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At least 163 records · Page 9
All sourcesNASA NTRSDOE OSTI
DOE OSTI2019

In situ transformation of hydraulic fracturing surfactants from well injection to produced water

Chemical changes to hydraulic fracturing fluids (HFFs) within fractured unconventional reservoirs may affect hydrocarbon recovery and, in turn, the environmental impact of unconventional oil and gas development. Ethoxylated alcohol surfactants, which include alkyl ethoxylates (AEOs) and polyethylene glycols (PEGs), are often present in HFF as solvents, non-emulsifiers, and corrosion inhibitors. We present detailed analysis of polyethoxylates in HFF at the time of injection into three hydraulically fractured Marcellus Shale wells and in the produced water returning to the surface. Despite the addition of AEOs to the injection fluid during almost all stages, they were rarely detected in the produced water. Conversely, while PEGs were nearly absent in the injection fluid, they were the dominant constituents in the produced water. Similar numbers of ethoxylate units support downhole transformation of AEOs to PEGs through central cleavage of the ethoxylate chain from the alkyl group. We also observed a decrease in the average ethoxylate (EO) number of the PEG–EOs in the produced water over time, consistent with biodegradation during production. Our results elucidate an overlooked surfactant transformation pathway that may affect the efficacy of HFF to maximize oil and gas recovery from unconventional shale reservoirs.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2018

Armstrong well

Computed tomography and multi-sensor core logger data for the Armstrong well, primarily Marcellus shale, described in Paronish, T.; Mackey, P.; Crandall, D.; Moore, J.; Brown, S.; Carr, T.; Dinterman, P; Jarvis, K. Computed Tomography Scanning and Geophysical Measurements of the Marcellus Formation from the Armstrong #1 Well; NETL-TRS-17-2018; NETL Technical Report Series; U.S. Department of Energy, National Energy Technology Laboratory: Morgantown, WV, 2018; p 60. DOI: 10.18141/1471662.

Core logging↗
DOE OSTI2020

Reduced methane recovery at high pressure due to methane trapping in shale nanopores

By 2050, shale gas production is expected to exceed three-quarters of total US natural gas production. However, current unconventional hydrocarbon gas recovery rates are only around 20%. Maximizing production of this natural resource thus necessitates improved understanding of the fundamental mechanisms underlying hydrocarbon retention within the nanoporous shale matrix. In this study, we integrated molecular simulation with high-pressure small-angle neutron scattering (SANS), an experimental technique uniquely capable of characterizing methane behavior in situ within shale nanopores at elevated pressures. Samples were created using Marcellus shale, a gas-generative formation comprising the largest natural gas field in the United States. Our results demonstrate that, contrary to the conventional wisdom that elevated drawdown pressure increases methane recovery, a higher peak pressure led to the trapping of dense, liquid-like methane in sub-2 nm radius nanopores, which comprise more than 90% of the measured nanopore volume, due to irreversible deformation of the kerogen matrix. These findings have critical implications for pressure management strategies to maximize hydrocarbon recovery, as well as broad implications for fluid behavior under confinement.

58 GEOSCIENCES↗
DOE OSTI2020

Gaining Perspective on Unconventional Well Design Choices through Play-level Application of Machine Learning Modeling

The recent development of unconventional oil and gas (O&G) reservoirs has led to an abundant hydrocarbon supply, both domestically and globally. However, there is a continued push to develop new and innovative approaches to improve exploration and extraction efficiencies and overall well productivity moving forward. Substantial improvements in unconventional O&G development are expected through optimized well completion and stimulation strategies aimed at maximizing well productivity. Optimizing well designs will require tailoring to the distinctive geologic conditions present for any newly placed well. To better evaluate the impact of well design attributes and their associated interactions on productivity in a major unconventional play, multivariate machine learning-based models that use empirical datasets were developed. A gradient boosted regression tree (GBRT) algorithm was applied. GBRT has been narrowly investigated for O&G applications but enables straightforward parametric importance and influence evaluation, as well as assessment of parameter interaction effects. Models were trained on well design and locational parameters that serve as a proxy for variable geologic conditions to estimate two types of productivity indicator response variables strongly correlated to estimated ultimate recovery (EUR). The dataset utilized consists of over 7,000 well observations that cover the majority of the productive region of the Marcellus Shale. Model performance was evaluated and algorithm parameters tuned by analyzing the goodness-of-fit for simulated results against observed data in a cross-validation approach. Models were found capable of 73–79 percent prediction accuracy on held out testing data of gas equivalent production and can be used to inform future well design and placement decisions for increasing EUR per well and improving overall field-level recovery. Study results indicate that Marcellus well performance improves most with upscaling perforated interval lengths and water and proppant volumes per foot; but relative productivity improvements are spatially dependent across the play. Finally, optimal combinations of water and proppant on well performance were found to vary depending on well location, emphasizing the utility of data-driven models capable of broad application across a play of interest for informing tailored well design approaches prior to their field deployment.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2020

Reactive Transport Modeling of Shale–Fluid Interactions after Imbibition of Fracturing Fluids

Injection of hydraulic fracturing fluid (HFF) into shale formations for unconventional oil/gas production results in chemical reactions in the shale matrix. Our recent experimental study determined the depths to which different types of reactions between the shale matrix and the HFF extended. In the present study, we built continuum-scale reactive transport models to understand the coupling of chemical reactions and the transport of aqueous species in these shale–HFF systems. Calibration of the model with our previous experimental results reveals that it takes hours to months for the shale matrix to completely neutralize the imbibed acids, depending primarily upon the carbonate content of the shale. Both the HFF pH and pore pH affect the location of barite precipitation, resulting in unique barite precipitation profiles extending millimeters into calcite-rich Eagle Ford shale but only tens of micrometers into low-carbonate Marcellus shale. In addition, dissolved oxygen and extracted bitumen are key to reproducing the experimental observation of Fe(III) (oxyhydr)oxide formation in the shale matrix as a result of pyrite dissolution in the shales. A comparison between the modeling results of porosity in the present study to experimentally measured permeabilities in our previous study suggests that chemical reactions occurring at a greater depth than the observable reaction zone might have impacted permeability. Our model serves as a benchmark for efficiently modeling water–rock interactions in similar systems where bulk rock samples react with a solution in batch reactors. Important reactive transport processes were ascertained via modeling, which allows for quantitative prediction of shale–HFF interactions in shale matrices given the shale and HFF compositions.

58 GEOSCIENCES↗
DOE OSTI2018

Multiphysics Lattice Discrete Particle Modeling (M-LDPM) for the Simulation of Shale Fracture Permeability

A three-dimensional multiphysics lattice discrete particle model (M-LDPM) framework is formulated to investigate the fracture permeability behavior of shale. The framework features a dual lattice system mimicking the mesostructure of the material and simulates coupled mechanical and flow behavior. The mechanical lattice model simulates the granular internal structure of shale, and describes heterogeneous deformation by means of discrete compatibility and equilibrium equations. The network of flow lattice elements constitutes a dual graph of the mechanical lattice system. A discrete formulation of mass balance for the flow elements is presented to model fluid flow along cracks and intact materials. The overall computational framework is implemented with a mixed explicit–implicit integration scheme and a staggered coupling method that makes use of the dual lattice topology enabling the seamless two-way coupling of the mechanical and flow behaviors. The proposed model is used for the computational analysis of shale fracture permeability behavior by simulating triaxial direct shear tests on Marcellus shale specimens under various confining pressures. The simulated mechanical response is calibrated against the experimental data, and the predicted permeability values are also compared with the experimental measurements. Moreover, the paper presents the scaling analysis of both the mechanical response and permeability measurements based on simulations performed on geometrically similar specimens with increasing size. The simulated stress strain curves reflect a significant size effect in the post-peak due to the presence of localized fractures. The scaling analysis of permeability measurements enables prediction of permeability for large specimens by extrapolating the numerical results of small ones.

58 GEOSCIENCES↗
DOE OSTI2021

Role of Mineralogy in Controlling Fracture Formation

The presence of fractures in caprocks can pose increased risks in subsurface energy systems and processes like CO 2 sequestration by introducing high-permeability leakage paths. Fracture apertures and permeability can be altered through mineral dissolution and precipitation reactions, but the reactive evolution of fractures is not well understood. In fractures, minerals that are otherwise inaccessible to reactive fluids can become exposed, resulting in mineral reactions unpredicted by bulk formation data. This work seeks to understand the relationship between mineralogy and fracture formation to enhance our understanding of reactive fracture evolution and CO 2 leakage potential. Here, the mineral compositions of mechanically induced fracture surfaces in samples of the Mancos and Marcellus shales have been quantified and compared to those of the near-fracture matrices using imaging and bulk X-ray diffraction (XRD) data. In the Mancos shale, the concentrations of clay minerals are enhanced along fracture surfaces with respect to the bulk, and the fracture is most likely to form at kaolinite–kaolinite interfaces. Further, evaluation of the mineralogical spatial variability through cross-correlation analysis of the surrounding matrix in images of samples cut perpendicular to the fracture shows that clay is 16.7 times more likely to be present than carbonate minerals near the fracture surface. The high correlation persists roughly 200 μm into the surrounding matrix for the Mancos sample and implies that the fracture formed within a defined clay-rich lithofacies.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2019

Thicknesses of Chemically Altered Zones in Shale Matrices Resulting from Interactions with Hydraulic Fracturing Fluid

Hydraulic fracturing of unconventional shale reservoirs increases the fracture network surface area to access hydrocarbons from the low permeability rock matrix. Porosity and permeability of the matrix, through which hydrocarbons migrate to fractures, are important for determining production efficiency and can be altered by chemical interactions between shale and hydraulic fracturing fluids (HFFs). Here, we present results from an experimental study that characterizes the thickness of the alteration zone in the shale matrix after shale–HFF interactions. Experiments were conducted with whole cores submerged in HFF both with and without added barium and sulfate to promote barite scale formation. After 3 weeks of reaction at 77 bar and 80°C, the cores were characterized using X-ray microtomography, synchrotron X-ray fluorescence microprobe imaging, and synchrotron X-ray absorption spectroscopy. Our results show that the thickness of the altered zone depends on shale mineralogical composition and varies for different chemical reactions. Reactions between the low-carbonate Marcellus shale and HFF, pyrite (FeS 2 ) oxidation manifests as both a thick zone of sulfur oxidation (>0.5 cm) and a thinner zone of iron oxidation (100–150 $μ$m). Carbonate dissolution extended 100–200 μm into the matrix, with the resulting observable secondary porosity localized at the shale–fluid interface where mineral grains were removed by either dissolution or mechanical erosion. In solutions oversaturated with respect to barite, barite precipitates were observed in the reaction fluid and at the shal–HFF interface. In contrast, the carbonate dissolution zone in the high-carbonate Eagle Ford was only 30–40 μm thick, within which a uniform texture of increased porosity was observed. Pyrite oxidation in the Eagle Ford was evident from an iron oxidation zone (150–200 μm thick), while sulfur oxidation was minor and hard to observe. Barite precipitation extended 1–2 mm into the matrix when the initial HFF was oversaturated with respect to barite, filling shale microcracks down to the submicrometer length scale. Our findings provide a scientific basis to predict the extent of chemical alteration in shale reservoirs during hydraulic fracturing and its impacts on hydrocarbon production.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2021

Accessibility of Pores to Methane in New Albany Shale Samples of Varying Maturity Determined Using SANS and USANS

The accessibility of pores to methane has been investigated in Devonian New Albany Shale Formation early-mature (Ro = 0.50%) to post-mature (Ro = 1.40%) samples. A Marcellus Shale Formation sample was included to expand the maturation range to Ro 2.50%. These are organic matter-rich rocks with total organic carbon (TOC) values of 3.4 to 14.4% and porosity values of 2.19 to 6.88%. Contrast matching small-angle neutron scattering (SANS) and ultra-small angle neutron scattering (USANS) techniques were used to generate porosity-related data before and after pressure cycling under hydrostatic (in a vacuum and at 500 bar of deuterated methane) and uniaxial stress (0 to ca. 350 bar) conditions. Our results showed that the accessible porosity was small for the samples studied, ranging from zero to 2.9%. No correlation between the accessible porosity and TOC or mineralogical composition was revealed, and the most likely explanation for porosity variation was related to the thermal transformation of organic matter and hydrocarbon generation. Pressure caused improvements in accessible porosity for most samples, except the oil window sample (Ro = 0.84%). Our data show that densification of methane occurs in nanopores, generally starting at diameters smaller than 20 nm, and that the distribution of methane density is affected by pressure cycling.

03 NATURAL GAS↗
DOE OSTI2016

Determination of elemental composition of shale rocks by laser induced breakdown spectroscopy

Laser induced breakdown spectroscopy (LIBS) is used for elemental characterization of outcrop samples from the Marcellus Shale. Powdered samples were pressed to form pellets and used for LIBS analysis. Partial least squares regression (PLS-R) and univariate calibration curves were used for quantification of analytes. The matrix effect is substantially reduced using the partial least squares calibration method. Predicted results with LIBS are compared to ICP-OES results for Si, Al, Ti, Mg, and Ca. As for C, its results are compared to those obtained by a carbon analyzer. Relative errors of the LIBS measurements are in the range of 1.7 to 12.6%. The limits of detection (LODs) obtained for Si, Al, Ti, Mg and Ca are 60.9, 33.0, 15.6, 4.2 and 0.03 ppm, respectively. An LOD of 0.4 wt.% was obtained for carbon. Finally, this study shows that the LIBS method can provide a rapid analysis of shale samples and can potentially benefit depleted gas shale carbon storage research.

58 GEOSCIENCES↗
DOE OSTI2013

Modeling of fault reactivation and induced seismicity during hydraulic fracturing of shale-gas reservoirs

We have conducted numerical simulation studies to assess the potential for injection-induced fault reactivation and notable seismic events associated with shale-gas hydraulic fracturing operations. The modeling is generally tuned towards conditions usually encountered in the Marcellus shale play in the Northeastern US at an approximate depth of 1500 m (~;;4,500 feet). Our modeling simulations indicate that when faults are present, micro-seismic events are possible, the magnitude of which is somewhat larger than the one associated with micro-seismic events originating from regular hydraulic fracturing because of the larger surface area that is available for rupture. The results of our simulations indicated fault rupture lengths of about 10 to 20 m, which, in rare cases can extend to over 100 m, depending on the fault permeability, the in situ stress field, and the fault strength properties. In addition to a single event rupture length of 10 to 20 m, repeated events and aseismic slip amounted to a total rupture length of 50 m, along with a shear offset displacement of less than 0.01 m. This indicates that the possibility of hydraulically induced fractures at great depth (thousands of meters) causing activation of faults and creation of a new flow path that can reach shallow groundwater resources (or even the surface) is remote. The expected low permeability of faults in producible shale is clearly a limiting factor for the possible rupture length and seismic magnitude. In fact, for a fault that is initially nearly-impermeable, the only possibility of larger fault slip event would be opening by hydraulic fracturing; this would allow pressure to penetrate the matrix along the fault and to reduce the frictional strength over a sufficiently large fault surface patch. However, our simulation results show that if the fault is initially impermeable, hydraulic fracturing along the fault results in numerous small micro-seismic events along with the propagation, effectively preventing larger events from occurring. Nevertheless, care should be taken with continuous monitoring of induced seismicity during the entire injection process to detect any runaway fracturing along faults.

03 NATURAL GAS↗
DOE OSTI2023

Using Low-Field Nuclear Magnetic Resonance and X-Ray Computed Microtomography Imaging to Explore Potential of Microbially-Induced Calcium Carbonate Precipitation Treatment to Seal Shale Fractures

Microbially-induced calcium carbonate precipitation (MICP) is a biological process in which microbially produced urease enzymes convert urea and calcium into solid calcium carbonate (CaCO 3 ) deposits. Studies have shown that MICP can be used to seal fractures in shale, raising the possibility of applying this technology to restimulate fracking wells by plugging underperforming fractures. For this and other applications to become a reality, non-invasive tools are needed to determine how effectively MICP seals shale fractures under subsurface conditions. In this study, a 2.54 cm wide and 5.08 cm long Marcellus shale core with a single, ~1 mm wide fracture held open by sand "proppant" underwent MICP-treatment at 60°C until reaching three orders of magnitude permeability reduction. Low-field nuclear magnetic resonance (LF-NMR) and X-Ray computed microtomography (μ-CT) techniques were used to assess the extent of biomineralization within the fracture. These tools revealed that while CaCO 3 precipitation occurred throughout the fracture, there was preferential precipitation around proppant, and the core sealed at the effluent end before filling most of the fracture. Both tools were able to independently calculate of the amount of solid biomineral formed inside the fracture. Furthermore, this study found that the distribution of proppant within the shale fracture was an important parameter controlling the degree of biomineralization.

clastic rock↗
DOE OSTI2018

Influence of Microbial Membranes on Biofilm Formation, Scaling Reactions, and Production Chemistry in Engineered Energy Systems (Final Report)

Humans are engineering the deep subsurface for the purposes of energy-capture, energy-storage, and environmental mitigation. Despite the potential for microbial communities to significantly alter the effectiveness of these technologies, we have historically lacked a clear understanding of how microbial cells interact in a fractured shale system. Existing knowledge has been heavily based on genomic information, lacking studies on in situ physiologies, kinetic rates, and attachment mechanisms governing biogeochemical reactions in the system. The overarching goal of this research was to advance understanding of engineered hydrocarbon extraction systems as they evolve from newly developed environments to mature use. Plasma membranes protect microbial cells, mediate many critical functions, and respond to intracellular cues and ecological perturbations through physicochemical modifications. The project objectives were to 1) characterize variables influencing growth and membrane features of shale taxa, 2) characterize the interactions between shale matrices and microorganisms and 3) elucidate engineered and environmental processes driving biogeochemical signatures at the field scale. Objectives were realized through laboratory experiments involving growth of pure cultures and enrichments in continuous culture and biofilms; access to samples from two DOE-NETL funded energy-capture sites: Marcellus Shale Energy and Environmental Laboratory (MSEEL and MSEEL II); and through collaborations with scientists and engineers at the Environmental Molecular Science Laboratory (EMSL) and National Energy Technology Laboratory (NETL). Key findings showed (a) Halanaerobium congolense WG10 makes its membrane more fluid and thicker through increasing its polyunsaturated fatty acid (PUFA) composition under non-optimal salinities (7% and 20%) compared to the optimum (13% NaCl); (b) anionic phospholipids within the plasma membrane are important for high salinity tolerance in H. congolense WG10 while zwitterionic species modulate biofilm physiologies in both isolate and mixed cultures, and (c) tyrosine accumulation with overexpression of Na+/H+ antiporters are essential for osmoprotection in H. congolense WG10 under high salinity while upregulation of aromatic amino acid synthesis and cell envelope maintenance underpin biofilm formation. It is clear from these results that microbial persistence in fractured shale reservoirs under environmental and engineered perturbations requires strategic plasma membrane lipid chemistry adjustments and metabolic restructuring, with implications for improved shale microbiology management and more efficient hydrocarbon extraction approaches targeting microorganisms.

03 NATURAL GAS↗
DOE OSTI2020

Controls on reservoir properties in organic-matter-rich shales: Insights from MICP analysis

Mercury injection capillary pressure (MICP) analysis was used to study organic-matter-rich Devonian shales varying in maturity from marginally mature to postmature to discuss controls on drainage and imbibition in shale reservoirs. Six samples come from the New Albany Shale; their total organic carbon (TOC) ranged from 3.3–8.4 % and vitrinite reflectance (R o ) from 0.54–1.42 %. One Marcellus Shale sample with R o 2.50 % was used to extend the maturity range to the advanced dry gas window. Three coal samples of varying rank were also included for comparison. Porosity of the shales ranges from 1.5–5.0 %, and MICP-derived permeability ranges from 0.17–9.9 mD. Injection capillary pressure curves have a range of entry pressures from 0.055 to0.421 MPa, and no relationship of entry pressure with maturity was revealed. Maturity, however, has an influence on pore size distribution, with the higher-maturity samples having significantly lower volumes of pores with throats less than 10 nm in diameter. Withdrawal capillary pressure curves document a wide range of withdrawal efficiencies from 55 % to almost 100 %, and pores having throats between 3–50 nm in diameter play a major role in the ability of mercury to be released from the pore system. The obtained data provide valuable information about shale properties and their behavior not only in the air-mercury system but also under reservoir conditions.

02 PETROLEUM↗
DOE OSTI2018

Fracture mechanics of shales under chemically reactive conditions

Fracture growth processes under subsurface conditions are known to be affected by fluid chemical environment. Chemical effects on fracture growth are likely to be relevant during host rock and organic matter diagenesis and catagenesis, hydraulic fracturing, in systems undergoing enhanced oil recovery, in geothermal systems, and in CO 2 sequestration reservoirs. To address the chemical effects on opening-mode fracture growth under a wide range in fluid chemical conditions and for different rock types we conducted double-torsion fracture mechanics tests to determine mode-I fracture toughness (KIC), subcritical index (SCI), and the stress-intensity factor vs fracture velocity (K-V) behavior. We tested sandstones, shales and, altered crystalline rocks. Samples were tested in aqueous conditions with variable salinity, solution pH, and at temperatures of up to 70 °C. Fracture growth in shales is highly sensitive to the environmental conditions, with a reduction of KIC of up to 47% from ambient air to water-saturated conditions. The primary interactions between shales and reactive solutions are clay-water and carbonate dissolution. For clay-rich Woodford and Mancos shales, solutions with higher salinity reduce subcritical fracture growth, while acidic conditions favor fracture growth in carbonate-rich Marcellus shale. Increasing the solution temperature promotes fracture growth. In sandstone, chemical effects on fracture parameters are most pronounced for clay- and carbonate-rich samples. Both KIC and SCI are lower in water than in air for nearly all sandstone lithologies tested. SCI is further reduced in chlorite-cemented Tuscaloosa Sandstone in acidic solutions. Mount Simon Sandstone is also sensitive to pH, most significantly in diagenetically bleached samples. Compositionally mature Aztec Sandstone is affected by water saturation, but shows little sensitivity to chemical environment. Silicified gabbro shows a slight reduction in KIC but a >60% reduction in SCI in aqueous environments compared to ambient conditions. The reduction in SCI is most pronounced in alkaline and saline solutions, suggesting silica dissolution and cation exchange at the fracture tip facilitate subcritical fracture growth. Limited reduction in KIC is attributed to low permeability. Overall, our results demonstrate that fracture properties depend strongly on water saturation, on fluid composition and pH, and on temperature, with an increase in temperature lowering fracture resistance.

58 GEOSCIENCES↗
DOE OSTI2019

Shale-fluid interactions during forced lmbibition and flow-back

One way to minimize the need for disposal of flow-back waters produced during the hydraulic fracturing of unconventional reservoirs is, potentially, to recycle these fluids by recovering and re-injecting them during hydraulic fracturing of nearby new wells. These flow-back waters contain, however, large concentrations of dissolved salts. During hydraulic fracturing of unconventional reservoirs, a well may undergo extended shut-in periods, following the initial hydraulic-fracture stimulation. The concern here, therefore, is that the salts dissolved in the re-injected flow-back waters may precipitate in the subsurface, thus promoting scale formation; or alternately, because of their high salinity, these same fluids may cause the dissolution of various minerals present in the subsurface. Large divalent cations (e.g., Ca²⁺, Ba²⁺ and Sr²⁺) and anions (e.g., CO3²⁻ and SO4²) may chemically interact with and cause the swelling of clay fractions, thus blocking pores in certain pore size ranges. All these phenomena (i.e., scale formation, clay swelling, minerals dissolution) can influence the petrophysical properties of the formation, including its permeability, porosity, contact angle, etc. One way to potentially overcome some of these technical challenges, is to pre-treat these flow-back waters, prior to re-injection (e.g., via chemical precipitation, followed by membrane filtration) in order to remove unwanted salts. However, such pre-treatment is costly, and the degree of salt removal needed to prevent formation damage is important in determining the economic viability of flow-back water recycle via re-injection. A key focus of this work, therefore, is to study the impact that the injection of flow-back waters, that have undergone varying degrees of pre-treatment and clean-up, will have on the flow-through characteristics of a tight-gas reservoir, particularly of the Marcellus Shale formation. To do so, we have carried-out forced-imbibition experiments with shale samples from various depths in the Marcellus formation, whose properties span high to low ranges of TOC, clay content and matrix permeabilities. We have studied the forced-imbibition characteristics, at an injection pressure of 24,233 kPa (3500 psig), of various flow-back fluids into shale cores saturated with methane at a pore pressure of 17,338 kPa (2500 psig) and a confining stress of 27,680 kPa (4000 psig). Following the forced imbibition experiments, we analyzed the cores for potential changes in permeability and porosity. Quantification of the ion content of the injected and recovered fluids was also performed using Ion Chromatography (IC). The IC analysis of the recovered fluids indicates substantial interactions and geochemical reactions between the invading fluids and the shale cores. The injection of flow-back fluids shows significant impact on the flow-through characteristics, with untreated flow-back fluids, which have the highest cation and anion content, also exhibiting the highest observable reductions in permeability (>90%).

defects, mechanical behavior, carbon sequestration↗