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At least 271 records · Page 15
All sourcesNASA NTRSDOE OSTI
DOE OSTI2018

Analysis and Distribution of Proppant Recovered from Fracture Faces in the HFTS Slant Core Drilled through a Stimulated Reservoir

Although sand proppant has been used since 1949 to increase efficacy of hydraulically fractured treatments by preventing fractures from closing after well depressurization, many questions remain regarding the behavior and distribution of proppant in the subsurface. To this end, we quantified the amount of recovered proppant in open fractures within a slant core drilled through hydraulically fractured Wolfcamp Shale. To improve understanding of hydraulic-fracture growth and patterns, we then addressed basic questions such as the following regarding proppant behavior in the subsurface: Is there variation along the length of the examined core? Is the proppant mainly found in hydraulic fractures, in reactivated natural fractures, or is it transported into drilling-induced fractures during recovery? Do the majority of proppant grains remain whole or tend to get crushed? To answer these questions, we collected all material from every open fracture (407 samples total) within ~600 ft of core. Samples consisted of drilling mud, aluminum shavings from the core barrel, shale and lithic fragments, calcite, and, potentially, sand proppant (95% plain and 5% colored resin-coated grains) pumped during the hydraulic fracturing of adjacent wells. We then washed, sieved into four size fractions, weighed, and imaged all samples for quantitative image analysis. Retrieved samples were labeled with respect to a master fracture database, where fractures were identified in the core and on CT scans of each 3-ft interval, allowing us to code them as either hydraulic, natural reactivated, or drilling/recovery-induced fractures. From this coding, we quantified the amount of proppant within each fracture, analyzed the distribution of grains among different fracture types, and traced base versus colored grains. Proppant packs 0.5–1 cm thick were found in two locations where there was complex fracture geometry, but fracture faces showed no evidence of proppant embedment. In situ sand patches were found on a few fracture faces, mostly in fractures near the proppant packs. Pumped proppant was 100 and 40/70 mesh (149–420 μm), and even though widespread grain crushing is not observed, the majority of recovered proppant ranges from 63 to 250 μm. The distribution of retrieved proppant, especially the larger retrieved sizes (250– >500 μm), mirrors the proximity of the slant core to the hydraulic fracture treatment wells. Hydraulic fracture samples contained variable amounts of proppant, and natural reactivated fractures sometimes contained more proppant than nearby hydraulic fractures, suggesting transference between fracture types in the subsurface. Regarding colored proppant, some colored sands occurred in discreet fractures, whereas other colors appeared to be mixed and widespread. Ultimately, all fractures contain at least some proppant, especially in the smallest size fractions; however, the extent to which the proppant was introduced during the core-drilling process is still unknown. Our study is one of the first attempts at physically recovering and quantifying injected proppant from parted fracture breaks within a stimulated reservoir, and the results are significant in terms of understanding propped fracture networks and predicting future proppant distribution during hydraulic fracturing.

Elliott, Sara↗
DOE OSTI2022

Mechanisms for the Generation of Complex Fracture Networks: Observations From Slant Core, Analog Models, and Outcrop

We use observations of hydraulic fractures in core, outcrop attributes of natural hydraulic fractures, and analogue models, to address how hydraulic fracture networks evolve. A slant core from the Wolfcamp Formation—an unconventional shale hydrocarbon reservoir in the Permian Basin of West Texas—collected within 18 m and 30 m of two hydraulically stimulated horizontal wells, provided an opportunity to examine hydraulic fractures directly. In approximately 183 m of core, 309 calcite-sealed natural opening-mode fractures and 375 hydraulic fractures were identified. Many hydraulic fractures in the core show complex morphology, including twist-hackle segmentation, diversion, and bifurcation; these structures most commonly develop at lithological bed boundaries and mechanical heterogeneities such as natural fractures and concretions. An outcrop of bed-parallel pavements in the Cretaceous Boquillas Formation in West Texas contains opening-mode fractures that likely formed by natural hydraulic fracturing. Fracture traces provide evidence of twist-hackle segmentation, and are typically associated with bed boundaries and preexisting bed-parallel stylolites. A laboratory study of hydraulic fracturing of 33 synthetic blocks of gypsum and hydrostone revealed fracture steps, diversions, twist hackles, and multiple overlapping fractures together with information on fracture growth directions. These complexities in the fracture network were dominantly nucleated at inclusions used to simulate pre-existing fractures, and as a result of mechanical heterogeneity introduced by the wellbore and perforations. Collectively, our results show that complex fracture networks are produced in hydraulic fracturing of self-sourced reservoir strata. Mechanical stratigraphic boundaries and other heterogeneities are likely to enhance fracture network complexity through the processes of segmentation, diversion, and bifurcation. These processes create multiple fracture strands, resulting in an increased number of hydraulic fractures over those initiated, thereby increasing total fracture surface area. Our study provides insight into hydraulic fracture network propagation, and has applications for evaluation, completion, production, and fracture modeling of unconventional reservoirs.

54 ENVIRONMENTAL SCIENCES↗
NASA NTRS2017

Characterizing Fractures Across the Astronaut Corps: Preliminary Findings from Population-Level Analysis

Despite evidence of bone loss during spaceflight and operational countermeasures to mitigate this loss, the subsequent risk of fracture among astronauts is not known. The physiologic process of diminished bone density and bone recovery during or following spaceflight is multifactorial. Such factors as age, sex, fracture history, and others may combine to increase fracture risk among astronauts. As part of the 2016 Bone Research and Clinical Advisory Panel (RCAP), the authors analyzed data collected on 338 NASA astronauts to describe the demographics, bone-relevant characteristics, and fracture history of the astronaut population. The majority of the population are male (n=286, 84.6%), have flown at least one mission (n=306, 90.5%), and were between the ages of 30 and 49 at first mission (n=296, 96.7% of those with at least one mission). Of the 338 astronauts, 241 (71.3%) experienced a fracture over the course of their lifetime. One hundred and five (43.5%) of these 241 astronauts only experienced a fracture prior to being selected into the Astronaut Corps, whereas 53 (22.0%) only experienced a fracture after selection as an astronaut. An additional 80 astronauts (33.2%) had both pre- and post-selection fractures. The remaining 3 astronauts had a fracture of unknown date, which could not be categorized as pre- or post-selection. Among the 133 astronauts with at least one post-selection fracture, males comprised 90.2% (n=120) compared to 84.5% of the entire Corps, and females accounted for 9.8% (n=13) compared to 15.4% of the Corps. Ninety-seven of the 133 astronauts with post-selection fractures (72.9%) had one fracture event, 22 (16.5%) had two fractures, and 14 (10.5%) had three or more fractures. Some astronauts with multiple fractures suffered these in a single event, such as an automobile accident. The 133 astronauts with a post-selection fracture accounted for a total of 188 fracture events. One hundred and four (78.2%) of astronauts with post-selection fractures experienced those fractures following their first mission (mean 12.7 +/- 11.1 years following first mission; range 14.0 days - 50.6 years). Additional analyses are ongoing and include examination of fracture history, skeletal site, mechanism, and type of fracture, age at time of fracture, time from spaceflight to fracture, as well as multivariable analysis comparing fracture events to non-events. The results of such analyses may reveal trends in risk factors for fracture among the astronaut corps that have yet to be systematically described through a corps-wide approach.

Rossi, Meredith M.↗
DOE OSTI2021

Fracture Description of the HFTS-2 Slant Core, Delaware Basin, West Texas

Previous work in the Midland Basin Hydraulic Fracture Test Site project (HFTS1) has shown the value of core recovered from a stimulated volume in providing information on the geometry and extent of hydraulic fractures. This project (HFTS2) is in the Wolfcamp Formation of the Delaware Basin. A slant core through the stimulated volume was acquired above and below a stimulated well and the results of the fracture description are presented here. Here, nine, 3-inch-diameter whole cores from the slant well were examined for fractures prior to slabbing, together with a CT scan of the core. We used criteria developed during the HFTS1 project to identify hydraulic, natural, drilling-induced and core-handling fractures. Material collected from a few fracture faces was cleaned, sieved, and examined under a microscope to look for proppant. A total of 1261 fractures, including 500 hydraulic fractures, were described in 948 feet of core. Hydraulic fractures are not evenly distributed through the cores; they tend to occur in clusters. Many are remarkably planar, smooth, and featureless, while others have twist hackles, steps, plumose, and kinks. Natural, subvertical fractures, mostly less than 1 mm in width, sealed with blocky calcite, are oriented NE-SW (Set 1) and WNW-ESE (Set 2). Two Set 1 fractures have drusy cement on parted faces and were possibly open prior to drilling. A few subvertical sealed fractures with different orientations are also present. Bed-parallel natural fractures, most having fibrous cement (beef), and some showing top-to-north bed-parallel shear are present. Faults with normal/oblique movement were found in one part of the core. Drilling induced and core-handling breaks were identified in all cores, and were also noted to have reactivated some natural fractures. The results from this work will allow hydraulic fracture distribution relative to the stimulated well to be assessed. The number of fractures is generally greater than the number of perforations, but these can be compared for different stages and perforation clusters. Surface features provide information about the direction of hydraulic fracture propagation and about segmentation and bifurcation that might increase the number of fracture strands. Reactivation of natural fractures, including bedding-parallel fractures, occurs although the mechanism of parting is mostly unknown. The wider HFTS2 project will make use of this fracture description to improve hydraulic fracture modeling (geomechanics and engineering), to help explain pressure depletion and fiber optics observations (reservoir depletion and frac geometry), to help verify indirect fracture diagnostic techniques such as microseismic monitoring (geophysics), and to help calibrate horizontal well image logs.

58 GEOSCIENCES↗
DOE OSTI2020

Role of interaction between hydraulic and natural fractures on production

One of the main purposes of hydraulic fracturing in unconventional resources such as shale is to improve the connectivity between existing natural fractures and the production well. Since the inherent permeability of shale is extremely low, this newly formed fracture connectivity provides faster paths for the hydrocarbon stored in preexisting natural fractures. In this study, we performed numerical simulations of the free gas production at large scale fractured reservoir with different pre-existing natural fracture network intensities and with variable hydraulic fracture sizes and staging. We explored production characteristics as a function of the properties of both, natural fractures (intensity) and hydraulic fractures (size and staging). Our hypothesis is that once maximum fracture connectivity is achieved, additional stimulation does not increase production significantly. In this numerical study we use an advanced modeling tool to study fractures connectivity, Discrete Fracture Network (DFN) approach, which can represent fracture networks similar to those observed on individual reservoir sites. In our model the horizontal production well and vertical hydraulic fractures were deterministically defined and surrounded by stochastically generated natural fracture networks. The performed numerical experiments show how fracture connectivity depends on hydraulic fracture settings in fractured reservoir with different preexisting fracture densities. We numerically showed that cumulative free gas production is not affected significantly by hydraulic fractures size (25 m–150 m) or spacing (15 m–45 m) for dense natural fracture networks. However, the hydraulic fracture size is important in reservoirs with sparse natural fractures, although spacing (number of stages) does not play a significant role.

58 GEOSCIENCES↗
DOE OSTI2018

Propagation, proppant transport and the evolution of transport properties of hydraulic fractures

Hydraulic fracturing is a widely used method for well stimulation to enhance hydrocarbon recovery. Permeability, or fluid conductivity, of the hydraulic fracture is a key parameter to determine the fluid production rate, and is principally conditioned by fracture geometry and the distribution of the encased proppant. A numerical model is developed to describe proppant transport within a propagating blade-shaped fracture towards defining the fracture conductivity and reservoir production after fracture closure. Fracture propagation is formulated based on the PKN-formalism coupled with advective transport of an equivalent slurry representing a proppant-laden fluid. Empirical constitutive relations are incorporated to define rheology of the slurry, proppant transport with bulk slurry flow, proppant gravitational settling, and finally the transition from Poiseuille (fracture) flow to Darcy (proppant pack) flow. At the maximum extent of the fluid-driven fracture, as driving pressure is released, a fracture closure model is employed to follow the evolution of fracture conductivity with the decreasing fluid pressure. This model is capable of accommodating the mechanical response of the proppant pack, fracture closure of potentially contacting rough surfaces, proppant embedment into fracture walls, and most importantly flexural displacement of the unsupported spans of the fracture. Results show that reduced fluid viscosity increases the length of the resulting fracture, while rapid leak-off decreases it, with both characteristics minimizing fracture width over converse conditions. Proppant density and size do not significantly influence fracture propagation. Proppant settling ensues throughout fracture advance, and is accelerated by a lower viscosity fluid or greater proppant density or size, resulting in accumulation of a proppant bed at the fracture base. ‘Screen-out’ of proppant at the fracture tip can occur where the fracture aperture is only several times the diameter of the individual proppant particles. After fracture closure, proppant packs comprising larger particles exhibit higher conductivity. More importantly, high-conductivity flow channels are necessarily formed around proppant banks due to the flexural displacement of the fracture walls, which offer preferential flow pathways and significantly influence the distribution of fluid transport. Higher compacting stresses are observed around the edge of proppant banks, resulting in greater depths of proppant embedment into the fracture walls and/or an increased potential for proppant crushing.

Mechanics↗
DOE OSTI2022

Experiments and Modeling of Proppant Embedment and Fracture Conductivity for the Caney Shale, Oklahoma, USA

ABSTRACT: The ultimate aim of hydraulic fracturing is to have a long and conductive flow path that extends from the wellbore into the formation. The effective fracture length is part of a hydraulically propped fracture which contributes to production. The difficulty in achieving economical production targets from shale reservoirs is at the forefront in many exploration companies. Fracture conductivity loss is related to; proppant embedment under depletion, proppant crushing, damage as a result of fracturing fluid, fines migration and proppant-pack permeability-damage are some of the factors that contribute to production decline after hydraulic fracturing in shale reservoirs. The Caney Shale is a calcareous organic-rich mudrock. Various studies have investigated the effect that clay on shale well productivity, however, there is currently no literature on the Caney shale in relation to horizontal wells; all available literature exists in vertical wells as well as on formations of the Caney that are shallow in comparison to an emerging play which is twice the depth. In this paper we investigate stress-dependent fracture conductivity of proppant-filled fractures and proppant embedment in Caney shale through laboratory and modeling studies. API fracture conductivity tests were conducted using 2% KCl on five locations within the Caney shale that consisted of selecting three brittle(reservoir) zones and two ductile zones. Confining pressures range from 1,000 psi to 12,000 psi at 210°F. Conductivity, permeability as well as embedment were measured during the test. Our experimental results have confirmed that improved fracture conductivity is attributed to; proppant size, the increase in porosity of the proppant pack, closure pressure changes and the reduction in fracture conductivity are a function of many factors such as fracture closure stress. The findings from this study could help the stimulation design by providing new insights into the critical factors that are to be determined to facilitate the choice of proppants as well as fracturing fluids for long term production and recovery from shale reservoirs. 1 INTRODUCTION The development of low permeability formations, like shales, has been aided by hydraulic fracturing of horizontal wells (Radonjic et al., 2020). Hydraulic fracturing fluid is injected at a high pressure to induce tensile fractures that can link to and stimulate natural fractures (Katende et al., 2021a,b). Preserving adequate conductivity in hydraulic fractures over the life of the wells is required for economic production; nevertheless, conserving such conductivity can be difficult in some circumstances, particularly in soft, clay-rich formations (Wang et al., 2021). Proppant particles help to keep the fractures open when the pumping stops and the fracturing fluid returns to the wellbore, producing one or more propped hydraulic fractures of varying length, breadth, and height (Katende et al., 2021a). The proppant pack within the hydraulic fracture boosts well output by providing a greater permeability flowpath for hydrocarbons (Duenckel et al., 2016). Proppant in the fracture is under complicated stress conditions, and the interplay between the rock formation and the proppant pack has a significant impact on proppant-pack permeability (Karazincir et al., 2019). Proppant may be embedded (Katende et al., 2021a) in the rock or crushed into small pieces if the proppant size and strength characteristics are not specified appropriately, resulting in a loss in proppant-pack permeability and fracture aperture, and consequently a fall in well output.

Katende, A.↗
DOE OSTI2015

Rock fracture processes in chemically reactive environments

Rock fracture is traditionally viewed as a brittle process involving damage nucleation and growth in a zone ahead of a larger fracture, resulting in fracture propagation once a threshold loading stress is exceeded. It is now increasingly recognized that coupled chemical-mechanical processes influence fracture growth in wide range of subsurface conditions that include igneous, metamorphic, and geothermal systems, and diagenetically reactive sedimentary systems with possible applications to hydrocarbon extraction and CO 2 sequestration. Fracture processes aided or driven by chemical change can affect the onset of fracture, fracture shape and branching characteristics, and fracture network geometry, thus influencing mechanical strength and flow properties of rock systems. We are investigating two fundamental modes of chemical-mechanical interactions associated with fracture growth: 1. Fracture propagation may be aided by chemical dissolution or hydration reactions at the fracture tip allowing fracture propagation under subcritical stress loading conditions. We are evaluating effects of environmental conditions on critical (fracture toughness KIc) and subcritical (subcritical index) fracture properties using double torsion fracture mechanics tests on shale and sandstone. Depending on rock composition, the presence of reactive aqueous fluids can increase or decrease KIc and/or subcritical index. 2. Fracture may be concurrent with distributed dissolution-precipitation reactions in the hostrock beyond the immediate vicinity of the fracture tip. Reconstructing the fracture opening history recorded in crack-seal fracture cement of deeply buried sandstone we find that fracture length growth and fracture opening can be decoupled, with a phase of initial length growth followed by a phase of dominant fracture opening. This suggests that mechanical crack-tip failure processes, possibly aided by chemical crack-tip weakening, and distributed solution-precipitation creep in the hostrock can independently affect fracture opening displacement and thus fracture aperture profiles and aperture distribution.

58 GEOSCIENCES↗