The Cambrian Eriboll Formation exposed in the footwall of the Moine Thrust, NW Scotland, provides a suitable outcrop analog for naturally fractured tight-gas sandstone reservoirs. Previous studies distinguished five regional sets of quartz-lined or quartz-filled macrofractures (>10 m in opening displacement) that have the following strikes, from oldest to youngest, N, NW to WNE, NE, EW, and NNE (set A through set E), respectively (Laubach and Diaz-Tushman, 2009). Crosscutting relations among microfractures imaged by scanning electron microscope cathodoluminescence (SEM-CL) indicate that microfracture sets follow the same age sequence as macrofractures. Macrofractures >100 m wide are characterized by crack-seal textures interpreted to reflect multiple generations of fracture opening and cemention. In contrast, multiple stages of fracture opening and sealing are not observed in thinner microfractures. Microfractures in the Eriboll Formation are completely to partially filled with quartz cement. Microfractures contain trails of fluid inclusions trapped during fracture cement precipitation. Using microthermometry, I determined that set A microfractures have the highest range in trapping temperature of all sets, ranging from 175°C to 222°C. Fluid inclusion trapping temperatures in set B range between 181°C and 183°C, in set C between 132°C and 143°C, and in set D between 128°C to 188°C. Fluid inclusion assemblages (FIAs) of set E fluid inclusions recorded the lowest temperatures between 79°C and 91°C. Fluid inclusion microthermometric data shows a wide range of up to 46°C in homogenization temperatures for all fluid inclusion assemblages. I attribute this wide range to a combination of (1) partial re-equilibration of inclusions by later thermal events, (2) protracted sealing of microfractures under changing burial temperature conditions, and (3) repeated opening and sealing of microfractures without a recognizable textural record of crack-seal. I interpret the lowest temperature, after pressure correction in each FIA, to record the temperature of initial fracture opening and refer to this as the initial trapping temperature Ti. Initial trapping temperatures (Ti) of 22 fluid inclusion assemblages (FIAs) in different microfracture sets record an overall decrease in temperatures from set A to set E. Based on the fluid inclusion trapping temperatures, I determined the duration of microfracture opening and sealing in comparison with the reconstructed thermal history of the Eriboll Formation. This comparison suggests that microfracture sets A through set E formed between 445 Ma to 205 Ma. Set A formed before the emplacement of the Moine Thrust. Set B and set C formed shortly after the emplacement of the Moine Thrust during Early Silurian times, and set D and set E formed during the subsequent uplift and cooling. The wide range in initial trapping temperature Ti for sets A and D suggests that these fracture sets formed over periods spanning 25 Ma and 30 Ma, respectively. Shorter times are indicated for sets B, C, and E. Long periods of fracture formation are also consistent with a 4°C range in fluid inclusion ice melting temperatures, suggesting fluid inclusion trapping and thus repeated opening and sealing of microfractures as pore fluid composition changed over time. These findings indicate that microfractures could remain open in deep basin settings for geologically long periods of time providing potential pathways for fluids in otherwise poorly conductive sedimentary sequences. / text

Characterization of fractures in an arkosic sandstone from the western damage zone of the San Andreas Fault (SAF) at San Andreas Fault Observatory at Depth (SAFOD) was used to better understand the origin of damage and to determine the scale dependence of fracture fabric and fracture density. Samples for this study were acquired from core taken at approximately 2.6 km depth during Phase 1 drilling at SAFOD. Petrographic sections of samples were studied using an optical petrographic microscope equipped with a universal stage and digital imaging system, and a scanning electron microscope with cathodoluminescence (SEM-CL) imaging capability. Use of combined optical imaging and SEM-CL imaging was found to more successfully acquire true fracture density at the grain scale. Linear fracture density and fracture orientation were determined for transgranular fractures at the whole thin section scale, and intragranular fractures at the grain scale. The microscopic scale measurements were compared to measurements of mesoscopic scale fractures in the same core, as well as to published data from an ancient, exhumed trace of the SAF in southern California. Fracturing in the damage zone of the SAF fault follows simple scaling laws from the grain scale to the km scale. Fracture density distributions in the core from SAFOD are similar to distributions in damaged arkosic sandstone of the SAF along other traces. Transgranular fractures, which are dominantly shear fractures, indicate preferred orientation approximately parallel to the dominant sets of the mesoscale faults. Although additional work is necessary to confirm general applicability, the results of this work demonstrate that fracture density and orientation distribution over a broad range of scales can be determined from measurements at the mesoscopic scale using empirical scaling relations.

Frequently a discrepancy is found between the stimulated shale volume (SSV) estimated from production data and the SSV expected from injected water and proppant volume. One possible explanation is the presence of a fracture network, often termed fracture complexity, that may have been opened or reopened during the hydraulic fracturing operation. The main objective of this work is to investigate the role of fracture complexity in resolving the apparent SSV discrepancy and to illustrate whether the presence of reopened natural fracture network can be observed in pressure and production data of shale gas wells producing from two shale formations with different well and reservoir properties. Homogeneous, dual porosity and triple porosity models are investigated. Sensitivity runs based on typical parameters of the Barnett and the Horn River shale are performed. Then the field data from the two shales are matched. Homogeneous models for the two shale formations indicate effective infinite conductivity fractures in the Barnett well and only moderate conductivity fractures in the Horn River shale. Dual porosity models can support effectively infinite conductivity fractures in both shale formations. Dual porosity models indicate that the behavior of the Barnett and Horn River shale formations are different. Even though both shales exhibit apparent bilinear flow behavior the flow behaviors during this trend are different. Evidence of this difference comes from comparing the storativity ratio observed in each case to the storativity ratio estimated from injected fluid volumes during hydraulic fracturing. In the Barnett shale case similar storativity ratios suggest fracture complexity can account for the dual porosity behavior. In the Horn River case, the model based storativity ratio is too large to represent only fluids from hydraulic fracturing and suggests presence of existing shale formation microfractures.

Both joint sets and fault-related fractures serve as important conduits for fluid flow. In the former case, they can strongly influence both permeability and permeability anisotropy, with implications for production of water, hydrocarbons and contaminant transport. The latter can affect issues of fluid flow, such as whether a given fault seals or leaks, and fault mechanics. These fractures are commonly interpreted as Natural Hydraulic Fractures (NHFs), i.e., mode 1 fractures produced when pore fluid pressure exceeds the tensile strength of the rock. Various mathematical models have been a rich source of hypotheses to explain the formation and propagation of NHFs, but have provided only limited information and nothing about processes of fracture initiation in originally intact rock. Recent laboratory experiments of French et al. (2012) have advanced our understanding of mechanical controls on fracture initiation and spacing. Here, detailed analysis of both through-going fracture surfaces, non-through-going fractures, in experimentally deformed samples provide a deeper understanding of NHF processes and resulting geometric features in porous siliciclastic sedimentary rocks. Observations indicate that both fracture planarity and microcrack damage (which has not previously been reported for opening mode fractures) vary significantly depending on the degree of mechanical heterogeneity and anisotropy of the host rock. Variations reflect mechanical controls on fracture initiation and propagation, suggesting that fracture spacing may in part reflect the distribution of mechanical heterogeneities. These data indicate that the more homogeneous the rock, the greater the microcrack damage surrounding a given NHF, increasing expected fracture-associated permeability for a given fracture aperture.

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