Enhanced Oil Recovery - Science topic

Ekrem Alagoz

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:

By following these steps, you can increase your chances of having your manuscript reviewed and potentially published.

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.

Dear Ammour Hadjer Ibtissam, nanofluids for example are interesting for EOR. Are you looking for something specific? Please check the following documents. My Regards

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.

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 K_La 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):

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.

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.

Thank you, Clare. I increased the throat/ outlets' length and recovered 99% Oil at contact angle of 0°

can you please provide its datafile, if you have?

Kristian Mogensen

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:

greetings

you could choose option 2 , because The EOR methods focuse on improvemnet of energy system(reservoir)

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.

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.

https://www.glossary.oilfield.slb.com/Terms/i/improved_oil_recovery.aspx

https://www.glossary.oilfield.slb.com/en/Terms/e/enhanced_oil_recovery.aspx

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.

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.

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…

You can get a small quantity of a well characterised oil from the North Sea asking to the Norwegian Petroleum Directorate

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)

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.

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.

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"

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.

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.

Monomers? The gelling agents in fracturing fluids are generally polysaccharides.

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.

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.

I would be interested to know the diesel consumption per metre borehole. Any suggestions?

This article is devoted to the use of CO2 for EOR and perspective of using this metods in Azerbaijan oilfids.

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. 

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.

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. 

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? 

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

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.

Thanks Kevin,

Do you have a reference for the 15ppm?

Dear Edo

Indeed, I do not work on saline sediments, but it would be interesting to start such discussion. Thanks for your comment.

Polla

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. 

You may see API specs.

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.

Typically, dispersivity decreases as salinity increases, I guess this is happened because the electrostatic interactions lead to form bridges among them.

The percent of cross linking compared to linear chain length is usually the determining factor in flex and rigidity.

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.

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. 

You may also look at the following papers

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.

You need to stir also or move the heater to different places in the drum. Convection of heat is (evidently) not sufficient.

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.

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).

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.

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.

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.  

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.

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.”

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.

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.

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.

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

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. 

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

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

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.

Ali,

Attached is an earlier master thesis that has the main concepts of CRM.

Also, you may get useful from the following paper.

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

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.

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.

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).

 Sorry I did not finish the idea:

You may get useful from the following RG publications.

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.

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.

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

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.

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.:-)