Carbonate Mineral Content Research Articles

Experimental Investigation of the Influence of Composition Changes in Shale on Pore Structure and Fractal Characteristics under Different HCl Concentrations.

Acidification is a promising stimulation technique for improving the pore structure of low-permeability shale reservoirs and enhancing shale gas production. Variations in the mineral composition and acid concentration play a significant role in altering the pore systems in shale reservoirs, thereby affecting shale gas transport and production. To investigate the effect of shale composition on pore structure and fractal characteristics under hydrochloric acid (HCl) treatment, experiments were carried out on carbonate-rich (68%), carbonate-medium (45%), and carbonate-poor (2%) shales with different concentrations of HCl solution (1, 5, 10 wt %). X-ray diffraction (XRD), low-temperature nitrogen adsorption, and fractal theory were performed to investigate variations in mineral composition, pore structure, and fractal characteristics of the unreacted and reacted shales. The results illustrated that the HCl treatment significantly reduced the content of carbonate minerals, and the dissolution degree of carbonate minerals increased with the increase in HCl concentration. More meso- and macropores were generated for carbonate-rich and carbonate-medium shale, while more micro- and mesopores were generated in carbonate-poor shale, which led to the increase in total pore volume (TPV) and total specific surface area (TSSA) at different degrees. Moreover, the pore surface roughness (D 1) and structure complexity (D 2) were reduced with the increase of HCl concentration for carbonate-rich shale, while the alteration of D 1 and D 2 showed an opposite trend for carbonate-poor shale. Additionally, D 1 decreased and D 2 increased for carbonate-medium shale. Relevant results could provide theoretical references for the acid fracturing of shale reservoirs with varying mineral compositions.

Multi-Parameter Experimental Investigation on the Characteristics of Acidizing Effectiveness in High-Temperature Carbonate Formation

Carbonate formation is the key reservoir in Sichuan Basin for natural gas development. Compared with the early stage of development, the burial depth of targeted formation becomes deeper, and the formation temperature gets higher. So, the characteristics of acidizing effectiveness in high-temperature carbonate formations make this evaluation slightly difficult. Currently, it is common that a single parameter is considered to study acidizing effectiveness by simulation and experiment methods. In this paper, for a more accurate investigation of acidizing effectiveness, multiple parameters, including permeability change rate, fracture conductivity, and surface roughness, were introduced by a series of experiments. It is revealed that the permeability change rate is more than 57% when using gelled acid. As the amount of diverting agent increases in diverting acid, the viscosity of the acid grows to its peak with the reaction, making it easier to block the high permeability core temporarily and divert to acidify the low permeability core, where the permeability change rate of the low permeability core goes from 51.6% to 64.2%, which shows well acidizing effectiveness. In addition, the short-term and long-term conductivity of the samples from the three different formations are more than 200 mD∙m under high closure stress. The conductivity of Maokou Formation is the largest due to its high content of carbonate minerals and high dissolution rate. And the results of long-term conductivity are consistent with those of surface roughness, making the evaluation results more reliable for acidizing effectiveness. It is worth noting that temperature is a factor that cannot be ignored in the evaluation of acidizing effectiveness because it has a great influence on the performance of the acid system, such as viscosity and the reaction-reduced rate, leading to an acidizing effectiveness affect. So, the temperature resistance of an acid system is important as well.

Effects of the Sedimentary Environment on Organic-Rich Shale in the Intracratonic Sag of the Sichuan Basin, China

The enrichment of organic matter in high-quality marine shale is generally controlled by factors such as the redox conditions of sedimentary environments, productivity levels, terrigenous input, and ancient productivity. However, the controlling effect of the sedimentary environment on organic matter enrichment in intracratonic sag is still unclear. This study takes samples from the Qiongzhusi formation shale in southern Sichuan Basin as the research object, focusing on trace elements as well as rare earth elements in different stratigraphic intervals. The provenance of the Qiongzhusi formation shale is mainly terrigenous, with sediment sources mainly consisting of sedimentary rocks and granites. The primary sedimentary environment transitions from a continental margin setting, influenced by rift-related tectonic activity and sediment influx from adjacent landmasses, to an open oceanic environment characterized by mid-ocean ridge processes and oceanic plate subduction zones. During sedimentation, saline water was present, with predominant sedimentary environments ranging from shallow water to deep water continental shelves. The shale in the study area is characterized by a higher content of silicates and a lower content of carbonate minerals. Its siliceous sources are mainly influenced by biogenic and terrigenous debris, indicating higher ancient primary productivity and representing a favorable target for shale gas exploration.

Trace element geochemistry of carbonatites and associated alkaline rocks of Mundwara Igneous complex, Sirohi district, Rajasthan, India

Carbonatites are widely recognized for their potential to host significant deposits of rare earth elements (REEs) and other rare metals. These igneous rocks, characterized by their high carbonate mineral content, are often rich in REEs, niobium, tantalum, and other valuable elements. This makes carbonatites key targets for mining and exploration. Carbonatites are believed to form from either primary carbonate magma derived directly from the mantle or from secondary melts. These secondary melts can originate from carbonated silicate magmas through liquid immiscibility or from the residual melts resulting from the fractional crystallization of silicate magmas. The coexistence of carbonatites and alkaline silicate rocks in most complexes, their coeval emplacement in many, and overlapping initial 87Sr/86Sr ratios supports the theory of their cogenesis. In this study, we aim to investigate the trace element geochemistry of carbonatites and coeval alkaline silicate rocks from the Mundwara Igneous Complex, Sirohi district, Rajasthan in India. Our trace element data indicate that the carbonatites and alkaline silicate rocks in this complex are products of fractional crystallization from two separate parental melts, formed through liquid immiscibility of a carbonated alkaline silicate magma.

Reservoir Characteristics of Marine–Continental Transitional Taiyuan Formation Shale and Its Influence on Methane Adsorption Capacity: A Case Study in Southern North China Basin

To further study the reservoir characteristics and adsorption capacity of the Taiyuan Formation shale in the South North China Basin (SNCB), the pore structure and adsorption capacity of shale are discussed using various analysis tests, including elemental geochemistry, organic geochemistry, mineral composition, low-temperature nitrogen adsorption (LTNA), and methane adsorption experiments. The results indicate that the Taiyuan Formation shale formed in a poor oxygen and anaerobic sedimentary environment in still water. The average value of total organic carbon (TOC) content is 2.37%. The organic matter type mainly consists of type III kerogen. The vitinite reflectance (Ro) ranges from 3.11% to 3.50%. The clay mineral content varies greatly, averaging at 40.7%, while the quartz content averages at 37.7%. The Taiyuan Formation shale mainly develops interparticle (InterP) pores, followed by organic pores, intraparticle (IntraP) pores, solution pores, and microfractures. BET specific surface area (SSA) is between 9.47 m2/g and 22.14 m2/g, while pore volume (PV) ranges from 0.0098 cm3/g to 0.022 cm3/g, indicating favorable conditions for shale gas storage. According to the results of the CH4 adsorption experiment, Langmuir volume from Taiyuan Formation shales exhibits 1.35~4.30 cm3/g, indicating excellent adsorption capacity. TOC content shows a positive correlation with both Langmuir volume and BET SSA from Taiyuan Formation shales, suggesting that TOC plays a crucial role in controlling microscopic pores and gas adsorption capacity. Organic matter enhances the shale adsorption capacity by providing abundant pore SSA. Due to formation compaction, the pore size of clay minerals decreases, leading to an increase in pore SSA, while kaolinite exhibits weak hydrophilic ability. Consequently, with the increase in clay minerals and kaolinite content, the shale adsorption capacity is enhanced to a certain extent. However, an increase in the carbonate mineral content may result in a decrease in the proportion of clay minerals, therefore reducing the CH4 adsorption capacity of shale.

Paleogene-Neogene ring-shaped sedimentary system and reservoir characteristics in the Western depression of the Qaidam Basin

The Paleogene-Neogene strata in the Western Depression of the Qaidam Basin represent a primary focus for oil and gas exploration and development. Influenced by both terrigenous clastic influx and endogenic carbonate deposition, these strata exhibit significant variation in sedimentary systems and reservoir characteristics. This study comprehensively examines the depositional patterns and reservoir properties of the Paleogene-Neogene sequence across the inner, middle, and outer belts of the basin, employing core analysis, thin section petrography, and physical property assessment of reservoirs. Key findings include 1) The development of a concentric sedimentary system in the Western Depression during the Paleogene-Neogene period, characterized by increased carbonate mineral content and decreased clastic material from the periphery to the center of the basin. 2) Varied sedimentary facies associations across different zones, with the outer belt dominated by fan delta and braided river delta deposits, and the middle and inner belts characterized by near-shore shallow lacustrine carbonates and algal mat deposits, and offshore semi-to deep-lacustrine fine sediments, respectively. 3) The outer belt exhibits reservoirs with favorable physical properties and connectivity, while the inner and middle belts show high heterogeneity, indicating potential for lithological traps and shale oil exploration. These insights offer scientific guidance for further investigation into the depositional systems of lacustrine basins in the Western Depression of the Qaidam Basin and for identifying promising reservoirs.

Evaluation of SC-CO2–brine on the micro-mechanical properties of lamina shales by micro-scratch test

The mechanism of SC-CO2–brine–rock interaction (SCBRI) and its effect on the mechanical properties of shale are crucial for shale oil development and CO2 sequestration. To clarify the influence of SCBRI on the micromechanics of shale, the lamina and matrix of shale were saturated with SC-CO2–brine for 2, 4, 6, and 8 days, respectively. The micro-scratch technique was then used to measure the localized fracture toughness before and after SC-CO2–brine saturation. Combining the micro-scratch results with SEM-QEMSCAN-EDS analysis, the differences in mineral composition and mechanical properties of lamina (primarily composed of carbonate minerals) and matrix (primarily composed of clay minerals) were studied. The QEMSCAN analysis and micro-scratch results indicate distinct mineralogical compositions and mechanical properties between the lamina and the matrix. The results showed that: (1) SCBRI leads to the decrease in carbonate mineral content and the significant increase in matrix porosity and laminar cracks. In addition, the damage degree increased at saturation for 6 days. (2) SCBRI weakens the mechanical properties of shale. The scratch depth of laminar and matrix increased by 34.38% and 1.02%, and the fracture toughness decreased by 34.38% and 13.11%. It showed a trend of first increasing and then decreasing. (3) SCBRI enhances the plastic deformation behavior of shale, and the plastic index of lamina and matrix increases by 18.75% and 21.58%, respectively. These results are of great significance for evaluating the mechanical properties of shale oil and gas extraction by CO2.

Effect of Paleoenvironmental Conditions on the Distribution of Lower Carboniferous Shale in Yaziluo Rift Trough, South China: Insights from Major/Trace Elements and Shale Composition

Paleoenvironmental conditions significantly influence the distribution patterns and organic matter enrichment of shale. This study investigated the vertical variations of major elements, trace elements, and total organic carbon (TOC) in the Lower Carboniferous marine shale from the Yaziluo Rift Trough, South China, to understand the paleoenvironmental conditions, including redox conditions, terrigenous detrital input, paleoproductivity, and paleo-seawater depth. The Lower Carboniferous formation consists of three sedimentary facies: basin facies, lower slope facies, and upper slope facies. From the basin to the lower slope and then to the upper slope facies, TOC, quartz, and pyrite contents gradually decrease, whereas the carbonate mineral content shows an increasing trend. A continuous decline in paleo-seawater depth transformed a deep-water anoxic environment with high paleoproductivity and low detrital input in the basin facies into a semi-deep-water environment with dysoxic-oxic conditions and moderate detrital influx in the lower slope facies, evolving further into a suboxic environment with high detrital flux in the upper slope facies. The geochemistry results suggest that anoxic conditions and high paleoproductivity were the primary controls on organic matter enrichment in the siliceous shale of the basin facies. In contrast, redox conditions significantly influenced organic matter accumulation in the mixed shale of the lower slope facies, attributed to relatively low paleoproductivity in a more restricted marine setting. Additionally, the adsorption of carbon components by clay minerals facilitated the preservation of organic matter in the calcareous shale of the upper slope facies.

Microstructural alterations of coal induced by interaction with sequestered supercritical carbon dioxide

A total of four samples with different coal ranks were exposed to supercritical CO2 (SC–CO2) fluids for one week at 313.15 K and 12 MPa. FTIR and X-ray diffraction were combined to explore the changes in functional groups, mineral compositions and aromatic microcrystallite structures of coal samples before and after SC-CO2 interaction. The results indicate that a great number of aliphatic hydrocarbons in coal are extracted and the content is reduced by 47.83–83.08 %, whereas the oxygen-containing groups are slightly changed within 8 %. The content of carbonate minerals is decreased by 29.05–46.11 % after SC-CO2 saturation, while quartz content is enhanced. The changes in coal crystalline structures are attributed to the mineral dissolution and hydrocarbon extraction during SC-CO2 saturation. Numerous voids are generated among aromatic layers after mineral dissolution, which directly enlarges the layer spacing of aromatic sheets. The extraction of aliphatic hydrocarbons can not only further increase layer spacing, but also loosen the coal macromolecular structure. Consequently, the directional alignment of aromatic microcrystallites is reduced within coal, leading to the decline of stacking height and aromatic layers. These findings are of significance for assessing both the recovery of CO2-enhanced coalbed methane and the trapping of CO2 in coal reservoirs.

Indicative significance of the interfacial interactions between pore surface and soluble organic matter on the shale oil mobility

The exploration and exploitation of shale oil resources enhance the necessity to characterize the mobility of the occluded oil in shales. Up to now, the understanding of the controlling factors of shale oil mobility has mainly come from molecular dynamics simulation but lacking in-depth research on actual shales. Therefore, in this study, the effects of mineral composition, soluble organic matter (SOM) composition and wettability on the shale oil mobility were studied by X-ray diffraction, N2 adsorption, mercury intrusion, contact angle, chloroform bitumen and group component detection methods, comprehensively. The results show that: (1) The asphaltene contents and (Asphaltenes × Aromatics)/(Saturates × Resins) negatively and positively correlate with clay and carbonate mineral contents, respectively, while the I/S and illite contents present opposite trend with (Asphaltenes × Aromatics)/(Saturates × Resins). These correlations indicate that the SOM that confined in the pores constructed with carbonate minerals and illite present better flow potential. (2) Both δVt and δSSA negatively correlate with asphaltenes and (Asphaltenes × Aromatics)/(Saturates × Resins). That is, less pores and surfaces can be released by extraction for the shales with more asphaltenes. Therefore, it can be concluded that asphaltene is a negative factor for shale oil seepage. Additionally, the larger pores present better flow condition for shale oil, even for asphaltenes. (3) Pore surface wettability also significantly affects the shale oil mobility. The hydrophobicity of the pore wall greatly inhibits the shale oil flow, especially for the mesopores and macropores. The pattern diagram was established to illustrate the effect of the interactions between pore surfaces and shale oil components on the movable potential. Based on our research, mineral composition, group composition and pore surface wettability are efficient parameters for the shale oil mobility evaluation based on the interfacial interaction theory, and the “sweet spots” for shale oil seepage of the Jiyang Depression are the shales with more illite, carbonate, saturates and relatively low lipophilicity.

Characteristics of rock fissure fillings and their relationship with the accumulation of uranium and associated elements in the Kailu Sag of the southern Songliao Basin, Northeast China

The relationship between deep fluids and the enrichment of uranium and associated elements in sedimentary basins remains unclear. Sandstone-type uranium deposits in the southern Songliao Basin exhibit abundant fault systems, and evidence of hot fluid activity is present in the ore-bearing strata, including the presence of hydrothermal minerals such as galena and sphalerite. To elucidate this relationship, we conducted detailed thin-section observations and micro-X-ray fluorescence spectroscopic analysis on the fissure fillings of mafic rocks, granite, sandstone, and mudstone in or near the ore-bearing strata. Our findings indicate that rock fissures are filled with minerals such as pyrite, quartz, ankerite, and calcite, suggesting that deep fluids have multiple sources and stages. Specifically, ankerite, rich in Fe and Mn, is closely associated with uranium mineralization, and is observed in both the fissure fillings and the ore-bearing strata. Fluids enriched in elements such as Tb and Dy likely originate from or are related to the mantle, while fluids with few other components may come from deep strata. However, U and Re contents are low in the fissure fillings, being insufficient for their mineralization. Furthermore, given the high content of carbonate minerals in the ore-bearing strata and their close association with uranium mineralization, we analyzed fluid inclusions and carbon–oxygen isotope composition of the carbonate minerals present in the rock fissures. Fluid inclusions in carbonate minerals indicate moderate to low temperatures (ranging from 145.5 to 298.5 ℃, with an average of 215.3 ℃) and low salinities (ranging from 0.18 to 7.99 wt%, with an average of 2.22 wt%). δ13CV-PDB values of carbonate minerals ranges from − 15.1 ‰ to 0.4 ‰, and δ18OV-SMOW values range from 0.5 ‰ to 14.4 ‰, suggesting a composite genesis of carbonate fluids involving magma and atmospheric precipitation. These test results on fissure fillings match roughly with those of the ore-bearing strata, indicating that deep fluids have infiltrated into the ore-bearing strata and contributed to uranium mineralization. Therefore, we propose that the U and Re enrichment in the ore-bearing strata originates from supergene fluids, whereas deep fluids may provide ore-forming materials such as ankerite, reducing fluids, and heat sources for uranium mineralization.

Influence of Rock Fabric on Physical Properties of Shale Oil Reservoir Under Effective Pressure Conditions

Abstract The physical properties of shale oil reservoirs under overburden pressure are of great significance for reservoir prediction and evaluation during exploration and development. Based on core, thin section, and SEM observations, as well as test data such as XRD, TOC, and porosity and permeability under pressure conditions, this study systematically analyzes the variation of physical properties of different lithofacies shales in the Jiyang depression and the influence of rock fabric on the physical variation under pressure. The porosity and permeability of shale samples significantly decrease under pressure. According to the phased reduction in porosity and permeability, the pressurization process is divided into three pressure stages: low pressure (<8 MPa), medium pressure (8–15 MPa), and high pressure (>15 MPa). The reduction of porosity is fastest in the low-pressure stage and slowest in the medium-pressure stage. The reduction of permeability is fastest in the low-pressure stage and the slowest in the high-pressure stage. The rock fabric has a significant impact on porosity and permeability under pressure conditions. The permeability of laminated shale and bedded shale is higher than that of massive shale under pressure, and the permeability loss rate is lower than that of massive shales. Especially under lower pressure, the difference can be 10–20 times. In addition, the reduction rate of porosity and permeability under pressure is negatively correlated with felsic minerals content, which is positively correlated with carbonate minerals content and clay minerals content. The contribution of clay minerals to the porosity reduction rate is dominant, followed by carbonate minerals. The contribution of carbonate minerals to the permeability reduction rate is dominant, followed by clay minerals. The TOC content has no significant impact on the porosity and permeability of shales under pressure in the study due to the low maturity.

In-situ laboratory study on influencing factors of pre-SC-CO2 hybrid fracturing effect in shale oil reservoirs

Supercritical CO2 (SC-CO2) fracturing, being a waterless fracturing technology, has garnered increasing attention in the shale oil reservoir exploitation industry. Recently, a novel pre-SC-CO2 hybrid fracturing method has been proposed, which combines the advantages of SC-CO2 fracturing and hydraulic fracturing. However, the specific impacts of different pre–SC-CO2 injection conditions on the physical parameters, mechanical properties, and crack propagation behavior of shale reservoirs remain unclear. In this study, we utilize a newly developed “pre-SC-CO2 injection → water-based fracturing” integrated experimental device. Through experimentation under in-situ conditions, the impact of pre-SC-CO2 injection displacement and volume on the shale mineral composition, mechanical parameters, and fracture propagation behavior are investigated. The findings of the study demonstrate that the pre-injection SC-CO2 leads to a reduction in clay and carbonate mineral content, while increasing the quartz content. The correlation between quartz content and SC-CO2 injection volume is positive, while a negative correlation is observed with injection displacement. The elastic modulus and compressive strength exhibit a declining trend, while Poisson's ratio shows an increasing trend. The weakening of shale mechanics caused by pre-injection of SC-CO2 is positively correlated with the injection displacement and volume. Additionally, pre-injection of SC-CO2 enhances the plastic deformation behavior of shale, and its breakdown pressure is 16.6% lower than that of hydraulic fracturing. The breakdown pressure demonstrates a non-linear downward trend with the gradual increase of pre-SC-CO2 injection parameters. Unlike hydraulic fracturing, which typically generates primary fractures along the direction of the maximum principal stress, pre-SC-CO2 hybrid fracturing leads to a more complex fracture network. With increasing pre-SC-CO2 injection displacement, intersecting double Y-shaped complex fractures are formed along the vertical axis. On the other hand, increasing the injection rate generates secondary fractures along the direction of non-principal stress. The insights gained from this study are valuable for guiding the design of preSC-CO2 hybrid fracturing in shale oil reservoirs.

A new type of shale gas reservoir—carbonate-rich shale: From laboratory mechanical characterization to field stimulation strategy

Recently, a new promising type of marine shale gas reservoir, carbonate-rich shale, has been discovered. But the mechanical properties of this type of shale were still unrevealed and the corresponding reservoir stimulation design was lack of guidance. Using the deep downhole cores of an exploratory carbonate-rich shale gas well, the physical and mechanical parameters and failure mechanism of the whole reservoir section were acquired and evaluated systematically, by performing XRD, tri-axial compression, Brazilian splitting, and fracture toughness tests. A new model was established to evaluate the reservoir brittleness based on fracture morphology and stress-strain curve. Recommended strategy for reservoir stimulation was discussed. Results showed that (1) Carbonate-rich shale possessed high compressive strength and high Young's modulus, which were improved by 10.74% and 3.37% compared to that of siliceous shale. It featured high tensile strength and fracture toughness, with insignificant anisotropy. (2) With the content of carbonate minerals increasing, the shear failure morphology transformed from sparse and wide brittle fractures to diffusely distributed and subtle plastic cracks. (3) The brittleness index order was: siliceous shale, clay-rich shale, carbonate-rich shale, and limestone. (4) The special properties of carbonate-rich shale were rooted in the inherent feature of carbonate minerals (high strength, high elastic modulus, and cleavage structure), resulting in greater challenge in reservoirs stimulation. The above findings would promote the understanding of carbonate-rich shale reservoirs and provide reference for the optimum design of reservoir stimulation.

Evolution of shale wetting properties under long-term CO2/brine/shale interaction: Implications for CO2 storage in shale reservoirs

In the case of Carbon Geological Storage (CGS), the wettability is one of the main parameters controlling the CO2 injection capacity and CO2 plume movement, which affects the safety of long-term CO2 storage. A full evaluation of this parameter is essential for risk evaluation and storage capacity estimation. The objective of this study was to investigate the wettability changes of shales from the Chang 7 Formation in the Ordos Basin by exposing the samples to ScCO2/brine for 10/20/30/and 60 days. The mineral composition, pore structure, chemical functional groups, and surface morphology changes of the shale were analyzed using x-ray diffractometer (XRD), low-temperature nitrogen adsorption (LN-N2), infrared spectroscopy (FTIR), and scanning electron microscopy (SEM). In addition, the solid-drop method was used to measure the contact angle of shale samples at different times of ScCO2 soaking. The results show that after 60 days of continuous ScCO2 soaking, the shale water contact angle and chemical group peak spectrum generally show an increasing trend, which is caused by the reduction of carbonate and clay mineral content. The prolonged time of ScCO2 soaking weakens the shale's water wettability and reduces the water-locking effect (water has a sealing effect in the pore channel of the reservoir), capillary force, and the height of CO2 sequestration columns, which is favorable for shale gas extraction (a method of extracting natural gas from shale rock by CO2 fracturing), but it may increase the CO2 geological leakage risk. The results have important implications for regulating the change of shale water wettability, and this study can also better provide theoretical references for Carbon Geological Storage programs.

Analysis of PAF and NAF Tests Using NAPP and ANC Methods at Hajak Site, North Barito, Central Borneo

Acid mine drainage (AMD) is a significant challenge for the global coal mining industry, necessitating specialized treatment to prevent its occurrence. A crucial step in AMD prevention is identifying rocks that contribute to its formation. These rocks are classified into Potential Acid-Forming (PAF) rocks and Non-Acid-Forming (NAF) rocks. PAF rocks have the potential to produce acid, while NAF rocks do not. Laboratory analyses, including Maximum Potential Acidity (MPA), Acid Neutralizing Capacity (ANC), Net Acid Producing Potential (NAPP), and Net Acid Generating (NAG) tests, identified 3 sample points with potential PAF characteristics out of 35 samples tested (see Table 3.1). Among these, 2 sample points were classified as Potential Acid Forming-Low Capacity, and 1 sample point was categorized as Potential Acid Forming-Medium Capacity (NAG pH 4.5, NAPP 10 kg H2SO4/ton). The acidity level of mine water resulting from landfilling varies significantly based on the mineral content and landfilling techniques used. Mined material with high carbonate mineral content tends to have lower acidity levels in leachate and can even neutralize formed acid. The stockpiling strategy implemented involves layering PAF material followed by a final cover of NAF material and a rooting zone to mitigate acid formation.

Experimental investigation of microscale mechanical alterations in shale induced by fracturing fluid contact

Understanding the changes in the mechanical properties of shale exposed to fracturing fluids is crucial for optimizing parameters in hydraulic fracturing. However, the dynamic alterations in mechanical properties still need to be disclosed due to the high heterogeneity of shale, particularly at the microscale. This paper aims to in-situ unravel the microscale changes in the dynamic mechanical properties of shale affected by fracturing fluids. A combination of nanoindentation, X-ray diffraction (XRD), scanning electron microscopy (SEM), and energy dispersive spectrum (EDS) techniques was employed. The nanoindentation results demonstrate a rapid initial decrease followed by a slower decline after 4 days in both Young's modulus and the hardness of shale exposed to fracturing fluids. Specifically, the average Young's modulus of shale ranges from 62.45 GPa to 56.275 GPa, 52.575 GPa, 40.15 GPa, and 39.5 GPa while the average hardness modulus varies from 3.305 GPa to 2.2125 GPa, 1.8175 GPa, 1.24 GPa and 1.1525 GPa with the treatment time of 0, 1, 2, 4, and 7 days, respectively. An exponential expression well describes the relationship between mechanical properties with the treatment time. XRD analysis shows carbonate and clay mineral content decrease, while quartz content increases. Moreover, in-situ SEM results highlight the emergence of many dissolution pores when shale is exposed to fracturing fluid. Further pH testing and EDS analysis indicates a corrosion effect, with hydrogen ions reacting with carbonate minerals in shale, leading to a significant reduction in calcite and dolomite. Consequently, the corrosion-induced dissolution pores weaken the stability of the shale matrix, leading to a reduction in mechanical properties. This study sheds light on the mechanism behind the dynamic mechanical properties of rock and provides valuable insights for optimizing the soaking time for fracturing fluids.

Using the kinetic approach for the adsorption of base ions (Ca, Mg, Na, K) by the calm flow method in some soils in the northern of Iraq

Abstract. Four soils were selected from northern Iraq, within the ranks (Mollisols, Inceptisols) from the provinces of Dohuk, Erbil and Sulaymaniyah from different agricultural fields from the root zone (0-0.30 m). Their physicochemical and mineral properties were estimated to study thermally isotropic adsorption by the calm flow method of soil columns using an electrolytic solution. At concentrations of (3) mmol charge.L-1, containing Ca, Mg, K, and Na ions in two repetitions at a constant temperature of approximately 298 ± 2 K. Stabilization filters were collected in which the ions were estimated according to the coefficients. The results indicated that the reactions ranged from medium alkaline to medium acidic. (6.7- (7.8), unaffected by salinity (1.44 - 0.29) dS.m-1 with an ion exchange capacity between (22.43 - (33.9 Cmolc.Kg-1) and is calcareous soil due to its high content of total carbonate minerals (-112) g.kg-1 .In addition to the calcareous origin material, and it has a high clay content (304-534) g.kg-1 with the predominance of smectite, chlorite, Ilite, kaolinite and Ilite clay minerals, the nature of ion exchange using the kinetic entrance of adsorption showed a clear effect of the porous fats and the contact time of the electrolyte solution on the adsorbed quantities depending on the type of soil. Show the mathematical description of the process of arranging the kinetic equations according to their validity as follows: Power > First order > Parabolic > Elovage > Zero order

Multiscale characterization of carbonate-rich shale: From micro structure to macro mechanical properties, a case study in Hongxing Block, China

As a new growth point of shale gas production, carbonate-rich shale has recently attracted great interest. However, gas production from this reservoir was poor since the properties of the carbonate-rich shale have not been systematically studied. This is an urgent need to be addressed. Downhole cores collected from an exploration well were analyzed by micro-structure experiments (X-ray diffraction, mineral quantitative evaluation, low-pressure nitrogen adsorption, and mercury intrusion piezometry test) and macro-mechanical tests (triaxial compression, Brazilian splitting, and fracture toughness test) to obtain multiscale characterization of carbonate-rich shale. The intrinsic relationship between the microstructural and mechanical characteristics of this reservoir has been revealed. The results showed that (1) The content of carbonate minerals exceeds 30%, just slightly lower than that of quartz. Calcite has large particle sizes and is closely cemented with quartz to form a dense rock skeleton. (2) The maximum adsorption volume, specific surface area, total pore volume and average pore diameter values are poor, which is unfavorable for shale gas accumulation. Limited porosity and permeability and great tortuosity can be obstacles to the release of accumulated gas. (3) High peak deviatoric stress, Young's modulus, and Poisson's ratio were contributed by dense rock skeleton. (4) Narrow maximum main fracture width is not favorable to place proppants and further to create effective gas transport channels. (5) High tensile strength and fracture toughness enhance high breakdown and extension pressure. These comprehensive insights are of great significance for both the exploration and development of carbonate-rich shale reservoirs.

A Study of the Effect of Chemical Properties and Their Spatial Distribution in the Soils of the Western Jadwal District in Karbala Governorate

The study area was chosen in the western Jadwal district of Karbala Governorate, which is located in the area confined between longitudes 44010′30" to 4403′30" east and latitudes N 32029′20" to 32037′20" north, in order to study the chemical properties of the soil and its impact and distribution in the soil, as soil samples were obtained From surface depth 0 – 30 cm 62 samples were obtained using the auger drilling machine (auger), and the coordinates were determined by the GPS device, then they were saved and transferred to the laboratory, and the necessary chemical laboratory measurements were carried out on them, as the results showed that the electrical conductivity ECe in all the soils of the study was low, values of soil sites ranged surface between 2.18 - 6.08 dSm-1, and the degree of reaction of pH was neutral to basic, ranged between 7.0 - 8.0. with a lower percentage Organic matter of organic matter in the surface soils ranged between 0.52 - 1.43%, and the high content of carbonate minerals, the percentage of carbonate minerals in the surface soils ranged between 15.82 - 25.24%.