (gas window). The maximum pyrolysis peak temperature (Tmax) ranges from 408 °C to 580 °C, with an average of 498.38 °C, further supporting the high thermal maturity of the kerogen. The content of brittle minerals, including quartz, feldspar, pyrite, and carbonate, ranges from 21% to 44% (averaging 32.54%), which is comparable to shale minerals found in American Ohio shale. The pore structure of the shale is predominantly characterized by open parallel plate slit pores and inclined slit pores. The pore diameter distribution curve can be divided into two types, including unimodal distribution and bimodal distribution. Micropores and mesopores contribute significantly to the specific surface area, and mesopores account for the highest proportion of pore volume. The thermal evolution degree has a direct impact on pore development of shale reservoirs. The micropore, mesopore, macropore, and total pore volumes of lacustrine shale in the study area show a negative correlation with TOC content, indicating that the organic matter within the shale is probably still in the first pyrolysis stage. However, no significant correlation is observed between pore volume and clay mineral content or between pore volume and brittle mineral content due to the complex interplay of several geological factors. These findings contribute to a better understanding of the lacustrine shale gas resource potential and can guide future exploration and exploitation efforts. In addition, the systematic analysis of reservoir characteristics serves as a foundation for the introduction and exploration of new shale fracturing technologies, which is of great significance for reducing the consumption of water resources and mitigating potential geo-disasters.

A brief review of steam flooding and its applications in fractured oil shale reservoirs

Steam flooding is an important thermal recovery method for heavy oil reservoirs, and convective heating technology is used to fracture oil shale reservoirs with good results. This paper reviews the main prediction methods, optimization approaches for steam flooding performance, and its application in fractured oil shale reservoirs. The prediction methods include experimental, numerical simulation, and statistical models. These provide insights into steam override, heat transfer, and production dynamics. To optimize steam flooding, parameters like quality, temperature, injection rate, and allocation need to be coordinated based on reservoir conditions and monitoring data. Real-time injection control, economic analysis, and sweep efficiency improvements should also be considered in optimization workflows. Although progress has been made, more field studies are needed to establish systematic optimization practices utilizing advanced technologies. This review summarizes the key developments in steam flooding modeling and optimization, providing a reference for further research and field applications.

NMR and CT characterizing the influence of O2 in air injection performance in shale oil cores

BackgroundThe primary objective of this paper is to evaluate the performance of extracting shale oil resources by air injection experiments. In this paper, the shale cores were acquired from Xinjiang Permian Lucaogou formation, with an average porosity of 14% and an average permeability of 0.3mD. 2) Method: The remaining oil distribution and mobilization of oil saturation was characterized by online NMR spectra and X-ray CT scanner. Nitrogen, 8% oxygen of air and 16% oxygen of air injection were evaluated for their enhanced shale oil recovery performance. 3) Significant findings: With the increase of oxygen concentration in the air, a higher oil recovery factor was yielded. Under different O2 concentration, oil recovery factor by nitrogen drive is 45.31%, and the highest (16% oxygen) is 69.81%. Most of hydrocarbons were produced from the 1～5 μ m pore size. Approximately 50% of oil was recovered by the first 0.6 PV of air injection. Oil recovery efficiency is remarkably declined for successive 0.6 PV of air injection. From the CT images of air injection into the fractured shale cores, air injection has the potential to recover incremental oil in the presence of fractures.

Comparison of mechanical characteristics of different types of shales in the Ordos Basin

Shale gas is a very important unconventional energy. The mechanical properties of the three types of shale (laminated shale, sandwich shale and foliated shale) are different, and the difference in fracturing effectiveness is very significant. In this paper, the mineral composition, mechanical properties and conductivity of these three different types of shale were studied and compared by X-ray diffraction, triaxial mechanical experiments, and fracture conduction experiments. The study found that the foliated shale has the lowest content of rigid minerals (47.5%), lower elastic modulus and tensile strength (26.98 Gpa and 168.29 MPa, respectively), higher Poisson’s ratio (0.25), the smallest brittleness index (0.48), and larger fracture toughness (0.42). The laminated shale has a higher content of rigid minerals (68.50%), the lowest elastic modulus and tensile strength (25.77 Gpa and 122.46 MPa, respectively), the highest Poisson’s ratio (0.26), the highest brittleness index (0.56), and the lowest fracture toughness (0.18). The sandwich shale has the highest rigid mineral content (78.16%), the highest elastic modulus and tensile strength (35.31 Gpa and 197.37 MPa, respectively), the lowest Poisson’s ratio (0.24), a larger brittleness index (0.52), and larger fracture toughness (0.415). Furthermore, with the increase in the coring angle, the elastic modulus of all three shales increases. In addition, with the increase in closing pressure and the decrease in the sand laying concentration, the proppant embedding depth gradually increases and the conductivity decreases. This means that from the perspective of forming complex fracture networks, the fracturing effect of the foliated shale is unsatisfactory, while the fracturing effect of the laminated and sandwich shales is better. Moreover, it is recommended to prefer directional injection along vertical laminae or at high angles, which is conducive to the formation of complex fracture networks. For laminated shale with low strength, the sand laying concentration should be increased to ensure the conductivity of the fractured fracture. This study provides some technical guidance for the identification of different types of shale fracturing desserts and fracturing processes.

Research on dual lateral log simulation of shale bedding fractures under different influencing conditions

Micro scale fractures play a crucial role in facilitating the migration of oil and gas in low permeability shale reservoirs. However, the identification of such fractures is a complex task. The efficacy of the dual lateral log physical field changes as a means of identifying shale micro fractures remains uncertain. To address this issue, a three-layer shale bedding fracture model was developed using the finite element method and core and conventional logging data from eight wells, which was based on different shale reservoirs within the Yanchang Formation in the Ordos Basin. The present study examines the dual lateral log response characteristics resulting from distinct characteristics of horizontal bedding fractures, with a focus on the response mechanism. The simulation of logging response characteristics of shale and siltstone combination were utilized by core statistical data for verification purposes. The results indicate that under the lithology combination of shale and siltstone, the magnitude of the difference between the resistivity of the filled fracture and the formation resistivity, the greater the formation resistivity of the shale itself, the wider the fracture width, and the greater the difference between the apparent resistivity and the real formation resistivity. Furthermore, the suitable conditions for the detection of shale bedding fracture characteristics by dual lateral log are clarified. In the presence of effective filling, the dual lateral log has the capability to identify shale fractures at the micron scale. The findings of our study establish a theoretical framework for the identification and assessment of shale fractures, and furnish technical assistance for the optimal selection of “sweet spots” within shale reservoirs and the precise evaluation of reservoirs. This study lays a theoretical foundation for the identification and evaluation of shale fractures, and provides technical support for the optimal “sweet spot” selection of shale reservoirs and the accurate evaluation of reservoirs.

Frac-Hit Prevention Countermeasures in Shale Gas Reservoirs with Natural Fractures

The development of natural fractures (NFs) in shale gas reservoirs is conducive to improving the productivity of shale gas wells. However, NF development leads to high-frequency frac hits between the infill and parent wells, which critically restricts its efficiency. To elucidate the large contribution of hydraulic fractures (HFs) and NFs in frac hits during the production and the development of NF-developed shale gas reservoirs, such reservoirs in the WY area of western China are taken as an example. A total of 197 frac hits well events in this area are systematically classified via the frac-hit discrimination method, and the effects of different factors on HF- and NF- dominated frac hits are classified and studied. Combined with the correlation analysis method and the chart method, the main controlling factors affecting the two types of frac hits are determined, and the corresponding frac-hit prevention countermeasures are proposed. The research demonstrates that (1) the distribution and development of NFs are crucial to production after frac hits. NFs and HFs in the WY area cause 51% and 49%, respectively, of the frac hits. (2) The main controlling factors in NF-dominated frac hits are the approximation angle, fracture linear density, and horizontal stress difference, whereas they are net pressure in fractures, horizontal stress difference, and liquid strength in HF-dominated frac hits. Sensitivity analysis shows that the NF activation difficulty coefficient fluctuates between −35.1% and 47.6%, and the maximum hydraulic fracture length fluctuates between −43.5% and 25.29%. (3) The corresponding frac-hit prevention countermeasures are proposed for the two types of formation mechanisms from different approaches, including frac-hit risk assessment and path planning, production well pressurization and stress diversion, and infill-well fracturing parameter optimization. This paper not only provides a reference for exploring the formation mechanism of frac hits in fractured shale gas reservoirs but also a theoretical basis for the corresponding frac-hit prevention countermeasures.

Impact of capillary pressure on micro-fracture propagation pressure during hydraulic fracturing in shales: An analytical model

Impact of capillary pressure on micro-fracture propagation pressure during hydraulic fracturing in shales: An analytical model

Impact of Effective Stress and Surface Roughness on Nonlinear Gas Flow in Shale Fractures

Impact of Effective Stress and Surface Roughness on Nonlinear Gas Flow in Shale Fractures

Characteristics and exploration targets of Chang 7 shale oil in Triassic Yanchang Formation, Ordos Basin, NW China

The geological characteristics and enrichment laws of the shale oil in the third submember of the seventh member of Triassic Yanchang Formation (Chang 73) in the Ordos Basin were analyzed by using the information of core observations, experiments and logging, and then the exploration potential and orientation of the Chang 73 shale oil were discussed. The research findings are obtained in three aspects. First, two types of shale oil, i.e. migratory-retained and retained, are recognized in Chang 73. The former is slightly better than the latter in quality. The migratory-retained shale oil reservoir is featured with the frequent interbedding and overlapping of silty–sandy laminae caused by sandy debris flow and low-density turbidity current and semi-deep–deep lacustrine organic-rich shale laminae. The retained shale oil reservoir is composed of black shale with frequent occurrence of bedding and micro-laminae. Second, high-quality source rocks provide a large quantity of hydrocarbon-rich high-quality fluids with high potential energy. The source-reservoir pressure difference provides power for oil accumulation in thin interbeds of organic-poor sandstones with good seepage conditions and in felsic lamina, tuffaceous lamina and bedding fractures in shales. Hydrocarbon generation-induced fractures, bedding fractures and microfractures provide high-speed pathways for oil micro-migration. Frequent sandstone interlayers and felsic laminae provide a good space for large-scale hydrocarbon accumulation, and also effectively improve the hydrocarbon movability. Third, sand-rich areas around the depression are the main targets for exploring migratory-retained shale oil. Mature deep depression areas are the main targets for exploring retained oil with medium to high maturity. Theoretical research and field application of in-situ conversion in low-mature deep depression areas are the main technical orientations for exploring retained shale oil with low to medium maturity.

Fracturing fluid imbibition impact on gas-water two phase flow in shale fracture-matrix system

A large amount of fracturing fluid in hydraulic fracturing is imbibed into the shale fracture/matrix, which leads to significant uncertainty in gas recovery evaluation. The mechanism of imbibition impact on the gas–water flow is not well understood. In this study, systematic comparative experiments are carried out to simulate imbibition in fractured shale samples obtained from the Wufeng-Longmaxi shale reservoirs in China, and the imbibition effect in the fracture–matrix system is qualitatively and quantitatively investigated. Nine cores are collected to measure their porosity and permeability using a helium porosimeter and nitrogen pulse–decay tests. Gas/liquid single-phase flow experiments are then carried out using methane and KCl solution, respectively. Subsequently, dynamic imbibition experiments are carried out on three samples in a visual cell. The gas–water interfacial tension, water imbibition amount, and displacement velocity are recorded. A single-phase gas/liquid flow test shows a high linear correlation between the fluid displacement velocity and pressure gradient in the fractured samples as the fracture is the main flow channel, dominantly determining the flow behavior. Moreover, the capillary force was introduced in the cross-flow term of the triple-medium model to characterize the imbibition effect, and a two-phase flow simulation model considering the fracturing fluid imbibition retention was developed, and the two-phase flow behavior by considering the imbibition effect of the fracturing fluid retention in the shale gas reservoir was analyzed. Valuable experiment data in this work are provided, which can be used to validate analytical equations for gas/water flow in the shale fracture–matrix system.

Analysis of fracture propagation and shale gas production by intensive volume fracturing

Analysis of fracture propagation and shale gas production by intensive volume fracturing

Enhancing oil-water flow simulation in shale reservoirs with fractal theory and meshless method

Introduction: Simulating oil and water flow in shale reservoirs is challenging due to heterogeneity caused by fractures. Conventional grid-based methods often have convergence issues. We propose a new approach using fractal theory and meshless methods to accurately model flow.Methods: A mathematical model describing oil-water flow in fractured horizontal shale wells was developed. The meshless weighted least squares (MWLS) method was used to numerically solve the model. Modeling points were placed flexibly, informed by fractal theory.Results: The MWLS solution aligned well with reference solutions but had enhanced flexibility. Comprehensive analysis showed the effects of modeling parameters like fracture properties on production.Discussion: The proposed methodology enabled accurate prediction of shale oil production. Convergence was improved compared to grid-based methods. The flexible modeling approach can be tailored to specific reservoir conditions. Further work could expand the model complexity and types of reservoirs.

Mixed-Mode Crack Propagation in Presence of Vein Fracture in Shale Sample in SCB Test

Mixed-mode fracture toughness refers to the ability of a material to withstand loads and expand under multiple modes of loading. It is usually tested by a semi-circular bend (SCB) to investigate the shale fracture toughness under combined modes of loading, such as tension and shear. When shale samples contain vein fractures, the dimensionless parameters Y1 and Y2 used in the SCB test method can be affected. The finite element method (FEM) was used to conduct a study investigating the impact of the natural fracture angle on the dimensionless parameters Y1 and Y2. The research findings indicate that as the vein fracture angle increases, Y1 and Y2 gradually increase. A construction was made to simulate the propagation path of a mixed-mode crack and compare it under various experimental conditions, utilizing the cohesive zone method (CZM). The results indicate that as the thickness of the vein fracture increases, the propagation path of the fracture becomes more tortuous. When the fracture encounters a vein with lower fracture strength, it will extend the vein fracture propagation. On the other hand, when the fracture encounters a vein with higher fracture strength, it will cross the vein fracture. This research considers the magnitude of the dimensionless stress intensity factor under different vein angles, simulating the crack propagation for varying vein widths and strengths.

Hydration inhibition and physical plugging to enhance shale stability using zwitterionic polymer/nano-silica composite

In order to enhance shale stability during drilling operations, efficient shale stabilizers in water-based drilling fluids become an urgent demand. In this work, a novel shale stabilizer (ZPS) was synthesized by grafting zwitterionic polymer onto nano-silica through two steps. The particle size of ZPS ranged from 80 to 355 nm, exhibiting a regular spherical shape. The hydration inhibition property was determined by Na-bentonite (Na-BT) immersion, linear swelling and hot-rolling dispersion test. ZPS behaved superior inhibition ability compared with commonly used shale inhibitors in all tests. The plugging performance was evaluated by pressure penetration test. Results indicated that ZPS could slow down pressure penetration rate and decrease shale permeability, which displayed better plugging ability than SiO2. The mechanism study showed that the cationic groups in ZPS could be tightly adsorbed on the clay surface through electrostatic attraction to inhibit clay hydration. In addition, ZPS could enter into the pores and fractures of shale to form a plugging layer with weak water affinity, resulting in excellent plugging performance. The dual roles of ZPS in hydration inhibition and physical plugging demonstrated its potential as an efficient shale stabilizer.

Characteristics and Evolution of Tectonic Fractures in the Jurassic Lianggaoshan Formation Shale in the Northeast Sichuan Basin

The features and formation stages of natural fractures have significant influences on the fracturing of shale reservoirs and the accumulation of oil and gas. The characteristics and evolution of tectonic fractures in the Lianggaoshan Formation in Northeast Sichuan were investigated based on outcrops, drill cores, geochemical data, and acoustic emission test results. Our results demonstrated that the fracture types of the Lianggaoshan Formation were mainly low-degree bedding-slip fractures, followed by high-degree through-strata shear fractures and vertical tensile fractures. The influences of strike-slip faults on the fractures were stronger than those of thrust faults; fractures in thrust faults were concentrated in the hanging wall. The densities of tensile and shear fractures were inversely proportional to the formation thickness, while the density of interlayer slip fractures was independent of the formation thickness. The density of tectonic fractures was proportional to the quartz content. The fractures of the Lianggaoshan Formation were generated in three stages during uplift: (1) Late Yanshan–Early Himalayan tectonic movement (72~55 Ma), (2) Middle Himalayan tectonic movement (48~32 Ma), (3) Late Himalayan tectonic movement (15 Ma~4 Ma). Fractures greatly improve the oil and gas storage capacity and increase the contents of free and total hydrocarbons. At the same time, they also reduce the breakdown pressure of strata. This study facilitated the prediction of the fracture distribution and oil and gas reservoirs in the Lianggaoshan Formation and provided references for the selection of favourable areas for shale oil and the evaluation of desert sections in the study area.

Experimental investigation on the anisotropy of mode-I fracture and tensile failure of layered shale

Mode-I fracture toughness (KIC) and tensile strength (σt) are significant parameters in hydraulic fracturing. Owing to the unique mineral composition and sedimentary environment of shale, the mechanical properties of shale exhibit anisotropy. In this study, the notched semi-circular bend (NSCB) and Brazilian disc (BD) tests were combined with acoustic emission (AE) and digital image correlation (DIC) technology to investigate the anisotropic fracture and tensile behaviors of layered shale. The critical plane approach (CPA) criterion is extended and validated, and the universality of the extended CPA criterion is confirmed for both KIC and σt prediction. In addition, the variation of KIC and σt versus loading angle, the relationship between KIC and σt, the typical failure modes of both NSCB and BD specimens, and the fracture initiation angle of layered shales are discussed comprehensively. The following conclusions were drawn: (1) KIC and σt increased with increasing in the loading angle (β), which indicated significant anisotropy of layered shale, and the AE responses for different loading angles also differed significantly. (2) The variation of anisotropic KIC and σt of different shales could be predicted by adjusting the spatial distribution parameter (Ω0), so that the extended CPA criterion could predict KIC and σt of different shales accurately, which confirmed the universality of the extended CPA criterion for both KIC and σt prediction. (3) There exists an approximately linear or power relationship between KIC and σt, and the power relationship can match both experimental and theoretical results much better. (4) The data from DIC and failure modes confirmed that when β was low, the failure modes were primarily affected by the bedding plane. In contrast, when β was great, the failure modes were primarily affected by the matrix. The NSCB specimens exhibited tensile failure, whereas the BD specimens exhibited more complex failure modes, which were a combination of tensile and shear failure. The results of this study can be used for guiding the design and construction of hydraulic fracturing and rock engineering.

Long-term CRISPR locus dynamics and stable host-virus co-existence in subsurface fractured shales

Viruses are the most ubiquitous biological entities on Earth. Even so, elucidating the impact of viruses on microbial communities and associated ecosystem processes often requires identification of unambiguous host-virus linkages-an undeniable challenge in many ecosystems. Subsurface fractured shales present a unique opportunity to first make these strong linkages via spacers in CRISPR-Cas arrays and subsequently reveal complex long-term host-virus dynamics. Here, we sampled two replicated sets of fractured shale wells for nearly 800days, resulting in 78 metagenomes from temporal sampling of six wells in the Denver-Julesburg Basin (Colorado, USA). At the community level, there was strong evidence for CRISPR-Cas defense systems being used through time and likely in response to viral interactions. Within our host genomes, represented by 202 unique MAGs, we also saw that CRISPR-Cas systems were widely encoded. Together, spacers from host CRISPR loci facilitated 2,110 CRISPR-based viral linkages across 90 host MAGs spanning 25 phyla. We observed less redundancy in host-viral linkages and fewer spacers associated with hosts from the older, more established wells, possibly reflecting enrichment of more beneficial spacers through time. Leveraging temporal patterns of host-virus linkages across differing well ages, we report how host-virus co-existence dynamics develop and converge through time, possibly reflecting selection for viruses that can evade host CRISPR-Cas systems. Together, our findings shed light on the complexities of host-virus interactions as well as long-term dynamics of CRISPR-Cas defense among diverse microbial populations.

Occurrence and Origin of Nanoscale Grain Boundary Channels Under Diagenetic Conditions

AbstractNatural fractures in shale and sandstone that formed under diagenetic and metamorphic conditions are frequently filled with mineral cement that lack residual fracture porosity visible under the petrographic microscope and that are generally interpreted to be impermeable. Scanning electron microscopy of calcite, dolomite, quartz, and barite fracture cement from low‐permeability, diagenetically altered shale and sandstone formations provides evidence of open and variably connected elongate pores or gaps with apertures of 10–600 nm, referred to as nanoscale grain boundary channels (NGBC). Electron backscatter diffraction of samples prepared using broad ion‐beam milling shows that NGBCs occur along grain boundaries of blocky or columnar fracture cement. Grain boundaries are either faceted or display undulation at the nanometer scale. NGBCs tend to increase in aperture with increasing maximum formation burial temperature, indicating dissolution‐precipitation kinetics influences grain boundary structure. Transmission electron microscopy reveals heterogeneous crystallographic domains with possible amorphous regions bridging across grain boundary channels. We propose a model of dynamic concurrent dissolution‐precipitation along grain boundaries that preserves NGBCs in carbonate and quartz fracture cements that have experienced diagenetic to low‐grade metamorphic conditions. While partially healed, NGBCs may be sufficiently connected to increase permeability of low‐permeability formations containing cemented fractures.