CA2852199A1 - Method for in-situ solid particles formation and applications thereof - Google Patents

Abstract

A method for producing in-situ particles for use as proppants and permeability modifiers for oil recovery. The process involves forming solid shells around surfactant micelles in injection fluids such as water, brine, seawater, and synthetic brine. The in-situ particles can also be used in water shut off, drilling, cementing, acidizing, sand consolidation, waterflooding, chemical enhanced oil recovery (CEOR), polymer flooding, and CO2 flooding.

Description

Method for In-Situ solid particles formation and Applications Thereof Cross Reference to Related Applications None Field of Invention The present invention generally relates to a method for producing in-situ organic/inorganic solid particles for oil field applications including but are not limited to improved oil-recovery, drilling, fracturing, cementing, sand control, permeability modification and water shut off.
Background of the Invention In-situ particles can be made and used in many different applications to replace particles commonly used in oil field applications. For example, proppants are used in the fracturing process to keep fracture open and permeable to liquid and gas flow after external pressure is withdrawn. Currently the proppants used are hard roughly spherical particles of various sizes and compositions. Among the materials used are sand, geopolymers, ceramics, resin coated sand, and glass beads. Hydraulic fracturing fluid generally contains water, polymer, crosslinker, fluid loss additives, flow back additives, surfactants, clay stabilizers, proppant, and gel breaker. The polymer is used to provide viscosity and keep the proppants suspended until they have reached their desired location in the fracture. The breakers are used to reduce the polymer viscosity, allowing the particles to settle and the liquid portion of the fracturing fluid to be returned to the surface when the external pressure is removed and the overburden pressure partially closes the fracture. The proppants remain in the fracture and keep a higher permeability channel to increase the oil production. The present invention provides a pumpable liquid system that will form in-situ particles to create the flow channels needed in the formation and replace the traditional fracturing practice.

U.S. Patent 7,810,562 describes a process of forming in-situ solids for well completion and zonal isolation. This process involves injection a sol of metallic alkoxide into a desired location in a wellbore and allowing it to gel to created solids in-situ. The sols can be stabilized using polymers or surfactants.
U.S. Patent Application 2013/0248191 describes a process of forming high porosity fractures in weakly consolidated formations. The process involves first introducing a stabilizing substance into the fracture with the fracturing fluid. This is followed by a treating fluid comprising a gel carrier, degradable solid-free gel bodies, and solids-laden gel bodies. These form multiple packs within the fracture. The solid-free gel particles are allowed to degrade to form a high porosity propped fracture of the solids laden gel bodies.
U.S. Patent Application 2013/0317135 describes a water shut-off system for producing and/or injection wells. This system includes organic products of relatively low viscosity that are pumped into a well in the liquid state. After a certain period of time they form a gel that can partially or fully block water flow.
These reduce the water passage but still allow oil to pass. This gel is not suitable for fracturing because it is compressible and cannot support the overburden pressure.
U.S. Patent 5,358,047 describes a process of fracturing with foamed cement.
The foamed cement has a permeability of at least 0.3 darcies when allowed to harden.
U.S. Patent 5,402,846 uses a foamed thermosetting gel to fracture a reservoir.
After the foam gel is placed within the fracture it is ignited and the remaining residue serves to prop open the fracture when the external pressure is withdrawn.
U.S. Patent 7,703,531 discloses multifunctional nanoparticles for downhole formation treatments. The disclosures include is the claim that these trap or fixate formation fines when deposited in a proppant pack in a fracture.
U.S. Patent 6,059,034 and U.S. patent 6,330,916 disclose a formation treatment method using deformable particles. Proppant is injected along with a deformable particulate material into a formation

2 during fracturing. The deformable particles can combine with the proppant to increase fracture conductivity, reduce fines generation and/or reduce proppant flowback. An example of the deformable particles that may be used are is polystyrene divinylbenzene beads.
U.S. Patent 3,747,677 discloses the control of the precipitation time of a plugging solution by the use of epoxide reactions. The epoxides form a gel when combined with a multivalent metal salt that is used to block the most permeable zones of the formation.
U.S. Patent 8,196,659 uses a fluid gelled with a viscoelastic surfactant and including an effective amount of particulate additive to stabilize the gel. The gels help trap and fixate formation fines when placed in a gravel pack or a proppant pack in a fracture.
U.S. Patent 8,006,759 discloses a method of manufacturing strong lightweight, hollow proppants. This method uses proppant made from thermally removable core and a permanent metal outer surface. The hollow proppants are manufactured prior to introduction into the fracturing fluid and the subterranean reservoir.
U.S. Patent 7,493,957 discloses methods for controlling water and sand production in subterranean wells. Consolidating agents are used to control water production and to transfer a portion of the formation surrounding the well bore into a consolidated region. The consolidating agent may be a resin, a tacifying agent or a gellable liquid composition. An example of such a consolidating agent is an amino methacrylate/alkyl amino methacrylate copolymer.
U.S. Patent 7,931, 089 discloses a proppant of a core part and a shell of a material different from the material of the core part. The shell contains a soft material attached to the core part. The material is injected as a solid contained in a fracturing fluid unlike the instant invention where the particles that serve as proppants are formed in-situ by introducing a totally liquid fracturing fluid that allows the fluid to penetrate deeper into the fracture before forming particles.

3 Canadian Patent Application CA2708166 discloses a fluid composition comprising epoxy particles; epoxy resin curing agent, proppant, and a well-bore fluid. The fluid containing the solid epoxy particles, proppant is injected into the fracture and the solid epoxy resins soften at defined temperatures, pH
values or sheer rates to bind the proppant together.
The present invention describes the method of forming in situ particles that can be used to replace the proppants and additives used in the fracturing fluid and in other oil field applications, such as improving relative permeability, improving the oil and gas recovery, sand flow back prevention and water shut off from subterranean reservoirs. Various methods used to improve oil recovery include but are not limited to water shut off, drilling, cementing, acidizing, sand consolidation, waterflooding, chemical enhanced oil recovery (CEOR), polymer flooding, and CO2 flooding. The present invention has the following advantages over the conventional fracturing process: :
a) The water used in the process is limited as compared to the conventional fracturing job. This resolves the major water source issue of the hydraulic fracturing.
b) Most of the ingredients in the formulation will be reacted to form in-situ particles. Very minimal to no fluid will flow back to the surface as the conventional fracturing process. This resolves the major water concerns in the fracturing applications c) Minimal to none un-desired fluid loss concern as compare to the conventional fracturing treatment. Since the injected in-situ particles formation formulation is in liquid form, it will form in-situ particle in the main fractures and in any leaked off area and increase the fracturing efficiency.
d) Elimination of the additives for conventional hydraulic fracturing fluid, including, but not limited to, polymer, crosslinker, fluid loss additives, flow back additives, surfactants, clay stabilizers, corrosion inhibitors, scale inhibitors, proppant, and gel breakers.

4 e) Less abrasion on the equipment since no solids are pumped into the reservoir.
f) Penetrate deeply into the formation, form in-situ particles and generate flow channels to increase the oil/gas production.
g) Less energy required during pumping as compared to conventional solids laden fluids.
h) Environmentally friendly. None to minimal produced fluid to dispose of.
i) Improved relative permeability that improves the oil and gas recovery from subterranean reservoirs during processes including but not limited to, water shut off, drilling, cementing, acidizing, sand consolidation, waterflooding, chemical enhanced oil recovery (CEOR), polymer flooding, and CO2 flooding.
e) The in situ" formed particles can be varied in size and hardness by manipulation of the ratio of injected components, the type of the components for different applications.
f) The rheology can be fine tuned based on the applications.
g) The strength of the particles and the time required to form the particles can be programmed for various applications.
List of Figures Figure la, b, c, d In-situ generated particles of various sizes.
Figure 2 Fine particles formed using nanoparticles Figure 3a, b Permeability of sand block to oil and water Brief Description of the Invention One embodiment of the present invention involves the use of (A), a primary liquid solid precursor containing surfactant micelles that form a template around which the primary solid precursor is attracted. The combination of surfactant and solid precursor is dissolved in an aqueous based carrier

5 fluid. (B), a secondary liquid solid precursor containing hardener, including but not limited to an amine, or an amide. The secondary liquid solid precursor is added either with the primary liquid solid precursor (A) during application or it can be added after the placement of the primary liquid solid precursor (A) in the reservoir through various mechanical means known to the art. The mixture of the primary and secondary liquid solid precursors are reacted after placement in the reservoir to form in-situ particles.
The time required for the in-situ particles to form, the size of the in-situ particles, and the strength of the in-situ particles can be controlled by the ratio of the primary and secondary liquid solid precursors, the type of surfactants used, the mono and poly cations in the carrying fluid, the shear energy, the temperature, the reservoir environments and the pH. Another embodiment of the present invention is that the in-situ generated solid particles can also be used to reduce the permeability of the reservoir formation but allow for spaces between each particle for fluid to flow. They also can be designed to be strong enough to withstand overburden pressure and prop open fractures formed during hydraulic fracturing and acidizing. In still another embodiment the current invention the process and composition can be fine tuned to change the surface properties and rheology of the particles for permeability modification and can reduce the water channeling through fractures, vugs, or reduce the bottom water drive without risk of sealing off the oil bearing pore spaces in a reservoir.
In still another embodiment of the present invention the particles can also be used to consolidate unconsolidated sand and to prevent sand flow back during fracturing.
Detail Description of the Invention The composition of the present invention contains:
a) one or more micellar forming surfactants, b) one or more liquid primary solid precursor,

6 c) one or more liquid secondary solids precursor (hardener) capable of combining with the one or more solids precursor to form a solid, d) an aqueous carrier.
The one or more micellar forming surfactants is selected from the group:
anionic surfactant, cationic surfactant, amphoteric surfactant. The one or more liquid primary solid precursor includes but is not limited to an epoxy compound, bis-phenol A, novalac resins, geo-polymer, polyurethane resins, silicates epoxy functional resins, epoxy functional nano materials. The one or more liquid secondary liquid solids precursor (hardener) include but are not limited to: amines such as cycloaliphatic amine, amidoamines, aliphatic amines, polyamides, boron tri-fluoride derivatives, functional resins, imidazoles, mercaptans, sulfide, hydrazides, latent and photo-induced reagents. The formation of solid particles may further need an additional cross linker that includes but is not limited to an initiator or retarder, diluents, tertiary amines, metal complexes, clay, mono and/or polyvalent alkali salts, geopolymers, sugars or other organic compounds.
The aqueous carrier including but not limited to water, water with mono, di and/or multivalent salts, seawater, produced brine and synthetic brine. The pH of the aqueous carrier can be adjusted with acid or alkali for different properties of the is-situ particles that may be required.
The composition is injected into one or more injection wells where it is allowed to react and form in-situ particles to serve as proppants, water shut off agents, permeability modifiers, or sand control agents.
Without being held to any particular mechanism or theory, the mechanism of the in-situ particles formation is proposed below.
a) By mixing surfactant(s) and aqueous fluid, the micelles form at above the critical micelle concentration (CMC) These micelles can be of different shapes and sizes based on the type of

7 surfactant, surfactant concentrations, type of fluid, the concentration of mono, di and polyvalent salts, and other conditions eluded to earlier.
b) Adding a functionalized epoxy or active polymeric mononner/oligomer, for example, bisphenol-A
epoxy, that forms a sphere around the surfactant micelles. The thickness of this sphere depends on the choice of the polymer and oligomer. This solution is quite stable until it comes in contact with another activation reagent to form linear or cross linked reactions with the oligomers. The viscosity of the overall liquid can be tuned by adding extra diluents or more aqueous fluid, for example brine.
c) Adding activation reagents to the stable solution of mechanism "b" above initiates a chain reaction to form solid particles. Based on the activation reagents, the strength and surface properties of these particles can be tuned. The reaction can be slowed down and sped up by adding additional additives.
Based on the oil field applications 100% high compressive strength >10,000 psi particles of few millimeters to centimeters size can be prepared (Figures la, b, c) and/or highly sticky colloidal particles can be prepared. Furthermore, fine particles of less than 1 millimeter (Figure 2) can be formed by adding one or more nano-solid supports selected from the group: nano clays, diatoms, layered double hydroxides, magnesium phosphate, cement, zeolites, metal oxides, organonnetallics, geopolymers, carbon nanotubes, graphene particles, and carbon. These additives further reduce the micellar sizes and ultimately the product size distribution and add additional strength to the material.
Once again, without being bound by any particular theory or mechanism, an alternate proposal is that the surfactant incorporates the primary precursor within micelles formed and that the secondary solid precursor reacts with the first solids precursor within the micelle to form particles.

8 In any case the formation of the particles at low temperature in an aqueous solution is an unexpected result of the present invention.
The present invention can be used in hydraulic fracturing and introduced into the fractures formed during the fracturing operation. The in-situ particles formed replace the traditional frac sand to keep the fractures open after the hydraulic fracturing and allow oil/gas to flow through the spaces between each particle. This process eliminates the need for solid proppants, polymers, breakers and other additives commonly employed during conventional hydraulic fracturing.
Examples Example 1: In-situ particle formation using amphoteric surfactant Primary liquid solid precursors Secondary liquid solid precursors Material Wt, gram Material Wt, gram Alkyl dimethyl amido betaine 5.0 Polyamide 20.0 Sea water 20.0 Bisphenol-Epoxy 20.0 Procedure:
1. Add the dinnethyl amido betaine to the sea water, mix well.
2. Add the bisphenol epoxy, mix well.
3. Add the polyannide, mix well.
4. The mixture is a flowable uniform liquid at this stage. Leave the mixture at 25 C for 16 hours and the particles formed as shown in Figure la. Yield is more than 90%.
The strength of the particles were tested using the Arbor 2-ton press and they hold up the pressure > 1,000 lb.

9 Example 2: In-situ particle formation using anionic surfactant Primary liquid solid precursors Secondary liquid solid precursors Material Wt, gram Material Wt, gram C14-16 alpha-olefin sulfonate 5.0 Polyamide 20.0 Sea water 20.0 Bisphenol-Epoxy 20.0 Procedure:
1. Add the C14-16 alpha-olefin sulfonate to the sea water, mix well.
2. Add the bisphenol epoxy, mix well 3. Add the polyamide, mix well.
4. The mixture is a flowable uniform liquid at this stage. Leave the mixture at 60 C for 16 hours and the particles formed as shown in Figure lb .The strength of the particles were tested using the Arbor 2-ton press and they hold up the pressure > 1,200 lb.
Example 3: In-situ particle formation using cationic surfactant Primary liquid solid precursors Secondary liquid solid precursors Material Wt, gram Material Wt, gram Hyamine 1622 5.0 Polyannide 20.0 Sea water 20.0 Bisphenol-Epoxy 20.0 Procedure:

1. Add the Hyamine to the sea water, mix well.
2. Add the bisphenol epoxy, mix well 3. Add the , polyamide, mix well.
4. The mixture is a flowable uniform liquid at this stage. Leave the mixture at 60 C for 16 hours and the particles formed as shown in Figure 1c.
5. The strength of the particles were tested using the Arbor 2-ton press and they hold up the pressure > 1,200 lb.
Example 4: In-situ particle formation in alkaline NaCI solution Primary liquid solid precursors Secondary liquid solid precursors Material Wt, gram Material Wt, gram Alkyl dimethyl amido betaine 5.0 Polyamide 20.0

10% NaCI solution 20.0 50% NaOH 5.0 Bisphenol-Epoxy 20.0 Procedure:
1. Add the dimethyl amido betaine to NaCI solution, mix well.
2. Add 50% NaOH, mix well. pH of this solution is 12-14.
3. Add the bisphenol epoxy, mix well.
4. Add the , polyannide, mix well.
5. The mixture is a flowable uniform liquid at this stage. Leave the mixture at 60 C for 16 hours to make spherical particles (Figure 1d) with more than 95% yield. The strength of the particles were tested using the Arbor 2-ton press and they hold up the pressure > 1,000 lb.

11 Example 5: In-situ fine particle formation using nanoparticles Primary liquid solid precursors Secondary liquid solid precursors Material Wt, gram Material Wt, gram Alkyl dinnethyl amido betaine 5.0 Polyamide 20.0 Sea water 20.0 Laponite nanoparticles 1.0 Bisphenol-Epoxy 20.0 Procedure:
1. Add the dimethyl amido betaine to the sea water, mix well.
2. Add the bisphenol epoxy, mix well.
3. Add the polyamide, mix well.
4. Add 1g Laponite nanoparticles. Mix well.
5. The mixture is a flowable uniform liquid at this stage. Leave the mixture at 60 C for 16 hours and the particles formed (Figure 2).
6. The strength of the particles were tested using the Arbor 2-ton press and they hold up the pressure > 1,000 lb.
Similarly, when the instant invention is used for sand consolidation the in situ formed particles attached to the loose sand to make a compact mass. In addition to holding together the loose sand bed, the in-situ formed particles leave empty spaces for both water and oil to pass through. Even though this process can be used to consolidate the whole sand body it is preferred to consolidate sand nearer the surface only. Once the porous consolidated mass is formed it will stop the loose sand from flowing back.
Example 6: Sand control by consolidation of the sand

12 Composition of the sand bonding fluid Wt%
Alkyl-Dinnethyl amidopropylbetaine 7.9 Sea water 30.7 Bisphenol Epoxy 30.7 Polyamide 30.7 Procedure:
1. Add 5g erucyl dinnethyl amido betaine to 20g sea water, mix well at RT.
2. Add Bisphenol-A epoxy, mix well.
3. Add activating agent for solidification, mix well.
4. The thin solution was passed through a bed of sand (100g). The sample was held at 60 C
overnight to produce a sand block with very good sand bonding and permeability.
Figure 3a shows the sand block and its permeability to oil. Fig 3b shows the sand block and its permeability to water.
Further embodiments and alternative embodiments of various aspects of the present invention may be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as the presently preferred embodiment.
Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features of the invention may be utilized independently, as would be apparent to those skilled in the art after having benefited by this description of the invention. Changes may be made in the elements described herein without departing from the spirit and scope of the invention as described in

13 the flowing claims. In addition, it is to be understood that features described herein independently may, in certain embodiments, be combined.
While the invention has been described in connection with a preferred embodiment, it is not intended to limit the scope of the invention to the particular form set forth, but on the contrary, it is intended to cover such alternatives, modifications, and equivalents as may be included within the spirit and scope of the invention as defined by the appended claims.

14

Claims (11)

What is claimed:

1. A method of forming in-situ particles for use as a proppant, sand consolidation, or permeability modifier in the process of recovery of oil from subterranean reservoirs by combining a) one or more micellar forming surfactants, b) one or more primary liquid solid precursor, c) one or more secondary liquid solid precursor as curing agent an aqueous carrier, injecting the mixture into one or more injection wells, and allowing the primary and secondary solid precursors to react to form in-situ particles.

2. The method of forming particles as described in Claim 1 where the one or more micellar forming surfactants are selected from the group: anionic surfactants, cationic surfactants, nonionic surfactants, and amphoteric surfactants.

3. The method of forming particles as described in claim 1 where the one or more liquid primary solid precursor is selected from the group: epoxy compounds, bis-phenol A, novalac resins, polymer, polyurethane resins, silicates epoxy functional resins, and epoxy functional nanomaterials.

4. The method of forming particles as described in Claim 1 where the one or more liquid secondary solid precursor is selected from the group: cycloaliphatic amine, amidoamines, aliphatic amines, polyamides, boron trifluoride derivatives, functional resins, imidazoles, mercaptans, sulfide, hydrazides, latent and photo-induced reagents.

5. The method of forming in-situ particles as described in Claim 1 where the aqueous carrier is selected from the group: water, seawater, produced brine and synthetic brine.

6. The method for forming in-situ particles as described in Claim 1 where the aqueous carrier is water containing alkali.

7. The method of forming in-situ particles as described in Claim 1 where the aqueous carrier is water containing monovalent salts.

8. The method of forming in-situ particles as described in Claim 1 where the aqueous carrier is water containing mono and polyvalent salts.

9. The method of forming in-situ particles as described in Claim 1 where the aqueous carrier is water containing acid.

10. The method of forming in-situ particles as described in Claim 1 where the size of the particles can be adjusted by varying the composition the ratios of the one or more micellar forming surfactants, the one or more liquid primary solid precursor and the one or more liquid secondary solid precursor.

11. The method of forming in-situ particles as described in Claim 1 where fine particles with added strength can be formed by adding one or more nano-solid supports selected from the group: nano clays, diatoms, layered double hydroxides, zeolites, magnesium phosphate, cement, metal oxides, organometallics, geopolymers, graphene particles, carbon, and carbon nanotubes.