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Enhanced Oil Recovery - Science topic

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pre-reviewed rejections
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There are several steps you can take to reduce the risk of your manuscript being rejected before it is reviewed, or "pre-reviewed rejection". These include:
  1. Understanding the scope and focus of the journal: Before submitting, carefully read the guidelines and the aims and scope of the journal to ensure that your research aligns with their interests.
  2. Checking for format and length requirements: Make sure that your manuscript meets the required format and length specified by the journal.
  3. Avoiding plagiarism: Ensure that the content of your manuscript is original and properly cited. Plagiarism can result in automatic rejection.
  4. Conducting a thorough literature review: Ensure that you have thoroughly reviewed the existing literature and that your manuscript makes a significant contribution to the field.
  5. Seeking feedback: Consider getting feedback from colleagues or professional editing services to improve the quality and clarity of your writing.
  6. Making a strong argument: Make sure your manuscript includes a clear and well-supported argument that highlights the significance of your research.
  7. Following submission guidelines: Carefully follow all submission guidelines, including the format of your manuscript, the use of keywords, and any other requirements.
By following these steps, you can increase your chances of having your manuscript reviewed and potentially published.
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CMG-STARS utilizes the average velocity of each grid block for the calculation of the capillary number. I'm trying to print these calculations in .OUT file. In the STARS user guide (Appendix D), it is mentioned that a keyword called "DBG_VEL" is responsible for printing these calculations. However, I can't find this keyword in any part of the software!! I'll be grateful for any help and clue.
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Hello! You could find the velocity option in I/O controls. Select with Simulation with output results followed by Grid in Items in Simulation Results File. You can select the VELCAPN for capillary number calculation. Hope this solves your query.
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more details about the effect of concentration, temperature, salinity and hardness on apparent viscosity
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I want to know about the commercial surfactants to compare and for cost analysis. Thank you.
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Dear Patel,
As far as I know, varied surfactants are utilized in EOR; including anionic, non-ionic, and cationic surfactants. Depending on the type of reservoirs, desired surfactants are chosen.
Take sandstone reservoirs as an example; it has been reported that anionic surfactants would be the best choice in the mentioned type of reservoirs.
I highly recommend you to read the below paper which is come in handy concerning your question:
""Most common surfactants employed in chemical enhanced oil recovery""
I hope this helps you.
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Inter-facial Tension (IFT), Combined Chemical (CC), Mathematical Model (MM)
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Much chemical process modelling and/or simulation work can be done with the widely-used Microsoft’s Excel.
Application example ― Simulations carried in Excel 5.0 with Visual Basic for Applications (VBA) macros ― The recursive least squares algorithm (RLS) allows for (real-time) dynamical application of least squares regression to time series. Years ago, while investigating adaptive control and energetic optimization of aerobic fermenters, I have applied the RLS algorithm with forgetting factor (RLS-FF) to estimate the parameters from the KLa correlation, used to predict the O2 gas-liquid mass-transfer, while giving increased weight to most recent data. Estimates were improved by imposing sinusoidal disturbance to air flow and agitation speed (manipulated variables). The power dissipated by agitation was accessed by a torque meter (pilot plant). The proposed (adaptive) control algorithm compared favourably with PID. Simulations assessed the effect of numerically generated white Gaussian noise (2-sigma truncated) and of first order delay. This investigation was reported at (MSc Thesis):
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As I am working on the surfactant for enhanced oil recovery processes but I am from the chemistry field not from engineering so, I would like to dive deep into interfacial tension what is happening between molecules with water/surfactant/oil.
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Recently encountered such a situation in the lab. What could be the reason for this type of behavior? looking for answers.
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In basis of my experience, as much as HLB of surfactant is less, the potential of foam generation and foam stability is higher. CMC is a function of HLB, but even high HLB surfactants can provide ultra-low IFT conditions at usually high concentrations. For example: SDBS is an anionic surfactant with HLB ~ 21, however, it can provide the IFT values less than 1 mN/m (0.82 mN/m) at 5000 ppm (CMC) [10.1021/acsomega.0c04464].
In other words, the topic of foam is not as dependent on IFT as it is on HLB.
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How can i increase the pH of sea water to 12? Because when i adding NaOH to seawater the pH does not go above 10 and begins to precipitate.
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Coloque el agua de mar en un baño de maría con hielo para mantener el agua fría y agregue lentamente NaOH hasta que alcance el PH 12.
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Hi there I am simulating a pore-throat micrometer model with two outlets at 120 and one inlet at 120 degrees. Pore is 35 microns, inlet and outlets were 15 microns but for an oil-saturated condition, I didn't get 99% oil recovery at 0 and 60 degrees contact angle. First, I refined the mesh and made it more uniformed even then I was unable to get oil recovery in the 90s. I, therefore, increase the length of the outlets to 40 microns. This results in 99% oil recovery at 0 degrees contact angle but when I changed the angle to 60 degrees and oil recovery is fluctuating between 30 and 50% and the flow time has reached 0.35 seconds. Can you please suggest what shall I do to get at least 97% oil recovery at 60 degrees contact angle. Where could I have mistaken?
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Thank you, Clare. I increased the throat/ outlets' length and recovered 99% Oil at contact angle of 0°
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How to use Eclipse simulation using nanotechnology for EOR
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can you please provide its datafile, if you have?
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The term 'Huff-and-Puff' is usually used for a single-well stimulation process in which the fluid is injected into a single well, the well is later shut-in and the fluid is allowed to soak into the oil for a period of time
BUT
What would be the correct way to refer to this method: EOR or IOR or both?
Thanks everyone for Opinions
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In addition to Sergei G. Parsegov 's contribution, IOR is used to describe any operation that increases Oil production beyond the primary non-stimulated recovery. This broad definition encompasses drilling In-fill wells, Well stimulation (acidizing and/or fracturing), Secondary recovery (water/gas injection), EOR (thermal, miscible, Chemical), Horizontal/Multilateral wells...
That being said, EOR is a subset of IOR. The term EOR is used to refer to any intervention technique that would alter the reservoir fluid properties to increase oil recovery. i.e. (thermal - Oil viscosity reduction, Chemical - Wettability alteration, Miscible - Interfacial/Surface tension alteration).
"Huff and Puff" method is a type of thermal EOR because it alters the Oil viscosity, and therefore it is both an EOR technique and broadly speaking an IOR technique.
For more information, see the attached files:
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I have noticed that the Applied Energy journal publishes researchers works that are related to the enhanced oil recovery (EOR). However, when I went through the journal classifications, I get confused on which one I should choose for this type of papers. Thanks
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greetings
you could choose option 2 , because The EOR methods focuse on improvemnet of energy system(reservoir)
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Looking for interest in developing a novel system to produce pure CO2 from methane. The application is for EOR projects where a source of CO2 is not readily available, but there is, or will be, associated gas with oil production. Rather then flaring this gas, it would be used to generate a pure CO2 stream for re-injection, as well as electrical power for the injection system. I'd like to discuss the thermodynamics and practicalities. System could also be used for geosequestration from a power gen system, but may only be break even...
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Hi, I am using the latest Ansys-Fluent 2019 R3 and simulating pore-throat geometry (Wen 2017). My results are not coming as per the research paper I want to validate. I am working on Enhance oil recovery in porous media. And according to paper if the contact angle for wettability is greater than 90degrees oil recovery factor is between 60 -75%. But mine is coming almost 100% where flow and volume fraction courant number for pressure-velocity Coupling scheme with Volume Fraction (modified HRIC) are 200 (default). Is this error due to the high courant number. If yes, then what value should I be selecting?
I can send you my case and data file if required.
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As a general rule of thumb, if there is unsteadiness and you want to correctly capture it, CFL must be O(1), independently from the stability. However, it might, or not, be the cause of your problems.
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Is the role of carbon dioxide when injected in the oil-bearing formation limited to the swelling of oil only or it has another role, such as reducing viscosity or anything else?
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Let's structure things simply. The first role of CO2 in oil revery is the role of sweep agent and pressure maintenance (for which CO2 can compete with immiscible gas or water). Secondary roles include swelling of residual oil and viscosity reduction of displaced oil both of derive from CO2 miscibility in oil. Other more complex and least ascertain effects can also exist. If establishing comparisons one need to make sure to isolate effects. As CO2 assisted recovery is sometimes operated in tertiary mode (after primary depletion and sweep by dry gas or water) one need to be a bit careful to sort attribute impact to one role or the other.
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How does the process of large scale hydraulic fracturing (in a naturally fractured reservoir) for a granite (for Enhancing Geothermal Energy-system) differ from that for a limestone (for Enhanced Oil Recovery)?
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I agree with Hanyi Wang .
Limestones, due to their chemical nature, have much higher cohesion and tend to fail preliminary in Mode I (tensile). The majority of preexisted natural fractures are filled by calcite cement and are challenging to reactivate both in shear and in tensile.
If horizontal stress anisotropy (SHmax-Shmin) is high enough, multistage hydraulic fracturing of horizontal wells will lead to a family of planar tensile fractures partially filled by proppant. This system of high fractures surface area will create a strong anisotropy of conductivity in the direction of current SHmax. Meanwhile, EGS fracture system conductivity will be more isotropic.
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Chemical engineering is a very diverse field of engineering. Current research areas in this field are plenty. Here are some of the major areas where currently work is being undertaken:-
Materials: Developing and tuning the properties of materials for particular uses like catalysis, strength, durability, conductivity and biocompatibility. Nanomaterials form a major part of it.
Microfluidics and Nanofluidics: Understanding flows at the micro, and nano levels in small channels enable us to develop portable instruments which can check for various diseases using body fluids, can be used for catalysis and making chemical sensors for a water purity test, gas leakage detection etc.
Regenerative medicine and Nanomedicine: Developing novel methods of drug delivery, growing organs and tissues out of stem cells, cancer and tumour detection, bio-imaging.
Bio-inspired material development: Application of biological rules and principles for a material design like gecko-inspired adhesive, mosquito inspired needle. You can find many such examples from nature.
Fuel cells and electrochemical Engg.: Fuel cells have zero-emissions and are quite efficient. Research is being done to find better catalysts, make cells lighter and more cost-effective.
Computational Fluid Dynamics: It is a very extensive field and is quite in use for getting accurate results for many real-world processes. It is now employed at the preliminary stage to judge the feasibility of a process.
Rheology: Most fluids we encounter in our daily lives are non-newtonian, e.g. toothpaste, hair-gels, gelatin, paints, adhesives. Study of their flows and their stability has a lot of industrial importance.
Control system design and plantwide control: Though this area are quite inundated, but it forms the core part of chemical engineering. With the advent of machine learning and AI, more can be explored in this area to make control decisions more reliable, safe and economical in operating complex chemical plants.
Few other important areas of the chemical engineering applications arealso as follows:
Nanotechnology
Polymers
Oil and Gas
Industrial Waste Management
Renewable Energy
Optimization Techniques in Processes
Products and Quality control
Processes operation and equipment design
The organisation of condensed matter
Separation processes
Predictive models
Fuel Cells
Biomass
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I would like to thank all of you who dedicate part of your free time to my question. Your answers stimulate my thinking on the subject. I am also glad to get information from people from various countries of the world.
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Suggest any book for Microbial enhanced oil recovery (MEOR).
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I have extensively researched MEOR (Microbial Enhanced Oil Recovery), and published my thesis in 2014. I am still working on an English version, but if you care to see the original, Portuguese version, see: http://bdtd.ibict.br/vufind/Record/UERJ_cde857c1488183c8bc51288b29567d9e
Good luck…
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I need to use crude oil sample for my experiment. The experiment is about CO2-oil-brine-rock interactions.
Is there any sample commercially available and well characterized?
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You can get a small quantity of a well characterised oil from the North Sea asking to the Norwegian Petroleum Directorate
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There are several options of gases to be re injected. Some companies re-inject natural hydrocarbon gas. It has commercial value and I am wondering why do not they inject CO2. Injecting natural gas seems to me like injecting money. Why do they do so. Is it because of its difficulty to capture? Is it because simply company has no source of cheap CO2?
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Gas source, if u hadboth, you´d try to separate as much CO2 as you could to inject/re-inject (tipically "dragging" 5-10% combustible gas)
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Hello everyone,
I am running a partitioning test for a surfactant mixture (Anionic/Nonionic) solution with crude oil. I am using HPLC with ELSD to measure the surfactant concentration after the test.
In some samples, i actually witnessed an increase in the surfactant concentration after the test to more than the initial value.
Is that normal or do i have to repeat the test because we always expect the surfactant concentration to decrease because the surfactant will partition into the oil phase. Or that's possible and there's a chemical reaction between the surfactant and the crude oil and that probably causes the surfactant concentration to increase more than the initial concentration.
Thank you
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In principle, the surfactant molecules should form micelles that include oil components. This may lead to apparent increase of surfactant concentration in aqueous phase when measuring with ELS detector. You should use another method of surfactant concentration measurement.
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In polymer enhanced oil recovery we should choose polymer according to reservoir properties. Is there general kind of polymer to choose approperiately?
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Why Polymers?
Polymers are essentially used to circumvent ‘coning’ or ‘fingering’ patterns whereby potentially large volumes of oil-saturated rock are bypassed by the water flood and the oil therein is not recovered.
The viscosity of injected water is increased with polymers in order to improve the sweep efficiency of the water flood.
This reduces the tendency of water to bypass or finger through oil, thereby sweeping more oil toward production wells to significantly improve recovery.
Polymer flooding can roughly enhance recovery by around 5-30% of OOIP.
Cost of polymer flooding is relatively lesser than that for water flooding as polymer flooding leads to decreased water production and an increased oil production.
Efficiency of polymer flooding is around 1 – 2 pounds of polymer per bbl of incremental oil production.
Polymer essentially increases water viscosity and reduces water relative permeability and eventually increases the oil recovery resulting from enhanced fractional flow.
Non-Newtonian hydrogel polymers
1. Partially hydrolyzed polyacrylamide (HPAM) - Synthetic Polyemr
2. Xanthan Gum – Biopolymer
Apart from using the right polymers, we need the following to achieve enhanced reservoir efficiency:
1. The lag time between injection and production response should NOT be high; and this means that the average distance between the wells should be as smaller as possible.
2. The fluid property of the oil in the reservoir should be such that the mobility ratio should always be favourable on the addition of the polymer solution.
3. Reduced injection rate of polymer.
4. Oil viscosity variation resulting from thermal and shear degradation (during injection) should be monitored as a function of reservoir temperature and polymer’s residence time within the reservoir.
5. Injectivity loss (polymer filtration ratio) and poor inversion of liquid emulsion polymers during polymer injection is critical.
6. Improved characterization of polymer rheology for low viscosity floods.
7. Lab test results should be used with care as the lab set up cannot reproduce the requirement of high shear regimes in order to invert the emulsion polymers.
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Carbon capture and storage (CCS) was one of the most promising technology for CO2 emission reduction without large-scale transition to renewables. Moreover, there are such options like CCS-EOR which can be really profitable even without state support. Or highly promising extraction of coal seam gas with help of CO2. But during the last years i saw some articles argued that expectations from such projects will not come true, and further research in this area is the waste of time and money. What do you think about it? I mean not only the influence of these technologies on the fight against global warming but also their economic and technical potential in the closest future.
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Difficult question. There are many technical and financial issues - with others in this conversation have intelligently identified. I am keen to point out two things:
a) with a CO2 emissions tax in Norway (for over 25 years), real industrial-scale CCS project can be realized (there are also similar projects in e.g. Canada and USA)
b) Do humans really want to use valuable hydrocarbon chains without emitting the CO2 molecules to atmosphere?
There are two simple answers to (b) either "No - stop using fossil fuels" or "yes - so lets use CCS"
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chemical flooding in Enhanced Oil Recovery
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At elevated temperatures, (a) the surfactant adsorption density would have come down; (b) the changes in surface energy would have got enhanced; and (c) the changes in the surfactant's concentration would have got mitigated. Off these three aspects, the second aspect on the enhanced changes in surface energy with increasing temperature is against the principle of using surfactant flooding. Thus, the reduced surfactant adsorption density at elevated temperatures, is associated with the enhanced changes in surface energy. And, this is where the thermal stability becomes very sensitive in picking the right choice of monomers.
In addition, the monomers will depend both on component as well as on its composition at elevated temperatures.
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Enhanced Oil Recovery
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Dear Allah,
It is a nice question. To my experience, the ammonium hydroxide (as a polymerization catalyst) is added to the solution for promoting polymerization process. This is to be done by reducing the time needed for polymerization to be activated. It is also known that polymer is more stable when ammonium is added.
Please note that the amount of ammonium (free or hydroxide) to be added in the polymer solution should be in economically determined, but there are some (let's say) rule of thumb.
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polymer used in Enhanced Oil Recovery
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Monomers? The gelling agents in fracturing fluids are generally polysaccharides.
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I am performing core flooding experiments as a research work. I started by initially saturating the core sample by the crude oil (Stock tank oil). However, I did not do enough vacuuming of the core sample before saturating it. I tried to measure the base permeability of the core with the crude oil but I did not get any stabilization on the pressure drop across the sample. Could the problem be attributed to the insufficient vacuuming?
How can the problem by solved?
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I completely agree with the answer given by Dr. Foroozesh. I must also add that the standard process for any type of core flooding follows an initial vacuum and dryness process. Vacuuming process assures that the core gets fully saturated with desired fluid, making an accurate measurement of effective porosity to that fluid, and also a fast stabilized flow regime for permeability measurements. Darcy's law stands only for a core being fully saturated with the fluid. In case vacuuming is not sufficient, you would not be sure whether the core gets fully saturated or not, air/water might be trapped.
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We are trying to set up a laboratory Enhanced Oil Recovery (EOR) system for pilot monitoring using hot water as injection fluid. We are having difficulty in strata formation that can withstand pressure without collapsing. Can anyone help? Thanks
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shear failure (collapse) may occur at low pore pressure for typical geomechanical environment. To model heat transfer you most likely need CMG STARS. You may also consider tNav (http://rfdyn.com/tnavigator/tnavigator-modules/thermal-compositional-simulator/).
For failure model you may use near wellbore analytical solutions for sanding in 1D/2D.
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to drill a well we required rig and its accessories.These machinery empowered by diesel engines (mostly).
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I would be interested to know the diesel consumption per metre borehole. Any suggestions?
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I would like to know whether CO2 as gaseous phase not supercritical phase has been used to enhance oil recovery. If so could you please refer me to the reference?
With best regards
Ebraheam Al-Zaidi
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This article is devoted to the use of CO2 for EOR and perspective of using this metods in Azerbaijan oilfids.
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I'm conducting desk study of any possible papers written on simulation of oil well enhanced oil recovery using gases other than conventional CO2, N2 and CH4. Why do we need to stick to these gases? Can we use hydrogen, or carbon monoxide or syngas (H2+N2+CO+CO2) directly and inject it into the oil well for Enhanced oil recovery? If yes, will it increase the recovery rate or decrease? or will it create more troubles inside the well?
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Azeez Aregbe is correct. CO is highly poisonous and cannot be safely used for EOR because there is always the danger of leaks; for this reason, syngas cannot be used either, since it contains CO. Hydrogen would not be useful because it would be more prone to leaks, and could lead to embrittlement of the steel well casing, especially at EOR injection pressures.
Gas used for EOR acts as a solvent or mobilizing agent to make the oil more "flowable". CH4 would work fine, but CO2 is injected as a supercritical fluid, which is a very good solvent for crude oil. Gases, however, do a poor job of displacing oil, so EOR is usually done in water-alternating-gas (WAG) cycles in which the CO2 and water are pumped into the injection wells in alternating cycles. The CO2 makes the oil flow more easily, then the water displaces the oil, pushing it towards the producing wells. 
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It does not necessarily have to focus on CO2 itself can be about gas flooding in general. 
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Hi Donaldo,
I've been modelling enhanced gas recovery (EGR), but I am guessing that the numerical method and physics are not a world away from EOR, so it may be useful if you are working on reservoir flow modelling. Our first paper models EGR using the finite element method (COMSOL Multiphysics) without formation water, and shows the effect of CO2 injection rate and physical dispersion on CO2-CH4 mixing. This is for a benchmark, horizontally layered reservoir geometry.
We submitted a follow-up paper studying the role of well perforation depth and the effects of formation water on EGR, and are hoping to hear back on this within the next few weeks.
Best,
Milan.
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this is used in BAC calculations
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We have been doing field research that recruits real-world drinkers from a bar at different BrAc levels (highest thus far was .29). We do administer a drinking questionnaire at the end of the study where we ask participants about drinking habits and other illegal drugs they have been consuming. The biggest problem of course is the social desirability of these answers and the extent to which this episodic recall is accurate at these high levels. 
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We are working on finding solution of models of imbibition phenomenon which occurs during oil recovery process. In this phenomenon water is injected in oil saturated porous medium and it displaces oil from it.
In the literature which I have refered so far, there are some papers in which they conclude that saturation of water increases as distance increase and there are some other papers in which they show that as distance increases, saturation of water decreases.
In mathematics, we can conclude both of this by assigning appropriate boundary conditions.
My doubt is which one is physically consistent ?
As I understand, the saturation of water should increase as we go further but that depends on water injection rates also.
But most of the standard papers show that saturation of water decreases as distance increases.
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based on my studies, I realized that when your porous medium is considered to be triangle Unit it will decrease when your pore size decreases ,however when it is circular tube the water pour the biggest pores and move to the smallest one then saturation increases in imbibition. I hope t was related to ur topic :S and dipak can I ask you worked on which equation to describe them mathematically? 
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I am investigating the mechanisms of polymer flooding in glass micromodels and need a syringe pump to inject the solution into it. What type of pump should I use? Ordinary or High pressure? How much is the range of injection pressures of a solution with about 50-100 cp viscosity in a micromodel?
Thanks.
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Actually there are many determining factors:
-You should know the absoloute permeability of the micromodel, if it is in mD scale, you might see high pressure but in this scale you should know the maximum working pressure of your micromodel because there might be risk of breaking the micromodel (generally they are expensive especially if they are produced specially)
So I suggest you first measure the permeability of micromodel with N2 in low pressure but you need to know cross-sectional area length etc of your micromodel (according to the Darcy law).
- if permeability of micromodel is very low, you might need high pressure pumps (which are expensive generally)
good lucks
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Greetings to Everyone,
Hope you are doing well. We want to make a lab facility to do research in EOR for our waxy oil on land. Is there any SOP or Best Practices to refer to while making this lab setup ?
Looking forward to your reply!
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You have to be specific on your needs. EOR research can focus on subsurface or surface behaviour and facilities. Once you have decided on your scope, the fastest way would be to contact equipment suppliers. If you wish to develop your own rigs, the literature is full of laboratory studies.
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What are the international standard regulations for the quality of produced water  for reinjection purposes in oil reservoirs? What is the maximum micron (ppm) of dispersed or emulsified oil in produced water to be used for re-injection to improve oil recovery?
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Thanks Kevin,
Do you have a reference for the 15ppm?
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I see that you are working with saline waters. I have a colleague working with oil well recovered frack water for raising Cynodon dactylon, Bermuda grass. He might be interested in discussion
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Dear Edo
Indeed, I do not work on saline sediments, but it would be interesting to start such discussion. Thanks for your comment.
Polla
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Do you use isuprel or NTG?
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Both can be used. However positive response is higher with NTG. In our institution we generally use NTG because of better tolerability compared to isoprenaline. 
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Is there any compiled list of data that show the types of crude oil and their percentage of oil, water and gas?
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You may see API specs.
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For oil wet carbonate rocks, capillary pressure is important or we can negligible as simulator input?
 I used black oil model in eclipse, I need your knowledge
thanks
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Of course it is important.  But the difference in carbonate rocks is that the pore geometry is very much more varied and so the model that you use must include a much wider range of capillary dispersion.  Think only of the effect of secondary porosity.  This range of capillary values throughout the rock will depend on a host of porosity-related factors, ranging from lithology through seminary process to diagenesis and fracturing. This is undoubtedly complex, and is the subject of numerous papers.  Whether you are able to capture this is another question.
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This Nanofluid will be used to enhance oil recovery in a lab experiment and measure their effects on it.
Thanks in advance.
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Typically, dispersivity decreases as salinity increases, I guess this is happened because the electrostatic interactions lead to form bridges among them.
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I have developed some measurements for both storage modulus (G') and loss modulus (G'') for different diluted polymeric solutions. A classification for the rigidity of the polymers is required. 
I found a paper which suggests to provide the ratio of storage and loss modulus as a possible way to discuses about the rigidity and flexibility. 
Does anyone have a better suggestion? How can be justified the strange behavior of PEO (polyethylene oxide)  compared to water?
I have uploaded the results here!
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The percent of cross linking compared to linear chain length is usually the determining factor in flex and rigidity.
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Hello,
I am looking for a thermo-responsive liquid which will not mix with water. The idea is to have two small connected reservoirs , one containing this liquid and the other having water. Then, upon heating,the thermo-responsive liquid will push out water from the other reservoir by expanding.
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The cheapest and most commonly available termo-responsive liquid  I know (that would not mix with water) is cooking oil.
Another way to avoid the first liquid mixing with the water in the other reservoir is to insert a small plug of mercury in the horizontal tube connecting the two reservoir. In this case, the first liquid can be water (perhaps coloured water). This set-up would minimize any non-thermal effect due to the possible different density of the two liquids.
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Multi-Phase Fluid Flow: Reservoir Engineering / Unconventional Hydrocarbon Resources: 
Can anyone enlighten me on – whether – where could I get the field data on the following four parameters: (a) well-bore radius; (b) effective radius; {And it’s respective}   (c) well-bore pressure; & (d) effective pressure; [along with the details of fluid compressibility] associated with an OIL or GAS RESERVOIR or SHALE GAS RESERVOIR or TIGHT GAS RESERVOIR?
I am looking for reference materials or any other related reports. Your help in this regard is highly appreciated.
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Desr Sir, Thanks for the references which involve fluid flow through fractured reservoirs. However, I am specifically interested in securing the details of pressure distribution as a function of space and time in a fractured reservoir. Anyway, thanks for your time. 
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Analytical calculation of recovery factor, GOR, BHP for different injection rates. 
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There are many factors affecting the correlations you mentioned. There is no a generalized formula for all oil fields and case studies. However, you can generate empirical formula given each case study. You can also use e Design of Experiments approaches to conduct that.
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Dear Sir/Madam,
I am using immersion heater and it has specs(3kw 418v)and it does have thermostat which can be controled temperature from 30 to 110 degree.
I am using this heater to typical drum (200 ltrs steel drum), the drum containes waste cooking oil (solid state). As you can see the dirty drawing( sorry about my hand drawing), most of oil melted but some of oil is still in solid state.
I calculated that the oil should have completely melt in 3hours at 15degree (atmospheric pressure) but even after 7 hours, still in same state like the hand drawing.I set the temperature of heater @ 80degree, thus the heater turned off at 75~76degree( its what the manufacturer says) automatically.
Does anyone can let me know the solution of even the reason for this..
Please let me know sirs..
best regards,
Kim
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You need to stir also or move the heater to different places in the drum. Convection of heat is (evidently) not sufficient.
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Hi Everyone.
As you probably know that one item that is involving during injection of low salinity water flooding into Carbonate reservoirs, is the presence of Anhydrite. Austa et. al published a paper “Conditions for a Low-Salinity Enhanced Oil Recovery (EOR) Effect in Carbonate Oil Reservoirs”
On their paper, they mentioned that “The dissolution of anhydrite increases as the temperature decreases. Sulfate is a catalyst for the wettability alteration process, and it is important to have a maximum concentration of sulfate dissolved in the brine.”
On the other hand, further studies by Awolayoetal.(2014) suggested that smart water with four times sulfate concentrations might be the optimum sulfate concentration.
Based on all aforementioned papers, I like to ask following questions:
1-      Is there any other limitation or valuable range for anhydrate concentration during Low Salinity water injection for Carbanete reservoirs? Generally speaking, what is role of anhydrate for LSW of carbonate reservoirs?
2-      As I went over the literature, I noticed that there are two kinds of chromatography for evaluating ions concentrations. These instruments are “ICS 3000” and “LA ICP-MS”. Are there any other types of instruments for counting ion concentration? Does anybody know more information about that?
3-      Finally, I have seen that some authors illustrate profile of the ion concentration vs P.V injection. How can I generate such graphs? Are they analysis produced water after each pore volume injection? what is the procedure of generating those plots?
Thanks,
Alireza.
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well I'm not in your field. bit my one class in petroleum engineering involved modeling the reservoir as dimensionless. therefore pore volumes injected is really just flow rate used to measure time. for ion concentration we would use the error function to model diffusion effects. I am unable to type the math on my phone but check out multicomponent flow modeling, not sure it you're referencing multiphase flow as well but that is a little more complex. We used Buckley leverett method of modeling injection of water to displace oil. similar concepts in terms of dimensionless dimensions, ie pore volumes injected  (an arbitrary number) replaces time.
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which EOR methods are approprate?
and which reservoire has  similar characteristics?
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A good EOR recipe would take into account the driving forces as well as reservoir characteristics such as wettability. If the reservoir has a good vertical permeability and communication, gravity segregation plays a major role and injecting gas would be a good option. That being said, choice of gas depends on the in situ gas composition as recent studies in the Cantarall field of Mexico suggest the gas composition impacts the Gas-Oil contact movement that you might want to keep track of.
One can also choose a chemical EOR method based on the reservoir wettability and oil characteristics. Depending on the porosity/permeability, surfactants can be chosen as some reservoirs favor production by micro-emulsion formation while others by capillary imbibition (tighter ones).
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Hi
I used the whey protein, Tragacanth gum and Oil  for preparing oil in water emulsion but it is stable for few days. please send me the best protocol that you think it is the best way.
Thanks
Rad
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Thank you so much, 
Actually, I am trying to mix a regular machine lubricating oil with distilled water. 
Can you suggest any other possibility to do so.
Hopefully, will get fruitful results.
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Oil in water emulsions obtained by mixing of crude oils, synthetic surfactants, and polymers are of great interest for those studying Enhanced Oil Recovery. However, special methods for those emulsions investigation by FFF should be developed. Can the following challenge be resolved: to clean the system after each emulsion injection taking into account that organic solution can damage (dissolve) tubing and filters? Is there a way to avoid organic solvents usage? What about the solution of detergents?
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Mean clean. The problem is not in the emulsions but in asphaltenes. I did not work with your system. I worked on the permeability of the core, depending on the formation of supramolecular structures. They are formed from the resins and asphaltenes at a concentration greater 0,02--0,2%. When changing the direction of flow retained some residual directivity filamentary structures.
Best regards.
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Is it possible to capture the details on areal and vertical sweep efficiency at the laboratory-scale??
Is there any specific laboratory / pilot-scale study in deducing the microscopic-displacement and macroscopic-volumetric sweep efficiency?
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For contact angle measurement, we must polish the surface because surface roughness adds to uncertainty and creates issues with contact angle measurement. This way, we will have fluid and rock interaction. Some people may say with polishing we are exposing fresh cut minerals which is true. But, we try to age the rock slabs and let the rock and fluids reach to chemical and surface charge equilibrium. In the pores however, we have sharp angle pore edges which is different from polished rocks. Thus, I prefer wettability measurement on cores and have contact angle measurement as a proof. As I said, contact angle measurement will give us information about rock-fluid interaction and it is very valuable. But the angle is not necessarily the same in the pores. 
If you crush the cores you will definitely change the pore geometry, and if you have unconsolidated rocks you may not be able to maintain pore geometry. But, rocks which are well consolidated such as carbonates will maintain their pore geometry after drilling. I worked with carbonates and tight unconventional rocks and they are hard enough to stay tight even under high confined pressure and under huge centrifugal forces.  
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Different methods are used for enhanced oil recovery. But, as the impact of natural factors?
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Vagif salam!
Without hesitation, geodynamic situation strongly influences to hydrocarbon deposit generation and its preservation. For instance, geological conditions in the Dead Sea Basin are very favorable for large oil deposits accumulation. At the same time non-stable geodynamic pattern and active seismology do not assist to hydrocarbon deposit safety. Therefore, several drilled boreholes in this area discovered only signatures of hydrocarbons.
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Am completing a biography on the personal and professional life of Lou Flournoy, a powerful independent oil and gas well drilling contractor for 50 years in Texas. In the 1950s when he was getting moving, Texas has 80 billion barrels in underground reserves, untapped. At the human world consumption rate of 22 million barrels per day, that wouldn't last too long. What is the current consumption rate, and how many billions of barrels are estimated to be left untouched--for later?
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The last time the USGS did a complete survey of world oil was back in 2000. Since the data was collected for that report, the world has consumed about 450 billion barrels of oil—two-thirds as much as had been used up to that date, over the entire previous history of the oil industry.
Given this prodigious use, oil companies are constantly scouring Earth in search of new oil fields. While they make their own assessments of how much oil might remain to be discovered, the only detailed, publicly available assessment of that kind is from the USGS. The new USGS survey focuses only on “undiscovered, technically recoverable” oil—that is, oil that has yet to be found, and that is plausible that people could get out of the ground.
The total amount of oil left to be discovered around the world is 565 billion barrels, the USGS estimated. That’s a drop of 13 percent from the 2000 study, which put the figure at 649 billion barrels.
Behind this drop, there are some large regional shifts. In two key regions in the Eastern Hemisphere—the Middle East and North Africa, as well as the Former Soviet Union—the amount of oil left to be discovered is about half as much as in the USGS’s 2000 assessment. Instead of holding more than half the oil remaining to be discovered, as in the 2000 assessment, now these areas are thought to hold less than a third of oil yet to be found.
Meanwhile, compared with 2000, the prospects in Central and South America are up 20 percent, to an estimate of 126 billion barrels, higher than any other region in the world (just surpassing the Middle East and North Africa, with 101 billion barrels).
Also, Sub-Saharan Africa’s estimate was up more than 50 percent, reaching 115 billion barrels.
While the figures for undiscovered oil dropped 13 percent, the estimated amount of undiscovered natural gas outside the U.S. went up by 20 percent. “What we’re seeing is more gas, versus oil,” said USGS director Marcia McNutt at the press conference. “That is something that we might want to take into account in our future energy mix.”
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specially in oil industries.
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Dear Behnam .
Absolutely agree with Ahmad it depends on too many factors. Oil industry is very generic title to give you any advice. What is your field of interest?(e.g. Drilling,Production and etc.) But i think the attached artilce will give you at less an idea of nanopartilces concenrations in nanofluids.
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Pls I need your contributions 
am working on developing different approach at which surface surveillance can be used to enhance oil production in a flow station. 
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In the large Weyburn oil field, Saskatchewan (Canada), pumping parameters and rod vibration data are transmitted continuously from each well head by radio to the field base, located near the center of the producing wells. Each well site has a little antenna pointed toward the Field Base. This is a simple automated surface surveillance method, that saves a lot of time to the people that maintain the field, and leads to immediate recognision of pump failure or rod defects, and prompt remedy. This improves the oil production of the field relative to the time before this system was implemented.
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there are many parameters measured and monitors for EOR like particulate size and count, pH, TSS Turbidity and so on.
what are the main parameters affected EOR and how?
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Ideally the performance of an EOR method is measured by macroscopic and microscopic displacement efficiency. For macroscopic displacement, the key factor is a mobility ratio between injected fluid and oil less than 1. The parameters related to this will depend on the type of EOR implemented. In miscible processes such as CO2 injection, this is achieved for higher gas viscosity or in the case of CO2 WAG or SWAG, lower relative permeability of the mixture. However, too much water may be detrimental to microscopic displacement. The microscopic displacement is related to interfacial tension and capillary pressure, which will affect the residual oil saturation.
In my research topic, I am running reservoir simulations to calculate mineral dissolution and precipitation in carbonate reservoirs during CO2 WAG injection. When CO2 is injected calcite dissolution happens near the injector and the pH decreases while precipitation occurs downstream. This change in porosity will affect the permeability in long term and may interfere in EOR performance, but I am still investigating this.
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How can we perform  molecular dynamic simulation for interaction between Surfactant and nanoparticle at oil-water interface?
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I am not sure if MD is really the appropriate tool because of accessible length scales. I know that the group of Jens Harting at Eindhoven Technical University used lattice Boltzmann simulations with functionalized particles which then formed pickering emulsions etc. 
Frijters, S.C.J., Günther, F.S. & Harting, J.D.R. (2014). Domain and droplet sizes in emulsions stabilized by colloidal particles. Physical Review E, 90(4), 042307-1/8. in Web of Science Cited 2 times
Günther, F.S., Frijters, S.C.J. & Harting, J.D.R. (2014). Timescales of emulsion formation caused by anisotropic particles. Soft Matter, 10(27), 4977-4989. in Web of Science Cited 9 times
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Especially, what role does viscoelasticity of polymer play in the flooding process? How can it be performed by molecular dynamics simulation?
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The effect of viscoelasticity is highly debated. There is a chinese group that shows some evidence that residual oil is reduced, but there is no general consensus on this question. 
Generally speaking, polymer is usually used to improve macroscopic sweep, i.e. Not on the pore scale but rather on the Darcy scale. This is all captured in the framework of fractional flow in 1D displacement. Also polymer can improve the shock-front mobility ration and in this way prevent viscous fingering, which is a 2D or 3D effect.
When looking at the pore scale, polymer does increase the viscosity ratio and also stabilize the pore scale displacement. There is a classical diagram by Roland Lenormand, who plots flow regimes in a diagram where the capillary number is on the horizontal axis, and the mobility ratio on the vertical axis. So by increasing the viscosity of the dislacing phase, i.e. The aqueous phase in a water flood, you change both the capillary number and the mobility ratio, which has an impact on the pore scale flow regimes. So this is all Newtonian rheology, no viscoelasticity.
But the impact on residual oil saturation is relatively minor as long as capillary numbers are below 10^-5 or so. Above that, capillary de-saturation starts, see capillary de-saturation section in the book by Larry Lake.
coming back to the question on how to model, I remember that there are several papers on modelling the impact of viscoelasticity on residual oil saturation, and they all use rather conventional CFD, but with non-Newtonian rhology. OpenFOAM for instance can be used. I am not sure if MD is the right tool, because you may be able to simulate one or two pores, but not more. However for residual oil saturation, which is a Darcy scale property, you need to model at least one representative elmenetary volume which is thousands of pores, and completely inacessible to MD. 
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I am currently working on designing test rig for bio-oil extraction . The bio-oil that I plan to extract is through mint leaves. According to research I found out  that the extraction of oil from mint leaves required longer time almost to 12 hours. My objective of the topic is to design test rig . In the test rig stirrer and heater are attached . So need some suggestion to be discussed in the result .
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The attached file shows fewer details about the test rig. I think you may be planning following steps for the bio-oil extraction: 
1. Put mint leaves in water in a container and boil with immersion electric heater and keep on stirring continuously for more than 12 hours.
2. Direct the distilled oil vapour through aluminum coil immersed in cold water in another container to condense the extracted oil.
3. extract the oil and purify to remove water condensate.
For this, you have to design the rig carefully to consider following:
1. Mount the two containers at different elevations:
2. Both the containers should have pressure relief valves for safety.
3. The Aluminum coil should have non-return valve
4. The boiler (container) should be a pressure vessel having proper insulation and thermally strong.
5. Cable connected to the heater should be heat/fire resistant.
6. Stirrer must have speed control mechanism
7. Aluminum coil should have good support against vibration.
8. Terminal point of the aluminum coil carrying the hot oil should be properly connected to oil collecting pot with proper fire protection and away from the boiler/heater.
9. Aluminum coil should withstand highest internal positive pressure as well as maximum vacuum pressure.
10. There should be another mechanism to continuously feed mint leaf in the boiler and extract the residue after oil extraction.
11. Boiler level and pressure monitoring and control to be provided.
12. Keep away from the setup while operation.
13. oil leak detector to be provided.
14. Fire extinguisher and first-aid box nearby available
15. Electric circuit breaker to be nearby apart from fuse
16.Material selections of all the components to be done carefully to withstand the prevailing environment.
Regards,
-Sohail Ahmad Khan
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Considering the economic feasibility..
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Dear. Ravikiran
Method in EOR ( Chemical, Miscible and Thermal).
Recovery in individual reservoir can range 5-80% of OOIP.But the recovery efficiency is result from rock and fluid of reservoir.
It is depend of your field or your specific case.
Thanks
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There is a large variety of thermal desorption facilities on the market particularly for the remediation of oil and gas sites. The main groups are the indirect fired types with oil recovery from the off-gas into the water phase and the other is the direct-fired either parallel flow or better counter flow TD with after combustion.
I would be interested how other remediation and hazardous waste treatment experts evaluate these two treatment possibilities.
Thank you and Glück Auf!
Dr. Rüdiger B. Richter
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Obviously nobody is really interested in thermal desorption. Otherwise on this platform is a considerable resistance with regard to soil washing.
Maybe the question is not very clear or simply too practical!?. - Basically I wanted to discuss the advantages and disadvantages of the two main streams of thermal desorption in terms of hydrocarbon treatment, including waxes and asphaltenes, maybe including the common problems with mercury, etc.
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after using capacitive resistive model and knowing the connectivity parameters(f,parameter of time),what other parameter should i consider to increase oil production and decrease water production?
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Ali,
Attached is an earlier master thesis that has the main concepts of CRM.
Also, you may get useful from the following paper.
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For a gas invaded zone in a naturally fractured reservoir, which EOR methods are suitable? Can you introduce me a case study where the method has been applied in a real reservoir?
We have thought of gas injection (enriched gas, CO2, increase of pressure) and CO2/foam but no real example has been found for them. Could you please introduce me related EOR projects? or any other recommended methods!
We have matrices saturated with oil, surrounded by dry gas injected into gas cap. How can the by-passed oil be recovered? The oil API is about 30 and viscosity is about 3 cp.
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Hi Maryam,
The attached paper did discuss the feasibility of several EOR processes such as continuous gas injection (GI), WAG (water alternative gas flooding), SWAG (simultaneous WAG), FAWAG (Foam Assisted WAG), and GAGD (Gas Assisted Gravity Drainage) process in gas and water invaded zones Highly Fractured Matured Field.
The paper is available in onepetro.org.  PM if you have no access to it.
Best,
Watheq
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What is the rational behind refining the grids that has CO2 injection wells n compositional reservoir modeling? Does it affect or facilitate the history matching?
Overall, is it so necessary to implement grid refinery at this problem?
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Selecting the coarser grid blocks (lower number of cells) in the compositional modeling through CO2 EOR flooding cause the larger effect of numerical dispersion. The presence of numerical dispersion has the effect of smearing out the recovery curves and make the determination of a break point more difficult / inaccurate. Hence, the task of determining the MMP becomes a balance between acceptable accuracy and acceptable CPU time consumption.  Further, as explained by Zick and Stalkup, the MMP can always be found by compositional simulation, though fine grids and repeated simulations at multiple pressures and certainly a significant computation times will be required.
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Are there any potential applications for ZnO Nanoparticles in Enhanced Oil Recovery Processes? Can it be adopted as an injection tool to change some reservoir and fluid properties?
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There are limited experimental works have been recently done to test the effectiveness of ZnO nano-materials to change some characteristics of petroleum reservoirs.  For instance, ZnO may result in significant change the wettability of a carbonate reservoir rock from oil-wet alter to water-wet leading to decrease water cut and enhance oil recovery, as shown in the attached paper link.
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In CO2 flooding in heterogeneous reservoirs, there are many reservoir and fluid properties that affect the reservoir performance.
From the past field-scale studies, what are the most influential factors of CO2 injection for EOR purposes?
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Using CO2 brings additional corrosion problems to tubing. Extracting CO2 and compressing CO2 for injection is not cheap. Some CO2 enhanced recovery projects did experience problems with injectivity reduction. So there are quite significant costs involved with CO2 flooding. Also the use of classical injection is limited to specific cruces in which you achieve multiple contact miscibility, these are relatively light oils. For heavier crudes you can consider alternative injection methods (local fast injection forcing strong fingering(which increases the contact surface oil/CO2), shutting down for mixing and then production by the injection well. There is a patent by Shell on this method).
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Which one is to be more preferred alkaline or acidic?
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 Sorry I did not finish the idea:
Ideal pH should depend of nature of the surface active molecules used to extract, at least in principle.
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Microbially enhanced oil recovery for conventional oil-fields are known. Can this technique  have some value in hydraulic fracturing (fracking)?
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As I know, it is generally best during the pre-heating(circluation) period to minimize net fluid production from the reservoir in order to promote heat absorption into the formation surrounding each wellbore.
So, is it good to shut-in the production well during that time? 
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SAGD pre production heating is typically achieved by circulating steam simultaneously within the open section of the production and injection wells of a given well pair. Steam is injected from a long tubing and flows back to a short tubing . tubings can be concentric or parallel. The wells are open to the formation. They are completed by a wire mesh screen or using a slotted liner. People usually first circulate ensuring minimal leakage in formation, then they switch to a semi SAGD mode in which the injector as a positive balance (injects in formation) and the producer a negative balance (produce from the formation) but there is still circulation of steam within the injector. At a late stage they move into true SAGD. As a function of the detaled setup , the well can require being reconfigured (worked over) between circulation and SAGD periods.
I dont remember any reference to heating only one of the well of the pair. Temperature diffusion being pretty slow, it would require pretty peculiar configuration to make economic sense. 
During circulation, one tries to speed up things as fast as possible (for economical reasons) while trying to ensure safety (see https://www.aer.ca/documents/reports/ERCB_StaffReport_JoslynSteamRelease_2010-02.pdf for an example of what can go wrong) and ensuring that early time actions do not destroy conformance.
Regards.
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I am looking to start a PhD in oil spill detection forensic, whereby we are able to rapidly implement ambient sampling, analysis, typing, and screening of possible multiple sources (vessels and others) in port areas to determine what the oil type is (bunkers, wastes, others, etc), likely sources and definitive non-sources.
The intent is to focus sampling and compliance resources away from likely non-sources (especially vessels on limited time frames and expensive port visits that would otherwise need to be detained as possible suspects), to speed up level one and level two type screening, so as to be able to say with confidence and evidence that a particular "possible" source is categorically NOT the source and let it move on, without compromising future legal defences for prosecutions and compensation.
My intent is to find (develop, adapt, adopt, assess) a simple, robust, rapidly deployed (hopefully hand-held) technology and device able to provide on-site (wharf edge) initial results to achieve the above outcomes.
Early stages of developing proposal so all answers (critique/comment) appreciated.
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Whilst I agree with Ernest that a number of spectroscopic and photometric methods can be used to supplement chromatographic data there is no better starting point than looking at the distribution of chain length that the GC indirectly gives you. I would seriously consider a portable GC system if you need to do analysis in the field.
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Literature review on the impact of increasing salt concentration (such as NaCl or Calcium chloride) suggests no specific trend though most of them suggest an increase in IFT. However, few other works (Abdel Wali, 1996; Vijapurapu and Rao, 2004 and Alotaibi and Nasr-El-Din, 2009) suggestt IFT may not necessarily increase with increasing concentration. I was wondering if anyone could shed some light on how the rends could be better understood
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I have not studied alkaline flooding/IFT in years, but have many references in my electronic files. I have attached some and there should be references in some of my papers cited on my page
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O/W , W/O or Bi continuous?
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I initially agree with Dan's reply, but for Oil recovery you also need to consider the interactions with the rock (wettability and adsorption)  and salinity (quantity and type of ions) plus the viscosity of the emulsion.
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I have read that microorganism really helps in recovery of oil extraction. Anyone can explain how does it works?what types of microorganism that can be used to extract the oil especially from fruit peels?
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Hai everyone,
Thank you for all your feedback. I'm really appreciate it.
Using microbe to oil recevery will be easier if we can isolate the microbe from the peel itself. Once the microbe been identifed, so oil recovery will be increased.
Thanks again.:-)
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I want to understand the phenomena how Na+ and Mg+2/Ca+2 will affect particle dispersion. Which stabilizing agents are used for in it? 
I have come across some literature and I found that Polyvinylpyrrolidone (PVP) can stabilize the solution for up to 220 hours and after that particles will start to settle down.
Can anyone make me understand how PVP will help in this regard? And please suggest if any alternate chemical I can use.
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