US20120267109A1

US20120267109A1 - Method of treating a fractured well

Info

Publication number: US20120267109A1
Application number: US13/093,531
Authority: US
Inventors: Jagannathan Mahadevan
Original assignee: University of Tulsa
Current assignee: University of Tulsa
Priority date: 2011-04-25
Filing date: 2011-04-25
Publication date: 2012-10-25

Abstract

This invention relates to a method of treating a tight gas well that has been fractured with a gel solution to increase the production of hydrocarbons. The gel solutions used for fracturing typically include an aqueous portion and a polymer material. Generally, the first step of the method is to apply a soak solution to the fractured formation to mix with the aqueous portion of the gel solution to increase the volatility of the aqueous portion. The next step is to apply a dry gas treatment to the tight gas well to remove the aqueous portion of the gel solution after the volatility has been increased.

Description

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

This invention was made with the government support under contract no. DE-AC26-07NT42677 awarded by Department of Energy.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention
This invention relates to a method for treating a tight gas well. Generally, the method includes the step of treating the tight gas well with a soaker solution then treating the tight gas well with a dry gas.
2. Description of the Related Art
Polymeric gels are widely used in hydraulic fracturing operations to produce hydrocarbons (natural gas and/or oil) from tight formations. The recovery of injected gel is often poor and large quantities are left behind, which can cause a loss in gas or oil productivity due to a reduction in the fracture conductivity.
Accordingly, there is a need for a treatment method of tight gas wells whereby larger quantities of the injected gel are recovered, thus increasing the fracture conductivity and production of hydrocarbons from tight formations.

SUMMARY OF THE INVENTION

The invention disclosed herein is directed to a method of treating an oil or gas well that has been fractured with an aqueous gel solution to increase the flow of hydrocarbons. The aqueous gel solution has an aqueous portion and a polymer material portion. The method includes contacting a fractured formation with a soak solution. The soak solution mixes with the aqueous portion of the aqueous gel solution to increase the volatility of the aqueous portion of the aqueous gel solution. The soak solution also removes, due to thermodynamic phase behavior, the aqueous portion from the gel solution. After the soak solution is applied, a dry gas treatment is applied to the well to evaporate the aqueous portion of the aqueous gel solution and reduce gel saturation in the fractured formation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a front elevation view of a wellbore and a fractured formation.

FIG. 2 is a close up, front elevation view of the wellbore and the fractured formation.

FIG. 3 is a graph view showing inlet pressure vs. time vs. flowrate.

FIG. 4 is a graph view showing gas relative permeability vs. time in sand pack during displacement at flow initiation pressure of 80 psia.

FIG. 5 is a graph view showing gas relative permeability vs. time in sand pack during dry gas treatment after displacement at a pressure drop of 10 psi.

FIG. 6 is a graph view showing gas relative permeability vs. time in fracture pack during displacement at flow initiation pressure of 80 psia.

FIG. 7 is a graph view showing gas relative permeability vs. time in fracture pack during dry gas treatment after displacement at a pressure drop of 10 psi.

FIG. 8 is a graph view showing gas relative permeability vs. time in fracture pack affected by solvent treatment at a pressure drop of 10 psi.

FIG. 9 is a graph view showing gas relative permeability vs. time in fracture pack during dry gas injection after solvent treatment/soak.

DETAILED DESCRIPTION OF THE INVENTION

The present invention relates to a method of treating oil and/or gas wells to increase the production of hydrocarbons (oil and gas) from tight formations 10. Referring now to the drawings and more particularly to FIGS. 1 and 2, shown therein is a wellbore 12 drilled down into the tight formation 10. Inserted into the wellbore 12 is a casing 14 held in place in the wellbore by cement 16. Furthermore, in FIG. 1 the tight formation 10, the casing 14 and the cement 16 have been perforated and fractured to generate multiple fractures 18 in the tight formation 10. The fractures 18 are typically made with an aqueous gel solution 20 that includes polymer material 22, proppants 24, such as sand. The proppants 24 are included in the aqueous gel solution 20 to prop open the fractures 18 of the formation 10.
Once the formation 10 has been fractured with the aqueous gel solution 20 and the proppants 24 have been placed in the fractures 18 to keep the fractures 18 open to facilitate the recovery of hycrocarbons from the formation 10, a portion of the gel solution 20 remains in the fractures 18 retarding the recovery of hydrocarbons. This is due to the polymer materials 22 of the aqueous gel solution 20 accumulating at the fracture surfaces, due to a phenomena called “leak-ff,” which increases the gel concentration of the gel solution 20 in the fractures. The gel solution 20 left in the fractures can be up to ninety percent (90%) water.
Saturation, S_gel, of the gel solution 20 is the fraction of the pore space of the fractures filled by the gel 20. This is represented by the equation S_gel=V_gel/V_poreand V_gel=V_polymer+V_water, wherein V_gelis the volume of the gel 20, V_poreis i the volume of the pore space of the fractures, V_polymeris the volume of the polymer material 22 in the gel solution 20 and V_wateris the volume of the water portion of the aqueous gel solution 20.
The gas permeability, thus hydrocarbon production, after the application of the method disclosed herein is an improvement of the gas permeability of the fractures 14 prior to the treatment method disclosed herein. The treatment method disclosed herein increases the gas permeability of the fractures 14 in an amount that is greater than about 5%.
The method disclosed herein can be used when connate brine is present in the formation 10. The method can also be used when condensate forms and is present in the formation 10 or well. Further, the method can be used in formations that are sensitive to water, such as swelling clay formations.
In one embodiment of the present invention, the fractured formation 10 is treated with a soak solution that is miscible with the aqueous portion of the gel solution 20. The soak solution also thermodynamically interacts with the aqueous portion of the gel solution 20. The soak solution then mixes with the aqueous portion of the gel solution 20 to produce a more volatile gel solution in the fractured formation 10, thus increasing the evaporation rate of the resulting gel solution. The soak solution also causes gel shrinkage due to removal of the aqueous portion from the gel solution, during the mixing process, thereby reducing the bulk volume of the gel solution. The soak solution can be any volatile solvent that is miscible with the aqueous portion of the gel solution 20. In one embodiment, the soak solution can include any alcohol comprising at least one carbon atom. In another more specific embodiment, the soak solution can be any alcohol comprising one, two or three carbon atoms. In one embodiment, alcohols that are environmentally less hazardous than mono carbon atoms (methanol) can be used. An example of a soak solution includes, but is not limited to, a solution containing isopropyl alcohol (IPA).
The soak solution can be applied at any pressure and flow rate such that soak solution contacts substantially all of the gel solution 20 that remains in the fractured formation 10. In one embodiment of the present invention, the soak solution is applied to the fractured formation 10 at a pressure that is lower than the fracture pressure of the formation so that no new fractures are created in the formation. Further, the soak solution can be applied with our without various additives. Examples of additives include, but are not limited to, enzymes that can break up the polymeric portion of the gel solution 20.
In another embodiment of the present invention, the soak solution is provided to the fractured formation 10 and shut in the well a specified amount of time to allow proper mixing with the aqueous portion of the gel solution 20. The amount of time the soak solution is shut in depends on various factors at each wellsite where this treatment method is being implemented.
Once the fractures 14 and the fractured formation 10 has been contacted with the soak solution, the resulting volatile gel solution (the mixture of the aqueous portion of the gel solution 20 and the soak solution) is removed from the fractures 14 and fractured formation. In one embodiment of the present invention, the resulting volatile gel solution is displaced by gas flow back or pumped out of the formation. In another embodiment of the present invention, the resulting volatile gel solution is evaporated by the gaseous hydrocarbons being recovered from the fractured formation 10. In the event that any of the soak solution is recovered from the formation, the spent or used soak solution can be recycled for later treatments.
In another embodiment of the present invention, the resulting volatile gel solution is subject to a dry gas treatment to remove the aqueous portion of the resulting volatile gel solution. The aqueous portion of the volatile gel solution is the resulting combination of the soak solution and the aqueous portion of the gel solution 20. The addition of the soak solution makes the aqueous portion of the volatile gel solution much more volatile (increased evaporation ability) than the aqueous portion of the gel solution 20. A volatile aqueous fluid is defined as a fluid whose vapor pressure is greater than that of the polymer which is dissolved in the gel solution. This increased volatility of the aqueous portion of the volatile gel solution allows the dry gas treatment to evaporate substantially all of the aqueous portion of the volatile gel solution. The evaporation of substantially all of the aqueous portion of the volatile gel solution from the dry gas treatment dries the fractures 18, the polymer material 22 and the proppants 24 delivered to the fractures 18 by the aqueous gel solution 20 lowers the V_waterin the fractures 18. Lowering the V_waterin the fractures 18 also lowers the V_gel. The lower V_gelresults in the S_gelbeing lower. The production of hydrocarbons from the fractured formation 10 increases as the S_gelis lowered. It should be understood and appreciated that the dry gas treatment described herein can be applied to gel solutions wherein the polymer material is mixed with a non-aqueous fluid to form the gel solution.
Once the volatile gel solution is dried, the polymeric portion 22 shrinks and does not swell again. The effects of this treatment method are irreversible unless fresh fracturing fluid is applied to the formation 10. In a further embodiment of the present invention, the treatment is applicable to specific polymer materials 22 used in the fracturing gel solution 20. Examples of these polymer materials 22 include, but are not limited to, guar gum polymer, guar gum crosslinked with metal atoms (such as Boron) and non-crosslinked naturally occurring guar based polymers. The treatment method disclosed herein is applicable at all concentrations of polymer material 22 in the gel solution 20. In a further embodiment of the present invention, the drying gas treatment can be applied to non-aqueous volatile gel solutions comprising of polymer materials or polymer like materials.
The gas used in the dry gas treatment can be any gas capable of efficiently evaporating the aqueous portion of the volatile gel solution. Examples of dry gas that can be used in accordance with the present invention include, but are not limited to, any single carbon atom gas (e.g. carbon dioxide or methane), air, nitrogen, monoatomic gases, diatomic gases, subcritical drying fluids, supercritical drying fluids, and combinations thereof (i.e. nitrogen enriched air). In a further embodiment of the present invention, the dry gas can be a flue gas, exhaust gas or any gases resulting from combustion. The dry gas can also have particulates removed therefrom via any manner known in the art. In another embodiment of the present invention the dry gas can be heated prior to injection into the well to increase the rate of evaporation of the aqueous portion of the volatile gel solution. The injected gas can also be a dry (free from aqueous component) supercritical fluid or liquid under reservoir conditions of temperature and pressure.

Experimental Method

Sandback Preparation

A metal shell is created by wrapping aluminum shim stock around a solid cylinder. The diameter and length of metal cylinder is 1.0 inch and 3.0 inches, respectively. The metal shell is then closed at one end with a sand screen supported by a perforated end piece. The sand screen helps to retain and prevent the sand from flowing along with the injected fluids during experiment. The metal shell is then completely filled with 16/40 (0.422-1.20 mm) mesh size sand and packed by continuous vibration. Subsequently the shell is closed with another end piece lined with a sand screen and the entire assembly is securely fastened by using adhesive tape.

Fracture-Pack Preparation

In order to create a fracture-pack, tight gas sandstone rock of 2.2 inch long and 1.0 inch diameter is cut longitudinally to create equally sized rock halves. A portion of the face of the rock is further removed to reduce the thickness of the rock half. The two halves are then assembled in the metal shell, prepared using procedure described in the previous section for sandpacks. The space between the two halves is then filled with sand of 16/40 (0.422-1.20 mm) mesh size completely and packed. The width of this fracture-pack is approximately 3.8 mm.

Dry Gas Treatment

Dry gas treatment method is used to improve gas flowrate recovery. Dry sandpack/fracture-pack is first subjected to invasion by gel fracturing liquid, the preparation of which is described herein. The invaded gel is then subjected to wet gas flow-back. This step mimics the gas flow-back from the well subsequent to fracturing operation. The clean-up process during this flow-back is mainly due to viscous displacement. The displacement process ends when no more gel is visually observed at the outlet end. When dry gas is injected, the water content of the gel is mainly removed by evaporation.

Solvent Treatment

Solvent treatment is used to improve gas flowrate recovery from gel damaged fracture-pack. Fracture-pack is initially subjected to fracturing fluid invasion followed by wet gas flow-back which displaces the trapped gel. Two different solvent treatment methods are followed to improve gas flowrate recovery from the fracture-pack. First is a solvent flow treatment immediately following the gas flow-back and gel displacement. Second is a solvent soak treatment in combination with dry gas treatment after the gas flow-back.

Fluids Used

A borate cross-linked guar polymer is used as the fracture fluid. The gel is prepared by slowly adding 3.0 grams of WG-35 Guar Polymer (obtained from Halliburton) to 1 liter of water and stirring at moderate speed for 30 mins. Finally, 1.75 ml BC-140 cross-linker (obtained from Halliburton) is added to the solution, making the solution crosslink immediately.
Dry air is used to evaporate the water content of the gel. Laboratory-grade isopropyl alcohol of 99.8% purity is used in experiments performed for evaluating the effect of solvents. Air saturated with water is used to displace the gel in the sandpack/fracture-pack. Wet gas helps minimize the evaporation effect during displacement.
Experimental Procedure
The sandpack is placed inside a Hassler type triaxial core holder and a confining pressure of 1000 psia is applied using compressed nitrogen. The tri-axial confinement prevents the sand from flowing under both axial and radial pressure. The sandpack is evacuated and fracturing gel is flowed through the sandpack at 10 cc/min for a time of 10 minutes. A gravimetric analysis is made to obtain the initial weight gained by the sandpack after injection. The gravimetric analysis is performed after the core is taken out of the core holder.
A certain inlet pressure is necessary to initiate gas flow through the sandpack which is completely saturated with fracturing gel. This pressure may also be termed as the flow initiation pressure. A previous study shows that the flow initiation pressure is governed by the viscosity of the fracturing liquid and the permeability of the sandpack. In this study, the flow initiation pressure for the sandpack is determined by conducting an experimental sensitivity study with increasing pressure drops upwards from atmospheric pressure. The results show that the gas flow in sandpack is initiated after an inlet pressure of 80 psia is achieved (FIG. 3)
After gravimetric analysis, the sandpack is placed back in the core holder to conduct gas displacement process and is subjected to the same confining pressure as before. Compressed instrument air, humidified by passing through a column of water, is injected into the sandpack at an inlet pressure of 80 psia with atmospheric pressure at the outlet. This step mimics the flowback from a gas well after a fracturing process using gel. The displaced gel, from the sandpack, is collected at the outlet. The gas injection is continued until no more gel is collected at the outlet end. A gravimetric analysis of the displaced liquid is conducted to determine the gel saturation in the sandpack at the end of displacement. Data acquisition system (National Instruments cFP-1804 with LabView) connected to a work-station is used to continuously record flowrates measured using a digital mass flow meter (Aalborg GFM17).
Subsequent to the displacement step, residual gel saturation is achieved in the sandpack, and no more gel can be removed. This condition is similar to that observed in the field where there is no more fracturing gel recovery after a certain time during well flow-back. The gas flowrates achieved after the displacement step is low (3-5%) due to the low relative permeability of gas. The wet gas flow-back is similar to the field condition, where the gas produced is generally completely humidified due to contact with reservoir brine.
Dry gas is injected into the sandpack at 25 psia inlet pressure, subsequently, to initiate the evaporation process and to reduce the water content of the trapped gel. The gas flowrates at the inlet end are continuously monitored using a mass flowmeter which is connected to the National Instruments data acquisition system. The dry gas injection process is complete when all the gel is completely dried and no more improvement in gas flowrate is observed. The dry gas treatment process on fracture-pack is performed using the same procedure as that of sandpack.
Solvent treatment is applied either prior to the dry gas injection or subsequently. In this study, Isopropyl Alcohol is used as a solvent. Approximately 15 pore volumes (80 mL) of solvent are flowed through the fracture-pack after the end of displacement. A soak period of 3 hours is provided to enable better dissolution of the gel before dry gas treatment.

Results and Discussion

Gel Clean-Up by Dry Gas Treatment in Sandpacks

When dry gas is injected, the water content of gel is gradually removed due to the partitioning of water between gas and gel phase. Water is evaporated at greater rates near the inlet end due to the lack of water in the injected gas. The gas becomes saturated with water on contact with the gel phase as the mass transfer rates are expected to be sufficiently fast to establish complete phase equilibrium across the entire pore space. The drying rate of gel in the sandpack therefore depends mainly on the gas convection rates and to some extent on the expansion driven drying. Viscous fingering, whose effects are discussed in a later section, however, can introduce complexities and thus cause a deviation from the above drying process.
When wet gas is flowed through the sandpack, to mimic gas well flow-back after a hydraulic fracturing treatment, only a portion of the gel is displaced and hence the flowrate of gas recovers only to a small extent. FIG. 4 shows the recovery of gas flowrate during displacement of gel from a sandpack. The gas flowrate is essentially zero at the beginning of the displacement and for up to an hour. This is because the gel saturation is 100% initially and the displacement of the gel is slow due to the high viscosity of the gel. At the end of displacement, when no more gel is observed at the outlet end, a gravimetric analysis is performed to determine the residual gel saturation. It is observed that about 80% of the initial gel is still trapped in the sandpack at the end of displacement.
Subsequent to the gel removal by displacement, dry gas is injected to evaporate or desiccate the trapped gel. FIG. 5 shows the improvement of gas relative permeability during the evaporation process. The effective gas relative permeability increases gradually from a value of ˜0.01, initially, to approximately 0.29 at the end of evaporation process. The gas relative permeability at early times during the dry gas injection is lower than that at the end of displacement. This is due to the fact that the inlet pressure during the displacement experiment is 80 psia while that in the case of the evaporation experiment is 25 psia. Due to the evaporation process, the sandpack is completely dry after about 20 hours. A gravimetric analysis confirms that the weight of gel in sandpack after the dry gas injection is close to zero.
The gas flowrate at the end of the dry gas treatment is much higher than that at the end of displacement by gas flow-back. Thus the viscous displacement process alone leads to a poor recovery as compared to the dry gas treatment process. The gas relative permeability does not, however, recover beyond 29% even if the sandpack is completely dry. This is probably so because the evaporated polymer organizes itself in the pore space in such a way that the pore throats are plugged with the deposited polymer which reduces the overall permeability of the sandpack. Gel Clean-up in Fracture-pack
When dry gas is injected into a fracture-pack, the evaporation process takes place in a similar way to that of the evaporation by dry gas in a sandpack. FIG. 6 shows the gas relative permeability recovery with time during displacement by gas flow-back in a fracture-pack. The gas flowrate recovers to about 5% of the original gas flowrate at the end of displacement while approximately 70% of the gel still remains trapped in the fracture-pack.
FIG. 7 shows the improvement in gas relative permeability when the fracture-pack is further subjected to dry gas treatment. The effective gas relative permeability reaches 32% before the rates achieve a plateau. Thus the dry gas treatment is effective in reducing the liquid gel saturation while improving gas recovery. It should be noted that the fracture pack was taken out of the core holder after displacement. The figure shows the flowrate evolution after the fracture pack was replaced to conduct the evaporation experiment. The early times show a much smaller effective gas relative permeability compared to that at the end of displacement. This could be mainly due to the lower pressure drop (10 psi) during the evaporation period as compared to the displacement (65 psi) period.

Effect of Solvent Treatment With No Soak

Subsequent to displacement by gas flow-back, 15 pore volumes of isopropyl alcohol are injected into the fracture to treat the residual gel. The fracture-pack is then immediately subjected to wet gas flow-back. FIG. 8 shows the improvement of the effective gas relative permeability with time during gas flow-back. The improvement is compared with a case when the gas flow-back is continued without any solvent treatment. The trends readily show that when the residual gel is treated with alcohol the rate of improvement and the ultimate gas relative permeability are higher. When alcohol treatment is used, the improvement of gas relative permeability in the first 20 hours is significant. Subsequently the improvement is gradual. The most likely cause of this variation is that the alcohol is more volatile and is easily evaporated during wet gas flow back as the wet gas contains no alcohol concentration initially. Subsequently the residual gel continues to evaporate due to compressibility driven drying (Mahadevan et al. 2006), which is considerably slower. When there is no alcohol treatment, only compressibility driven drying takes place and improvement due to gel saturation reduction is much more gradual.
The ultimate gas flowrate achieved after the alcohol treatment, with no soak period, is 11% of the original undamaged rate, which is lower than that achieved with a dry gas treatment (34%). While multiple treatments of alcohol may be able to increase the end point gas relative permeability or improve the ultimate gas flowrate achievable, the use of alcohol alone is not as effective as a dry gas treatment.

Solvent Soak/Dry Gas Combination Treatment

When both dry gas and solvent treatment are used, the resulting clean-up and improvement in the gas flowrate is expected to be greater. Two different treatment processes are considered in this study. In the first case dry gas treatment is conducted after an alcohol injection and soak period. In the second case dry gas treatment is followed by an alcohol treatment.
Approximately 15 pore volumes of alcohol are injected into the fracture-pack after displacement and allowed to remain in the fracture-pack for approximately 3 hours to allow enough time for the gel to dissolve in alcohol. Subsequently dry gas is injected to completely evaporate the alcohol and water trapped in the fracture-pack. The improvement in relative permeability during dry gas treatment is shown in FIG. 9. The figure also shows the improvement during a similar dry gas injection without any alcohol treatment. The trends observed in the figure clearly show a greater and faster improvement in the gas flowrate in the case of alcohol treated fracture-pack as compared to that when there is no alcohol treatment. When treated with alcohol it takes less than an hour to achieve 15% of the undamaged gas flowrate compared to 6.5 hours when not treated with alcohol. The ultimate gas effective relative permeability achieved is also high at 43%. It is possible that the higher volatility of alcohol combined with the phase behavior of gel causes faster and greater recovery of gas rates.
In order to investigate the effect of addition of isopropyl alcohol (IPA) to gel, we performed an experiment ex-situ of the porous sandpack/fracture-pack. The experiment was timed to evaluate the gel's water content when it is simply exposed to IPA. 10 grams of the gel was immersed and soaked in 100 ml of IPA for 3 hours which is an identical soak time compared to the alcohol treatment experiment on the sandpack. Visual observation of the gel immersed in the alcohol showed that the gel shrank and only a skeleton structure of a white colored substance (most likely the polymer and the cross-linker that were added to create the gel) remained along with some entrapped water. The entire mixture was filtered using a type 1 Whatman filter paper in a Buchner funnel. The residue exactly corresponded to the weight of polymer and cross-linker used in making the gel. Thus the IPA addition results in complete removal of water from the gel matrix which perhaps represents the ultimate equilibrium phase behavior of the gel alcohol system. The reduction of gel size/weight due to removal of water content can lead to reduction of gel saturation and hence allow greater gas flow.
When dry gas treatment alone is used the ultimate gas rate is a maximum of 34% of the original undamaged fracture-pack. This is evidently lower than that of the case when alcohol treatment/soak precedes the dry gas injection.
Injection of alcohol after a dry gas treatment, when the residual gel is completely dried, does not produce any significant impact on the recovered flowrate. This may be due to the non-dissolution of dried polymer gel by the alcohol. It is here that additives mixed with the soak solution can provide a break-up of the polymer thus increasing the recovery rate even higher.

Discussion on Gel Drying

Drying of liquids from porous media due to gas flow depends on the distribution of the liquid within the medium. When the viscosity of the liquid is small capillary effects can redistribute the volatile liquid and enhance drying rate. However, in the gels, the viscosity is generally high and hence the gels are not mobile. Thus gel is poorly distributed within a porous medium and is also affected by viscous fingering. The drying rate of gel, in the presence of complex viscous fingering and other mass transfer limitations is not well understood. This area is a candidate for future investigations as such compositional effects in the presence of unfavorable mobility displacements has wider applications than considered in this study.
From the above description, it is clear that the present invention is well adapted to carry out the objectives and to attain the advantages mentioned herein as well as those inherent in the invention. While presently preferred embodiments of the invention have been described for purposes of this disclosure, it will be understood that numerous changes may be made which will readily suggest themselves to those skilled in the art and which are accomplished within the spirit of the invention disclosed and claimed.

Claims

1. A method of treating an oil or gas well that has been fractured with an aqueous gel solution to increase the flow of hydrocarbons, the aqueous gel solution having an aqueous portion and a polymer material portion, the method comprising the steps of:

contacting a fractured formation with a soak solution, the soak solution mixing with the aqueous portion of the aqueous gel solution to increase the volatility of the aqueous portion of the aqueous gel solution; and

applying a dry gas treatment to the well to evaporate the aqueous portion of the aqueous gel solution and reduce gel saturation in the fractured formation.

2. The method of claim 1, wherein the soak solution comprises an alcohol having one, two or three carbon atoms.

3. The method of claim 2, wherein the soak solution comprises isopropyl alcohol.

4. The method of claim 1, wherein the method further comprises the step of shutting in the soak solution for a predetermined amount of time to ensure optimum mixing of the soak solution and the aqueous portion of the gel solution.

5. The method of claim 1, wherein the method further comprises the step of recovering the increased flow of hydrocarbons after applying the dry gas treatment.

6. The method of claim 1, wherein the dry gas treatment includes a gas selected from the group consisting of air, nitrogen, nitrogen-enriched air, single carbon atom gases, monoatomic gases, diatomic gases, subcritical drying fluids, supercritical drying fluids, flue gases, exhaust gases, combustion gases, and combinations thereof.

7. The method of claim 1, wherein the single carbon atom gases can be selected from the group consisting of methane, carbon dioxide and combinations thereof.

8. The method of claim 1, wherein the method further comprises the step of heating the dry gas before applying the dry gas treatment.

9. The method of claim 1, wherein the soak solution comprises an alcohol having at least one carbon atom.