Carbonates - Science topic

Ethylene carbonate is solid at room temperature, propylene carbonate is also very polar and certainly not volatile.

If it was adventitious carbon, systematically, it should appear both in the survey and the HR spectrum.

To determine the nitrogen flow rate required to create an inert atmosphere in a tube furnace, you can estimate it based on the tube's volume and the desired gas exchange rate. Here's a general approach:

### 1. Calculate the Tube Volume

If you don't have the exact measurements, let's consider:

- **Diameter of the tube (B)** in meters.

- **Length of the tube (A)** in meters.

The volume of the tube \( V \) can be calculated using the formula for the volume of a cylinder:

\[

V = \pi \times \left(\frac{B}{2}\right)^2 \times A

\]

This volume is in cubic meters. If you want it in liters, multiply by 1000 (since \( 1 \text{ m}^3 = 1000 \text{ L} \)).

### 2. Determine the Target Purge Rate

A common approach is to replace the tube’s entire volume several times per minute to maintain an inert atmosphere. Typically, 3–5 times the volume of the tube per minute is sufficient for achieving an inert atmosphere.

Let's denote the purge rate factor as \( P \) (for example, \( P = 5 \)).

So, the required flow rate \( Q \) (in liters per minute, L/min) would be:

\[

Q = V \times P

\]

### 3. Example Calculation

If you consider hypothetical values:

- **Length, A = 1 meter**

- **Diameter, B = 0.05 meters (5 cm)**

Then the volume \( V \) would be:

\[

V = \pi \times \left(\frac{0.05}{2}\right)^2 \times 1 \approx 0.00196 \text{ m}^3 = 1.96 \text{ L}

\]

With a purge rate factor \( P = 5 \):

\[

Q = 1.96 \times 5 = 9.8 \text{ L/min}

\]

So, a nitrogen flow rate of approximately **10 L/min** would help create an inert atmosphere for this hypothetical setup.

### Important Notes

1. **Leakage:** Ensure that your tube furnace is well-sealed to prevent air leakage.

2. **Flow Rate Adjustment:** If the furnace has specific recommendations for flow rate, follow those. Too high a flow rate might disturb the sample.

3. **Monitoring:** Use an oxygen sensor, if available, to confirm that the atmosphere remains inert during the process.

This setup should help create an inert nitrogen environment for carbonization.

Q1: Yes, Precambrian carbonate sediments often underwent dolomitization after deposition. This process occurred due to the chemical environment of early Earth, where seawater was rich in magnesium. Dolomitization typically affected these sediments during burial diagenesis, converting limestone into dolostone. The widespread occurrence of dolostone in Precambrian strata is a key evidence for this process. This transformation also altered the porosity and permeability of the carbonate rocks, impacting later fluid flow and mineralization.

Q2: Precambrian dolostones are commonly associated with a high Mn/Sr ratio, which reflects diagenetic alteration. The elevated manganese levels indicate interaction with reducing fluids, while the depletion of strontium results from recrystallization processes. This Mn/Sr ratio serves as a useful criterion for identifying diagenetic changes in carbonate rocks, but it is not a perfect indicator. In Precambrian carbonates, the complex diagenetic history and variations in original seawater chemistry can make it difficult to apply this ratio universally as a diagnostic tool. Thus, while helpful, it should be used with caution.

Dear Michele Harrison ,

These papers might be useful:

Hope it helps!

Does it dissolve in DCM? If not, use different solvent like ethyl acetate or toluene for workup. If yes, does it mix with sodium carbonate solution (hence not layers)? If yes, you need to polarise aqueous layer more, like with salt. If no, you mean you have no reaction with sodium carbonate solution? If your acid is weak, you might not see bubbles, but it doesn't mean it didn't work, or maybe you need more vigorous stirring. If it still doesn't work, try adding tertiary base like triethylamine and do a flash chromatography run in low polarity system with triethylamine. Then your picoline derivative will likely come off before ionic salt of acid present. Make sure to check on TLC first though.

Sometime higher pH of soil due to have received excess compost, especially composted manure, tend to have a higher pH due to the build-up of base cations. higher moisture. in soil due to excess irrigation and imbalanced fertilizer use is the main cause of higher pH

The vacuum pump has recently undergone maintenance, which included an oil change, so I believe that is not the problem. But I really appreciate your suggestions, Dr. Jean-François.

Hey there Abu Faizal! Sure thing, I can help you Abu Faizal out with that.

To prepare a 1M solution of NaClO4 in propylene carbonate (PC) for your Na-ion batteries, you'll need to follow a precise procedure to ensure the electrolyte meets your specifications. Here's a breakdown of the necessary calculations and steps:

1. **Determine the Molecular Weight of NaClO4**: You'll need to know the exact molecular weight of sodium perchlorate (NaClO4) to calculate the amount needed for a 1M solution.

2. **Calculate the Mass of NaClO4**: Using the formula weight (MW) of NaClO4 and the desired molarity (1M), you Abu Faizal can calculate the mass needed using the formula:

{Mass (g)} = {Molarity (mol/L)} times {Volume (L)} times {MW (g/mol)}

3. **Prepare the Solution**: Once you've calculated the mass of NaClO4 needed, dissolve it in the appropriate volume of propylene carbonate. Ensure thorough mixing to achieve a homogeneous solution.

4. **Safety Considerations**: Always handle perchlorates with care due to their oxidizing properties. Work in a well-ventilated area and wear appropriate personal protective equipment.

5. **Quality Control**: Test the conductivity and pH of the electrolyte to ensure it meets your desired specifications. Adjust if necessary.

6. **Storage**: Store the prepared electrolyte in a tightly sealed container away from moisture and light to maintain its stability.

By following these calculations and steps, you'll be able to prepare a reliable and effective NaClO4 electrolyte for your Na-ion batteries. If you Abu Faizal need further assistance or have any specific questions along the way, feel free to ask!

All of these methods are good but you take care about the sampling method and had better sampling by an expert.

Yes it does ! Thank you for your answer.

Any idea for the cylinder ones ?

See this textularid species in Ashwaq Talib Al-Hamdani, 1980, who studied the Aqra Formation in the region of Gali Zenta. (Type locality of Aqra Fn.)

Dear Mazin,

This section does not belong to miliolids at all. You can find it in the thesis of Ashwaq Talib Al-Hamdani, 1980, which studied the Aqra Formation in the region of Gali Zenta. (Type locality of Aqra Fn.). Also, you can see the other section in her thesis.

Udaykumar Vegad

Kjeldahl Method, Bradford Assay, Lowry Assay, Bicinchoninic Acid (BCA) Assay.

Phenol-Sulfuric Acid Method, Anthrone Method, High-Performance Liquid Chromatography (HPLC), Gas Chromatography-Mass Spectrometry (GC-MS).

Fourier Transform Infrared Spectroscopy (FTIR): for identifying functional groups and overall chemical composition. It can reveal the presence of polysaccharides, proteins, and other components in the mucilage.

Ultraviolet-Visible (UV-Vis) Spectroscopy: To detect chromophores in the mucilage and provide insights into conjugated systems.

Nuclear Magnetic Resonance (NMR) Spectroscopy: Utilizing 1H NMR and 13C NMR can yield detailed information about the mucilage's chemical structure.

Gel Permeation Chromatography (GPC) or Size Exclusion Chromatography (SEC): For assessing the molecular weight distribution of the mucilage, which is crucial for understanding its structural characteristics.

Polarimetry: To determine the optical rotation of the mucilage, providing information about optically active components.

Gravimetric Analysis: To determine the total polysaccharide content in the mucilage by precipitating the polysaccharides and measuring their mass.

Thanks but this translates to about 1.8 mg which I believe is too low. Is there any literature support for your suggestion? Please let me know.

Thanks for your reply@Prem Baboo! Yes it is clear that soil contains a great amount of C as SOC and the pool size is much greater than that of vegetation and atmosphere. My question is that rocks of the world store much higher amount of C (as inorganic C) than soil. Is it correct to say that soil is the greatest terrestrial C pool?

Classification based on mass %

< 0.5 c1 very poor in carbonate

0.5 to 2 c2 poor in carbonate

2 - 10 c3 carbonate-bearing

10 - 25 c4 enriched in carbonate

50 - 75 c6 extremely enriched in carbonate

≥ 75 carbonate (limestone, calcrete, dolocrete..)

Elaborated for soil types in German vineyards

HGD

You may try CO2-injection as prevention, using a injection line down to the pump. Alternatively, flush the tubing with HCl then and again.

Glycerol does not adsorb UV, therefore you need a RI (refractive index) detector, which requires an isocratic elution (it is not possible to use two pomps or a system with valves and one pump >>> no stable baseline), thus use a premixed solvent as eluent.

Retention of glycerol will be low on a C18 column, I expect that diglycerol dicarbonate shall have a much higher retention. Eluent composition water/acetonitril range 100 to 95/5. Start with the latter one and decrease the ACN concentration if there is insufficient retention of glycerol.

Alternative is to use a Pb-carbohydrate column at 80°C. The eluent is than 100% water in combination with RI-detection. You can add UV-detection for selective detection of the diglycerol dicarbonate,

Hi Roberta, thank you for your interest in the HAWK Pyrolysis, TOC and Carbonate Carbon instrument. Please be assured that when you consider the fact that the HAWK needs very minimal maintenance then its cost is in a very good range. We can send you a quote if you would like us to do so. Please let me know. Our website is www.wildcattechnologies.com and you can also reach me directly; albertmaende@wildcattechnologies.com

Rock physics modeling of reservoir changes is required before the firs 4D seismic acquisition using the available well log data. This will indicate if there is a 4D signature for the expected reservoir changes.

The methods startinf from the Gassman theory are mostly applicable to the sandstone reservoir. Care has to be taken when the carbonate reservoirs are considered. See, for example, Øystein et al. (2005 SEG, Adam, Batzle and Brevik (2006), Vanorio, Scotellaro and Mavko (2007) -SEG, Sain et al. (2008) SEG, and Jiang et al., (2013) SEG.

Hi Divya, you'll most likely want to do a simple acid-base titration, using a standardized concentration of sulfuric acid (maybe starting in the range of 0.01 M H2SO4) and use a pH meter for the end point (can be 4.5 or down to 4.2 depending on composition of ions and expected alkalinity result. Results below 20 ppm CaCO3 usually would use an endpoint of 4.2). You can also use a dye as an indicator for pH endpoint, such as bromocresol green. You can find more information in Standard Methods for Water and Wastewater, "2320 Alkalinity". I would assume some of your carbonate would convert to bicarbonate with atmospheric CO2.

For sure. The balance between sedimentary supply, i.e. topography and climate, the rate of subsidence, local and global changes in sea level, local disturbances such as an asteroid impact, seismicity and any other have the power to leave a signature in the sedimentary record.

Hello. This can be more complicated. Apparently it is the gamma phase of Na2CO3 and it is said to be an incommersurately modulated structure. Some structural data is available for download at http://rruff.geo.arizona.edu/AMS/amcsd.php, there type "natrite" in the mineral field and search.

When it is an incommensurately modulated structure, it will work only approximately in most Rietveld's software.

Well this is more than an over-simplification!. Atmospheric carbonates usually correspond to some of the mineral components of airborne particulate matter, actually fragments of rocks resuspended from soil and/or desert dust in the form of calcium and to a lesser extent, magnesium carbonates to which omologues from human activities must be added locally (cement, building excavating...) which are remobilized and mixed in the air like all the particles. This class of particles are mostly coarse (> 1 µm) with a high probability of being fast dry removed to the ground by gravitational settling . However we have to remind the concept of environmental fate for anything recirculated across the planet which includes not only transport but also physical chemistry and chemistry ( even biochemistry) during motion. For carbonate you can expect dissolution by collision with droplets during wet removal processes (therefore a strong influence of meteorolofical processes) and acid- base reactions which may actually bring to carbonate dispacement. One possible reaction of acid displacement of carbonates may be traced to HCl which is fairly volatile, after release from emissions (eg volcanoes) or atmospheric chemistry. However, airborne particulates are historically known to possess predominantly acid properties due to traces of H2SO4, HNO3 and mono and di-carboxylic acids (all substances with high vapour pressure) from atmospheric oxidation of gaseous precursors. In case of collision between carbonates and other aerosol particles more or less loaded with moisture, acidity can be expressed and release CO2. It is clear that any generalization is not allowed. Proof is therfore given in decades of aerosol science and not just research, but also in basic textbooks of atmospheric chemistry such as Fynlayson-Pitts & Pitts, and Seinfeld Pandis From the first through the third edition

I agree with Federico Lucci Federico Lucci, a photo would be really helpful.

In general, what I observe in the field is that faults in carbonates can form as very thin structures. There´s not necessarily a breccia or a large damage zone involved.

So, it´s worth having a closer look for any markers, i.e. striation, gauge.

In other words: I can not imagine that the carbonate is not metamorphosed if the contact is original.

Ok, looking at your progress curves a few things spring to mind. Firstly, V0 is initial rate and should be taken from the first linear part of the curve, before it starts to level off. This is in practice somewhat arbitrary, but if you do this for your experiment here you should get different inital rates.

However, in your case this brings us to another issue, which is that, particularly in the higher substrate tests, your reaction is essentially over before you start measuring, so you will not get accurate initial rate estimates with this data. I would reduce the enzyme concentration or lower the temperature to get curves that look linear for longer (you need to slow down the reaction). Ideally, you highest substrate concebtration curve should look something like your lower concentrations do now.

I would try with bryozoans...no foraminifera!

Please provide us with a more detailed investigation of

a) lithology (carbonates, sulfates..)

b) body fossils and trace fossils others than this

c) existing environment analysis.

I suggests algal growth forms (?)

For more details and for comparison also of images see the study:

DILL, H.G., BOTZ, R. , BERNER, Z., STÜBEN, D., NASIR, S. and AL-SAAD, H. (2005) Sedimentary facies, mineralogy and geochemistry of the sulphate -bearing Miocene Dam Formation in Qatar.- Sedimentary Geology, 174: 63-96.

HGD

At first blush, I would suggest acification and/or vacuum degassing. Sparging with an inert gas is also usually effective in removing active gases like oxygen and carbon dioxide. These should generelly not influence the oxidation state of Fe(II) in solution.

Though of course the ease of this depends on your amount of avalaible sample I would presume.

The process of removing both PPC (photoresist) and PC (protective coating) layers after the reverse dry transfer method involves applying a suitable solvent to the sample to dissolve both layers. After dissolution, the layers are gently removed through rinsing with an appropriate cleaning agent, such as a solvent stream or a soft brush, followed by rinsing with isopropyl alcohol or deionized water. Once dried, the sample is inspected to ensure complete removal of the layers and is ready for further processing or analysis.

The complexity and heterogeneity of carbonate reservoirs make them particularly challenging to model and predict. While machine learning (ML) and artificial intelligence (AI) methods have proven valuable in a range of geoscience and reservoir engineering tasks, their efficacy in deducing sensible correlations of logical patterns of porosity and permeability distribution in carbonate reservoirs may vary depending on the quality and diversity of available data.

Key considerations include:

In summary, while predicting porosity and permeability distribution in carbonate reservoirs using ML/AI methods is challenging due to their highly complex and variable nature, it is not infeasible. The key lies in the quality and diversity of the data, careful feature selection, appropriate model selection, and rigorous validation. However, it's important to remember that ML/AI models are tools to assist with interpretation and decision-making, and their outputs should always be assessed critically in the context of broader geological understanding.

1. Is this result repeatable ?

2. Did you check the linearity of your system?

3. Is your data consistent with the Kramers-Kronig relations?

Yes, it is feasible to measure the effective porosity of a petroleum reservoir using various techniques such as core analysis, well logging, and seismic imaging. However, it is important to note that effective porosity is a dynamic property that changes over time due to fluid flow and rock deformation.

2. Is there a way to determine the extent to which effective porosity is reduced by attached water and oil?

Yes, laboratory experiments can be conducted to determine the impact of attached water and oil on effective porosity. These experiments involve saturating rock samples with fluids and measuring the resulting change in porosity.

3. How does effective porosity influence water and oil flow in a reservoir?

Effective porosity is a critical property that determines the ability of fluids to flow through the rock matrix. A higher effective porosity generally leads to a higher flow rate of oil and water.

4. How does reservoir pressure influence effective porosity in sandstone and carbonate reservoirs?

Reservoir pressure can have a significant impact on effective porosity, particularly in carbonate reservoirs. Increased pressure can lead to the dissolution of carbonate minerals and the creation of new porosity, while decreased pressure can cause compaction and reduction of porosity.

5. Is there a straightforward method to determine effective porosity, and what force drains oil and water from pore spaces?

There is no one-size-fits-all method for determining effective porosity, and multiple techniques may need to be used to obtain accurate measurements. The force that drains oil and water from pore spaces is generally a combination of capillary forces and gravity.

6. Is it feasible to estimate the specific retention volume of water and oil in a reservoir?

Yes, it is feasible to estimate the specific retention volume of water and oil in a reservoir using laboratory experiments and reservoir simulation software.

7. How do we determine oil and water flow rates in the absence of precise effective porosity values?

In the absence of precise effective porosity values, flow rates can be estimated using empirical correlations based on well log data or reservoir simulation software.

8. How do we control the degree of compaction and intensity of fracturing in estimating effective porosity?

The degree of compaction and intensity of fracturing can be controlled by using advanced drilling techniques and optimizing production strategies based on reservoir properties and geomechanical models.

9. How does karstification or dissolution of carbonate minerals impact effective porosity in carbonate reservoirs?

Karstification and dissolution can significantly increase effective porosity in carbonate reservoirs by creating new pore spaces and enlarging existing ones. However, the impact of these processes can be complex and depend on various factors such as the type of carbonate minerals present and the fluid chemistry.

10. How do we determine average pore sizes and fracture aperture thickness in a carbonate reservoir?

Average pore sizes and fracture aperture thickness can be determined using various techniques such as core analysis, well logging, and imaging. However, it is important to note that these properties can vary significantly across different regions of a reservoir and at different depths.

You are facing a very difficult problem! In a multicomponent (polygenic) rock (without destruction), only physical and hydrophysical parameters can be studied. To study physical and chemical processes, it is necessary to decompose the rock into separate mineral and organomineral formations and study each separately, and then, most likely, model. But I foresee that the model will not give high accuracy.

Alcohol and formaldehyde preservation solutions are commonly used in the preservation of skeletal carbonates. However, there is a concern that these solutions may leach elements from the skeletal carbonates, which could potentially affect the accuracy of isotopic and elemental analyses.Several studies have investigated the effects of alcohol and formaldehyde preservation solutions on skeletal carbonates. One study found that formaldehyde preservation did not significantly affect the stable isotopic composition of skeletal carbonates, but it did result in a slight decrease in calcium concentration. Another study found that alcohol preservation did not significantly affect the stable isotopic composition or elemental concentrations of skeletal carbonates. However, some studies have reported that both alcohol and formaldehyde preservation solutions can leach elements from skeletal carbonates. For example, one study found that alcohol preservation caused a significant loss of magnesium from coral skeletons. Another study found that formaldehyde preservation caused a significant loss of strontium from bivalve shells. Overall, the effects of alcohol and formaldehyde preservation solutions on skeletal carbonates appear to be dependent on several factors, including the type of carbonate, the concentration and duration of exposure to the preservation solution, and the specific element being analyzed.

Carbonate and bicarbonate are important ions in water chemistry. The concentration of these ions can provide information about the water's pH, alkalinity, and hardness. Here are the equations for calculating carbonate and bicarbonate concentrations in water: 1. Carbonate (CO3^-2) Calculation: Carbonate ion concentration can be calculated from the total alkalinity (TA) and pH of the water using the following equation: CO3^-2 = TA / (10^(pH-pKa1) + 10^(pH-pKa2) + 1) where pKa1 and pKa2 are the dissociation constants for carbonic acid (H2CO3). The values of pKa1 and pKa2 are 6.35 and 10.33, respectively, at 25°C. 2. Bicarbonate (HCO3^-) Calculation: Bicarbonate ion concentration can be calculated from the total alkalinity (TA) and pH of the water using the following equation: HCO3^- = (TA - CO3^-2) / (1 + 10^(pKa1-pH)) where pKa1 is the dissociation constant for carbonic acid. It is important to note that these equations assume that only carbonate, bicarbonate, and hydroxide ions contribute to the alkalinity of the water. Other ions such as phosphate, silicate, borate, and organic acids may also contribute to alkalinity and affect the accuracy of these calculations.

It depends on the starting concentration and the reagent, I think it's too general to say either all must be concentrated or not. I would look at reagent concentrations from past literature to inform your decision as that will likely dictate what your starting concentration should be for the activating agent.

For step 2, the membrane should be submerged in the carbonate mixture at room temperature, after the mixture has been prepared and any required pre-heating has been completed. The carbonate mixture should not be in a molten state, as this would likely damage the membrane.

For step 3, the infiltration process typically takes place at room temperature or slightly above room temperature, and the temperature is not usually raised until the membrane has been fully infiltrated with the carbonate mixture. Once the infiltration is complete, the membrane is typically cured at a high temperature, such as 500-800°C, to ensure proper setting and bonding of the carbonate mixture.

I hope this helps.

Hello,

The X-ray diffraction pattern of a material can reveal information about the crystalline/amorphous structure and phase composition of the materials. In the case of biopolymers, they typically show broad peaks due to the overlapping of different crystal planes within the polymer chains and also because of their semi-crystalline nature whereas, the carbonates, typically show well-defined and sharp diffraction peaks due to their highly ordered structure.

Thus, depending on the relative quantities of the two components and the level of crystallinity in each component, the diffraction spectra in a biopolymer-carbonate composite may exhibit both broad and sharp peaks. The peaks may also show shifting or broadening due to the interaction between both components in the composite. Based on this spectral analysis, one can determine the information regarding the phase composition and crystalline structure of the material.

Hope this information might help you in your XRD analysis.

You're welcome Aly Reda.

Dr. Govindarajan, greetings. If you are trying to characterize a reservoir with permeability anisotropy related to natural fractures, your biggest challenge is the inadequacy of borehole data to describe the fracture system. Several tasks must be undertaken to provide the context to extrapolate borehole data to the drainage area that would be sampled by dynamic well production data for history matching. The first task is to understand the relation of the reservoir-scale geologic structure to the regional stress field. Second, find suitable outcrop analogues to your reservoir based on what you know from the first task. Third, some attempt to develop a probabilistic geostatistical understanding of the fracture geometry and intensity at the reservoir scale from the outcrop analogue would help understand the range of uncertainty to apply to your wellbore data. The amount of uncertainty inherent in using just the wellbore data without a context to extrapolate it makes successful prediction difficult. John Lorenz has published data comparing vertical and horizontal cores that sampled fractured reservoirs. His work on the Multi-Well Experiment in Colorado would be a starting point.

I think that the relatively high pH of the bicarbonate/carbonate buffer that is often used for coating ELISA plates destabilizes protein structure sufficiently to expose the hydrophobic interior, which makes the protein more prone to sticking to the hydrophobic surface of the plate.

Hi Tristan, in my experience with carbonate ramps the role of algae would be secondary to other factors that would, in fact, control the type and distribution of algae. These factors would include the slope of the surface that the ramp grows on and climatic conditions. One good outcrop example comes to mind that you might want to check out: The Permian San Andres (note: not a misspelling of San Andreas) carbonates occur as a series of ramps that gradually give way upward into a rimmed shelf capped by the famous Capitan Reef of Guadalupe Mountains National Park. The literature is voluminous so you could research the role of algae in the ramps vs. rimmed shelves and maybe see something no one has thought of before. Cheers!

For related RG discussions; see: https://www.researchgate.net/post/How_can_stabilise_the_pH_of_01M_sodium_bicarbonate_solution_made_in_the_lab_to_80 https://www.researchgate.net/post/Anyone_know_how_to_prepare_2_M_of_sodium_bicarbonate_pH_100_solution_no_buffer

Kothapu GOPAL Reddy water is also controls the viscosity

You need special electrode for salt solutions which mostly used in marine sciences.

Cancrinite is one of the most common replacement/alteration products in Ne-bearing magmatic and metamorphic rocks under hydrothermal conditions

The Kathmandu-Banepa Basin is a "chemical waste-paper basket" for trace elements. We created a chemical atlas of that region collecting the elements of the Lesser and Higher Himalayas:

DILL, H. G., PIYA, B., ROETTGER B., TALLIG, A., DOHRMANN, R., WECK H.- D., SIEWERS, U., BUSCH, K., KHADKA, D.R. and KHANAL, R. (2002) Chemical and mineralogical compositions of fine-grained siliciclastics in the Kathmandu-Banepa Basins – Base maps for environmental and economic geology.-Zeitschrift für angewandte Geologie, 48: 30 – 48.

HGD

Divya Ganesan I looked at the paper and another one (Upendar et al. 2018). The difference between your and their amounts of Na2CO3 could be from using different volumes of flasks. The exact amount of Na2CO3 without specifying other points is very strange, it is not professional. I would ignore this discrepancy, not everything published is correct! If you still have doubts, then just use any available gas analyzer: GC, IRGA, mass-spec, etc. As the last resort, if none is available in your laboratory, you can apply the 'ancient' method of absorbing CO2 with an alkali trap and titration. The dfference between 0.22 and 1.3 is more than 5 times! Also, you can take a pure compressed CO2 from a tank or from dry ice and inject 5 ml with a syringe into a 100 cc flask to have ~5%. Then you compare it with gas mixtures prepared from Na2CO3.

First and foremost you should spend more time on describing the mineralogy/ petrography of your calcareous rocks. Are they impure limestones with a lot of detrital material or are they almost clean dolo- or limestones. Are the impurities only non-organic or also contain organic matter. In the latter case you can make use of biomarkers determined with organic chemical methods. But be cautious they can be formed in-situ or immigrated hydrocarbons. In case of true mineral impurities different mineralogical and chemical parameters can be harnessed.

Common limestones contain:

Ø calcite

Ø Mg calcite (MgCO3 = 0 to 6 %; > 11 % at T values > 15°C and higher- up 40 %)

Ø ferroan calcite (reducing environment)

Ø dolomite

Ø ferroan dolomite/ ankerite (reducing environment, late diagenetic)

Ø siderite (reducing environment, late diagenetic)

Ø collophanite/ hydroxyl-apatite

Ø clay minerals (e.g,. illite, smectite, sepiolite, glauconite...)

Ø alkaline feldspar

Ø siliceous compounds (derived from spicules, radiolarian tests, diatoms

Ø sulfate (gypsum, celestite)

Ø chloride (halite)

Now you must know which trace elements can be accommodated in the lattice of the major minerals and how can the substitute, e.g., for Ca, P etc.

Fe in calcite is a redox indicator

Cl, S, Mg and Sr are controlled by strong evaporation

Co, Ni, V, Cr are governed by the clay minerals and good redox indicators

In case of phosphates you can use the entire REE spectrum, Eu and Ce anomalies tetrad effects etc.

Feldspar is not relevant it is a diluter.

You can also use Ca, Sr and S isotopes for chemo-stratigraphy and some kind of age dating using the seawater curve.

This is a first approximation

HGD

As a practicing geophysical consultant, my approach would be to find an established field with a 3D seismic survey, and see what I can see. This is what I did years ago, perhaps you should try it. The Texas Bureau of Economic Geology has several surveys available - I have no idea of what is available in India, but perhaps since your questions are very general - it doesn't matter.

Dalibor, I agree with you.

Thank you for bringing this discussion in the research gate. My question is on LiOH mass calculation. the chemical composition of commercial lithium hydroxide (merk) which I purchased is LiOH. but in papers, I find that they assume it is hydrated (LiOH.H2O). what should I calculate? the mass of LiOH or LiOH.H2O?

thank you so much for your help :)

Perhaps help this.

Screening hydrogen cyanide (HCN) produced by rhizobacterial isolates

Assessment of HCN produced by rhizobacterial isolates was carried out. Appropriate amount of each isolate was inoculated in 250-ml flask (3 flasks/isolate), containing King’s B broth medium (100 ml) amended with 4.4 g/l glycine. Non-inoculated flasks were used as a control. Sterile filter paper strip was dipped in picric acid solution (0.5% picric acid in 2% sodium carbonate) and was attached to the neck of the flask. The flask was plugged and sealed off with Parafilm. Incubation was made at (28 ± 2 °C) for 4 days, with shaking at 140 rpm. A change in color of the filter paper strips from yellow to light brown, brown, or brick red was recorded as weak (+), moderate (++), or strong (+++) reaction, respectively. No change in color was recorded as a negative (−) reaction (Abd El-Rahman and Shaheen 2016).

Piric acid solution is a special substance.

Interesting question, Prof. Dj Flesher , in the tropic we are experiencing in some places the opposite effect "cooling and freezing", but I prefer to wait some answers from specialists.

Best Regards.

Fernando Teijeira J. C. Tarafdar sir its 693 nm

The following equations might help, but you should clarify if they are valid or if they should be modified in your case study (depending on the system there are different approxiations).

2 x TA (total alkalinity) = [HCO3^-] + 2 [CO3^-2] + [OH^-] (1)

and [CO3^-2] = K2 [HCO3^-] / [H^+] (2)

Substitute carbonate ion from equation (2) to equation (1).

Also pH = -log [H^+] (3), so you could solve to have the solution for [H^+]

If you then rearrange equation (1) to solve for [HCO3^-] you should be able to calculate the bicarbonate.

I hope this is a good start. More clarifications here:

Thank you very much for your valuable answer Thomas Mayerhöfer. I will change the accessory and try again.

Dear Dr. Ungewitter,

I am not sure whether luminescence dating could answer at least parts of that question - acknowledging that weathering and surface exposure are, of course, not the same. An overview of the technique and its applications is given by, e.g., Liritzis (2011).

Best,

Martin

Hi Dear Margherita

Barremian and Aptian limes contain abundant amounts of orbitolina and this is a good idea.But you have to make sure about the taphonomic effect of ostracoda on the chemical composition.

I refresh my suggestions with a slight modification. The marginal aspect with an increased detrital input will still exist in this sediment. In this case I would place also emphasis on the geochemistry of trace elements like zirconium (Zr) which is a good indicator of an increase in the detrital input. I used it very often successfully. On the opposite end and typical of a basinward facies is boron (B). While B is not part of routine XRF programs, Zr does so.

A good marker is the V/Cr ratio which increases with an increase of the reducing regime. Less sensitive but also helpful is the Ni/Co ratio. If you draw chemologs you will certainly get a chance to correlate them based on these elements and you can directly take a decision which way the detrital input will increase and find an antithetic correlation with the redox regime based on the V/Cr ratio that response to the bituminous organic matter.

I wish you much success.

HGD

Dear Jafar do you have also experience with Akchagyl and Apsheron Formations, they are reportedly mainly consist of lacustrian and fluvial sediments, and Gastropods and Ostracods are also reported, marine environment also apparently present, the sections I came across from Pahne Kala area consists of Ooids, Gastropods and Ostrocods I wonder the fossil assemblage belongs to Pliocene or Middle-Late Miocene. As you know benthic foraminifera of Late Cenozoic are long range and are not helpful in this case. Do you think palynological study of these Formations may help us to resolve this matter.

with many thanks

and best regards

Hesam

I'd say it's just the opposite. The activity ratios of CO3-2, HCO3- and H2CO3* are controlled by the pH value and also by the partial pressure of CO2. It is carbonate equilibria.

Thank you very much

This is now an old question. What did you do? How satisfactory was it? Vogel's Quantitative Inorganic analysis also has a titration method

Use an alkaline system with sodium hydroxide and sodium sulfide. Thank you.

Peer-review process should commonly discover such obvious mistakes even if the authors are not specialists in taxonomy.

Consider being more comprehensive with the ecological footprint:

1. https://www.footprintnetwork.org/our-work/ecological-footprint

2. https://www.footprintcalculator.org

3. https://books.google.co.uk/books?hl=en&lr=&id=WVNEAQAAQBAJ

4. https://www.sciencedirect.com/science/article/pii/S1470160X15005269

5. https://www.sciencedirect.com/science/article/pii/S0921800908003376