Shale Alteration Research Articles

Pore Structure Alteration of Shale with Exposure to Different Fluids: The Longmaxi Formation Shale in the Sichuan Basin, China

The interaction between shale and various fluids is crucial as it modifies pore structures, which govern the effective development of shale gas and the geological storage of carbon dioxide in shale formations. In this study, samples from the Longmaxi Formation shale in Sichuan Basin of China were exposed to different fluids, including 6 MPa CO2, 12 MPa CO2, 6 MPa CO2+brine, and 12 MPa CO2+brine, at 45 °C for 100 days. Various methods, including X-ray diffraction (XRD), X-ray fluorescence (XRF), field-emission scanning electron microscopy (FESEM), and the low-pressure gas adsorption (N2) test, were adopted to evaluate chemical and structural changes during the exposure process. After being treated with supercritical CO2+brine and subcritical CO2+brine, the shale underwent significant changes in its major element composition. The content of Ca, Al, and K in shale saturated with supercritical CO2+brine decreased from 13.00% to 10.34%, from 3.65% to 3.36%, and from 1.56% to 1.37%, respectively. Meanwhile, the content of Si and Na in the same shale increased slightly after saturation. The amount of quartz and dolomite increased, while the levels of clay and calcite slightly decreased. The surface of the shale sample became rougher and small bumps and cracks appeared after saturation with different fluids, as shown by the FESEM analysis results. Furthermore, the changes in both the total pore volume and pore size followed a similar pattern to the alterations in the specific surface areas. The highest level of variation occurred with the shale that was saturated with 12 MPa of CO2, indicating that gas pressure and CO2 phase state have a significant influence on the shale’s pore structure. In addition, the distribution of pore sizes showed a bias towards larger sizes across all diameters; this suggests that the reaction resulted in a decrease in the number of micropores. This also highlights that the impact of varying fluid saturation was primarily focused on micropores and macropores. The results of this study provided experimental evidence to further test the mechanisms and permeability of geological storage of CO2 in organic-rich self-sourced shale.

Experimental investigation and intelligent modeling of pore structure changes in type III kerogen-rich shale artificially matured by hydrous and anhydrous pyrolysis

The occurrence and enrichment of shale plays are highly controlled by pore characteristics of the formation. In this study, an immature sample rich in kerogen type III from the Damoguaihe formation, Hailar Basin in China is subjected to hydrous and anhydrous pyrolysis (HP and AHP) across an extensive temperature range (300–450 °C). Next, low-pressure N2 adsorption analysis was conducted on the pyrolyzate of each maturity stage to study the pore structures’ evolution during thermal maturity simulation. Moreover, deconvolution and fractal dimension analyses were implemented to study pore families and the complexity of pores within the shale samples. Finally, radial basis function (RBF) neural networks optimized by four evolutionary approaches were applied for modeling N2 adsorption data obtained from the HP and AHP samples. According to the results, the original shale sample and all pyrolyzates obtained with HP and AHP scenarios exhibited type IV isotherm with H3 hysteresis loops. As a whole, BET surface area, micro-, meso- and total pore volume of HP pyrolyzates were higher than AHP ones. The unheated shale sample had seven families containing three mesopore and four macropore groups. Although all pyrolyzates obtained from the pyrolysis had families with similar means, their pore volumes were entirely different, which proves that the pore structure of samples undergoes changes during thermal maturation and the presence of water can also enforce these changes. Both fractal dimensions showed a direct relationship with BET surface area and a negative correlation with the average pore diameter of shale samples. The RBF model optimized by differential evolution (DE) delivered a mean absolute percent relative error (MAPRE) value of 4.84% and determination coefficient (R2) of 0.9946 for the total data set, which outperforms other RBF models in predicting N2 adsorption/desorption tests of pyrolyzates. The outcome of sensitivity analysis suggested that the N2 adsorption/desorption behavior of the pyrolyzates was mostly affected by relative pressure and the pyrolysis type (HP or AHP). Ultimately, the results clearly revealed that the effect of water on the pores' alteration of shales with type III kerogen is greater than the effect of temperature or thermal maturity itself.

Effect of supercritical CO2-water-shale interaction on mechanical properties of shale and its implication for carbon sequestration

The mechanical behaviors of shale are important parameters influencing the CO2 storage security in shale reservoirs. Thus, understanding the mechanical properties alteration of shale induced by the injected CO2 is essential for evaluating the stability of shale reservoir rock and caprock. In this study, the impact of supercritical CO2(ScCO2)-water soak pressure and temperature (P = 0, 10, 15, 20 MPa, T = 308, 323, 338, 353 K) on the mechanical properties of shale were investigated. Mineral, pore and mechanical alterations in shale triggered by ScCO2-water soak were obtained by multiple characterization methods. The results indicated that ScCO2-water soak caused the decrease in clay and carbonate mineral contents, and the increase in macropore volume and porosity. Then, the average triaxial compressive strength and elastic modulus of shale decreased from 286.65 MPa to 156.90–247.20 MPa, and 13.62 GPa to 10.52–12.99 GPa, respectively, while Poisson's ratio v in shale increased from 0.1147 to 0.1179–0.1780. ScCO2-water soak induced mechanical weakening in shale is positively correlated with the soak pressure and negatively associated with soak temperature. The dissipated energy ratio decreased first and then increased during the stress loading process in all the tested shales, ScCO2-water soaked shale has a larger proportion of energy dissipation in each stage of stress loading. The results inferred that ScCO2-water soak caused an enhanced plastic deformation behavior in shale. The mechanical degradation in shale may increase the failure risk of reservoir rock or caprock, which should be concerned in CO2 geological storage engineering.

Water wettability alternation of CO2-water-shale system due to nanoparticles: Implications for CO2 geo-storage

The wettability of rocks is closely related to the CO2 geo-storage (CGS) security after CO2 injection into the reservoir. Nanofluids can be used to efficaciously alter the wettability of the CO2-water-rock system toward an advantageous state (water-wet) for CGS. In this study, we investigated the potential of SiO2 and Al2O3 nanofluids at different aging time and concentrations to retain the wettability reversal of CO2-exposed shale from the Sichuan Basin after supercritical carbon dioxide (ScCO2) exposure. Fourier Transform Infrared Spectrometer and field emission scanning electron microscopy tests were performed to evaluate the variations of functional groups and surface topography of shale. Results indicated that both nanoparticles efficiently retain the wettability reversal of shale after a period of ScCO2 treatment, which is conducive to structural trapping in the CGS project. The efficiency was improved by increasing the nanofluid aging time and concentrations, while beyond a certain value, the contact angle value changed trivially. Quasi-homogeneously distributed on the shale surface in ScCO2 may contribute to the wettability alteration of shale in ScCO2, whereas there are still removals of nanoparticles in some sites. The variations of functional groups suggest that the existence of nanoparticles may mildly expedite the CO2 mineralization, signifying the change of wetting behavior of shale in ScCO2 depends on the wettability of nanoparticles, and the nanofluids treatment may exert a positive influence on mineral trapping in the CGS project. The findings in this research provide an important basis for raising the CO2 geological storage security and potential via nanofluids.

Influence of sequential stimulation practices on geochemical alteration of shale

Water-based hydraulic fracturing fluids (HFFs) can chemically interact with formation shale, resulting in altered porosity and permeability of the host rock. Experimental investigations of spatial and temporal shale-HFF interactions are helpful in interpreting chemical compositions of the injectate, as well as predicting alteration of hydraulic properties in the reservoir due to mineral dissolution and precipitation. Most bench-top experiments designed to study shale-HFF chemical interactions, either using batch reactors or flow-through setups, are carried out assuming that the acid spearhead has already become mixed with neutral HFFs. During operations, however, HFFs are typically injected according to a sequenced pumping schedule, starting with a concentrated acid spearhead, followed by multiple additions of near-neutral pH HFFs containing chemical amendments and proppant. In this study, we use geochemical modeling to consider whether this pre-mixed experimental protocol provides results directly comparable to a sequential discrete fluid-shale interaction protocol. Our results show that for the batch system, the transient evolution in major ion concentrations is faster with the sequential procedure. After 2 h of reaction time, the two protocols converge to the same aqueous concentrations. In a flow-through geometry, the pre-mixed model predicts extensive chemical alteration close to the injection point but negligible alteration downstream. In contrast, the sequential model predicts mineral reactions over hundreds of meters along the flow path. The extent of shale alteration in the sequential model at a given location depends on shale mineralogy and where the acid spearhead resides during the shut-in period. The predictive model developed in this study can help experimentalists to design bench-top tests and operators to better translate the results of laboratory experiments into practical applications.

Time-Dependent Measurements of Shale's Compressive Strength When Contacting Ionic Solutions.

Time-dependent measurements of uniaxial compressive strength, and ionic and water transport were conducted to analyze the alteration of shale’s strength, as a function of time, when exposed to aqueous solutions. Results showed that the compressive strength of shale is time-dependent, and it relies highly on water activity and ionic concentration differences between shale and aqueous solutions. Data obtained from this work showed that time-dependent water and ion transport into shale correlated well with compressive strength measurements. It was revealed that initial water extraction by osmosis strengthened shale until ions and their associated water clouds invaded shale causing reduction in its strength. It is quite possible that water flow by diffusion osmosis may have counteracted water flow by chemical osmosis rendering ionic diffusion as the primary regulator on shale strength alteration. Furthermore, it was found that alteration of compressive strength when it interacted with aqueous solutions could be adequately explained within the confines of chemical osmosis, ionic diffusion, and diffusion osmosis. Data suggests that the impact of chemical osmosis on compressive strength is observed earlier than ionic diffusion and diffusion osmosis. Data also showed that potassium ions seem to contribute to the enhancement of the compressive strength of shale.

ON CO2 SEQUESTRATION: CHANGES IN CO2 ENTRY PRESSURE AND ADSORPTION CAPACITY BY HEAT

Geological sequestration of CO2 requires a deep permeable geological formation where captured CO2 can be stored and an overlying impermeable caprock that prevents buoyant CO2 from leaking upward to the surface. Shale formations are good seals due to their abundancy and typically ultralow permeability. Shale's excellent sealing ability makes it a good caprock formation. The correct evaluation of the CO2 sequestration ability of shale caprocks, also referred to as sealing capacity, must be conducted under high-pressure and high-temperature conditions representative of in situ conditions. The CO2 sequestration quality of shale caprocks, sealing capacity, is usually evaluated through measurements of CO2 capillary entry pressure into shale caprocks. In this work, CO2 capillary entry pressure in different shales under a wide range of temperatures (298-428 K) is measured using an incremental pressure transmission methodology. The impact of temperature on the physicochemical and petrophysical properties of shale is addressed, and their indirect effect on CO2 capillary entry pressure is analyzed. Furthermore, the influence of temperature on interfacial tension between CO2 and shale's pore fluid and contact angle is examined. Also, the effect of temperature on CO2 sorption on clay sites is analyzed. The experimental outcome exhibited that capillary entry pressure increases steadily and appreciably for shales (A and B) up to a certain temperature (around 358.15 K), after which the behavior of capillary entry pressure of CO2 for both shales changes markedly. For shale (A), the increase in measured capillary entry pressure for temperatures above 358.15 K slows down significantly, ranging between 841 and 851 psi compared to its measured value of 835 psi at 358.15 K. As for shale (B), the reaction is completely different, where measured capillary entry pressures of CO2 for temperatures above 358.15 K decreased noticeably as measured capillary entry pressures dropped from 534 psi at 358.15 K to 473 psi at 428.15 K. Results show that temperature has a profound impact on CO2 capillary entry pressure when interacting with shales through the alteration of shale's physicochemical and petrophysical properties. Data suggests that pore throat size could be altered by heat through a phenomenon called pore dilation. It was also clearly shown that higher temperature causes higher interfacial tension, which indeed causes higher capillary entry pressures when CO2 interacts with shale. Moreover, results indicate that high temperature could energize active swelling clays and invoke a transition of inactive clays to active swelling clays. High temperature causes clay swelling and may produce hydrational and expansive stresses in shale, especially when confined, which could induce fissures and microfractures. The creation of fissures and microfractures could enhance shale's average pore radii and permeability, thus reducing the capillary entry pressure. In addition, results suggest that the adsorption capacity of CO2 on clay sites decreases with increasing temperature and that the presence of smectite clay greatly enhances the swelling potential of shale upon exposure to CO2.

The impact of supercritical CO2 on the pore structure and storage capacity of shales

Injection of supercritical CO2 (SCCO2) causes significant changes in the petrophysical properties of shales and affects the integrity of geological storage sites. The alteration of mineralogy and pore structure plays a major role in defining the fluid transport in pours media of shale gas during CO2 storage. In this study, a series of SCCO2 treatment experiments were performed on different types of shales to evaluate the alterations of the pore structure and mineralogy. Two types of shales from Eagle Ford and Mancos fields were treated with SCCO2 and analyzed with scanning electron microscope, X-ray diffraction, and low-pressure nitrogen adsorption before and after 30 days at 70 °C and 18 MPa. The experimental results indicated that SCCO2 affected the mineral composition and changed the macropore structure of shales, due to the adsorption-induced expansion effect. The pore structure of clay-rich shales samples was more affected by CO2 treatment compared to quartz-rich shales, due to the dissolution of clay contents in the former, which reduced the overall pore volume by 24% in Eagle Ford shales. Conversely, the development of micro-cracks in Mancos shale surface created new pores and increased the pore volume by more than 13%. The results from nitrogen adsorption isotherms indicated a prominent alteration in the mesopores structure. The specific surface area and total pore volume of Eagle Ford shale reduced by 35.46% and 11.86% respectively after the SCCO2 treatment, while the specific surface area and total pore volume of Mancos shale increased by 27.4% and 25.92% respectively. A positive correlation was reported between the fractal dimension and specific surface area. It appeared that the surface roughness was reduced in Eagle Ford shale and relatively increased in Mancos shales after the treatment. The obtained results suggested that the adsorption capacity of clay-rich shales could be reduced after the CO2 treatment, while quartz-rich shales displayed a uniformed pore size distribution profile, indicating a possible increase in the adsorption capacity. These findings can provide technical support to further understand the effect of CO2 on the pore structure and mineralogical alteration of shale during geological storage.

Surface wettability alteration of shales exposed to CO2: Implication for long-term integrity of geological storage sites

Surface wettability is a key factor controlling the CO2 seal capacity and defines the CO2 storage potential. Limited studies have addressed the shale/water wettability behavior during CO2 injection, thus considerable attention is needed to understand this concept. In this paper, an ample number of supercritical CO2 exposure experiments were conducted to evaluate the alteration of shale/water contact angles. Different types of shales with various mineralogy from Eagle Ford, Wolfcamp, and Mancos fields, were exposed to SCCO2 at different durations, pressures, and temperatures. Shale mineralogy and surface were analyzed using X-ray diffraction and scanning electron microscope. The results indicated a strong relationship between mineral composition and the alteration in shale/water wettability. Clay-rich shales displayed a possible turn in wetting behavior to CO2-wet with extending the SCCO2 treatment time and increasing the treatment pressure, caused by SCCO2 dissolution of clay and carbonate minerals. While the wettability of high-quartz contents shales remained strongly hydrophilic after various SCCO2 treatment conditions. Increasing the temperature accelerated the CO2/shale interactions, and a minor effect was observed on the shale hydrophilicity. Increasing the cohesive energy density of CO2 promotes a favorable CO2 wetting environment, which reduced the hydrophilicity of the surface and reduces the surface energy. In conclusion, shales with high quartz contents exhibit strong water wetting behavior after SCCO2 treatment, which leads to better sealing capacity, more efficient integrity of geological storage sites, and higher potential for CO2 containment.

Microstructure and mechanical properties alterations in shale treated via CO2/CO2-water exposure

CO2 injections into shale reservoirs can enhance the recovery of oil and gas, while simultaneously sequestrating CO2. However, with the injection of CO2, the microstructure and mechanical properties alteration of shales caused by CO2/CO2-water exposure is should be noticed, which is of great importance to predicting the efficiency of CO2-enhanced shale oil/gas recovery and safety of CO2 sequestration in shale reservoirs. Therefore, this study clarifies the influence of sub/super-critical CO2-water exposure on the microstructure and mechanical properties of shale. Results show that after Sub/ScCO2 and Sub/ScCO2 water exposure, the contents of carbonate and clay in shale were decreased. Additionally, the proportion of micropores and mesopores were decreased, while the proportion of macropores was increased, leading to the increase of porosity and the improvement of pore connectivity, and the decreases of the pore surface fractal dimensions D1 and pore volume fractal dimensions D2 in shale. The uniaxial compressive strength (UCS) and elastic modulus (E) of shale were also decreased. Acoustic emission (AE) analysis results indicated that the cracks closure stage and stable crack propagation stage was prolonged and shorten, respectively, and AE signals show obvious multifractal characteristics. ScCO2 induced greater alteration in pore structure and mechanical properties than SubCO2, and the alterations were enhanced for CO2-water exposure. UCS and E of shale samples show a good negative correlation with porosity, and a positive correlation with D1 and D2. UCS in shale is positively related to the proportion of micropores and mesopores, and negatively related to the proportion of macropores, which indicated that microstructure alterations inevitably affected the macroscopic mechanical properties of shale.

Analysis of shale property changes after geochemical interaction under CO2 sequestration conditions

This study implements a supercritical CO2 (scCO2) sequestration environment in a laboratory and investigates the geochemical effects of scCO2 on the properties of rock specimens. Shale specimens constituting caprock were kept in a laboratory reactor chamber with scCO2 for 63 days. Chemical interaction between rock surface and the scCO2 was then induced, and the changes in the properties were inspected before and after the reaction through various tests. The non-destructive tests comprised measurement of elastic wave velocity, shore hardness followed by investigation using the inductively coupled plasma mass spectrometer, and scanning probe microscope. The destructive tests include uniaxial compressive strength, Brazilian tensile strength, and X-ray fluorescence tests. Results show that mechanical properties are significantly weakened when shale specimens are exposed to both scCO2 and brine. The specimens reacting with only scCO2 induced a self-healing effect by precipitation of secondary sediments, becoming a more intact rock with increased strength and elastic modulus. The results denote that the geochemical alteration of shale occurs in a short time and are highly dependent on the reaction conditions. These results provide fundamental information for the stability of CO2 storage sites regarding the physical and chemical reactions between rocks under geological sequestration conditions.

Shale weathering: A lysimeter and modelling study for flow, transport, gas diffusion and reactivity assessment in the critical zone

Shale weathering was characterized and quantified in a lysimeter and modelling study that jointly considered the flow, transport, gas diffusion and reactivity processes induced by exposure to the atmosphere of a recently excavated shale. In this mechanically disaggregated shale presenting preferential pathways for water and a hydraulic conductivity at saturation of 100 cm/day, the water content and the seasonal saturation and desaturation cycles were identified as the main driving mechanisms of shale alteration. The water content determined the diffusion of gaseous oxygen in the shale’s unsaturated porosity, which gave rise to a zonation of the oxidation of pyrite, contained at 1 wt% in the shale. The acidification associated with this oxidation of pyrite was efficiently buffered by calcite but a release of sulphates, cations, iron and trace metals (Pb, Ni, Zn, Co, Cu and As, mainly) was observed. Besides pyrite and calcite dissolution, iron (oxy-)hydroxide formed and proved to be a good phase for sorbing trace metals, whose content remained at low concentrations in the drainage water. Seasonal precipitation of gypsum was also identified, in connection with the summer desaturation of the shale’s shallow layers. The hydraulic, chemical and mineralogical observations made in the lysimeters were reproduced using HP1, a reactive transport code, under unsaturated conditions. It was possible to account for the gas diffusion where O2 availability controlled the reactivity with the shale, depending on the meteorological conditions and the drainage at the base of the lysimeter.

Hydrocarbon Potential of the Disang Group of Rocks of the Inner Paleogene Fold Belt of Assam-Arakan Basin Exposed along the Dimapur-Senapati Road Section of Nagaland and Manipur, India

Carbonaceous shales of the Upper Disang Formation of the Inner Paleogene Fold Belt of Assam-Arakan Basin, exposed along the Dimapur-Senapati road section of Nagaland and Manipur states of India have been studied for interpreting hydrocarbon potential. The Upper Disang Formation is mostly composed of alteration of shales, sandstones and siltstones. The shales are black coloured and splintery in nature. The shales and associated sandstones show sedimentary structures like bioturbation, cross bedding and ripple marks indicating shallow water origin. The shales contain appreciable amount of pyrites indicating marine influence in the depositional basin. The average TOC of the carbonaceous shale samples is 0.53% indicating poor generative potential. The poor generative potential of the formation is also supported by low S1 (average 0.04 mg/gTOC), S2 (average 0.16 mg/gTOC) and HI (average 36 mg/gTOC). The organic matters are represented dominantly by Type IV kerogens (inertinite) with subordinate amount of Type III kerogens (vitrinite) as shown by both Rock Eval parameters and organic petrography. The dispersed organic matters (DOM) are identified as semifusinite and collotelinite under the microscope. The organic matters are interpreted to be inert/post mature kerogens from the maturity parameters like Rock Eval Tmax (average 563°C), and mean vitrinite reflectance (average 2.0% in oil). The study indicates very poor hydrocarbon potential of the Upper Disang Formation of the Dimapur-Senapati road section.

Multi-fractal analysis for the AE energy dissipation of CO2 and CO2+ brine/water treated low-clay shales under uniaxial compressive tests

Carbon dioxide (CO2) is a promising fluid which can be used for shale gas recovery. In this study, uniaxial compressive strength tests were performed on low-clay shale samples soaked in sub-/or super- critical CO2 and its dissolved water/brine solutions for 10, 20 and 30 days. The deformation and crack evolution during the experiments were analyzed by the multi-fractal method based on the acoustic emission (AE) signals. The results show that the value of Δα (the width of the spectrum) increases with increasing soaking time, which is related to the alteration of shale’s internal structure during imbibition. Sub-or super- critical CO2+ water/brine solutions significantly decrease the strength and change the brittleness of shales, which decrease the frequencies of large and small AE signals and present low values of Δf (the relationship between small and large signal frequencies). The morphology analysis shows that samples with imbibition produce more large-scale cracks during the compression tests and tend to have right skewed distributions. From the crack closure stage to the stable/unstable crack propagation stage, the average value of Δα for soaked samples decreases, which means the structure of the AE signals becomes simpler. Super-critical conditions, which decreases the complexity of shale deformation and weakens the role of small/high signals in the AE energy release, yield a lower value of Δα than the corresponding sub-critical conditions. This study helps to understand the effect of CO2 and its saturated fluids on shales and the mechanism of cracks propagation during CO2 enhanced shale gas recovery and CO2 sequestration in shale reservoirs.

Shale-brine-CO2 interactions and the long-term stability of carbonate-rich shale caprock

The success of geological carbon storage (GCS) depends on the sealing properties of caprocks, typically mudrocks, and their laminated variety – shales. In this study, we examined mineralogical changes in carbonate-rich Mancos Shale and corresponding changes in micro-mechanical properties following the reaction with carbon dioxide (CO2). Mineralogical changes of Mancos Shale depended on the pressure of CO2 during its exposure to the CO2-brine mixtures for up to 8 weeks. Dedolomitization was observed in the reactors pressurized with 100 psi of CO2, combined with the precipitation of gypsum. In the reactor pressurized with 2500 psi of CO2, the complete dissolution of calcite, partial dissolution of dolomite, and precipitation of magnesite and anhydrite were observed. Localized mechanical weakening was observed only for dolomite-muscovite-illite-rich laminae following whole shale puck alteration at 2500 psi of CO2, and a decrease of up to 50 ± 20% in scratch toughness was observed. The quartz-calcite-rich laminae did not exhibit a measurable difference in scratch toughness before and after reaction in CO2-rich brine. The predicted changes in mineralogy, porosity, density, and hardness of Mancos Shale are limited, according to the geochemical models describing alteration of shale by CO2-rich brine lasting for 5000 years. This study illustrates a coupled and localized chemical-mechanical response of caprock to the injection of CO2.

Shale alteration after exposure to supercritical CO2

Caprock seal efficiency evaluation is a vital part of the assessment of any CO2 storage site. The main goal of this study was to examine the dynamic seal capacity of several intra-formational shale units in the Latrobe Group in the Gippsland Basin, Australia and to characterise their caprock sealing efficiency before and after exposure to supercritical CO2 (scCO2).This laboratory study examined changes to the mineralogical composition of the shale, capillary threshold pressure, and pore size distribution before and after being exposed to scCO2 at reservoir conditions utilizing several analytical methods. Samples selected for this study were taken from cores that have been stored in a sample facility. Since the original mineralogy of the samples is likely to have changed over time at surface storage conditions, thus chemical reactions may be different if fresh samples could have been analysed.X-ray diffraction (XRD) and scanning electron microscopy (SEM) indicate that there are several chemical reactions that occurred between rock-forming minerals and the brine-scCO2 system. Chemical reactions include dissolution and precipitation of several authigenic minerals such as kaolinite, natrojarosite, silica and gypsum.Mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) measurements indicate a reduction in the capillary threshold pressures and an increase in pore volume for most of the samples exposed to scCO2.

Content and mode of occurrences of rare earth elements in the Zagrad karstic bauxite deposit (Nikšić area, Montenegro)

Three vertical sections through the Zagrad deposit of Jurassic karst bauxite in central Montenegro have provided knowledge of the vertical distribution of major and some selected trace elements, including rare earth elements (REE). Variations in the mineralogy, particularly those hosting REE, have been studied. This has revealed the presence of authigenic mineral phases such as xenotime, mottramite and monazite (best proved using Raman microprobe analysis) as well as residual phases such as zircon, titanite and monazite. The mobility of the elements during bauxitization processes has been studied to show that the REE minerals ensure progressive concentration of these elements during removal of major elements through weathering. The similarity of normalized REE in the bauxite to the typical Post-Archean Australian Shales (PAAS) and Upper Continental Crust (UCC) profile, and the preserved Eu anomaly, are evidence that the bauxite was not derived from carbonates and represents alteration of shale, marly limestone and volcanogenic or proximal igneous sourced detritus that accumulated in the original karst landform. Mass change during bauxitization, using Ti as “index” element and compared to PAAS composition, revealed almost 100% depletion of Si and weak enrichment in Al. Deeper parts of the deposit with authigenic minerals exhibit very strong enrichment in all REE. The bauxite ores have high ΣREE contents (693.5–6953.4ppm), especially ΣLREE contents (582.8–4882.9ppm), while ΣHREE contents (106.6–2070.5ppm) are much lower.

The CO2 consumption potential during gray shale weathering: Insights from the evolution of carbon isotopes in the Susquehanna Shale Hills critical zone observatory

Shale covers about 25% of the land surface, and is therefore an important rock type that consumes CO2 during weathering. We evaluated the potential of gray shale to take up CO2 from the atmosphere by investigating the evolution of dissolved inorganic carbon (DIC) concentrations and its carbon isotopic ratio (δ13CDIC) along water flow paths in a well-characterized critical zone observatory (Susquehanna Shale Hills catchment). In this catchment, chemical weathering in shallow soils is dominated by clay transformation as no carbonates are present, and soil pore waters are characterized by low DIC and pH. In shallow soil porewaters, the DIC, dominated by dissolved CO2, is in chemical and isotopic equilibrium with CO2 in the soil atmosphere where pCO2 varies seasonally to as high as 40 times that of the atmosphere. The degradation of ancient organic matter is negligible in contributing to soil CO2. The chemistry of groundwater varies along different flowpaths as soil pore water recharges to the water table and then dissolves ankerite or secondary calcite under the valley floor. Weathering of carbonate leads to much higher concentrations of DIC (∼2500μmol/L) and divalent cations (Ca2+ and Mg2+) in groundwaters than soil waters. The depth to the ankerite weathering front is hypothesized to be roughly coincident with the water table but it varies due to heterogeneities in the protolith composition. Groundwater chemistry therefore shows different saturation indices with respect to ankerite depending upon location along the valley. The δ13CDIC values of these groundwaters document mixing between the ankerite and soil CO2. The major element concentrations, DIC, and δ13CDIC in the first-order stream incising the valley of the catchment are derived from groundwater and soil waters in proportions that vary both spatially and temporally. The CO2 degassed slightly in the stream but little evidence of C isotopic equilibration with the atmosphere is observed, due to the short length of the stream and short contact time with air.The ankerite reaction front also lies close to the pyrite dissolution front. Pyrite oxidation in bedrock likely released sulfuric acid and played a minor role in the ankerite dissolution, shifting groundwater δ13CDIC slightly above the expected mixing values. At the catchment scale, the stream SO42− is also dominantly derived from wet deposition, as stream has δ34SSO4 values around 3‰, well within the range of acid deposition.A mass balance calculation shows that silicate and ankerite dissolution of the Rose Hill shale at Shale Hills consumes CO2 at a rate of ∼44 and ∼42–48molm−2ky−1 respectively, while degradation of ancient organic matter releases CO2 at a rate of ∼1.3molm−2ky−1. Silicate dissolution at the shallow soils is facilitated by low pH and high soil pCO2. As ankerite dissolution and organic matter oxidation are shown to occur early during shale alteration, CO2 consumption by shale weathering is thus limited by initiation of rock disintegration (e.g., fractures) and exposure of fresh surface area to infiltrating CO2- and O2-rich water.

The Effect of Water Activity in Shale on Wellbore Instability

It is accepted that the water flux in/out of the shale during drilling is the key factor, which controls wellbore instability. This flow can be divided into two components:1) the hydraulic flow due to the difference between the wellbore and pore hydraulic pressure; 2) the osmotic flow due to the imbalance between activities of the shale and the drilling fluid. The former can be prevented by adjusting the wellbore hydraulic pressure balance in the well hole, while the latter is much more difficult to control . The water activity of shale is a controlling factor in many areas of drilling. It impacts all situations wherein the temperature or the stress state of a shale is altered such as in wellbore stability, drilling rate and hydraulic fracturing. This chemical “potential activity interaction” produces a mechanical failure due to the movement of water in/out of shales. In order to have no shale alteration, it requires that the chemical potential of each component must be the same in all phases. This is seldom the case. After a lot of studies the shale activity is shown to be a function of pressure and temperature. Results showed inverse relationship between the platelet distance and the shale water activity. This experimental method proves to be a reliable and efficient way for studying the relationships for the shale water activity, comfining pressure, temperature, and platelet distance.

Geological discontinuities, main flow path and chemical alteration in a marly hill prone to slope instability: Assessment from petrophysical measurements and borehole image analysis

AbstractClay shale landscapes are sensitive to landslide, erosion, and re‐sedimentation processes. In this context, tectonized clay shales have peculiar hydrological and mechanical behaviours. In order to improve our understanding of the processes involved in such systems, an experimental site has been settled in the Draix Observatory (ORE DRAIX) on a black marl hill slope of the Southern Alps (France) in the framework of the ECOU‐PREF project. The site is a natural laboratory to study the evolution of clay shale landscapes at several scales (regional to µm). In this study, we aim to characterize the internal structure and fissure patterns of a stable interfluve, in order to locate preferential water flows within the system, and anticipate its evolution. This work is based on a series of mutli‐disciplinary approaches including petrophysical analyses, well pulse injection tests and downhole geophysical measurements. Borehole geophysical results were combined with laboratory measurements on core plugs (permeability, density, porosity, and acoustic velocity). Optical and acoustical images have been used as an original tool for internal discontinuities characterisation and potential active flow path detection. They allowed the identification of three main lithological units interpreted as several stages of shale alteration. In addition, several main structural plane discontinuities (open fractures, schistosity planes, and fractures infilled with calcite or clays) were identified from the images and their potential transmissivity discussed with regard to piezometric and tracer measurements. In all, the integration of measurements leads to propose a simple scenario of fluid circulation and chemical alteration of the interfluve. Copyright © 2011 John Wiley & Sons, Ltd.