WO2023242851A1

WO2023242851A1 - A system and method for enhanced hydrocarbon recovery

Info

Publication number: WO2023242851A1
Application number: PCT/IN2022/050678
Authority: WO
Inventors: Hemachandra DUTTA; Ashok N. Bhaskarwar
Original assignee: Dutta Hemachandra
Priority date: 2022-06-14
Filing date: 2022-07-27
Publication date: 2023-12-21

Abstract

Disclosed herein a system and method for enhanced crude oil recovery, comprising generating surfactant based heated air microbubbles, pumping the surfactant based heated air microbubbles and injecting the surfactant based heated air microbubbles into the hydrocarbon reservoirs, wherein said method further comprises of recovering oil by channelizing the surfactant based preheated air microbubbles for efficiently displacing the oil inside the hydrocarbon reservoirs and enabling it to burst for further additional recovery of the oil. The oil recovery system comprises of a bubble generator, a pump and an air microbubble injector for injecting the microbubbles into the hydrocarbon reservoirs. The above system and method help in recovering both light and heavy crude oil from the reservoir and can be effectively used in any kind of reservoirs.

Description

A System and Method for Enhanced Hydrocarbon Recovery

Field of the Invention

The present invention relates to methods and system for enhanced recovery for obtaining hydrocarbons. More particularly, the present invention relates to methods and system for enhanced oil recovery from multiple zones of the hydrocarbon reservoir using colloidal gas aphrons.

Background of the Invention

An oil reservoir passes through several stages of oil recovery development: primary, secondary, and enhanced recovery stages. At every stage some portion of the initial oil-in- place is recoverable by injection of a fluid. The primary production takes support of its initial reservoir energy utilizing conventional technology. After primary recovery, when the reservoir energy is not sufficient to lift the oil to the surface, it is supplemented by water or natural gas injection for pressure maintenance and also for displacement of oil towards the production wells. Any oil recovery after application or injection of fluids other than water and gas comes into enhanced oil recovery (EOR) category. With present level of technological development, only an average of 20-40% (Muggeridge et al. 2014) of underground oil is recoverable and the rest stay remain untouched.

Any oil recovery after application or injection of fluids, other than of water and gas comes into the enhanced oil recovery (EOR) category. There have been multiple EOR techniques used before, Usually, the secondary recovery factor is in the range of 30-50% and it has also been found that one or more of these conventional enhanced oil recovery techniques raise the recovery factor even to 50-80% (Stosur et al. 2003).

Presently, there are many chemical based EOR techniques, such as polymer flooding, surfactant flooding and others in use in oil fields to get additional oil recovery from a reservoir. It has been observed that they do not favour an increased sweep efficiency and high mobility ratio. Therefore, these result in most of the recoverable oil being remain untouched by the displacing fluid. Various formulations of polymers and surfactant-based fluids have also been used to solve the problems of low mobility ratio and sweep efficiency with varying degree of success. But then, apart from the technical issues, these chemical based technologies are expensive and become less economical when oil prices are low.

Another challenge which still persists in such conventional enhanced oil recovery methods is that they are not effective in displacing both light and heavy oil during the recovery stage. Most of them are effective in recovering light oil but fail to recover the heavy oil from the hydrocarbon reservoirs. Even the ones which recover both the kinds of oil, the oil recovery percentage is too low. Therefore, the existing methods or systems or fluids used for oil recovery from the hydrocarbon reservoirs are not versatile enough to be used for efficiently recovering both light and heavy crude oil.

An effort has been made to study and find out oil recovery factors of various EOR methods through patent and non-patent literature survey. Some of the relevant prior arts have been explained as below:

A US Patent no. 6105672A discloses Enhanced (WAG type) oil recovery process in an underground reservoir, which uses forced injection, through one or more wells, alternately of fluid slugs and gas slugs, and recovery, through one or more production wells of petroleum fluids displaced by the wetting fluid and the gas injected. The process includes dissolving a pressurized gas in the liquid of certain slugs and, after injection, relieving the pressure prevailing in the reservoir so as to generate gas bubbles by nucleation in the smallest pores, which has the effect of driving the oil away from the less permeable zones into the more permeable zones (with large pores or with fractures) where the oil is swept by the gas slugs injected later on. Implementation of the process considerably increases the oil recovery ratio that is usually reached with WAG type processes.

PCT international publication no. WO2022054326A1 discloses a method for enhanced oil recovery which is provided for enhanced recovery of oil included in an oil reservoir using an injection well configured by two flow channels: a water flow channel and a gas flow channel, the method comprising: a step for injecting injection water from the water flow channel; a step for injecting injection gas from the gas flow channel, and ejecting the injection gas as a fine stream of gas through a microbubble generation device installed at the lower end of the gas flow channel; and a step in which a gas-liquid mixture fluid permeates the oil reservoir, the gas-liquid mixture fluid including microbubbles generated from the injection water and the fine stream of gas mixed in the injection well.

The invention disclosed in PCT international publication no. W02008007718A1 provides an enhanced recovery process and an enhanced recovery system by which a larger amount of crude oil or natural gas can be recovered. The enhanced recovery process comprises the step of converting an injection gas into microbubbles in injection water to form a gas-liquid mixed fluid, the step of injecting the mixed fluid into a petroleum or gas reservoir through an injection well to make the microbubbles contained in the mixed fluid permeate into fine crevices in the petroleum or gas reservoir, and the step of recovering crude oil or natural gas expelled from the crevices by the microbubbles through a production well. The enhanced recovery system comprises an injector unit for injection water, a micro-bubbling unit, and a recovery unit for recovering crude oil or natural gas. Abramova et al., 2014 Santos et al., 2014 pays attention to the technologies of hydrofracturing and the ultrasonic technology of EOR, which showed good results as the thermal enhanced oil recovery percentage were reported to be between 30-58%.

It can be concluded from the above literature survey that most of the EOR techniques may be categorized as Heat injection, Gas injection and Chemical injection. Methods such as in-situ combustion, steam injection, CO₂ gas injection, polymer and surfactant injection are widely used in the petroleum industry. But these methods disclosed in the prior arts are reservoir and oil specific. Further, the implementation of such EOR technology in an oil reservoir is capital intensive and techno-economics is not favourable in the present global oil scenario.

It has been found that CO2 injection is effective in oil displacement and as much as 10-30% oil recovery is possible, however there cannot be any further recovery due to the due to the high mobility ratio. Also, the CO2 generation requires a completely different setup and requires specific equipments for CO₂ bubbling, hence making it expensive and the handling difficult. The stability of CO₂ bubble is also critical as its untimely bursting may lead to inefficient recovery.

Also, in none of the prior arts, the method is enabling the recovering of both light and heavy oil from the oil reservoir and the oil recovery percentages are not yet satisfactory.

As detailed above, there are various solutions that have been provided according to the existing arts, however, still there are challenges existing because of the incapability of the existing EOR systems and methods to efficiently work irrespective of the kind of reservoirs for recovering both light and heavy crude oil. It is, therefore, desirable to work on the alternative solution for develop a system and method with alternate EOR fluid which are efficient and economical and obviates the challenges of the prior arts and overcome the problems associated with the prior arts.

Summary of the Invention

The below objectives and embodiments of the present invention as presented herein are understood to be illustrative of the present invention and not restrictive thereof and are nonlimiting with respect to the scope of the invention.

It is one of the objectives of the present invention to provide a method for efficiently recovering both light and heavy crude oil from the hydrocarbon reservoirs. Another objective is to provide a method for oil recovery which can be used for recovering oil from any type of hydrocarbon reservoirs.

Yet another objective of the present invention is to provide a method that avoids usage of excessive chemical for oil recovery from the hydrocarbon reservoirs.

Yet another objective is to provide a method which is user compliant and adaptable for any operator in charge for recovering oil from the hydrocarbon reservoirs.

Yet another objective is to provide a method which involves minimum cost and maximum efficiency in terms of oil recovery from the hydrocarbon reservoirs.

In accordance with one embodiment of the present invention, there is provided a method of recovering oil from hydrocarbon reservoirs, comprising generating surfactant based heated air microbubbles employing a preheated microbubble generator, pumping the surfactant based heated air microbubbles with the help of a pump into an air microbubble injector and injecting the surfactant based heated air microbubbles employing the air microbubble injector into the hydrocarbon reservoirs, wherein said method further comprises of recovering oil by channelizing the surfactant based preheated air microbubbles for efficiently displacing the oil inside the hydrocarbon reservoirs and enabling it to burst for further additional recovery of the oil.

In accordance with another embodiment of the present invention, there is provided a method of recovering oil from hydrocarbon reservoirs, comprising generating surfactant based heated air microbubbles employing a preheated microbubble generator, pumping the surfactant based heated air microbubbles with the help of a pump into an air microbubble injector and injecting the surfactant based heated air microbubbles employing the air microbubble injector into the hydrocarbon reservoirs, wherein said method further comprises of recovering oil by channelizing the surfactant based preheated air microbubbles for efficiently displacing the oil inside the hydrocarbon reservoirs and enabling it to burst for further additional recovery of the oil, wherein said surfactant based heated air microbubbles is generated by agitating a mixture of water and an anionic surfactant in the microbubble generator, wherein said anionic surfactant is preferably a solution of sodium lauryl sulphate (SLS) which is 0.4% by weight.

In accordance with another embodiment of the present invention, there is provided a method of recovering oil from hydrocarbon reservoirs, comprising generating surfactant based heated air microbubbles employing a preheated microbubble generator, pumping the surfactant based heated air microbubbles with the help of a pump into an air microbubble injector and injecting the surfactant based heated air microbubbles employing the air microbubble injector into the hydrocarbon reservoirs, wherein said method further comprises of recovering oil by channelizing the surfactant based preheated air microbubbles for efficiently displacing the oil inside the hydrocarbon reservoirs and enabling it to burst for further additional recovery of the oil, wherein recovered oil is 70-90 % of the original oil in place.

In accordance with one of the above embodiments of the present invention, wherein said method recovers 40-50 % heavy crude oil of the original oil in place by alternately injecting microbubbles and the solution of sodium lauryl sulphate (SLS) into the hydrocarbon reservoirs.

In accordance with one of the above embodiments of the present invention, wherein said method comprises recovering 70-90% light crude oil of the original oil in place by injecting the SLS solution based heated air microbubbles supplemented by ultrasonic waves into the hydrocarbon reservoirs.

In accordance with one embodiment of the present invention, there is provided an oil recovery system to be used with hydrocarbon reservoirs, comprising a preheated microbubble generator configured to generate surfactant based heated air microbubbles, a peristaltic pump adapted to pump the surfactant based heated air microbubbles from said preheated microbubble generator, and an injector operatively connected with the peristaltic pump for receiving the pumped surfactant based heated air microbubbles and configured to inject the same into the hydrocarbon reservoir enabling formation a flow channel for recovering oil from the hydrocarbon reservoir, wherein said system recovers 40-50 % heavy crude oil of the original oil in place from the hydrocarbon reservoir.

In accordance with another embodiment of the present invention, there is provided an oil recovery system to be used with hydrocarbon reservoir, comprising a preheated microbubble generator configured to generate surfactant based heated air microbubbles, a peristaltic pump adapted to pump the surfactant based heated air microbubbles from said preheated microbubble generator, and an injector operatively connected with the peristaltic pump for receiving the pumped surfactant based heated air microbubbles and configured to inject the same into the hydrocarbon reservoir enabling formation a flow channel for recovering oil from the hydrocarbon reservoir, said system recovers 70-90 % light crude oil of the original oil in place from the hydrocarbon reservoir.

In accordance with one of the above embodiment for the oil recovery system, wherein said injector is supplemented with an ultrasonic device.

Detailed Description of the Invention

In view of the foregoing disadvantages inherent in the known types of existing method and system of enhanced oil recovery in the prior art, the present invention provides an effective and universal method of recovering crude oil by way of generating surfactant-based microbubbles (colloidal gas aphrons (CGAs)) and injecting the same into the hydrocarbon reservoir which synergistically overcomes the various drawbacks existing in the art.

The solutions of the present disclosure are clearly described in the following with reference to the accompanying experimental supporting analysis and data. It is obvious that the embodiments to be described are only a part rather than all the embodiments of the present disclosure. All other embodiments obtained by persons skilled in the art based on the embodiments of the present disclosure without creative efforts shall fall within the protection scope of the present disclosure.

The numerous specific details in the description are set forth in order to provide a thorough understanding of embodiments of the present invention. It will be apparent to one skilled in the art that embodiments of the present invention may be practiced without some of these specific details.

Various terms as used herein in the invention is not defined and it should be given the broadest definition persons in the pertinent art have given that term as reflected in printed publications and issued patents at the time of filing.

It is an advantage of the present invention that by using surfactant-based microbubbles or colloidal Gas Aphrons (CGAs), there is achieved an enhanced oil recovery in less water requirement, therefore, resultantly there is a less water cut and hence, less water discharge during the process of oil recovery. This makes the process economical and highly contributes in enhancing recovery factor when implemented on a field scale.

Another advantage of the present invention is that it generates and employs air microbubbles whose stability need not to be monitored as its bursting anytime and anywhere inside the hydrocarbon reservoirs contributes in oil displacement. The air microbubbles mainly consists of oxygen and nitrogen, therefore, when it bursts, results in oxidation of oil, thereby generating heat for enhanced oil displacement in the hydrocarbon reservoir and the pressure released from the bursted microbubbles results in better dislodging the oil even from the hydrocarbon rocks. Further, generating air microbubbles is cost effective as the setup for the same is simple and involves minimum resources. The only cost incurred in generating air microbubbles is the electricity cost because of stirring and only resources required is minimum amount of an anionic surfactant. According to the present invention, experiments have been conducted to recover two types of crude oil - light oil having specific gravity 0.865 and viscosity 14.7 cP, and heavy oil having specific gravity 0.92 and viscosity 19 cP. The corresponding API gravity values related to specific gravity are32.08°API for light oil and 22.3°API for heavy oil.

In accordance with one embodiment of the present invention, the anionic surfactant used in the preparation of air microbubbles is Sodium Lauryl Sulphate (SLS) which varied between 0.01 to 0.8% by weight, wherein it is observed that size of the air microbubble generated using the SLS at above concentration, the diametric size of the air microbubble increases with time and at some concentration of the SLS, the generated air microbubbles are found highly stable and durable with respect to the variation of bubble size with time.

In accordance with another embodiment of the present invention, the anionic surfactant used in the preparation of air microbubbles is Sodium Lauryl Sulphate (SLS) the concentration of which preferably are 0.05%, 0.1 % and 0.2% by weight, wherein it is observed that size of the air microbubble generated using the SLS at the concentration of 0.05%, 0.1 % and 0.2% by weight initially decreases with increasing concentration and rate of bubble deformation decreases with increasing concentration of SLS, hence these two factors together helped in concluding that oil recovery factor will decrease with decreasing SLS concentration.

Further, in another preferred embodiments, the concentration of anionic surfactant Sodium Lauryl Sulphate (SLS) is increased and oil recovery from the hydrocarbon reservoir is made employing the injecting of air microbubbles generated using Sodium Lauryl Sulphate (SLS) at the concentration of 0.4 to 0.8% by weight into the hydrocarbon reservoirs, wherein it is observed that the rate of bubble growth (deformation rate) as a function of time decreased with increasing SLS concentration and specifically in case of SLS concentration at 0.4%, 0.6% and 0.8% by weight, initial bubble size and rate of deformation remains almost the same at all the concentrations as there is no effect on size of the bubbles and hence the recovery factor also remained the same at all the above concentration. But since the cost of generating air microbubble for injection increased with the increase in SLS concentration and the oil recovery factor also remained the same, therefore, the minimum SLS concentration at which the oil recovery factor is maximum or equal relative to the oil recovery factor at higher SLS concentration is chosen for further oil recovery from the hydrocarbon reservoirs.

According to one embodiment of the present invention, a CGAs or surfactant-based air microbubble generator is fabricated which uses anionic surfactant, preferably Sodium Lauryl Sulphate (SLS), cationic (CTAB) and non-ionic (Triton X-100) in water to generate CGAs or surfactant-based air microbubbles, wherein when the Sodium Lauryl Sulphate (SLS) solution is used for microbubble generation in the generator, its concentration is 0.4 % by weight.

In the present invention, a peristaltic pump is used for injecting water, surfactant solution and CGAs as and when required for recovering crude oil from the reservoirs.

The CGA generator is provided with a spinning disc which is mounted between two L- shaped vertical baffles. The disc is capable of rotating at an rpm greater than 7000 rpm. The generator is provided with an outlet at its centre of the bottom and connected to a silicon tube. This tube helps in withdrawing sample of CGAs as and when required. This tube could also be connected to peristaltic pump for onward injection into the hydrocarbon reservoir.

According to the present invention, the flow of CGA in the reservoir by the mechanism of oil droplets attachment and movement enables smaller oil droplets go inside the outermost surfactant layer through two surfactant molecules and get attracted to hydrophobic tail parts of surfactant molecules. The slightly bigger oil droplets after displacing one surfactant molecule in the outermost layer get attracted to hydrophobic tails of adjacent molecules. The larger oil droplets, get attached to a greater number of microbubbles after displacing surfactant molecules from the outermost surfactant layers on getting attracted by hydrophobic tails. Further, while moving up, the inner gas cores of CGAs expand carrying the oil droplets as shown below.

Following is the mechanism of enhanced oil Recovery by CGAs injection:

As CGAs enter an oil reservoirthrough the injector, it moves in horizontal direction by attaching oil particles with them, and the other CGAs moving in the pore spaces and permeability channels expands and bursts during the process, wherein, simultaneously, the surfactant part reduces adhesive forces between oil and reservoir content and the air in CGA removes the oil. Further, the buoyancy of the encapsulated gas with adherence of oil particles lifts them in the vertical direction inside the reservoir. Therefore, in the displacement mechanism, CGA has two motions, both horizontal and vertical resulting in higher displacement and sweep efficiency resulting in very high oil recovery factor.

In the present invention, the air microbubbles produced from aqueous solution of 0.4% anionic surfactant (without addition of any modifier or stabilizer) are effective in enhancing oil recovery. Once these air microbubbles are inside the reservoir, they displace the oil towards production well, some of them even convert into foam which block high permeability channels to divert the microbubbles to low permeability unswept oil zone to improve oil recovery.

Further, in the present invention, the resulting air and surfactant solution obtained from broken microbubbles are also very effective for oil displacement. It works better than WAG (water alternate gas injection) - the EOR technique presently in use in Oil industry.

In the present invention, since the major constituent of air microbubble is about 70% air and only 30% water, cost of injection of an EOR fluid is drastically reduced. There is no need of adding any chemical to modify the micro bubbles.

In general, three litres of surfactant solution of concentration 4g/l is taken in the CGAs generator and a stirrer of the generator is switched on and rpm is slowly increased such that the CGAs started getting formed at 6000-7000 rpm. It is also observed that a steady level of CGAs can be maintained at an rpm of about 6000. The generated CGAs are having a high stability with a specific gravity of Specific gravity of CGAs specimens was also determined. For example, mass of 10 ml of CGAs is found to be 3.5 gm, therefore, the specific gravity of the generated CGAs is 0.35 gm/ml.

Further, a 0.4% liquid surfactant solution is drained into the CGAs specimens for preparing the surfactant-based microbubbles. The CGAs specimen in the measuring cylinder is left for overnight and then in the next observation, the air content found to be in the range 60-70% in the surfactant-based microbubbles.

In the present invention, injection of fluids in the oil reservoir is performed by water injection followed by injection of EOR fluid(s).The water injection is done to create channels by penetrating in the reservoir rock of the reservoir and it also establishes permeable paths. The CGA generator filled with RO water and peristaltic pump are switched on and after about one hour, water started coming out at the exit end. This helps in creating water saturation in the media of the reservoirs and also form some channels were also created through reservoir media.

In one of the embodiments, a volume of surfactant solution is prepared each time for generating microbubbles using the microbubble generator which contains 0.4% w/w surfactant in the solution. The surfactant powder is dissolved in water at low rpm of the stirrer. After complete dissolution, rpm of the disc is gradually increased to more than 6000 rpm and once the CGAs are formed, rpm of the spinning disc was lowered to 5500 and this speed is maintained till the end of injection. It is reported that the size of the generated CGAs was in the range 10-100pm.

In another embodiment, after establishing the suitability of CGAs for injection, the silicon tube was connected to the inlet of the reservoir and injection of CGAs is started. It may be noted that the reservoir can already contain water in it. After injection of CGAs for required duration (usually 4 - 6 hrs), it is stopped for overnight and then resumed usually, the next day. The injection of CGAs is resumed the next day and then continued for 5-6 days.

Further, the injection is continued till no oil appeared in the output fluid and then the entire accumulated output fluid is measured for its oil and water content, wherein, the output of oil as well as water is also measured as to determine if there is any pattern in the volume as composition of the output fluid. In general, the efficiency of the oil recovery factor by way of overall operation is analysed in terms of: (i) total duration of injection (ii) number of days of injection, during which injection was carried out, and (iii) average rate of output.

The movement of CGAs in the reservoir is the space in-between the walls of the reservoir and the media present in the reservoir which displaces oil to accumulate near the exit end of the reservoir and after some time, oil starts flowing out of the exit end.

In accordance with one embodiment of the present invention, there is a method provided for recovering light crude oil in long tube of overall length (including female joints at the end) of 61 cm, diameter of 7.6 cm, effective volume of cylindrical reservoir media pack is 2053 ml with porosity 21.3 %, pore volume is 437 ml, volume of oil used in the reservoir is 255 ml, which implies that residual oil saturation is 58.4 %, wherein water injection, injection of surfactant solution and injection of CGAs (surfactant based microbubbles) into the reservoirs are performed separately to check oil recovery factor as follows: Water injection

For this, about 3 litres of water is injected at a flow rate of about 6 ml/min. After 2 hrs of time, water started flowing out of the reservoir suggesting that pore volume is completely filled with water. Finally, it is observed that no oil is present in the output liquid. It is also observed that some horizontal volume along the length of the reservoir in the upper portion of the cylindrical reservoir is created, wherein the height of the space is about 0.8 cm. Another observation is that some channels appeared in the flow path, implying reservoir content is no longer uniform and the fluid flow through the path of least resistance.

This experimental work is discontinued at the end of the day and resumed the next day, wherein the water injection into the reservoir is performed for about five days, but still yielded no oil.

Injection of surfactant solution - 1^st Recovery (R1)

0.4 % Sodium Lauryl Sulphate (SLS) is injected in the reservoir at a rate of about 6.5 ml/min, wherein the surfactant is seen to be advancing in the reservoir towards the outlet end, and after about 75 minutes of injection, a mixture of oil and water started appearing in the outlet fluid and within next two and half hours, a total volume of 1000 ml of oil and water mixture is collected, and within another two hours, about 900 ml mixture is obtained. Further, in another 45 minutes, 293 ml of oil-water mixture is collected.

The process is stopped, when no oil is observed in the outlet fluid any further. Therefore, the total duration of surfactant injection is 6 hours and 30 minutes at a stretch, wherein, the oil is separated from the accumulated liquid.

Total volume of output liquid : 2630 ml

Total oil obtained from the output liquid : 50 ml

Original-oil-in-place (OOIP) : 255 ml

The injected surfactant forms a complex with the oil and helps in further dislodging oil from the surfaces of the reservoir by overcoming adhesive forces between oil and other contents of the reservoir.

Inferences:

(i). No oil output is observed, during water injection.

(ii). 19.6 % of OOIP is obtained by the injection of surfactant (0.4 % SLS) solution.

(iii). 80.4 % of OOIP is further investigated. Injection of CGAs (Surfactant based microbubbles) - 2^nd Recovery (R2)

The next day after oil recovery using the injection of 0.4% surfactant solution, injection of CGAs into the reservoir is performed. As mentioned above in one of the embodiments, CGAs generation is done by stirring 0.4 % SLS surfactant solution in RO water at around 6000 rpm. CGAs contained 23.2% of liquid content and 76.8% of air content, wherein the CGAs are injected through peristaltic pump into the reservoir.

After about half an hour, creaming of CGAs is observed, which are flowing in the channels created by the injections. The movement of dislodged oil droplets is also seen in the channels. Some foam formation is observed in the upper portion of the reservoir, causing some resistance to the fluid movement. The CGAs are injected at a rate of about 3.2 ml/min for 6 hours and 30 minutes at a stretch. Following this injection, several other injections of CGAs was performed at a regular interval of time on four different days. Following are the results:

Volume of CGAs injected: 2.3 litres

Output product : Oil 70 ml,

Surfactant solution: 765 ml a. Recovery by injection of surfactant solution is 19.6 % of OOIP and b. Further recovery by CGAs injection is 27.45 % of OOIP.

It is also observed that the surface area of CGAs produced from a unit volume of surfactant solution is significantly larger than the surface area of contents of the reservoirs and the grains contacted by the surfactant solution. Therefore, surfactant-based microbubbles (i.e. CGAs) is capable of contacting a very large number of oil droplets and dislodging them from the reservoir content, thereby, CGAs further significantly dislodging most of residual oil left over after injection of surfactant.

In order to check the ageing effect of the reservoir, the experiment is resumed after a few months by CGA injection process and examine the possibility of additional oil recovery from the residual oil left over by earlier processes applied.

Injection of CGAs after a few months - 3^rd Recovery (R3)

About 5 litres of surfactant (0.4% SLS) solution is prepared for generation of CGAs. First injection: CGAs are injected at the rate of about 6 ml/min for 2 hours. It is observed that the upper portion of the reservoir is blocked by the foam generated during CGA injection process. This phenomenon is observed throughout the CGAs injection process.

Second consecutive injection: Injection of CGAs is resumed and continued for 6 and half hours.

Third consecutive injection : The injection of CGAs was resumed and continued for about

5 hours. CGAs are observed to be flowing in the gas cap (upper empty space) of the reservoir. Output fluid is observed to be flowing at the rate of 2.6 ml/min.

Fourth consecutive injection: Injection of CGAs was resumed and continued for about 5 and half hours.

Fifth consecutive injection: The injection of CGAs is resumed and soon discontinued as no oil is found to be coming out from the reservoir.

From the above, it can be concluded that, initially, the CGAs displace oil by dislodging it from sand grains, but after covering some distance, CGAs transform into surfactant water. After some time, CGAs are also observed in the output fluid. It is termed as breakthrough.

Overall observations during 3^rd recovery (R3)

Total surfactant solution used for generating CGAs : 3 litres

Total surfactant water obtained in the product output: 2314 ml

Total oil obtained: 10 ml( 7.4 % of residual oil or 3.92 % of OOIP)

The injection of CGAs at the end of “Recovery 2” is discontinued as the production of oil appeared to have stopped from the reservoir. However, after a gap of a few 9 months, it is still possible to obtain oil in the product output.

The above experiment proves that it is possible to recover some portion of residual oil by CGAs injection even after ageing.

Further, to check if some more oil may be recovered by altering the composition of surfactant solution from which CGAs are generated. The subsequent results are as follows:

Injection of CGAs produced from miscellaneous fluids - 4^th recovery (R4) Four such injections are performed, these have been discussed as below.

1 . Injection of CGAs produced using the surfactant solution (0.4%SLS+0.2% glycerol)

Air content of the CGAs is 62 %. CGAs produced and injected for three days, for about 5-6 hours every day, wherein the total volume of surfactant solution from which CGAs are produced is 1800 ml, the total volume of output liquid is 1400 ml , the amount of oil obtained is about 2 ml.

Though quantity of oil produced is very less, it is still possible to dislodge oil from content of the reservoir even further.

2. Injection of CGAs produced using 0.4 % Triton X-100 surfactant solution

It may be noted that Triton X-100 is non-ionic surfactant, whereas SLS is anionic surfactant. CGAs are produced as before. In this case, air content in the CGAs is 54 %, CGAs are injected at the rate 6 ml /min, for 2 days for about 6 hrs each day. CGAs was breaking through the reservoir and getting produced at the output end. In this case, no oil is produced.

3. Injection of CGAs produced from 0.4%SLS +0.2% Xanthum gum in water solution

It is observed that this solution is much more viscous than the above solutions used so far.

Stable microbubbles are formed at more than 700rpm in this case and the injection rate is 5ml/min. Injections are carried out on 3 consecutive days for 3-4 hours each to obtain a total output liquid of 1850 ml. Though some traces of oil are observed in the output fluid.

4. Injection of preheated CGAs obtained from 0.4%SLS solution

Injection studies were carried out on 8 different days.

To produce CGAs at high temperature, the CGA generator is immersed in a hot water bath. Following are the parameters which are correlated - (i) temperature in the hot water bath and (ii)temperature of the CGAs in the generator, (iii)stability of CGAs at the outlet of the peristaltic pump, i.e. inlet of the reservoir and all the relevant temperature of CGAs. For this purpose, the entire tubing and the reservoir are insulated with suitable asbestos rope. The temperature of the hot water bath is 67°C and the temperature of CGAs obtained is 60°C. On a particular day, the hot water bath is switched on and the generation of CGAs is started, and the characteristics of CGAs is determined and after establishing the suitability of CGAs, injection is started. Injection is continued for 8 days for 5 hours each day and then stopped.

Observations:

CGAs injection temperature: 59-60°C

CGAs injection rate: 2-3 ml /min

Air content : 54%

Total output liquid : 2800 ml

Oil produced : 2 ml

Inference: It indicates that there is a definite effect of temperature on EOR and the preheated CGAs may dislodge the oil more effectively than CGAs at the room temperature.

Hot water injection is performed in one of the embodiments, wherein the temperature of hot water bath is 67 - 68°C, the temperature of water in the CGAs generator is 49 - 51 °C, the hot water is injected for about four and half hours by peristaltic pump. There is no oil observed to coming out in the output liquid. The injection of hot water is repeated next day as well. However, no oil is observed in the output liquid.

It can be concluded that that hot water alone is not effective under the existing conditions.

After a gap of about one year, the injection of CGAs is resumed.

Miscellaneous injections - 5^th recovery (R5)

1 . Injection of CGAs prepared from 0.8% SLS solution, volume of aqueous solution obtained is 1400 ml and no oil is obtained. It is estimated that it contained about 7 ml of dissolved oil in it.

2. Plain RO water injection to flush out SLS content from the reservoir model and CTAB (0.8%) solution is injected to neutralize SLS, if any, present in the reservoir. Again, there is no oil obtained.

3. Injection of CGAs of 0.4% cationic surfactant (CTAB) solution into the reservoir is performed, some traces of oil is observed to be obtained in the output fluid. 4. Injection of CGAs from CTAB (0.8%) solution is performed to ascertain any further recovery. There is no oil obtained in this case.

Overall Experimental analysis:

(i) Total oil in the reservoir - 255 ml

(ii) Injection processes a. Oil recovered by 0.4% SLS solution - 50 ml (R1) b. Oil recovered by CGAs prepared from 0.4% SLS solution - 70 ml (R2)

After a few months (Ageing effect)

(iii) Oil produced using different CGAs a. CGAs produced from 0.4% SLS solution - 10 ml (R3) b. CGAs produced from 0.4% SLS +0.2% glycerol - 2 ml (R4) c. CGAs produced from 0.4% SLS + 0.2% xanthum gum - 1 ml (R4) d. Preheated CGAs produced from 0.4% SLS solution - 2 ml (R4)

Total oil recovered after ageing : 15 ml i.e. 6% of OOIP)

(iv) Injection of CGAs prepared from 0.8% SLS, oil recovered from aqueous output: 7 ml (R5)

Total oil recovered from all displacement processes = R1 + R2 + R3 + R4 + R5 = 50 + 70 + 10 + 5 + 7 = 142 ml i.e. 55.68% of OOI P.

As evident from the above observations, only 55.68% of OOIP is recovered from the oil obtained from all the above displacement processes. Therefore, the residual oil still adhering to the reservoir content is 44.32 %

Further, the residual content of the reservoir is taken out and processed as follows to estimate the quantity of the remaining oil: 1 . It is contacted with sufficient quantity of cyclohexane, wherein some oil is dissolves in cyclohexane and the solid particles is separated from the solution. It is estimated that 13.8 ml of oil is present in the cyclohexane solution.

2. The above remaining solid particles is contacted with acetone and the further the residual solid particles/liquid solution is separated from the original solution. It is estimated that about 8 ml of oil is present in the acetone solution.

3. The above residual solid particles/liquid solution is heated in a Muffle furnace at 500 °C. It is estimated that 87.7 ml of oil is removed in the heating operation.

Since the oil recovery is an unsteady state operation. After the second recovery, the injection is stopped. During the ageing period, the reservoir conditions, such as fluid saturations are stabilized to achieve equilibrium state. Therefore, when the recovery process is resumed, some more oil is obtained.

In the above embodiments and experiments, it is shown that light crude oil recovery is performed by injection of surfactant solution which is followed by injection of CGAs for recovering oil from the reservoirs. Further, in a preferred embodiment, oil recovery from the reservoir is performed by injecting only the CGAs prepared from 0.4 % SLS solution.

In accordance with a preferred embodiment, there is provided a method for recovering light crude oil in a tube, wherein the overall length (including female joints at the end) of the tube is 23 cms, diameter is 5 cms, the effective volume is 250 ml, porosity is 30%, pore volume is 75 ml, volume of oil in the reservoir is 45 ml, which implies that residual oil saturation is 60 %, wherein the method for recovering oil comprises the following steps:

Water injection: As indicated above, 40% pore volume of the reservoir contain only water and for this purpose, water is injected for 34 minutes when water started flowing out of the reservoir.

Injection of water was carried out for a total duration of 4 hours, wherein the water obtained at the outlet end is 725 ml. It is observed that the output fluid does not contain oil.

Injection of CGAs (surfactant-based microbubbles)

The injection rate of CGAs at the outlet of the peristaltic pump is 2.5 ml/min, wherein a yellowish output liquid is observed to be coming out of the outlet. The oil droplets starts appearing after 255 ml of yellowish output liquid, wherein the total duration of CGAs injection is 70 hours in 18 working days, the total oil produced is 35 ml and the total water produced is 5175 ml.

The injection of CGAs is discontinued after 18 days, when it is conclusively evident that no oil is coming out along with the output fluid. The recovery by injection of CGAs is 77.7 %, which is much higher than those obtained by surfactant solution (R1) and CGAs (R2) combined together to yield about 47 % recovery in the embodiments explained above. In this case, the fluid contact the oil loaded reservoir grains more uniformly.

Injection of CGAs accompanied by ultrasonic waves

In this case, reservoir is subjected to sonication bath which generates and transmits ultrasonic waves at a frequency of 30 kHz. During the initial stages of experimentation, it is observed that on sonication, CGAs break. Therefore, an alternate CGAs injection and sonication for about half an hour each is performed. On a typical day, this experiment is carried for three and half an hour and finally oil drops are observed in the output fluid.

Further, the total duration of sonic wave propagation and CGAs injection is 40 hours, water obtained in the output fluid is 1700 ml ( yellowish in color) and oil obtained is 5 ml. It can be concluded that propagation of ultrasonic waves helps in dislodging oil droplets from the reservoir content, and further helps in re-arranging the solid particles in the reservoir and blocking of displacing fluid is automatically removed by sound waves, hence, creating pathways. Therefore, ultrasonic waves dislodge oil adhered to the solid particles in the reservoirs. The wave propagation along with CGAs injection further improves recovery by 1 1 %. This works better when it follows CGAs injection as during simultaneous operations, CGAs break due to vibrations created by ultrasonic wave.

In accordance with a further embodiment, the amount of oil dissolved in yellow water is estimated to be about 1 .70 ml, wherein the remaining solid particles are removed from the reservoir and washed with acetone to remove the small quantity of oil still adhering to the solid particles sand. Following are the results:

Original oil in place (OOIP): 45 ml

Oil produced by CGA injection: 35 ml, i.e. 77.7% = R’

Oil produced by CGA injection + ultra sound propagation: 5 ml i.e.11.1 % = R”

Oil present in aqueous solution (dissolved): 1 .7 ml ( 3.7% ) = R’”

Total oil recovered: 41.7 ml = 92.6% = R Oil recovered by way of acetone wash is 0.5 ml.

Oil adhering to the reservoir content determined by heating in Muffle furnace at 500°C is 1 .95 ml.

Losses = 45- (35+5+1.7+1.95+0.5) = 0.85 ml (1.9%).

In accordance with another preferred embodiment, there is provided a method for recovering heavy crude oil from the hydrocarbon reservoir, wherein 44.5 ml of heavy oil is present with 250 ml of reservoir content in the reservoir, and remaining conditions are kept same as the case while recovering light oil, wherein the steps are as follows:

Water injection is carried out with the help of peristaltic pump for about 71 minutes, when water started coming out in the output fluid. For three days, water injection is carried out for about two and half hours every day. The objective of water injection is to create water saturation in the reservoir so as to make pathways for fluid movement and displacing oil, if any. In this case, the total water obtained in the output fluid is 1200 ml but no oil is obtained.

In another embodiments, injections of CGAs produced from 0.4% SLS solution and injection of CGAs in a heated reservoir are performed, but it is observed that no oil was observed to be coming out of the outlet and in some cases, the oil is obtained with very little success.

In accordance with a preferred embodiment, there is provided a method for recovering heavy crude oil from the hydrocarbon reservoir, wherein 44.5 ml of heavy oil is present with250 ml of reservoir content in the reservoir, and remaining conditions are kept same as the case while recovering light oil, wherein the steps are as follows:

Injection of 0.4% SLS solution alternating with CGAs into the preheated reservoirs is carried out, wherein the hot water bath is switched on and after it is established that entire length of the reservoir tube is hot, injection of surfactant solution is started. After a few minutes, oil is also observed to be flowing out in the output fluid. This is continued for about half an hour. The injection of CGAs and SLS solution were alternated for half an hour each. In this case, the pressure invariably builds up in the reservoir indicating some blockage for outward flow, because of injection may be interrupted and resumed after about half an hourwith the injection of the fluid otherthan the previous one, wherein it is also observed that oil content in the output fluid is more, when CGAs are being injected.

The above steps are carried out for 5-6 hours with 2-3 interruptions every day for overall 22 days. The overall oil recovered from is 20 ml (about 45% of OOIP) and water obtained is 1700 ml. It is still possible to recover the remaining oil if there are few more steps of oil recovery is performed.

In accordance with one of the embodiments of the present invention, in case of heavy oil, the recovery by CGAs alone is not possible, wherein considerable difficulties are encountered in injection of CGAs and blockages might have been developed due to movement and accumulation of oil forming an oil bank at the end and causing blocking of flow paths. Another reason of blockages could have breakage of CGAs and their conversion into surfactant solution and some foam.

Therefore, there is a recovery of 45 % heavy oil employing the above method.

It may be noted in the present invention that recovery of oil from a reservoir is an unsteady state process. The conditions of the reservoir changes change with every processing step and also with time. In light of the same, the oil recovery has been carried out under the circumstances where conditions of the reservoir changes with every processing step and also with time.

Based on the description of disclosed embodiments, persons skilled in the art can implement or apply the present disclosure. Various modifications of the embodiments are apparent to persons skilled in the art, and general principles defined in the specification can be implemented in other embodiments without departing from the spirit or scope of the present disclosure. Therefore, the present disclosure is not limited to the embodiments in the specification but intends to cover the most extensive scope consistent with the principle and the novel features disclosed in the specification.

Claims

I Claim:

1 . A method of recovering oil from hydrocarbon reservoirs, comprising: generating surfactant based preheated air microbubbles employing a microbubble generator; pumping the surfactant based preheated air microbubbles with the help of a pump into an air microbubble injector; and injecting the surfactant based preheated air microbubbles employing the air microbubble injector into the hydrocarbon reservoirs, wherein said method further comprises of recovering oil by self-channelizing the surfactant based preheated air microbubbles for efficiently displacing the oil inside the hydrocarbon reservoirs and enabling it to burst for further additional recovery of the oil.

2. The method as claimed in claim 1 , wherein said surfactant based heated air microbubbles is generated by agitating a mixture of water and an anionic surfactant in the microbubble generator.

3. The method as claimed in claim 2, wherein said anionic surfactant is preferably a solution of sodium lauryl sulphate (SLS) which varies between 0.05% to 0.8% by weight.

4. The method as claimed in claim 2, wherein said anionic surfactant is preferably a solution of sodium lauryl sulphate (SLS) which varies between 0.4% to 0.8% by weight.

5. The method as claimed in claim 2, wherein said anionic surfactant is preferably a solution of sodium lauryl sulphate (SLS) which is 0.4% by weight.

6. The method as claimed in claim 1 , wherein recovered oil is 70-90 % of the original oil in place.

7. The method as claimed in claim 1 , wherein said method comprises recovering 40-50 % heavy crude oil of the original oil in place by alternately injecting microbubbles and the solution of sodium lauryl sulphate (SLS) into the hydrocarbon reservoirs.

8. The method as claimed in claim 1 , wherein said method comprises recovering 70-90% light crude oil of the original oil in place by injecting the SLS solution based heated air microbubbles supplemented by ultrasonic waves into the hydrocarbon reservoirs.

9. An oil recovery system to be used with hydrocarbon reservoirs, comprising: a preheated microbubble generator configured to generate surfactant based preheated air microbubbles; one or more pump adapted to pump the surfactant based heated air microbubbles from said preheated microbubble generator; and an injector operatively connected with the peristaltic pump for receiving the pumped surfactant based heated air microbubbles and configured to inject the same into the hydrocarbon reservoir enabling formation a flow channel for recovering oil from the hydrocarbon reservoir.

10. The oil recovery system as claimed in claim 7, wherein said system recovers 40-50 % heavy crude oil of the original oil in place from the hydrocarbon reservoir.

1 1 . The oil recovery system as claimed in claim 7, wherein said system recovers 70-90 % light crude oil of the original oil in place from the hydrocarbon reservoirs.

12. The oil recovery system as claimed in claim 7, wherein said injector is supplemented with an ultrasonic device.