Scale Deposition Research Articles

Innovative stimuli-responsive membrane MSF brine rejection dilution by tertiary treated sewage effluent

In this study, treated wastewater and Multi-Stage Flash (MSF) brine were integrated into the Forward Osmosis (FO) system using pressure stimuli-responsive Nanofiltration (PSRNF) membranes to dilute magnesium, calcium, and sulfate MSF plant brine reject. The deposition of magnesium sulfate and calcium sulfate in the heat exchanger is one of the main issues affecting the performance and efficiency of MSF thermal desalination plants. Reducing the concentration of the divalent ions can minimize scale formation and deposition to a level that allows the MSF plant to operate at high top brine temperature (TBT) and without scale problems. The PSRNF membranes were chosen in the FO process because of their high water permeability, rejection of divalent and monovalent ions, small structure parameter (S), and inexpensiveness compared to commercial FO membranes. Three PSRNF membranes were tested in the FO process with the feed solution facing the active membrane layer to avoid active layer delamination. Although the PSRNF membrane exhibited negligible water flux at 0 bar, it increased when a 2–4 bar was applied to the feed solution. The wastewater temperature was set at 25 °C while 40 °C was the brine operational temperature to mimic the field situation. A maximum average water flux of 39.5 L/m2h was recorded at 4 bar feed pressure when the PSRNF membrane was used for the brine dilution, achieving up to 42% divalent ions dilution at 0.02 kWh/m3 specific power consumption. The average water flux in the PRSNF membrane was 35% higher than that in the commercial TFC FO membrane. Notably, the PSRNF membrane is ten times cheaper than commercial FO membranes. Notably, the PSRNF membrane is ten times cheaper than commercial FO membranes, achieving substantial cost reductions and pioneering advancements in FO purification technology.

Sustainable Calcite Scale Inhibitors via Oxidation of Lignosulfonates.

Deposition of inorganic scales in wells, flow lines, and equipment is a major problem in the water treatment, geothermal, or upstream oil and gas industries. Deployment of scale inhibitors has been adopted worldwide for oilfield scale prevention. Commercial synthetic scale inhibitors such as polymeric carboxylates and sulfonates or nonpolymeric phosphonates offer good scale inhibition performance but often suffer from one or more limitations including biodegradability, calcium compatibility, and thermal stability. Lignin-based biomaterials such as sodium lignosulfonates are natural, sustainable, and widely available polymers that are accepted for use in environmentally sensitive areas. Here we show that, although lignosulfonates perform relatively poorly as calcite scale inhibitors in dynamic tube blocking tests, oxidized lignosulfonates show a much improved inhibition effect by a factor of 20-fold. The oxidized lignosulfonates are easy to prepare in a 1-step reaction and show excellent calcium compatibility and thermal stability, useful for downhole squeeze treatments in high temperature wells. This present study unequivocally establishes oxidized lignosulfonates as a new class of sustainable green scale inhibitors, thereby bridging the gap between materials derived directly from nature and the classic synthetic polymeric scale inhibitors.

Analysis of Scale Problem Using Acidizing Stimulation in Field Z Kalrez Petroleum (Seram) LTD

The annual decrease in production at well Z occurs due to scale deposits that impede fluid flow. Scale is a production problem due to the mixing of two types of water with different properties so that the solubility limit of the compound in the formation water is exceeded. To overcome the scale, stimulation is carried out with an acidizing method using a type of acid (HCL 10%). Evaluation was conducted to determine the effect of acidizing stimulation on scale based on productivity index (PI), inflow performance relationship (IPR) curve and comparison of stimulation methods. Evaluation of test results after acidizing stimulation of well Z experienced an increase in production. Productivity Index increased from 4.748 bbl/psi to 9.036 bbl/psi. Based on the IPR curve before acidizing, the maximum flow rate (Q max) = 324,107 bpd, increased to Qmax = 769,021 bpd.Keywords: Cost Benefit, Productivity Index, Scale, Acidizing Stimulation

Predicting scale deposition in oil reservoirs using machine learning optimization algorithms

Scale deposition, a form of formation damage, not only affects the reservoir but also damages the well and equipment. This phenomenon occurs due to changes in temperature, pressure, and the injection of incompatible salt water, leading to ionic reactions. This study investigated permeability reduction due to scale deposition and examined how parameters such as temperature, pressure drop, and ion concentration affect the prediction accuracy. The scale deposits investigated in this study include CaSO4, BaSO4, and SrSO4. This paper uses Python to employ different machine-learning algorithms to predict the results. Each machine learning model has certain hyper-parameters that need adjustment. Failure to do so will result in reduced accuracy and incomplete interpretation of input data. The accuracy of the support vector regression (SVR) algorithm was significantly affected by the variation of the epsilon parameter in the dataset used. Therefore, before hyperparameter optimization, SVR had the lowest accuracy at 0.575. After adjusting the hyper-parameters, our findings show that SVR had the highest increase in R-squared value, which was 0.900, and the most minor growth in KNN, which went from 0.995 to 0.996. Additionally, the highest accuracy value for K-Nearest Neighbor is 0.996. Furthermore, most errors were related to SVR and XGBoost algorithms, while the most negligible errors were for the Decision Tree and KNN algorithms.

A review of scale inhibitor methods during modified smart water injection

AbstractEnhancing oil recovery (EOR) through water flooding methods, including smart water injection, low salinity water injection, polymer injection, and surfactant injection has become a pivotal strategy for enhancing productivity. Despite their promising outcomes, these methods often encounter challenges such as scaling formation and deposition, impacting reservoir permeability and production rates. A comprehensive understanding of scaling formation is crucial for effective implementation of these methods. This article explores various scaling types prevalent in the field, examining key parameters (temperature, pressure, and pH) that influence scaling formation. Additionally, it presents a diverse range of inhibitors employing both chemical and mechanical methods to mitigate and prevent scaling, thus safeguarding reservoir performance. The efficiency of inhibitors is scrutinized concerning chemical composition and performance maintenance under different temperature and pressure conditions. This study serves as a valuable resource for researchers, engineers, and industry experts involved in the oil industry and reservoir management. By elucidating scaling mechanisms, delineating consequences, and offering extensive solutions, it enhances comprehension and provides a foundation for improving oil recovery strategies. The findings of this study contribute to a better understanding of scaling mechanisms, providing insights that can be applied to optimize oil recovery processes, mitigate reservoir challenges, and improve overall reservoir management strategies.

ANALYSIS OF THE PROPERTIES OF COATINGS USED TO PROTECT THE PUMP AND COMPRESSOR PIPE

In this article considers basic properties of protective coatings applied to the inner wall of tubing in order to extend pump and compressor pipe (PCP) service life PCP and minimize operational risks. The main complicating factors, such as scale deposits, corrosion aggressiveness, mechanical impurities, etc., arising during PCP operation are specified, groups of test media and test parameters for grading different types of coatings according to their resistance to complicating factors are singled out. Influence of various aggressive media on PCP, such as distilled water, petroleum product simulator, etc., coatings is described, and test media and test parameters for protective coatings are reviewed. The basic methods for determining the physical and mechanical characteristics, such as determining adhesion, thickness and dielectric continuity, of coatings are given, and brief informative and descriptive references for each of them are given. Recommendations are given for testing protective coatings on the inner surface of PCP for compliance with technical requirements, which ultimately allows selecting materials most resistant to aggressive field environments. The relevance of studying the influence of aggressive media on the protective coatings of the inner wall of tubing is due to the need to increase the level of reliability and durability of technical systems in operating conditions. The work is of interest to specialists in the field of materials science, technical expertise and tubing design, as well as researchers involved in the development of new materials and methods for surface protection in operating conditions. The results obtained will optimize the choice of protective coatings for specific operating conditions, which helps to increase the service life of tubing and reduce maintenance costs. This is of direct importance for reducing the risks of accidents and the environmental consequences of oil and gas production processes. In addition, the development of innovative materials and methods for protecting the surfaces of the inner wall of the tubing contributes to improving the efficiency of the operation of oil and gas wells, as well as helps to reduce equipment downtime.

Performance evaluation of glutaraldehyde-modified red onion skin extract as oilfield scale inhibitors

Scale deposition occurs due to changes during injection operations and the mixing of incompatible brines. Scale inhibitors are used to mitigate such occurrences. The inhibition efficiency of the glutaraldehyde-ROSE resin (ROG) was evaluated in synthetic brines containing CaSO4, BaSO4, and CaCO3 under static conditions according to NACE standard methods. The formulated scale inhibitor was compatible with the brine and thermally stable. The inhibition studies of ROG revealed optimal inhibition of 89% at 80 ppm and 58% at 100 ppm at 90 °C and 22 h, respectively, for BaSO4 and CaCO3 scales, while for CaSO4 scales, optimal inhibition of 67% was observed at 100 ppm, 71 °C, and 22 h. On comparison, the Commercial Scale Inhibitor (CSI) showed optimal inhibition of 97% at 100 ppm and 94% at 80 ppm at 71 °C and 22 h, respectively, for BaSO4 and CaSO4 scales, while for CaCO3 scales, optimal inhibition of 98% was observed at 80 ppm, 90 °C, and 22 h, respectively. This indicates that ROG efficiently mitigated the formation of CaSO4, BaSO4, and to some reasonable extent, CaCO3 scales, and its inhibition performance compared favorably with the CSI, thus unveiling its potential for consideration as a green oilfield scale inhibitor.

Integrated treatment of wax and scale removal in old wells of the Tanjung Field

The majority of oil wells in the Tanjung Field are old wells with reservoir characterized by low pressure and temperature, as well as high water production. The characteristic of oil in the Tanjung Field has a relatively high wax content of 17.61%. This condition has led to several wells in the Tanjung Field experiencing issues with the simultaneous formation of wax and scale deposits within the wellbore equipment. The simultaneous occurrence of wax and scale can significantly impact the production rate. Therefore, addressing this production issue efficiently requires a method known as wax scale removal (WSR). WSR can effectively tackle the problem of wax and scale deposits occurring simultaneously in production equipment. In this method, a solvent for dissolving wax deposits and an acid for dissolving scale are injected together using the huff and puff technique.

Oil-infused surface on galvanized iron pipes for anti-scaling in industrial applications

Scale deposition on the surface of pipelines is a common phenomenon in industrial production. It not only decreases the heat conduction efficiency of the pipeline and increases energy consumption, but also leads to corrosion of the pipeline. Although varieties methods are developed to prevent pipeline scale deposition, these methods could not meet the requirements of harsh production conditions. This study introduces a novel oil-infused surface on galvanized iron for efficient anti-scaling in industrial pipelines. The surface of galvanized iron is firstly oxidized and modified to be superhydrophobic/superoleophilic, followed by injection of oil to form oil-infused surface. This oil-infused superhydrophobic/superoleophilic surface demonstrates excellent water repellency and superior anti-scaling performance compared to untreated galvanized iron. It may provide a promising anti-scaling option for iron-based pipelines in industrial productions.

Analysis of scale problem using acidizing stimulation in field Z Kalrez Petroleum (Seram) LTD.

The annual decrease in production at well Z occurs due to scale deposits that impede fluid flow. Scale is a production problem due to the mixing of two types of water with different properties so that the solubility limit of the compound in the formation water is exceeded. To overcome the scale, stimulation is carried out with an acidizing method using a type of acid (HCL 10%). Evaluation was conducted to determine the effect of acidizing stimulation on scale based on productivity index (PI), inflow performance relationship (IPR) curve and comparison of stimulation methods. Evaluation of test results after acidizing stimulation of well Z experienced an increase in production. Productivity Index increased from 4.748 bpd/psi to 9.036 bpd/psi. Based on the IPR curve before acidizing, the maximum flow rate (Q max) = 324.107 bpd, increased to Qmax = 769.021 bpd. Based on the Cost Benefit Analysis (CBA), the Acidizing Stimulation method (10% formic Acid) was chosen to overcome the scale problem because the B/C ratio >1 or 1.9 means that for every 1 US$ invested in the Acidizing Stimulation method (10% formic Acid), a savings ratio of 1.9 will be obtained. So it is very reasonable to decide that the Acidizing Stimulation method (10% formic Acid), is feasible and more useful and efficient.

SCALE FORMATION IN THE OIL AND GAS INDUSTRY AND THE TRANSITION TOWARDS «GREEN» INHIBITORS

Hydrocarbon production in oil field conditions invariably involves the joint production of significant amounts of water. Mineral salts of various compositions can precipitate from produced water under certain conditions. In the oil and gas industry, the deposition of mineral salts on the surface and underground production equipment can cause various problems, such as deterioration of reservoir properties, reduced production and premature failure of well equipment. Scale deposition can also lead to pump malfunctions, reduced efficiency of heat exchangers, reduced quality of commercial products and increased corrosion processes. Salt deposits lead to expensive restoration work, downtime in well operations and, ultimately, to an increase in the cost of produced hydrocarbons.As a result of the geochemical processes between the injected water and the formation water and the formation rock, as well as the complex composition of the formation fluids, controlling the formation of inorganic scales becomes a challenge. In the oil and gas industry, carbonate (calcium), sulfide (iron) and sulfate (calcium, barium, strontium) deposits are most often encountered. The formation of scale deposits depends on several factors, which include, but are not limited to, temperature, pressure, solution saturation and hydrodynamic flow characteristics.There are many approaches to managing scale deposits, but the most common currently is the use of chemical reagents – scale inhibitors. Traditional scale inhibitors contain phosphorus- and nitrogen-based chemicals as their active base, which can be harmful to the environment and human health. In this regard, in the world practice of oilfield chemistry, the direction of «green» chemistry is actively developing – reagents that can effectively prevent the formation of mineral salts with minimal negative impact on the environment and humans.This review discusses various scale types, methods for their removal, scale inhibitors of various natures and the mechanism of their work. Attention is also paid to «green» inhibitors and their development.

Hydrothermal Alteration Zones Mapping Using Sentinel 2 MSI and Terra Aster Data in The Uruguay Mine, Minas do Camaquã District

Objective: This work has as main objective to evaluate the usage of data from the Terra ASTER multispectral sensor, as well as data from Sentinel 2 MSI for the identification of hydrothermal alteration zones in the Uruguay Mine. Another objective of this work was to map a not-so-great scale deposit that present a hydrothermal pattern associated in a tropical country. Method: Were applied principal component analysis and entropy analysis technique to the ASTER surface reflectance data and principal components only to the surface reflectance MSI data. The field spectra provided were obtained with the ASD FieldSpec-3 High-Resolution spectroradiometer. The samples collected contained spectral features characteristic of minerals such as ferric chlorite, hematite, goethite and illite (Phengite). Result and Conclusion: The ASTER data resulted in a good radial highlighted pattern at the mine location indicating that the processing was able to map the target spectral patterns. The MSI data were processed to map the ferric minerals and presented a pattern highlighting the mine contours and slopes, demonstrating the possible occurrence of minerals containing the aimed spectral features. The entropy usage as an intensity factor applied to intensity-hue-saturation (IHS) fusion on ASTER data improved the reliability of the results, by highlighting the pixels with deepest absorbance features, reducing the uncertainty associated with the process. The results were considered good since both processes showed correspondence in the location of the mine. Implication of the research: This work contributes for the understanding of spectroscopy analysis of alteration minerals related to copper mineralization, and techniques of remote sensing to map them. Originality/value: Good results of the application of principal component analysis in the studied area and application of entropy concept in spectral analysis.

Magnetic treatment as a suppressive method for CaCO3 scale deposition in hard waters in the presence of air bubbles

Calcium carbonate (CaCO3) scale deposition in hard water is a common problem affecting the performance and efficiency of various industrial applications such as water heating systems and pipelines. The aim of this study was to investigate the effectiveness of magnetic treatment as a suppressive method for CaCO3 scale deposition in hard water in the presence of air bubbles. A series of experiments were carried out using a laboratory-scale setup. The different CaCO3 concentrations (100 mg/L, 500 mg/L and 1000 mg/L) were considered. The hard water samples according to the various water circulation times (10, 20 and 30 min) were pumped with the flow rate of 50 L/h and passed through the region of the magnetic lines and air bubbles. A neodymium magnet (NdFeB-NB12) with a non-uniform magnetic flux density of 0.2 T on the inner walls and 0.05 T at the center was used. The CaCO3 particles deposition rate was measured using turbidity amount. The results demonstrated that the magnetic treatment significantly reduced CaCO3 deposition in hard waters in the presence in air bubbles. Turbidity changed from 0.3 NTU to 0.65 NTU at the CaCO3 concentration of 100 mg/L. It changed from 0.5 NTU to 2.25 NTU at the CaCO3 concentration 500 mg/L. Moreover, in CaCO3 concentration 1000 mg/L turbidity altered from 0.8 NTU to 3 NTU over circulation time 30 min. The simultaneous presence of magnetic fields and air bubbles reduced the amount of CaCO3 scale deposition and increased the nucleation in the bulk of the water. Aeration-based magnetic treatment is a promising alternative to chemical-based methods and an eco-friendly approach for hard waters treatment.

Evaluation of compatibility between formation and Injection water into the Reservoir Rock

Scale deposition represents a critical challenge encountered in water injection systems. The objective of this study is to assess the compatibility between the candidate smart water and the formation water in an oil reservoir rock sample. To achieve this, water samples were collected and analyzed to evaluate the extent of deposit formation under varying temperature and pressure conditions. Additionally, the study also examined the combined influence of temperature and pressure on deposit formation. The results indicated that as the temperature increased, there was a decrease in the concentration of sulfate in the seawater. Taking into account the low concentration of barium (zero) in seawater and the unchanged strontium concentration, the decrease in sulfate concentration can be attributed to the deposition of calcium sulfate. Contrarily, in various ratios of smart water, the sulfate concentration has shown an increase with rising temperatures. This can be attributed to the transformation of sulfite present in the formation water into sulfate due to the influence of temperature. The presence of a low concentration of barium in the formation water resulted in insignificant changes in sulfate concentration due to the precipitation of barium sulfate. Additionally, despite the high concentration of strontium, strontium sulfate deposition did not occur, possibly due to the solubility product constant. The analysis of different smart water ratios under various pressures at ambient temperature revealed that pressure had a minimal effect on the solubility of sulfate and calcium salts. During the sediment analysis, no evidence of strontium sulfate sediment formation was observed. However, the analysis indicated a high possibility of iron sulfide and iron oxide deposits forming. Ultimately, under the experimental conditions, significant sediment formation was not observed.

A comprehensive equilibrium model for the phosphonate scale inhibitor-carbonate system including coupled adsorption/precipitation (Γ/Π)

Inorganic scale deposition is one of the main flow assurance issues in hydrocarbon production, and injection systems, leading to significant loss in production and subsequent expense to mitigate. Scale Inhibitors (SI) are chemicals that are commonly used to prevent the inorganic scale from building up in the system. SIs are usually injected into the porous media, where they can react and be retained, and released back into the produced brine as the production commences. This in situ scale prevention method is known as “squeeze treatment”, and the lifetime of this process is determined when the SI concentration in the return fluid falls below the MIC (Minimum Inhibitor Concentration), where the SI is sufficiently effective at preventing or efficiently reducing scale formation. In this study, a general chemical equilibrium model has been developed to simulate the chemical reaction of phosphonate scale inhibitors and their retention in a carbonate system (calcite), in the presence of an aqueous phase containing free divalent cations. The model couples together the following processes (i) the carbonate system, (ii) speciation of the SI, modelled as a weak polyacid, HnA, (iii) the metal (Ca2+, Mg2+) binding – SI chelant interactions, (iv) phosphonate SI acid impurity reactions, (v) adsorption of the free and complex species to the rock surface and (vi) and finally, the precipitation of complex species (SI-Ca-Mg). To find the equilibrium conditions, charge balance and mass balances for key components in the system were considered, and combined utilizing reaction constants, i.e. equilibrium constants, stability constants, and solubility constants. This full equation set can be solved numerically to find the equilibrium concentration of all engaged species to characterize the equilibrium condition. To account for the adsorption and precipitation retention in this system, a coupled adsorption/precipitation (Γ/Π) isotherm has been presented and used for the first time. The coupled Γ/Π isotherm is a mathematical representation of the retention amount in the system that coupled adsorption and precipitation retention mechanisms are in action, which can scale up the retention results to other systems with different mass to volume ratios. To validate the proposed model, experimental results of a DETPMP-Calcite equilibrium system in NSSW were considered. The model and the experimental results were in good agreement demonstrating the reliability of the model. Furthermore, the reliability of the model in stoichiometry prediction of complexes, and distribution of species in different conditions was evaluated which confirmed the validity of the model.

Effect of Wettability Gradient on the Scale Formation in Falling Film Flow

Abstract Mitigation of scale formation and performance degradation remains a vital challenge for falling film evaporators in various industries. In this work, an experimental study of falling film flow on a horizontal tube is conducted to investigate the effects of wettability gradients on thermal, hydraulic, and fouling behavior. It is revealed that certain hydrophobic coating patterns, such as strip, ring, and grid patterns, lead to unwetted heat transfer area, which results in decreased heat transfer compared to fully wetted plain tube. By adjusting the geometry and position of the wettability gradient, the hybrid coating demonstrates improved heat transfer performance. Based on the characteristics of horizontal tube falling film flow, impinging jet, thin film flow, and liquid retention at the tube bottom, a hybrid coating pattern is developed to improve surface wetting and mitigate the scaling coverage. It is revealed that scale deposition is regulated by wettability gradient. Crystals tend to be dense and compact in hydrophilic areas, while they appear scattered or even absent in hydrophobic regions, depending on the dimension of the hydrophobic area. While at the hydrophilic/hydrophobic boundary, a noticeable scale thickness step is observed, which raises the potential for self-cleaning. The balance of minimization of scaling layer coverage and maximization of wetting area requires an optimal design in coating dimensions, for which a systemic study of both flow dynamics and fouling characteristics on the falling film is necessary in the future.

A numerical study of CaCO3 deposition on the membrane surface of direct contact membrane distillation

This numerical study investigates the effect of CaCO3 deposition on the performance of direct contact membrane distillation (DCMD). It is the first numerical study to directly evaluate the deposition and film thickness of CaCO3 on the membrane surface. Therefore, a 3D computational fluid dynamics (CFD) model, which combines momentum, heat, species transport reaction, and the Eulerian wall film model, is used to analyze the CaCO3 mass deposition rate and scaling deposition thickness on the membrane surface. HSC Chemical Software is used to evaluate the ion compositions and reaction kinetics, including the activation energy (Ea) and pre-exponential factor (Ar). The CFD model is validated with experimental results. The results reveal that the CaCO3 deposition rate increases significantly at a high temperature, velocity, and salinity of the solution. The CaCO3 mass deposition increased by 15 times and scaling deposition thickness increased from 0.05 nm to 1 nm when the temperature was raised from 318.15 K to 348.15 K, whereas an increase of approximately 25 % in deposition was observed with an increase in velocity from 0.17 to 1.38 m/s at a concentration of calcium (Ca+2) ions, 0.03 % and bicarbonate (HCO3−) ions 0.004 %. The results also indicate that CaCO3 deposition decreases the flux and efficiency of the DCMD by 2 % with a low concentration of Ca+2 ions, 0.03 %, and HCO3− ions, 0.004 %. The findings indicate that the high feed salinity (75.23 g/l) increases CaCO3 mass deposition and scaling deposition thickness on the membrane surface due to the high concentration of Ca+2 ions, 0.07 %, and HCO3− ions, 0.01 %, significantly reducing the permeate flux by 14 %. The study's model development and implementation can be adjusted to offer guidance for studying the MD process in treating high saline water with fouling issues.

The role of electrical current mode in calcium carbonate deposition on conductive carbon nanofiber–epoxy coating

AbstractCalcium carbonate is one of the most common scaling minerals. In this paper we have used different electrical current modes (direct current [DC], pulsed DC, and alternating current [AC]) to control the amount, morphology, and distribution of calcium carbonate deposit on electroconductive epoxy/carbon nanofiber (CNF) coating. The effect of different current modes on surface scaling was visualized using scanning electron microscopy. It has been shown that both AC and DC anodic polarization limited scale deposition on epoxy/CNF coated surfaces, although the mechanisms of scale inhibition during AC and DC polarization were different. DC polarization of the coating at +2 V resulted in the smallest scale buildup without leading to coating degradation, while DC polarization at potentials as high as +5 V caused the coating to degrade. Interestingly, application of pulsed DC with high pulse frequency (50 Hz) inhibited the degradation. The type of current applied affected also the morphology of the precipitate at the cathode. The results presented in this work show, for the first time, how different modes of electrical current applied to electroconductive composite coatings can be used to control the morphology and distribution of calcium carbonate scale, and how the organic coating degradation at high polarization potentials can be avoided.

Fingerprinting Pb-Zn mineralization events in the SW Yangtze Block, South China: A case from Yuanbaoshan deposit

The southwestern Yangtze Block represents one of the world’s largest lead–zinc provinces, comprises more than 400 known carbonate-hosted Pb-Zn deposits and contains over 30 million tons (Mt) of total Pb + Zn reserves. The Pb-Zn deposits in this area have been studied extensively by economic geologists, but the origin and mineralization processes of these deposits are still controversial. The Yuanbaoshan deposit is a typical carbonate-hosted Pb-Zn deposit of medium scale (0.19 Mt P + Zn reserves @ 0.7–26.31 wt%), which is in the northern part of the Pb-Zn mineral belt in the southwest margin of the Yangtze Block. In this study, we have conducted LA-ICP-MS sulfides trace elements, S isotope analyses, together with gangue carbonate C-O stable isotope analyses and pyrite Rb-Sr dating. We present Rb-Sr isotopic data on the pyrite that yields an isochron age of 196.4 ± 2.3 Ma. The mineralization temperature at Yuanbaoshan, as determined by the Ga, Ge, In, Mn and Fe (GGIMF) in sphalerite geothermometer, ranges from 161 to 264 ℃ (Sp1) and 141 to 246 ℃ (Sp2). The δ13CPDB values range from −0.66 to 0.61 ‰, δ18OSMOW values range from 15.6 to 17.3 ‰. In situ S isotopes show that the δ34S values of sulfides range from −1.4 to 17.73 ‰. The field, petrologic, geochemical and isotopic data from our study lead to the following salient findings. (1) The dissolved carbon and oxygen of ore forming-fluids of these Pb-Zn deposits were mainly derived from sedimentary carbonate dissolution. (2) The reduced S in the sulfide of the Yuanbaoshan Pb-Zn deposit is mainly derived from the thermochemical sulfate reduction (TRS) and the reduced S produced by the pyrolysis of S-containing organic matter in the carbonaceous mudstone of the Ebian Group. (3) The large-scale Pb-Zn mineralization in the southwest margin of the Yangtze Block was influenced by the post-collision extension between the Indosinian Block and the South China Block during ca. 200 Ma.

Rapid and facile detection of PBTC antiscalant using functionalized polystyrene nanoparticles and latex agglutination

Organophosphate-based compounds, particularly 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTC), have been crucial in circulating cooling systems and wastewater treatments as corrosion inhibitors preventing scale deposits in industrial facilities. Employing the reagent within its optimum concentration range is essential for effective performance, minimizing costs and environmental impacts. However, measuring PBTC separately can be challenging due to its functional groups’ similarity to other common molecules found in natural water, necessitating complex procedures. In this study, amine-functionalized polystyrene (PS) latex nanoparticles were synthesized through emulsifier-free emulsion polymerization and utilized as nanosorbents for PBTC detection via a straightforward latex agglutination method. This phenomenon is facilitated by electrostatic and hydrogen bonding interactions between the positively charged layers on the particle’s surface and the negatively charged PBTC molecules. The pH and concentration of the PBTC solution are key factors influencing the adsorption behavior and capacity of the functionalized latex particles. A graphical representation of aggregation domains, dependent on both PBTC concentration and pH, was created. This map serves as an effective tool for detecting PBTC concentration. The resulting particles show great promise for monitoring the concentration range of phosphate additives in water, offering a simple, rapid detection process with low costs and reduced chemical and equipment requirements.