VKir

yatchehThank you for your help and brainstorming! That was very usefull! Thanks a lot! Small advise: http://www.careers.total.com/en/find-job-total?professional_domain=Research%20Innovation%20%26%20Development&type_search=s Cheers!

Which is almost in line with feelings of driller thats what we do prior to drill, otherwise https://en.wikipedia.org/wiki/Deepwater_Horizon_oil_spill

I agree...but i need it to by equipment based on something. Equipment cost around 10-15m$ and its different for different corrosion environmental. (geologist won't help. they are f*cking idiots They can only draw and construct geological models). is it possible, base on the formula only, to say at which proportion CO2 will be produced? 2%, 0.05% or 20%... ? CaSO4 + CH4 à CaCO3 + H2S + H2O CaSO4 + C2H6 à 2CaCO3 + H2S + S + 2H2O 4S + CH4 + 2H2O à 4H2S + CO2 CaSO4 + 3H2S + CO2 à CaCO3 + 4S + 3H2O

I will definitely take the sample of the gas in the lab. Even more i will have chromatograph on the drilling rig. But it will be during the drilling. Now why i know that is pure methane. Because geologist analysed data from the wells around. They built a geological model and performed 3D seismic. So we know pressure, length of reservoir and pressure charge from below of reservoir. Knowing that it is easy to calculate specific gravity of gas. which is 0.24sg. Which is almost pure methane at our pressure and temperature. (shortly ). We have information about 500ppm H2S from one of the offset wells. Not officially. Other information is completely confidential. Therefore i know only what i told you before. Can we calculate from formulas CO2 amount? concentration? mol? anything? CaSO4 + CH4 à CaCO3 + H2S + H2O CaSO4 + C2H6 à 2CaCO3 + H2S + S + 2H2O 4S + CH4 + 2H2O à 4H2S + CO2 CaSO4 + 3H2S + CO2 à CaCO3 + 4S + 3H2O

I've realized today that 900 deg C is needed for reaction CaCO3+H2S=CaS+HOH+CO2. Which is not possible in my conditions so its a crap. But i did something else: 1. Summary dataØ Carbonate reservoir up to 860m length Ø Dry biogenic gas; 0.24sg (at reservoir conditions) expected Ø Porosity ranging from 13 to 24% and permeability ranging from 10 to 200mD Ø Confirmed 200-400ppm of H2S during DST on xxx Ø Temperature in the range 54-74 deg C 2. Analysis 2.1. Introduction in the theoryTo have a clear understanding of the CO2 formation process we shall review first the process of H2S creation in the carbonate environmental as these to gases are associated to each other. The three main sources of H2S in hydrocarbon reservoirs are: Ø Bacterial or microbial sulphate reduction Ø Thermal decomposition of organic sulphur compounds in the oil Ø Thermo chemical sulphate reduction (TSR) Bacterial sulphate reduction is the common source of H2S in recent sediments and low-temperature reservoirs, but generally leads to low levels of H2S in gas (<5%). This source is considered to be limited to temperatures below 80 deg C. Thermal decomposition of organic-sulphur in oil occurs during heating and petroleum generation but can contribute < 5% H2S to gas because of the limited amount of organic sulphur bound in these materials. TSR is the only source which contributes high concentrations of H2S. TSR is the thermally driven reaction (225degC > temp > 140degC) of sulphate (anhydrite, CaSO4) with hydrocarbons producing combinations of H2S, carbonate minerals (calcite, CaCO3), CO2, elemental sulphur (S) and water (H2O). The overall process may be written: Anhydrite + hydrocarbons à calcite + H2S + H20 + S + CO2 Understanding the specific reactions that occur during TSR is critical to the prediction of H2S / CO2 concentration. For preparation of this particular paper different study were reviewed where authors adopt an integrated approach (gas chemistry, petrography, mineralogy and carbon and sulphur isotope analysis of minerals and gases) to determine which reactions occur during TSR. Even more this document is a short review and summary of the core information explaining the process. 2.2. Chemical approachConditions for the TSR are: Ø Temperature in the range 140 – 225degC Ø Existence of anhydrite as it is only initial sours of S Ø Hydrocarbons Stoichiometrically balanced reactions: CaSO4 + CH4 à CaCO3 + H2S + H2O CaSO4 + C2H6 à 2CaCO3 + H2S + S + 2H2O *The initial reaction between hydrocarbon and anhydrite. Similar with C3, C4, C5, C6 and C7. It is confirmed by modeling that anhydrite and methane are thermodynamically unstable together under most plausible digenetic conditions. Anhydrite and methane are only stable together at either very high ratios of H2S to CH4 fugacity (concentrations) or very high temperatures (> 225deg C). The above presented reactions continued by: 4S + CH4 + 2H2O à 4H2S + CO2 CaSO4 + 3H2S + CO2 à CaCO3 + 4S + 3H2O To be noted that the gas data show (Khuff Formation, Abu Dhabi) that alkanes with C2+ are consumed at the earliest stages of TSR. Thus reaction (2) is more favorable then (1). An addition reaction (2) also provides a free S for the reaction (3), which is the most valuable in terms of CO2 formation. Analyzing that process we can conclude that concentration of H2S is higher in dry gas, but is not increasing too much: Ø For instance for the dry gas option (1), one molecule of anhydrite and molecule of methane will give one molecule of H2S. Ø Whilst for the wet gas option (2+3) one molecule of anhydrite and two molecule of methane will give five molecules of H2S Basically that means that with time anhydrite / C2+ / CH4 will be transformed to the calcite / H2S / CO2. Of course reaction will be thermodynamically dependant and therefore will be equilibrated as soon as critical ratio of H2S to CH4 fugacity will be reached. The CO2 content also increases slightly during TSR. CO2 is consumed by reaction (3), but if reaction (3) is immediately followed by reaction (4) then this should leave CO2 constant. The only way that CO2 can increase is by reactions (2) being followed by reaction (3). In any case we can see that amount of CO2 produced by reaction (3) is significantly lower than H2S. And therefore concentration of CO2 in the gas will be always lower than H2S. That is all at the moment. The one more question: 4S + CH4 + 2H2O à 4H2S + CO2 Does the formula above means that i will get 1/5 of CO2 and 4/5 of H2S???? i didn't get it even thru google translator... youtube is locked on my f*cking laptop :/ Exactly!!! BUT: it is not calcite. It is porous carbonate. Chemically both are the same shit, but molecular structure is different. You are wrong. Its confirmed by 10000 wells drilled in carbonate formation. H2S is very common there as well as CO2. Why? i dont yet know exactly. Close ) I will correct a little bit: We know there is methane with H2S. We don't know is there CO2 (it is different from : "there is no CO2"). I want to predict CO2 presence and concentration in case of presence. 70 million years... it is a Cretaceous period.

There is no way to measure it...the well is not drilled yet. The idea is to predict CO2 concentration based on any logical hypotheses and data we have. Geologist won't help with that as it is purely chemical question. Perhaps i've provided excess of information. Let me try to simplify: There is a pure Methane with 500ppm of H2S Gas is trapped inside porous carbonates. CaCO3 80 deg C, 450bar, no light, time 70M years Questions for chemists: Does it react? CaCO3+H2S=CaS+HOH+CO2 Any possibility to calculate CO2 (%,ppm,mol...anything) based on H2S? Thanks

Anyway, thanks for review!

Hi Guys! Sorry for English. Friend (russian) of mine suggested me to use this platform for the chemical related question. Hopefully someone will understand and help me. I'm working for oil and gas company and i'm going to drill an exploration well at the unknown area. So, the situation is: Well will be drilled down to 4250m TVD/MSL (true vertical depth/mean sea level). Offshore with 1700m of water depth. Thus only 2550m of formation (earth, ground) will be drilled. We will drill thru the claystone, salt and thru the CARBONATE reservoir. 900m of reservoir full of gas. Top of reservoir at 3340m. Bottom at 4200m. Carbonate reservoir. Reservoir is absolutely permeable porous formation. Full of dry gas. Dry gas means Methane. CH4. Concentration is not known. Some small part of C2, C3, C4 can exist, but not to much. Based on the offset data (wells around, to far, but still some information) and geological information (comparison, seismic data and so on) we predict gas with 0.24 s.g. (specific gravity/water) at the reservoir conditions. Note: we use specific gravity, but not density. Methane 0.55SG / air at standard conditions. Or water related if we speak about gas at reservoir conditions. It's simplify other (pressures) calculations on the later stage. Reservoir conditions: 80 deg C, 444bar at 3340m and 464bar at 4200m. Gas 0.24sg/air. Sour gas. Up to 200-500ppm of H2S confirmed by other offset wells in the region. The presence of CO2 is likely in case of H2S occurrence (usual sour gas association in carbonate reservoirs). Question: Is there any way to predict CO2 concentration depending on H2S concentration (%, ppm)? Thank you guys for any help and explanations!

Hi Guys! Sorry for English. Friend (russian) of mine suggested me to use this platform for the chemical related question. Hopefully someone will understand and help me. I'm working for oil and gas company and i'm going to drill an exploration well at the unknown area. So, the situation is: Well will be drilled down to 4250m TVD/MSL (true vertical depth/mean sea level). Offshore with 1700m of water depth. Thus only 2550m of formation (earth, ground) will be drilled. We will drill thru the claystone, salt and thru the CARBONATE reservoir. 900m of reservoir full of gas. Top of reservoir at 3340m. Bottom at 4200m. Carbonate reservoir. Reservoir is absolutely permeable porous formation. Full of dry gas. Dry gas means Methane. CH4. Concentration is not known. Some small part of C2, C3, C4 can exist, but not to much. Based on the offset data (wells around, to far, but still some information) and geological information (comparison, seismic data and so on) we predict gas with 0.24 s.g. (specific gravity/water) at the reservoir conditions. Note: we use specific gravity, but not density. Methane 0.55SG / air at standard conditions. Or water related if we speak about gas at reservoir conditions. It's simplify other (pressures) calculations on the later stage. Reservoir conditions: 80 deg C, 444bar at 3340m and 464bar at 4200m. Gas 0.24sg/air. Sour gas. Up to 200-500ppm of H2S confirmed by other offset wells in the region. The presence of CO2 is likely in case of H2S occurrence (usual sour gas association in carbonate reservoirs). Question: Is there any way to predict CO2 concentration depending on H2S concentration (%, ppm)? Thank you guys for any help and explanations!